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At 0955 on February 2, 2009, a Reactor Water Cleanup System heat exchanger outlet high temperature alarm and isolation signal was received. The Reactor Water Cleanup System inlet isolation valve (V-16-1), did isolate but the heat exchanger inlet isolation valve (V-16-14), failed to close in response to the system high temperature signal. The heat exchanger outlet high temperature isolation function was not a safety function and not a Tech .

Spec requirement. Later troubleshooting determined that a malfunctioning relay prevented V-16-14 isolation from the heat exchanger outlet high temperature signal. During troubleshooting on February 3, 2009, Operations determined that since V-16-14 was a primary containment isolation valve, this same malfunctioning relay would have also prevented that safety function and Tech Spec 3.5.A.3 applies. The Tech Spec required actions within four hours if a primary containment isolation valve became inoperable The relay problem was corrected and V-16-14 was returned to operable status at 1712 on February 3, 2009.

Based on the above, the four-hour.Tech Spec requirement was not achieved and this is being reported under 10 CFR 50.73(a)(2)(i)(B).

On May 7, 2015 at 1727 hours, a Main Turbine Trip and subsequent Reactor Scram occurred from a trip of the Main Transformer Differential Lockout Relay, 86T. The Main Transformer Differential Lockout Relay, 86T is a protection function provided by Digital Protection Relay System "B" (DPRSS). The 86T trip signal was sensed and cleared, without operator action, in 17 milliseconds (ms) or 1 cycle prior to the 230KV output breakers opening. The results of extensive troubleshooting ruled out an actual fault in the Main Transformers or Iso-phase Sus, and determined that the Main Transformer Differential Relay actuation was a spurious trip, and not due to an actual degraded equipment condition.

• ENS 51055 was submitted on May 7, 2015 as required by 10 CFR 50.72 (b)(2)(iv)(8). This issue is reportable under 10 CFR 50.73(a)(2)(iv)(A), any event or condition that resulted in manual or automatic actuation. of any of the systems listed in paragraph 10 CFR 50.73(a)(2)(iv)(8).

On October 29, 2012 at 21:00:57 hours, Nine Mile Point Unit 1 (NMP1) experienced an unplanned, automatic, reactor scram due to a Turbine Trip from 100 percent power caused by activation of a generator lockout relay. The generator trip was an unexpected consequence and was initiated by a high fault current condition in the Scriba switchyard detected by both NMP I instantaneous ground directional overcurrent relays. A polarity wiring error within the generator step up transformer neutral ground current transformers (CTs) caused the relay protection circuits to actuate on the fault in the Scriba switchyard. This was not expected because the relay protection circuits were designed to detect a fault condition between the main generator and the station output breakers. The error was caused by less than adequate oversight by CENG personnel of transformer XF-TB01 testing with respect to unclear specificity of requirements for vendor performed testing and inadequate methods of verification for ensuring vendor compliance with engineering specifications.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an actuation of the reactor protection system and an actuation of the high pressure coolant injection system while the reactor was critical.

Corrective actions include correcting the wiring of the CT circuits, verifying all the requirements in the engineering specification have been met, revising the associated electrical drawings, and revising engineering procedures to require the listing of critical attributes for equipment/components and to define testing criteria/verification methods to be performed when factory acceptance testing or modification functional testing cannot be performed to verify the functionality of equipment/components.

On November 02, 2009, an automatic reactor trip (RT) was initiated as a result of a turbine-generator protective trip (86P Lockout Relay). All control rods fully inserted and all required safety systems functioned properly.TThe Main Steam Isolation Valves (MSIVs) were closed after reports that one of the four turbine stop valves did not indicate fully closed.TThe plant was stabilized in hot standby with decay heat being removed by the Steam Generators (SG) via the Atmospheric Steam Dump Valves.TThe Emergency Diesel Generators did not start as of f site power remained available. The Auxiliary Feedwater System automatically started as expected due to SG low level from shrink effect.TThe direct cause was a high resistance connection on the common ground terminal between the Generrex power supplies and alarm cards.TThe cause of the event was a poor Original Equipment Manufacturer (OEM) design of the common ground wiring connections on the Generrex power supply distribution block.TCorrective actions included repairs to the Generrex power supply connection and installation of a second ground connection in the exciter cabinet.

T A Generrex system upgrade is planned for the refueling outage 19 in the spring of 2010 which includes upgrading to solid state power supplies and testing the ground wire.TThe event had no effect on public health and safety.

On July 3,'2013, operators initiated a manual reactor trip as a result of lowering steam generator (SG) levels due to the loss of feedwater (FW) from the trip of both main FW pumps. All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The Auxiliary Feedwater System automatically started as expected. Investigations determined the decreasing SG levels were due to a loss of main FW flow as a result of the closure of the FW regulating valves. The FW regulating valves closed due to a loss of instrument air (IA) pressure. The IA pressure was lost when a two inch copper IA tubing in the 22 Main Transformer moat separated at a soldered coupling. Prior to the event piping lines including the IA line buried in the main transformer moat were excavated and temporary supports installed. The apparent cause was poor legacy workmanship assembling the IA tubing coupling during original plant construction. The IA tubing was not fully inserted into the coupling resulting in reduced joint strength. Corrective actions included reassembly and soldering of the IA joint with full insertion, acoustic emission and snoop testing on repaired coupling.

Axial and thrust restraints were installed on the IA line in the moat. A caution was placed in the Buried Piping Program database associated with buried copper tubing identifying the potential for the separation of soldered joints when the line is excavated and the need for restraints or other contingencies to minimize the probability of a line separation.

The event had no effect on public health and safety.

On March 8, 2006 at approximately 1553, a loss of the Unit 3 3A 4 kV electrical distribution bus occurred during restoration of the 3C load center (LC) following outage maintenance. The 3A load sequencer performed bus load stripping and a loss of offsite power to the 3A bus occurred due to a degraded voltage 1 condition that was sensed on the 3C LC. This was caused by a misaligned auxiliary switch contact on the newly refurbished 3C 480V LC feeder breaker (30302). The 3A emergency diesel generator automatically started and restored power to the 3A bus; however, the 3C LC 4 kV supply breaker (3AA14) failed to close due inadequate contact wipe on normally closed relay contacts. Core cooling was reestablished at approximately 1600 utilizing the 3B residual heat removal (RHR) pump. The cause was vendor human error during breaker refurbishment of the 3C LC breakers (30302 and 3AA14) which went undetected by the vendor test and inspection programs and Turkey Point pre-installation checks. Corrective action includes:

For breaker 30302, the breaker refurbishment standard revised the final test and inspection procedure to record as left auxiliary switch contact configuration and compare it to the as found configuration (checks to be independently verified). For breaker 3AA14, the procurement specification and applicable receipt inspection procedure for HMA relays have been revised to verify adequate contact wipe by vendor and receipt inspection personnel, respectively. The increase in risk due to loss of core cooling is judged to be very small given the availability of the redundant RHR pump and power source, and the short period for restoration of cooling.

NRC FORM 966 (6-2004) PRINTED ON RECYCLED PAPER v.(�

On June 27, 2005, at 0316, Turkey Point Unit 4 reactor was automatically tripped from 100% power Main Transformer. The transformer was recently installed during the refueling outage in Spring 2005.

The fault ruptured the transformer tank releasing oil and caused a fire that damaged the transformer and adjacent equipment. At 0327, an Unusual Event was declared based on the fire in the plant protected area lasting longer than 10 minutes. The site fire brigade responded and extinguished the fire. Offsite fire fighting assistance was requested, but was not used to extinguish the fire. The fire was extinguished and the Unusual Event was terminated at 0500. All plant systems functioned as designed during and after the event. The operating crew controlled and stabilized the plant, and therefore the health and Main Transformer failure was a failed manufacturing process employed by the vendor's supplier of the clamping ring. Corrective actions included replacement of the Main Transformer and repair/replacement of components damaged by the resultant fire.

On August 2, 2001, at 0813 hours, lightning struck a 345 kV line that connected to the Quad Cities switchyard. This resulted in failure of the Unit 2 Main Power Transformer (MPT), an automatic reactor scram on Unit 2 and loss of normal offsite power to Unit 2. An Unusual Event was declared, the Unit 2 and 1/2 Emergency Diesel Generators started, and the Reactor Core Isolation Cooling system and the Safe Shutdown Makeup Pump were manually started to maintain reactor vessel level. The MPT fire was extinguished at 0845 hours and normal offsite power was restored to Unit 2 at 1047 hours.

The safety significance of this event was minimal. All safety systems operated as designed to shut the Unit 2 reactor down and maintain it in a safe shutdown condition. Offsite power was available to Unit 2 from the Unit 1 Reserve Auxiliary Transformer through the emergency bus crosstie throughout the event.

The root cause of the MPT failure was mechanical failure of the bus bar clamps due to original equipment manufacturer design and construction errors. The root cause of the loss of normal offsite power was age degradation in a Static Breaker Failure (SBF) relay.

The SBF relay was replaced and the preventive maintenance program has been upgraded concerning local breaker backup schemes. The MPT Specification Development Lessons Learned Review Checklist has been upgraded and a comprehensive transformer monitoring strategy will be implemented.

NRC FORM 3 6 6A (7-2 0 01 ) ���

On February 6, 2013 at 1132 CST, an undervoltage condition occurred on Unit 1, 1A-05 and 1A-06 safety-related buses, which was caused by a loss of 1X-03 high voltage station auxiliary transformer (HVSAT). The four emergency diesel generators (EDGs) started. The GO1 and G03 EDGs loaded onto buses 1A-05 and 1A-06. Unit 2 maintained offsite power throughout the event.

Unexpected operation of the 1F89-112 circuit switcher resulted in de-energization of the 1X-03 transformer causing a low voltage condition, which started the standby EDGs. The opening of the circuit switcher did not cause a lockout of 1X-03. As a result, the automatic transfer to the redundant offsite power supply In the switchyard was not initiated, and G01 and G03 EDGs automatically loaded onto Unit 1 safety-related buses 1A-05 and 1A-06, once they had reached operating voltage and frequency.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A), any event or condition that resulted in a manual Dr automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B), including any event or condition that results in the actuation of the emergency AC electrical power system.

On 5/24/2005, with three Oconee Units at 100% power in Mode 1, Oconee Operations and Engineering concluded that both Keowee Emergency Power Paths could be lost following certain single failures. An electrical contactor failed in the "Normal" supply to the cooling system of the Overhead Path Main Transformer. The "Back up" supply from the redundant Underground Path closed automatically. This line up would allow loss of both Emergency Power Paths on certain single failures. At 1350 hours TS 3.8.1 condition C was entered. The system was realigned and the TS condition was exited at 1540 hours. An investigation determined that the unacceptable alignment had existed since 0820 on 4/21/2005. Operations personnel found parts from the failed contactor on 5/3/2005, and notified their supervision but it was assumed the parts were from a different component with a known problem and did not take further action. The component failed primarily due to age and was replaced.

Root Causes are 1) the operability assessment failed to detect inadequate train separation, and 2) failure of the supervisor to verify his assumption.

On 07/18/2005, a corrective action revealed another single failure mode based on power alignment resulting from an original design deficiency. TS 3.8.1 condition C was entered briefly until the system was realigned and the condition exited. These events have no significance with respect to the health and safety of the public.

On 06/18/04 at 0640, with the plant at full power, a turbine load reject scram occurred due to a two phase electrical fault to ground on the 22 kV iso-phase bus. All safety systems responded as designed and the reactor was shutdown without incident. Off-site power transmission lines and station emergency power sources were available throughout the event. Arcing and heat generated during the fault damaged an area around the iso-phase bus ducts and Main Transformer low voltage bushings. The electrical faults disrupted an oil line flange between the Main Transformer oil conservator (expansion tank) and the "C" phase low voltage bushing box, and the leaking oil ignited. Fire suppression systems activated automatically. An Unusual Event was declared at 0650 for a fire lasting greater than 10 minutes. The VY fire brigade and local community fire departments declared the fire under control at 0717. At 1245, the Unusual Event was terminated. The electrical grounds that initiated the event were caused by loose material in the "B" iso-phase bus duct as a result of the failure of a flexible connector. The grounds raised the voltage on the "A" and "C" iso-phase busses contributing to the failure of the "A" phase surge arrester.

The root causes of the event were determined to be the result of a flexible connector fabrication deficiency and preventative maintenance not being performed on the surge arresters located in the Main Generator Potential Transformer (PT) Cabinet. There was no release of radioactivity, breach of secondary containment or personnel injury during this event.

On May 26, 2010, at approximately 1526 hours, a generator lockout and automatic reactor trip occurred on differential current between a current transformer (CT) installed in the newly commissioned switchyard and a CT installed in the plant. During startup, when the plant reached 72% power, both channels of the reactor protection system (RPS) actuated and all control rods inserted. Following the reactor trip reactor vessel level decreased causing primary containment isolation system (PCIS) actuation for groups 2, 3, 4, and 5.. All associated valves functioned correctly. Additionally, both trains of standby gas treatment system actuated.

Immediate plant actions included entering appropriate trip response procedures. The operators stabilized the plant and reset both RPS and PCIS. During RFO 28, Vermont Yankee (VY) and the Vermont Electric Power Company (VELCO) commissioned a new 345kV switchyard. The direct cause of the trip was that VELCO changed the CT ratio settings within the 345kV Switchyard and failed to communicate the new ratio setting to VY. As power was increased, the differential current caused by the difference in CT ratio settings resulted in the generator lockout. Corrective actions include adjustment of the VY CT to the correct settings and establishment of the necessary programmatic controls to preclude recurrence. This event is reportable as a licensee event report (LER) per 10CFR50.73(a)(2)(iv)(A) as an event or condition that resulted in actuation of the any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B), which includes RPS and PCIS.

On July 7, 2010, at approximately 1118, an automatic reactor trip was initiated due to a turbine trip above 50% reactor power. The turbine trip was the result of the actuation of the regular and back-up phase B-C differential relays in the main generator protection scheme. This actuation was the result of an arc flash across the "B" phase main power transformer bushing following an inadvertent actuation of the transformer fire protection deluge system. The deluge system was actuated by one of the 18 air-pilot sprinkler heads that fused due to the transformer's heat, unusually high ambient temperatures, direct sunlight and restricted ventilation caused by concrete walls that surround three sides of the main power transformer "B" phase. Mist from the deluge system actuation rose above the main power transformer "B" phase bushing, driven by the transformer operating fans, heat rising from the transformer and the close proximity of the concrete wall enclosure, which resulted in the observed arc flash and bushing failure.

Corrective actions included replacing the main power transformer deluge system air-pilot sprinkler heads with sprinkler heads that have a higher temperature setpoint.

This report is being made in accordance with 10CFR50.73(a)(2)(iv)(A), "any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)....

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As a result of control rod interference monitoring testing performed by Operations personnel on 1/28/09, it was determined that three control rods were inoperable during the unit shutdown that was performed on 1/21/09. This testing determined that Control Rods 14-55, 18-55 and 42-55 could be inoperable for operational conditions involving time periods when reactor pressure is below 850 psig (Mode 2 operations). This occurrence is considered reportable as a common cause that resulted in the inoperability of three control rods for approximately 4.75 hours on 1/21/09 during Mode 2 unit operations. The common cause is related to control rod blade interferences with the fuel channel. There were no actual safety consequences associated with this event. Appropriate shutdown margin was maintained during this event. A control rod interference monitoring / testing program was established. Extent-of-condition testing was performed on Units 2 and 3. There were no .previous similar LERs identified.

NRC FORM 366 (9-2007) PRINTED ON RECYCLED PAPER 5

On October 9, 2016 at 0254 hours, with Unit 1 and Unit 2 at 100 percent power, Unit 2 experienced an automatic reactor trip initiated by a turbine trip due to generator differential lockout relay actuation. At the time of the trip, high wind and heavy rain conditions existed due to the effects of Hurricane Matthew. All three auxiliary feedwater pumps automatically started on low-low steam generator water level as expected. All plant systems functioned as required, and Unit 2 was stabilized at hot shutdown. The trip response was not affected by any previously inoperable systems, structures, or components.

The direct cause of the generator differential lockout was an electrical ground overcurrent initiated by water accumulation in the "A" phase of the "A" station service transformer leads termination enclosure. Affected electrical enclosures were drained, the system was tested, and modifications to the enclosures to prevent recurrence of water intrusion were completed prior to returning Unit 2 to power operation on October 13, 2016.

This report is being submitted pursuant to 10CFR50.73(a)(2)(iv)(A) as an event that resulted in the automatic actuation of the Reactor Protection System' and the Auxiliary Feedwater System.

On July 6, 2006, at 0352 hours an automatic reactor trip (RT) occurred as a result of a short circuit that occurred in the junction box of the Main Generator output phase 113' differential protection current transformer (CT).

The plant responded to the trip as designed. The Auxiliary Feed Water System (AFW) actuated and the AFW Pumps started as designed due to the Steam Generator (SG) shrink caused by the trip from 100% power. All plant systems operated normally with the exception 31 Main Boiler Feed Pump Recirculation Valve did not open due to a failed solenoid and the 32 Main Steam Line Trap was isolated due to having a minor steam leak. The root cause of this condition was determined to be design inadequacy in material application. The abrasive property of the conductor's insulation jacket was not evaluated for use in a continuous vibration environment. Corrective actions included repair of damaged cables, coaching of personnel on the lessons learned, process/procedure revisions to improve the considerations on material selection in the design process and training enhancements to address material considerations. This event had no effect on public health and safety.

On August 10, 2009, during a severe thunderstorm, the Control Room received indication of a Turbine Trip and Reactor Trip initiated by the Generator Primary Lockout Relay (86P). All control rods fully inserted and all required safety systems functioned properly.T6.9 kV Bus 2 failed to auto transfer to 6.9 kV bus 5 resulting in the trip of the 34 Reactor Coolant Pump and de-energization of 480 volt safeguards Bus 2A.

Emergency Diesel Generator (EDG) 31 automatically started and re-energized 480 volt bus 2A.TThe plant was stabilized in hot standby with decay heat being removed by the main condenser.TThere was no radiation release.TEDG-32 and 33 remained in standby as of f site power remained available.

TThe Auxiliary Feedwater (AFW) System automatically started as expected due to Steam Generator low level from shrink effect.

T6.9kV Bus 2 was energized from 6.9 kV bus 5 via closure of 6.9 kV bus 2-5 tie Breaker. The direct cause was actuation of the Generator Primary Lockout Relay (86P) due to misoperation of relay 85L1/345 due to extraneous voltage induced on ground during a lightning strike.TThe root cause was the 345 kV Primary Pilot Wire System is susceptible to the maximum ground potential rise (GPR) based on the original design.

TThe susceptibility to GPR is due to 1) the calculated worst case GPR is higher than the insulating rating of the pilot wires, 2) The pilot wire system was not provided with equipment to protect against GPR. Corrective actions included inspection of 345 kV output feeder W96,Ttesting of pilot wire cables, calibration and testing of applicable protection system relays.TEnhancements will be implemented'to the Station Grounding Plan, and the 138 kV and 345 kV pilot wire systems replaced.TThe event had no effect on public health and safety.

On May 9, 2015, an automatic reactor trip (RT) occurred due to a Turbine-Generator trip as a result of a failure of the 31 Main Transformer (MT). All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the condenser. There was no radiation release. The emergency diesel generators did not start as offsite power remained available. The auxiliary feedwater system actuated as-expected due to steam generator low level from shrink effects. Control room operators received alarms on the fire detection panel of the activation of the 31 MT and curtain wall deluge valves. Report to operators that there was an explosion and fire on the 31 MT. The plant fire brigade responded to the fire. The 31 MT had failed. Due to collateral influence from the 31 MT failure, the deluge system for the 32 MT and Unit Auxiliary transformer had also activated. In accordance with the emergency plan a Notice of Unusual Event (NUE) was declared at 1801 hours, which was terminated at 21:04 hours. The direct cause was an internal fault of the A Phase high voltage winding in the upper portion of the transformer.

The root cause was vendor design/manufacturing deficiency that caused an internal failure that resulted in a fault on the A phase HV side of the transformer and the A phase HV voltage bushing. Key corrective actions included replacement of the 31 MT with a spare transformer, associated acceptance testing, repair of the isophase bus ducting for the 31 MT, inspections, cleaning, testing of the 32 MT, the Unit Auxiliary Transformer, high voltage components, isophase buses and main generator. A 4-year PM was prepared to perform Partial Discharge testing on the Unit 2, and Unit 3 MTs, Unit 2 and Unit 3 Auxiliary Transformers and the Unit 3 GT Auto Transformer The event had no significant effect on public health and safety.

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