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The following was received via fax and phone: This telephone notification is provided in accordance with Exelon Reportabllity manual SAF 1.1 0, 'Major Loss of Emergency Preparedness Capabilities', and 10CFR50.72(b)(3)(xiii). On June 6th 2015 at 12:13 (CDT), it was determined that the onsite Technical Support Center (TSC) Ventilation System Supply Fan belts had failed, resulting in loss of ventilation for the facility. Repairs were not completed within the time required had the TSC needed to be staffed. There is currently no emergency event in progress requiring TSC staffing. If an emergency is declared and the TSC ERO activation is required, the TSC will be staffed and activated unless the TSC becomes uninhabitable due to ambient temperatures, radiological, or other conditions. If relocation of the TSC staff becomes necessary, the Station Emergency Director will relocate the staff to an alternate TSC location in accordance with applicable site procedures. The licensee has notified the Senior Resident Inspector of the issue.

• • • UPDATE PROVIDED BY TODD CASAGRANDE TO NESTOR MAKRIS AT 2305 EDT ON 06/06/2015 ***

After repairs were completed, the TSC ventilation was restored to service at 2300 (EDT) on 06/06/2015. The licensee has notified the NRC Resident Inspector. Notified R3DO (Passehl) via email

LaSalle Station has completed a review of seismic monitor performance. The seismic monitor is currently operable; however, this review identified 6 times in the past 3 years that the seismic monitor was inoperable such that emergency classification at the ALERT level could not be obtained with site instrumentation. The seismic monitor was determined to be inoperable on the following dates:

 1) January 28, 2015
 2) May 28, 2014
 3) January 1, 2014
 4) August 5, 2013
 5) April 17, 2013
 6) April 10, 2012

These unplanned inoperable conditions of the seismic monitor were entered into the LaSalle Corrective Action Program when they occurred. While Exelon procedural direction allowed the use of offsite sources to obtain seismic data when the seismic monitor is incapable of assessing emergency plan Emergency Action Levels (EALs), this was not explicitly referenced in the approved EALs. The loss of assessment capability is reportable to the NRC within 8 hours of discovery in accordance with 10 CFR 50.72(b)(3)(xiii). This report is required per 10 CFR 50.72(a)(1)(ii) as an event that occurred within 3 years of the date of discovery. The licensee has notified the NRC Resident Inspector.

This notification is being provided pursuant with SAF 1.6 10CFR50.72(b)(2)(iv)(B) and SAF 1.7 10CFR50.72(b)(3)(iv)(A). At 1734 CDT on August 5, 2014, LaSalle Unit 2 automatically scrammed due to an RPS actuation. The MSIVs isolated on a Group 1 signal, the cause is under investigation. The reactor water cleanup system isolated during the transient. The plant is stable with Reactor Pressure Control being maintained by the Reactor Core Isolation Cooling System and SRVs and level being controlled by the Low Pressure Core Spray System. The plant is planned to remain in hot shutdown pending investigation of the trip." The Unit 2 electric plant is in a normal shutdown lineup. All control rods inserted fully on the scram. Unit 1 was not affected by the Unit 2 transient. The licensee notified the NRC Resident Inspector.

• * * UPDATE PROVIDED BY MICHAEL FITZPATRICK TO JEFF ROTTON AT 1650 EDT ON 8/6/2014 * * *

The initial notification to the NRC stated that the reactor water cleanup system had isolated during the transient. The actual status is being corrected to state that the reactor water cleanup pump tripped during the transient. The licensee has notified the NRC Resident Inspector. Notified R3DO (Stone).

This report is being made pursuant to 10CFR50.72(b)(3)(v)(D), Event or Condition that could have prevented fulfillment of a Safety Function needed to Mitigate the Consequences of an Accident. During routine Instrument Maintenance Surveillance Testing (LIS-HP-205), the High Pressure Core Spray System (HPCS) minimum flow valve pressure switch set point was found outside the Technical Specification allowable value. This could have prevented the High Pressure Core Spray System (HPCS), a single train safety system, from performing its design function. This is reportable as an 8 hour ENS notification. The required actions of Technical Specification (TS) 3.5.1 were entered on 7/01/13 at 1646 (CDT) when the system was made inoperable for surveillance testing. At 1705, maintenance personnel reported minimum flow valve pressure switch set point was found at 112.6 psig, which is outside of the TS Allowable Value of greater than or equal to 113.2 psig (0.6 psig below the Allowable Value). The minimum flow valve pressure switch set point has been calibrated and was left within Technical Specification allowable values, HPCS was declared OPERABLE at 1815 on 7/01/13." The licensee has notified the NRC Resident Inspector.

• * * RETRACTION FROM STEVE CHURCHILL TO JOHN SHOEMAKER AT 1346 EDT ON 8/5/2013 * * *

The event notification was reported by LaSalle Generating Station on 7/01/2013 at 2147 EDT. This update is being provided for the purposes of retracting that notification. On July 1, 2013, during surveillance testing, the Unit 2 High Pressure Core Spray System (HPCS) minimum flow valve pressure switch setpoint was found below the Technical Specification (TS) 3.3.5.1 allowable value. HPCS was declared inoperable, and TS Required Actions (RA) were entered on July 1, 2013, at 1646 hours (CDT). Because HPCS is a single train system, an ENS report was made pursuant to 10 CFR 50.72(b)(3)(v)(D), as an event or condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident. The minimum flow valve pressure switch setpoint was calibrated to within TS allowable values, and HPCS was declared operable on July 1, 2013, at 1815 hours. A post-event review determined that declaring HPCS inoperable was not required. The inoperability of the pressure switch would not have impacted the function of the HPCS minimum flow valve to automatically open as required to prevent overheating of the HPCS pump. The as-found setpoint was 0.6 psig below the TS allowable value, which would have resulted in the minimum flow valve opening slightly sooner. The inoperability would also not have prevented or delayed the automatic closing of the valve at the required system flow to assure that adequate ECCS flow is available. It should be noted that the LaSalle ECCS (Emergency Core Cooling System) LOCA (Loss Of Coolant Accident) analysis assumes that the HPCS minimum flow valve is open during an injection. TS 3.3.5.1 RA D.4 requires that the minimum flow valve pressure switch be restored to operable status within 7 days. If it cannot be restored within that time, RA G.1 requires that the supported system (HPCS) be declared inoperable, precluding extended operation with the minimum flow pressure switch inoperable. The pressure switch was re-calibrated to within TS allowable values within approximately 1 hour and 29 minutes of being declared inoperable. Therefore, the HPCS system was operable with the minimum flow pressure switch 0.6 psig out of calibration for 1 hour and 29 minutes. This event did not constitute a loss of safety function of the HPCS system, and the event was not reportable under 10 CFR 50.72(b)(3)(v)(D). The licensee has notified the NRC Resident Inspector. Notified R3DO (Lara).

LaSalle Unit 1 and LaSalle Unit 2 have both experienced an automatic reactor scram, in conjunction with a loss of offsite power. This was caused by an apparent lightning strike in the main 345kV/138kV switchyard during a thunderstorm. 138kV line 0112 has been inspected in the field, and heavy damage has been noted on the insulators on two of the three phases on a line lightning arrestor line side. The plant systems have all responded as expected. All five diesel generators started, and have loaded on to their respective buses as designed. All rods went full in on both units during the respective scrams. HPCS (High Pressure Core Spray) system was started on each unit and automatically aligned for injection for initial level control. The MSIVs (Main Steam Isolation Valves) are shut on both units with decay heat being removed via the safety relief valves. Suppression pool cooling is in progress. The licensee will notify the NRC Resident Inspector and has notified the State. Notified DHS, FEMA, USDA, HHS, DOE, NICC, EPA, and Nuclear SSA via email.

• * * UPDATE FROM DON PUCKETT TO VINCE KLCO AT 2113 EDT ON 4/17/2013 * * *

In addition to information (previously provided), LaSalle Unit 2 received a high drywell pressure signal (1.77 psig) due to loss of containment cooling from the loss of power. At the time of this high drywell pressure signal, high pressure core spray pump and 2B residual heat removal (RHR) pump was already in operation, the low pressure core spray system and 2A residual heat removal system was secured and (placed) in pull to lock. When the signal was satisfied the ECCS (Emergency Core Cooling Systems) signal was processed but only the 2C RHR pump would have started. In this case, the 2C RHR pump tripped when the signal was received. There is no evidence of reactor coolant leakage. There was no additional ECCS systems discharging into the RCS (Reactor Coolant System). As (initially stated), level was controlled using High Pressure Core Spray and level control is now being maintained using the Reactor Core Isolation Cooling (RCIC) systems. The 2C RHR pump trip is under investigation. Due to the initial loss of offsite power for both Unit 1 and Unit 2 reported at 1511 (CDT), multiple containment isolation valves isolated and closed as expected. Once initial containment isolations were verified, two Unit 2 primary containment vent and purge valves were opened to vent the Unit 2 containment. Once Unit Two containment pressure reached 1.77 (psig), these two vent valves isolated as expected. Due to the loss of offsite power, the Station Vent Stack Wide Range Gas Monitor (WRGM) and the Standby Gas Treatment Wide Range Gas Monitor (VGWRGM) also lost power. Manual sampling has been implemented and power is restored to the VGWRGM, however the VGWRGM has not been declared operable yet. Normal radiation levels have been reported from the manual sampling. (This is being reported in accordance with 10CFR50.72(b)(3)(xiii).) The licensee notified the NRC Resident Inspector and the State of Illinois. Notified the R3 IRC, NRR EO(Skeen), IRD MOC (Grant).

• * * UPDATE AT 0057 EDT ON 04/18/13 FROM MIKE LAWRENCE TO S. SANDIN * * *

After the Unit 2 primary containment vent and purge system isolated on the Unit 2 containment High Pressure signal, Venting of the Unit 1 primary containment was commenced. At 2005 CDT, Unit 1 primary containment pressure reached the Group 2 primary containment isolation system setpoint (1.77 PSIG) causing the primary containment vent and purge valves being used to vent the Unit 1 containment to isolate. Unit 1 primary containment venting was being performed through the Standby Gas Treatment system which is a filtered system. In addition to the primary containment isolation signal on high drywell pressure, an ECCS initiation on high drywell pressure also occurred. The ECCS signal resulted in an auto start of the 1C RHR system. The 1B RHR system was already running in suppression pool cooling mode. 1A RHR and LPCS had been secured to prevent overloading the common diesel generator for division 1. The common diesel generator supplies both Unit 1 and Unit 2 division 1 ESF busses. The licensee informed the NRC Resident Inspector. Notified NRR EO (Skeen), IRD MOC (Grant) and R3IRC (Louden).

• * * UPDATE AT 0947 EDT ON 04/18/13 FROM JUSTIN FREEMAN TO PETE SNYDER * * *

LaSalle has terminated the unusual event which was initiated at 1511 on 4/17/13 and reported under EN 48939. This unusual event has been terminated based on meeting the following established criteria. This report is being made in accordance with 10CFR50.72.(c)(1)(iii). 1) Off-site power has been restored to all ESF busses 2) Fuel Pool Cooling has been restored on both units 3) Primary Containment Chillers have been restored on both units 4) Drywell pressure is less than ECCS initiation setpoint 5) ECCS signals cleared to allow diesels to be placed in stand by Recovery of remaining plant systems will be managed through the Outage Control Center (OCC)." The licensee informed the NRC Resident Inspector. Notified R3DO (Orth), NRR EO (Chernoff), IRD (Grant), DHS, FEMA, USDA, HHS, DOE, NICC, EPA, and Nuclear SSA via email.

• * * UPDATE AT 1711 EDT ON 4/21/2013 FROM GREG LECHTENBERG TO MARK ABRAMOVITZ * * *

In addition to the 10 CFR 50.72 Sections initially identified, the Loss of Offsite Power was also reportable under 10 CFR 50.72(b)(3)(v)(D) as an event or condition that could have prevented the fulfillment of the safety function of systems needed mitigate the consequences of an accident. This event is considered a safety system functional failure for both Units 1 and 2. The licensee will notify the NRC Resident Inspector. Notified the R3DO (Orth).