ML062540193

To (28 Pages) with Attachments. 03/17/2003 Operational Transient Event at Hope Creek

ML062540193
Person / Time
Site:	Salem, Hope Creek
Issue date:	03/25/2003
From:	Public Service Enterprise Group
To:	Office of Nuclear Reactor Regulation
References
FOIA/PA-2005-0194
Download: ML062540193 (66)

Text

i 0PSEG To:

From :

Date: 3/25/2003 Subj: 3/17/2003 Operational Transient Event at Hope Creek On 3/17/2003 while conducting a reactor shutdown to perform corrective miaintenance an operational transient occurred which resulted in a reactor power, pressure, and level excursion. The plant Was stabilized following this transient and was safely brought to Mode 4, cold.hutdown.

I have pers6nally reviewed the circumstances surrounding this event and commissioned an independent review of the same to ensure the nature of the transient and the operator actions taken as a.result'are fully understood. From these reviews and

-assessments I have concluded, that this transient represents a sibhificant operational event and'that inappropriate operator actions allowed the transient to occur. Additionally, I have concluded that the most appropriate operator action following the onset of the" transient wbould have been io manually scram the reactor to terminate the reactor:power.

excursion. This-action was not taken as I would have expected.

A summary of the circumstances. that led to the plant shutdown, a description. of the event, and the post event a~ctions.that have been taken thus far is attached. I have also included a summary of the most significant performance ihortfalls identified by the independent review team and a timeline of the relevant events and activities. To ensure all necessary corrective actions are identified a root cause investigation has also been initiated.

As theM M f the Hope Creek'Generating Station I aim.

personally responsible and accountable to.ensure I set the highest performanc6 standards and expectations for the safe operation of my facility, and that those standards are consistently reflected in the performance of those who operate my facility. The performance of my staff involved in this event did not meet my expectations. I am upset, very disappointed, and embarrassed that this event could occur under my leadership of the station. I assure y6u that I will take the necessary corrective actions to aggressively and effectively address this significant performance shortfall.

41/

Very Respectfully, In accordance With the. Freedom-of Infoirnation Act, exemptions -"0-

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Background:

On 3/14/2003 at approximately 2200 the Hope Creek main generator was synchronized to the grid following the completion of a planned maintenance. outage.

Upon synchronization it was identified t*hat the #2 turbine bypass valve (BPV) failed to fully close as expected. A technical issues determination process was initiated by the Outage Control Center and a troubleshooting plan was developed to identify the cause of the problem so repairs could be planned and performed. The subsequent troubleshooting indicated that the problem with #2 BPV was most likely 'mechanical in nature and could not be performed with the steam lines pressurized.or with main condense/- vacuum present. The troubleshooting pro. edure also iderifified that the #2 BPV Was stuck open at approximately 45% but would still operate properly to position demands greater than 45%. Since plant conditions were stable it was decided to hold the.plant in it's current condition (20% power, generator synchronized) while plans were developed to address the #2 BPV.

Operating strategies to safely place the plant in the condition necessary to fix the BPV were reviewed. Two basic operating strategies were available to achieve the plant conditions needed:

1) Scramming the redctor.fom. normal operating pressure INOP) and conducting a plant cooldown to cold shutdown. This strategy was the typical methodology used when conducting plant shutdowns. This strategy posed an operational challenge to maintain the RPV cooldo-wn rate within established limits since the core was at end of life and pressu-re control would be difficult following the scram due to the amount of steam that would be used by operating equipment (feedpumps, steam jet air ejeciors) combined with the amount of steam that would be passed by.the stuck open BPV. Operating experience gained-the previous week while conducting a non-nuclear NOP pressure test f6llo Wiing maintenance activities on 2 SRV's showed that thedecay heat from the core was such that the RPV could be co6led.down by opjening main steami line drains. Therefore this strategy would be expected to result in the closure.of the MSIV's to control the cooldown of the RPV anid manual control of RPV water level and pressure using RCIC/ HPCI injection find main steam line drains.

2) Performing a controlled shutdown of the reactor and cooldown of the plant to achieve reactor power less than 5% (in MODE 2) and RP.V pressure less than 650 psig prior to scrammingthe reactor. These plant conditions would allow RPV water level to be maintained in automatic using condensate and would allow main condenser vacuum to be maintained with-the mechanical v'acuuim pumps allowing automatic RPV pressure control using EHC. This strategy would require coordination and control of RPV water level and pressure as the reactor would be operating at low power levels with the intermediate range nuclear instrument (IRM's) inserted and the APRM scram setdown setpoints active.

The second strategy was selected, as it was believed to have the lowest operational risk and was similar in many respects to the plant configurations and

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Y operational lineups seen during plant startups. Recognizing that this strategy was unique in nature it 'Was identified as an Infrequently Performed Test or Experiment (IPTE) and was reviewed by SORC. Industry Operating Experience relative to conducting RPV cooldowns while critical was reviewed and a new procedure section for conducting the evolution was developed. The operating crew who would be performing the evolution was provided simulator training the night prior to performing the evolution. During the simulator training the crew identified that the use of the BPV jack (manual pressure control) allowed a much smoother depressurization of the RPV than reducing the automatic pressure controller setpoint (pressure set) based on their.experience while performing the RPV cooldown the pre*vious week during the maintenance outage.-'hutdown. The crew practiced the evolution by utilizing the BP'Ijack and keeping the pressure set setpoint close to actual RPV pressure.

Event Description The unit shut down commenced on dayshift 3/16/2003 and progressed smoothly into the night shift. Shortly after midnight the reactor was at 6.5% power and 795 "psig with pressure being controlled manually using the BPV jack. While lowering pressure set to be closer to actual RPV pressure a"small perturbation.on the BPV.'.s was noted causing #1 and #3 BPV's to pulse full shut and back open again to their

,original positions. This caused minor changes in reactor power, pressure; and level

(<1%, 7 psig, and 3" respectively). The operating crew stopped the evolution and discussed the response seen. They concluded that the response was due. to pressure control transitioning to the automatic controller from the bypass valvejack as the pressure set setpoint was* being lowered.. The crew then determined that is was: safe to continue by ensuring -sufficient margin was maintained between.the pressure set setpoint and actual RPV pressure.

The BPV jack controller.was then raised to recommence, the cooldown. When the BPV jack pushbutton wasdepressed #3 BPV immediately opened from 0% to 75%.

This unexpected response resulted in RPV pressure being reduced by approximately 50 psig and RPV water level, to lower 8". The NCO controlling RPV water level requested that the pressure reduction be terminated to allow R.PV water level to slowly recover. The NCO:controlling.RPV pressure reduced the BPV jack demand to zero to allow RPV pressure control to transition back onto pressure set. This closed the BPV's (except for #2 BPV which remained at 45%) and RPV pressure began to recover. The reactor water level control system began to automatically.respond to the lowering water level and raised feedflow to the RPV. The RPV pressure and level transient resulted in a rise in reactor power. The NCO controlling reactor power observed the rise in reactor power and manipulated the IRM range switches, one at a time, to maintain thle IRM's within 25-75% the indicating band specified in the Integrated Operating procedure being used for the shutdown. 6 of 8 IRM's were ranged up one range with each IRM range switch manipulation being peer checked by another NCO. Reactor power peaked at 13.5% on the APRM's (7% change in power from the transient) and returmed to the pre-transient level. The NCO controlling RPV

J I.."L L LI L J water level secured air to the startup level control valves to secure feedwater flow to the RPV as RPV water level reached 37". He then utilized the startup level control valves to restore water level to 30". Pressure set automatically stabilized and controlled RPV pressure at 800 psig. The duration of the transient from start to finish was approximately one minute.

Following the transient the IPTE was terminated and notifications were made to the Outage Control Center personnel and to the AOM-shift. After discussing the.

event with the AOM-shift, direction was provided to terminate the use of the BPV jack for reducing RPV pressure and to utilize pressure set as the pressure control means for the remainder of the shutdown &6b'ldown sequence. The remainder of the shutdown and cooldown eVolution was then completed with no other operational challenges.

Event Response:

Although many individuals were aware that the transient occurred during the shutdown sequence it was not communicated to senior management until 2. days f6llowing the transient. The significance of the transient was recognized and the following actions were taken:

> The operating crew involved in the.transient was relieved of licensed operator duties until the circumstances surrounding the transientand their performance is fully understood. While off Shift the crew was assembled and performed a critical self-assessment of their performance.

> A.review of the event was conducted byReactor Engineering to determine the'potential impacttO the fuel as a result of the power transient. It was

• determined that the potential for an'y ad, Verse effects on the fuel was. very small due to the-low power levels which existed it the time of the transient which provided largemargins to thermal limits and fuel pre'conditioning limits.

> Troubleshooting of the BPV systeminidentified a problem with the BPV jack potentiometer. This condition resulted in erralic response of the BPV jack. This potentiometer was replaced during theoutage'and retested satisfactorily.

> Use of the BPV jack control system while the reactor is critical has been prohibited

> An independent review of the event was conducted by an experienced TARP team lead and former SRO using the TARP procedure as guide to ensure the post transient review process was thorough.

> The notification written to identify the event was upgraded by SORC to a Level I (requiring a root cause to be performed). SORC directed that the results of the root cause be presented to both SORC and the Corrective Action Review Board (CARB) when completed.

,ummary

> A remediation plan for the operating crew was initiated consisting of a self-assessment of their performance, completion of a case study review focusing on conservative decision-making, and an oral board assessment.

Completion of the remediation plan will be finalized upon completion of the root cause evaluation.

> An independent review team of former and current SRO's was formed to conduct an independent review of the transient, the crew's actions, and the organizational response to the transient. The team reviewed the circumstances surrounding the evolution, the plant response, the crew's actions taken, and interviewed the~key people involved in the planning and execution of the eolution. This team's review identified the most significant gaps in performance from this transient. The results of this review are attached and will, in turn, be provided to the root cause team for further review and assessment.

IiiucpCHeIiuiL ixeCview:

MeSUIES Safety Significant Issues Failure to manually scram the unit Four APRM upscale rod block alarms were in for approximately 25 seconds, indicated power reached 13.5%. The rate of rise was equivalent to a 70 second period (Note - periods of less than 60 seconds shall not be. maintained when conducting reactor startups). The power change required the manipulation of the IRM range switches to track the power rise and prevent a reactor scram. The IPTE and reactivity briefings had discussed the need to manipulate the IRM ranges switches due to small power changes'antkipated as.a result of charfgiiig pressure. However, the actual power change and rate of fis"that occurred due to the transient was not anticipated.

An unanticipated transient with EHC affected both pressure and feedwater response.

These parameters both directly affect reactor power. In response to the feedwater transient, the operator removed air from the startup level control valve (causing them to close) to terminate the reactor power increase and rising RPV level.

2 Continuifig in the face of adversity/luncertainty The station staff and. management'elected to use the EHC system with both an actual deficiency (#2 BPV stuck open at 45%) and a perceived deficiency (the Crew believed pressure set control was not as smooth as. the BPV jack control While cooling down the plant cooldown based oh.recent operating experience) to shutdown the unit.

Although the evolution could have been safety* conducted as planned and theplant shutdown was delayed to-allow' planning and preparation for the-evolution, the

,decision makers underestimated the level 6f crew and organizational preparation needed for flawless execution.

The crew continued to use the EHC System for reactor pressure.control after the first pressure transient, without fully understanding the cause. Although the transition from.pressture-set to the bypass valve jack had been performed three times that shift prior to the event, the operating c'rew rationalized that ihe anomaly that initially occurred 'was due to normal system dynamics of this same EHC system transition.

The crew continued to use the EHC system for reactor pressure *control after the second pressure transient without fully understanding the cause. Even after the system caused a reactor power excursion, the crew and station staff elected to rely on the EHC system rather than scramming the reactor.

Contrary to station management expectations, the crew did not practice the evolution with the final draft of the procedure to be used. Rather, the crew conducted a procedure V&V and developed the technique and methodology which was to be incorporated in the final version of the procedure. This resulted in the training focus being "what next" versus "what if' as it related to the execution of the evolution.

The operating crew left the training center the night before the evolution familiar with the shutdown strategy but was uncertain whether the plant was going to proceed to

cold shutdown or remain in hot shutdown with the MSIV's closed while repairs were being made to #2 BPV. This decision was dependent on how well RPV pressure could be controlled with the MSIV's open following the scram based on the low decay heat load at end of cycle.

Training did not question the pressure reduction methodology chosen by the crew and deviated from the standard training protocol for "just-in-time" training for infrequently performed evolutions.

3 The notification in regard to this event was not written until thirty-six hours after the event.

Although the operating crew, OCC staff, QA representative, Reactor Engineering representative, IPTE test manager and test engineer, and the Assistant Operations Manager all were cognizant that the plant had experienced an unplanned power increase from 6.5% to 13.5% as a result of this event, the notification was not written until thirty-six hours after the event, and was written as a result of prompting from the Assistant Operations Manger to the Shift Manager that was.on duty at the time of the event.

Senior management-was not informed of the event in a timely manner.

Other Significant Issues 1 The development, assessment, and preparation for the shutdown method used did not sufficiently consider reactivity event risk.

Reactiv ity control relied, in part, on a degraded system regardless of the operating strategy chosen.: Station management and the dperating crew did not ensure the appropriate level of rigor necessary'for flawless execution was present in the preparation. and execution of the evolution.

The.operating crew used the bypass valve jack -with the reactor in the IRM range.

When the jack is in service, 2 parameter's affecting reactivity (control rods and pressure) are *in manual control, requiring additional control room team oversight and coordination for positive reactivity control. Although the proceduire allowed operation of either the bypass valve jack or pressure set, it did not clearly reflect management's expectation that pressure set was the preferred option until the reactor was shutdown.

A.%_ý I L%, VV L%.%_..3LLLLZ) 2 Abnormal procedures were not consulted, and some actions were taken that deviated from or are not contained in station procedural guidance.

The initial method used to reduce reactor pressure was not specifically delineated in the IPTE briefing and violated a procedural requirement to maintain a differential pressure of between 100 to 50 psig between pressure set and reactor pressure while the bypass jack was being used.

During the RPV water level transient, the air was shut off to the Stanup Level Control valve to terminate the power excursio.. Procedural guidance for this action does not exist.

I.,.

The crew-did not implement the applicable abnormal operating procedures for this transient in accordance with management's expectations, Some abnormal operating procedure contingencies were discussed during the IPTE briefing but they were not discussed at a level of detail applicable for the specific evolution. For example, the RPV level malfunction abnormal contingency for inserting a reactor scram at +15 inches was discussed but there was no correlation to what the effect on reactor power would be if level had lowered and then was subsequently recovered.

3 TheIPTE test manager and engineer were ineffective in terminating the test when confronted with uncertainty.

The initial minor event did not result in the IPTE oversight personnel stopping the evolution, and investigating the anomaly with sufficient rigor. Additionally, the IPTE oversight personnel did not recognize that the pressure control methodology being used by the crew deviated from the procedural guidance.

4 Organizational, training, and Cirew lack of sensitivity to the complexity of the task resulted in insufficient crew pr~eparatioin An acceptable, and clearly defined fnd controlled method of pressure. reduction was not established until after the reactivity event occurred. The Assistant Operations Manager provided guidance to the Shift Manager on the method -to be used to -shut

'down the plant post-event. This method, use of pressure-set, and insertion of control rods, resulted in safe, challenge-free operation for the remainder of the shutdown.

This methodology should have been discussed and-practiced during the training session.

LILkL%4 J'.AIU'.,LJL L%.%...V0-VV L%.C:3ULLZ 5 Potential crew knowledge and communication gaps resulted in incorrect decisions being made with respect to using the bypass valve jack.

The crew discussion following the first event with the EHC system did not include the information that the transition from pressure-set mode to the valve jack had been performed at least three times earlier in the eveninrg without event. Had this been understood and effectively communickted to. the OCC and the Assistant Operations Manager, the pressure set meiltodology would have been invoked at that time and the second transient may have been avoided all together.

The discussion led by the Shift Manager between the management team and the Assistant Operations Manager to continue to use EHC to remove the unit from service did not include the information that the transition from pressure-set mode to the valve jack had been performed at least three times earlier in the.evening without event.

Additionally, there was insufficient crew oversight in the control room. Thb Shift Manager and STA wvere stationed by the EHC control panel and, as such, their ability to monitor the overall response of the plant and the crew when the. BPV jack malfunction occurred.

Station Event Timeline 3/14/03 - Friday i1:54 Main Generator is Synchronized, #2 Turbine Bypass Valve does not fully close.

The technical issues process & troubleshooting effort commences.

3/15/03 - Saturday 06:00 Troubleshoofing effort in.,cates problem is mechanical in nature. Shutdown plan development commences.

18:00 Shutdown plan is developed, and procedure draft is produced for verification, validation, and comment.

18:00 Crew commences review of draft procedure and practices method of shutdown in simulator.

18:3 0 A conference call was held between station management, the Outage Control Center, Director-Operations, VP-Operations, and other members of the Seftior leadership team. The conference call communicated the status of # 2 BPV (stuck open @ 45%, problem ismechanical in nature) and that a plant shutdown is required for repair. The discussion includes that plant current status is stable &

safe, and that time will be taken to ensure the correct actions going forward. The Assistant Qperations Manager provides this information; the.Operations Manager is not available at this time, but is cognizantfof the plant status.

23:59 Crew review in siniulator. completedcommenced procedure rievision process, 3/16/03 - Sunday

.06:00 Procedure revised, plan refined, procedure.review process completed.

10:00 SORC review of procedure and approval of method for shutdown completed.

13:44 Commenced shutdown of reactor 14:31 Main Turbine Tripped 18:24 Operational Condition 2 attained, 10% RTP 3/17/03 - Monday 00:07 Commenced pressure reduction from NOP. Reactor power is 7.5%.

I LLIIeLIMI 00:15 First EHC event occurs, resulting in small changes in level and power. Pressure set is in control. Plant manipulations are halted, crew reviews issue.

00:23 Second EHC event occurs, resulting in level transient and power excursion.

Pressure set is in control. After recovery, plant manipulation is halted.

00:30 Teleconference with Assistant Operations Manager with all available management resources (OCC, IPTE, QA, and Shift Manager). Assistant Operations Manager provides specific guidance to the Shift Manager on method for continued shutdown actions.

01:26 Recommenced power andý.ressure reduction 05:34 Manual Scram. Bypass valve #2 closes.

06:00 Assistant Operations Manager is leading effort to ensure organization is aligned to investigate and repair BPV #2.

08:00 Assistant Operations Manager briefs Operations Manager on plant status and the EHC transient. OPS Manager out of state due to emergent family needs.

10:30 VP-Operations contacted to ensure statibn focus and alignment.on investigation and repair of BPV #2.

12:00 Operations Manager, Assistant Operations Manager, Shift Manager, IPTE Manager, QA, and OCC staff are all cognizant of reactivity event. Senior Management including VP-Operations and Director-Operations have not been informed.

13:40 Shutdown cooling 82 psig interlock cleared 17:00 "B" SDC in service 18:00 Operational Condition 4 3/18/03 - Tuesday 06:00 Assistant Operations Manager continues efforts to assure plant is repaired; and that the event is investigated. In addition, he ensures preparation of data to present to SORC for re-start of unit. Operations manager returns to site.

08:00 Shift Manager commences data gathering and writing description of event.

16:22 -Notification written by the Shift Manager to document EHC problem and resultant power excursion.

J.I LL1t-L*ILi 3/19/03 - Wednesday 09:30 SORC restart readiness review conducted. Summary of transient is presented to SORC by the AOM. Potential significance of transient is recognized. The need for more investigation and a better understanding of the circumstances surrounding the transient is identified and discussed between the Operations Manager and Director - Operations.

11:00 Notification is presented at Managers Meeting as a significance Level 2.

14:00 VP-Operations notified of event by Director-Operations and is provided a summary of the event des*'iption and draft evaluation.

17:00 SORC re-convened for re-start readiness review. The notification for the transient is raised to a Level I and a SORC open item is created to have a SORC review of the root cause. Immediate corrective actions for the event were reviewed by SORC and established as startup restraints. These immediate actions included:

Crew removed from watch standing duties Standing order issued prohibiting use of the bypass valve jack when reactor is critical

" Independent review completed to ensure the immediate corrective actions taken were adequate

• Reviewof the event by Fuels/Re actor engineering to assess potential consequences of power excursion."

21:30 Restart restraints completed. Director-OPS discusses completion of immediate corrective actions with VP-Operations and recommendation to restart Hope Creek. Director-OPS authorizes Operations Manager to commence unit startup.

21A:45 Operations Manager authorizes unit startup to commence.

23:00 Mode 2 entered, reactor startup commenced, 3/20/03 -Thursday 09:30 Operations Manager meets with Operating crew sequestered for self assessment and creates understanding of the significance of the event for the crew and communicates self assessment expectations.

10:00 Root Cause team leader designated by Operations Manager.

17:30 Operations Ma'nager debriefs with crew on progress made/ insights gained from self assessment activities.

I IIi111IIC 3/21/03 - Friday 11:00 Crew continues self assessment at training center. Re-enacting transient in simulator.

12:00 Independent review team formed to review the circumstances/ information relevant to the transient to develop a thorough understanding of the event and performance shortfalls.

16:00 Operations Manager and Director-..perations debriefed by crew on their findings and conclude that the crew owns ihe event:and has a good understanding of their performance shortfalls ani&-actions necessary to improve performance.

20:00 VP-OPS briefed on preliminary results of independent review team's findings.

3/22/30 - Saturday 08:00 Independent review continues -findings and conclusion drafted and briefed to Operations Manager and Director-Operations.

3/23/03 - Sunday 08:00 Independent review team conducts interviews with operating crew and AOM.

Crew remediation strategy is developed by AOM and Operations Manager.

21:30 Operations Manager debriefed on Independent review team's findings.

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10 houi r 16 2003 Mon Mar 17 Default\\GRAPHO0I 5033: 10C650CHB237 REACTOR WATER 'Start Sun Mar 15 2003 23:13:00 End: Mon Mar 17 2003 11:35:00 PR-3684B LEVEL LR-2043

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09/24/2002 07:04:04

(-U AT 09/22/2002 00:59:51 S, )

NOTIFICATION

SUMMARY

[VERIFY CURRENT REQUIREMENTS CONTAINED IN NC.WM-AP..ZZ-0000(Q)

"NOTIFICATION PROCESS"]:

1) DESCRIBE THE ACTUAL CONDITION? Steam leak on the bonnett to 22MS42 requires isolation of the main steam to 22 SGFP.

This valve will have to* be leak repaired and is not isolable from the MS header except by closing itself.

The valve is currently closed and the leak is stopped.

Significant quantities of steam and water was deposited in the turbine building and on the group busses.

The following overhead alarms came in J-45 Turbine building 460-230V Bus hot spot, J-39 4KV Group bus Xfer Fail, and A-17 Annunciator ground detect.

The J-45 and A-17 have subsequently cleared, the J-39 alarm remains at this time.

The turbine area sump pumps have their breakers.opened to ensure sumps are sampled or pumped to non rad waste.

2)

HOW DOES THIS ISSUE IMPACT PLANT OR PERSONNEL SAFETY?

22 SGFP is not available.

3)

PSEG NUCLEAR OR REGULATORY REQUIREMENT NOT MET?

Leakage from steam systems.

4)

WHAT CAUSED THE CONDITION?

steam leak on the bonnett.

5)

WHAT ACTIONS, IF ANY, :HAVE BEEN TAKEN TO CORRECT THE CONDITION?.

22MS42 closed and 22"SGFP is tripped.,

6) RECOMMENDED ACTION/CORRECTIVE. ACTION AND WORK CENTER RESPONSIBLE FOR CORRECTING CONDITION.

(USE TITLE/POSITION, NOT NAME)

Leak repair 22MS42.

7)

A.NY OTHER RELEVANT INFORMATION? (WHO,

WHEN, WHERE,

WHY, REFERENCES, ESTIMATED COST,

EMISTAG, ECT)

Unit at 47% power and holding with 22 SGFP out of service.

09/22/2002 16:51:23 f IO(NUM4M)

This notification references 3 separate Overhead alarms which were received during the leak on 22MS42.

A review of the wiring diagrams for these alarms was performed to determine if a common terminal box or junction box may have been wetted which may have caused these alarms and determine if furthur inspection or drying may be required.

A Annunciator Ground detection

- This alarm was most likely caused by the leak and moisture causing a ground on the 125v dc circuit that originates with in the Annunciator system to monitor field contacts. Since alarms J-45. and J-39 also were received falsely it is reasonable to expect that a ground was developed on the annunciator 125v dc.

J-39 Group bus Xfer failure This alarm has wiring which is terminated in the plant area where the leak occurred. Terminations points are with

2 -

in cubicles 2EAD, 2HAD, 2FAD,

2GAD, 21HSD,

21ESD, 22GSD and 22 FSD.

J-45 Turbine Building 460- 230v Bus Hot Spot This alarm also has wiring which is terminated in the plant where the leak had occurred.

Terminations points are at the 2H 460v transformer, 2F 460v transformer, 2F 230v transformer, 2H 230v transformer, 2HL 208-120v lighting transformer, and JT 517 juniction box located at Elevation 116 col.

K14 IK15.

There are no common termination point panels or boxes associated with the alarms that were received except for the c6mmonality of the A!nnunciators ground detection which would be common for both of the ala'rms. Both alarms J-39 and J-45 utilize the annunciator 125V dc to monitor the N.O. contacts for these alarms.

Based upon a walkdown of the area, inspection in a spare 4kv cubicle near the origin of the leak and the fact that the alarms have cleared it is apparent that the moisture from the leak which caused all 3 alarms has dried.

Therefore no furthur action is recommended for this notification.-

09/24/2002

.07:04:13 f(NIMAT)

CRRC NOTE: DOWNGRADED 0 SL-3 AT THE M MEETING ON 09/23/02.

1 -

09/23/2002 15:43:27 (NUDJM)

1) This notification written to document the sudden gasket failure of the 22MS42 valve that occurred on 9/22/0. The body to bonnet gasket of the valve failed in approximately 30 minutes from first indication, resulting the need to secure 22 steam generator feedpump until an emergency leak repair was prepared. The valve' is a William Powell 6.

gate valve. This notification was written to evaluate the gasket design and determine the apparent cause of the gasket.failure so that corrective actions can be taken.

2)

There is no operability issue. An emergency leak repair was performed on 9/22/01 to repair the leak and the 22 steam generator feedpump was restored to an operable status.

3)

This notification is written to determine why the gasket failed and what can be done to prevent future failures. An expectation is that components do not suddenly fail in service as this gasket did.

4)

The apparent cause of the failure is not known at this time. The short period of time between identification of a leak and gasket filure warrants an apparent cause determination.

5)

The valve was leak repaired on 9/22/02.'

6) Assign the CR-Eval to R-PEV. Component Engineering-Valves 7)---This notification submitted b x72.14.

09/24/2002 07:16:31' (NUM3C)

See CR 70027084 (SL-3) for inclusion into this level 2 eval.

09/24/.2002 09:50:26 4(NUMAT)

CRRC NOTE: VALIDATED Al SL-2 AT*F*M MEETING ON 09/24/02.

1 Steam leak on 22MS42 Y1 20113757 09/22/2002 00:59:51 (NUW)

NOTIFICATION

SUMMARY

[VERIFY CURRENT REQUIREMENTS CONTAINED IN NC.WM-AP.ZZ-0000(Q)

"NOTIFICATION PROCESS ] :

1) DESCRIBE THE ACTUAL CONDITION? Steam leak on the bonnett to 22MS42 requires isolation of the main steam to 22 SGFP.

This valve will have to be leak repaired and is not isolable from the MS header except by closing itself.

The valve is currently closed and the leak is stopped.

Significant quantities of steam and water was deposited in the turbine building and on the group busses.

The. following overhead alarms came in J-45 Turbine building 460-230V Bus hot spot, J-39 4KV Group bus Xfer Fail, and A-17 Annunciator ground detect.

The J-45 and A-17 have subsequently cleared, the J-39 alarm remains at this time.

The turbine area sump pumps have their breakers opened to ensure sumps are sitmpied or pumped to non rad waste.

2)

HOW DOES THIS ISSUE IMPACT PLANT OR PErSONNTEL SAFETY?.

22 SGFP is not available.

3) PSEG NUCLEAR OR REGULATORY REQUIREMENT NOT MET?

Leakage from steam systems.'

4)

WHAT CAUSEDýTHE C6NDITION?

steam leak on the bonnett.

5)

WHAT ACTIONS, IF ANY, HAVE BEEN TAKEN 7'O CORRECT THE CONDITION?.

• 22MS42 closed and 22 SGFP is tripped.

6)

RECOMMENDED ACTION/iCORRECTIVE ACT-IONA "D WORK CENTER RESPONSIBLE FOR CORRECTING.CONDITION.

(USE TITLE/POSITION, NOT NAME)

Leak repair 22MS42.

7) ANY OTHER RELEVANT INFORMATION? (WHO, V EN,

WHERE, WHY, REFERENCES, ESTIMATED COST,

EMISTAG, L T)

Unit at 47% power and holding with 22 S'--

out of service.

09/22/2002 16:51:23 I*iT Tlif ('

4M)

This notification. references 3 separatr-verhead alarms which were received during the leak on 22MS4' A review of the wiring diagrams for these alarms was performed -- determine if a common terminal box or junction box may have bee.. wetted which may have caused these alarms and determine if furt ur inspection or drying may be required.

A Annunciator Ground detection T is alarm was most likely caused by the leak and moisture ca sing a ground on the 125v dc circuit that originates with in t a Annunciator system to monitor field contacts. Since alarms 0 45 and J-39 also were received falsely it is reasonable to expe t that a ground was developed on the annunciator 125v dc.

2 -

J-39 Group bus Xfer failure This alarm has wiring which is terminated in the plant area where the leak occurred.

Terminations points are with in cubicles 2EAD, 2HAD, 2FAD, 2GAD,

21HSD, 21ESD, 22GSD and 22 FSD.

J-45 Turbine Building 460- 230v.Bus Hot Spot This alarm also has wiring which is terminated in the plant where the leak had occurred. Terminations points are at the 2H 460v transformer, 2F 460v transformer, 2F 230v transformer, 2H 230v transformer, 2HL 208-120v lighting transformer, and JT 517 junction box located at Elevation 116 col. KI4 K15.

There are no common termination point panels or boxes associated with the alarms that were received except for the commonality of the Annunciators ground detection which would be common for both of the alarms. Both alarms J-39 and J-45 utilize the annunciator 125V dc to monitor the N.O. contacts for these alarms.

Based upon a walkdown of the area, inspection in a spare 4kv cubicle near the origin of the leak and the..fact that the alarms have cleared it is apparent that the mnisture from the leak which caused all 3 alarms has dried.

Therefore no furthur action is recommended for this notification.

09/24/2002 07:04:13 (NUMAT)

CRRC'NOTE: DOWNGRADED HE M MEETING ON 09/23/02.

1 -

22MS42 body to bonnetp Let failure 09/23/2002 15:43:27 NUDJM)

1) This notification written to document the sudden gasket failure of the 22MS42 Valve that occurred on 9/22/0. The body to bonnet gasket of the valve failed in approximately 30 minutes from first indication, resulting the need to secure 22 steam generator feedpump until an emergency leak *repair was prepared.

The valve is a William Powell 6. gate valve. This notific'ation was written to evaluate the gasket design and determine the apparent cause of the gasket failure so that corrective actions can be taken.

2).There is no operability issue. An emergency leak repair was performed on 9/22/01 to repair the leak and the 22 steam generator feedpump was restored to an operable status.

3) This notification is written to determine why the gasket failed and what can be done to prevent future failures. An expectation is that components do not suddenly fail in service as this gasket did.

4)

The apparent cause of the f.ailure is not known at this time.

The short period of time between identification of a leak and gasket failure warrants an apparent cause determination.

5) The valve was'leak repaired on 9/22/02.

6) Assign the CR-Eval to R-PEV. Component Engineering-Valves

7) This notification submitted by x7214.

09/24/2002 07:16:31(NUN3C)

See CR 70027084 (SL-3) for inclusion into this level 2 evai.

09/24/2002 09:50:26 (NUMAT)

CRRC NOTE: VALIDATED M MEETING ON 09/24/02.

Hope Creek 9/16/02 HPCI Outage Critique Executive Summary: The HPCI outage of work week #89 was scheduled for 89 hours0.00103 days <br />0.0247 hours <br />1.471561e-4 weeks <br />3.38645e-5 months <br /> duration and completed in 91 3/4 hours. While the actual and scheduled duration deviation appears to be relatively small, the execution of the work inside the window did not proceed in accordance with the target schedule and various breakdowns resulted in significant deviation from the + four hour schedule adherence requirements of our work management program.

Significant changes to the plan and schedule (with new targets ) were required in order to support recovery on the target system outage duration. There was no emergent fieldwork identified during execution of this window. It appears that the failure to execute the schedule represents a breakdown in organizational and individual accountability. The breakdowns encountered in this system outage were many and the accountability for them can be widely assigned. Each department owned pieces of the problems.

Major problems leading to the breakdowns in schedule adherence include inadequate preparation by maintenance to validate safety tagging boundaries, inadequate resources to execute scheduled work, inadequate walkdown of pre-staged parts, deficiencies in storeroom parts rendering the parts unusable, insufficient supervisory oversight, work interferences not.identified, incorrect job durations, and poor callout response. These issues are explained in detail in this report. While many opportunities exist for improvement, there.were also many positives noted through both the preparation and execution of the window. These positives will also be highlighted in order that they may be carried into subsequent suich efforts.

Preparation:

Tri weekly meetings were held commencing ai T-4 and continiuing to execution week. A "Straw Boss" from Hope Creek Operiations (AOM) was assigned.to provide oversight and assist the Work Week Superintendent incoordination of the system outage. The use of an SRO to perform this roll has benefits in* understanding work integration and system functionality, however, requirements to attend training and stand proficiency watches prevented attendance at all meetings. Meeting attendees included the "Straw Boss",

Work Week Superintendent,'Senior Scheduler, Operations Coordinator, Work Group Coordinators from each discipline, and occasionally Production Engineering and Materials. A detailed schedule review was conducted with an action item database maintained to address issues and their resolution. There was excellent participation by the attendees leading to the development of a well planned schedule. Maintenance supervisors and superintendents were included in some of the meetings in order to obtain their concurrence on the work plan. While the meetings flushed out many problems, the initial schedule had numerous issues requiring resolution that should have been fixed long before the T-4 timeframe. These include:

Identification of work that can be done pre-outage and scheduling of this work in prior weeks (i.e. pre-fab work, scaffolding, hoist inspections).

S:\\Hope Creek\\Shared\\WCCG-SRO\\HPCI Outage\\HPCI Outage Critique.doc

The gear box inspection was determined to have been done during the 12/01 sy~stem outage during a meeting that included a maintenance supervisor who had previously done the work. It was also identified that there had been bearing and alignment tolerance concerns at that time that had required engineering evaluation.

Several significant surveillance orders that were missed during initial scoping (50003596 and 50003600 for rupture disc replacement) required Code Job Package evaluations to be done at T-3. The orders were vague and did not have these operations clearly assigned. Several others had STEX's processed from December 2001 to allow them to reach the 9/16/02 window and were.

still missed from the initial scope (see notification 20111358).

" Coding of work that could be performed outside of the LCO window (i.e.

surveillance tests that do not require HPCI out of.se-vice).

• Decision on appropriate work calendar. We are inconsistent on application of WMAP-I requirement for working LCO windows. It is wrong to say that only "critical path" work needs to be scheduled per the WMAP since as we often find, the "critical path" often changes and this creates gaps in work execution and havoc in trying to schedule the outage;

" Unavailability of required parts (i.e. PSV's for F076 and F077 Cat C replacements. It wa's known back in December 2001, and probably before that, that these valves would need.to be checked, and yet parts were not available.).

" Schedule activities do not exist for MQS"to do weld PT's. These should be incorporated into the work order and scheduled.

A template for the 18 month HPCI outage still does not exist. The outage always follows a standard plan and this should be'captured so that it doesn't have to be created each'time.

Execution:

There were many challenges to work execution. Among the most significant-are the following:

1) The. largest single impact on execution of the schedule was the delay in Mechanical Mairitenance to complete -their walkdown and validation of the safety tagging boundaries. All iagouts were hiung by Operations on schedule, and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> -were allotted and scheduled.for each maintenance group to check their.tags.

This time period was deemed to be acceptable by all groups during schedule preparation, however, it took ovei 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> before Mechanical Maintenance completed walking down the tags. This delay created an immediate conflict that severely challenged the entire schedule. At 1100, the maintenance shop was full of workers awaiting completion of tag walkdowns by chiefs and supervisors. At 1430, mechanics were observed in the HPCI room checking their tags. This could have easily been done in parallel with supervisor walkdowns. Mechanical chiefs brought in for overtime coverage were studying the tagouts late in the afternoon trying to understand the tagging scheme.

Workers and Rad Pro were unprepared for walkdown of components in High Radiation areas even though component locations are provided on the tagging requests. Operations personnel volunteered S:\\Hope Creek\\Shared\\WCCG-SRO\\HPCI Outage\\HPCI Outage Critique.doc

to assist in tagging request explanation and walkdown but were not taken up on Sthe.offer_.The-n*,_masonathe-schedile was not impacted more than it was is due to most scaffolds being installed in the prior week even though the installation activities remained in the-first several hours of the HPCI schedule.

i. Recommended actions:

1. For major system outages with significant tagging, schedule tag walkdowns in prior week to familiarize supervisors with tag locations. Include Ops and RP support. Get more accurate duration for tag walkdown.

2. Scheduled overtime should be able io be asked ahead of time so that workers can prep for the work.

3. Streamline tag walkdowns by having workers and supervisors walkdown tags simultaneously. Workers should targe t specific tags for theirjob. Chiefs and supervisors should take advantage of procedure allowances which allow tag walkdowns to be split among several personnel.

4. Ops identify how many high rad/contaminated area entries are involved for each tagging request, and then give RP this information for their manning plans.

2) Supervisory oversight was lacking during.the first and most critical day 6f the outage. 5-key superintendents and supervisors were sent to GAP training on Monday morning. This occurred even though there were major challenges to schedule execution and their assistance was vital to recovering.the work plan.

The absence of these personnel was not discussed with the prep team prior to execution.

i. Recommended action:

1. Non-production activities should not take precedence over "scheduled work activities. WANO criticized our lack of supervisors oversight and field presence along with our lack of sensitivity to major LCO.windows.

3) On Monday, Electrical identified that the group hadinsufficient resources to begin the battery cell maintenance. One individual called out, and cther personnel were assigned to duties such as Safety Council and IBEW business that had apparently not been accounted for during the schedule review process. The work group had affirmed previously that resources were satisfactory. Electrical was additionally not prepared for work execution as necessary fire impairment was not obtained for battery charger PM. When the impairment was requested Electrical did not emphasize the need for timely response and Fire Protection initially wanted to wait until after lunch to hang the permit. The Ops Coordinator followed up with Fire Protection to get the permit hung immediately. Planned battery cell replacement was changed to a repair effort for the installed cells.

While this was a good recommended corrective action, it should have been identified and resolved weeks earlier. Had cell replacement been needed, the S:\\Hope Creek\\Shared\\WCCG-SRO\\HPCI Outage\\HPCI Outage Critique.doc

required discharge test documentation was not initial, available and had to be obtaineidbyngincerng, Time and manhours were u iecessarily expended as cells were moved from the material center to the Maiý.*nance Shop and back.

i. Recommended actions:

1. Non-production activities shouW i nottake precedence over scheduled work activities. Workers should check in and if scheduled activities cannot be covered then other duties should be deferred.

2. Maintenance and engineering need to work closer on issues where there is a possible "maintenance fix" to the problem.

Job walkdowns for CM work should ask the question !'is there a better way to complete this work".

4) Work on the gear box inspection and valve replacements on the V9966 and V9994 drain pot valves presented an FME conflict that wasi not identified during schedule preparation and review. The late start by Mch-.r*'.al Maintenance exacerbated this conflict as resources had to be spread among these two critical jobs and the gland seal inspection. When work finally commenced Monday night, Mechanical notified the AOM that both the.gear box Qnd gland seal inspections with 1000 scheduled starts and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> planned dural ions would be given priority to work that night over the *Valve replacements which had 1600 starts and 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> durations. This was communicated to the Work Week Superintendent, however, it was not determined that the valve replacement wo.rl: would become critical.path until after the gearbox work failed to start until 0800 ton Tuesday.

L. Recommended action:

1. Future schedule review/readinr'ss meetings need to include an integrated in-field walkdown of work to look for field conflicts like FME.

5) The gearbox inspection was initially scheduled as a. 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> duration (16 work hours on calendar 5). Following the-discovery that tl-_- inspection had been previously completed, the duration was not changed-owever it was discussed that the inspection would be shortened'and probably be.dne only through the inspection access ports vice pulling the gear, box cov-. r. On Tuesday afternoon after an initial inspection via the access ports, mainm ance and engineering decided that the gear box cover' needed to be iemnevc due to the fact that paperwork from the previous inspection documenri' a complete inspection could not be located. This expanded the scope of the ins-.

zion effort and pushed recover of the Iube oil system by 15 1/2 hours fron i original schedule.

Additionally, alignment work was not scheduled s-.,

-the need for alignment was "to be determined by engineering". Mechanical sup, vision and workers were required to work around the clock to complete the insoections.

i. Recommended actions:

1. Order needs to be replanned. The need for an alignment should be evaluated weeks ah, -d of time and incorporated into the schedule.

S:\\Hope Creek\\\\Shared\\WCCG-SRO\\HPCI Outage\\HPCI O01 age Critique.doc

2. All significant changes to planned work scope must be eyvluate-dwiththe Work Week Superintendent for impact to the schedule.

3. Previous work (last recurring task) should be reviewed as part of the T-4 walkdown for work with the potential for expanded scope (inspections, etc.).

6) Work on repack of the F028 drain pot drain line isolation scheduled to start at 1200 on Tuesday was pushed until late Tuesday night when resources from Salem were to become available. These resources were diverted back to Salem on Tuesday night prior to starting workwithout notification being made to the AOM or Work Week Superintendent. This job was identified early as potential for expanded scope due to a long standing packing leak, and we were fortunate that only a repack was required since due to the late start significant valve work would have easily pushed closure of this window. This valve should have been tagged in the open position to facilitate stem inspection.

i. Recommended actions:

1. Changes toresource utilization which impact schedule completion should be approved by the Work-Week Superintendent.

2. Repack activities where stem inspections are needed should have valves tagged open.

7) Work on the condensate transfer system valves V037 and V038 did not start on schedule due to resources being diverted to other work. This resulted in a 7 hour8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> delay in the tagging release.

8) Communications between maintenance/operations and the AOM/Work Week Superintendent'were poordurifig this outage. Very few 1031 -calls were made even though there were numerous schedul.e slips. The poor start to the outage may have contributed to this as the schedule had to be repeatedly modified for some groups and they may have been confused as to what should be reported.

9) The commencement of tagging releases for Oil, Water, Steam, and Condensate Tran.sfer, were initially spread out in the schedule -to make Ops restoration efforts manageable. Due to schedule delays and necessary modifications, the oil release occurred 15 1/2 hours late, the Condensate Transfer release occurred 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> late, and the Steam release occurred 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> late. This put the three major releases on one shift. Although Operations attempted to call in additional personnel when the likelihood of this was recognized Tuesday morning, there was no response.

Problems were complicated further when an NEO called out sick on Wednesday night and an NCO was called for a random off hours FFD. Two NEO's were held over from dayshift Wednesday for an additional 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> when the Water release seemed imminent, but tag release was not given to Ops until 2015 and the extra NEO's were only available until 2200.

i. Recommended actions:

S:\\Hope Creek\\Shared\\WCCG-SRO\\HPCI Outage\\HPCI Outage Critique.doc

1. Ops should consider overstaffing when there are major tagging releases-sckdiled for backshift to account for possible callouts and schedule slips.

10) Several issues were identified with prestaged parts that were defective. The replacement valve for the V026 failed blue check. The spare bearings for the gear box were corroded and pitted beyond use (20112828).

i. Recommended actions:

1. Inspection of parts in. a previous week should be scheduled for critical parts or those with poor histories. Inspections should include things like "blue checks" to ensure parts are good. Either that or set up a more rigorous receipt inspection standard.

11) Hose control was an issue in that a blue (non-contaminated) hose was utilized to drain a portion of the system. Other hoses used were not neatly laid out and presented a tripping hazard to workers.

12) Transient combustible. permits were not acquired for lube oil drums that were staged in the HPCI room. A permit was later obtained, but when an additional drum of oil was' needed a permit was again not obtained.

13) Problems with control of watertight doors was found by an NRC resident.

Workers had left doors open and unattended during cleanup and demobilization.

Despite the many challenges, there were also many strengths realized that should be captured for future outages.

1) Assignment of a "Straw Boss" for the outage helped in focusing preparation and resolving issues during execution. In the future,.the roles and responsibilities of this persor need io be defined so that there is no confusion as to who* is getting status updates.(Straw Boss or Work Week Superintendent). In the fiutire it would be good to i&ycle this duty through Ops, Maintenance, and Engineering so that each group can get insight into the process and its challenges.

2) Pre outage meetings.were held routinely and many schedule issues were resolved.

While the Work Week Specialists represented their departments well, more involvement from the supervisors/superintendents is needed. The meetings where front line personnel participated provided excellent insight, although somewhat late in the process.

3) Operations shifts were given advance notice of their involvement in the outage and provided excellent feedback and assisted in outage review and preparation.

The shifts reviewed and understood the tagouts that they were scheduled to hang and release, and due to this advance preparation were able to recover many hours during tag release and system restoration. Retest and testing binders were' assembled including pre-job briefs and copies of the IST's and retests. Most of the needed hoses and ladders were prestaged at the site and made tagging quicker and easier.

S:\\Hope Creek\\Shared\\WCCG-SRO\\HPCI Outage\\HPCI Outage Critique.doc

4) The main prejob brief for the tagging was completed the night before and only a short rief wa needpdithenighJt of the outage start. This was significant in that tagging was scheduled to commence at 1800 when the shift arrived.

5) Good coordination between scaffold group, Ops, and Safety on determining appropriate access to backdraft dampers prevented safety concerns during execution.

6) Time was scheduled for walkdown of tagouts and pre-job briefings. Durations were not adequate, but concept was good.

7) Cleanup and decon activities were scheduled and resourced. This was a lesson learned from R.CIC which provided an excellent return of the HPCI room post maintenance.

8) Post outage critique was held and lessons learned captured. Attendance was not as good as expected with no representatives from I&C or Electrical.

S:\\Hope Creek\\Shared\\WCCG-SRO\\HPCI Outage\\HPCI Outage Critique.doc

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Performance Partnership Goals and Measures Business Focus Area: Long Term Reliability:

"Achieve Long Term Equipment Reliability through effective use of the Equipment Reliability Process" Shift Managers Goal: Targeted Equipment Reliability Problem areas are understood by all personnel and issues are driven to closure by Shift Managers.

Measures:

" Equipment Reliability 2003 top fixes are completed in 2003 (ER03 list).

" Top 20 target areas show significant reliability improvement via "Rainbow Chart".

Actions to take:

" Shift Managers ensure CRS'sare trained on targeted equipment reliability problem areas and can speak to these areas and the efforts being made to improve.

• Shift Managers lead the organization to ensure completion of all work items identified as top Equipment Reliability 2003 fixes. Challenge removal or deferral of work that falls into these categories. Personal iniervention in the Work Management, Outage, Engineering, and Maintenance departments will be required.

" Shift Managers and CRS's ensure emergent items within the targeted areas are promptly identified and driven to resolution.

" Shift Managers ensure corrective actions for issues regarding targeted equipment reliability problem areas are effective in prev*enting reoccurrence.

" Shift Managers incorporate '.System SRO's" into teams working on targeted equipment reliability problems.

" Work-on targeted reliability equipment is closely tracked by System SRO's and Operations Coordinators to ensure successful completion.

Goal: Scoping and Identification of Equipment Reliability concerns and Critical components minimizes forced loss rate.

Measures:

" Single point vulnerabilities that can cause plant trips or derates are identified and mitigated.

" No forced outages due to previously identified reliability concerns.

Actions totake:

• Shift Managers follow through on incoming notifications and with potential reliability consequences.

Goal: Performance Monitoring reports are validated by Operations and provide meaningful and correct system information.

Measures:

" Unit Analysis Report is utilized by management to focus attention and resources.

" System Health Reports are utilized by management to focus attention and resources.

o Operations Management speaks from facts and with one voice to drive equipment reliability issues.

Actions to take:

• Shift Managers provide expectations to System SRO's to ensure demonstrated ownership of their systems. These expectations should include quarterly reports on systems owned by each SRO, which are reviewed and approved by the Shift Manager and presented to the AOM.

• Shift Managers review and provide insight into Unit Analysis Reports prior to submittal.

Operations Departments sign off on quarterly reports is required.

• Shift Managers ensure System SRO's review and provide insight into appropriate System Health Reports and sign off on quarterly reports. System SRO's meet regularly with designated Performance Engineer to discuss system problems and upcoming resolutions.

Goal: Corrective Actions for Equipment Reliability Problems are effective in preventing recurrence.

Measures:

No repeat root causes for equipment reliability problems.

• All equipment reliability root causes have substantial Operations input.

Shift Managers review and concur with equipment reliability apparent cause corrective actions.

Actions to take:

• Shift Managers ensure Operations Department representatives are involved in all equipment reliability root cause investigations.

• Protocol established for Shift Manger review and concurrence with equipment reliability apparent cause corrective actions.

Goal: Continuing Equipment Reliability Improvement.

Measures:

• Equipment Reliability performance is driven by Operations and high standards are enforced.

Actions to take:

• Leak Management Plan is understood by all personnel, supported by Operations, and low tolerance for leaks maintained through housekeeping, trending, and identification. Operations involvement in condition based monitoring program is evident.

" Shift Managers hold maintenance superintendents accountable to properly repair equipment and return to service in better than found condition.

Shift Managers hold engineering superintendents accountable to follow through on resolution of reliability issues.

• Shift Managers hold all personnel accountable to closely monitor, trend, and maintain equipment in high state of operational maintenance. Use of PAOWF observations to document coaching.

• Shift Managers support and champion ideas for equipment reliability improvement through ERB.

Performance Partnership Goals and Measures Business Focus Area: Long Term Reliability:

"Achieve Long Term Equipment Reliability through effective use of the Equipment Reliability Process" Shift Control Room Supervisors Goal: Targeted Equipment Reliability Problem areas are understood by all personnel and issues are driven to closure.

Measures:

" Equipment Reliability 2003 top fixes are completed in 2003 (ER03 list).

• Top 20 target areas show significant reliability improvement via "Rainbow Chart".

Actions to take:

CRS's are knowledgeable of targeted equipment reliability problem areas and can speak to these areas and the efforts being made to improve. CRS's train NCO's and NEO's on target areas.

CRS's ensure emergent items within the targeted areas are promptly identified and driven to resolution.

"System SRO's" participate in teams working on targeted equipment reliability problems.

Work on targeted reliability equipment is closely tracked by System SRO's to ensure successful completion.

Goal: Scoping and Identification of Equipment Reliability concerns and Critical components minimizes forced loss rate.

Measures:

" Single point vulnerabilities that can cause plant trips or derates are identified and mitigated.

" No forced outages due to previously identified reliability concerns.

Actions to take:

System SRO's take lead in working with Reliability Engineering to incorporate EOOS reliability model.

• CRS's appropriately prioritize incoming notifications and flag those with potential reliability consequences.

• Backlog work is prioritized and validated through T-16 walkdowns.

• PM feedback is provided by Operations and attention is given to flagging unnecessary PM's both within and outside Operations to allow focus on more critical work.

Goal: Performance Monitoring reports are validated by Operations and provide meaningful and correct system information.

Measures:

" Unit Analysis Report is utilized by management to focus atiention and resources.

" System Health Reports are utilized by management to focus attention and resources.

• Operations Management speaks from facts and with one voice to drive equipment reliability issues.

Actions to take:

• System SRO's meet expectations to ensure demonstrated ownership of their systems. These expectations include preparation of quarterly reports on systems owned by each SRO, which are reviewed and approved by the Shift Manager and presented to the AOM.

System SRO's review and provide insight into appropriate System Health Reports and sign off on quarterly reports. System SRO's meet regularly with designated Performance Engineer to discuss system problems and upcoming resolutions.

Goal: Corrective Actions for Equipment Reliability Problems are effective in preventing recurrence.

Measures:

" No repeat root causes for equipment reliability problems.

• All equipment reliability root causes have substantial Operations input.

" Shift Managers review and concur with equipment reliability apparent cause corrective actions.

Actions to take:

Sys!em SRO's are aware of root a.nd apparent cause investigations on systems under their ownership and provide insight into recommended corrective actions.

Goal: Continuing Equipment Reliability Improvement.

Measures:

Equipment Reliability performance.is driven by Operations and high standards are enforced.

Actions to take:

Leak Management Plan is understood by all personnel, supported by Operations, and low.

tolerance forleaks maintained through housekeeping, trending, and identification. Operations involvement in condition based monitoring program is evident.

CRS's hold maintenance supervisors accountable to properly repair equipment and return to service in better than found condition.

• CRS's hold engineering supervisors accountable to follow through on resolution of reliability issues.

CRS's hold NEO's accountable to closely monitor, trend, and maintain equipment in high state of operational maintenance. Use of PAOWF observations to document coaching.

• CRS's solicit and champion ideas for equipment reliability improvement through ERB.

OPERATIONS EXCELLENCE - 2003 PERFORMANCE Cn)AIR SAFETY Human Pei-formnance and Safety Goals:

I will not get hurt. I am alert and identify potential hazards to ensure the safety of others and myself.

I will ensure no one gets hurt - (station wide when I am the on-shift SM) (in my group when I am an off-shift SM).

I will wear my PPE as required.

a As the on-shift SM, I.will ensure station shift personnel have access to the right tools, procedures, and PPE to safely and effectively do their jobs.

o As an off-shift SM, I will ensure my associates have access to the right tools, procedures, and PPE to safely and effectively do their jobs and the product my group produces identifies or provides for the same to 13romote safe and effective job execution.

As the on-shift SM, I will not only participate in, but also insist on pre and post job briefs and that the safety manual is referred to during them - station wide.

As an off-shift SM, I will insist that the product my work group produces promotes/allows for pre and post job briefs and that the product is in full compliance with safety manual requirements.

I will have a questioning attitude regarding the safety aspect of all (activities that occur - station wide for on-shift SM assignment) (products my group produces for off-shift SM assignment).

I will be aware of my expected exposure for every entry into the RCA.

I will co nduct PAOWF observations in accordance With all Director and Departmental expectations; I will document observable adherence to safety standards and use the PAOWF system to improve station safety perfo'rmance.

I will use Self-Assessments, the CAP, and Training Programs to improve station safety performance.

I will ensure all (station shift personnel for on-shift SM assignment) (my associates for off-shift SM assignment) use the CAP to improve station safety performance.

I will follow all procedures.

I will champion maximum attendance at the PSEG Human Performance I Safety day.

I will champion 100% attendance at Safety / Human Performance Simulator Training.

I will ensure the 19 Health and Safety System Components and the Safety Council Leadership positions are inculcated into our day-to-day operations to achieve an incident free workplace (at the station shift associates level for on-shift SM) (at my group level for off-shift SM).

Measures:

As the on-shift SM, there will be noaccidents or injuries at the station that cause the OSHA Recordable Incident Rate to exceed 0.25 for the site.

As an off-shift SM, there will be no accidents.or injuries in my group that cause the OSHA Recordable Incident Rate to exceed 0.25 for the site S4th Quarter'Safety Culture Survey score >85% indicating an -involved workforce knowledgeable in the health and

-safety system components and their Council leadership Plant Configuration E

Goals:

-Measures:

3E - 2003 PERFORMANCE GOALS RELIABILITY Long Term Reliability W h Goals:

Measures:

Summer Capacity Fact o"

in Goals:

• -No forced de-rates during summer peak period of May 15 to Sept 15 Turbine Valve Testing Improvements Hope Creek Core Design optimized to avoid control rod pattern adjustments during summer months Measures:

100% capacity factor during summer No forced outages No forced unit de-rates due to equipment failures or personnel error Turbine Valve Testing interval increased to support 100% power through summer months Turbine control valve testing is performed at maximum safe power level No down powers for control rod pattern adjustments during summer months Work Management Goals:

.Measures:

OPERATIONS EXCELLENCE - 2003 PERFORMANCE GOALS

$ COST Improve Outa-ge Performanc Goal:

ensure outage milestones and goals are met ensure outage dose improvement suggestions are generated and considered ensure outage vs. on-line philosophy and outage scope control process is established and understood ensure outage scope is identified ensure outage staffing plan is in place ensure outage-related license changes and. plant modifications are identified to improve outage durations Measures:

total outage days < 66 days total outage dose < 226 REM total outage cost < $51 M maintain 2% scope stability production rate of 500 activities per da

>100 day run following outages Implement Effective Prole cts.v Goals' Measures:

Financial Control -iRL Goals:

Measures:

O)PERATIO)N5q FXCFl IFNCE - 2003' PERFORMANflF rnAt S

© PEOPLE Integrated Labor Plan J*

Goals:

Develop a forward-looking department overtime management process that effectively controls department overtime costs and trains CRSs to effectively implement the process' Train CRSs to effectively manage workforce availability. Include hierarchy of corporate practices through NBU and department practices, and associated documentation requirements.

o Identify decision-making and communications skills necessary to effectively communicate work tasks /job assignments, management policies, equipment maintenance prioritization, and NBU processes. Shift Managers train CRSs to develop aforementioned skill sets.

Measures:

• . Overtime costs 'less than I equal to' 2003 year end overtime budget Department unavailability <4%

Department workforce turnover rates <6%

Gallup Survey scores continue to improve Human Performanc Goals:

1 will read and internalize the Managers' Human Performance Briefing Book and all Tool Kits by 3/31/03. I will fMlfill the roles and responsibilities of a manager (and supervisor when applicable) contained therein. Also, I will

-efsuFe-al-46tatieR-Shft asseOGiatesfer-eR-shift-SM) (my assGiates-for ff shift SM) *rc e-aae-ef4he4-GHman Error Traps and how to recognize and mitigate themr..

YWhen the Human Performance Procedure/Policy is issued, I will read and internalize it within one month of issue.

I will ensure the weekly human.performance eiror trap and mitigating tool rollouts'provided by. the Continuous Performance Improvement Group (CPIG) are effectively communicated in their entirety to all (station shift associates for on-shift SM) (my associates for 6ff-shift SM) AND they 'hderstand the error traps and mitigating tools.

As the on-shift SM, I will not only. participate in, but also insist on proe and.postjob briefs and that all human error traps and mitigating strategies are covered during them -.station wide.

As an off-shift SM, I Will insist that the product my work groupproduces promotes/allows for pre and post job briefs and that the product inherently minimizes human error traps.

1. will have a questioning attitude regarding the human performance aspect of all (activities that occur - station wide for on-shift SM) (products my group produces for off-shift SM).

I will conduct PAOWF observations in accordance with all Director and Departmental expectations; I will document observable adherence to human performance standards and use the PAOWF system to improve

.station human performance.

I will dontribute to the RF11 I Human Performance Lessons-learned hotline during RF1 1 to identify ways to improve station human performance in RF12.

I will be fit for duty and alert to the 10 Human Error Traps.

I will self-check via STAR and QW.

I will be clear and concise in my communications using three-point communications when appropriate.

I will use Self-Assessments, the CAP, and Training Programs to not only track and trend human performance, but also to improve iL My efforts in these programs will positively impact FEAT POC TOL.

I will ensure all station personnei use the CAP to improve station human performance I will follow all procedures I will champion 100% attendance at Safety / Human Performance Simulator Training Measures:

there will be no station forced outages, downpowers, or LERs that are a result of station shift human performance issues.

there will be no Event Free Clock Resets at the station that cause the site reset periodicity to be less than 25 days.

OPERATIONS EXCELLENCE - 2003 PERFORMANCE GOALS

OPERATIONS EXCELLENCE - 2003 PERFORMANCE GOALS SAFETY Human Performance and Safety Goals:

I will not get hurt. I am alert and identify potential hazards to ensure the safety of others and myself I will ensure no one gets hurt on my shift

° I will wear my PPE as required.

I will ensure my shift personnel have access to the right tools, procedures, and PPE to safely and effectively do their jobs a

I will not only participate in, but also insist on pre and post job briefs and that the safety manual is referred to during them at all times I will have a questioning attitude regarding ihe safety aspect of all activities that occur onmy shift I will be aware of my expected exposure for every entry into the RCA.

I will conduct PAOVVF observations in accordance with Departmental expectations; I will document observable adherence to safety standards and use the PAOWF system to improve my OPS shift's safety performance.

I will use Self-Assessments, the CAP, and Training Programs to improve station safety performance.

I will ensure all my associates use the CAP to improve station safety performance.

I will follow all procedures.

• . I will champion maximum attendance at the PSEG Human Performance Safety day.

I will champion 100% attendance at Safety I Human Performance Simulator Training.

I will partner with my Safety Repres'entative to ensure the 19 Health and Safety System Components and the Safety Council Leadership positions are inculcated into our day-to-day operations to achieve an incident free workplace at the shift associate level Measures:-

there will be no accidents or injuries on my shift that cause the OSHA Recordable Incident Rate to exceed 0.25 for the site.

4* Quarter Safety Culture Survey score >85% indicating an involved workforce knowledgeable in the health and safety sistem components and their Council leadership.

Plant Conficturation1mt

• Goals:

Measures:

M ---

A Z.4

OPERATIONS EXCELLENCE - 2003 PERFORMANCE GOALS RELIABILITY Long Term Reliabilit' Goals:

0 Measures:

Summer Capacity Factor Goals:

° No forced de-rates during summer peak period

• ,Turbine Valve Testing Improvements a Hope Creek Core Design Optimized to Avoid Control Rod Pattern Adjustments During Summer Months Measures:

0 100% capacity factor during summer No forced outages No forced, unit de-rates due to equipment failures or personnel error Turbine Valve Testing interval increased to support 100.% power through summer months Turbine control valve testing is performed at maximum safe power level a No down powers for control rod pattern adjustments during summer months Work Managemen.

Goals:

Measures:

Page 2 of 2

OPERATIONS EXCELLENCE - 2003 PERFORMANCE GOALS

$ COST Improve Outage Perforimanc Goals:

• map) meet department outage milestones prepare and implement outage schedule to meet outage goals generate and champion outage improvement suggestions to improve dose performance, outage efficiency, and outage durations understand and implement outage vs. on-line philosophy and outage scope control.process identify outage items identify outage-related license changes and plant modifications to improve outage durations Measures:

total outage days < 24 days a

total outage dose < 116 REM total outage cost < $23.5M maintairi 2% scope stability production rate of 500 activities per day

>100 day run following outage Implement Effective Projects" Goals:

Measures:

FinancialCo6n Goals:

Measures:

a

OPERATIONS EXCELLENCE - 2003 PERFORMANCE GOALS

© PEOPLE osnte-rated Labor Plan Goals:

CRSs implement the department overtime process to effectively control department overtime costs. Including effective implementation of overtime rules, efficient control of electronic staffing roster databa.se, effective and efficient management and awareness of direct reports work assignments and locations, 100% time reporting accuracy by direct reports.

CRSs effectively manage workforce availability in accordance with corporate and NBU practices; and maintain all required documentation accurate and up to date.

• CRSs exhibit skillsets and related knowledge of work prioritization and business decision making needs, and management policies and processes, including familiarization and successful implementation of Work Managetnent procedures...???

Measures:

Overtime costs 'less than I equal to' 2003 year end overtime budget Department unavailability <4%

Department workforce turnover rates <6%

Gallup Survey scores continue to improve.

The above-listed items need polish to align them with the Performance Partnership Guide content and format recommendations for Establishing Expectations.

Human Perfor anc*

f Goals:

I will read and internalize the Managers' Human Performance Briefing Book and all Tool Kits by 3 131/03. I will fulfill the roles and responsibilities ot a supervisor contained therein. Also, I will ensure all of my shift personnel are aWare of the 10 Human Error Traps.and how to recognize and mitigate them.

When the Human Performance Procedure/Policy is issued, I will read and internalize it within one month of issue.

I will ensure the weekly human performance error trap and mitigating tool rollouts provided by theContinuous Performance Improvement Group (CPIG) are effectively communicated in their entirety to all my OPS shift personnel AND they understand the error traps and mitigating tools.

I will not only. participate in, but also insist on pre and post job briefs and that all human error traps and mitigating strategies are covered during them AND I.will use the pre-job briefing checklist at all times.

I will have a questioning attitude regai'ding.the human performance aspect of all activities that occur on my shift

.0 I will.conduct PAOWF observations in accordance with Departmental expectations; I will document observable adherence to human performance standards and use the PAOWF system to improve my OPS shift's human performance.

I will contribute to'the'RF11 Human Performance Lessons-learned hotline during RF11 to identify ways.to improve station human performance in RF12.

I will be fit for duty and alert to the 10 Human Error Traps.

I will self-check via STAR and QW.

I will be clear and concise in my communications using three-point communications when appropriate.

I will use Self-Assessmehts, the CAP, and Training Programs to not only track and trend human performance, but also to improve it. My efforts in these programs will positively impact FEAT POC TOL.

a I will ensure all my shift associates use the CAP to improve station human performance.

I will follow all procedures I will champion 100% attendance at Safety / Human Performance Simulator Training.

Measures:

there will be no station forced outages, downpowers, or LERs that are a result of human performance issues on my OPS shift there will be no Event Free Clock Resets caused by my shift that cause the site reset periodicity to be less than 25 days.

Work Environment Goals:

Measures:

PI:: n A nf A

OPERATIONS EXCELLENCE - 2003 PERFORMANCE nOAl R I.

Page 5 of 5

OPERATIONS EXCELLENCE - 2003 PERFORMANCE rOAl £A

0) SAFETY Human Performance and Safet Goals:,

I will not get hurt. I am alert and identify potential hazards to ensure the safety of others and myself.

J.1 will ensure no one gets hurt in my group I will wear my PPE as required I will ensure my associates have access to the right tools, procedures, and PPE to safely and effectively do their jobs and the product my group produces identifies or provides for the same to promote safe and effective job execution As an off-shift SRO, I will insist that the product my work group produces promotes/allows for pre and post job briefs and that the product is in full compliance with safety manual requirements.

I will have a questioning attitude regarding the safety aspect of all products my group produces I will be aware of my expected exposure for every entry into the RCA.

I will conduct PAOWF observations in accordance with Departmental expectations; I will document observable adherence to safety standards and use the PAOWFsystem to improve my OPS shifts safety performance.

I will use Self-Assessments, the CAP, and Training Programs to improve station safety performance.

I will ensure all my associates use the CAP to improve station safety performance.

I will follow all procedures.

I will champion maximum attendance at the PSEG Human Performance / Safety day.

I will champion 100% attendance at Safety / Human Performance Simulator Training.

I wiil partner with my (OPS shift/group) Safety Representative to ensure the 19 Health and Safety System Components and the Safety Council Leadership positions are inculcated into our day-to-day operations to

achieve an incident free workplace at my group level d

a t

-Measures:

a there will be no accidents or injuries in my group that cause the OSHA Recordable Incident Rate to exceed 0.25 for the site 40 Quarter Safety Culture Survey score >85% indicating an involvedworkforce knowledgeable in the health and safety system components and their Council leadership.

Plant Confinuiatio Goals:

Measures:

OPERATIONS EXCELLENCE - 2003 PERFORMANCE GOALS RELIABILITY Long Term Reliabii Goals:

Measures:

Summer Capacity Factor Goals:

No forced de-rates during summer peak period Turbine Valve Testing Improvements Hope Creek Core Design Optimized to Avoid Control'Rod Pattern Adjustments During Summer Months Measures:

100% capacity factor during summer No forced outages No forced unit de-rates due to equipment failures or personnel error Turbine Valve Testing interval increased to support 100% power through summer months Turbine control valve testing is performed at maximum safe power level No down powers for control rod pattern adjustments during summer months Work Manaq gen Goals:

Measures:

0°

OPERATIONS EXCELLENCE - 2003 PERFORMANCE COC)AlS

$ COST Improve Outage Perfomna ncr Goals:

meet department outage milestones prepare and implement outage schedule to meet outage goals generate and champion outage improvement suggestions to improve dose performance, outage efficiency, and outage durations understand and implement outage vs. on-line philosophy and outage scope control process identify outage items identify outage-related license changes and plant modifications to improve outage durations Measures:

total outage days < 24 days total outage dose < 116 REM total outage cost < $23.5M maintain 2% scope stability production rate of 500 activities per day

>100 day run following outage Implement Effective Pro iec Goals:

Measures:

_F in a-nca ETConTr o I

Goals:

Measures:

OPERATIONS EXCELLENCE - 2003 PERFORMANCE GOALS

© PEOPLE integrated Labor Plan~i Goals:

I

& CRSs implement the department overtime process to effectively control department overtime costs. Including effective implementation of overtime rules, efficient control of electronic staffing roster database, effective and efficient management and awareness of direct reports work assignments and locations, 100% time reporting accuracy by direct reports.

• CRSs effectively manage workforce availability in accordance with corporate and NBU practices, and maintain all required documentation accurate and up to date.

CRSs exhibit skillsets and related knowledge of work prioritization and business decision making needs, and management policies and processes, including familiarization and successful implementation of Work Management procedures...???

Measures:

Overtime costs 'less than I equal to' 2003 year end overtime budget Department unavailability <4%

Department workforce turnover rates <.6%

Gallup Survey scores continue to improve.

The above-listed items need polish to align them with the Performance Partnership Guide content and format recommendations for Establishing Expectations.

Human Performance Goals:

I will read and internalize the Managers' Human Performance Briefing Book.and all Tool Kits by 3131/03. will fulfill the roles.and responsibilities ot a supervisor contZtrred-therei-ttsoi-hwil-ensure-al-rmy-ass6ciates-are-aware of the.10 Human Error Traps and how to recognize and mitigate them.

• When the Human Performance Procedure/Policy is issued, I will read and internalize it within one month of issue.

I will ensure the weekly human performance error trap and mitigating tool rollouts provided by the Continuous Performance improvement Group (CPIG) are effectively communicated in their entirety.to all my associates AND

!hey understand the error traps and mitigating tools.

I will'insist that the product my work group produces promotes/allows for pre and post job briefs and that the product inherently minimizes humari error traps.

will have' a qiiestioning attitude regarding the human performance aspect of all products my group produces I will conduct PAOWF observations in accordance with Departmental expectations; I will document observable adherence to human performance standards and use the PAOWF system to improve my OPS shift's human performance.

I will contribute to the RFI 1 Human Perf6rmance Lessons-learned hotline during RN 1 to identify ways to improve'station human performance in RF12.

• I will be fit for duty and alert to the 10 Human Error Traps.

I will self-check via STAR and QW.

I will be clear and concise in my communications using three-point communicatiohs when approopriate.

I will use Self-Assessments, the CAP, and Training Programs to not.only track and trend human performance, but also to improve it. My efforts in these programs will positively impact FEAT POCTOL I will ensure all my associates use the CAP to improve station human performance.

• I will follow all procedures I will champion 100% attendance at Safety / Human Performance Simulator Training.

Measures:

there will be no station forced outages, downpowers, or LERs that are a result of human performance issues within my group there will be no Event Free Clock Resets attributed to my group that cause the site reset periodicity to be less than 25 days.

Work Environment Goals:

\\.

Mea~ures:

C)PFRATIONS EXCELLENCE - 2003 PERFORMANCE GOALS I

!Is L-

LEADERSHIP AT PSEG NUCLEAR WHAT IS LEADERSHIP?

Webster's dictionary defines leadership as "the ability to lead". In its. simplest terms, to lead means to "show the way". In business, as in life, simply showing someone the way doesn't quite capture the essence of leadership. At PSEG Nuclear, we believe leadership is the ability to:

Define your vision as a reality, Continuously mold a team and involve them in a way that results in a shared understanding of that vision, and Develop the individual team members in a caring and nurturing way so that their strengths become integral parts of the success you wish to achieve, their weaknesses do not hinder the progress of the team, and their growth ensures your vision is carried on in your absence.

We believe that there was an emotional side to leadership that involves the ability to deeply care about the team's goal, the team members themselves, and the impact the team is to have on the company. We believe that the opportunity and a real need exist how for true leaders at PSEG, 'We also believe that the atmosphere has changed such that true leaders have an opportunity to emerge.

Leadership is now being defined a little bit differently, and the emotional intelligence necessary to be a successful leader is now valued as much, if not more, than the technical qualifications required for the job.

WHAT BEHAVIOURS DOES A LEADER DISPLAY?

Each Vice-President has contributed to~the definition.of leadership that is contained withinathis document. In support of this ai set of leadership attributes has been identified that captures -the essence of leadership here at PSEG. These attributes are:

Own the whole Focus on and achieve end results at PSEG Nuclear The accept ownership of PSEG Nuclear's performance.and drive for Top' Quartile in Safety, Reliability and Cost through people.

Energy To create change Relentless pursuit of results Totally committed Creates alignment/teamwork - build partnerships, focus on integration and alignment, up/down/horizontal Tenacity and persistence - to implement change and improve performance Energize Others Own success and failure of their personnel Holds themselves and others accountable Creates trust and an open environment I

Creates leadership in others - who then go for exc. Hlence Inspires others Develops people Champion change Edg*e Drives and creates change (get better every day)

Self-initiate ideas and results Yes/no'not maybe (decisive, action oriented)

Create healthy tension Words and actions consistent

cute Deliver results Know the details-they put their eyeball on the scene and know what is going on Exe Knowledge - they know that they are talking about Recognizes People They celebrate results with their people Talk about people. not themselves when discussinr, succe=.s WHAT ARE WE DOING TO IMPROVE THE QUALITY O LEA DERSHIP HERE AT PSEG NUCLEAR?

As a result of our own assessments, observations by our stake-tolders, and feedback from our people,.we identified a GAP between where we were and where we needed to be in the area of leadersh.ip. The following efforts were put in placc to make a step-change in our leadership:-

1)

A new leadership team was org ariized e

2)

A leadership coach was hiied. to work with the team and develop leadership skills throughout the organization (Kymn).

ve'7eaesi

3)

A.strategy was developed to significantly improve :heleadership skills of our people using the following courses:

a. First line.supervisors attended the Supervisor's Leadership Academy.

b. Managers attended the Power Leadership Exco'lence Course.

4)

Individuals Who graduated from the courses note.

bove have developed a support network that includes the Gung Ho wet, s". and teami meetings.

5)

The Gallup Organization was retained to rneastr ur ascent to Top quartile Leadership via the Gallup survey. The repetitiv.,

ministration of the Gallup Survey enabled us to measure our journey on th:

dd to excellence.

Additional measurement tools used to determine our success v.ould include the corrective action process, our performance indicators, and the event free Jock. Thie ultimate measurement tool for PSEG Nuclear would be the SRC throughi P performance indicators that have been developed over the past several years. Simply r,ut, we have determined that we will measure our success using the following metrics:

2

Safety - INPO index Reliability - Capacity factor Cost - Cents per KW People - The results of the Gallup Survey and "Smiles on the faces or our employees".

EVIDENCE Since we have determined.to reach excellence through our leadership, the folloviing improvements have been.identified:

1)

Significantly'improved professionalism in the control rooms at both Salem and Hope Creek.

2)

A reduction in the number of grievances in Operations.

3)

A reduction in the number of Licensee Event Reports generated - Salem 2R12 was completed without an LER.

4)

Top Quartile performance in radiation exposure at Hope Creek.

5)

Significant ownership of the Line of Business Safety Councils by the IBEW.

6)

A significant reduction in the corrective maintenance backlog.

7)

A significant increase in Gallup Scores.

The following Gaps exist between our current performance and wheie we want to be.

1.) All managers have not attended the Leadership Excellence Course

2) Gallup survey scores are not Top Quartile.

3) OSHA recordableincident. rate is not on target for 2002.

3

A Senior Operator's Leadership Philosophy By: An unnamed Senior Operator Introduction This document is intended to represent a consensus of professional philosophy shared by each Senior Operator. It reflects bits of idealism and omits an occasional cynicism. It is written in the subjective to reflect the individualism that must be present for any philosophy to exist in a practical form.

Authority and Responsibility.

The word "authority" and "responsibility" go together. How can anyone have one without the other? I have the "responsibility" for the operation of my plant in accordance with the directives and guides which I've been given, therefore, I have all the "authority" I need to satisfy myself that I'm fulfilling my responsibilities. Only someone who hasresponsibilities that are broader than mine and that encompass mine has the responsibility and authority to change my guides or directives, issue me orders, or to assume my responsibilities. I've got "it' and if I err, I'll do so on the side of assuming too much responsibility and authority rather than too little - particularly wnere none of my bosses are avaflabIde-ad,-needo-onake-a-decosirn-with.out-waitgr-totarify the situation.

I'm sensitive to the desires expressed by my boss. I fully discuss any controversial matter with him, particularly if it involves safety. I make sure he uriderstands the basis of my concern, and the fact that I am concerned. Once this is done, I proceed as directed, using my full professional skill to make things work out using the directions I received. It is his job to give'directions where he feels they are needed and it is my job to carry them out.

Some of the people who work for me or interface with me may not treat matters for which I am responsible as seriously as I do, but this only results in my recognition that I'm being depended upon to fulfill my assigned responsibility, regardless of how the people assigned to me view the matter. Also, I know that if I don't look after all of my responsibilities, some of my authority may be usurped, particularly where there seems to be a vacuum of activity of my part. If that should happen, I could lose my effectiveness and, also, I would still be responsible for any task not done properly.

I value the trust and confidence placed in me by higher management. I work for them -

particularly my immediate supervisor. I try to harmonize my work style with theirs, to anticipate their desires and make them feel that I'm trying to key my efforts to their concerns as well as to provide skillful, consistent and dependable direction of routine and abnormal operations. I I

recognize that higher management has even more responsibility for plant operations than I do. I know the General Manager is responsible for what the Operations Manager does, and for what I do. If an operator makes a mistake, I'm responsible - so is the Operations Manager, the General Manager, etc. We all should have taken steps to assure that the operator didn't make the mistake - but we didn't, so we must take some action "to preclude its happening again.

Responsibility can't be shared - it must be fully assumed by each and everyone in the chain -

there's no way to divide it up.

I make reports up-the-line out of recognition of management's responsibilities. My management wants to be kept informed in order to be confident that it is doing what it should to give new or revised directives due to changed cbnditions. Also, management has assigned me certain resources, some of which may not be optimum for doing our job the way it can best be done.

This may limit my capacity to fully deal with a condition or problem and they want to recognize this to help alleviate the situation. My bosses are in the same boat with me - we're all working to fulfill our responsibilities.

My Basic Workinq Principles My basic working principles are three-fold. First, I keep informed about conditions of the plant and activities in progress. Second, I continuously manage priorities. Third, I strive to maintain strong, positive control over the operation of the plant and things that could threaten'that control.

I get Informed as I take over the shift then continuously build upon what I know during the shift.

This allows me to adjust my priorities wisely. With respect to priorities, I always keep safety as paramount. I want to feel adequately comfortable about what I'm doing, knowing that there is always some element or risk in anything.we do. I give foremost consideration to the prevention of an incident or condition that could lead to exqessive release of radioactivity.

The heart of my job is to maintain strong, positive control over what'is going on in the plant and what needs to be done to assure proper operation. I need to feel in control - from moment to moment and ready for what will or might happen next.

How I Keep Informed I keep informed by reading gages, checking annunciators and alarms, referring to trends on recorders, reviewing log sheets, reviewing tagouts, observing the actions of shift personnel and a host of other things. Although I enjoy the feel of looking at a control panel or discussing a situation with a supervisor more than reviewing written documents, I make sure the written documents are serving my needs - to keep informed and to maintain positive control of the plant.

2

When I initial a log or sign a tagout, I'm making a mental entry of information and I'm telling the involved shift persons that I'm in control of what I've just signed and that I'm hereafter a party to whatever use is made of that document. I never give my signature away. I always get a bit of information from what I've signed even though I may scan a routine document rather casually. I try to make paper work for me - or at least for my boss.

I like to frequently look at the condition of my plant and what's.going on first hand. If I can't do that enough, I try to get a look through other shift personnel by asking questions and by requesting reports about specific places or activities.

I watch people - and I study them - talk to them - listen to them and ask questions. It may be as important to me to know the amount of concern a. person has for a certain problem as to know more about that particular problem. Keeping informed about my shift personnel is.about as important as keeping informed about plant conditions, since I have to know both where attentibn is needed in the plant and Who needs more direction or supervision.

I position myself and conduct my activities with the realization thiat incidents can develop rapidly and that before I must make decisions, I may not have the time to find out how long we've had a certain alarm or why a piece of equipment is tagged out or what test is in progress. I maintain a "feel" for the plant so that I'm ready.to take direct control over virtually every important action that must be taken. I'm the leader that the shift will look to and will be depended upon when

• trouble comes, or when an bperator may freeze or move irrationally. In terms of a football team, I'm the quarterback as well as the safety. I'm the last backup for every person.on the shift. In order to be that, I've got to know what's goIng on.

The Sense of Priority Which I Use to Move Work Alona On My Shift It's not enough just to say that safety has first priority and productivity is what I try to achieve in the rest'of my efforts. I have to sort the things to be done some way and keep them in mind as I push along. The things that have to get done can be thought of'as falling into one of the following categories:

1. Routine work.

2.

Investigating problems.

3.

Changing plant conditions by changing plant parameters or by putting equipment into service or taking it out of service 3

4.

Conducting a test.

5.

Getting maintenance done and/or making modifications.

6.

Training Somehow, I have to get all of these done in order to be productive and to move things along properly on my shift. I must arrange and set the order of my attention, and that of other shift personnel; I must provide for coordination among activities going on; I must establish prerequisites for upcoming work and activities; and I must make judgments between safety versus productivity. So - here's how I think about each of the categories of work to be done as I try to meld them all together to keep the plant safe and move along.

Priority Considerations

1. Routine work - Routine work must be done, shift by shift. It is designed to detect problems and to prevent problems. If I neglect it, It's like proceeding blindly, hoping to get by -

possibly while things build up or get worse.

2. Investigating problems-As we carry out our routine work and identify problems, we must follow up to some degree on every irregularity or abnormality. If we don't, the extent of the problem and significance to safety and productivity will remain obscure. If we cut our follow-up short, we can actually cover-up a problem because we give following shifts the illusion that irregularities and abnormalities have been looked into and don't have any significance -

we have'to guard against these by leaving a clean trail or what has or has not been done and what has or has not been found out about a problem.

3. Changing plant conditions"- This is how we make progress and also where we are apt to make mistakes and be subjected to equipment failures. As we change plant conditions, we increase the demands on part of the plant while possibly decreasing it on other parts.

Changing plant parameters or placing equipment in or out of service therefore requires very close operator and supervisory attention. I must ensure that I make, and take the time required for such attention and that my other shift personnel do likewise.

4. Conducting tests - Conducting tests is something like changing plant conditions - in fact -

that's what it is except that it isn't necessarily the more routine type of changes. The fact that it isn't a routine plant manipulation means that I must ensure we're properly set up for it 4

with respect to special prerequisites, initial conditions, and manning. My shift is staffed for routine types of activities therefore certain testing may require more people or special talents. If so, I must get the extra people on station and provide them direction as part of my shift work force.

During the course of testing, I must keep abreast of the results and plant responses. I can waste a whole shift by not recognizing that the test conditions weren't proper or that desired results were not achieved.

5.

Conducting maintenance and making plant modifications.- This is where we reinforce safety, reliability and future productivity. It's like putting money in the bank, in that it has to be done in order to take it out. But - it must be done under adequate, operator controls and supervision. We have to make, and take the time to give it proper attention.

6.

Training - It seems as if training is always with us like a little conscience sitting on our shoulders. I seem to usually give it last priority although I know that's being short-sighted. I know that as a supervisor, a constant oasic pad mf iy jub is to-Irintiose-uEnder*me-.;-rust always keep in mind that it is my responsibility to train shift individuals to do their individual jobs better and to contribute more to the shift crew as a team. I also know that I must.make opportunities for trainees to get experience on. my shift under close supervision. I must inaintain an'envirohment of continuous learning on my shift-including my own growth of knowledge and skills. We usually don't learn how to Work harder - only smarter and in that way to do things more safely and productively.

So it's with all of this in mind, that I push and pull to move the shift along. It's only by taking frequent inventory.of these considerations am I confident as to whether.I've made progress or whether I'm just bridging the shifts thatcome before and after me.

Maintaining Positive Control of the Plant I believe that doing my job properly means that I am maintaining positive control of the plant. I define "positive control" in a very subjective way. To me, it means that I am adequately informed about the status of the plant and activities in progress, that I can predict how the plant will behave in the next several minutes barring an unpredictable incident, that I can stabilize the plant (if it is not already stable) whenever in my judgment due caution requires it, and that the activities for which I am responsible are being done the way I want them done.

From a philosophical aspect, control over shift activities is the most

ýallenging. In maintaining this control, I must be successful in imposing my will upon shift pers inel and upon those other personnel who interface with shift responsibilities. I can best express my philosophy by addressing how I feel about the control of the principal shift activities.

1. Monitoring, Directing and Verifying Operator Actions I monitor operator actions in order to learn, then follow, how each operator performs, his strengths and his weaknesses, as well as to simply keep abreast of what is going on.

• I direct operators in order to tell them what I want done and how I want it done - but I don't direct them in a step-by-step fashion about how to do things unless the type of activity is one requiring special direction or coordination.

I verify the performance of operators by directly spot-checking things which I feel are important and which I feel are most apt to be unsatisfactory, eo-those activities most prone to errors.

I make frequent, deliberate judgments on just how much monitoring, directing and verifying is enough. My only guide is that level at which I feel is at my threshold of comfort and confidence with respect to a given person and a given set of pltant conditions and circumstances. I pay particular attention to shift personnel who let it be known that.they want to be left alone to go their ownway when I feel that they are nc. performing their job the way they should. I must function as a team coordinator, director and leader. I do Seek to make working on my shift enjoyable and rewarding for each person - lut never at the expense of what Ideem to be unacceptable performance.

Standards of performance on my. shift are what I make them a, d accept - not what I might just want or wish. If I accept performance which I know isn't 1. 't I think it should be, then my standards.are automatically set by what I've accepted.

2. Use of Management Control Systems Management control systems such as documented procedure. qualification programs, reporting instructions etc., provide a disciplined framework for :-onsistent, acceptable results, particularly for activities being performed by large numbers of,,eople working on things requiring high quality results. They constitute management tolIs which I use to extend my control over many shift activities. I myself "go by the book" in he use of management control systems and I assure that my shift does likewise. I an i stickler in their use because 6

in many cases, they are substitutes for detailed supervision and/or for more experience and knowledge than the performing operator may have. Therefore, misuse can be dangerous. If there seems to be justification for not going by the booki I make sure that "the book" is properly changed before proceeding.

3.

Shift Training There is one aspect of on-shift training which I feel is very important to maintaining po'sitive control of the plant. That is the conduct of precautionary review (or training) concerning how to handle the plant with existing abnormalities and how to handle the plant prior to making non-routine changes in plant lineups or conditions. I assure this type of training is performed as part of shift turnover when coming on shift or as early in the shift as practical. I hold each person responsible for making such reviews and I spot check that it's done by asking questions which should be answered correctly if the reviews have been made.

4.

Performing Modifications and Doing Maintenance Making modifications or performing maintenance always feels threatening to maintaining positiv*controt-of-the-pla-nt.-I-ry-to-*ninimize-te-threat-by-meticulous-use-of-applicable management control systems and by requiring that each operator keeps abreast.of such work going on within his sphere or responsibility. I also keep abreast with the status of the more significant work in progress in order that I can be alert for, or anticipate impacts upon operational equipment.

I also have operators monitor the working spaces where modifications or maintenance is being perfoiMed in order to detect anything that might adversely affect operations such as working outside the cleared work area or system or workers crawling ove'r operational equipment.

5. Testing My concern for maintaining positive plant control always goes up when we're performing testing. First, normal shift manning is geared only to that testing that is considered part of normal shift operations. When additional testing is done, it always requires additional operator. attention to certain aspects of the plant, thereby tending to decrease attention to others. It can be that performing certain tests simultaneously with normal operational requirements are just too much, and that, additional operators are needed. In certain testing, absolutely constant monitoring of indicators is required and failure to do so can have dire results. Also, testing usually requires closer, more disciplined communications - without disrupting the communications needed for routine plant operations.

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I am always particularly sensitive to my instinct for caution in starling and conducting tests. I stay very close to what's going on and I assert my positive control over any test that in any way affects operations.

If technical supervision from a vendor or other source is available, I ensure that it is fully utilized in getting set up for the test and in giving advice during the course of testing.

6.

operational Problems Positive plant control can only be maintained with each responsible operator knowing each operational problem within his scope of responsibility, his verifying that the problem has been investigated and corrective actions initiated, and his implementing compensatory action to minimize adverse affects. Also, I and each operator must fuss about the continuation of operational problems by virtually demanding timely resolution. 'Living" with problems clearly leads to inadequate plant control.

.7T*luotirre-Cperat ion s Maintaining positive control of the plant is what routine operations is all about. Shift routines are based upon this concept. Early detection of problems and initiation. of compensatory and corrective actions are vital.

Teamwork and work discipline must be practiced in.normal operations* or performance errors will be excessive and discipline won't be achievable for abnormal circumstances.. Above all, shift personnel must stay busy monitoring spaces and indicators, looking for and investigating problems, keeping and reviewing logs, maintaining spaces clean and orderly, etc. Operators must never just pass the timel It takes full time effort by.all personnel to perform the tasks and maintain the teamwork to get the work done that is necessary to maintain positive plant control. I am not, In any way, being unreasonable ir requiring that each and every operator performs accordingly and that a casual or lax atmosphere is not allowed to exist on rny shift.

8. Changing Plant Modes and Conditions I insist upon being very much in control of changing plant modes or conditions. I do not want major equipment started or stopped without my concurrence except, of course, when emergency conditions dictate otherwise. In all cases, I want to be kept informed. Likewise, 8

all shift operators must be kept informed about changing plant conditions involving or affecting equipment or spaces for which they are responsible.

When changing plant conditions, I stabilize at logical points to look over the plant and to have the other operators look over the plant before going on. I lead such reviews and ensure that it's a team effort by all involved.

9.

Removing and Returning Systems and/or Eguipment from/to Service The full and proper use of management control systems for these actions is vital.

Documentation should be closed out through careful reviews and I periodically check this.

Manipulation of valves, switches and other controls must be done with close supervision.

The use of direct, reliable communications is also vital.

Wherever equipment is being tested for return to service, any technical advisors or experts who are available should be made a part of th.e shift team to verify readiness for service.

I keep personally involved in returning major systems and equipment to service. This clearly requires team effort.

Motivating The Individuals That-Work With Me As the leader of my shift, I want my employees to move In the direction of high output, without accidentsor abuse of equipment, producing work of good quality, and on a whole showing a willingness to accept changes made necessary by management's decisions. Over and beyond the line of duty I want my shift to rise to the occasion when emergencies or rush periods, call for special effort, overtime, or Inconvenience.

I understand'that money incentives, which are under management's control, can only be applied externally and do not necessarily produce the results that I strive for on my shift. I realize that I jdst can't keep pushing employees in'a certain direction. My goal is to transform the external incentives into internal motivating forces by creating a work environment where the members of my shift want to produce maximum output of required quality and to do all the other things enumerated above. In short, I try to create a certain level of job enthusiasm.

As often as time and regulatory constraints allow, I follow a participative management style that allows my coworkers to realize that a "we" attitude is one of my major goals. Employees with 9

this attitude instinctively identify their own interests with those of the company. This plural approach to the job, this instinctive thinking about the company in terms of "we' rather than "they" is what transforms my shift from working on the job to doing a job. We want to meet budgets, want to be cost-conscious and methods-minded, want to cut down on waste and want to submit suggestions for improvement at every opportunity. To achieve this goal, I give praise when problems are solved independently, I entrust others with full responsibility and accountability for assigned tasks, where able I give control as to how and when tasks are done, and I strive to instill a sense of growth and advancement.

Finally, I realize that creating a sense of belonging, of participation, and of accomplishment in each and every employee is one of my most vital responsibilities.

Conclusion I believe that this philosophy provides a desirable basis for the way each senior operator can approach their job and have confidence that their work principles are sound. Of course, this philosophy is not all inclusive. It must be built upon in order to handle the many conditions and situations that arise.

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