ML16174A094

NRC Component Design Bases Inspection Report 05000373/2016007; 05000346/2016007

ML16174A094
Person / Time
Site:	LaSalle
Issue date:	06/22/2016
From:	Jeffers M Division of Reactor Safety III
To:	Bryan Hanson Exelon Generation Co
References
IR 2016007
Download: ML16174A094 (47)

See also: IR 05000373/2016007

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION III 2443 WARRENVILLE RD. SUITE 210 LISLE, IL 60532-4352 June 22, 2016 Mr. Bryan C. Hanson Senior VP, Exelon Generation Company, LLC President and CNO, Exelon Nuclear 4300 Winfield Road Warrenville, IL 60555 SUBJECT: LASALLE COUNTY STATION, UNITS 1 AND 2 - NRC COMPONENT DESIGN BASES INSPECTION, INSPECTION REPORT 05000373/2016007; 05000374/2016007 Dear Mr. Hanson: On May 13, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed a Component Design Bases Inspection at your LaSalle County Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on May 13, 2016, with Mr. Trafton, Site Vice President, and other members of your staff. Based on the results of this inspection, four NRC-identified findings of very-low safety significance were identified. The findings involved violations of NRC requirements. However, because of their very-low safety significance, and because the issues were entered into your Corrective Action Program, the NRC is treating the issues as Non-Cited Violations in accordance with Section 2.3.2 of the NRC Enforcement Policy. If you contest the subject or severity to any of these Non-Cited-Violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the LaSalle County Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the LaSalle County Station.

B. Hanson -2- In accordance with Title 10 of the Code of Federal Regulations Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). Sincerely, /RA/ Mark T. Jeffers, Chief Engineering Branch 2 Division of Reactor Safety Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18 Enclosure: IR 05000373/2016007; 05000374/2016007 cc: Distribution via LISTSERV

Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION III Docket No: 50373; 50-374 License No: NPF11; NPF-18 Report No: 05000373/2016007; 05000374/2016007 Licensee: Exelon Generation Company, LLC Facility: LaSalle County Station, Units 1 and 2 Location: Marseilles, IL Dates: April 4, 2016 May 13, 2016 Inspectors: N. Féliz Adorno, Senior Reactor Inspector, Lead A Dahbur, Senior Reactor Inspector, Electrical J. Corujo Sandín, Reactor Inspector, Mechanical D. Reeser, Operations Inspector J. Leivo, Electrical Contractor C. Edwards, Mechanical Contractor Approved by: M. Jeffers, Chief Engineering Branch 2 Division of Reactor Safety

TABLE OF CONTENTS SUMMARY ................................................................................................................................ 2 REPORT DETAILS .................................................................................................................... 5 1. REACTOR SAFETY ......................................................................................... 5 1R21 Component Design Bases Inspection (71111.21) ...................................... 5 4. OTHER ACTIVITIES .......................................................................................22 4OA2 Identification and Resolution of Problems .................................................22 4OA6 Management Meetings .............................................................................26 SUPPLEMENTAL INFORMATION ............................................................................................. 1 KEY POINTS OF CONTACT .................................................................................................. 1 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED ....................................................... 1 LIST OF DOCUMENTS REVIEWED ...................................................................................... 2 LIST OF ACRONYMS USED .................................................................................................17

2 SUMMARY Inspection Report 05000373/2016007; 05000374/2016007, 04/04/2016 05/13/2016; LaSalle County Station, Units 1 and 2; Component Design Bases Inspection. The inspection was a 3-week onsite baseline inspection that focused on the design of components. The inspection was conducted by four regional engineering and operations inspectors, and two consultants. Four Green findings were identified by the team. These findings were considered Non-Cited Violations (NCVs) of U.S Nuclear Regulatory Commission (NRC) regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green; or Green, White, Yellow, and Red) and determined using , dated April 29, 2015. Cross-cutting aspects are determined using Inspection Manual Chapter the Cross-Cutting Areas,d December 4, 2014. All violations of NRC requirements are February 4, 2015. The s program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-,5, dated February 2014. NRC-Identified and Self-Revealed Findings Cornerstone: Mitigating Systems Green. The team identified a finding of very-low safety significance (Green) and an associated NCV of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B, Instructions, Procedures, and Drawingsfouling conditions of the core standby cooling system (CSCS) equipment area coolers. Specifically, the licensee did not develop performance test procedures to assess the fouling conditions of the safety-related CSCS equipment area coolers and did not have acceptance criteria that delineate when to remove accumulations. The licensee captured this issue in their Corrective Action Program (CAP) as Action Request (AR) 02665463 and established a standing order for operations to impose more restrictive service water temperature limits to reasonably assure the operability of the affected coolers until long term corrective actions were implemented to restore compliance. The performance deficiency was determined to be more than minor because it was associated with the Mitigating System cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee reviewed actual service water temperature values measured during the last 12 months, performed an operability evaluation, and concluded that the historical temperatures did not exceed the operability limits established by the operability evaluation. The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance. Specifically, the test program for the CSCS equipment area coolers was developed in the decade of 1990s. (Section 1R21.3.b(1))

3 Green. The team identified a finding of very-low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, for the failure to have the capability to verify the supply breakers of both reactor units feeding the swing diesel generator (DG) components were closed during normal plant operation. Specifically, the circuit design and procedures for the swing DG room fan, fuel oil transfer pump, and fuel storage tank room exhaust fan did not ensure the detection of the condition where one of these feeder breakers was tripped in the open position during normal plant operation. The licensee captured this issue in their CAP as AR 02668759 and created a special log to monitor the associated breakers once per day. The performance deficiency was determined to be more than minor because it was associated with the Mitigating System cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance (Green) because it did not result in the loss of system and/or function, represent an actual loss of function of at least a single train or two separate safety systems out-of-service for greater than its Technical Specifications (TS) allowable outage time, and represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, a historical review did not find an example where the swing DG was non-functional for a period greater than the applicable TS allowable outage time as a result of this finding during the last year. The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the mean to detect an opened breaker associated with the affected loads was established more than 3 years ago. (Section 1R21.3.b(2)) Green. The team identified a finding of very-low safety significance (Green) and an associated NCV of 10 CFR Part failure to establish procedures that were appropriate to manage containment debris consistent with the emergency core cooling system strainer debris loading design basis and supporting design information. Specifically, the procedures did not contain instructions for evaluating containment debris sources consistent with the associated analyses and other design documents. The licensee captured the team concerns in their CAP as AR 02663076 and AR 02656299. The immediate corrective actions included an operability evaluation that reasonably determined all of the affected emergency core cooling system strainers remained operable. The performance deficiency was determined to be more than minor because it was associated with the procedure quality 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. The finding screened as of very-low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee performed an operability review and reasonably determined that only a portion of the unqualified coatings would be available for transport to the strainers and this quantity was bounded by the associated design basis analysis. In addition, this review reasonably determined that sufficient analytical margin existed to accommodate the quantities of the other debris types found during recent inspections. The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the associated procedures were established more than 3 years ago. (Section 1R21.4.b(1))

4 Green. The team identified a finding of very-low safety significance (Green) and associated NCV of the LaSalle County Station Operating License for the failure to ensure that procedures were in effect to implement the alternate shutdown capability. Specifically, the abnormal operating procedures (AOPs) established to respond to a fire at the main control room did not include instructions for verifying that supply breakers for three reactor core isolation cooling motor-operated valves (MOVs) were closed to ensure they could be operated from the remote shutdown panel. Fire-induced failures could result in tripping MOV power supply breakers prior to tripping the MOV control power fuses. The licensee captured the team concerns in their CAP as AR 02668854 and established compensatory actions to reset the affected breakers, if required The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of protection against external events (fire), and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very-low safety significance (Green) because it was assigned a low degradation factor. Specifically, the procedural deficiencies could be compensated by operator experience/familiarity and the fact that the AOPs included steps to verify other breakers at the same locations were closed would likely prompt operators to close the remaining breakers. The team determined that this finding had a cross cutting aspect in the area of problem identification and resolution because the licensee failed to take effective corrective actions for a similar issue identified in 2014. Specifically, the resolution of this issue included actions to revise the affected AOPs to include verifying all the reactor core isolation cooling MOVs supplied breakers were closed. However, the licensee failed to include all of the MOVs in the revised AOPs. [P.3] (Section 4OA2.b(1))

5 REPORT DETAILS 1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1R21 Component Design Bases Inspection (71111.21) .1 Introduction The objective of the Component Design Bases Inspection (CDBI) is to verify that design bases have been correctly implemented for the selected risk-significant components and that operating procedures and operator actions were consistent with design and licensing bases. As plants age, their design bases may be difficult to determine and an important design feature may be altered or disabled during a modification. The Probabilistic Risk Assessment (PRA) Model assumes the capability of safety systems and components to perform their intended safety function successfully. This inspectable area verifies aspects of the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones for which there are no indicators to measure performance. Specific documents reviewed during the inspection are listed in the Attachment of this report. .2 Inspection Sample Selection Process The team LaSalle County Station, Unit 1 and 2, Standardized Plant Analysis Risk Model to identify one scenario to use as the basis for component selection. The scenario selected was a loss of offsite power (LOOP) event. Based on this scenario, a number of risk-significant components were selected for the inspection. In addition, the team selected a risk-significant component with Large Early Release Frequency (LERF) implications using information the LaSalle County Station, Units 1 and 2, Standardized Plant Analysis Risk Model. The team also used additional component information such as a margin assessment in the selection process. This design margin assessment considered original design reductions caused by design modifications, power uprates, or reductions due to degraded material condition. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as performance test results, significant corrective actions, repeated maintenance activities, Maintenance Rule (a)(1) status, components requiring an operability evaluation, system health reports, and U.S. Nuclear Regulatory Commission (NRC) resident inspector input of problem areas and/or equipment. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins. A summary of the reviews performed and the specific inspection findings identified are included in the following sections of this report. The team also identified procedures and modifications for review that were associated with the selected components. In addition, the team selected operating experience issues associated with the selected components.

6 This inspection constituted 17 samples (i.e., 11 components, 1 component with LERF implications, and 5 operating experiences) as defined in Inspection Procedure 71111.21-05. .3 Component Design a. Inspection Scope The team reviewed the Updated Final Safety Analysis Report (UFSAR), Technical Specification (TS), Technical Requirements Manual, drawings, calculations, and other available design and licensing basis information to determine the performance requirements of the selected components. The team used applicable industry standards, such as the American Society of Mechanical Engineers Code, Institute of Electrical and Electronics Engineers Standards, and the National Electric Code, to assess the systems design. The team also reviewed licensee actions, if any, taken in response to NRC issued operating experience, such as Generic Letters (GL) and Information Notices (INs). The team reviewed the selected components design to assess their capability to perform their required functions and support proper operation of the associated systems. The attributes that were needed for a component to perform its required function included process medium, energy sources, control systems, operator actions, and heat removal. The attributes that verified component condition and tested component capability were appropriate and consistent with the design bases may have included installed configuration, system operation, detailed design, system testing, equipment and environmental qualification, equipment protection, component inputs and outputs, operating experience, and component degradation. For each of the components selected, the team reviewed the maintenance history, preventive maintenance activities, system health reports, operating experience-related information, vendor manuals, electrical and mechanical drawings, operating procedures, and licensee Corrective Action Program (CAP) documents. Field walkdowns were conducted for all accessible components selected to assess material condition, including age-related degradation, configuration, potential vulnerabilities to hazards, and consistency between the as-built condition and the design. In addition, the team interviewed licensee personnel from multiple disciplines such as operations, engineering, and maintenance. Other attributes reviewed are included as part of the scope for each individual component. The following 12 components (i.e., samples), including a component with LERF implications, were reviewed: Unit 2, Reactor Core Insolation Cooking (RCIC) Pump (2E51-C001): The team reviewed the following hydraulic calculations to assess the pump capability to perform its required mitigating functions: pump minimum required flow, runout flow, flow capacity, and minimum required net positive suction head (NPSH). In addition, the team reviewed analyses associated with water hammer and other gas intrusion considerations, such as the condensate storage tank minimum water level setpoint and instrument uncertainty calculations. The team also reviewed test procedures and completed surveillance tests, including quarterly and comprehensive in-service testing, to assess the associated methodology, acceptance criteria, and test results. In addition, the team reviewed design analyses and test documents of the equipment area cooler to assess its

7 capability to maintain room temperature below the maximum qualification temperature value of the RCIC pump support components. The team also assessed the pump protective measures against flooding, seismic, and high-energy line break (HELB) effects. Unit 2, RCIC Turbine (2E51-C002): The team reviewed analyses for turbine minimum required steam flow, turbine required speed, and water hammer in the steam exhaust line to assess the RCIC turbine capability to perform its required mitigating functions. The team also reviewed turbine speed control and trip test procedures, results, and trends, as well as vendor information, such as General Electric Service Information Letters, to assess the turbine control system capability to perform its function. In addition, the team reviewed design analyses and test documents of the equipment area cooler to assess its capability to maintain room temperature below the maximum qualification temperature value of the RCIC turbine support components. The team also assessed the turbine protective measures against flooding, seismic, and HELB effects. Unit 2, RCIC Steam Supply MOV (2E51-F045): The team reviewed analyses for maximum differential pressure, weak link, and minimum required thrust to assess the valve capability to provide its required mitigating functions. In addition, the team reviewed test procedures and recently completed surveillance tests to assess the associated methodology, acceptance criteria, and test results. The team also reviewed the valve seismic and HELB analyses to assess the associated protective measures. In addition, the team reviewed electrical load flow calculations to assess the motor capability to operate the valve under degraded voltage conditions. The team also reviewed the protective relaying scheme, including drawings, calculations and schematic diagrams, to assess its capability to provide motor protection and to preclude spurious tripping under accident conditions. Unit 2, Drywell Purge Isolation Air-Operated Valve (2VQ-34): The team reviewed analyses for maximum differential pressure, weak link, and minimum required thrust to assess the valve capability to provide its function. The team reviewed leak rate test procedures and recently completed surveillance tests to assess the associated methodology, acceptance criteria, and test results, and ultimately assess the valve capability to perform its containment barrier function. In addition, the team reviewed the valve seismic and HELB analyses to assess the associated protective measures. This review constituted one component sample with LERF implications. Swing Diesel Generator (DG) (0DG01K): The team reviewed the following DG test procedures and completed surveillance tests to assess the associated methodologies, acceptance criteria, and test results: single load rejection, full load rejection, and capability to accept load within it design bases time. In addition, the team reviewed tests and calculations associated with room heat up, combustion air, and exhaust design. The team also reviewed the DG protective measures against flooding, HELB, and tornado generated missiles. The following loading calculations were reviewed to assess the DG capability to perform its safety function: voltage, frequency, current, and loading sequences during postulated LOOP and loss-of-coolant accident (LOCA) conditions. The team also reviewed protective relay setpoint calculations and setpoint calibration

8 test results to assess the DG protection during testing and emergency operations. A sample of TS surveillance results were reviewed to assess compliance with the acceptance criteria and test frequency requirements. In addition, the team reviewed the following DG auxiliary sub-components: Air Start Receivers (0DG06TA/B) and Motors (0DG08KA/B/C/D): The team reviewed the pre-operational test results of the air start receivers to assess their capacity to support the minimum number of required DG starts. In addition, test procedures and completed surveillance tests were reviewed to assess the air start receivers and motors capability to start the DG. Jacket Water Cooler (0DG01A): The team reviewed the jacket water cooler thermal analysis to assess its capability to maintain engine temperature within design limits and verified that the licensee had updated the analysis to reflect the latest design bases ultimate heat sink temperature limit changes. In addition, the team reviewed the implementation of the GL 89-13 Program and its commitments associated with the jacket water cooler. Specifically, the team reviewed thermal performance test and inspect-and-clean procedures and completed surveillances to assess the associated methodologies, acceptance criteria, and test results. Fuel Oil Storage Tank (0DO2T): The team reviewed fuel oil consumption calculations, and main storage and day tank capacity calculations, including the associated level instrument setpoints and uncertainty analyses, to assess the availability of the required DG fuel oil supply. The team also reviewed test procedures for fuel oil quality. In addition, tevaluation and resolution of related operating experiences and a Non-Cited Violation (NCV) identified in a previous CDBI as discussed in Section 1R21.4.a and Section 4OA2.1.a of this report. Fuel Oil Transfer Pump (0DO01P): The team reviewed hydraulic calculations to assess flow capacity, NPSH, and air-entraining vortices preventive measures. The team also reviewed the control circuit design and the pump protective devices. Swing DG Room Fan (0VD01C) and Ventilation Balancing Dampers (0VD01/2/3YA/B): The team reviewed air flow calculations to assess the fan capability to maintain the swing DG room within its design bases temperature limit. The team also reviewed design documentation and procedures associated with the DG room temperature and fan intake filter differential pressure instrumentation to assess the licensee capability to detect and address degraded ventilation conditions. In addition, the team reviewed the preventative maintenance documents for the fan and dampers, including sub-components such as hydramotors and control logic circuitry, to assess their periodicity and consistency with vendor information. The team also reviewed the protective measures against flooding, seismic, and tornado generated missiles. The supply fan maximum brake horsepower requirements were reviewed to assess the motor capability to supply power during worse case design basis conditions.

9 The results of load flow and voltage regulation analyses were reviewed to assess the motor capability to start and run during degraded offsite voltage conditions coincident with a postulated design basis accident. The team also reviewed the motor breaker settings to assess the motor overcurrent protection during the most limiting design basis operating conditions. The DG operating and standby readiness procedures were reviewed to assess the consistency between the DG ventilation system operation and the design requirements. The team also reviewed the design of the instrumentation relied upon for the automatic room ventilation operation, including power supplies and setpoints, to assess the system operation. Unit 2, RCIC High-Temperature and High-Steam Flow Isolation Instrumentation (TE-2E31-N004A/B, TE-2E31-N005A/B, TS-2E31-N602A/B, TS-2E31-N603A/B, 2E31-N013BA): The team reviewed schematic diagrams, instrument specifications such as range and accuracy, setpoint and uncertainty calculations, and the installation configuration to assess the temperature and flow instrumentation capability to perform its function. In addition, the team reviewed test and calibration procedures as well as recently completed surveillances to assess the associated methodology, acceptance criteria, and test results. The team also considered the protective measures against flooding, seismic, and HELB when reviewing the described analyses and during field walkdowns. Unit 2, Suppression Pool Water Temperature and Level Instrumentation (2TE-CM-057/037, 2UY-CM037, 2LT-CM-030, 2LS-E22-N002): The team reviewed schematic diagrams, instrument specifications such as range and accuracy, margin and uncertainty calculations, and the installation configuration to assess the capability of the temperature and level instrumentation to perform its function. In addition, the team assessed the consistency between plant surveillance procedures and the methodology for determining average water temperature and data quality allowances described in vendor documentation. The team also reviewed test and calibration procedures as well as recently completed surveillances to assess the associated methodology, acceptance criteria, and test results. In addition, the team considered the protective measures against flooding, seismic, and HELB when reviewing the described analyses and during field walkdowns. Unit 2, 125 Volts Direct Current (Vdc) Distribution Panels 211Y/212Y (2DC11E/13E): The team reviewed design calculations for the loading, short circuit, voltage drop, ground detection/management, and electrical protection for the distribution panels and a sample of loads to assess the ratings and capability of the panels to serve the loads under design basis conditions, provide coordinated protection, and to preclude premature tripping. In addition, the team also reviewed the station blackout (SBO) load shedding procedures to assess their consistency with the design margins established by the calculations and the within the times assumed in the calculations. The team also reviewed test procedures and recently completed surveillances to assess the associated methodology, acceptance criteria, and test results. In addition, the team considered the protective measures against flooding and seismic when reviewing the described analyses and during field walkdowns.

10 Unit 2, RCIC Instrumentation 125Vdc to 120 Volts Alternating Current (Vac) Inverter (2E51-K603): The team reviewed the loading and protection specifications and features for the inverter to assess its capability to serve the instrument power supply loads under design basis conditions, including operation under minimum direct current (DC) input voltage conditions. The team also reviewed the basis for the inverter qualification, including surge protection and electromagnetic compatibility. In addition, the team reviewed the modification discussed in Section 1R21.5.a of this report. The team also reviewed test procedures and recently completed surveillances to assess the associated methodology, acceptance criteria, and test results. In addition, the team considered the protective measures against flooding and seismic when reviewing the described analyses and during field walkdowns. Unit 2, 250Vdc Motor Control Center (MCC) 221Y (2DC06E): The team reviewed the system short circuit and loading calculations to assess the available short circuit current under faulted conditions and the capability to serve the maximum anticipated bus load. The team also reviewed the bus, breaker, and cable ratings to assess their capability to carry maximum loading and interrupt maximum faulted conditions. In addition, the team reviewed cable separation design to assess compliance with single failure and Title 10, Code of Federal Regulations (CFR), Part 50, Appendix R criteria. Breaker coordination was also reviewed to assess their capability to interrupt overloads and faulted conditions. The team also reviewed recent engineering changes (ECs) to assess the bus current capability to support design requirements. In addition, the team reviewed test procedures and recently completed surveillances to assess the associated methodology, acceptance criteria, and test results. Unit 2, 4 Kilovolt (kV) Switchgear 241Y (2AP04E): The team reviewed the design of the 4.16kV bus degraded voltage protection scheme, including degraded voltage relay setpoint calculations, to assess its capability to supply the required voltage to safety-related devices at all voltage distribution levels. The team also reviewed 125Vdc system voltage drop calculations to assess the 4.16kV bus circuit breakers control voltage. In addition, the team reviewed supply breaker control logic and wiring diagrams to assess the capability to automatically transfer between the normal and alternate sources under postulated conditions as described in the UFSAR and in accordance with operating procedures. This review included an assessment of the automatic and manual transfer schemes between alternate offsite sources and the swing DG. The team also reviewed the control circuit voltage to assess the circuit breakers capability to close and trip. In addition, the team reviewed test procedures and recently completed surveillances to assess the associated methodology, acceptance criteria, and test results. b. Findings (1) Failure to Monitor the Fouling Conditions of the Core Standby Cooling System Equipment Area Coolers Introduction: The team identified a finding of very-low safety significance (Green) and an associated NCV of 10 CFR Part failure to monitor the fouling conditions of the core

11 standby cooling system (CSCS) equipment area coolers. Specifically, the licensee did not develop performance test procedures to assess the fouling conditions of the safety-related CSCS equipment area coolers and did not have acceptance criteria that delineate when to remove accumulations. Description: On July 18, 1983, the NRC issued GL 89-Service Water System Problems Affecting Safety-Related Equipmentexperience and studies that raised concerns regarding service water systems in nuclear power plants. The GL requested licensees, in part, to provide a response describing the actions planned or taken to ensure that their service water systems were and will be maintained in compliance with applicable regulatory requirements. The licensee provided its response in a letter t-dated January 29, 1990. Subsequent reviews revealed weaknesses in the licensee original GL 89-13 Program. As a result, the licensee re-baselined the program and 89-13 Revised equipment area cooler testing program woul--- During this inspection period, the licensee controlled the implementation of GL 89-13 activities with Revision 7 of Procedure ER-AA- 89-13 Program Implementing -testing performance test procedures that will verify the capabilities of the safety related heat exchangers, including test procedure and instrument uncertainties, and contain acceptance criteria based on the design Revision 9 of Procedure ER-AA-340-1001, 89-the implementation of GL 89-inspect/test for macroscopic biological fouling organisms, sediment, corrosion and The team noted that the licensee developed a test procedure to measure flowrate and dP for the CSCS cooler for the room containing the low pressure core spray and RCIC systems (i.e., cooler 2VY04A) on a biennial basis and to evaluate the flowrate results against an acceptance criterion. However, the dP results were only trended because an associated acceptance criterion was not established. In addition, the team noted that the cooler was cleaned four times since the GL 83-13 Program was established but was unable to determine the trigger for these cleaning activities. The team was concerned because flow verification by itself was insufficient to assess the cooler fouling condition. Moreover, the team was concerned about the actual cooler fouling conditions because the dP trend data since year 2010 showed a dP of approximately 8 times the dP measured in the early 1990s when dP was first measured. A simplified calculation, which assumed tube blockage was the cause for the increased dP results, determined that approximately 60 percent of the tubes were completely blocked. In contrast, the design basis analysis for the cooler only assumed 5 percent of the tubes were blocked.

12 The licensee captured the team concerns in their CAP as AR 2665463. The immediate corrective actions included an extent of condition that determined this concern was applicable to all four CSCS room coolers of each reactor unit. The other coolers supported the residual heat removal (RHR) and high-pressure core spray systems. The licensee also performed an operability evaluation that reasonably determined all of the affected equipment were operable based, in part, on the actual service water temperatures. In addition, because operability could not be supported at the service water temperature TS limit, the licensee established a control room standing order to declare some of the affected coolers inoperable at reduced service water temperature limits until the coolers were cleaned. The licensee proposed plan to restore compliance at the time of this inspection was to clean the affected coolers and revise the GL 89-13 Program documents to incorporate applicable Electric Power Research Institute monitoring guidance. Analysis: The team determined the failure to monitor the fouling conditions of the CSCS room coolers was contrary to licensee Procedures ER-AA-340 and ER-AA-340-1001, and was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Mitigating System Cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to verify that the fouling conditions of the CSCS room coolers are consistent with the associated design analysis does not ensure that these coolers would be capable of performing their mitigating functions. The team determined the finding could be evaluated using the Significance Determination Process (SDP) in accordance with Inspection Manual Chapter (IMC) issued on June 19, 2012. Because the finding impacted the Mitigating Systems cornerstone, the team screened the finding through IMC 0609, Significance Determination Process for Findings At-The finding screened as of very-low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee reviewed actual service water temperature values measured during the last 12 months and concluded that these values did not exceed the operability limits established by the operability evaluation. The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the test program for the CSCS equipment area coolers was developed in the decade of 1990s. Enforcement: Title 10 CFR Part 50, Appendix B, CriterioProcedures, prescribed by documented procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures. The licensee established Revision 7 of Procedure ER-AA-340 an Revision 9 of Procedure ER-AA-340-1001 as the implementing procedures for monitoring, in part, CSCS room coolers capability to perform their required safety functions, an activity affecting quality.

13 Procedure ER-AA-340, Step 4.2.3nt a heat exchanger performance-performance test procedures that will verify the capabilities of the safety-related heat exchangers, including test procedure and instrument uncertainties, and contain acceptance criteria based on the design In addition, Procedure ER-AA-340-1001, Step 4.1.1.1.C, stated organisms, sediment, corrosion and general componeinspection/test program shall have acceptance criteria that delineate when to remove Contrary to the above, as of May 4, 2016, the licensee failed to follow Step 4.2.3 of Procedure ER-AA-340 and Step 4.1.1.1.C of Procedure ER-AA-340-1001. Specifically, the licensee did not develop performance test procedures that verify the capabilities of the safety-related CSCS room coolers because the test program did not inspect or test for macroscopic biological fouling organisms, sediment, corrosion and general component condition, and did not have acceptance criteria that delineate when to remove accumulations. The licensee is still evaluating its planned corrective actions. However, the team determined that this issue does not present an immediate safety concern because the licensee established a standing order for operations to impose more restrictive service water temperature limits to reasonably assure the operability of the affected coolers. Because this violation was of very-low safety significance (Green) and was entered into AR 2665463, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000373/2016007-01; 05000374/2016007-01, Failure to Monitor the Fouling Conditions of the CSCS Equipment Area Coolers) (2) Failure to Ensure that Both Feed Supply Breakers for Swing Diesel Generator Components Were Closed During Normal Plant Operation Introduction: The team identified a finding of very-low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterfailure to have the capability to verify the supply breakers of both reactor units feeding the swing DG components were closed during normal plant operation. Specifically, the circuit design and procedures for the swing DG room fan, fuel oil transfer pump, and fuel storage tank room exhaust fan did not ensure the detection of the condition where one of these feeder breakers was tripped in the open position during normal plant operation. Description: Section 8.1.2.2 Unit Class 1E AC [Alternating Current] Power Systemll of the ESF [engineered safety feature] equipment required to shut down the reactor safely and to remove reactor decay heat for extended periods of time following a LOOP and/or a LOCA are supplied with AC power from the Class 1E AC power system. This UFSAR section defined Class 1E AC power systems as that portion of the station auxiliary power system which supplies AC power to the ESF The unit Class 1E AC power system is divided into three divisions (Divisions 1, 2 and 3 for Unit 1; Divisions 1, 2, and 3 for Unit 2), each of which is supplied from a 4160-volt bus (141Y, 142Y, and 143 for Unit 1 respectively) and (241Y, 242Y, and 243 for Unit 2 respectively).Two ESF groups (Division 2 and 3) of each unit are supplied standby power from individual diesel-generator units, while the third ESF group (Division 1) for each unit obtains its standby power from a

14 common diesel-generator unit, "0", which serves either of the corresponding switch groups in each unit (Bus 141Y or 241Y). With this arrangement, alternate or redundant components of all ESF systems are supplied from separate switch groups so that no single failure can jeopardize the proper functioning of redundant ESF. Because the swing DG was designed to supply power to the division 1 ESF bus for either reactor unit, several safety-related components that supported the swing DG operation (i.e., room vent fan, fuel storage tank room exhaust fan, and fuel transfer pump) were designed with one power supply from each reactor unit. As an example, Unit 1 supplied power to the swing DG room fan (i.e., 0VD01C) via compartment B4 of MCC135X-2 while Unit 2 supplied power to this component via compartment B4 of MCC235X-2. Schematic diagram 1E-0-4433AA, ed the following operational sequence for the associated control circuit design: If both MCCs were energized with no breaker or fuse failures during normal operation, the fan would be powered from Unit 1. In addition, the plant process computer (PPC) alarm contact from relay 74 would be closed causing the alarm to not be displayed at the Main Control Room (MCR). During a LOOP event, the fan control circuit would connect to the MCC of the reactor unit with a LOCA signal. Thus, the Units 1 and 2 MCCs were not considered redundant or backup to each other. If the Unit 1 MCC feed breaker tripped open and/or the Unit 1 control transformer fuse opened during normal operation, relays AR1 and AR2 would de-energize and power would automatically transfer to the Unit 2 MCC. At the same time, the loss of power from Unit 1 would cause relay 74 to drop out until Unit 2 power picked up. If the PPC alarm contact from relay 74 opened before relay 74 was energized by Unit 2 power, the PPC alarm would appear on the ESF panel. However, the team noted that the circuit design did not preclude a contact/relay race between relays AR1/AR2 and relay 74 and, thus, the PPC alarm contact from relay 74 was not assured to open before relay 74 was energized by Unit 2 power to provide the alarm function. If the Unit 2 breaker tripped and/or the Unit 2 control transformer fuse opened when the fan was powered from Unit 1 during normal operation, no PPC or annunciator alarm would appear at the MCR. If both Unit 1 and 2 MCCs de-energized during normal operation, relay 74 would dropout to activate the ESF display and overload alarm at the MCR annunciator, which would prompt operators to respond in accordance with Procedure LOR-0PL17J-2-Diesel Generator Ventilation Fan 0VD01C Automatic Trip If either the Unit 1 MCC or the Unit 2 MCC thermal overload relays tripped during normal operation, the fan control circuit would de-energize. The fan would not run from either power source until the thermal overload relays was reset. In addition, relay 74 would drop out to activate the ESF display and overload alarm in the MCR.

15 The circuit designs for the swing DG fuel storage tank room exhaust fan and fuel oil transfer pump were similar. The team was concerned because the licensee had not assure that the failure of the Unit 1 or Unit 2 feed breakers for these swing DG components during normal plant operation would be detected. Specifically, the licensee relied on an alarm at the MCR to detect a failure of either feed breaker during normal operation but the associated circuit design did not assure an alarm signal would be generated by either of these conditions. The team further noted that an undetected breaker failure during normal operations would allow the swing DG to be and remain inoperable during normal operations, which would result in the loss of total DG system given a postulated accident assuming a single failure of the redundant DG train. In addition, the team noted that a failure of either of these breakers during normal operations was credible given recent internal operating experience. Specifically, on July 24, 2011, an equipment operator found the Unit 1 swing DG room fan feed breaker (i.e., MCC 135X-2, B4) tripped during an operator round. The licensee captured the discovery of this issue in their CAP as AR 01243373, verified that the Unit 2 swing DG room fan feed breaker (i.e., MCC 235X-2, B4) was closed, declared the swing DG inoperable for Unit 1, and replaced the failed Unit 1 breaker. In addition, the licensee reviewed historical PPC data and determined that the Unit 1 breaker tripped on July 22, 2011, during the DG monthly surveillance run. Thus, the operators missed the PPC alarm and the previous equipment operator rounds did not identified the condition. The licensee capture the team concern in their CAP as AR 02668759. The immediate corrective actions was to create a special log to monitor the associated breakers once per day. At the time of this inspection, the licensee was still evaluating its planned corrective actions to restore compliance. Analysis: The team determined that the failure to have the capability to verify the supply breakers of both reactor units feeding the swing DG components were closed during normal plant operation was contrary to 10 CFR Part 50, Appendix B, Criterion III, The performance deficiency was determined to be more than minor because it was 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. Specifically, the failure to have the capability to verify the supply breakers of both reactor units feeding the swing DG components were closed during normal plant operation would allow a condition where one of the feeder breakers is in the open position during normal plant operation to go undetected, which did not ensure power would be available to these components to support the swing DG operability. The team determined the finding could be evaluated using the SDP in accordance with the Mitigating Systems cornerstone, the team screened the finding through IMC 0609, - finding screened as of very-low safety significance (Green) because it did not result in the loss of system and/or function, represent an actual loss of function of at least a single train or two separate safety systems out-of-service for greater than its TS allowable outage time,

16 and represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, a historical review did not find an example where the swing DG was non-functional for a period greater than the applicable TS allowable outage time as a result of this finding during the last year. The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the means to detect an opened breaker associated with the affected loads were established more than 3 years ago. Enforcementpart, that measures be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. the various plant buses so that the loss of any one diesel generators will not prevent the -failure criteria. Contrary to the above, as of May 13, 2016, the licensee failed to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. design control measures did not assure that the swing DG was applied to the buses supplying power to its room fan, fuel oil transfer pump, and fuel storage tank room exhaust fan such that the total DG system would be able to satisfy the single-failure criteria. The associated circuit design and procedures did not ensure the detection of a condition where the feeder breaker of one of the associated buses was tripped in the open position during normal plant operation. The licensee is still evaluating its planned corrective actions. However, the team determined that the continued non-compliance does not present an immediate safety concern because the licensee established a special log to monitor the associated breakers once per day. Because this violation was of very-low safety significance (Green) and was entered into the AR 02668759, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000373/2016007-02; 05000374/2016007-02, Failure to Ensure that Both Feed Supply Breakers for Swing DG Components Were Closed During Normal Plant Operation) .4 Operating Experience a. Inspection Scope The team reviewed five samples of operating experience issues to ensure that NRC generic concerns had been adequately evaluated and addressed by the licensee. The operating experience issues listed below were reviewed as part of this inspection: IN 2006--Low-Sulfur Diesel Fuel Oil Could Adversely Impact

17 IN 2009-act Diesel Engine Performan IN 2012-16Preconditioning of Pressure Switches Before Surveillance Testing; IN 2013-; and Bulletin 96-by Debris in Boiling- b. Findings (1) Inadequate Procedures for Containment Debris Management Introduction: The team identified a finding of very-low safety significance (Green) and an associated NCV of 10 CFR Part ures, containment debris consistent with the emergency core cooling system (ECCS) strainer debris loading design basis and supporting design information. Specifically, the procedures did not contain instructions for evaluating containment debris sources consistent with the associated analyses and other design documents. Description: On May 6, 1996, the NRC issued Bulletin 96-of Emergency Core Cooling Suction Strainers by Debris in Boiling-to request addressees to implement appropriate procedural measures and plant modifications to minimize the potential for clogging of ECCS suppression pool suction strainers by debris generated during a LOCA and to provide a response describing these actions. The licensee provided an initial response in a letter to the NRC titled 96-November 1, 1996. This response stated, in part, that the licensee planned to install larger capacity passive strainers designed using the guidance contained in NEDO-Boiling Water Reactors Owners Group Utility Resolution Guidance for ECCS Suction Strainer Blockage, which was endorsed with exceptions by the NRC. By -licensee informed the NRC that all actions requested by the bulletin were completed, including the implementation of procedures for periodic drywell and wetwell inspections and periodic suppression chamber desludging. The NRC documented its review and acceptance of the licensee responses in Bulletin 96-03, LaSalle County Station, Units 1 ad June 2, 2000. The licensee estimated the head loss across the debris bed formed on the strainers due to accumulation of debris produced during a LOCA in calculation L-002051. This calculation established separate design limits for different debris sources at specified containment locations, such as unqualified coatings, rust flakes, and sludge. During this inspection period, the licensee used Revision 9 of Procedure CC-AA- to control the amount of undocumented/unqualified coatings within the design limits. In addition, Revision 8 of Procedure LTS-600- was used to perform and document the periodic drywell and wetwell inspections to identify and maintain containment debris quantities below their design limits. Moreover, Revision 18 of Procedure OP-AA-108-108, Attachment 1, Department Start-U step 24, required the licensee to verify that the

18 ECCS strainer debris loads were within design limits prior to unit startup. The licensee completed this step by performing an evaluation using ECs. However, the team noted that the procedures were inadequate to maintain containment debris quantities consistent with the design basis and design supporting information. Specifically, Procedure CC-AA-205 did not contain instructions to ensure that the appropriate coating supporting design information (i.e., thickness and density) was used when evaluating degraded coatings that were originally considered as qualified against the applicable strainer debris loading design basis limit. Specifically, the licensee documented the identified areas of unqualified coatings in a log using units of square feet. Because calculation L-002051 established a design limit of 328 pounds, the licensee converted the units from square feet to pounds. However, the team noted that the licensee used the coating supporting design information for the coating system that was originally installed as unqualified, which had smaller thickness and density values than the originally qualified coating system that was found degraded during the inspections and, thus, was no longer qualified. As a result, the licensee underestimated the amount of drywell unqualified coatings. Specifically, the incorrect logs showed an available margin of about 16 percent and 44 percent for Units 1 and 2, respectively. When the logs were corrected, the design basis limits were exceeded by about 20 percent and 7 percent for Units 1 and 2, respectively. Procedure LTS-600-41 contained a sludge acceptance criterion that was inconsistent with the applicable design basis limit and was non-conservative. Specifically, calculation L-002051 established a sludge design limit of 750 pounds. However, procedure LTS-600-41 contained an acceptance criteria of 1000 pounds. Procedure LTS-600-41 did not contain appropriate instructions to evaluate the as-found conditions against the design basis limit for each debris type evaluated by calculation L-002051. As a result, the licensee was not evaluating the as-found conditions consistent with this calculation. For example, the diver inspection report attached to Work Order 01317612 described the identified sludge piles [inches] [inch] In contrast, the NEDO-32686 sludge particle maximum size was 0.003 inches. Based on other documented inspection report descriptions, the team determined that the likely debris type described by the diver was rust flakes, which had a design basis limit of 100 pounds as opposed to 750 pounds for sludge. A second example is documented in the next bullet. Procedure LTS-600-41 did not contain appropriate instructions to evaluate the aggregate effects of the debris found when performing different inspection activities at different containment locations. Specifically, the team noted instances when the inspection for the entire containment was not completed in a single effort and the evaluation of the results for each inspection effort did not account for the results for the other inspection activities when comparing the identified condition against the design basis limits. For example, EC 392593, which used the LTS-600-41 sludge results and was performed to meet Step 24

19 of Procedure OP-AA-108-108, Attachment 1, evaluated only the suppression pool sludge against the design basis allowances of multiple debris sources. -002051 describes the following suppression pool particulate matter debris assumed in the ECCS suction strainer head loss analysis: 750 lbs. [pounds] of sludge, 300 lbs. [pounds] of dirt/dust, 85 lbs. [pounds] of qualified paint debris, 328 lbs. [pounds] of unqualified paint debris, and 100 lbs. 4 (205 lbs. [pounds]) and the predicated accumulation by L2R15 (365 lbs. [pounds]) are well below the amount assumed in Design Analysis L-002051 (750 lbs. [pounds] plus EC 392593 did not consider the amount of debris sources at both the drywell and wetwell other than suppression pool sludge when crediting the design basis limits for multiple drywell and wetwell debris sources. The team was concerned that this licensee practice would allow a condition where the debris amount identified in each inspection location is within the design basis limits but, in aggregate, would exceed them. This example also illustrates the concern described in the previous bullet. The team noted similar observations on other start-up ECs. Overall, the team was concerned because the procedures were not adequate to ensure that the containment debris quantities were consistent with the design basis analysis and their relative distribution were consistent with the design information, including testing, that supported the design basis analysis assumptions. The licensee captured the team concerns in their CAP as AR 02663076 and AR 02656299. The immediate corrective actions included an operability evaluation that reasonably determined all of the affected ECCS strainers remained operable. Specifically, the licensee reasonably concluded that only a fraction of the unqualified coatings would be available for transport to the strainers during a LOCA and this amount was bounded by the associated design basis limit. This determination was based, in part, on unqualified coating testing and the documented condition of the unqualified coatings. In addition, the licensee reviewed containment cleaning records and the inspection results for the other debris sources and reasonably determined that the associated design basis limits were met. The licensee proposed plan to restore compliance at the time of this inspection was to revise the affected procedures and the coating logs. In addition, the licensee planned to revise calculation L-002051 if additional margin is required to meet the corrected coating log values. Analysis: The team determined the failure to establish procedures that were appropriate to manage containment debris consistent with the ECCS strainer debris loading design basis and supporting design information, was contrary to 10 CFR Part 50, Appendix B, CriteInstructions, Procedures, and Drawingsdeficiency. The performance deficiency was determined to be more than minor because it was associated with the procedure quality 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. Specifically, the failure to establish procedures that were appropriate to manage containment debris does not ensure that the ECCS strainer debris loading during a LOCA will be bounded by the associated design basis analysis.

20 The team determined the finding could be evaluated using the SDP in accordance with the Mitigating Systems cornerstone, the team screened the finding through IMC 0609, Significance Determination Process for Findings At-screened as of very-low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee performed an operability review and reasonably determined that only a portion of the unqualified coatings would be available for transport to the strainers and this quantity was bounded by the associated design basis analysis. In addition, this review reasonably determined that sufficient analytical margin existed to accommodate the quantities of the other debris types found during recent inspections. The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the associated procedures were established more than 3 years ago. Enforcement: Title 10 CFR Part 50, Appendix B, CriterioProcedures, prescribed by documented procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures. The licensee established Revision 9 of Procedure CC-AA-205 and Revision 8 of Procedure LTS-600-41 as the implementing procedures for containment debris management, an activity affecting quality. Contrary to the above, as of April 29, 2016, the licensee failed to have procedures of a type appropriate to manage containment debris consistent with the ECCS strainer debris loading design basis and supporting design information, as evidenced by the following examples: Procedure CC-AA-205 did not contain instructions to ensure that the appropriate coating supporting design information (i.e., thickness and density) was used when evaluating degraded coatings that were originally considered as qualified against the applicable strainer debris loading design basis limit. Procedure LTS-600-41 contained a sludge acceptance criterion that was inconsistent with the applicable design basis limit and was non-conservative. Procedure LTS-600-41 did not contain appropriate instructions to evaluate the as-found conditions against the corresponding design basis debris type. Procedure LTS-600-41 did not contain appropriate instructions to evaluate the aggregate effects of the debris found when performing different inspection activities at different containment locations. The licensee is still evaluating its planned corrective actions. However, the team determined that the continued non-compliance does not present an immediate safety concern because the licensee performed an operability review and reasonably determined that ECCS was operable based on the as-found conditions documented in recent inspection reports.

21 Because this violation was of very-low safety significance (Green) and was entered into AR 2656299 and AR 2663076, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000373/2016007-03; 05000374/2016007-03, Inadequate Procedures for Containment Debris Management) .5 Modifications a. Inspection Scope The team reviewed two permanent plant modifications related to the selected risk significant components to verify that the design bases, licensing bases, and performance capability of the components had not been degraded through modifications. The modifications listed below were reviewed as part of this inspection effort: EC 396093, Install 125Vdc/120Vac Inverter to Power Existing 120Vac/24Vdc Power Supply that Feeds Existing Containment Instrumentation; and ion due to C RHR and LPCS [Low-Pressure Core Spray] anti- b. Findings No findings were identified. .6 Operating Procedure Accident Scenarios a. Inspection Scope The team performed a detailed reviewed of the procedures listed below associated with a loss of offsite power and a complete loss of AC power (i.e., SBO). The procedures were compared to UFSAR, design assumptions, and training materials to asses for constancy. The following operating procedures were reviewed in detail: LOA-DG- LOA-FC- LGA-RH-LGAS/LSAMGSRevision 12(13); LOP-RH-Revision 57; LOP-RH- LOA-IN- LOP-Revision 25.

22 For the procedures listed, time critical operator actions were reviewed for reasonableness. This review included walkdowns of in-plant actions with a licensed operator and the observation of licensed operator crews actions during the performance of an SBO scenario on the station simulator to assess operator knowledge level, procedure quality, availability of special equipment where required, and capability to perform time critical operator actions within the required time. The simulated scenario started with a dual unit loss of offsite power and then degraded, several minutes later, into an SBO on Unit 1 with limited power available to Unit 2. In addition, the team evaluated operations interfaces with other departments and the transition to beyond licensing basis event procedures to assess the interface between licensing basis and beyond licensing basis procedures. The following operator actions were reviewed: establish automatic depressurization system control in the auxiliary electric equipment room; DC load shedding; placement of RHR in the suppression pooling cooling mode following an SBO; and replacing drywell pneumatic air supply nitrogen bottles. b. Findings No findings of significance were identified. 4. OTHER ACTIVITIES 4OA2 Identification and Resolution of Problems .1 Review of Items Entered Into the Corrective Action Program a. Inspection Scope The team reviewed a sample of problems identified by the licensee associated with the selected components and that were entered into the CAP. In addition, the team reviewed a sample of CAP documents for the last 3 years resulting from degraded conditions. The team reviewed these issues to assess threshold for identifying issues and the effectiveness of corrective actions related to design issues. In addition, corrective action documents written on issues identified during the inspection were reviewed to assess the incorporation of the problem into the CAP. The specific corrective action documents sampled and reviewed by the team are listed in the attachment to this report. The team also selected three issues identified during previous CDBIs to assess the evaluation and resolution. The following issues were reviewed: NCV 2007009-03, Blackout Analysis for Reactor Core Isolation Cooling (RCIC); NCV 2010006-02, DG Usable Fuel and RHR Pump NPSH Calculations Failed to Consider Appropriate DG Frequency Variations; and NCV 2010006-04, .

23 b. Findings (1) Alternate Shutdown Procedures Failed to Ensure RCIC MOVs Supply Breakers Were Closed Introduction: The team identified a finding of very-low safety significance (Green) and associated NCV of the LaSalle County Station Operating License for the failure to ensure that procedures were in effect to implement the alternate shutdown capability. Specifically, the AOPs established to respond to a fire at the MCR did not include instructions for verifying that supply breakers for three RCIC MOVs were closed to ensure they could be operated from the remote shutdown panel (RSP). Fire-induced failures could result in tripping MOV power supply breakers prior to tripping the MOV control power fuses. Description: In the event of an MCR evacuation due to a fire, the safe shutdown analysis credited the RCIC system for the alternate shutdown method from the RSP. Specifically, RCIC was credited for reactor water makeup and decay heat removal. During this event, the MCR control circuits for the RCIC MOVs needed to be transferred from the MCR to the RSP. To accomplish this transfer, the licensee included instructions to the operators for placing the RCIC remote shutdown transfer switches in the emergency position at the RSP in Procedure LOA-FX-101Unit 1 Safe Shutdown with a Fire in the Control Room and Procedure LOA-FX-201Unit 2 Safe Shutdown with a Fire in the Control Room. This transfer was intended to ensure that the alternate shutdown capability was independent of the MCR fire area by isolating the MCR control circuits for the RCIC MOVs and connecting a different set of control fuses that fed from a separate power source at the RSP for each MOV. However, in 2014, the NRC identified that the licensee failed to ensure that the alternate shutdown capability was independent of the MCR during the NRC Triennial Fire Protection inspection. Specifically, the inspectors noted that the control circuit design did not ensure the MOV control power fuses trip before the associated feeder breakers as a result of fire-induced failures, such as a short circuit in the control circuit. A tripped MOV feed breaker would impair the operation of the associated MOV from the RSP. In addition, the inspectors noted that Revision 26 of LOA-FX-101 and Revision 27 of LOA-FX-201 did not include instructions to reset the affected breakers. This issue was documented by the inspectors as NCV 05000373/2014008-01; 05000374/2014008-01, with Alternate Shutdown Capability Free of Fire-Induced Damagdated February 27, 2015. The licensee captured this issue in their CAP as AR 02424674 and reviewed the control circuits of the affected MOVs. Specifically, the licensee completed analysis L-004-fuse coordination for all 28 RCIC MOVs (14 per reactor unit) during a postulated MCR fire event. This analysis identified 16 MOVs (8 per reactor unit) that could be adversely affected by a postulated MCR fire and, thus, required further evaluation for potential lack of breaker fuse coordination. In addition, the licensee revised Procedures LOA-FX-101 and LOA-FX-201 to verify closed the breakers associated only with these 16 MOVs after control was transferred to the RSP.

24 During this CDBI inspection, the team noted that analysis L-004017 calculated the fault current using the maximum DC bus voltage divided by the resistance of each cable (using a value of 0.273 ohms per 1000 feet). Thus, shorter cable lengths led to smaller cable resistances resulting in higher fault current values. However, the analysis did not consider all potential fire-induced short circuits that could potentially affect breaker-fuse coordination and, as a result, failed to evaluate short circuits that resulted in shorter short circuit cable lengths. Specifically, the analysis only considered a short circuit (conductor to conductor dead short) for the control cable associated with each MOV and that provided the shortest path for each MOV from the 250Vdc power source to the MCR. For example, the analysis determined that the existing breaker settings for MOVs 1E51-F019, 2E51-F019, and 1E51-F059 were acceptable because their maximum calculated fault current was less than the minimum breaker trip setting using a cable length of 2926 feet, 3512 feet, and 1821 feet, respectively. The analysis also determined the margins between the minimum breaker setting and maximum fault current were 14.49 percent, 19.92 percent, and 2.57 percent for these MOVs, respectively. However, the analysis did not consider fire-induced circuit failures such as shorts between cables associated with these MOVs and other MOVs from the same 250Vdc power source resulting in shorter short circuit cable lengths. The analysis also failed to consider shorts between cables associated with these MOVs and the ground, and cables associated with other MOVs with shorter cable lengths and the ground that would end with short circuit via the ground. The team was concerned because the unanalyzed fire-induced circuit failures (i.e., short between cables and short to grounds) would have the potential to result in higher available fault current values that could trip the feeder breaker for the affected MOVs. In addition, the team was concerned because the AOPs revisions in effect at the time of this inspection (i.e., Revision 27 of LOA-FX-101 and Revision 29 of LOA-FX-201) did not include instructions to verify that the feeder breakers were closed for all of the affected MOVs based on the conclusions of analysis L-004017. The team further noted that the AOPs required operators to open valves 1E51-F019 and 2E52-F019 as part of the expected response for a safe shutdown with a fire in the MCR and the AOPs did not include alternative instructions in the event these valves could not be opened. In addition, the AOPs required operators to open valve 1E15-F059 if RCIC flow was not within the expected range. Thus, the team determined that the inability to operate these values would not be within the bounds of the AOPs for a safe shutdown with a fire in the MCR. The licensee captured the team concerns in their CAP as AR 02668854. The immediate corrective actions included revising Standing Order S14-09 to establish compensatory actions to reset the affected breakers, if required. The licensee proposed plan to restore compliance at the time of this inspection was to revise the AOPs to reset the affected breakers, if required. Analysis: The team s were in effect to implement the alternate shutdown capability was contrary to LaSalle County Station Operating License conditions for the Fire Protection Program and was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of protection against external events (fire), and affected the cornerstone objective of

25 ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure to ensure that procedures were in effect to transfer RCIC control from the MCR to the RSP in the event of an MCR fire does not ensure the alternate shutdown capability of RCIC. The team determined the finding could be evaluated using the SDP in accordance with ng affected the ability to reach and maintain safe shutdown conditions in case of a fire, the team art 1: eptember 20, 2013. The finding screened as of very-low safety significance (Green) because it was assigned a low degradation factor based on the criteria in IMC 0609, Appendix F, Attachment 2, team assigned a low degradation factor because the procedural deficiencies could be compensated by operator experience/familiarity and the fact that the procedure included steps to verify other breakers at the same MCCs were closed. The team determined that this finding had a cross cutting aspect in the area of problem identification and resolution because the licensee failed to take effective corrective actions. Specifically, AR 02424674 included actions to revise the affected AOPs to include verifying all the RCIC MOVs supplied breakers were closed to correct an issue identified on 2014. However, the licensee failed to include all of the MOVs in the revised AOPs. [P.3] Enforcement: License conditions 2.C.25 and 2.C.15 of the LaSalle County Station, Unit 1 and Unit 2 Operating Licenses, respectively, require, in part, that the licensee implement and maintain all provisions of the approved Fire Protection Program as described in the UFSAR for LaSalle County Station, and as approved in NUREG-0519, associated amendments. The license conditions also indicate that the licensee may make changes to the approved Fire Protection Program without prior approval of the NRC only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. LaSalle Comparison to 10 CFR Part 50, Appendix R, in Revision 7 of the Fire Protection Program, Section he shutdown capability for specific fire areas may be unique for each such area, or it may be one unique combination of systems for all such areas. In either case, the alternative shutdown capability shall be independent of the specific fire area(s) and shall accommodate post fire conditions where offsite power is not available for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In Procedures shall be in effect to implement this capability. The LaSalle omply, specific post fire safe shutdown procedures have been developed for the Control Room and AEER. LOA-FX-101(201) Contrary to the above, from December 12, 2015, to at least May 13, 2016, the licensee failed to have procedures in effect to implement the alternative shutdown capability for a fire area where alternative shutdown capability was established. Specifically, the safe shutdown procedures developed for the MCR, a fire area, (i.e., Revision 27 of

26 LOA-FX-101 and Revision 29 of LOA-FX-201) did not include instructions for verifying that the supply breakers for all RCIC MOVs susceptible to fire-induced failures were closed to ensure the successful operation of the RCIC system, which is the credited alternate shutdown system in the event of a fire in the MCR. The licensee is still evaluating its planned corrective actions. However, the team determined that the continued non-compliance does not present an immediate safety concern because the licensee established compensatory actions to reset the affected breakers, if required. Because this violation was of very low safety significance (Green) and was entered into nt with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000373/2016007-04; 05000374/2016007-04, Alternate Shutdown Procedures Failed to Ensure RCIC MOVs Supply Breakers Were Closed) 4OA6 Management Meetings .1 Exit Meeting Summary On May 13, 2016, the team presented the inspection results to Mr. Trafton, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The team asked the licensee whether any materials examined during the inspection should be considered proprietary. Several documents reviewed by the team were considered proprietary information and were either returned to the licensee or handled in accordance with NRC policy on proprietary information. ATTACHMENT: SUPPLEMENTAL INFORMATION

Attachment SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee W. Trafton, Site Vice President H. Vinyard, Plant Manager J. Kowalski, Engineering Director J. Keenan, Operations Director V. Shah, Engineering Deputy Director G. Ford, Regulatory Assurance Manager M. Chouinard, Design Engineer P. Patel, Electrical Engineer A. Ahmad, Design Engineer D. Murray, Regulatory Assurance Engineer U.S. Nuclear Regulatory Commission M. Jeffers, Chief, Engineering Branch 2 N. Féliz Adorno, Senior Reactor Inspector LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened and Closed 05000373/2016007-01; 05000374/2016007-01 NCV Failure to Monitor the Fouling Conditions of the CSCS Equipment Area Coolers (Section 1R21.3.b(1))05000373/2016007-02; 05000374/2016007-02 NCV Failure to Ensure that Both Feed Supply Breakers for Swing DG Components Were Closed During Normal Plant Operation (Section 1R21.3.b(2))05000373/2016007-03; 05000374/2016007-03 NCV Inadequate Procedures for Containment Debris Management (Section 1R21.4.b(1))05000373/2016007-04; 05000374/2016007-04 NCV Alternate Shutdown Procedures Failed to Ensure RCIC MOVs Supply Breakers Were Closed (Section 4OA2.b(1)) Discussed None

2 LIST OF DOCUMENTS REVIEWED The following is a list of documents reviewed during the inspection. Inclusion on this list does not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that selected sections of portions of the documents were evaluated as part of the overall inspection effort. Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report. CALCULATIONS Number Description or Title Revision L-002051 ECCS Strainer Head Loss Performance Analysis 2A L-003354 ECCS & RCIC Pumps NPSH Road Map Calculation 1 ATD-0070 Limiting Operating Conditions For Net Positive Suction Head (NPSH) for HPCS, LPCS, RCIC & RHR pumps 0 L-001222 Estimation of Worst-Case Unit 1 RMI Debris Inventory Available for Transport to the Suppression Pool 2 MAD-72-32 Pressure Drop Calculations, RCIC System 0 L-002540 NPSH Margin for HPCS, RHR, & RCIC Pumps, Backpressure for RCIC Turbine 2 97-1998 VY Cooler Thermal Performance Model 1(2)VY04A A L-001024 LPCS Pump Cubicle Cooler Ventilation System 2 066455(EMD) Generic Evaluation of 5 Degree F Increase in Suppression Pool Temperature OA L-003317 RCIC Lube Oil Cooler Operation with SBO Event maximum Suppression Pool Temperature 0 MAD 72-32 Pressure Drop Calc RCIC System 0 ATD-0351 RCIC Pump Room Temperature Transient Following Station Blackout with Gland Seal Leakage 1 L-002440 Cross Index for Environmental Qualification Parameters and Their Respective Source Documents 1A L-000550 Zone H5A Equipment Qualification Dose 0 L-001384 Reactor Building Environmental Transient Conditions Following RWCU and RCIC HELBs and LOCA/Loss of HVAC Event 10 L-003263 Volume Requirements for ADS Back-up Compressed Gas System (Bottle Banks) 3A EC 372452 Generic Letter 2008-01 Void Calculation and Acceptance Criteria 24 EC 343185 Maximum Expected Run Hours for Suppression Pool Cooling/Full Flow Test Operating Modes of RHR 0 110A Ventilation Air Intake Extension for Diesel Generator 2 97-195 Thermal Model of ComEd/LaSalle Station Unit 0, 1 and 2 Diesel Generator Jacket Water Cooler 0 DG-08 NPSH for HPCS DG Fuel Pumps 1B DO-6 Elevation Diesel Fuel Oil Tanks 0 EC 366261 Revise Setpoint of DG Fuel Oil Storage Tank Low Level Switches 0 EC 372326 0DG Thermal Performance Margin with Tube Blocked 0 EC 381640 Minimum Required On-Site Usable Diesel Fuel Required to Support Both Six Days and Seven Days of Continuous Emergency Diesel Generator Operation Per Tech Spec Bases Table B.3.8.3-1 0

3 CALCULATIONS Number Description or Title Date or Revision EC 382235 Evaluation of The NPSH For Safety Related Pumps In Support of Op Eval 10-005 0 EC 384217 2A DG Heat Exchanger Thermal Performance Test Evaluation 0 EC 389270 UHS Temperature Increase 0 EC 395837 2A DG Heat Exchanger Thermal Performance Test Evaluation 0 L-002901 Verification of the Division 1 and 2 Diesel Oil Storage and Day Tank Volumes 1A L-003364 0DG Electrical Loading Calculation 3 L-003416 Emergency Diesel Generators Onsite Usable Fuel Volume Requirements 0B VD-1A Standby Diesel Generator Room Ventilation System 0 VD-1C Diesel Generator Room Vent System Duct Pressure Drops 0 VD-2A Standby Diesel Generator Room Ventilation System 0 VD-2C Diesel Generator System Duct Pressure Drops 0 VD-3C Engine-Generator for High Pressure Core Spray System 0 3C7-0788-001 Assessment of Bulk Pool Temperature Calculation Methods [I&C interface review] 2 DCR 990833 Change NED-I-EIC-0260 to incorporate Results of 24 Month Drift Analysis 03/07/00 EC 380464 Evaluation of Preconditioning of TS and TRM Pressure Switches 1 L-002590 Condensate Storage Tank Level Switch Setpoint Error Analysis 1 L-002664 Review of Design Bases for 2° F Correction Factor Used in LOP-CM-03, Rev. 11 [I&C interface review] 1 L-002968 DC System Ground Detector Action Levels, Sections 7.6, 8.0 0 L-003447 LaSalle Units 1 and 2,125 Vdc System Analysis 001B L-003845 RCIC Steam Line High Flow Isolation Error Analysis 0 NED-I-EIC-0196 Suppression Chamber High Level Setpoint Error Analysis 0 NED-I-EIC-0213 RCIC Equipment Area/Pipe Tunnel High Ambient and Differential Temperature Outboard and Inboard Isolation Error Analysis 001G NED-I-EIC-0259 Suppression Chamber Water Temperature Indication Loop Analysis 1 NED-I-EIC-0260 Suppression Chamber Wide Range Water Level Indication Error Analysis 0 PC-03 Design Analysis: Suppression Pool Volume Check [I&C interface review] 0 LAS-2E51-F046 DC Motor Operated GL96-05 Globe1 Valve 8 LAS-2E51-F045 DC Motor Operated GL96-05 Globe1 Valve 8 L-003364 ETAP Output Report for EDG Load Flow 3

4 CALCULATIONS Number Description or Title Revision L-003897 Setpoint Analysis for DG Feed Breaker Close Time Delay Relay 1 L-002589 Instrument Setpoint Analysis for 4.16KV Undervoltage (Loss of Voltage) Relay-Time Delay Function 0 L-002588 Loss of Voltage Relay Setpoint for 4.16 KV Buses Undervoltage Function 0 L-003823 1AP76E(135Y-2) MCC Voltage Drop, CB and TOL Setting 0 L-000300 Thermal Overload Relay Setting for Continuous Duty Motors 2 L-003448 LaSalle Units 1 and 2, 250 VDC System Analysis 0 L-003820 1AP72E (135X-2) MCC Voltage Drop, CB and TOL Setting 0 L-004017 250 VDC Breaker Fuse Coordination for RCIC 0 CORRECTIVE ACTION DOCUMENTS GENERATED DUE TO THE INSPECTION Number Description or Title Date AR02665463 Plugging in 2VY04A 05/04/16 AR02654987 LOA-FC-101/201 Minor editorial procedure issue. 04/13/16 AR02655443 LOA-LOOP-101/201 Contains operating guidance for the RCIC System that conflicts with operating guidance found in LGA-001. 04/14/16 AR02656039 DC Load Shedding procedure enhancements. 04/15/16 AR02661078 Configuration Control (Locking Status) of RCIC Pump Water Leg Pump Discharge Valve (F062). 04/26/16 AR02659810 NRC CDBI 2016 - UFSAR Table 8.3-3 Shows Inaccurate Rev Bar 04/22/16 AR02661013 NRC-CDBI Identified SBLC Issue with UFSAR 04/26/16 AR02666354 NRC CDBI 2016 UFSAR, App B PG B.0-11 Shows Inaccurate Rating 05/06/16 AR02655170 NRC CDBI Identified Packing leak 04/13/16 AR02659688 NRC CDBI Identified Calculation NED-EIC-0196 Reference Has Not Been Superseded 04/22/16 AR02665136 NRC CDBI Identified Error in Design Analysis NED-EIC-0260 05/04/16 AR02667806 NRC CDBI Identified Concern [Reporting and Trending of Conditions Identified and Corrected During PM Activities] 05/10/16 AR02655692 0VD02C Fan Motor LRC Discrepancy 04/14/16 AR02668854 NRC CDBI Identified Issue Related to Breaker Coordination 05/12/16 AR02668759 NRC Concern about 0VD01C Alarm in MCR 05/12/16 AR02663076 NRC CDBI Concerns on Strainers 04/29/16 AR02656299 NRC-CDBI -600-41 PCRA Sludge Weight Correction 04/15/16 AR02668855 CDBI2016 NRC Observation on Use of Measured LRC for 1EBOP 05/12/16 AR02653895 NRC-CDBI Identified Issue HPCS UFSAR description 04/11/16 AR02668085 NRC-CDBI Identified Issue post-TIA 2001-14 procedures 05/11/16 AR02662445 NRC CDBI L-002051 Enhancements to Microtherm Assumptions 04/28/16 AR02655171 NRC-CDBI Identified Issue RCIC storage ladders 04/13/16 AR02655372 NRC ID CDBI LTS-600-41 PC Inspection PCRA Needed 04/14/16 AR02656385 04/15/16 AR02657236 NRC Identified CDBI Suction Strainer Calculation Review 04/18/16 AR02659561 -600-41 04/22/16 AR02661223 Values Listed in L-002540 04/26/16

5 CORRECTIVE ACTION DOCUMENTS REVIEWED DURING THE INSPECTION Number Description or Title Date AR02637587 NRC Question Coatings in Drywell on Floor Elevation 736 03/08/16 AR02571878 Unqualified Coatings Log Discrepancy 10/16/15 AR00673099 CDBI RCIC Ops During SBO w/Elevated Suppression Pool Temps 09/19/07 AR01575421 CDBI IST Instrumentation Accuracy 10/22/13 AR01177556 2E51-C002 As-Found Condition of the #7 steam Jet Body 02/20/11 AR01177586 Potential FME Noted during Disassembly of RCIC Turbine 02/20/11 AR00157514 NRC Response to TIA 2001-14 05/06/03 AR01503409 Lightning Strike in 138KV Switchyard Results in Automatic Reactor Shutdown of LaSalle Units 1 and 2 Root Cause Investigation Report 06/20/13 AR01088030 Procedure to align RCIC to draw suction from CST. 07/06/10 ACIT1356743-03 Braidwood and Byron EDG Full Load Reject Practice Review 06/13/12 AR00442006 Low Flow on Cooler 2VY02A During LOS-DG-Q3 01/13/06 AR00498484 OPEX Review Fermi Impact of EDG Frequency on Loading 06/09/06 AR00534749 Potential Issues with the Use of Ultra Low Sulfur in EDGs 02/13/12 AR00547835 IN 2006-22 Ultra Low Sulfur Fuel633 10/23/07 AR00688908 Part 21 for 0 DG Air Start Solenoid Valve Never Installed 10/24/07 AR00820843 0DG HX Inspection Found 19 Tubes Blocked 09/22/08 AR01136071 CDBI: Potential Non-Conservative Tech Spec for EDG Fuel Oil 11/05/10 AR01141618 NRC Identified, CDBI, ECCS NPSH with Increased DG Frequency 11/17/10 AR01164421 LOS-DG-Q1 Att A4 Failure 01/19/11 AR01166990 NOS ID: OPEX Actions From NRC IN 2009-02 were Not Implemented 01/26/11 AR01175718 0XI- 02/16/11 AR01232144 0 DG Fuel Oil Transfer Pump Excessive Start Freq Alarm 06/23/11 AR01232202 Header Downstream of Engine Air Box Drain Valve Blocked 06/23/11 AR01232221 0XI-DG077 Pyrometer Reading is Erratic 06/23/11 AR01243373 Feed Breaker to 0VD01C at 135X-2 Found Tripped 07/24/11 AR01244368 0VD01C Monitoring Plan 07/27/11 AR01257379 NRC Identified Issue with 0VD01YA manual Bypass Blade 08/30/11 AR01293864 0 DG Pyrometer Reading Low 11/23/11 AR01432987 10/29/12 AR01503431 0 DG Tied to Both Units During Transient 04/18/13 AR01557106 Inline Oiler Is Not Entraining Proper Amount of Oil 09/11/13 AR02381332 0 DG HX Inspection Found Evidence of Bypass Flow 09/15/14 AR02381627 0DG01A DG Heat Exchanger Does not Have Appropriate Coating 09/16/14 AR02382031 STS Controller Outputs Found Degraded During PM Testing 09/17/14 AR02382989 0DG01A HX Coating Repairs Needed 09/18/14 AR02382997 Common DG Cooler Leak from North Blank Flange 09/18/14

6 CORRECTIVE ACTION DOCUMENTS REVIEWED DURING THE INSPECTION Number Description or Title Date AR02425069 0 DG Cooler Leaking from North End 12/14/14 AR02460815 0 Diesel Generator Issues 02/28/15 AR02571589 0DO01T Level Low 10/15/15 AR02599071 0 DG Cooler Flange Leak Increased When 0 DG Cooling Pump Run 12/11/15 AT1166990-06 Station Diesel Owner to Review/Audit site-Specific Fuel Oil Purchase, Delivery, and Processing Logistics for Each Station Diesel Engine Application 05/31/11 AR00560991 Prints Not Correct: 2E51-K603 11/21/06 AR00872658 01/27/09 AR01030566 1DC13E Top Right Bolt Is Stripped and Will Not Tighten 02/15/10 AR01124515 MCR Recorder 2TR-CM038A Backup Battery Issue 10/10/10 AR01130619 MCR Recorder 2TR-CM028 Backup Battery Issue 10/26/10 AR01184065 2TR-CM037A Recorder Pen Stuck, Does not Respond to Change 03/07/11 AR01301597 2E31-N013BA Has Chemical Buildup at Ports on Switch 12/13/11 AR01353739 2E31-N013BA Trend Code B4 04/13/12 AR01377629 During LIS-RI-201 2E31-N013BA Stop Valve Leaking By 06/13/12 AR01406112 Instrument Out of Tolerance, 1E31-N013BA, Trend Code B4 08/28/12 AR01458428 Power Light not on for 2E51-K603 01/04/13 AR01470186 2TR-CM038A Recorder Pen Sticky 02/01/13 AR01519502 1E31-N013BA Failed/No Reset Obtainable LIS-RI-101 05/30/13 AR01524753 Instrument Out-of-Tolerance, 2E31-N013BA, Trend Code B1 06/13/13 AR01552116 Instrument Out of Tolerance, 1E31-N013BA, Trend Code 3 08/29/13 AR01605840 DC to AC Power On Light not Lit 01/09/14 AR01632613 U-2 Division 1 Ground 75 Volts 03/12/14 AR01632888 U-2 Division 1 125 Vdc Ground 60 Volts 03/13/14 AR01658819 U-2 Division 1 Ground Received 05/12/14 AR01659226 U-2 Division 1 Ground 05/13/14 AR01661043 U-2 Division 1 DC Ground 05/16/14 AR01663544 U-2 Division 1 Ground Alarm 05/23/14 AR01669065 Division 1 Ground U-2 06/08/14 AR01669913 Division 1 Battery Ground Alarm 06/11/14 AR01673406 Division 1 Ground Alarm Received 06/20/14 AR01676713 Division 1 125 VDC Ground Alarm 06/30/14 AR01693700 1LR-CM208 Suppression Chamber Water Level Recorder not Reliable, Sticks at Zero 08/18/14 AR01695294 U-2 Division 1 Ground 08/22/14 AR01695615 2TE-CM-057C-A Reading Abnormally High 08/22/14 AR02381644 U-2 Division 1 DC Ground 09/16/14 AR02383228 Received Division 1 125 VDC Ground Alarm 09/19/14 AR02392651 Unexpected MCR Alarm 211X/Y Ground Detector 10/08/14

7 CORRECTIVE ACTION DOCUMENTS REVIEWED DURING THE INSPECTION Number Description or Title Date AR02397905 Received Division 1 125 VDC Ground Detector Alarm 10/20/14 AR02418240 Unexpected MCR Alarm 2PM01J-A409, Division 1 DC Ground 11/28/14 AR02418638 Intermittent Division 1 Ground Alarm Alarming in MCR 11/30/14 AR02419372 Received Momentary 2PM01J-B504 Division 2 Ground Detection Alarm 12/02/14 AR02425660 Unit 2 Division 1 125 VDC Ground Alarms 12/15/14 AR02429456 Momentary Division 1 125 VDC Ground Detector Alarm 12/24/14 AR02447974 Unit 2 Division 1 DC Ground Spiking 02/05/15 AR02449037 Unit 2 Division 125 VDC Momentary Ground Alarm 02/07/15 AR02453155 Unexpected Momentary Unit 2 Division 2 125 VDC Ground Alarm 02/15/15 AR02455840 Condenser Tube Pull Area Fire Alarm Circuit Causes Division 1 Ground 02/19/15 AR02496015 Unexpected MCR Alarm 2PM013-A409 Division 1 Ground 05/05/15 AR02509179 -CM030 Added to Passport 06/02/15 AR02509186 -CM030 Added to Passport 06/02/15 AR02520165 Division 1 DC Bus Ground Detector Alarm 06/26/15 AR02520553 Annunciator 2PM01J-A409, Division 1 Ground Detector 06/27/15 AR02523164 Unexpected MCR Alarm, Division 1 Ground Detector Trouble 07/02/15 AR02577832 1DC11E Door Handle Mechanism is Broken 10/27/15 AR02599359 Division 1 Ground Detector Alarm 2PM01J-A409 Received Alarm 12/12/15 AR02636107 Instrument Out-of-Tolerance, 1LT-CM-062, Trend Code B4 03/04/16 AR02637638 Unit 2 Division 2 125 VDC Ground Due to MDRFP Seal Failure 03/28/16 AR01139601 CDBI Potential Deficiency in Calculation L-003364 11/12/10 AR01141298 CDBI Fast Bus Transfer of 4KV Buses 11/16/10 AR01244368 0VD01C Monitoring Plan 07/27/11 AR01243373 Feed Breaker to 0VD01C at 135X-2 Found Tripped 07/24/11 AR00699172 Division 3 DG Neutral Ground Resistor Location not per Design 11/12/07 DRAWINGS Number Description or Title Date or Revision M-149, Sh. 3 P&ID Reactor Building Floor Drains H M-92, Sh. 1 P&ID Primary Containment Vent & Purge AU M-147, Sh. 1 P&ID Reactor Core Isolation Coolant System (RCIC) BL M-147, Sh. 2 P&ID Reactor Core Isolation Coolant System (RCIC) AO 761E205AA Process Diagram, Reactor Core Isolation Coolant System 8 M-127 P&ID Cycled Condensate Storage System AL D-0805 L 28SW404563 Assembly Dwg, Safety Related Cooling Coils, CSCS Equipment Area 07/26/76 66781E RCIC Pump Outline F M-66 Drywell Pneumatic System P&ID; Sheets 1 AC

8 DRAWINGS Number Description or Title Revision M-66 Drywell Pneumatic System P&ID; Sheets 2 V M-66 Drywell Pneumatic System P&ID; Sheets 3 AI M-66 Drywell Pneumatic System P&ID; Sheets 4 AB M-66 Drywell Pneumatic System P&ID; Sheets 5 O M-66 Drywell Pneumatic System P&ID; Sheets 6 O M-66 Drywell Pneumatic System P&ID; Sheets 7 U M-66 Drywell Pneumatic System P&ID; Sheets 8 H M-66 Drywell Pneumatic System P&ID; Sheets 9 B M-66 Drywell Pneumatic System P&ID; Sheets 10 A M-66 Drywell Pneumatic System P&ID; Sheets 11 A M-96 Residual Heat Removal System P&ID; Sheets 1 BC M-96 Residual Heat Removal System P&ID; Sheets 2 BB M-96 Residual Heat Removal System P&ID; Sheets 3 AU M-96 Residual Heat Removal System P&ID; Sheets 4 AG M-96 Residual Heat Removal System P&ID; Sheets 5 M 19518 Performance Curve [ECCS Water Leg Pumps] 2 13251-1 DAAP-7402 Opposed Multiblade Damper Outline G 13251-2 Schedule for Drawings 13251 & 13251-1 G 1E-0-4418AA U 1E-0-4433AB Schematic Diagram Diesel Generator Room Ventilation System VD Part 2 L 1E-1-4026AA Schematic Diagram Diesel Fuel Oil System V 74-2131, Sh. 1 DG Storage Tank 4 74-2131, Sh. 1A DG Storage Tank 5 M-1444 P&ID Diesel Generator Room Ventilation System J M-3444, Sh. 1 HVAC C&I Detail Diesel Generator Room Ventilation System Supply Fan Start-Stop & Damper Interlock D M-83, Sh. 2 P&ID Diesel Generator Auxiliary System AF M-85, Sh. 1 P&ID Diesel Oil System AE M-865, Sh. 1 Diesel Generator Room Misc. Piping U M-865, Sh. 2 Diesel Generator Room Misc. Piping M 1E-1-4000LE Key Diagram, 120/208 VAC Distribution Panel at 480V MCC 135x-2 (1AP72E) O 1E-1-4018ZA Loop Schematic Diagram, Containment Monitoring System CM Part 1 R 1E-1-4018ZB Loop Schematic Diagram, Containment Monitoring System CM Part 2 O 1E-1-4018ZJ Loop Schematic Diagram, Containment Monitoring System CM Part 9 AB 1E-1-4214AA Schematic Diagram, Remote Shutdown System RS, Part 1 M 1E-2-4000FB Key Diagram 125 Vdc Distribution ESS Division 1 O 1E-2-4000FC Key Diagram 125 Vdc Distribution ESS Division 2 P 1E-2-4018ZE Loop Schematic Diagram Containment Monitoring System CM Part 5 K

9 DRAWINGS Number Description or Title Revision 1E-2-4226AA Schematic Diagram, Reactor Core Isolation Cooling System RI (E51) Part 1 R 1E-2-4226AF Schematic Diagram, Reactor Core Isolation Cooling System RI (E51) AA 1T-7000-E-EN-08 SOR Models 102 and 103 Equivalent Replacement, Sh. 1 F 1T-7000-E-EN-08 SOR Models 102 and 103 Equivalent Replacement, Sh. 2 D M-1340 Instrument Installation Details, Sh. 15 J 1E-0-4412AA Schematic Diagram 4160 SWGR 141Y, Feed ACB 1413 AD 1E-0-4412AB Schematic Diagram Feed ACB 2413 AD 1E-0-4412AJ Schematic Diagram W 1E-1-4026AB Schematic Diagram V 1E-1-4026AA Schematic Diagram 1 V 1E-1-4000PG Relaying & Metering Diagram 4160 Switchgear Q 1E-1-4005AM Schematic Diagram 4160 Switchgear N 1E-1-4226AU Schematic Diagram Reactor Core Isolation Cooling System - Z 1E-0-4418AA Schematic Diagram U 1E-2-4000EB Key Diagram 250V DC Bus No.2 and MCC 221X M 1E-2-4000EC Key Diagram 250V DC MCC 221Y S 1E-0-4401S V 1E-0-4433AA Schematic Diagram Diesel Generator Room Ventilation M 10 CFR 50.59 DOCUMENTS (SCREENINGS/SAFETY EVALUATIONS) Number Description or Title Date ER 9501392 Filter Bag Installation in Reactor Building, Turbine Building and Auxiliary Building Floor Drains 08/30/95 LST-95-085 Installation of Mesh Basket/Screens in the Floor Drains 12/07/95 L03-0273 UFSAR Change LU2003-024, Suppression Pool Cooling Operating Time Limitation 07/24/03 L13-180 New Procedure LOA-LOOP-101(201) 09/27/13 L97-180 Diesel Generator VD Bypass Damper 05/05/98 L02-0242 50.59 Review - Revise TRM 3.7.g Area Temperature Monitoring 07/24/02 L02-0359 EDG Ventilation Modified to Control Air In-Leakage 10/18/02 L-14-104 50.59 Screening for EC 396093 02/13/15 L15-58 Unit 1 4KV Bus Transfer Logic Modification for an Open Phase Condition Concurrent with LOCA 08/24/15

10 MISCELLANEOUS Number Description or Title Date or Revision Containment Coatings Program UDC/UQF Log 03/16/16 Spec.No.T-3763 Mechanical and Structural Work Specification Maintenance/Modification Work 20 Containment Coatings Program Plan 1 EC392593 Evaluation of Estimated Amount of L2R14 Suppression Pool Sludge 05/29/13 EC401088 Assessment of De-Sludeging Deferral from L2R15 02/1715 SL-2038 Letter, H. Peffer to A. Meligi, LaSalle RCIC Turbine Seismic Re-Evaluation 05/11/81 GEH-LCS-AEP-045 LaSalle TPO Station Blackout Evaluation Task T0903 07/07/09 22A2869AF GE Design Specification Data Sheet, RCIC System 12 EMD-029197 Seismic Requalification of Reactor Core Isolation Cooling Pump (E51-C001) 03/27/81 EC 376896 Establishment of IST Acceptance Criteria for RCIC Pump 0 DBD-LS-M11 Topical Design Basis Document Flood Protection E CQD-028928 Vent and Purge Valves Qualification CECo Mod. 1-1-84-026 03/26/86 VM J-0395 Clow-Tricentric Valves/GH Bettis Actuators 4 Atwood & Morrill Report No. 7-25-85, Purge & Vent Valve Operability Qualification Analysis 0 22A3008 GE Design Specification, BWR Equipment Environmental Interface Data 5 VM J-0010 RCIC Pump Performance 8 GL 89-13 Program Basis Document 10 0024-00991 (LST-81-057) DG-Start Test on Stored Air 10/27/81 0084-02812 (LST-82-104) DG-0, 1A,1B, 2A Starts on Stored Air (Pre-Op Testing) 04/05/82 IST-LAS-PLAN IST Program Plan 10/12/07 J-2585 DG Fan Vendor Manual 06/09/78 PES-P-006 Diesel Fuel Oil (Standard) 11 RS-10-031 Application For Technical Specifications Change Regarding Risk-Informed Justification For The Relocation of Specific Surveillance Frequency Requirements To a Licensee Controlled Program 02/15/10 RS-10-136 Additional Information Supporting Request For License Amendment Regarding Application Of Alternate Source Term 08/03/10 TE 362860 Technical Evaluation Ultra Low Sulfur Diesel Fuel Evaluation 10/06/06 TE 375645 Technical Evaluation Biodiesel Blend Fuel Oil Evaluation 05/21/09 22A1483AJ General Electric Design Specification Data Sheet, High Pressure Core Spray System, Sheet 8 9 ACE 2607807-02 Apparent Cause Investigation Report: Main Steam Line High Flow Switch 2E31-N011D not Holding Pressure 02/09/16 IM-025046-1 NLI Instruction Manual for Inverter Assembly, P/N NLI-INV250-125-115, LaSalle Station 0

11 MISCELLANEOUS Number Description or Title Date or Revision L-2459 L2462; L-2497 L2501 Drift Verification for SOR Models Suffix X6, X7, X8 Pressure Switches: Calculation Spreadsheets L-2459 through L-2462; L-2497 through L-2501 12/31/15 PES-S-002 Exelon Document: Shelf Life, pp. 1, 7 8 QR-025046-1 Qualification Report for NLI Inverter Assembly P/N NLI-INV250-125-115 0 VETIP J-0800 GE-NUMAC Suppression Pool Temperature Monitor (SPTM), GEK-97056B Appendix C, SPTM Functions 1 Plant Engineering failure trend data for SOR switches associated with leak detection system 1984 to present Vickery-Sims Orifice Performance Curve, E51-N001 11/29/72 AT01553707-07 OPEX Evaluation NRC IN 2013-14, Potential Design Deficiency 10/29/13 MODIFICATIONS Number Description or Title Date or Revision 02-008 Change Request to TRM 3.7.g 09/16/02 96-034 UFSAR Revision Associated with Tech Spec Amendment 109 and 94 05/16/96 LU 2002-023 UFSAR Change Section 9.4.5.1.2 10/18/02 LUCR-181 UFSAR Chang for EC 374810 05/07/09 LUCR-216 UFSAR Changes Associated with the Alternate Source Term Implementation 11/12/10 EC 396093 Install 125 Vdc/120 Vac Inverter to Power Existing 120 Vac/24 Vdc Power Supply that Feeds Existing Containment Instrumentation 02/26/15 EC 395217 Unit 2 Division 1 and 2 DG Feed Breaker Logic Mod due to C RHR and LPCS Anti-Pump Logic 1 EC 331699 Abandonment of Diesel Fire Pump Fuel Oil Transfer Pump Suction Valves 1(2)DO024 07/27/01 OPERABILITY EVALUATIONS Number Description or Title Revision EC 405589 VY Cooler Pressure Drop for Op Eval 16-003 0 EC 405581 VY Cooler Heat Transfer with Tubes Plugged for Op Eval 16-003 0 OE 13-005 Non-compliance of Pump IST Instrumentation Accuracy with ASME Code Requirements 1 OE 16-003 Impact of Increased Cooling Water dP Across Safety Related Room Coolers on Heat Transfer Performance Capability 0 OE 10-005 Potential Non-Conservative Tech Spec for EDG Fuel Oil 6

12 PROCEDURES Number Description or Title Revision ER-AA-330-008 Exelon Service Level I, and Safety-Related (Service Level III) Protective Coatings 10 CC-AA-205 Control of Undocumented/Unqualified Coatings Inside the Containment 9 LTS-600-41 Primary Containment Inspections for ECCS Suction Strainer Debris Sources 9 LMP-GM-80 Suppression Chamber Desludging 5 LOS-RI-Q5 RCIC System Pump Operability, Valve Inservice Tests in Modes 1, 2, 3 and Cold Quick Start 39 LMP-RI-02 RCIC Turbine Maintenance 23 LTS-100-6 Primary Containment Vent and Purge Outlet Valves, Local Leak Rate Test, 1(2)VQo31/32/34/35/36/40/68 30 OP-LA-102-106 LaSalle Station Operator Response Time Program 7 OP-LA-103-102-1002 Strategies for Successful Transient Mitigation 16 LGA-RH-103 Unit 1 A/B RHR Operations in the LGAS/LSAMGS 12 LGA-RH-203 Unit 2 A/B RHR Operations in the LGAS/LSAMGS 13 LOA-AP-101 Unit 1 AC Power System Abnormal 52 LOA-AP-201 Unit 2 AC Power System Abnormal 48 LOA-DG-101 DG Failure [Unit 1] 9 LOA-DG-201 DG Failure [Unit 2] 8 LOA-FC-101 Unit 1 Fuel Pool Cooling System/Reactor Cavity Level Abnormal 25 LOA-FC-201 Unit 2 Fuel Pool Cooling System/Reactor Cavity Level Abnormal 23 LOA-IN-101 Loss of Drywell Pneumatic Air Supply 9 LOA-LOOP-101 Loss of Offsite Power [Unit 1] 4 LOA-LOOP-201 Loss of Offsite Power [Unit 2] 4 ER-AA-340 GL 89-13 Program Implementing Procedure 7 ER-AA-340-1001 GL 89-13 Program Implementation Instructional Guide 9 LOP-CX-08 Uninterruptible Power Supply Startup, Operation, and Shutdown 10 LOP-HY-04 Main Generator Hydrogen Removal 20 LOP-IN-05 Replacing Nitrogen Bottles on Instrument Nitrogen System 25 LOP-RH-01 Filling and Venting the Residual Heat Removal System 57 LOP-RH-02 Venting the Residual Heat Removal System 9 LOP-VD-03 Startup and Operation of Ventilation Systems for Diesel Generator 0DG01K Room and Associated Diesel Fuel Storage Room 12 LOP-VD-05E Unit 0 Diesel Ventilation System Electrical Checklist 7 LOR-1H13-P601-C405 1A RHR PMP DSCH PRESS LO 5 LOR-1PM13J-A404 INSTRUMENT NITROGEN SYS TROUBLE 7 LOR-1PM13J-B404 INSTRUMENT NITROGEN SYS TROUBLE 6 ER-AA-200-1001 Equipment Classification 1 ER-AA-340-1002 Service Water Heat Exchanger Inspection Guide 6 LEP-EQ-127 Hydramotor Replacement 21

13 PROCEDURES Number Description or Title Date or Revision LMS-ZZ-04 Water Tight Door Inspection 6 LOP-DG-04 Diesel Generator Special Operations 66 LOP-DO-01 Receiving and sampling New Diesel Fuel Oil 39 LOP-PF-01 Closure of Water Tight Doors 6 LOR-0PL17J-1-1 Diesel Generator Room Ventilation Supply Air Filter Differential Pressure High 1 LOS-DG-M2 1A Diesel Generator Fast Start 93 LOS-DG-Q1 0 Diesel Generator Auxiliaries Inservice Test 65 LOS-DG-Q3 1B DG Fuel Oil Transfer Pump Test 71 LOS-DO-SR2 Diesel Fuel Oil Analysis Verification (New Fuel Oil) 17 LOS-PF-M1 ECCS/CSCS Water Tight Door Surveillance 0 LTS-200-11 Diesel Generator Cooling Heat Exchanger Thermal Performance Monitoring 17 LTS-800-101 0 Diesel Generator Start and Load Acceptance Surveillance 2 LES-GM-130 Inspection of Westinghouse Motor Control Center Equipment and GE Molded Case Breakers 23 LIP-CM-605 Unit 2 Suppression Chamber High Level Calibration 2 LIS-CM-201 Unit 2 Suppression Chamber Wide and Narrow Range Water Level Indication Calibration 17 LIS-RI-203A Unit 2 RCIC Equipment Room/Steam Line Tunnel High Ambient and Differential Temperature Outboard Isolation (Division 1) Calibration 15 LIS-RI-203B Unit 2 RCIC Equipment Room/Steam Line Tunnel High Ambient and Differential Temperature Inboard Isolation (Division 2) Calibration 15 LIS-RI-403A Unit 2 RCIC Equipment Room/Steam Line Tunnel High Ambient and Differential Temperature Outboard Isolation (Division 1) Functional Test 10 LIS-RI-403B Unit 2 RCIC Equipment Room/Steam Line Tunnel High Ambient and Differential Temperature Outboard Isolation (Division 2) Functional Test 9 LIS-RX-202 Unit 2 Remote Shutdown System Suppression Chamber Water Temperature Indication Calibration 6 LOP-CM-03 Suppression Chamber Average Water Temperature Determination 13 LOS-CM-M1 Monthly Accident Monitoring Instrumentation Channel Check, Attachment 1A, Item 11, Suppression Pool Water Temperature 44 MA-AA-723-325 Molded Case Breaker Testing 15 OP-AA-102-106 Operator Response Time Validation Sheet [TCA 24: 30 minute response time] 06/24/14 LOA-FX-101 Unit 1 Safe Shutdown with a Fire in the Control Room 27 LOA-FX-201 Unit 2 safe Shutdown with a Fire in the Control Room 29 LES-GM-109 Inspection of 480V Klockner-Moeller Motor Control Center 41 NES-E/I&C 10.01 Molded Case Circuit Breaker Selection and Setting Design Standard 2

14 PROCEDURES Number Description or Title Revision MA-LA-773-401 6 LOP-CX-03 ESF Status Panel Operation and Response to Panel Indication 14 SURVEILLANCES (COMPLETED) Number Description or Title Date WO 01534018 RCIC Control Sys Surveillance, LIS-RI-215 08/18/14 WO 01315081 RCIC Control Sys Surveillance, LIS-RI-215 04/09/12 WO 01602574 IM Verify APRM A, B, C, D Flow 02/19/15 WO 01885199 RCIC Cold Quick Start Quarterly Surveillance, LOS-RI-Q5 03/18/16 WO 01709225 RCIC Cold Quick Start Comprehensive Surveillance, LOS-RI-Q5 09/08/15 WO 01885198 Unit 2 PCIS Valves Operability and Inservice Inspection Test 03/14/16 WO 01602514 Unit 2 VQ Valves Position Indication Test, Grease Inspection and EQ Inspection for Primary containment Isolation Valves 12/13/14 WO 01182421-01 IM-CAL 0 DG Vent Damper Temp Control Loop 0VD003 07/09/14 WO 01620128-02 OP Perform LOS -DG-201 U-2 0 DG Start and Load Acceptance 02/19/15 WO 01675903-01 IM LIP-DG-901 DG 0 Fuel Oil STG TK Level Switch & Ind Cal 07/21/14 WO 01681600-01 OP LOS-DG-Q1 0 DG FO Transfer Pump Test ATT A1 01/14/14 WO 01697599-14 OP Perform LOS-DG-101 For PMT of EC 395216 Div 1 03/04/16 WO 01755831-01 OP LOS-DG-M1 0 DG Idle Start ATT 0-Idle 08/20/14 WO 01799852-01 OP LOS-DG-Q1 0 DG FO Transfer Pump Test ATT A1 04/14/15 WO 01824458-01 OP LOS-DG-Q1 0 DG FO Transfer Pump Test ATT A1 07/10/15 WO 01846833-01 OP LOS-DG-M1 0 Diesel Generator Fast Start Att O-Fast 02/10/16 WO 01870155-01 OP LOS-DG-Q1 0 DG FO Transfer Pump Test ATT A1 01/12/16 WO 01906522-01 OP LOS-DG-M1 0 DG Idle Start Att 0-Idle 03/25/16 WO 01212770 IM LIS-RX-202 U2 Remote Shutdown System Suppression Chamber Water Temperature 08/19/10 WO 01365359 IM LIS-RX-202 U2 Remote Shutdown System Suppression Chamber Water Temperature 08/15/12 WO 01395536 2E51-K603 Inverter: Verify Proper Voltages 03/20/13 WO 01460932 IM LIS-CM-201 U2 Suppression Chamber Wide and Narrow Range Water Level Indication 12/11/13 WO 01488819 IM LIP-CM-605 U2 Suppression Chamber High Level Calibration 10/01/14 WO 01568087 IM LIS-RI-201 U2 Suppression Chamber Water Temperature Indication Calibration 12/15/14 WO 01568153 IM LIS-RX-202 U2 Remote Shutdown System Suppression Chamber Water Temperature 10/12/14 WO 01602534 RCIC Area/Pipe Tunnel High Ambient/Differential Temperature Isolation Channel A & C [LIS-RI-403A] 12/12/14 WO 01625514 2E51-K603 Inverter: Verify Proper Voltages 03/11/15 WO 01635855 RCIC Area Pipe Tunnel High Ambient/Differential Temperature Isolation Channels B&D 04/07/15

15 SURVEILLANCES (COMPLETED) Number Description or Title Date WO 01844790 IM LIS-RI-201 U2 Steam Line High Flow RCIC Isolation Calibration 10/13/15 WO 01868212 RCIC Area Pipe Tunnel High Ambient/Differential Temperature Isolation Channels B&D [LIS-RI-403B] 01/04/16 WO 01869497 IM LIS-RI-201 U2 Steam Line High Flow RCIC Isolation Calibration 01/16/16 WO 01889791 RCIC Area/Pipe Tunnel High Ambient/Differential Temperature Isolation Channel A & C [LIS-RI-403A] 04/18/16 WO 01890374 IM LIS-RI-201 U2 Steam Line High Flow RCIC Isolation Calibration 04/06/16 WO 01907719 LOS-CM-M1 U2 Containment Monitoring Instrumentation Att. 2A 04/14/16 WO 01601996 Perform LES-DG-100 Attachment 1 and 2 on 0DG01K 09/17/14 TRAINING DOCUMENTS Number Description or Title Revision 011 EDG and Auxiliaries 14 Chapter 128 Safety Related Ventilation, VD, VY, VX 3 WORK DOCUMENTS Number Description or Title Date WO 01727033 Inspect U1 Primary Containment 02/27/16 WO 01522325 Inspect U1 Primary Containment 02/11/14 WO 01317612 Inspect U1 Primary Containment 03/01/12 WO 01317605 Desludge U1 Suppression Pool 02/26/12 WO 00932692 Desludge U1 Suppression Pool 02/21/08 WO 01629258 Inspect U2 Primary Containment 02/17/15 WO 01448698 Inspect U2 Primary Containment 02/28/13 WO 01330504 Desludge U2 Suppression Pool 03/07/13 WO 01214505 Inspect U2 Primary Containment 03/05/11 WO 01039324 Desludge U2 Suppression Chamber 01/28/09 WO 00637256 Desludge U2 Suppression Pool 02/22/05 WO 01235193 MM RCIC Turbine Inspection/Rebuild 03/06/11 WO 00544334-01 MM Disassemble, Inspect Heat Exchanger 10/03/07 WO 00551674-01 -DG-01 03/05/04 WO 01445980-01 MM Disassemble, Inspect Heat Exchanger 07/09/14 WO 01501078-01 IM LIP-DG-903 DG Fuel Oil Day Tank Level Switch & Ind Cal 07/13/15 WO 01673449-01 Inline Oiler Is Not Entraining Proper Amount of Oil 04/23/15 WO 01713585-01 0 DG Room HVAC Air Filter High D/P Alarm 04/10/15 WO 00328231 Perform LES-GM-130 for 2H13P601 at 212Y CB-3 (2DC13E) 01/23/03 WO 00584724 Perform LES-GM-130 for 2H13P612 at 211Y CB-8 (2DC11E) 02/17/05

16 WORK DOCUMENTS Number Description or Title Date WO 00584733 Perform LES-GM-130 for Cross-Tie 111Y at 211Y CB-23 02/16/05 WO 00584738 Perform LES-GM-130 for ESS-240 at 211Y CB-11 (2DC11E) 02/18/05 WO 00839517 Perform LES-GM-130 for X-Tie 112Y at 212Y CB23 (2DC13E) 10/27/08 WO 00839520 Perform LES-GM-130 for 2P08J at 212Y CB-15 (2DC15E) 04/03/08 WO 00839523 Perform LES-GM-130 for ESS #041 at 212Y CB-11 (2DC13E) 10/27/08 WO 01235373 Perform Breaker Inspection, Maintenance and Testing: 2DC08E-CB3B 02/26/11 WO 01235380 Perform LES-GM-130 for 2H13P601 at 212Y CB-3 (2DC13E) 02/18/11 WO 01239529 2E51-K603 Inverter: Verify Proper Voltages 12/15/10 WO 01427028 Perform LES-GM-130 for Swgr 251-1 at 211Y CB-15 (2DC11E) 02/15/13 WO 01428173 Perform LES-GM-130 for 2H13P612 at 211Y CB-8 (2DC11E) 02/18/13 WO 01428176 Perform LES-GM-130 for 2C61P001 at 211Y CB-24 (2DC11E) 02/18/13 WO 01621668 2TE-CM-057A/C Suppression Pool Thermocouple Reads too High 12/15/14 WO 01695411-04 IM-PMT per EC 396093: LIS-CM-201 Sections E.3 and E.4 02/22/15 WO 01695411-12 IM-PMT per EC 396093: Perform Updated LIS-RX-202 02/09/15 WO 01629492 Perform Breaker Inspection, Maintenance, and Testing [MA-AB-725-110] for 212Y Feed 2DC15E-CB3B 02/08/15

17 LIST OF ACRONYMS USED AC Alternating Current ADAMS Agencywide Document Access Management System AOP Abnormal Operating Procedure AR Action Request CAP Corrective Action Program CDBI Component Design Bases Inspection CFR Code of Federal Regulations CSCS Core Standby Cooling System DC Direct Current DG Diesel Generator dP Differential Pressure EC Engineering Change ECCS Emergency Core Cooling System ESF Engineered Safety Feature GL Generic Letter HELB High Energy Line Break IMC Inspection Manual Chapter IN Information Notice kV Kilovolt LERF Large Early Release Frequency LOCA Loss-Of-Coolant Accident LOOP Loss of Off-site Power MCC Motor Control Center MCR Main Control Room MOV Motor-Operated Valve NCV Non-Cited Violation NPSH Net Positive Suction Head NRC U.S. Nuclear Regulatory Commission PARS Publicly Available Records System PPC Plant Process Computer PRA Probabilistic Risk Assessment RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal RSP Remote Shutdown Panel SBO Station Blackout SDP Significance Determination Process TS Technical Specification UFSAR Updated Final Safety Analysis Report Vac Volts Alternating Current Vdc Volts Direct Current

B. Hanson -2- In accordance with Title 10 of the Code of Federal Regulations of this letter, its enclosure, and your response (if any) will be available electronically for public ent Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). Sincerely, /RA/ Mark T. Jeffers, Chief Engineering Branch 2 Division of Reactor Safety Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18 Enclosure: IR 05000373/2016007; 05000374/2016007 cc: Distribution via LISTSERV DISTRIBUTION: Jeremy Bowen RidsNrrDorlLpl3-2 Resource RidsNrrPMLaSalle RidsNrrDirsIrib Resource Cynthia Pederson Darrell Roberts Richard Skokowski Allan Barker Carole Ariano Linda Linn DRPIII DRSIII ROPreports.Resource@nrc.gov ADAMS Accession Number ML16174A094 Publicly Available Non-Publicly Available Sensitive Non-Sensitive To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy OFFICE RIII RIII RIII RIII NAME NFeliz-Adorno:cl MJeffers DATE 06/20/16 06/22/16 OFFICIAL RECORD COPY