IR 05000443/2014002

IR 05000443-14-002; 01/01/2014 - 03/31/2014; Seabrook Station, Unit No. 1; Operability Determinations and Functionality Assessments

ML14127A376
Person / Time
Site:	Seabrook
Issue date:	05/06/2014
From:	Glenn Dentel Reactor Projects Branch 3
To:	Ossing M, Walsh K NextEra Energy Seabrook
Dentel G
References
IR 14-002
Download: ML14127A376 (37)

Text

May 6, 2014

SUBJECT:

SEABROOK STATION, UNIT NO. 1 - NRC INTEGRATED INSPECTION REPORT 05000443/2014002

Dear Mr. Walsh:

On March 31, 2014, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at Seabrook Station, Unit No. 1. The enclosed inspection report documents the inspection results, which were discussed on April 10, 2014, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified finding of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance, and because it was entered into your corrective action program (CAP), the NRC is treating the finding as a non-cited violation (NCV), consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the subject or severity of any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Seabrook Station. In addition, if you disagree with the cross-cutting aspect assigned to the finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at Seabrook Station.

Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last six months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter (IMC) 0310. Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross-cutting aspect assigned, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at Seabrook Station.

In accordance with Title 10 of the Code of Federal Regulations (CFR) 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents Access Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects

Docket No.

50-443 License No.

NPF-86

Enclosure:

Inspection Report No. 05000443/2014002

w/ Attachment: Supplemental Information

REGION I==

Docket No.:

50-443

License No.:

NPF-86

Report No.:

05000443/2014002

Licensee:

NextEra Energy Seabrook, LLC

Facility:

Seabrook Station, Unit No.1

Location:

Seabrook, New Hampshire 03874

Dates:

January 1, 2014 through March 31, 2014

Inspectors:

P. Cataldo, Senior Resident Inspector C. Newport, Resident Inspector

E. Burket, Emergency Preparedness Inspector

T. Burns, Reactor Inspector B. Dionne, Health Physicist W. Cook, Senior Reactor Analyst

Approved by:

Glenn T. Dentel, Chief

Reactor Projects Branch 3

Division of Reactor Projects

Enclosure

SUMMARY

IR 05000443/2014002; 01/01/2014-03/31/2014; Seabrook Station, Unit No. 1; Operability

Determinations and Functionality Assessments.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified one finding of very low safety significance (Green), which was an NCV. The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using IMC 0609, Significance Determination Process (SDP), dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within Cross-Cutting Areas, dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated June 7, 2012. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4.

Cornerstone: Mitigating Systems

Green.

The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion V,

Procedures, because NextEra did not ensure adequate separation was maintained between temporary scaffolding and safety-related equipment. Specifically, six instances of scaffolding installed in the plant were identified with less than the minimum standoff distance to safety-related equipment specified in NextEra procedures and no corresponding engineering evaluation to support these deviations. NextEra entered this NCV into their CAP as AR 01933827 and assessed the six deviations for any impact on the associated safety-related systems.

This performance deficiency was considered more than minor because it affected the protection against external factors attribute of the Mitigating Systems cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, NextEra did not evaluate scaffolding installations when insufficient separation to safety-related equipment existed after procedural requirements were revised to a more restrictive value. Additionally, it was similar to example 4.a in IMC 0612, Appendix E, Examples of Minor Issues, which states that the issue of failing to appropriately evaluate scaffold installation as required by procedures is more than minor if the licensee routinely failed to perform engineering evaluations. The issue was evaluated in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power and determined to be of very low safety significance (Green), because it did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic event. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because NextEra personnel did not perform an adequate extent of condition review after revision of their erection of scaffold procedure. This performance deficiency directly contributed to multiple instances of scaffold members erected within two inches of safety-related equipment without an engineering evaluation [P.2]. (Section 1R15)

REPORT DETAILS

Summary of Plant Status

Seabrook operated essentially at full power for the entire assessment period, with the exception of minor downpowers for turbine control valve testing. However, on March 31, 2014, plant load was reduced to approximately 15% for turbine generator testing prior to a shutdown and entry into refueling outage No. 16 at midnight, March 31, 2014. Documents reviewed for each section of this inspection report are listed in the Attachment.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors reviewed NextEras preparations for the onset of cold weather and snow on February 5, 2014. The inspectors reviewed the implementation of adverse weather preparation procedures before the onset of and during this adverse weather condition. The inspectors verified that operator actions defined in NextEras adverse weather procedure maintained the readiness of essential systems. The inspectors discussed readiness and staff availability for adverse weather response with operations and work control personnel.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

Partial System Walkdowns (71111.04Q - 3 samples)

a. Inspection Scope

==

The inspectors performed partial walkdowns of the following systems:

'A' emergency diesel generator (EDG) while 'B' EDG was out of service (OOS) for annual maintenance on January 27, 2014

Supplemental emergency power system (SEPS) while 'A' EDG was OOS for annual maintenance on February 12, 2014

'A' emergency feedwater (EFW) pump return to service on March 26, 2014

The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), technical specifications (TSs), work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies.

The inspectors also reviewed whether NextEra staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

==1R05 Fire Protection

Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)

a.==

Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that NextEra controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for OOS, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

Residual heat removal (RHR) containment spray safety injection (CSSI) equipment vault train 'A' RHR-F-1B-Z, RHR-F-2B-Z, RHR-3B-Z, RHR-F-4B-Z, RHR-F-4B-Z1, RHR-F-4B-Z2 on January 15, 2014

RHR CSSI equipment vault train 'B' RHR-F-1A-Z, RHR-F-2A-Z, RHR-3A-Z, RHR-F-4A-Z, RHR-F-4A-Z1, RHR-F-4A-Z2 on January 16, 2014

SEPS-F-1-0 on January 21, 2014

Circulating water pump room SW-F-1A-Z on March 11, 2014

Primary auxiliary building (PAB) piping penetration area PAB-F-1A-Z, PAB-F-1J-Z on March 17, 2014

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Internal Flooding Review

a. Inspection Scope

The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to assess susceptibilities involving internal flooding. The inspectors also reviewed the CAP to determine if NextEra identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors also focused on the B EDG building to verify the adequacy of equipment seals located below the flood line, floor and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on January 23, 2014, which included simulated degraded equipment and subsequent equipment failures and initiators, which resulted in escalating degraded plant conditions that ensured implementation of emergency operating procedures by the operating crew, as well as implementation of the emergency plan. This emergency plan implementation included classification of specific events that warranted an Alert Event Declaration. The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the TS action statements entered by the control room supervisor.

Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed general control room activities, including alarm response and control room shift turnovers, conducted on January 13, 2014, March 14, 2014 and March 27, 2014. Additionally the inspectors observed turbine control valve testing on January 17, 2014, engineered safety features actuation system (ESFAS) relay testing on January 27, 2014, operator response to a failed open B steam generator feed regulating bypass valve on March 14, 2014, and restoration from enclosure building exhaust fan EAH-FN-4A testing on March 19, 2014. The inspectors observed test performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, or component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance WOs, and maintenance rule (MR) basis documents to ensure that NextEra was identifying and properly evaluating performance problems within the scope of the MR. For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with 10 CFR 50.65 and verified that the (a)(2)performance criteria established by NextEra staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that NextEra staff was identifying and addressing common cause failures that occurred within and across MR system boundaries.

SW pump P-41C increased vibration trending in January 2014

ED/EDE 120 VAC electrical distribution systems on February 18, 2014

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that NextEra performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that NextEra personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When NextEra performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

RHR system valve maintenance and testing on January 14, 2014

ESFAS relay testing on January 15, 2014

Inverter 1B corrective maintenance following internal transformer failure on February 19, 2014

Planned SW cooling tower switchover on March 20, 2014

'B' feedwater regulating bypass valve M/A station replacement on March 27, 2014

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

East and west pipe chase low temperature impact on feedwater isolation valve operability on January 3, 2014

Operability of safety-related equipment in close proximity to temporary scaffolding on January 16, 2014

Service water pumphouse seismic monitor non-functional following monthly testing on January 24, 2014

Containment enclosure ventilation area seal gaps identified on January 28, 2014

'A' EDG did not trip on overspeed during return to service testing on February 14, 2014

Reactor coolant system (RCS) leakage into the RHR system on March 13, 2014

Turbine-driven EFW pump P-37B oil leak identified during testing on March 19, 2014

The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to NextEras evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by NextEra. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

Introduction.

The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, Procedures, because NextEra did not ensure adequate separation was maintained between temporary scaffolding and safety-related equipment. Specifically, six instances of scaffolding installed in the plant were identified with less than the minimum standoff distance to safety-related equipment specified in NextEra procedures and no corresponding engineering evaluation to support these deviations.

Description.

10 CFR 50, Appendix B, Criterion V, requires that activities affecting quality be prescribed by documented procedures and be accomplished in accordance with those procedures. When used in the plant, the design and installation of temporary scaffolding must be controlled to ensure that it is not installed too close to safety-related equipment. During a seismic event, scaffolding installed too close to safety-related equipment can come into contact with that equipment, cause damage to it, and affect its safety function. NextEra procedures control the installation of temporary scaffolding at Seabrook by specifying a minimum separation between scaffolding and safety-related equipment, and by requiring an engineering evaluation when the minimum separation cannot be met.

NextEra mechanical maintenance procedure, MS0599.47, Erection of Scaffolding, Revision 2, states that members of scaffolding erected adjacent to operable safety-related equipment shall not be less than two inches unless justified by an Engineering Evaluation. MS0599.47 was revised in February 2013, and the requirement for scaffold separation from operable safety-related equipment was changed from...should not be less than 2 inches and in no case less than 1/2 inch without an engineering evaluation to

...shall not be less than 2 inches unless justified by engineering evaluation.

While performing a plant walkdown on January 15, 2014, the inspectors identified temporary scaffold members installed less than two inches from the A Containment Building Spray (CBS) pump discharge and suction lines. The A CBS pump and its associated piping are classified as safety-related equipment and were operable at the time. The identified scaffold did not include an engineering evaluation that provided acceptance of separation of less than two inches. Subsequent plant walkdowns by NextEra personnel identified five additional instances of scaffolding installed less than two inches from operable safety-related equipment without an associated engineering evaluation. NextEra personnel determined that an inadequate extent of condition review following the February 2013 revision of MS0599.47, resulted in scaffolding being staged in the plant at less than the new, more restrictive scaffold separation requirement of two inches. Having identified multiple instances where NextEra personnel had not complied with the separation requirement of the scaffolding procedure, the inspectors concluded that NextEra had not been adequately controlling the design and installation of temporary scaffolding.

NextEra entered the additional instances of inadequate separation identified during their independent walkdowns into the CAP. All discrepancies were corrected and assessed for any potential impact to the operability or functionality of affected systems. The inspectors reviewed the CRs and determined that the safety function of each system potentially impacted by temporary scaffolding, including those identified by the inspectors and NextEra, would not have been affected during a seismic event.

Analysis.

The inspectors determined that not providing adequate separation between temporary scaffolding and safety-related equipment without an engineering basis was a performance deficiency within NextEras ability to foresee and correct. Specifically, several scaffold members were observed within two inches of safety-related equipment without an engineering evaluation as specified by current procedural requirements.

This performance deficiency was considered more than minor because it affected the protection against external factors attribute of the Mitigating System cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, NextEra did not evaluate scaffolding installation when insufficient separation to safety-related equipment existed after procedural requirements were revised to a more restrictive value.

Additionally, it was similar to example 4.a in IMC 0612, Appendix E, Examples of Minor Issues, which states that the issue of failing to appropriately evaluate scaffold installation as required by procedures is more than minor if the licensee routinely failed to perform engineering evaluations. The issue was evaluated in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power and determined to be of very low safety significance (Green) since it did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic event.

This finding is related to the cross-cutting area of Problem Identification and Resolution-Evaluation, because NextEra did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance (P.2). Specifically, NextEra personnel did not perform an adequate extent of condition review after revision of their erection of scaffolding procedure. This performance deficiency directly contributed to multiple instances of scaffolding members erected within two inches of safety-related equipment without an engineering evaluation.

Enforcement.

10 CFR 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be prescribed by documented procedures and shall be accomplished in accordance with those procedures. NextEra mechanical maintenance procedure, MS0599.47, Erection of Scaffolding, Revision 2, states that members of scaffolding erected adjacent to operable safety-related equipment shall not be less than two inches from the equipment unless justified by an Engineering Evaluation. Contrary to the above, on January 15, 2014, the inspectors identified that certain activities affecting quality at Seabrook were not accomplished in accordance with documented procedures. Specifically, following a revision of the minimum scaffolding separation requirement in February 2013, multiple instances of scaffolding outside of the new requirements were left uncorrected and engineering evaluations were not completed.

Installation of temporary scaffolding in the vicinity of safety-related equipment has the potential to adversely affect that equipments performance during a seismic event because it was installed with insufficient standoff distance. After the issue was identified by the inspectors, NextEra performed independent walkdowns of all scaffolding, identifying five additional instances of inadequate separation distance. All identified discrepancies were corrected or evaluated as adequate. Because this violation is of very low safety significance (Green) and NextEra entered this into their CAP (AR

===01933827), this violation is being treated as an NCV consistent with the Enforcement Policy. (NCV 05000443/2014002-01, Scaffolding Installed with Insufficient Separation to Safety Related Equipment)

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors evaluated a modification that replaced the SW flow element to the A EDG jacket water cooler implemented under engineering change EC280824, and completed on February 13, 2014. The inspectors verified that the design and licensing bases, as well as the performance capability of the affected SW train and associated components were not degraded by the modification. The inspectors reviewed associated modification documents, which included topic notes, implementation work order instructions, equivalent change revisions, applicable interface documents (for example, drawings), and applicable post-modification testing.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

Thermal barrier cooling pump monthly surveillance following electrical breaker testing on January 11, 2014

SEPS diesel generator DG-2A maintenance on January 21, 2014

Portable diesel driven pump B.5.b functional test following repairs on February 3, 2014

EDG A exhaust valve Belleville washer replacement on February 11, 2014

1B vital inverter Ferro-Resonant transformer replacement on February 19, 2014

Service water pump P-41C following shaft sleeve replacement on March 6, 2014

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and NextEra procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

Rod control testing and verification of proper operation of digital rod position indication on January 9, 2014

Portable diesel driven pump B.5.b annual functional test on January 14, 2014

'A' cooling tower pump comprehensive inservice test on January 16, 2014 (IST)

RCS leak rate surveillance test on March 5, 2014 (RCS leak rate)

RCS pump seal monthly controlled leakage surveillance on March 12, 2014

Containment enclosure exhaust fan EAH-FN-4A monthly testing on March 19, 2014

'B' EDG operability surveillance and ESFAS slave relay testing March 25, 2014

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

Emergency Preparedness Drill Observation

a. Inspection Scope

NextEra implemented various changes to the Seabrook Emergency Action Levels (EALs), Emergency Plan, and Implementing Procedures. NextEra had determined that, in accordance with 10 CFR 50.54(q)(3), any change made to the EALs, Emergency Plan, and its lower-tier implementing procedures, had not resulted in any reduction in effectiveness of the Plan, and that the revised Plan continued to meet the standards in 50.47(b) and the requirements of 10 CFR 50, Appendix E.

The inspectors performed an in-office review of all EAL and Emergency Plan changes submitted by NextEra as required by 10 CFR 50.54(q)(5), including the changes to lower-tier emergency plan implementing procedures, to evaluate for any potential reductions in effectiveness of the Emergency Plan. This review by the inspectors was not documented in an NRC Safety Evaluation Report and does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety. The requirements in 10 CFR 50.54(q) were used as reference criteria.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated a routine NextEra emergency drill on March 12, 2014, to identify any weaknesses and deficiencies in the event classification and notification activities. The inspectors observed emergency response operations in the simulator and technical support center to determine whether the event classification and notification activities were performed in accordance with procedures. The inspectors also attended the individual facility drill critique to compare inspector observations with those identified by NextEra staff, to evaluate NextEras critique and to verify whether NextEra staff was properly identifying weaknesses and entering them into the CAP.

b. Findings

No findings were identified.

.2 Emergency Preparedness Training Observations

a. Inspection Scope

The inspectors observed a simulator training evolution for Unit 1 licensed operators on January 23, 2014, which involved simulated emergency plan implementation by an operations crew. NextEra planned for this evolution to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that NextEra evaluators noted the same issues and entered them into the CAP.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

From March 4 to March 8, 2014, the inspectors reviewed NextEras performance in assessing the radiological hazards and exposure control in the workplace. The inspectors used the requirements in 10 CFR Part 20 and guidance in Regulatory Guide (RG) 8.38, Control of Access to High and Very High Radiation Areas for Nuclear Plants, TSs, and the NextEra procedures required by TSs, as criteria for determining compliance.

Inspection Planning

The inspectors reviewed 2013 NextEra performance indicators for the occupational exposure cornerstone for Seabrook Nuclear Station. The inspectors reviewed the results of radiation protection program audits. The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection.

Radiological Hazard Assessment

The inspectors determined if there have been changes to plant operations since the last inspection that may result in significant new radiological hazards. The inspectors evaluated whether NextEra assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last two radiological surveys from the Fuel Transfer Canal and Letdown Line in the Demineralizer Alley. The inspectors evaluated whether the thoroughness and frequency of the surveys were appropriate for the given new radiological hazard.

The inspectors conducted walk-downs and independent radiation measurements in the facility, including radioactive waste processing, storage, and handling areas to evaluate material and radiological conditions.

The inspectors reviewed one risk-significant work activity that involved exposure to radiation. This activity was the initial entry, survey and decontamination of the fuel transfer canal following the second dry spent fuel storage cask loading campaign. For this work activity, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if radiological hazards were properly identified (e.g., discrete radioactive hot particles, transuranics and hard to detect nuclides in air samples, transient dose rates and large gradients in radiation dose rates).

The inspectors observed work in potential airborne radioactivity areas, and evaluated whether the air samples from the fuel transfer canal air sample locations were representative of the breathing air zone and were properly evaluated.

Instructions to Workers

The inspectors selected three containers of radioactive materials and assessed whether the containers were labeled and controlled in accordance with 10 CFR Part 20 requirements.

The inspectors reviewed the following radiation work permits (RWP) used to access high radiation areas (HRA) and evaluated if the specified work control instructions and control barriers were consistent with TS requirements for HRA.

RWP 14-0015 High Integrity Container/Liner Shipping Preparation to include Capping, Weighing and Transfer to Waste Processing Building, January 1, 2014

RWP 14-0022 Inspect CS Valves inside Letdown Valve Room at Power, January 15, 2014

RWP 14-0027 Primary Auxiliary Building Demineralizer Alley Work/Entry, December 31, 2013

RWP 14-0058 Fuel Storage Building Transfer Canal Radiation Protection Survey, Decontamination and Maintenance Support Activities, March 2, 2014 For these RWPs, the inspectors assessed whether allowable stay-times or permissible dose for radiologically significant work under each RWP were clearly identified. The inspectors evaluated whether electronic personnel dosimeter (EPD) alarm set-points were in conformance with survey indications and plant procedural requirements.

The inspectors reviewed two occurrences where a workers EPD malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately. The inspectors assessed whether the issue was included in the corrective action program and whether compensatory dose evaluations were conducted as appropriate.

For work activities that could suddenly increase radiological conditions, the inspectors assessed the NextEra means to inform workers of these changes.

Contamination and Radioactive Material Control

The inspectors reviewed NextEras criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was sufficient procedural guidance on alarm response.

The inspectors reviewed NextEras procedures and records to verify that the radiation detection instrumentation was used at an appropriate sensitivity level. The inspectors selected six sealed sources from the NextEra inventory records and reviewed whether the sources were accounted for and were tested for loose surface contamination.

The inspectors evaluated whether any recent transactions involving nationally tracked sources were reported in accordance with 10 CFR Part 20 requirements.

Radiological Hazards Control and Work Coverage

The inspectors evaluated ambient radiological conditions and performed independent radiation measurements during walk-downs of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, RWPs, and associated worker briefings.

The inspectors examined NextEra physical and programmatic controls for highly activated or contaminated materials stored within spent fuel and other storage pools.

The inspectors assessed whether appropriate controls were in place to preclude inadvertent removal of these materials from the pool.

The inspectors examined the posting and physical controls for selected HRAs, locked high radiation area (LHRA) and very high radiation areas (VHRA) to verify conformance with the occupational performance indicator.

Risk-Significant HRA and VHRA Controls

The inspectors discussed with the Radiation Protection Manager (RPM) the controls and procedures for high-risk HRAs and VHRAs. The inspectors assessed whether any changes to NextEra relevant procedures reduce the effectiveness of worker protection.

The inspectors evaluated NextEra controls for VHRAs and areas with the potential to become a VHRA to ensure that an individual was not able to gain unauthorized access to these areas.

Problem Identification and Resolution

The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by NextEra at an appropriate threshold and were properly addressed for resolution in the licensees corrective action program. The inspectors assessed the appropriateness of the corrective actions for problems documented by NextEra that involve radiation monitoring and exposure controls. The inspectors assessed NextEra processes for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

The inspectors assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR Part 20, RG 8.8, Information Relevant to Ensuring that Occupational Radiation Exposures at Nuclear Power Plants will be As Low As Is Reasonably Achievable, RG 8.10, Operating Philosophy for Maintaining Occupational Radiation Exposure As Low as Is Reasonably Achievable, TSs, and NextEra procedures required by TSs, as criteria for determining compliance.

Inspection Planning

The inspectors reviewed information regarding Seabrooks collective dose history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants three year rolling average collective radiation exposure.

The inspectors compared the site-specific trends in collective exposures against the industry average values and from similar nuclear power plants. In addition, the inspectors reviewed any changes in the radioactive source term by reviewing the trend in average contact dose rate with reactor coolant piping and steam generator primary channel head space and manways. The inspectors reviewed site-specific procedures associated with maintaining occupational exposures ALARA, which included a review of processes used to estimate and track exposures from specific work activities.

Radiological Work Planning

The inspectors assessed whether NextEra planning identified appropriate dose reduction techniques; considered alternate dose reduction features; and estimated reasonable dose goals. The inspectors evaluated whether NextEras ALARA assessment had taken into account decreased worker efficiency from use of respiratory protective devices and/or heat stress mitigation equipment. The inspectors determined whether NextEra work planning considered the use of remote technologies as a means to reduce dose and the use of dose reduction insights from industry operating experience and plant-specific lessons learned. The inspectors assessed the integration of ALARA requirements into work procedure and RWP documents.

Source Term Reduction and Control

The inspectors used licensee records to determine the historical trends and current status of plant source term known to contribute to elevated facility collective dose. The inspectors assessed whether the licensee had developed contingency plans for expected changes in the source term as the result of changes in plant fuel performance issues or changes in plant primary chemistry.

Problem Identification and Resolution

The inspectors evaluated whether problems associated with ALARA planning and controls are being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees corrective action program. The inspectors assessed NextEras process for applying operating experience to their plant.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with Complications===

a. Inspection Scope

The inspectors reviewed NextEras submittals for the following Initiating Events Cornerstone performance indicators for the period of January 1, 2013 through December 31, 2013.

Unplanned scrams per 7000 critical hours

Unplanned scrams with complications

Unplanned power changes per 7000 critical hours

To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed NextEras operator narrative logs, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that NextEra entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP and periodically attended condition report screening meetings.

b. Findings

No findings were identified.

.2 Annual Sample: Increasing Frequency of Leaks in Service Water Piping in the Vicinity of

Installation/Fabrication Welds

a. Inspection Scope

During the period January 27 to January 31, 2014, inspectors reviewed a root cause evaluation (RCE AR 16379222) completed by NextEra staff for a service water pipe leak that occurred in August 2013. This problem was described in a licensee event report submitted to the NRC dated December 23, 2013. The inspectors determined the effectiveness of actions by NextEra staff to identify, characterize, correct and prevent reoccurrence of SW system leaks.

The inspectors assessed problem identification threshold, apparent cause analysis, extent of condition reviews, and timeliness of corrective actions. The inspectors reviewed documents listed in the Attachment to this report and interviewed NextEra engineering personnel to assess the effectiveness of the planned, scheduled, and completed corrective actions to resolve the identified deficiency.

The inspectors reviewed non-destructive test procedures, procedure qualifications including test personnel qualifications to determine compliance with the applicable American Society of Mechanical Engineers codes and standards. Also, the inspectors reviewed system health reports, work orders, procurement documents, drawings and photographs to determine if the nonconforming condition was appropriately identified, documented, characterized and entered into NextEras corrective action process.

The inspectors reviewed root cause evaluation AR 16379222 and interviewed members of the evaluation team. The inspectors interviewed the qualified non-destructive test examiner to evaluate the ultrasonic test method used. Test results were reviewed with the test examiner to assess the remaining wall thickness for continued operation without encroaching on minimum wall requirements.

b. Findings and Observations

No findings were identified. The root cause evaluation and corrective actions were reasonable, appropriate and timely.

NextEras root cause evaluation addressed a history of SW degradation (corrosion/

erosion) resulting in wall thinning and pressure boundary penetration and leakage. The areas where wall thinning and leakage occurred was determined to be associated with the loss of protective coating and/or liner failure at fabrication/installation welds which typically results in turbulent fluid flow. This turbulent flow was particularly aggressive in the attack of base metals and protective coatings at these weld locations and configuration changes. The inspectors assessed the root cause determination, results of the extent of condition investigation of other locations within the SW system and other fluid (circulating water) systems with similar piping materials, operating parameters and configurations.

The inspectors noted that examination using ultrasonic testing was performed at selected locations with known change in flow patterns and velocity changes. The results of this testing identified areas exhibiting variable wear rates. An evaluation of these test results was made to determine pipe structural and pressure retaining integrity.

The inspectors visually examined several portions of previous SW pipe and fittings that had been removed from the SW system in prior outages due to identified leaks. The removed samples provided confirmatory evidence of corrosive/erosive attack from turbulent flow at root locations of field welds, configuration changes and pipe to fitting intersections. These locations revealed characteristic pin hole leaks at weld locations and a general wastage of pipe and fitting interior diameters. These locations were evaluated for compliance with minimum wall thickness requirements. Those locations which were identified as active leaks at weld locations or, where areas exhibiting loss of wall thickness and were encroaching on minimum wall requirements, were dispositioned for repair/replacement in the CAP.

The inspectors determined that this issue received appropriate management attention as indicated by the corrective action that was taken to perform a temporary leak repair by the installation of a weldolet encapsulating the leak location. At the next outage, (OR16)the weldolet will be removed and replaced with a more suitable flush patch. The patch will be coated internally with a corrosion/erosion resistant material. The inspectors discussed the licensee plans to systematically remove and replace the SW piping with a base metal that is significantly more resistant to erosion/corrosion attack. The inspectors examined numerous lengths of pipe and fittings which were staged for replacement in the plant during the April 2014 refueling outage and subsequent outages.

.3 Annual Sample: Review of Activities Associated with Alkali Silica Reaction Affected

Structures

a. Inspection Scope

March 12 to 13, NRC inspectors from Region I and a structural engineer from the Division of License Renewal, NRR, witnessed testing conducted at the Ferguson Structural Engineering Laboratory (FSEL) at the University of Texas - Austin. The testing was conducted in support of the Seabrook Alkali-Silica Reaction (ASR)

Integrated Corrective Action Plan. Specifically, the inspectors witnessed load testing of the control beam for reinforcement anchorage (lap-splice) capacity. The testing was performed in accordance with MPR Project 0326-0063, Procedure 5-7, Structural Testing of Shear and Anchorage Specimens, Revision 1.

The inspectors also reviewed the results of the December 2013, Combined Crack Indexing (CCI) measurements and the supporting engineering analysis. Proprietary data sheets and associated evaluations were made available for inspector review.

Additionally, the inspectors review included discussions with the responsible Seabrook engineers, as well as petrography specialists consulting for the University of Texas Ferguson Structural Engineering Laboratory

Lastly, the inspectors reviewed NextEras revised Prompt Operability Determinations (PODs) that address additional Seabrook structures identified as being affected by ASR via the Phase 3 ASR walkdown program.

b. Findings and Observations

The inspectors identified no findings.

Review of CCI and Crack Width Measurements

The inspectors examined the December 2013 CCI measurement results documented in Foreign Print (FP) 100847 and FP 100848, dated January 30, 2014. As documented in these NextEra reports, there are 32 areas currently being monitored for ASR progression using the CCI and crack width methodology. As of December 2013, 26 of the 32 areas have been monitored on a six-month basis for approximately two years. Based upon the data collected to date, NextEra has concluded the following: 1) the data suggests a slow increasing trend in CCI and crack width over the past two years; 2) at 14 interior ASR locations, the horizontal and vertical CCI data indicates an overall upward trend (an average increase of 0.04 mm/m, with a measurement tolerance of 0.05 mm); 3) at nine exterior locations, the horizontal and vertical CCI data indicates no significant change over the two-year period; 4) the six floor/ceiling/roof locations indicate flat to upward trends early in the period, but no change later in the two-year period; and, 5) some fluctuation in the measured CCI and crack width values have been observed. The fluctuations may be attributed to thermal effects, cyclic or constant moisture exposure, measurement device accuracy, or the condition of the measured surfaces as impacted by cleaning/preparation and weathering effects. Independent inspector review of CCI and crack width measurement data and photographs of selected areas confirmed NextEras conclusions. As stated in FP 100847 and FP 100848, NextEra will continue the six-month data collection to comply with the Structures Monitoring Program and validate these observed ASR progression trends.

Review of Operability Determinations

Based on the result of recent Phase 3 walkdowns, NextEra identified six additional areas with CCI > 1.0 millimeter per meter (mm/m). In accordance with the Seabrook Structures Monitoring Program (SMP), NextEra staff completed evaluations of the affected structures to assess the potential impact of ASR on continued operability. The six additional areas identified with a CCI value greater than 1.0 mm/m were: cooling tower exterior (elevation 25, reference CTE-02); primary auxiliary building (PAB)penetration area (elevation -26, reference MF105-01); west pipe chase (elevation 12, reference MF202-02); and three areas in electrical manholes (below grade elevations, reference CI-W03-Wall, CI-W05-Wall, and CI-W11-Wall). The structural evaluations were documented as Supplement IV and V to FP 100716, Seabrook Station: Impact of ASR on Concrete Structures and Attachments, and utilized the same design capacity versus calculated demand margin analysis approach as the previously completed PODs (reference Section 9.1, NRC Inspection Report 05000443/2012010). Inspector review of the six additional ASR-affected area PODs concluded that the impacted structures have adequate strength margin available and are fully capable of performing their safety functions.

Control Beam Testing Observations

The inspectors witnessed the performance of load testing of the first control beam (a specimen that has not undergone ASR aging). The beam (A-7, reinforcement anchorage control specimen) was tested in accordance with MPR Project 0326-0063, Procedure 5-7, Structural Testing of Shear and Anchorage Specimens, Revision 1, on March 13, 2014. Beam failure occurred at a load of approximately 251,000 pounds, as compared to the estimated failure load of 214,000 pounds. The failure load was slightly higher than the estimated design capacity, but within the accuracy of the design calculations. No test anomalies were identified. The results of the control beam test will be used to compare subsequent ASR-affected specimen tests to evaluate the impact of ASR degradation on structural performance. The inspectors observed proper procedural adherence, good test coordination and proper communications and safety practices exhibited by the testing staff, supervisory personnel and quality assurance overseers.

The inspectors verified proper testing preparations and quality control oversight as specified by MPR Project 0326-0063, Procedure 5-6, General Preparation of Test Facilities and Specimens, Revision 2, and MPR Procedure 0326-0062-46, Procedure for In-process Inspections of FSEL Reinforcement Anchorage Test Setup for Seabrook Station, Revision 0.

Initial Test Specimen ASR Expansion Results

NextEra and the UT-Austin FSEL staff have observed in the large-scale test specimens that the X-and Y-direction deep pin expansion measurements (comparable to the Seabrook vertical and horizontal wall surface CCI measurements) do not appear to correlate with the through-wall (e.g., out-of-plane, or Z-direction) deep pin expansion measurements after the initial phase of ASR expansion. X-and Y-direction expansion appears to plateau while the Z-direction expansion continues to trend upward (increase).

All large-scale reinforcement anchorage and shear specimens have demonstrated this expansion trend. The Z-direction expansion in the test specimens has been observed to be 10 times greater than the X-and Y-expansions after approximately one year.

The preliminary implication of these test specimen expansion measurement trends is that the X-and Y-expansion measurement methods (CCI and crack width) currently used for monitoring the progression of ASR on Seabrook Station structure surfaces (per the Structures Monitoring Program) may not provide alone, an adequate means to monitor

(1) ASR progression and

(2) by inference (pending the completion of the testing program), the ASR impact on the affected buildings structural performance. The validation of the use of the CCI and crack width measurements for monitoring the structural impact of ASR has been an objective of the large specimen testing program.

In considering these initial test program results, NextEra staff initiated an Action Report (No. 01952162) to address this issue. In addition to evaluating the future impact of using CCI to monitor ASR progression on affected structures, NextEra staff conducted a preliminary assessment of this test data for impact to their PODs completed for ASR-affected Seabrook structures. NextEra staff concluded this initial test program data does not adversely impact the POD margins analyses, principally because the PODs are not dependent upon measured CCI values for assessing the level of ASR degradation.

Instead, those structures demonstrating the most significant ASR progression (as assumed by CCI and crack width measurements of >1.0 mm/m and >1.0 mm, respectively) were evaluated using conservative and bounding degradation values derived from published research and testing data developed from non-reinforced concrete specimens. At the close of the inspection period, NextEra staff had initiated actions to re-evaluate the use of CCI and crack width for the SMP and to re-evaluate their methods for monitoring and assessing ASR progression of test specimens in order to correlate test data to Seabrook Station.

NextEra staff communicated with the inspectors their plans to fabricate an additional large-scale test specimen to instrument with strain gages and allow ASR progression in order to validate the use of strain gages for through-wall (Z-direction) expansion monitoring. The purpose of this activity is to validate the use of one or more strain gage designs that can subsequently be installed in Seabrook structures to accurately monitor through-wall expansion. In addition, NextEra staff described plans to increase the core sampling of control and ASR-affected large scale test specimens in order to more accurately measure ASR impact on concrete compressive and tensile strength and modulus of elasticity. NextEra staff further communicated plans to conduct petrographic examination of through-wall core samples from the test specimens. This additional concrete material property testing and data collection is intended to be used to support the correlation of testing program structural performance data to Seabrook structures (along with additional, but not yet defined, core sampling of Seabrook ASR-affected structures).

In summary, the inspectors concluded that the PODs completed for ASR-affected Seabrook structures remain unaffected by the X-,Y-and Z-direction expansion data measured, to date, in the test specimens. Actions planned by NextEra to assess the adequacy of the SMP structural evaluation criteria and modify the ASR testing program were viewed appropriate by the inspectors and the Seabrook ASR Issue Technical Team, at this time. As stated above, the PODs use bounding assumptions not dependent on the degree of expansion measured. Additional inspections are planned by the NRC to evaluate NextEras ongoing corrective actions to resolve the non-conformance related to ASR-affected structures at the Seabrook Station.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

Plant Events

a. Inspection Scope

For the degraded plant equipment transient listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. The inspectors reviewed NextEras follow-up actions related to the events to assure that NextEra implemented appropriate corrective actions commensurate with their safety significance.

B steam generator feedwater bypass valve failed to open on March 14, 2014

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Cross-Cutting Aspects

The table below provides a cross-reference from the 2013 and earlier findings and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014 will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.

Finding Old Cross-Cutting Aspect

New Cross-Cutting Aspect 05000443/2013004-01, Inadequate Operability Determination Regarding Service Water Leakage and Associated TS Violation H.1(b)

H.14

.2 Buried Piping, TI-2515/182, Phase 2 (1 sample)

a. Inspection Scope

The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraphs 03.02.a of the Temporary Instruction (TI) 2515/182, and it was confirmed that activities which correspond to the completion dates specified in the program, that have passed since the Phase 1 inspection was conducted, have been completed.

The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the TI and responses to specific questions found in http:www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to NRC headquarters staff.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On April 10, 2014, the inspectors presented the inspection results to Mr. Kevin Walsh, Site Vice President, and other members of the Seabrook Station staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

K. Walsh, Site Vice President

T. Vehec, Plant General Manager

V. Brown, Senior Licensing Engineer

M. Chevalier, RP Supervisor

J. Connolly, Site Engineering Director

D. Currier, Emergency Planning Manager

K. Douglas, Maintenance Director

D. Flahardy, Radiation Protection Manager

M. Ossing, Licensing Manager

V. Pascucci, Nuclear Oversight Manager

D. Robinson, Chemistry Manager

T. Waechter, Nuclear Plant Shift Manager

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000443/2014002-01 NCV Scaffolding Installed with Insufficient Separation to Safety Related Equipment (Section 1R15)