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05000293/FIN-2015007-022015Q1PilgrimFailure to Identify, Evaluate, and Correct A SRV Failure to Open Upon Manual ActuationA self-revealing preliminary White finding and AV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, and Technical Specification (TS) 3.5.E, Automatic Depressurization System, was identified for the failure to identify, evaluate, and correct a significant condition adverse to quality associated with the A SRV. Specifically, Entergy failed to identify, evaluate, and correct the A SRVs failure to open upon manual actuation during a plant cooldown on February 9, 2013. In addition, the failure to take actions to preclude repetition resulted in the C SRV failing to open due to a similar cause following the January 27, 2015, LOOP event. Entergy entered this issue in to the CAP as CR-PNP-2015-01983, CR-PNP-2015-00561, and CR-PNP-2015-01520. Immediate corrective actions included replacing the A and C SRVs and completing a detailed operability analysis of the installed SRVs which concluded that a reasonable assurance of operability existed. Entergys failure to identify, evaluate, and correct the condition of the A SRVs failure to open upon manual actuation during a plant cooldown on February 9, 2013, was a performance deficiency. In addition, the failure to take actions to preclude repetition resulted in the C SRV failing to open due to a similar cause following the January 27, 2015 LOOP event. The self-revealing finding was within Entergys ability to foresee and correct because indications were available to determine that the A SRV valve did not open upon manual actuation. This was discovered as a result of an extent of condition review of the C SRV failing to open upon manual actuation following the January 27, 2015 LOOP event. This performance deficiency is more than minor because it could reasonably be viewed as a precursor to a significant event if two of the four SRVs failed to open when demanded to depressurize the reactor, following the failure of high pressure injection systems or torus cooling, to allow low pressure injection systems to maintain reactor coolant system inventory following certain initiating events. In addition, it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors screened this issue for safety significance in accordance with IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, issued June 19, 2012. The screening determined that a detailed risk evaluation was required because it was assumed that for a year period, two of the four SRVs were in a degraded state such that they potentially would not have functioned to open at some pressure lower than rated pressure and would not fulfill their safety function for greater than the TS allowed outage time. Specifically, the assumptions of failures to open were based on: a failed actual opening demand at 200 psig reactor pressure on January 27, 2015, for the C SRV; examination of the valve internals at the testing vendor (National Technical Systems); and a previous failed actual opening demand at 114 psig reactor pressure on February 9, 2013, for the A SRV. The staff determined that there wasnt an existing SDP risk tool that is suitable to assess the significance of this finding with high confidence, mainly because of the uncertainties associated with: the degradation mechanism and its rate; the range of reactor pressure at which the degraded valves could be assumed to fully function; any potential benefit from an SRV lifting at rated pressure, such that the degradation would be less likely to occur and, therefore, prevent a subsequent failure at low pressure in the near-term; the time based nature of plant transient response relative to when high pressure injection sources fail and the associated impact of reduced decay heat on the SRV depressurization success criteria; and the ability to credit other high pressure sources of water. Based on the considerations above, the risk evaluation was performed using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, issued April 12, 2012. The NRC made a preliminary determination that the finding was of low to moderate safety significance (White) based on quantitative and qualitative evaluations. The detailed risk evaluation is contained in Attachment 4 to this report. This finding does not present a current safety concern because the A and C SRVs were replaced during the outage following the January 27, 2015 LOOP and reactor trip event. Also, Entergy performed a detailed operability analysis of the installed SRVs which concluded that a reasonable assurance of operability existed. This finding had a cross-cutting aspect in Problem Identification and Resolution, Evaluation, because Entergy did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, Entergy staff did not thoroughly evaluate the operation of the A SRV during the February 9, 2015 plant cooldown and should have reasonably identified that the A SRV did not open upon three manual actuation demands.
05000293/FIN-2015007-012015Q1PilgrimInadequate Past Operability Assessment of C Safety Relief ValveThe team identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when Entergy staff performed an inadequate past operability determination that assessed performance of the C safety/relief valve (SRV), which did not open as expected when called upon to function. Specifically, following the January 27, 2015 reactor scram, operators placed an open demand for the C SRV twice during post-scram recovery operations, but the valve did not respond as expected and did not perform its pressure reduction function on both occasions. Entergys subsequent past operability assessment for the valves operation incorrectly concluded that the valve was fully capable of performing its required functions during its installed service. In response to the teams past operability concerns, Entergy subsequently re-evaluated the past operability of C SRV and concluded that it was inoperable and placed the issue into the corrective action program (CAP) as CR-PNP-2015- 02051. The team determined the failure to adequately assess past operability of the C SRV was a performance deficiency that was reasonably within Entergys ability to foresee and correct. This NRC-identified performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent core damage. The team evaluated the finding using IMC 0609, Appendix 0609.04, Initial Characterization of Findings, which directed the use of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. Using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, the team determined this finding was not a design or qualification deficiency and was not a potential or actual loss of system or safety function, and was therefore of very low safety significance (Green). The finding had a cross-cutting aspect in Human Performance, Conservative Bias, because Entergy did not use decision making practices that emphasized prudent choices over those that are simply allowable. Specifically, Entergy did not appropriately evaluate unexpected and unsatisfactory performance of the C SRV in consideration of the entire pressure range that the SRV, including its automatic depressurization system (ADS) function, was required to be operable.
05000293/FIN-2015007-032015Q1PilgrimInadequate Loss of Instrument Air Abnormal Operating ProcedureA self-revealing Green NCV of TS 5.4.1, Procedures, was identified because Entergy failed to include appropriate operator actions to both recognize the effects of and recover systems and components important to safety within Procedure 5.3.8, Loss of Instrument Air, abnormal operating procedure. Entergy entered this issue into the CAP as PNP-CR-2015 0888 and issued a revision to Procedure 5.3.8 to provide additional guidance to operators during a loss of instrument air. The inspectors determined that the level of detail in Procedure 5.3.8, Loss of Instrument Air, Revision 39, was inadequate to provide appropriate operator guidance to identify and mitigate key events of January 27, 2015. This self-revealing performance deficiency was reasonably within the ability of Entergy personnel to foresee and the issue should have been prevented. The finding was more than minor because it was associated with the procedure quality attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesired consequences. The lack of adequate instructions in the procedure adversely affected several operator actions and plant equipment on January 27, 2015, during the LOOP and loss of instrument air. The team evaluated the finding using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The team determined this finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not result in a loss of function of a TS required system, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as a high safety-significant system. This finding had a cross-cutting aspect in the area of Human Performance, Resources, because Entergy leaders did not ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety.
05000293/FIN-2015007-042015Q1PilgrimFailure to Follow RCIC System Manual Restart ProcedureA self-revealing Green NCV of TS 5.4.1, Procedures, was identified because the operating crew failed to implement a procedure step to open the reactor core isolation cooling (RCIC) system cooling water supply valve during a manual startup of the system. As a result, the RCIC system was operated for over 2 12 hours with no cooling water being supplied to the lubricating oil cooler or to the barometric condenser. Entergy entered the issue into the CAP as CR-PNP-2015-0566, CR-PNP-2015-0570, and CR-PNP-2015-0952 and conducted a human performance review of the Control Room operators involved with the issue. The inspectors determined that the failure to implement Procedure 5.3.35.1, Attachment 29, RCIC Injection Manual Alignment Checklist, and the Vacuum Tank Pressure Hi Alarm, C904L-F3, alarm response procedure was a performance deficiency and was reasonably within the ability of Entergy personnel to foresee and prevent. This self-revealing finding was more than minor because it was associated with the human performance attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesired consequences. Specifically, on January 27, 2015, reactor operators failed to open MO-1301-62, cooling water supply valve, during a manual restart of the RCIC system in accordance with procedure 5.3.35.1, RCIC Injection Manual Alignment Checklist. Additionally, the operating crew failed to identify the valve was out of position even after the Vacuum Tank Pressure Hi Alarm, C904L-F3, was received two minutes after the system was re-started and the alarm response procedure identified Improper Valve Lineup as a probable cause. The team evaluated the finding using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The team determined this finding was not a design or qualification deficiency and was not a potential or actual loss of system or safety function, and is therefore of very low safety significance (Green). During the period when the RCIC system was operated in this condition, no temperature limits were exceeded. The inspectors noted that in the event of a RCIC system automatic start, the cooling water supply valve would have opened automatically. This finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because Entergy licensed personnel did not implement procedure 5.3.35.1, RCIC Injection Manual Alignment Checklist , to open MO-1301-62. Additionally, Entergy licensed personnel did not implement the Vacuum Tank Pressure Hi Alarm, C904L-F3, response procedure to check for an improper valve line-up.
05000293/FIN-2015007-052015Q1PilgrimFailure to Identify Condition Adverse to Quality Associated with CS Discharge Header VoidingThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because PNPS staff failed to identify and correct conditions adverse to quality associated with the partial voiding of the A core spray (CS) discharge header on January 27, 2015, following the loss of the keepfill system due to a LOOP. PNPS entered the issue into the CAP as CR-PNP-2015-01406 and planned procedural changes that would provide guidance to operate the affected pumps in order to prevent pump discharge piping from voiding if keepfill pressure is lost. The failure to identify, evaluate, and correct the A CS discharge header partial voiding following loss of keepfill on January 27, 2015, is a performance deficiency that was within Entergys ability to foresee and correct. Because the issue was not entered into the CAP, the condition was neither evaluated nor was corrective action taken or planned. This NRCidentified issue is more than minor because it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, to IMC 0609, Significance Determination Process. This finding was determined to be of very low The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because PNPS staff failed to identify and correct conditions adverse to quality associated with the partial voiding of the A core spray (CS) discharge header on January 27, 2015, following the loss of the keepfill system due to a LOOP. PNPS entered the issue into the CAP as CR-PNP-2015-01406 and planned procedural changes that would provide guidance to operate the affected pumps in order to prevent pump discharge piping from voiding if keepfill pressure is lost. The failure to identify, evaluate, and correct the A CS discharge header partial voiding following loss of keepfill on January 27, 2015, is a performance deficiency that was within Entergys ability to foresee and correct. Because the issue was not entered into the CAP, the condition was neither evaluated nor was corrective action taken or planned. This NRCidentified issue is more than minor because it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Appendix A,The Significance Determination Process for Findings At-Power, to IMC 0609, Significance Determination Process. This finding was determined to be of very low.
05000293/FIN-2015007-062015Q1PilgrimFailure to Implement Compensatory Measures for Out-of-Service EAL InstrumentationThe inspectors identified a Green NCV of 10 CFR 50.54(q)(2) for failing to follow and maintain an emergency plan that meets the requirements of planning standards 10 CFR 50.47(b) and Appendix E. Specifically, on January 27, 2015, following a loss of instrument air, the indications in the Control Room for Sea Water Bay level were lost, and Entergy did not implement compensatory measures, as directed by an Emergency Plan Implementing Procedure, to determine whether a Sea Water Bay level emergency action level (EAL) threshold had been exceeded. Entergy entered this issue into the CAP as CR-PNP-2015- 00948 and initiated corrective actions to identify alternative means for assessing this EAL in the event of a loss of Sea Water Bay level instruments. The inspectors determined that Entergys failure to implement compensatory measures for out-of-service EAL instrumentation was a performance deficiency that was within Entergys ability to foresee and correct and should have been prevented. Specifically, Entergy did not implement the compensatory measure listed in Attachment 9.2 of EP-IP-100.1, Emergency Action Levels, Revision 10. The inspectors determined that following a loss of instrument air, the indications for Sea Water Bay level EAL were lost, rendering those EALs ineffective such that Entergy was not able to determine whether a Sea Water Bay level EAL threshold had been exceeded and to declare an emergency based on the Sea Water Bay level. This NRC-identified performance deficiency was more than minor because it was associated with the emergency response organization performance (program elements not meeting 50.47(b) planning standards) attribute of the Emergency Preparedness cornerstone and affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the out-of-service Sea Water Bay level instrumentation could have led to an emergency not being declared in a timely manner. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012. The attachment instructs the inspectors to utilize IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, issued September 23, 2014, when the finding is in the licensees Emergency Preparedness cornerstone. The inspectors determined the finding was associated with risk significant planning standard 10 CFR 50.47(b)(4), Emergency Classification System, and corresponded to the following Green Finding example in Table 5.4-1: an EAL has been rendered ineffective such that any Alert or Unusual Event would not be declared, or declared in a degraded manner for a particular off-normal event. Therefore, using Figure 5.4-1, Significance Determination for Ineffective EALs and Overclassification, and the example in Table 5.4-1, the inspectors determined the finding was of very low safety significance (Green). The finding had a cross-cutting aspect in the area of Human Performance, Documentation, because Entergy did not maintain complete and accurate documentation. Specifically, compensatory measures associated with out-of-service EAL instrumentation are not governed by comprehensive and high-quality programs, processes, and procedures.
05000293/FIN-2015007-082015Q1PilgrimInadequate Testing of the Diesel-Driven Air CompressorA self-revealing Green finding was identified for Entergys failure to verify that the diesel-driven air compressor (K-117) was available for service prior to the January 27, 2015 winter storm. Specifically, although K-117 was tested prior to the winter storm, the test methodology did not reveal that the capacity of the starting battery was inadequate. The failure to verify that the diesel-driven air compressor (K-117) was available for service prior to the January 27, 2015 winter storm is a performance deficiency that was within Entergys ability to foresee and correct. This resulted in a loss of instrument air during the plant trip which complicated the event response. Entergy entered the issue into the corrective action program (CAP) as condition report (CR)-PNP-2015-00559 and initiated actions to supply instrument air with a temporary air compressor. Entergy also revised the operability test for K-117 air compressor to remove the alternating current (AC) power source prior to starting the air compressor. This self-revealing issue was more than minor because it is associated with the procedure quality and design control attributes of the Initiating Events cornerstone and adversely impacted the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, failure of K-117 resulted in loss of instrument air, which adversely impacted the plant response during the January 27, 2015 winter storm. Additionally, this issue is also associated with the procedure quality and design control attributes of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating event to prevent undesirable consequences. The inspectors screened the issue under the Initiating Events cornerstone using Attachment 4 and Exhibit 1 of Appendix A to IMC 0609, Significance Determination Process, because that cornerstone was determined to be more impacted by the finding than the Mitigating Systems cornerstone. The inspectors concluded that a detailed risk evaluation would be required because the finding involved the complete loss of a support system (instrument air) that contributes to the likelihood of an initiating event and affects mitigation equipment. A senior reactor analyst performed a detailed risk evaluation of this issue. The NRC model for PNPS was adjusted to account for a loss of the instrument air compressor on a LOOP. The change in core damage frequency was very low. A review of the dominant accident sequences indicated the contribution from a large early release and from external risk contributors to be very small. Therefore, the issue was determined to be of very low risk significance (Green). The finding had a cross-cutting aspect in the area of Human Performance, Design Margins, because Entergy failed to ensure that the K-117 battery was designed with adequate margin. This finding is reflective of current performance because the inadequate design margin of the battery should have been discovered through proper testing.
05000293/FIN-2015007-072015Q1PilgrimFailure to Report a Major Loss of Emergency Assessment CapabilityAn NRC-identified SL IV NCV of 10 CFR Part 50.72(b)(3)(xiii) was identified when Entergy failed to make a required event notification within eight hours for a major loss of assessment capability. Specifically, an unplanned loss occurred of all EAL instrumentation associated with Sea Water Bay level that resulted in an inability to evaluate all EALs for an abnormal water level condition. Entergy entered the issue into the CAP as CR-PNP-2015-00949. Compliance was restored on February 5, 2015, when Entergy reported the major loss of assessment capability under Event Notification (EN) 50790. The inspectors determined that Entergys failure to submit an event notification in accordance with 10 CFR 50.72 within the required time was a performance deficiency that was reasonably within Entergys ability to foresee and correct, and should have been prevented. Since the failure to submit a required event report impacts the regulatory process, the violation was evaluated using Section 2.2.4 of the NRCs Enforcement Policy, dated July 9, 2013, instead of the SDP. Using the example listed in Section 6.9.d.9, A licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73, the issue was evaluated and determined to be a SL IV violation. The inspectors reviewed the condition for reactor oversight process significance. Because this NRC-identified violation involves the traditional enforcement process and does not have an underlying technical violation that would be considered more-than-minor, the inspectors did not assign a cross-cutting aspect to this violation in accordance with IMC 0612.
05000219/FIN-2014005-022014Q4Oyster CreekInadequate Review of Change in Maintenance Process Results in Inoperable Emergency Diesel GeneratorThe inspectors identified a preliminary White finding and an associated apparent violation of 10 CFR 50, Appendix B, Criterion III, Design Control, because Exelon staff did not review the suitability of the application of a different maintenance process at Oyster Creek that was essential to a safety-related function of the emergency diesel generators (EDG). Specifically, in May 2005, Exelon staff changed the method for tensioning the cooling fan belt on the EDG from measuring belt deflection to belt frequency and did not verify the adequacy of the acceptance criteria stated for the new method. As a result, Exelon staff did not identify that the specified belt frequency imposed a stress above the fatigue endurance limit of the shaft material, making the EDG cooling fan shaft susceptible to fatigue and subsequent failure on July 28, 2014. As a consequence, Exelon also violated Technical Specification 3.7.C, because the EDG No. 2 was determined to be inoperable for greater than the technical specification allowed outage time. Exelons immediate corrective actions included entering the issue into their corrective action program as issue report (IR) 1686101, replacing the EDG No. 2 fan shaft, examining the EDG No.1 fan shaft for extent of condition, and performing a failure analysis to determine the causes of the broken shaft. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors screened the finding for safety significance and determined that a detailed risk evaluation was required because the finding represented an actual loss of function of a single train for greater than its technical specification allowed outage time. The detailed risk evaluation concluded that the increase in core damage frequency was 5.1E-6, or White (low to moderate safety significance). This finding does not have an associated cross-cutting aspect because the performance deficiency occurred in 2005 and is not reflective of present performance.
05000219/FIN-2014009-012014Q4Oyster CreekInadequate Application of Materials, Parts, Equipment, and Processes Associated with the Electromatic Relief ValvesThe NRC identified a preliminary Yellow finding and associated apparent violation of 10 CFR 50, Appendix B, Criterion III, Design Control, and Technical Specification 3.4.B, Automatic Depressurization System, because the station did not establish adequate measures for selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the electromatic relief valves (EMRVs). The violation was also preliminarily determined to meet the IMC 0305, Section 11.05, criteria for treatment as an old design issue. Specifically, on June 20, 2014, during refurbishment of EMRVs that were removed from the plant during the 2012 refueling outage, Exelon personnel identified deficiencies with the B and D EMRVs. As part of the planned EMRV actuator testing and refurbishment activities, Exelon personnel conducted bench testing on June 26, 2014. Both valves did not stroke satisfactorily and resulted in two inoperable EMRVs for greater than the Technical Specification allowed outage time of 24 hours. Exelons immediate corrective actions included placing this issue into the corrective action program as issue report 1679428 and redesigning the EMRV actuators to ensure the spring is on the outside of the guide bushing, therefore removing the possibility of the spring entering the guide bushing area and subsequently jamming the actuator causing valve failure. All of the actuators were replaced with redesigned actuators during the refueling outage in October 2014. In addition, Exelon issued a 10 CFR Part 21 report to inform the industry of the deficient EMRV actuator design. This finding is more than minor because it adversely affected the design control quality attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the design deficiency of the EMRVs and the inadequate maintenance process led to the inability of the B and D EMRVs to perform their safety function. The inspectors screened this issue for safety significance in accordance with IMC 0609, Appendix A, Exhibit 2, and determined a detailed risk evaluation was required because the EMRVs were potentially failed or unreliable for greater than the Technical Specification allowed outage time. As described in Attachment 3 to this report, a detailed risk evaluation concluded that the increase in core damage frequency (CDF) related to failure of the B and D EMRVs is in the mid E-5 range; therefore, this finding was preliminarily determined to have a substantial safety significance (Yellow). Due to the nature of the failures, no recovery credit was assigned. The dominant sequences included loss of main feedwater with failures of the isolation condensers, and failure to depressurize. This finding does not represent an immediate safety concern because Exelon replaced all of the actuators with the redesigned actuators during the refueling outage in October 2014. Further, the NRC is considering treatment of this finding as an old design issue because the condition existed since the original installation of the EMRVs, and is not indicative of current licensee performance. Additional details are discussed in Attachment 1. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency was not reflective of current licensee performance. Specifically, the inspectors determined that the performance deficiency existed since original installation of the EMRVs. Although an opportunity to identify this issue following original installation occurred in 2006 when Quad Cities changed the EMRV actuator design due to similar issues, the inspectors could not conclude that the issue would have likely been identified during that period since a Part 21 Report was not issued to inform the industry and NRC of the design change and industry operating experience focused on plants that completed or were scheduled to complete an extended power uprate.
05000423/FIN-2014008-022014Q3MillstoneFailure to Identify and Promptly Correct a Condition Adverse to QualityThe inspection team identified a self-revealing apparent violation of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion XVI, Corrective Action, involving Dominions failure to promptly identify and correct a condition adverse to quality. Specifically, the Unit 3 turbine-driven auxiliary feedwater (TDAFW) pump was operated from May 2013 through February 2014 in an adverse configuration due to the installation of an incorrect cam follower bearing. As a result of this adverse configuration, the pump experienced three overspeed trips during the subject timeframe. As a consequence, Dominion violated Technical Specification (TS) 3.7.1.2, since TDAFW was determined to be either failed or unreliable for greater than the TS allowed outage time. Dominion installed the correct cam follower, entered this issue in their corrective action program (CAP) as condition report (CR) 538743 and CR 531536, and completed a root cause evaluation (RCE) (RCE 001111). The issue was determined to be more than minor since it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operation of the TDAFW pump with the incorrect spherical bearing reduced the reliability of a risksignificant, safety-related mitigating system. The issue was evaluated in accordance with IMC 0609, Appendix A, Exhibit 2, and was determined to require a detailed risk evaluation based on the finding representing an actual loss of function of a single train for greater than its TS allowed outage time. The detailed risk evaluation concluded that the increase in core damage frequency of this issue is in the mid to high E-6 range, or White (low to moderate safety significance). The dominant core damage sequences involved fire scenarios resulting in control room abandonment that rely upon the TDAFW pump as the primary source of make-up to the steam generators and decay heat removal. This finding had a cross-cutting aspect in Human Performance, Consistent Process, where individuals use a consistent, systematic approach to make decisions and risk insights are incorporated as appropriate. Specifically, Dominion did not implement consistent, systematic approaches to resolve the condition as evidenced by their inadequate and inconsistent use of CAP and troubleshooting.
05000423/FIN-2014008-012014Q3MillstoneFailure to Provide Adequate Maintenance Instructions for the Turbine Driven Auxiliary Feedwater Pump Governor Control Valve LinkageThe inspectors identified a self-revealing Green NCV of TS 6.8.1, Procedures and Programs, when Dominion did not maintain an adequate maintenance procedure to ensure reliable performance of the TDAFW system. Specifically, TDAFW properly started following the August 9, 2013, reactor trip, but was subsequently shut down after observed flow and pressure oscillations. Dominion staff discovered the control valve linkage misaligned due to a loose cam follower bearing retaining nut. As part of the repair, Dominion implemented a revision to the C MP 711 procedure to require application of thread-locker to the cam follower bearing retaining nut during reassembly. Additionally, Dominion entered this issue in their CAP as CR 522896. The finding was more than minor because it is associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the maintenance procedure did not provide sufficient written instructions to ensure adequate torque of the retaining nut and thereby reliable performance of the TDAFW system three months after reassembly. The finding was evaluated using IMC 0609, Attachment 4 and Appendix A, Exhibit 2.A, and determined to be of very low safety significance (Green) since it was not associated with a design or qualification deficiency, not a loss of system/function, and not an actual loss of its TS function. This finding had a cross-cutting aspect in the area of Human Performance, Documentation, in that licensee organizations are expected to create and maintain complete, accurate, and up-to-date documentation. Specifically, Dominion did not maintain a comprehensive, high-quality maintenance procedure that was thorough to assure assembly of critical TDAFW components.
05000336/FIN-2014011-012014Q3MillstoneFailure to Complete a 10 CFR 50.59 Evaluation for Removal of SLODThe NRC identified a Severity Level III AV of Title 10 of the Code of Federal Regulations (10 CFR) 50.59, Changes, Tests, and Experiments, for Dominions failure to complete a 10 CFR 50.59 evaluation and obtain a license amendment for a change made to the facility as described in the Updated Final Safety Analysis Report (UFSAR). Specifically, Dominion removed a special protection system (SPS), known as severe line outage detection (SLOD), which was described in the UFSAR. Dominion concluded in the 10 CFR 50.59 screening that a full 10 CFR 50.59 evaluation was not required and, therefore, prior NRC approval was not needed to implement this change. The team concluded that prior NRC approval likely was required because the removal of SLOD may have resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of the offsite power system as described in the UFSAR. Dominion has documented condition reports CR 553967 and CR 551068, and participated in a root cause evaluation with Northeast Utilities to determine whether the relay operations that initiated the events of May 25, 2014, were appropriate for the circumstances. Dominion also implemented a compensatory measure by issuing an Operations Standing Order for interim guidance on offsite line outages and plant generation output. The team determined that the failure of Dominion to complete a 10 CFR 50.59 evaluation of the modification for the removal of the SLOD system involved traditional enforcement because it impacted the NRCs ability to perform its regulatory function. This AV was determined to be more than minor because the team determined that the change to the facility required a full 10 CFR 50.59 evaluation and it likely would have required Commission review and approval prior to implementation. The severity level of this AV was determined, in part, using SDP risk significance in accordance with the NRC Enforcement Policy. A Region I Senior Risk Analyst conducted a conditional core damage probability estimate and determined that it was most properly characterized at a Severity Level III. Cross-cutting aspects are not assigned to traditional enforcement violations.
05000272/FIN-2014404-022014Q2SalemSecurity
05000272/FIN-2014404-012014Q2SalemSecurity
05000354/FIN-2014002-072014Q1Hope CreekLow-Low Set Safety/Relief Valve Pilot Solenoid Operated Valve Failed As-Found TestingThis issue is considered within the traditional enforcement process because there was no performance deficiency identified and IMC 0612, Appendix B, Issue Screening, directs disposition of this issue in accordance with the Enforcement Policy. The inspectors used the Enforcement Policy, Section 6.1 Reactor Operations, to evaluate the significance of this violation. The inspectors concluded that the violation is more than minor and best characterized as Severity Level IV. In reaching this conclusion, the inspectors considered that the underlying technical finding would have been evaluated as having very low safety significance (i.e. green) under the Reactor Oversight Process 37 Enclosure using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process. The inspectors screened the issue, and evaluated it using Checklist 7 of IMC 0609, Appendix G, Attachment 1. Based on these reviews, this issue would screen as very low safety significance (Green), because qualitative assessment concluded that PSEG maintained adequate mitigation capability and the event was not characterized as a loss of control. The manufacturer assembly error could not be identified during inspection and testing. Because it has been determined that it was not reasonable for PSEG to foresee and prevent inadequate assembly of the SOV by the manufacturer, no performance deficiency exists. The NRC has decided to exercise enforcement discretion in accordance with Section 3.5 of the NRC Enforcement Policy and refrain from issuing enforcement action for the violation of TS (EA-14-050). Further, because licensee actions did not contribute to this violation, it will not be considered in the assessment process or the NRCs Action Matrix. This LER is closed.
05000354/FIN-2014002-012014Q1Hope CreekInadequate Preventative Maintenance for Safety-Related Circuit CardsA self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1.a, Procedures and Programs, was identified regarding PSEG failing to adequately establish, implement, and justify the initial replacement frequency for the 1DD481 inverter control circuit cards. As a result, an age-related failure of circuit cards for the safety-related 1E channel D (1DD481) Inverter occurred on December 24, 2013, which caused PSEG to enter an unplanned 24 hour shutdown TS 3.8.3.1.a.4 for On-site Power Distribution Systems. PSEGs corrective actions include conducting an extensive extent of condition review of first-call preventive maintenances (PMs). The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors determined that this finding was of very low safety significance (Green) using NRC IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 Initiating Events Screening Questions, dated June 19, 2012, because for findings involving support system initiators, i.e. the Loss of a DC (direct current) bus, the result did not involve the complete or partial loss of a support system that contributed to the likelihood of, or cause, an initiating event and affected mitigation equipment. The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of present licensee performance.
05000354/FIN-2014002-022014Q1Hope CreekUntimely Identification and Corrective Actions for a Condition Adverse to Quality related to 480 VAC Masterpact BreakersA self-revealing Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified because PSEG failed to assure that a condition adverse to quality (CAQ) was promptly identified and corrected. Specifically, PSEG did not initiate a timely notification for a potential design flaw in the operation of some 480 volt alternating current (VAC) Masterpact breakers control logic scheme. PSEGs corrective actions included an extensive operability evaluation, compensatory measures conducted every shift by operators to ensure the operability and reliability of these breakers in the short-term, and a proposed design change to remove the design flaw in the breaker control logic by 2015. The performance deficiency was determined to be more than minor because it was associated with the equipment performance and design control attributes of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors determined that this finding was of very low safety significance (Green) using NRC IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012, because although the breakers design is affected, the operability of the breakers is maintained. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting aspect of Problem Identification and Resolution, Identification, because PSEG failed to identify issues completely, accurately, and in a timely manner in accordance with the corrective action program (CAP).
05000354/FIN-2014002-032014Q1Hope CreekFailure to Follow Procedure Resulting in the Potential Inoperability of a Safety-Related SystemA self-revealing Green NCV of TS 6.8.1.a, Procedures and Programs, was identified for PSEGs failure to follow procedure HC.OP-SO.BH-0001, Standby Liquid Control (SLC) System Operation, when restoring the SLC system after routine maintenance. Specifically, the licensee failed to adequately coordinate the restoration of the SLC system using the work control document (WCD) and the SLC system operating procedure which led to an incorrect SLC system lineup causing the inadvertent addition of demineralized (DI) water to the SLC storage tank. As a result, PSEG had to determine the immediate and prompt operability of the SLC system and enter the associated 8 hour SLC Technical Specification Action Statement (TSAS). PSEGs corrective actions include restoring the SLC tank concentration, briefing the operating crews on proper WCD turnover process, and addressing operator gaps in the SLC system operation that may have adversely affected the timeline and the inaccuracy of the immediate operability calculation method. The performance deficiency was determined to be more than minor because it was associated with the configuration control attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, failing to follow procedure leading to configuration control issues could have rendered a safety-related system inoperable. This performance deficiency was also similar to examples 3.j and 3.k of NRC IMC 0612, Appendix E, in that the addition of 80 gallons of DI water to the SLC tank created a reasonable doubt of operability of the SLC system. The inspectors determined the finding to be of very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. Using Exhibit 2, the inspectors determined that the finding screened as very low safety significance (Green) because although the SLC tank boron concentration was diluted, the SLC system was still capable of providing sufficient negative reactivity to shut down the reactor. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting aspect of Human Performance, Work Management, because PSEG failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority.
05000354/FIN-2014002-042014Q1Hope CreekInadequate Evaluation of 480VAC Motor Control Center Design ChangeA self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for PSEGs failure to adequately evaluate a modification to the design change package for replacement buckets on the Class 1E 10B232 480 VAC motor control center (MCC) in accordance with PSEG procedure CC-AA-103-1001, Implementation of Configuration Changes. This resulted in damage to and deenergization of the 10B232 MCC during maintenance activities to install a new replacement bucket on October 28, 2013. PSEGs corrective actions included a full extent of condition inspection of all installed modified MCC buckets and removing instructions to install terminal block screws in future modifications. This issue was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstones objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Because this finding occurred while the plant was shut down, the inspectors used IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, dated February 28, 2005. The inspectors determined the finding to be of very low safety significance (Green) using Checklist 7 of Attachment 1, Boiling Water Reactor Refueling Operation with Reactor Coolant System (RCS) Level Greater Than 23 Feet, because qualitative assessment concluded that PSEG maintained adequate mitigation capability and the event was not characterized as a loss of control. The inspectors determined that the finding had a cross-cutting aspect in Human Performance, Procedure Adherence, because PSEG personnel did not follow site procedures.
05000354/FIN-2014002-052014Q1Hope CreekFailure to Maintain B.5.b Equipment in a State of Readiness to Support Mitigation Strategies per 10 CFR 50.54(hh)(2)The inspectors identified a Green NCV of 10 CFR 50.54(hh)(2), Conditions of Licenses. Specifically, PSEG failed to adequately assess the functionality of the B.5.b portable gas generator on multiple occasions and implement adequate corrective actions in response to repeated failures of the B.5.b portable gas generator. This resulted in an unrecoverable and unavailable individual mitigating strategy associated with the remote operation of safety relief valves (SRV) with reactor pressure vessel (RPV) injection for approximately two and half months while the portable gas generator was unavailable. PSEGs corrective actions include repairing the B.5.b portable gas generator and returning it to an available, standby condition as well as performing a validation of all B.5.b equipment and associated mitigating strategies. The inspectors determined the performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The inspectors determined that this finding was of very low safety significance using NRC IMC 0609, Appendix L, B.5.b Significance Determination Process, Table 2 - Significance Characterization, dated December 24, 2009, as specified for 10 CFR 50.54(hh) findings by IMC 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, because the finding affected the Mitigating Systems cornerstone while the plant was at power and resulted in an unrecoverable unavailability of an individual mitigating strategy. Specifically, because the B.5.b portable gas generator was not functional for approximately 2.5 months with no compensatory actions in place, the Remote Operation of SRVs with RPV Injection mitigation strategy per Hope Creek procedure HC.OP-AM.TSC-0024, Revision 8, was determined to be unrecoverable and unavailable during this time. The inspectors noted that the reactor core isolation cooling (RCIC) system remained functional during this time period and as such the finding did not represent an unrecoverable unavailability of multiple mitigating strategies such that injection to RPV could not have occurred. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting aspect of Problem Identification and Resolution, Evaluation, because PSEG failed to thoroughly evaluate equipment deficiencies related to the B.5.b portable gas generator to ensure that the resolutions addressed causes and extent of conditions commensurate with the B.5.b equipments safety significance.
05000354/FIN-2014002-062014Q1Hope CreekFailure to Use Approved Method of Post-Scram Reactor Pressure ControlA self-revealing Green NCV of TS 6.8.1, Procedures and Programs, was identified for PSEGs failure to use procedures during scram recovery on December 5, 2013. Specifically, PSEG failed to use an approved method of post-scram reactor pressure control, causing the main turbine bypass valves (BPVs) to cycle rapidly resulting in a reactor pressure transient, reactor water level transient, and reactor protection system (RPS) actuation. PSEG entered this issue into their CAP under notification (NOTF) 20632369 and chartered a quick human performance investigation. As part of PSEGs corrective actions, the operators involved in the event were removed from shift and retrained, and each shift manager (SM) reviewed post-scram reactor pressure control methods with their crew and received training on this event, decision making, and procedural adherence. The inspectors determined that the performance deficiency was more than minor because it is associated with the human performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, PSEGs failure to implement procedures resulted in an unplanned reactor pressure transient, reactor water level transient, and ultimately resulted in RPS actuation and a trip signal to standby safety injection systems during scram recovery. Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety significance (Green) because it was not a deficiency affecting the design or qualification of a mitigating structure, system or component; it did not represent a loss of system or function; it did not represent the loss of function for any TS system, train, or component beyond the allowed TS outage time; and it did not represent an actual loss of function of any non TS trains of equipment designated as high safety significant in accordance with the PSEGs maintenance rule program. This finding was determined to have a cross-cutting aspect in Human Performance, Consistent Process, because PSEG failed to ensure that individuals use a consistent, systematic approach to make decisions and incorporate risk insights as appropriate. Specifically, operators did not use a systematic approach when making the decision to lower reactor pressure using the digital electro-hydraulic control (DEHC) system cooldown controller on December 5, 2013.
05000289/FIN-2012012-012012Q4Three Mile IslandFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000352/FIN-2012012-012012Q4LimerickFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000272/FIN-2012012-012012Q4SalemFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000219/FIN-2012012-012012Q4Oyster CreekFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000254/FIN-2012012-012012Q4Quad CitiesFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000456/FIN-2012012-012012Q4BraidwoodFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000461/FIN-2012012-012012Q4ClintonFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000454/FIN-2012012-012012Q4ByronFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000373/FIN-2012012-012012Q4LaSalleFailure to provide complete and accurate decommissioning status reportsDuring an NRC investigation completed on November 22, 2011, and a supplemental investigation completed on October 10, 2012, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.75(a) establishes requirements for indicating to the NRC how a licensee will provide reasonable assurance that funds will be available for the decommissioning process and states that for power reactor licensees, reasonable assurance consists of a series of steps as provided in paragraphs (b), (c), (e), and (f) of 10 CFR 50.75. 10 CFR 50.75(f)(2) states, in part, that power reactor licensees shall report at least every 2 years on the status of its decommissioning funding for each reactor or part of a reactor that it owns; and, that the information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c). 10 CFR 50.75(b)(1) states, in part, that for a holder of an operating license under 10 CFR Part 50, financial assurance for decommissioning shall be provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) adjusted using a rate at least equal to that stated in paragraph (c)(2). 10 CFR 50.75(c)(1) states the minimum amount required to demonstrate reasonable assurance of funds for decommissioning by reactor type and power level. 10 CFR 50.75(c)(2) requires, in part, that an adjustment factor be applied, which is based on escalation factors for labor and energy, and waste burial. 10 CFR 50.9(a) states, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on March 31, 2005, March 31, 2006, March 31, 2007, and March 31,2009, Exelon Generation Company, LLC (Exelon) provided information on the status of its decommissioning funding that was not complete and accurate in all material respects, when it submitted the decommissioning funding status (DFS) reports pursuant to 10 CFR 50.75. Specifically, the March 31, 2005, March 31, 2007, March 31, 2006, and March 31, 2009, DFS reports stated that the decommissioning funds estimated to be required for each of the reactors, as listed in the report, were determined in accordance with 10 CFR 50.75(b) and the applicable formulas of 10 CFR 50.75(c). However, in multiple instances, the amount reported was a discounted value that was less than the minimum required amount specified by 10 CFR 50.75(b) and (c). This is a Severity Level IV violation.
05000247/FIN-2000007-062000Q2Indian PointN/AThe control room operators did not enter significant plant items, such as event declaration and implementation of the emergency plan, in the control room logs, as required by Con Edison procedures. This procedure violation was a problem that was also noted for the August 31, 1999, loss of bus event. The failure to enter significant items into the control room logs was determined to be a non-cited violation. Although this issue does not affect any of the seven cornerstones (Attachment 1), it was considered important because prior corrective actions were not effective (Section 4OA2.3).
05000247/FIN-2000007-112000Q2Indian PointN/AIn the operations and engineering support areas, corrective actions to resolve known problems were untimely or incomplete. While the problems were of very low risk significance, some of these procedure and equipment problems caused unnecessary challenges to the operators and delays in achieving cold shutdown after the event. These problems included difficult procedural guidance for aligning pressurizer spray flow, non-functional steam generator leak monitoring (N-16) recorder, high pressure steam dump system deficiencies, and the lack of gas turbine Nos. 2 and 3 remote start capability (Section 4OA5).
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