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On February 27, 2011, at 2159 CST, during the testing of the A train safety injection (SI) system (BQ), it was discovered that the oiler for the Unit 2, B train SI pump, had rotated and the oil had drained out. The B train SI pump was declared inoperable. At the time of the event, the A train of SI was out of service for performance of a routine inservice test. Because both trains of SI were inoperable, LCO 3.0.3 was entered. Upon completion of the A train inservice test, Unit 2 exited LCO 3.0.3 at 2211 CST.

Immediate corrective actions taken included restoring the oiler to the vertical position, refilling it and performing a 5-minute pump run. The root cause of the event was determined to be a 1995 modification to the SI pump oiler which introduced a latent design/configuration flaw. Additional corrective actions will include a design change to the SI pumps and oiler assemblies for both units to reduce the possibility of accidental misalignments. The actions are being tracked to completion in the corrective action program.

An 8-hour ENS report was made in accordance with 10 CFR 50.72(b)(3)(v)(D) on February 28, 2011 at 0345 CST.

On October 30, 2017, with Unit 1 in MODE 3 for refueling activities, a boric acid indication downstream of 1CV-309B, 1P-1B Reactor Coolant Pump (RCP) Labyrinth Seal 1 DPT-124 Upper Root Valve was identified as a through-wall flaw. The flaw location on the root valve to differential pressure transmitter (DPT) instrument tubing welded joint was within the reactor coolant system (RCS) pressure boundary.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(ii)(A) for material defects in the primary coolant system that were not acceptable in accordance with ASME Section XI.

At 1724 (CDT) on 9/18/17 Door-061, South Control Room Door (DR) was inadvertently disabled. The door became wedged open against its backstop during control room ventilation testing. Door-061 is a barrier that functions to maintain the control room envelope (NA). The barrier was subsequently disengaged from the backstop allowing it to close. The door was inspected and returned to operable status at 1750 (CDT). While the door was stuck open, the control room was in an unanalyzed condition, a condition that could have prevented fulfillment of a safety function, and a common cause inoperability of independent trains or channels.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(ii)(B), 10 CFR 50.73(a)(2)(v)(A), 10 CFR 50.73(a)(2)(v)(D), and 10 CFR 50.73(a)(2)(vii) for a degraded barrier that affected the control room envelope.

On April 1, 2016 the 345/13.8kV high voltage station auxiliary transformer (1X-03) tripped on a differential current relay (1-87A/X-03) actuation. Review of this event determined that there were three instances over the past three years when the required action completion time for not satisfying the Limiting Conditions For Operation of Technical Specification 3.8.1 (AC Sources - Operating) and 3.8.2 (AC Sources - Shutdown) would have been exceeded with the latent error present.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B) for operation or condition prohibited by technical specifications.

On June 4, 2015 with both units at full power, it was identified that removal of the W-185A(B), G-03(04) Emergency Diesel Generator (EDG) Switchgear Room Exhaust Fan from service may result in the inability to maintain switchgear room temperatures below that required to maintain equipment operable.

Subsequent engineering evaluation has determined that room temperature could have exceeded environmental conditions at which the components would be reasonably expected to function for their respective mission times with the G-03(04) EDG Switchgear Room Exhaust Fan(s) out of service. This condition resulted in a condition prohibited by Technical Specifications, Technical Specification 3.8.9. Distribution Systems- Operating. Additionally, Technical Specification 3.8.9 required action A.1 would have required immediate declaration of the associated supported required feature(s) inoperable.

No opposite train plant systems were affected by this condition.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B), Operation or Condition Prohibited by Technical Sf.J~:dfi .... auuns, and 10 CFR 50.73(a)(2)(vii), Common Cause lnoperability of Independent Trains or Channels.

On December 2, 2014, operators commenced a rapid power reduction of Unit 1 due to noted degradation of Unit 1B Condensate Pump. At 2050 on December 2, 2014, with Unit 1 in Mode 1 at 62% power, operators initiated a manual reactor trip of Unit 1 following securing of the Unit 1B Condensate Pump due to imminent failure. The Auxiliary Feedwater Pumps started as expected on low steam generator level experienced due to the reduced steam demand from the turbine trip in response to the reactor trip. All other plant systems functioned as required.

After the reactor trip, feedwater pump suction pressure remained low. The decision was made to secure both Main Steam Generator Feedwater Pumps. The Main Steam Generator Feedwater Pump A was manually secured. Prior to securing the Main Steam Generator Feedwater Pump B, it automatically tripped. All control rods fully inserted in the core due to the manual trip. There was no Emergency Core Cooling System actuation. Offsite power was maintained throughout the event. The Main Steam Generator Feedwater Pumps were available to be restarted due to the recovered feedwater suction pressure from the running Condensate Pump A.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) for both the manual RPS actuation and also for the automatic initiation of Auxiliary Feedwater.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01131/2017 Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. NuclearRegulatory Commission, Was hington, DC 20555-0001,or byinternet e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

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 June 6, 2011, while Unit 1 was in MODE 1 and Unit 2 was in MODE 4, the feeder breaker to safeguards 480V bus, 2B-04, opened on overcurrent.

The feeder breaker tripped on overload after energizing a pressurizer heater group. This trip resulted in de- energizing electrical bus 2B-04. No other breakers tripped during this event. The results of an investigation determined the overload trip was improperly set low.

A technical assessment for reportability was completed. Nextera Energy Point Beach, LLC (NextEra) determined that electrical bus 2B-04 was inoperable for specific time periods from March 23, 2011 through June 7, 2011 for Unit 1 and Unit 2. Technical Specification Limiting Conditions for Operation (LCOs) and associated Action Conditions (TSACs) for TS 3.8.9 Distribution System - Operating (TSAC 3.8.9 A and B), TS 3.8.10 Distribution Systems - Shutdown (TSAC 3.8.10 A), and TS 3.5.3 ECCS - Shutdown (TSAC 3.5.3 A and B) were not met during specific time periods. Therefore, pursuant to 10 CFR 50.73(a)(2)(i)(B), the event is reportable as a condition prohibited by Technical Specifications. This event is also being reported pursuant to 10 CFR 50.73(a)(2)(v)(D), any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

The feeder breaker overload trip setting was corrected.

On 11/27/2011 at 0226 CDT, an undervoltage condition occurred on Unit 1, 1A-05 and 1A-06 safety-related buses during the restoration of 1X-03 high voltage station auxiliary transformer (HVSAT). The four emergency diesels (EDGs) started. The G-01 and G-03 EDGs loaded onto buses 1A-05 and 1A-06. Offsite power remained available to Unit 2 throughout the event via an alternate path.

During switchyard realignment of the 1X03 HVSAT, the 1F89-112 circuit switcher failed. This resulted in a low voltage condition which started the standby EDGs. The fault did not cause a lockout of 1X03, the associated switchyard component. As a result, the automatic transfer to the redundant offsite power supply in the switchyard was not initiated, and GO1 and G03 automatically loaded onto Unit 1 safety system buses 1A05 and 1A06 once the diesels had reached operating voltage and frequency.

The safety significance of this event was low because at the time of the event Unit 1 was in MODE 5, and shutdown cooling capability was maintained via the steam generators. Following the event, station procedures were revised to check local circuit switcher indicators for proper configuration prior to and following operation.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A), any event or condition that resulted in a manual or 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.

This supplement provides the results of the detailed extent of condition evaluation completed in March 2009 and the risk significance evaluation completed on April 17, 2009. On July 16, 2008, plant staff concluded that an inadequate cable separation condition in the Auxiliary Feedwater (AFW) room could potentially compromise the plant's ability to meet Appendix R safe shutdown requirements. An 8-hour report was made via the emergency notification system (EN 44351), pursuant to 10 CFR 50.72(b)(3)(ii) (B). Immediate corrective actions included fire area rounds already being performed by plant personnel, implementation of transient combustible controls in the AFW area and performance of thermography for insipient fire detection in the AFW pump rooms.

An extent of condition evaluation completed in March 2009 confirmed the results of the August 2008 evaluation identifying six (6) areas where an inadequate cable separation condition could potentially result in a loss of significant equipment in areas beyond that postulated in the initiating fire area. The results of a risk significance evaluation completed on April 17, 2009, concluded that the risk significance of each of the inadequate cable separation conditions was less than the red finding threshold and may be resolved in accordance with the alternate methods established in NFPA-805.