IR 05000354/1989020

Safety Insp Rept 50-354/89-20 on 891107-900105 No Violations Noted.Major Areas Inspected:Operations,Radiological Controls & Surveillance Testing,Emergency Preparedness,Security, Engineering/Technical Support & Safety Assessment

ML19354E337
Person / Time
Site:	Hope Creek
Issue date:	01/18/1990
From:	Kenny T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML19354E336	List: IR 05000354/1989020 ML19354E335
References
50-354-89-20, NUDOCS 9001310022
Download: ML19354E337 (14)

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U. S. NUCLEAR REGULATORY COMMISSION

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REGION I

Report No.

50-354/89-20 License NPF-57 Licensee:

Public Service Electric and Gas Company P. O. Box 236 Hancocks Bridge, New Jersey 08038 Facility:

Hope Creek Generating Station Dates:

November 7,1989 - January 5,1990 Inspectors:

Thomas P. Johnson, Senior Resident Inspector David K. Alisopp, Resident Inspector Paul D. Kaufman, PrQect Engineer

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Glenn M. Tracy, Reactor Engineer f/W Approved:

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py i: ting Chief, Projects

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Inspection Summary:

I Inspection 50-354/89-20 on November 7.1989 - January 5.1990 Areas Inspected:

Routine resident safety inspection of the following areas:

operations, radiological controls, maintenance & surveillance testing, emergency preparedness, security, engineering / technical support, safety assessment / assurance of quality, and Licensee Event Report followup.

Results: The inspectors did not identify any violations. There were three licensee identified, non-cited violations two of which involved personnel errors. An executive summary follows.

9001310022 900122 PDR ADOCK 050003'34 O

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EXECUTIVE SUMMARY Hope Creek Inspection Report 50-354/89-20 November 7, 1989 To January 5, 1990 Operations: An automatic reactor scram occurred on December 30, 1989 which was

caused by a failed main turbine thrust bearing wear detector.

Licensee manage-ment did not achieve their goal for reduction in the number of lit annunciator windows upon restart frcm refueling. The licensee acknowledged this shortcoming and has directed actions to reduce these alarms.

Radiological Control:

Licensee management was noted as being aggressive in the proper conduct and closecut of the drywell prior to unit restart from refueling.

Maintenance / Surveillance: The containment failed the initial integrated leak rate test.

A~ subsequent test was acceptable. A personnel error made by an I&C i

technician resulted in a r eportable event. An error by operations and technical personnel resulted in failure to increase inservice testing-frequency on a valve.

l Emergency preparedness: The licensee's emergency plan implementation and ENS i

calls were appropriate.

Security:

Routine inspections did not identify any unacceptable or noteworthy findings.

• Engineering / Technical Support: A Part 21 notification was appropriately executed. The licensee was aggressive in finding electrical separation and fire protection deficiencies.

Safety Assessment / Assurance of Quality:

Licensee plant management and a Significant Event Response Team (SERT) responded to the December 30, 1989 automatic reactor scram.

These efforts were extensive, timely, and appropriate.

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Details 1.

SUMMARY OF OPERATIONS i

The unit began the report period shutdown conducting the final stages of

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the station s second refueling outage.

The containment integrated leak rate test was completed on November 13, 1989. The unit restarted on November 15, 1989 and criticality was achieved November 16, 1989.

Startup activities and testing were performed and the unit was synchronized with the grid on November 19, 1989.

The unit automatically scrammed from full power on December 30, 1989 due to a main turbine trip.

The unit restarted on January

.1, 1990. After the close of the inspection period, the unit subsequently scrammed from 96% power on January 6, 1990.

2.

OPERATIONS (71707,93702)

2.1 Inspection Activities The insp'ectors verified that the facility was operated safely and in

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conformance with regulatory rcquirements.

Public Service Electric and Gas (PSE&G) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility records. These inspection i

activities were conducted in accordance with NRC inspection procedure 71707.

The inspectors performed 400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> of normal and back shift inspection including weekend and holiday inspection on:

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November 14, 1989 10:00 p.m. - 1:30 a.m.

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December 29, 1989 12:00 noon - 4:00 p.m.

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December 31, 1989 midnight

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2.2 Inspection Findings and Significant Plant Events A.

Inverter 200482 Failure

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While the unit was in cold shutdown, the licensee made an Emergency Notification System (ENS) call at 11:40 a.m. on November 9, 1989 to report a failure of the control switch for inverter 1C0482.

The licensee reported that the loss of this inverter would have prevented the service water system, the safety auxiliary cooling system and the

"C" diesel generator from starting during a loss of power or an accident signal.

The inverter was manually bypassed with backup power.

The licensee repaired the switch and returned the inverter to a normal lineup.

Subsequent licensee followup determined the event was not reportable.

The basis for this conclusion was that the remaining 3 channels

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(A, B and 0) were available to fulfill safety function requirements.

Therefore, this was not a single event / failure which would prevent the fulfillment of a safety function.

The inspector followed up on this event by reviewing the incident report, inspecting in-field equipment and by holding discussions with licensee engir,eering and operations personnel.

The inspector concluded that the licensee made an initial conservative ENS call.

The root cause analysis of the failure was still in progress at the end of the report period. The inspector questioned the licensee with regard to their method of retracting ENS calls that were later found conservative with respect to 10CFR50.72 reporting requirements.

Procedure NA-AP.ZZ-0006 does not delineate the methodology. Apparently, Salem does this by making a " retracting" ENS call and Hope Creek usually initiates a letter.

In this case, Hope Creek did not initiate a letter. A letter retracting the ENS call was promptly sent and licensee personnel indicated that a procedure revision would be considered.

B.

Unit Startup From the Second Refueling Outage The licensee started up the Hope Creek reactor after a two month refueling outage. Control rod withdrawal began on Wednesday night November 15, 1989, and criticality occurred at 12:51 a.m. on November 16, 1989.

Reactor heatup and pressurization was completed upon obtaining adequate chemistry results.

The Unit was synchronized with the grid on November 19, 1989 and full power was achieved on November 23, 1989.

The inspector observed rod withdrawal and criticality, surveillance testing, and power ascension activities from the control room.

The inspector noted that all activities were well planned, coordinated and implemented, and were in accordance with procedures.

With the unit at full power, the inspector observed what appeared to be an excessive number of control room alarms that were illuminated /

alarmed.

For example, at 7:00 a.m. on November 22, 1969, the inspector noted a total of 33 alarm windows that were lit.

(The Hope Creek control room has approximately 500 alarm windows).

Licensee manage-ment had also expressed this concern as demonstrated at the 7:30 a.m.

morning meeting in the control room.

The inspector discussed thie, item with licensee plant and operations management.

The inspector determined that management had not achieved its goal to have less than 10 alarm windows illuminated upon unit restart.

Steps are ongoing to address this item and reduce the number of alarms.

For example, control roem alarm status is reviewed (aily bj plant management and weekly the alarm reduction program is discussed with plant management and updated.

The inspector noted that on December 18, 1989, IS control room alarms were lit.

The inspector reviewed the

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Automatic Reactor Scram on December 30, 1989 Sequence of Events and Licensee Actions i

The Hope Creek reactor automatically scrammed at 7:47 p.m. on December 30, 1989 when the main turbine tripped while at 100% power.

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The scram occurred during turbine thrust bearing wear detector.

testing. Upon completion of the test, the detector did not run back

(reposition) to the neutral position before tl- * -bine trip bypass j

feature became unbypassed. This resulted in a to.bine trip and

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reactor scram.

The licensee initiated repairs to the detector and implemented a modification to bypass the trip feature with a keylock switch during testing.

Conditions were normal during the scram with the exception that one of

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the two low-low set safety relief valves (SRV) did not open.

Reactor pressure increased to 1090 psig and another SRV opened to limit the pressure transient.

The licensee has attributed the failure to drift of the low-low set actuating pressure transmitter, and has replaced and recalibrated the instrument.

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Ouring a drywell inspection in response to an increase in unidentified reactor coolant leak rate (.15 to.28 gpm) while in hot shutdown on December 31, 1989, the licensee noted a pin hole crack in a one 9nch reactor recirculation loop flow instrument line. The crack was located

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in a socket weld for an elbow union approximately 6 feet from the recirculation line. The licensee proceeded to cold shutdown upon discovering the crack and made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS call. The licensee repaired the weld defect by replacing the pipe and elbow union. The licensee inspected 14 other similar weld areas and no additiona1 abnormalities were found.

l The unit was restarted and criticality achieved at 12:44 a.m. on January 3,1990. The turbine was synchronized with the grid at 2:30 p.m.

NRC Review and Conclusions

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The inspector responded to the site to review post scram plant con-ditions and to assess licensee actions.

The inspector reviewed control room instruments and recorder traces, interviewed the on-shift operators, reviewed emergency procedure implementation and reviewed the post scram review checklist (OP-AP.ZZ-101).

The-inspector noted that licensee plant and operations management had responded to the site for scram followup.

In addition, the licensee had initiated a Significant Event Response Team (SERT) to independently review the scram.

(See Section 9.1) The inspector reviewed the revised main turbine functional test (HC.0P-FT.AC-0002) and operator training on

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" Control Room Overhead Annunciator Reduction Program" list and attended several related meetings that addressed this issue.

The inspector concluded that although the licensee initially did not achieve their goal, sufficient management attention is being provided as evidenced by a~ decreasing number of alarms. At the end of the period (prior to the December 31, 1989, scram) 14 alarms were illuminatea.

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Failure to Increase Surveillance Frequency On November 29, 1989, a licensee inservice test (IST) review deter-mined that a surveillance frequency for a Safety Auxiliaries Cooling System (SACS) valve was not increased as required based on IST data taken on JLly 17, 1989. The affected valve, EG-HV-2302B, provides cooling for B filtration, recirculation, and ventilation system recirculation unit.

IST data taken on July 17, 1989 indicated that the valve stroke time (1.87 seconds) constituted an operable valve (since it was less than 5 seconds) but should have been monitored more frequently (since it exceeded 1.5 stconds). Although the failure to Increase the frequency of the IST is similar to other personnel errors which occurred in the July 1989 time frame, this event preceded corrective actions which were implemented as a result of these earlier events. Corrective action included counselling and retraining the personnel involved and incorporating the incident into operations training curriculum.

The inspector concluded that the missed frequency increase for this surveillance test represented a licensee identified violation and would not be cited because tre criteria specified in Section V.G. of the Enforcement Policy were met.

(NCV50-354/89-20-001)

(LER 89-24)

D.

Reported Deviation from Plant Fire Protection Requirements On December 8, 1989, Hope Creek reported a suspected deviation from plant fire protection requirements.

The discrepancy consisted of 28 electrical cables with polyvinyl chloride (PVC) insulation which was initially evaluated as not meeting IEEE-383 standards. These cables were installed on the Safety Parameter Display System (SPOS) during implementation of a design change.

Subsequent investigation determined that cables were acceptable, and the proper controls were in place associated with implementing this design change.

Procurement auality assurance had initially identified this non IEEE-383 qualified cable

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and after their own evaluation determined it was equivalently qualified to IEEE-383. An independent analysis by off-site safety review con-curred with this initial evaluation.

A designer in the field initially observed and questioned the PVC insulated cable utilization.

This process of self-identification and proper resolution of suspected plant deficiencies is roteworthy and should be encouraged.

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utilization of the design change implemented as corrective action.

The inspector concluded that the licensee had performed adequate followup and review of the scram.

Corrective actions were also reviewed and verified to be complete.

3.

RADIOLOGICALCONTROLS(71707)

3.1 Inspection Activities PSE&G's compliance with the radiological protection program was verified on a periodic basis.

These inspe: tion activities were conducted in accordance with NRC inspection procedure 71707.

3.2 Inspection Findings and Review of Events A.

Drywell Tour and Closeout The inspector toured the drywell between 11:00 a.m. and noon on November 15, 1989. The inspector accompanied licensee operations and radiation protection management personnel on the tour. The licensee performed proceduie OP.GP.ZZ-002 to formally closeout the i

drywell prior to unit restart.

The inspector roted that QA and maintenance personnel were also present on this, closeout inspection.

The licensee stopped the formal closeout inspection due to work still in progress. The closeout was completed later in the day.

The inspector noted that the drywell was clean, equipment and material condition was good and no leaks were noted.

4.

MAINTENANCE / SURVEILLANCE TESTING (62703,61726,70313)

4.1 Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards.

These inspections were conducted in accordance with NRC inspection procedure 62703.

Portions of the following activity was observed by the inspector:

Work Order Procedure Description 890923099 IC-CC.BB-037 Reactor Protection System high pressure relay replacement The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance program.

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4.2 Surveillance Testing Inspection Activity l

t The inspectors performed detailed technical procedure reviews, witnessed in progress surveillance testing, and reviewed completed Surveillance packages.

The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications, appreved procedures, and NRC regulations.

These inspection activities were conducted in accordance with NRC inspection procedure 61726.

The following surveillance tests were reviewed, with portions witnessed by the inspector:

IC-CC.SE-15 Channel calib-stion on C Average Power Range

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Monitor (APRM)

IC-CC.SE-016 Channel calibration on D APRM

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IC-CC.SE-020 Channel calibration on Rod Block Monitor (RBM) B

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i IC-FT. SK-010 h.nettonal test of Division 11 steam leak

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detection channel IC-FT. SP-22 Functional test on cooling tower process

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radiation monitor

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IC-FT.SM-005 Functional test on main steam line A pressure

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instrument OP.IS.ZZ 001 Inservice Leakage Test of the Reactor Containment

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Pressure Boundry (RCPB),

Revision 7 RE.ST.BF.001 Control Rod Scram Time Testing

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M9-ILP-01H Containment Integrated Leak P. ate Test

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(CILRT)

The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing program.

4.3 Inspection Findings A.

The inspector observed portions of the CILRT from the control room, the plant and the test control center in the Operations Support Center (050).

Initially, the leakage was excessive and the licensee decided to isolate 5 penetrations (P22, 220, 23, 219, 220).

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penetrations were blanked, and a successful CILRT was completed on November 13, 1989.

The licensee determined that penetration P-220

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was the cause of the failure as valves GS-HC-5031 and 5032 were leaking excessively (Reactor Building to torus vacuum breakers).

Repairs were made and successful local leak rate testing was accomplished.

The final CILRT report will be reviewed by a specialist in a future inspection.

B.

During the preceding inspection on October 11, 1989, a personnel error during a sensor calibration resulted in an engineered safety features actuation. An instrument and calibration technician deviated from the procedure while filling and venting a recently replaced trans-mitter which caused a pressure spike in the associated reactor vessel reference leg. All necessary equipment responded normally to the induced reactor level spike. Corrective action included counselling and retraining the technicians involved and incorporating the incident into the I&C training curriculum.

No similar events have occurred over a two year period and this event date preceded complete implemen-tation of corrective action associated with earlier personnel error events. The inspector concluded that this procedure deviation bec, resented a licensee identified violation and would not be cited rep ause the criteria specified in Section V.G. of the Enforcement Policy were met.

(NCV 50-354/89-20-002) (LER 89-20)

5.0 ENGINEERING SAFETY FEATURE (ESF) SYSTEM WALKDOWN (71710)

5.1 Inspection Activity The core spray and standby liquid control (SLC) systems were evaluated in accordance with NRC inspection procedure 71710 to identify equipment conditions that might degrade performance, to determine that instrumentation was calibrated and functioning, and to verify that valves were properly

positioned and locked as appropriate.

5.2 Inspection Findings The core spray system was inspected and found to be fully functional.

System components were properly identified and labeled.

Equipment tagouts were examined and found satisfactory.

The inspectors observed packing leakage from valves V059, V235, and V012, and seat leakage from valve V9988.

These deficiencies had not been previously identified by licensee personnel.

In addition, items of radiological protective clothing,as well as other items of debris, were found scattered in equipment spaces during the course of the inspection.

The inspector informed operations, QA and radiation protection of these discrepancies.

The licensee initiated action to document the inspectors findings and took adequate corrective actions.

The SLC System was inspected and found to be fully functional.

Specific minor deficiencies were discussed with the system enginee i

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6.

EMERGENCY PREPAREDNESS (71707)

6.1 Unusual Event on November 21, 1989 At 1:45 p.m. on November 21, 1989, the licensee declared an unusual event when a low water level in the Delaware River was experienced.

The low level was due to the combined effects of high winds and low tide. The Delaware River decreased to the low level criterion of 82 ft.

The licensee maintained reactor power steady until the tide turned.

The licensee

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reported that service water pumps (river pumps) had no Net Positive Suction Head problems. The licensee informed the states of New Jersey and Delaware, and the Lower A110 ways Creek Police, as a result of declaring an Unusual t

Event. The licensee terminated the unusual event at 2:20 p.m. when the Delaware River returned to 83 ft.

The inspector monitored the ENS call, reviewed emergency plan implementing procedures, and event classification guides.

The inspector also discussed this event with control room and management personnel.

No unacceptable conditions were identified.

6.2 Loss of Offsite Emergency Si. ens on December 19, 1989 At 10:35 a.m. on December 19, 1989, the licensee made a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> ENS call reporting that the emergency warning sirens were out of service. The licensee was notified by the Salem County Emergency Operations Center of a computer problem which prevented actuation at 10:20 a.m.

This was discovered during a daily testing of the system.

The computer system which initiates the sirens was repaired and returned to service, resulting in another ENS call at 12:29 p.m.

The inspector monitored the ENS calls, reviewed appropriate reporting procedures and discussed the event with licensee personnel.

No unacceptable conditions were noted.

7.

SECURITY (71707)

7.1 Inspection Activity PSE&G's compliance with the security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries.

These inspection activities were conducted in accordance with NRC inspection procedure 71707.

7.2 Inspection Findings No unacceptable ceriditions were noted.

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8.

ENGINEERING /TECHt.ICALSUPPORT(37828,71707)

8.1 part 21 Notification On November 16, 1989, PSE&G made a Part 21 notification regarding misapplication of a magnetrol level switch used on both the high pressure coolant injection (HPCI) and reactor coolant isolation cooling (RCIC)

turbine steam supply drain lines. On high condensation level, this level switch opens a bypass valve around the steam trap to assist the steam trap in removing condensation from the steam line.

PSE&G has experienced failure of these switches at shorter intervals than specified by the vendor (General Electric).

Subsequent investigation determined that the increased failure rate is caused by excessive temperatures in the level switch housing. The potential safety concern is a loss of the HPCI/RCIC function due to failura to keep the steam lines drained of moisture buildup.

This could occur if the normal drain trap failcri concurrent with a level switch failure allowing the subsequent condensation buildup to damage the turbine on startup.

Both the HPCI and RCIC systems utilize Terry turbines which haye proven to be highly reliable regardless of moisture content of the main steam, PSE&G's corrective action included declaring the level switches inoperable and positioning the steam tiap bypass valve in the l

open position thus assuring no moisture buildup.

For long term corrective action the vendor will modify spare level switch assemblies to include an extended, cooling-finned section between the condensate pot portion and the microswitch housing.

The modified switch assembly will still be quali-fied to IEEE 323-1974 and IEEE 344-1975 and should return the microswitch temperatures to within the General Electric qualified life basis.

The inspector verified the corrective action had been properly implemented and reviewed magretrol liquid level detector preventive maintenance end calibration procedure MD-GP.ZZ-055.

The inspector determined that the

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Part 21 notification had been appropriate and properly executed.

i 8.2 Temporary Modifications Review The backlog of active temporary modifications which consist of lifted leads, jumpers, mechanical modifications, and electrical modifications were reviewed to determine their impact on unit startup.

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The entire current backlog of 19 temporary modifications were reviewed and -

evaluated for conformance with licensee aoministrative controls contained in SA.AP-ZZ-13. " Control of Temporary Modification".

The inspectors con-cluded that the temporary modifications were being properly controlled and reverified on a monthly basis as required by the procedure.

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The inspectors reviewed the Temporary Modification Control Log, monthly reverification listing, applicable operational working drawings that were

" redlined" reflecting the necessary plant change, and Limiting Condition Operation (LCO) log to verify that no existing active temporary modification would restrict unit startup.

The inspectors determined that no active temporary modifications would impact unit startup.

However, there were two active temporary modifications which have existed t,ince mid 1986.

These were on non-safety related systems (temperature monitoring and demineralized water). The licensee has issued Design Change Requests (DCRs) for each one, but the formal design change has yet to be approved. The inspector discussed this with the licensee.

The licensee agreed that they should pursue resolution to these long outstanding active temporary modifications. The fnspectors will continue to monitor these outstanding modifications under the routine resident inspection program.

8.3 Deviation From Electrical Separation Criteria Between Transient Monitoring Circuitry and Reactor Protection System Panel Circuitry In the preceding inspection on October 13, 1989, an engineering review determined that two design changes af fecting the General Electric Transient Analysis Recording System (GETARS) violated class IE electrical separation criteria.

The review determined that external class IE power concurrently supplied a GETARS multiplexer and several reactor protection system (RPS) contacts downstream of the multiplexer.

This violation of electric separation had minimal safety significance based on the redundant, fail-safe design of the RPS.

An electrical fault could potentially have been propagated from the ESF panel to the RPS panel via the as-found electrical arrangement. However, any electric fault would have been limited in magnitude by either an inline fuse or a fiber optic link. Any electrical fault which propagated to the RPS would have resulted in the reactor conservatively shutting down.

This design change was prepared in 1986 by (

construction support personnel who are no longer on site.

Corrective action included immediately removing the power supplies which did not conform to electric separation and requirements re powering these GETARS components from appropriate power supplies. The design change process has i

been improved from that in place in 1986 in that the new procedure includes a design input checklist and peer review process. These enhancements should prevent recurrence of similar events.

The inspector concluded that this violation of electrical separation criteria represented a licensee identified violation and would not be cited because the criteria specified

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in Section V.G. of the Enforcement Policy were met.

(NCV 50-354/89-20-003)

(LER 89-21)

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9.

SAFETY ASSESSMENT / QUALITY VERIFICATION (71707,42500)

9.1 Significant Event Response Team (SERT)

In response to the scram on December 30, 1989, the licensee assembled a SERT to review the event. Members from onsite safety review, QA, operations, the technical group, and engineering independently reviewed the sequence of events, operator actions, and plant and equipment functionality. The SERT documented their conclusions and recommendations in a report dated January 3, 1990. The inspector concluded this SERT effort was well planned, or-ganized and implemented.

The station's effort to perform an extensive and timely evaluation of the unit trip is noteworthy and should be encouraged.

10.

LICENSEE EVENT REPORT (LER) AND REPORT FOLLOWUP (90712,90713,92700)

PSE&G submitted the following event reports and periodic reports, which were reviewed for accuracy and adequacy of the evaluation. The

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asterisked (*) items identify reports which involve licensee identified Technica,1 Specification violations which are not being cited based upon meeting the criteria of 10 CFR 2 Appendix C.

Monthly Operating Report for October and November 1989

• LER 89-020 Engineered Safety Features Actuation During Performance of Sensor Calibration; Discussed in Section 4.3.B of this inspection report.

• LER 89-021 Deviation from Electrical Separation Criteria Between Transient Monitoring Circuity and Reactor Protection System Pane'l Circuitry; Discussed in Section 8.3 of this inspection report.

LER 89-022 Loss of Shutdown Cooling due to Reactor Protection System Actuation; Discussed in Section 2.2.B of NRC Inspection Report 50-354/89-17.

LER 89-023 Full Reactor Protection System Initiation During Integrated Leak Rate Testing; Discussed in Section 2.2.0 of NRC Inspection Report 50-354/89-17.

• LER 89-024 Failure to Increase Surveillance Frequency Based on ASME Inservice Test Procedure Results; Discussed in Section 2.2.0 of this inspection repor.,.

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i 11. NRC/PSE&G LICENSING MEETING (94702)

The resloent inspector attended a joint Hope Creek and Salem meeting to i

discuss licensing issues. The meeting reviewed the status of outstanding

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license change requests (LCR) under NRC review and projected LCRs under licensee development.

The discussions were detailed and the meeting informative.

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12.

EXIT INTERVIEW (30703)

The inspectors met with Mr. Joe Hagan and other PSE&G personnel periodi-i c.11y and at the end of the inspection report period to summarize the scope and findings of their inspection activities.

I Based on Region I review and discussions with PSE&G, it was determined that

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this report does not contain information subject to 10 CFR 2 restrictions.

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