Text

Issuance of Amendment No. 202, Revise Technical Specifications to Adopt TSTF-425 Rev. 3, Relocate Surveillance Frequencies to Licensee Control-Risk Informed Technical Specification Task Force (RITSTF) Initiative 5b
	ML111661877
Person / Time
Site:	Callaway
Issue date:	07/29/2011
From:	Thadani M; Plant Licensing Branch IV
To:	Heflin A; Union Electric Co
	Gibson, Lauren, NRR/DORL/LPL4, 415-1056
References
	TAC ME4506
	Download: ML111661877 (223)
	v • d • e

UNITED NUCLEAR REGULATORY WASHINGTON, D.C. 20555*0001 July 29, 2011 Mr. Adam C. Heflin Senior Vice President and Chief Nuclear Officer Union Electric Company P.O. 80x 620 Fulton, MO 65251 CALLAWAY PLANT, UNIT 1 -ISSUANCE OF AMENDMENT RE: ADOPTION OF TSTF-425, REVISION 3, "RELOCATE SURVEILLANCE FREQUENCIES TO LICENSEE CONTROL -RITSTF INITIATIVE 58" (TAC NO. ME4506)

Dear Mr. Heflin:

The U.S. Nuclear Regulatory Commission (NRC, the Commission) has issued the enclosed Amendment No. 202 to Facility Operating License No. NPF-30 for the Callaway Plant, Unit 1. The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated August 5, 2010, as supplemented by letters dated March 23, May 3, and July 25, 2011. The amendment revises the TSs by relocating specific surveillance frequencies to a controlled program with the guidance of Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies." The amendment adopts NRC-approved Technical Specification Task Force (TSTF)-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control -RITSTF [Risk-Informed TSTF] Initiative 5b." When implemented, TSTF-425 relocates most periodic frequencies of TS surveillances to a licensee-controlled program, the Surveillance Frequency Control Program (SFCP), and provides requirements for the new program in the Administrative Controls section of the TSs.

A. Heflin -A copy of the related Safety Evaluation is also enclosed.

The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice. Sincerely, Mohan C. Thadani, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-483

Enclosures:

1. Amendment No. 202 to NPF-30 2. Safety Evaluation cc w/encls: Distribution via Listserv UNITED NUCLEAR REGULATORY WASHINGTON, D.C. 20555-0001 UNION ELECTRIC CALLAWAY PLANT, UNIT DOCKET NO. AMENDMENT TO FACILITY OPERA liNG Amendment No. 202 License No. NPF-30 The Nuclear Regulatory Commission (the Commission) has found that: The application for amendment by Union Electric Company (UE, the licensee), dated August 5,2010, as supplemented by letters dated March 23, May 3, and July 25, 2011, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's regulations set forth in 10 CFR Chapter I; The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regUlations; The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

Enclosure 1

-2 Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2} of Facility Operating License No. NPF-30 is hereby amended to read as follows: (2) Technical Specifications and Environmental Protection Plan* The Technical Specifications contained in Appendix A, as revised through Amendment No. 202 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. This amendment is effective as of its date of issuance, and shall be implemented within 180 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Facility Operating License No. NPF-30 and Technical Specifications Date of Issuance:

Jul y 29, 2011 ATTACHMENT TO LICENSE AMENDMENT NO. FACILITY OPERATING LICENSE NO. DOCKET NO. Replace the following pages of the Facility Operating License No. NPF-30 and Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change. Facility Operating License REMOVE INSERT Technical Specifications REMOVE INSERT REMOVE INSERT TOe 1 to Toe 4 Toe 1 to Toe 4 3.5-2 to 3.5-12 3.5-2 to 3.5-13 3.1-1 3.1-1 3.6-6 3.6-6 3.1-3 3.1-3 3.6-13 to 3.6-17 3.6-13 to 3.6-17 3.1-10 3.1-10 3.6-19 to 3.6-21 3.6-19 to 3.6-22 3.1-12 3.1-12 3.7-8 3.7-8 3.1-14 to 3.1-15 3.1-14 to 3.1-15 3.7-11 3.7-11 3.1-20 to 3.1-22 3.1-20 to 3.1-23 3.7-17 to 3.7-18 3.7-17 to 3.7-18 3.2-3 3.2-3 3.7-20 3.7-20 3.2-5 3.2-5 3.7-22 3.7-22 3.2-8 3.2-8 3.7-25 3.7-25 3.2-9 3.2-9 3.7-27 3.7-27 3.2-13 3.2-13 3.7-31 3.7-31 3.3-12 to 3.3-77 3.3-12 to 3.3-83 3.7-34 3.7-34 3.4-2 to 3.4-3 3.4-2 to 3.4-3 3.7-38 3.7-38 3.4-5 to 3.4-6 3.4-5 to 3.4-6 3.7-40 3.7-40 3.4-9 3.4-9 3.7-42 3.7-42 3.4-11 3.4-11 3.7-45 3.7-45 3.4-14 3.4-14 3.7-47 3.7-47 3.4-16 3.4-16 3.8-6 to 3.8-39 3.8-6 to 3.8-41 3.4-18 3.4-18 3.9-2 3.9-2 3.4-24 3.4-24 3.9-4 3.9-4 3.4-28 to 3.4-29 3.4-28 to 3.4-29 3.9-6 3.9-6 3.4-31 3.4-31 3.9-8 3.9-8 3.4-34 to 3.4-35 3.4-34 to 3.4-35 3.9-10 3.9-10 3.4-39 3.4-39 3.9-12 to 3.9-13 3.9-12 to 3.9-14 3.4-41 to 3.4-44 3.4-41 to 3.4-45 5.0-21 5.0-21

-3 UE, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source of special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and UE, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility, This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below: Maximum Power Level UE is authorized to operate the facility at reactor core power levels not in excess of 3565 megawatts thermal (100% power) in accordance with the conditions specified herein. Technical Specifications and Environmental Protection Plan* The Technical Specifications contained in Appendix A, as revised through Amendment No. 202 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. Environmental Qualification (Section 3.11! SSER Deleted per Amendment No. Amendments 133, 134, & 135 were effective as of April 30, 2000 however these amendments were implemented on April 1, 2000. The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report and/or its supplements wherein the license condition is discussed.

Amendment No. 202 TABLE OF 1.0 USE AND APPLICATION

........................................................................ 1.1 Definitions

.......................................................................................... 1.2 Logical Connectors

............................................................................ 1.3 Completion Times .............................................................................. 1.4 Frequency

.......................................................................................... 2.0 SAFETY LIMITS (SLs) ..........................................................................2.1 SLs ...................................................................................................2.2 SL Violations

....................................................................................3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY

..... 3.0-1 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY

.................... 3.1 REACTIVITY CONTROL SYSTEMS .....................................................3.1.1 SHUTDOWN MARGIN (SDM) ........................................................3.1.2 Core Reactivity

............................................................................... 3.1.3 Moderator Temperature Coefficient (MTC) ...................................... 3.1.4 Rod Group Alignment Limits ......................................

..................... 3.1.5 Shutdown Bank Insertion Limits .....................................................3.1.6 Control Bank Insertion Limits ........................................................... 3.1.7 Rod Position Indication

.................................................................... 3.1.8 PHYSICS TESTS Exceptions

-MODE 2 ........................................ 3.1.9 RCS Boron Limitations

< 500°F ....................................................... 3.2 POWER DISTRIBUTION LIMITS .........................................................Heat Flux Hot Channel Factor (Fa(Z>> (Fa Methodology)

......................................................................

3.2-1 3.2.2 Nuclear Enthalpy Rise Hot Channel Factor ................................... AXIAL FLUX DIFFERENCE (AFD) (Relaxed Axial Offset Control (RAOC) Methodology)

..................................................

3.2-9 3.2.4 QUADRANT POWER TILT RATIO (QPTR) ................................... 3.3 INSTRUMENTATION

............................................................................3.3.1 Reactor Trip System (RTS) Instrumentation

...................................Engineered Safety Feature Actuation System (ESFAS) Instrumentation

..........................................................................

3.3-27 3.3.3 Post Accident Monitoring (PAM) Instrumentation

............................3.3.4 Remote Shutdown System ............................................................. CALLAWAY Amendment 202 TABLE OF CONTENTS 3.3 INSTRUMENTATION (continued) Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation

..........................................................................

3.3-59 3.3.6 Containment Purge Isolation Instrumentation

................................. Control Room Emergency Ventilation System (CREVS) Actuation Instrumentation

.........................................................

3.3-67 Emergency Exhaust System (EES) Actuation Instrumentation

.........................................................................

3.3-73 3.3.9 Boron Dilution Mitigation System (BDMS) ...................................... 3.4 REACTOR COOLANT SYSTEM (RCS) ................................................ RCSPressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits ...................................................

3.4-1 3.4.2 RCS Minimum Temperature for Criticality

....................................... 3.4.3 RCS Pressure and Temperature (prr) Limits .................................. 3.4.4 RCS Loops -MODES 1 and 2 ......................................................... 3.4.5 RCS Loops -MODE 3 ..................................................................... 3.4.6 RCS Loops -MODE 4 ..................................................................... 3.4.7 RCS Loops -MODE 5, Loops Filled ................................................ 3.4.8 RCS Loops -MODE 5, Loops Not Filled ......................................... 3.4.9 Pressurizer

....................................................................................... 3.4.10 Pressurizer Safety Valves ................................................................ 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) ...................... 3.4.12 Cold Overpressure Mitigation System (COMS) ............................... 3.4.13 RCS Operational LEAKAGE ............................................................ 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage ................................ 3.4.15 RCS Leakage Detection Instrumentation

........................................ 3.4.16 RCS Specific Activity ....................................................................... 3.4.17 Steam Generator (SG) Tube Integrity

.............................................. 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) ........................... 3.5.1 Accumulators

................................................................................... 3.5.2 ECCS -Operating

........................................................................... 3.5.3 ECCS -Shutdown ............................................................................ 3.5.4 Refueling Water Storage Tank (RWST) ......................................... 3.5.5 Seal Injection Flow ........................................................................... 3.6 CONTAINMENT SYSTEMS .................................................................. 3.6.1 Containment

................................................................................... 3.6.2 Containment Air Locks ..................................................................... 3.6.3 Containment Isolation Valves ......................................................... CALLAWAY PLANT Amendment 202 TABLE OF CONTENTS 3.6 CONTAINMENT SYSTEMS (continued) 3.6.4 Containment Pressure .....................................................................3.6.5 Containment Air Temperature

.........................................................3.6.6 Containment Spray and Cooling Systems ......................................3.6.7 Recirculation Fluid pH Control (RFPC) System ...............................3.7 PLANT SYSTEMS .................................................................................3.7.1 Main Steam Safety Valves (MSSVs) ...............................................Main Steam Isolation Valves (MSIVs). Main Steam Isolation Valve Bypass Valves (MSIVBVs), and Main Steam Low Point Drain Isolation Valves (MSLPDIVs)

.................................

3.7-5 3.7.3' Main Feedwater Isolation Valves (MFIVs), Main Feedwater Regulating Valves (MFRVs). and Main Feedwater Regulating Valve Bypass Valves (MFRVBVs)

..............................................

3.7-9 3.7.4 AtmospheriC Steam Dump Valves (ASDs) ......................................3.7.5 Auxiliary Feedwater (AFW) System .................................................3.7.6 Condensate Storage Tank (CST) ....................................................3.7.7 Component Coaling Water (CCW) System .....................................3.7.8 Essential Service Water System (ESW) ..........................................3.7.9 Ultimate Heat Sink (UHS) ................................................................3.7.10 Control Room Emergency Ventilation System (CREVS) .................3.7.11 Control Room Air Conditioning System (CRACS) ...........................3.7.12 Not Used .......................................................................................... 3.7.13 Emergency Exhaust System (EES) .................................................3.7.14 Not Used .......................................................................................... 3.7.15 Fuel Storage Pool Water Level ........................................................3.7.16 Fuel Storage Pool Boron Concentration

..........................................3.7.17 Spent Fuel Assembly Storage .........................................................3.7.18 Secondary Specific Activity ..............................................................3.7.19 Secondary System Isolation Valves (SSIVs) ...................................3.8 ELECTRICAL POWER SYSTEMS ........................................................3.8.1 AC Sources -Operating

...................................................................3.8.2 AC Sources -Shutdown ..................................................................3.8.3 Diesel Fuel Oil, Lube 011, and Starting Air .......................................3.8.4 DC Sources -Operating

..................................................................3.8.5 DC Sources -Shutdown ..................................................................3.8.6 Battery Cell Parameters

...................................................................3.8.7 Inverters

-Operating

........................................................................3.8.8 Inverters

-Shutdown ........................................................................3.8.9 Distribution Systems -Operating

.....................................................CALLAWAY PLANT Amendment 202 TABLE OF CONTENTS 3.8 ELECTRICAL POWER SYSTEMS (continued) 3.8.10 Distribution Systems -Shutdown ..................................................... 3.9 REFUELING OPERATIONS

................................................................. 3.9.1 Boron Concentration

........................................................................3.9.2 Unborated Water Source Isolation Valves ....................................... 3.9.3 Nuclear Instrumentation

................................................................... 3.9.4 Containment Penetrations

............................................................... Residual Heat Removal (RHR) and Coolant Circulation

-High Water Level ...................................................

3.9-9 Residual Heat Removal (RHR) and Coolant Circulation

-Low Water Level ....................................................

3.9-11 3.9.7 Refueling Pool Water Level ............................................................. 4.0 DESIGN FEATURES ............................................................................... 4.1 Site Location .................................................................................... 4.2 Reactor Core ................................................................................... 4.3 Fuel Storage .................................................................................... 5.0 ADMINISTRATIVE CONTROLS ........................................................... 5.1 Responsibility

................................................................................... 5.2 Organization

.................................................................................... 5.3 Unit Staff Qualifications

................................................................... 5.4 Procedures

...................................................................................... 5.5 Programs and Manuals ..................................................................... 5.6 Reporting Requirements

.................................................................. 5.7 High Radiation Area ......................................................................... CALLAWAY PLANT Amendment 202 3.1.1 SDM 3.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM) LCO SDM shall be within the limits provided in the COLR.

MODE 2 with keff < 1.0, MODES 3, 4, and 5. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. SDM not within limit. A.1 Initiate boration to 15 minutes restore SDM to within limit. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.1.1 Verify SDM to be within limits. In accordance with the Surveillance Frequency Control Program CALLAWAY 3.1-1 Amendment No. 202 3.1.2 Core Reactivity SURVEILLANCE REQUIREMENTS SR -----------------------------

NOTE The predicted reactivity values may be adjusted (normalized) to correspond to the measured core reactivity prior to exceeding a fuel burnup of 60 effective full power days (EFPD) after each fuel loading. Verify measured core reactivity is within +/-1 % L'lk/k of predicted values.

Once prior to entering MODE 1 after each refueling Only required after 60 EFPD In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.1-3 Amendment No. 202 3.1.4 Rod Group Alignment Limits SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.4.1 Verify individual rod positions within alignment limit. In accordance with the Surveillance Frequency Control Program SR 3.1.4.2 Verify rod freedom of movement (trippability) by moving each rod not fully inserted in the core 10 steps in either direction.

In accordance with the Surveillance Frequency Control Program SR 3.1.4.3 Verify rod drop time of each rod, from the fully withdrawn position, is:5 2.7 seconds from the beginning of decay of stationary gripper coil voltage to dashpot entry, with: a. Tavg 500°F; and b. All reactor coolant pumps operating.

Prior to reactor criticality after each removal of the reactor head CALLAWAY PLANT 3.1-10 Amendment No. 202 3.1.5 Shutdown Bank Insertion Limits SURVEILLANCE REQUIREMENTS SR 3.1.5.1 Verify each shutdown bank is within the limits specified in the COLR.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.1-12 Amendment No. 202 3.1.6 Control Bank Insertion Limits ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Control bank sequence or overlap limits not met. B.1.1 OR B.1.2 AND B.2 Verify SDM to be within the limits provided in the COLR. Initiate boration to restore SDM to within limit. Restore control bank sequence and overlap to within limits. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months C. Required Action and associated Completion Time not met. C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.1.6.1 Verify estimated critical control bank position is within the limits specified in the COLR. Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to achieving criticality SR 3.1.6.2 Verify each control bank insertion is within the limits specified in the COLR. In accordance with the Surveillance Frequency Control Program (Continued)

CALLAWAY PLANT 3.1-14 Amendment No. 202 3.1.6 Control Bank Insertion Limits SURVEILLANCE REQUIREMENTS (continued)

SR Verify sequence and overlap limits specified in the COLR are met for control banks not fully withdrawn from the core.

In accordance with the Surveillance Frequency Control Program CALLAWAY 3.1-15 Amendment No. 202 3.1.8 PHYSICS TESTS Exceptions

-MODE 2 ACTIONS (continued) CONDITION C. RCS lowest operating loop average temperature not within limit. C.1 REQUIRED ACTION Restore RCS lowest operating loop average temperature to within limit. COMPLETION TIME 15 minutes D. Required Action and associated Completion Time of Condition C not met. D.1 Be in MODE 3. 15 minutes SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.1.8.1 Perform a CHANNEL OPERATIONAL TEST on power range and intermediate range channels per SR 3.3.1.7, SR 3.3.1.8, and Table 3.3.1-1. Prior to initiation of PHYSICS TESTS SR 3.1.8.2 Verify the RCS lowest operating loop average temperature is 541°F. In accordance with the Surveillance Frequency Control Program SR 3.1.8.3 Verify THERMAL POWER is :s; 5% RTP. In accordance with the Surveillance Frequency Control Program (contInued)

CALLAWAY PLANT 3.1-20 Amendment No. 202 3.1.8 PHYSICS TESTS Exceptions

-MODE 2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.8.4 Verify SDM is within limits provided in the COLR. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.1-21 Amendment No. 202 RCS Boron Limitations

< SOO°F 3.1.9 3.1 REACTIVITY CONTROL SYSTEMS 3.1.9 RCS Boron Limitations

< SOO°F LCO The boron concentration of the Reactor Coolant System (RCS) shall be greater than the all rods out (ARO) critical boron concentration.

APPLICABILITY:

MODE 2 with keff < 1.0 with any RCS cold leg temperature

< SOO°F and with Rod Control System capable of rod withdrawal, MODE 3 with any RCS cold leg temperature

< SOO°F and with Rod Control System capable of rod withdrawal, MODES 4 and S with Rod Control System capable of rod withdrawal.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A RCS boron concentration not within limit. A. 1 OR A2 OR A3 Initiate boration to restore RCS boron concentration to within limit. Initiate action to place the Rod Control System in a condition incapable of rod withdrawal.

NOTE Not applicable in MODES 4 and S. Immediately Immediately Initiate action to increase all RCS cold leg temperatures to S SOO°F. Immediately CALLAWAY 3.1-22 Amendment No. 202 I 3.1.9 RCS Boron Limitations

< 500°F SURVEILLANCE REQUIREMENTS SR 3.1.9.1 Verify RCS boron concentration is greater than ARO critical boron In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.1-23 Amendment No. 202 3.2.1 Fa(Z) (Fa Methodology)

SURVEILLANCE REQUIREMENTS

NOT E During power escalation following shutdown, THERMAL POWER may be increased until an equilibrium power level has been achieved, at which a power distribution map is obtained.

SR 3.2.1.1 Verify F8(Z) is within limit.

Once after each refueling prior to THERMAL POWER exceeding 75% RTP Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions after exceeding, by 10% RTP, the THERMAL POWER at which F8(Z) was last verified In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.2-3 Amendment No. 202 3.2.1 Fa(Z) (Fa Methodology)

SURVEILLANCE REQUIREMENTS SR 3.2.1.2 (continued)

Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions after exceeding, by 10% RTP, the THERMAL POWER at which was last verified I n accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.2-5 Amendment 202 SURVEILLANCE

NOT E During power escalation following shutdown, THERMAL POWER may be increased until equilibrium power level has been achieved, at which a power distribution map is SURVEILLANCE SR 3.2.2.1 Verify F t1NH is within limits specified in the COLR. FREQUENCY Once after each refueling prior to THERMAL POWER exceeding 75% RTP In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.2-8 Amendment No. 202 AFD (RAOC Methodology) 3.2.3 3.2 POWER DISTRIBUTION LIMITS 3.2.3 AXIAL FLUX DIFFERENCE (AFD) (Relaxed Axial Offset Control (RAOC) Methodology)

LCO The AFD in % flux difference units shall be maintained within the limits specified in the COLR. --------------------------------------------

NOT E The AFD shall be considered outside limits when two or more OPERABLE excore channels indicate AFD to be outside limits.

MODE 1 with THERMAL POWER 50% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. AFD not within limits. A.1 Reduce THERMAL POWER to < 50% RTP. 30 minutes SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.3.1 Verify AFD within limits for each OPERABLE excore channel. In accordance with the Surveillance Frequency Control Program CALLAWAY 3.2-9 Amendment No. 202 3.2.4 QPTR SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.4.1 ---------------------------------

NOTE

1. With input from one Power Range Neutron Flux channel inoperable and THERMAL POWER s 75% RTP, the remaining three power range channels can be used for calculating QPTR. 2. SR 3.2.4.2 may be performed in lieu of this Surveillance.

Verify QPTR is within limit by calculation. I n accordance with the Surveillance Frequency Control Program SR 3.2.4.2 ---------------------------------

NOTE Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after input from one or more Power Range Neutron Flux channels are inoperable with THERMAL POWER > 75% RTP. Verify QPTR is within limit using power distribution measurement information.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.2-13 Amendment No. 202 3.3.1 RTS Instrumentation SURVEILLANCE REQUIREMENTS

NOTE Refer to Table 3.3.1-1 to determine which SRs apply for each RTS Function.

SURVEILLANCE FREQUENCY SR 3.3.1.1 Perform CHANNEL CHECK. I n accordance with the Surveillance Frequency Control Program SR 3.3.1.2 ---------------------------------

NOTE Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is 15% RTP. Compare results of calorimetric heat balance calculation to power range channel output. Adjust power range channel output if calorimetric heat balance calculation results exceed power range channel output by more than +2% RTP. In accordance with the Surveillance Frequency Control Program SR 3.3.1.3 ---------------------------------

NOTE Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is 50% RTP. Compare results of the incore power distribution measurements to Nuclear Instrumentation System (NIS) AFD. Adjust NIS channel if absolute difference is In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.3-12 Amendment No. 202 3.3.1 RTS Instrumentation SURVEILLANCE FREQUENCY SR 3.3.1.4 ---------------------------------

NOTE This Surveillance must be performed on the reactor trip bypass breaker for the local manual shunt trip only prior to placing the bypass breaker in service. Perform TADOT. In accordance with the Surveillance Frequency Control Program SR 3.3.1.5 Perform ACTUATION LOGIC TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.1.6 ---------------------------------

NOTE Not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after achieving equilibrium conditions with THERMAL POWER 75 % RTP. Calibrate excore channels to agree with incore power distribution measurements.

In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.3-13 Amendment No. 202 3.3.1 RTS Instrumentation SURVEILLANCE REQUIREMENTS continued)

SR 3.3.1.7 ---------------------------------

NOTE Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after entry into MODE 3. Source range instrumentation shall include verification that interlocks P-6 and P-10 are in their required state for existing unit conditions.

Perform COT.

In accordance with the Surveillance Frequency Control Program CALLAWAY 3.3-14 Amendment No. 202 3.3.1 RTS Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SR ---------------------------------

NOTE This Surveillance shall include verification that interlocks P-6 and P-10 are in their required state for existing unit conditions.

Perform COT.

NOTE Only required when not performed within the frequency specified in the Surveillance Frequency Control Program Prior to reactor startup 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reducing power below P-10 for power and intermediate instrumentation Four hours after reducing power below P-6 for source range instrumentation CALLAWAY 3.3-15 Amendment No. 202 3.3.1 RTS Instrumentation SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.8 (con tinued) In accordance with the Surveillance Frequency Control Program SR 3.3.1.9 ---------------------------------

NOTE Verification of setpoint is not required.

Perform TADOT. In accordance with the Surveillance Frequency Control Program SR 3.3.1.10 ---------------------------------

NOTE This Surveillance shall include verification that the time constants are adjusted to the prescribed values. Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program (contlnueo)

CALLAWAY PLANT 3.3-16 Amendment 202 3.3.1 RTS Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.11 ---------------------------------

NOTE

1. Neutron detectors are excluded from CHANNEL CALIBRATION.

2. This Surveillance shall include verification that the time constants are adjusted to the prescribed values. 3. Power and intermediate range detector plateau voltage verification is not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after achieving equilibrium conditions with THERMAL POWER 2 95% RTP. Perform CHANNEL CALIBRATION In accordance with the Surveillance Frequency Control Program SR 3.3.1.12 Not used. SR 3.3.1.13 Perform COT. In accordance with the Surveillance Frequency Control Program SR 3.3.1.14 ---------------------------------

NOTE Verification of setpoint is not required.

Perform TADOT. In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.3-17 Amendment No. 202 3.3.1 RTS Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE I I=REQUENCY SR 3.3.1.15 ---------------------------------

NOTE Verification of setpoint is not required.

Perform TADOT. Prior to exceeding the P 9 interlock whenever the unit has been in MODE 3, if not performed in the previous 31 days SR 3.3.1.16 ---------------------------------

NOTE Neutron detectors are excluded from response time testing. Verify RTS RESPONSE TIMES are within limits. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.3-18 Amendment No. 202 RTS Instrumentation 3.3.1 TABLE 3.3.1-1 (PAGE 1 OF 8) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 1. Manual Reactor Trip 1,2 3(b), 4(b), Sib) 2 2 B C SP 3 3.1 1t1 SF': 3.3.1 NA NA 2. Power Range Neutron Flux a. High 1,2 4 D SF< 11 SR 3.31 SR 3.3.1 '1 SR3.3.111 SR 3.3.1.16 S; 112.3% RTP b. Low 1 (c),2(f) 4 V SR 3.3.1.1 SR 3.3.1.8 SR 3.3.1 11 SR3.3.116 28.3% RTP 2(h),3(i) 4 Y,Z SR3.3.1.1 SR 331.8 SR 3.3.1! SR 33.1.1 :::;28.3%

RTP 3. Power Range Neutron Flux Rate -High Positive Rate 1,2 4 E SR :33.1.7 SR 3 3.1 1 SH 3.31.16 6.3 % RTP with time constant 2 sec 4. Intermediate Range Neutron Flux 1(e),2(d) 2 F, G SR 3 3.1.1 SR 3318 SF{ 3.31.11 :::; 35.3% RTP The Allowable Value defines the limiting safety system setting except for Trip Functions 14.a and 14.b (the Nominal Trip Setpoint defines the limiting safety system setting for these Trip Functions).

See the Bases for the Nominal Trip Setpoints. With Rod Control System capable of rod withdrawal or one or more rods not fully inserted. Below the P-l0 (Power Range Neutron Flux) interlock. Above the P-6 (Intermediate Range Neutron Flux) interlock. With kef! 1.0. With kef! < 1.0, and all RCS cold leg temperatures 500°F, and RCS boron concentration s; the ARO critical boron concentration, and Rod Control System capable of rod withdrawal or one or more rods not fully inserted. With all RCS cold leg temperatures?:

500°F, and RCS boron concentration s; the ARO critical boron concentration, and Rod Control System capable of rod withdrawal or one or more rods not fully inserted CALLAWAY 3,3-19 Amendment No. 202 I RTS Instrumentation 3.3.1 TABLE 3.3.1-1 (PAGE 2 OF 8) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 5. Source Range Neutron Flux 2(e) 2 I, J SR3.3.1.1 SR:'U.1.8 SR:U 1.11 1.6 E5 cps 3(b), 4(b), 5(b) 2 J, K SR 3.3.1.1 SR 7 3.3.1.11 1.6 E5 cps 6. Overtemperature ilT 1,2 4 E SR 3.31.1 SR SR 3.3.1.6 SR 3.317 SR 3.3.1.10 SRJ.3116 Refer to Note 1 (Page 3.3-23) 7. Overpower il T 1,2 4 E SR 3.1.1 3.3.1.7 SR 3.3.1.10 SR 3.3.1 16 Refer to Note 2 (Page 3.3-24) 8. Pressurizer Pressure a. Low 1(g) 4 M SR 3.:1.1.1 SR 3.3.1.7 SR 3.3.1.10 SR33.116 21874 psig b. High 1,2 4 E Sf'\ 331 1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.1G :> 2393 psig The Allowable Value defines the limiting safety system setting except for Trip Functions 14.a and 14.b (the Nominal Trip Setpoint defines the limiting safety system setting for these Trip Functions).

See the Bases for the Nominal Trip Setpoints. With Rod Control System capable of rod withdrawal or one or more rods not fully inserted. Below the P-6 (Intermediate Range Neutron Flux) interlock. Above the P-7 (Low Power Reactor Trips Block) interlock.

CALLAWAY 3.3-20 Amendment No. 202 I RTS Instrumentation 3.3.1 TABLE 3.3.1-1 (PAGE 3 OF 8) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 9. Pressurizer Water Level-High 3 M SR 3.3.1 1 SR3.3.1.7 SR 3.3.1.10 10. Reactor Coolant Flow -Low 3 per loop M SR 3.3.1.1 SR 3.3.17 SR SR 3.3.116 11. Not Used 12. Undervoltage RCPs 2/bus M SR 3.3.1.9 SR 3.3.1.10 SR 3.3.116 13. Underfrequency RCPs 2/bus M SR 3.3.1.9 SR 3.3.1 10 SR 3.3.1 16 14. Steam Generator (SG) Water Level Low-Low(l)

a. Steam Generator Water Level Low-Low (Adverse Containment Environment) 1,2 4 per SG E SR 3 3.1 1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16 s; 93.8% of instrument span 88.8% of indicated loop flow 10105 Vac 57.1 Hz 20.6% (q) of Narrow Range Instrument Span The Allowable Value defines the limiting safety system setting except for Trip Functions 14.a and 14.b (the Nominal Trip Setpoint defines the limiting safety system setting for these Trip Functions).

See the Bases for the Nominal Trip Setpoints. Above the P-7 (Low Power Reactor Trips Block) interlock. The applicable MODES for these channels in Table 3.3.2-1 are more restrictive. Not used. 1. If the as-found instrument channel setpoint is conservative with respect to the Allowable Value, but outside its as-found test acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

2. The instrument channel setpoint shall be reset to a value that is within the as-left setpoint tolerance band on either side of the Nominal Trip Setpoint, or to a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoints and the methodology used to determine the as-found test acceptance criteria band and the as-left setpoint tolerance band shall be specified in the Bases CALLAWAY 3.3-21 Amendment No. 202 I RTS Instrumentation 3.3.1 TABLE 3.3.1-1 (PAGE 4 OF 8) Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE(a) 14. Steam Generator (SG) Water Level Low-Low(l)

b. Steam Generator Water Level Low-Low (Normal Containment Environment) 4 per SG E SR3.3.1.1 SR 3.3.17 SR 3.3.1 10 SR 3.3.1 16 16.6% (q) of Narrow Range Instrument Span c. Not used. d. Containment Pressure Environmental Allowance Modifier 1,2 4 x SR:U.11 SR :U.1.7 SR 3.3.1.10 SR 3.3.1 1G 2.0 psig 15. Not Used The Allowable Value defines the limiting safety system setting except for Trip Functions 14.a and 14.b (the Nominal Trip Setpoint defines the limiting safety system setting for these Trip Functions).

See the Bases for the Nominal Trip Setpoints. The applicable MODES for these channels in Table 3.3.2-1 are more restrictive. Not used. Not used. Except when the Containment Pressure -Environmental Allowance Modifier channels in the same protection sets are tripped. 1. If the as-found instrument channel setpoint is conservative with respect to the Allowable Value, but outside its found test acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

2. The instrument channel setpoint shall be reset to a value that is within the as-left setpoint tolerance band on either side of the Nominal Trip Setpoint, or to a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoints and the methodology used to determine the as-found test acceptance criteria band and the as-left setpoint tolerance band shall be specified in the Bases CALLAWAY 3.3-22 Amendment No. 202 I RTS Instrumentation 3.3.1 TABLE 3.3.1-1 (PAGE 5 OF 8) Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE(a) 16. Turbine Trip a. Low Fluid Oil Pressure 3 o SR 3.:1.1.10 SR 33.1.15 539.42 psig b. Turbine Stop Valve Closure 4 P SR3.3.1.10 :331 15 1% open 17. Safety Injection (SI) Input from Engineered Safety Feature Actuation System (ESFAS) 1,2 2 trains Q SR 3.3.1 14 NA 18. Reactor Trip System Interlocks

a. Intermediate Range Neutron Flux, P-6 2 S SR 3.3.1.11 SR 3.3.113 6E-11 amp b. Low Power Reactor Trips Block, P-7 1 per train T SR 33.1.5 NA c. Power Range Neutron Flux, P-8 4 T SR 3.3.111 SR 3.3.1 13 ::;; 51,3% RTP d. Power Range Neutron Flux, P-9 4 T SR 3.3.1.11 SR:U.113 <:; 53,3% RTP The Allowable Value defines the limiting safety system setting except for Trip Functions 14.a and 14.b (the Nominal Trip Setpoint defines the limiting safety system setting for these Trip Functions).

See the Bases for the Nominal Trip Setpoints, (e) Below the P-6 (Intermediate Range Neutron Flux) interlock.

U) Above the P-9 (Power Range Neutron Flux) interlock.

CALLAWAY 3.3-23 Amendment No. 202 I RTS Instrumentation 3.3.1 TABLE 3.3.1-1 (PAGE 6 OF 8) Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE(a) 18. Reactor Trip System Interlocks

e. Power Range Neutron Flux, P-10 1,2 4 S SR:U.l.11 SH:U1.13 ? 6.7% RTP and 12.4% RTP f. Turbine Impulse Pressure, P-13 2 T SR :)3.1.10 SR 3.3.1.13 $12.4% turbine power 19. Reactor Trip Breakers (RTBs)(k) 1,2 3(b), 4(b), 5(b) 2 trains 2 trains R C SR 3.3.1.4 SR 331.4 NA NA 20. Reactor Trip Breaker Undervoltage and Shunt Trip Mechanisms(k) 1,2 3(b), 4(b), 5(b) 1 each per RTB 1 each per RTB U C SR :331.4 SR :J.3.1.4 NA NA 21. Automatic Trip Logic 1,2 3(b), 4(b), 5(b) 2 trains 2 trains Q C SR 3.3.15 SR 3.3.1.5 NA NA The Allowable Value defines the limiting safety system setting except for Trip Functions 14.a and 14.b (the Nominal Trip Setpoint defines the limiting safety system setting for these Trip Functions).

See the Bases for the Nominal Trip Setpoints. With Rod Control System capable of rod withdrawal or one or more rods not fully inserted. Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB. CALLAWAY 3.3-24 Amendment No. 202 I 3.3.1 RTS Instrumentation TABLE 3.3.1-1 (page 7 Reactor Trip System Note 1: Overtemperature T The Overtemperature T Function Allowable Value shall not exceed the following setpoint by more than 1.23% of T span (1.85% RTP). flT(1+'1 S )( 1 1 rJ+K 3 (p-P') f 1 (fll)}(1 + '2S) 1 + (1 + '5S) 1 + '6S T is measured RCS T, of. To is the indicated t.T at RTP, of. s is the Laplace transform operator, sec*1. T is the measured RCS average temperature, T' is the nominal Tavg at RTP, $ P is the measured pressurizer pressure, P' is the nominal RCS operating pressure =0 K1 =0 K2 = K3 */psig '1

sec '2 $ 0 '3

sec 0'4

sec '5 $ '6

sec * {*% + (q! -when qt -qb <: * %RTP 0% when' %RTP $ ql qb $ * %RTP * {(qt -qb)-when q! -qb > * %RTP where qt and qb are percent RTP in the upper and lower halves of the core, respectively, and ql + qb is the total THERMAL POWER in percent RTP. The values denoted with' are specified in the COLR. CALLAWAY PLANT Amendment 202 I 3.3.1 RTS Instrumentation TABLE 3.3.1-1 (page 8 of Reactor Trip System Note 2: Overpower t,T The Overpower t, T Function Allowable Value shall not exceed the following setpoint by more than 1.21 % of t, T span (1.82% RTP). Where: t, T is measured RCS t, T, oF. t, To is the indicated t, T at RTP, oF. s is the Laplace transform operator, sec*1 . T is the measured RCS average temperature,°F.

T" is the nominal Tavg at RTP, S 'oF. Ks =',OF for increasing Tavg K6 =',OF when T> T" ',OF for decreasing Tavg ',OF when T s T" '1 ;:>: , sec '2 s' sec '3 =' sec '6 =' sec '7;:>: , sec The values denoted with' are specified in the COLR. CALLAWAY PLANT 3.3-26 Amendment 202 I ESFAS Instrumentation 3.3.2 3.3 INSTRUMENTATION 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation LCO The ESFAS instrumentation for each Function in Table 3.3.2-1 shall be OPERABLE.

According to Table 3.3.2-1. ACTIONS -----------------------------------------------------------

NOTE Separate Condition entry is allowed for each Function.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions with one or more required channels or trains inoperable.

A.1 Enter the Condition referenced in Table 3.3.2-1 for the channel(s) or train(s).

Immediately B. One channel or train inoperable.

B.1 Restore channel or train to OPERABLE status. OR B.2.1 Be in MODE 3. 81:iD. B.2.2 Be in MODE 5. 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months 54 hours 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months (continued)

CALLAWAY 3.3-27 Amendment No. 202 I 3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One train inoperable.

NOTE One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

C.1 ------------

NOTE AND C.2 OR C.3.1 AND C.3.2 Only required if Function 3.a.(2) is inoperable.

Place and maintain containment purge supply and exhaust valves in closed position.

Restore train to OPERABLE status. Be in MODE 3. Be in MODE 5. Immediately 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 30 hours 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months l continued}

CALLAWAY PLANT 3.3-28 Amendment No. 202 I 3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One channel inoperable.

NOTE The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

... _-............

_-_... _...... _...... _-------...--....--_... __.. D.1 Place channel in trip. OR 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months D.2.1 Be in MODE 3. AND 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months D.2.2 Be in MODE 4. 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months E. One Containment Pressure -------------------

NOTE channel inoperable.

One additional channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing. -----------------------------------------------_

.. E.1 Place channel in bypass. OR 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months E.2.1 Be in MODE 3. AND 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months E.2.2 Be in MODE 4. 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months ( contln u ed ) CALLAWAY PLANT 3.3-29 Amendment No. 202 I 3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME F. One channel or train inoperable.

F.1 Restore channel or train to OPERABLE status. QB 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months F.2.1 Be in MODE 3. AND 54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months F.2.2 Be in MODE 4. 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months G One train inoperable.

NOTE One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

_

.. G.1 Restore train to OPERABLE status. OR 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months G.2.1 Be in MODE 3. AND 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months G.2.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months H. One or more trains inoperable.

NOTE One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

......-------------------------------------_

...... __... __...... H.1 Declare associated Pressurizer PORV(s) inoperable.

Immediately (contlnueo)

CALLAWAY PLANT Amendment No. 202 I 3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME I. One channel inoperable.

NOTE The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

_

... _---..........

_... 1.1 Place channel in trip. OR 1.2 Be in MODE 3. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 78 hours J. One channel inoperable.

NOTE The inoperable channel may be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of other channels.

J.1 Place channel in trip. OR J.2 Be in MODE 3. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 30 hours (ContinUed)

CALLAWAY PLANT 3.3-31 Amendment No. 202 I 3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME K. One channel inoperable.

NOTE An inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

K.1 Restore channel to OPERABLE status. OR K.2.1 Be in MODE 3. AND K.2.2 Be in MODE 5. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 78 hours 108 hours0.00125 days 0.03 hours 1.785714e-4 weeks 4.1094e-5 months L. One or more required channel{s) inoperable.

L.1 Verify interlock is in required state for existing unit condition.

OR 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months L.2.1 Be in MODE 3. AND 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months L.2.2 Be in MODE 4. 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months (continued)

CALLAWAY PLANT 3.3-32 Amendment No. 202 I 3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME M. Two channels inoperable.

AND M.1 OR Place channels in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months AFW actuation on Trip of all Main Feedwater Pumps maintained from one actuation train. M.2 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months N. One or more Containment Pressure -Environmental Allowance Modifier channel(s) inoperable.

N.1 OR Place channel(s) in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months N.2.1 AND Be in MODE 3. 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months N.2.2 Be in MODE 4. 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months O. One channel inoperable.

0.1 AND 0.2 Place channel in trip. Restore channel to OPERABLE status. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months During performance of the next required COT (continUed)

CALLAWAY PLANT 3.3-33 Amendment No. 202 I 3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME P. One or more channel(s) inoperable.

P.1 Declare associated auxiliary feedwater pump(s) inoperable.

AND P.2 Declare associated steam generator blowdown and sample line isolation valve(s) inoperable.

Immediately Immediately Q One train inoperable.

NOTE One train may be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing provided the other train is OPERABLE.

Q.1 Restore train to OPERABLE status. OR 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Q.2.1 Be in MODE 3. AND 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months Q.2.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

CALLAWAY PLANT 3.3-34 Amendment No. 202 I 3.3.2 ESFAS Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME R. One or both train(s) inoperable.

R.1 Restore train(s) to OPERABLE status. OR 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months R.2.1 Be in MODE 3. AND 54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months R.2.2 Be in MODE 4. 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months S. One train inoperable

NOTE One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

S.1 Restore train to OPERABLE status. OR 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months S.2.1 Be in MODE 3. AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months S.2.2 Be in MODE 4. 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months CALLAWAY PLANT 3.3-35 Amendment No. 202 I 3.3.2 ESFAS Instrumentation SURVEILLANCE REQUIREMENTS

NOT E Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.2.2 Perform ACTUATION LOGIC TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.2.3 ---------------------------------

NOTE The continuity check may be excluded from the BOP ESFAS test.

Perform ACTUATION LOGIC TEST. I n accordance with the Surveillance Frequency Control Program SR 3.3.2.4 Perform MASTER RELAY TEST. In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.3-36 Amendment No. 202 3.3.2 ESFAS Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.5 Perform COT. In accordance with the Surveillance Frequency Control Program SR 3.3.2.6 ---------------------------------

NOT E Not applicable to slave relays K602, K620, K622, K624, K630, K740, K741 , and K750. Perform SLAVE RELAY TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.2.7 ---------------------------------

NOTE Verification of relay setpoints not required.

Perform TADOT. In accordance with the Surveillance Frequency Control Program SR 3.3.2.8 ---------------------------------

NOTE Verification of setpoint not required for manual initiation functions.

Perform TADOT. In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.3-37 Amendment No. 202 3.3.2 ESFAS Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SU RVEI LLANCE FREQUENCY SR 3.3.2.9 ---------------------------------

NOT E This Surveillance shall include verification that the time constants are adjusted to the prescribed values. Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.2.10 ---------------------------------

NOTE Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after SG pressure is 900 psig. Verify ESF RESPONSE TIMES are within limits. In accordance with the Surveillance Frequency Control Program SR 3.3.2.11 ---------------------------------

NOTE Verification of setpoint not required.

Perform TADOT. In accordance with the Surveillance Frequency Control Program SR 3.3.2.12 Perform COT. In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.3-38 Amendment No. 202 3.3.2 ESFAS Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.13 ---------------------------------

NOTE Only applicable to slave relays K602, K622, K624 , K630, K740, and K741. Perform SLAVE RELAY TEST. In accordance with the Surveillance Frequency Control Program Prior to entering MODE 4 when in MODE 5 or 6 > 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , if not performed within the previous 92 days SR 3.3.2.14 ---------------------------------

NOTE Only applicable to slave relays K620 and K750. Perform SLAVE RELAY TEST. In accordance with the Surveillance Frequency Control Program Prior to entering MODE 3 when in MODE 5 or 6 > 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , if not performed within the previous 92 days CALLAWAY PLANT 3.3-39 Amendment No. 202 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 1 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 1. Safety Injection a, Manual Initiation 1,2,3,4 2 B SR 3,3.2 8 NA b. Automatic Actuation Logic and Actuation Relays (SSPS) 1,2,3,4 2 trains C SR 3.3,2.2 3.3,2.4 SR 3.3,2,(i SR 3,3,2,1] NA c. Containment Pressure High 1 1,2,3 3 D SR :\3,2.1 SR SR :\.32.9 SR 33.2.10 4,5 psig d, Pressu rizer Pressure Low 1,2,3(b) 4 D SR 3321 SR 3.3.2,5 SR 3,3.2,9 SR 3.3,2,10 2: 1834 psig e, Steam Line Pressure Low 1,2,3(b) 3 per steam line D SR 3,32.1 SR 3.3.2.5 SR 3.3.2,9 SR 3.3,2,10 2: 610 pSig(C)(S)

2. Containment Spray a. Manual Initiation 1,2,3,4 2 per train, 2 trains B SR 3,3,2 8 NA b. Automatic Actuation Logic and Actuation Relays (SSPS) 1,2,3,4 2 trains C SR 3,3,2 2 SR :U,2.4 SR 3.3.2.0 NA The Allowable Value defines the limiting safety system setting except for Functions 1 ,e, 4,e,(1), 5,c, 5,e,(1), 5.e.(2), 6.d.(1), and 6.d,(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints, Above the P-11 (Pressurizer Pressure) interlock and below P-11 unless the Function is blocked. Time constants used in the lead/lag controller are '1 2: 50 seconds and '2 s 5 seconds. 1. If the as-found instrument channel setpoint is conservative with respect to the Allowable Value, but outside its as-found test acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

2. The instrument channel setpoint shall be reset to a value that is within the as-left setpoint tolerance band on either side of the Nominal Trip Setpoint, or to a value that is more conservative than the Nominal Trip Set point; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoints and the methodology used to determine the as-found test acceptance criteria band and the as-left setpoint tolerance band shall be specified in the Bases. CALLAWAY 3.3-40 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 2 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) Containment Spray Containment 1.2.3 4 E SR :>3.2.1 s 28.3 psig Pressure SR 3,3.2.5 High -3 SR 3.3.2,9 SR 3.3,2,10 Containment Isolation Phase Manual 1.2.3,4 2 B SR 3,3.2.8 NA Initiation (2) 1.2.3,4 2 trains C SR 3.3,2.2 NA Actuation SR 3.3.2.4 Logic and SR 3 3.2.6 Actuation SR 3.3.2.13 Relays (SSPS) (3) Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Injection Phase (1) 1,2,3,4 2 per train, B SR 3,3.2 8 NA Initiation 2 trains (2) 1,2,3,4 2 trains C SR 3,3,2.2 NA Actuation SR 3,3,24 Logic and SR 3,3,2.6 Actuation Relays (SSPS) (3) 1,2,3 4 E SR 3.3.2.1 s 28.3 psig ment SR 3.3.2.5 Pressure SR 3.3.2.9 High -3 SR3.32.10 The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(1). 5.c, 5.e.(1), 5.e,(2}, 6,d,(1). and 6.d,(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints.

CALLAWAY 3.3-41 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 3 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 4. Steam Line Isolation

a. Manual Initiation 1,2(i)(k), 3(i)(k) 2 F SR :U.2.R NA b. Automatic Actuation Logic and Actuation Relays (SSPS) 1,2(i)(k), 3(i)(k) 2 trains G SR 3.3.2.2 SF{ 3.:3.2 4 SF< :U.2.6 NA c. Automatic Actuation Logic and Actuation Relays (MSFIS) 1, 2(k),3(k) 2 trains(o)

S SR :U23 NA d. Containment Pressure -High 2 1,2(i)(k), 3(i)(k) 3 D SR SR 3.3.2.5 SR 3.3.2.D SR 3 ;3210 18.3 psig The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(1), 5.c, 5.e.(1), 5.e.(2). 6.d.(1), and 6.d.(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints. Except when: 1. All MSIVBVs are: 1.a Closed and de-activated, or 1.b Closed and isolated by a closed manual valve, or 1.c Isolated by two closed manual 2. All MSLPDIVs are: 2.a Closed and de-activated, or 2.b Closed and isolated by a closed manual valve, or 2.c Isolated by two closed manual valves. Except when all MSIVs are closed and de-activated. Each train requires a minimum of two programmable logic controllers to be OPERABLE.

CALLAWAY 3.3-42 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 4 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 4. Steam Une Isolation

e. Steam Une Pressure (1) Low (2) Negative Rate -High 1,2 (i)(k), 3(b)(i)(k) 3(g)(i)(k) 3 per steam line 3 per steam line D SR:3 321 SR 33.25 SR 33.29 SR 332.10 D SR 3.321 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 610 pSig(C)(S) 5124 psi(h) The Allowable Value defines the limiting safety system setting except for Functions 1 ,e, 4.e.(1), 5.c, 5.e.(1), 5.e.(2), 6.d,(1), and 6.d.(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints. Above the P-11 (Pressurizer Pressure)

Interlock and below P-11 unless the Function is blocked. Time constants used in the leadllag controller are '1 50 seconds and '2 5 seconds. Below the P-11 (Pressurizer Pressure)

Interlock; however, may be blocked below P-11 when safety injection on low steam line pressure is not blocked. Time constant utilized in the ratellag controller is 50 seconds. Except when: 1. All MSIVBVs are: 1.a Closed and de-activated, or 1.b Closed and isolated by a closed manual valve, or 1,c Isolated by two closed manual 2. All MSLPDIVs are: 2.a Closed and de-activated, or 2.b Closed and isolated by a closed manual valve, or 2.c Isolated by two closed manual valves. Except when all MSIVs are closed and de-activated. 1. If the as-found instrument channel setpoint is conservative with respect to the Allowable Value, but outside its as-found test acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

2. The instrument channel setpoint shall be reset to a value that is within the as-left setpoint tolerance band on either side of the Nominal Trip Setpoint, or to a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoints and the methodology used to determine the as-found test acceptance criteria band and the as-left setpoint tolerance band shall be specified in the Bases. CALLAWAY 3.3-43 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 5 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 5. Turbine Trip and Feedwater Isolation

a. Automatic Actuation Logic and Actuation Relays (SSPS) (j) (j) (j)1 ,2 ,3 2 trains G SR :)32 2 SR :13.2.4 SR :U.2,6 SR 3.3.2.14 NA b. Automatic Actuation Logic and Actuation Relays (MSFIS) 2 trains(O)

S SR 3.3.2.3 NA c, SG Water Level High High (P-14) 4 per SG SR 3.3.2.1 SR 3.3.2,5 SR 3,3.2,9 SR 3.32.10 :; 91.4%(s) of Narrow Range Instrument Span d. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Applicability exceptions of Footnote (j) also apply to Function 5.d. The The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(I), 5.c, 5.e.(1). 5.e.(2), 6.d.(I), and 6.d.(2} (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints.

Except 1 All MFIVs are closed and 2. All MFRVs are: 2.a Closed and de-activated, or 2.b Closed and isolated by a closed manual 3. All MFRVBVs are: 3.a Closed and de-activated, or 3.b Closed and isolated by a closed manual valve. or 3.c Isolated by two closed manual valves. Except when all MFIVs are closed and de-activated. Each train requires a minimum of two programmable logic controllers to be OPERABLE. 1. If the as-found instrument channel setpoint is conservative with respect to the Allowable Value, but outside its as-found test acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

2. The instrument channel setpoint shall be reset to a value that is within the as-left setpoint tolerance band on either side of the Nominal Trip Setpoint, or to a value that is more conservative than the Nominal Trip Setpoint; otherwise.

the channel shall be declared inoperable.

The Nominal Trip Setpoints and the methodology used to determine the as-found test acceptance criteria band and the as-left setpoint tolerance band shall be specified in the Bases. CALLAWAY 3.3-44 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 6 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 5. Turbine Trip and Feedwater Isolation

e. Steam Generator Water Level Low-Low(q)

(1) Steam Generator Water Level Low-Low (Adverse Containment Environment) 1 m, 2m, 3m 4 per SG D SR:U.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 Z 20.6%(5) of Narrow Range Instrument Span (2) Steam Generator Water Level Low-Low (Normal Containment Environment) 1 m(r), 2(j)(r), 3(j)(r) 4 per SG D SR 3.3.2.1 SR :33.2.5 SR 3.3.2.9 SR 3.3.2.10 z 16.6%(5) of Narrow Range Instrument Span The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(1}, 5.c, 5.e.(1}, 5.e.(2}, 6.d.(1}, and 6.d.(2} (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints. Except when: 1. All MFIVs are closed and 2. All MFRVs are: 2.a Closed and de-activated, or 2.b Closed and isolated by a closed manual 3. All MFRVBVs are: 3.a Closed and de-activated, or 3.b Closed and isolated by a closed manual valve, or 3.c Isolated by two closed manual valves. Feedwater isolation only. Except when the Containment Pressure -Environmental Allowance Modifier channels in the same protection sets are tripped. 1. If the as-found instrument channel setpoint is conservative with respect to the Allowable Value, but outside its as-found test acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

2. The instrument channel setpoint shall be reset to a value that is within the as-left setpoint tolerance band on either side of the Nominal Trip Setpoint, or to a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoints and the methodology used to determine the as-found test acceptance criteria band and the as-left setpoint tolerance band shall be specified in the Bases. CALLAWAY 3.3-45 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 7 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 5. Turbine Trip and Feedwater Isolation

e. Steam Generator Water Level Low-Low(q)

(3) Not used. (4) Containment Pressure Environmental Allowance Modifier 1m, 2m, 3m 4 N SR 3 3.2.1 :33.2.5 SR:3 3.2.9 SR :U.2.10 s 2.0 psig The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(1), 5.c, 5.e.( 1), 5.e.(2), 6.d.( 1), and 6.d.(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints. Except when: 1. All MFIVs are closed and 2. All MFRVs are: 2.a Closed and de-activated, or 2.b Closed and isolated by a closed manual 3. All MFRVBVs are: 3.a Closed and de-activated, or 3.b Closed and isolated by a closed manual valve, or 3.c Isolated by two closed manual valves. Feedwater isolation only. CALLAWAY 3.3-46 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 8 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 6. Auxiliary Feedwater

a. Manual Initiation 1,2,3 1/pump P SR 3.32.8 NA b. Automatic Actuation Logic and Actuation Relays (SSPS) 1,2,3 2 trains G SR 3.3.22 SR 3.3.2.4 SR 3.3.2.6 NA c. Automatic Actuation Logic and Actuation Relays (BOP ESFAS) 1,2,3 2 trains Q SR 3323 NA d. SG Water Level Low-Low (1) Steam Generator Water Level Low-Low (Adverse Containment Environment) 1,2,3 4 perSG D SR :U.2 1 SR 3:)25 SR 3.3.2.9 SR 3.3.2.10 20.6%(s) of Narrow Range Instrument Span (2) Steam Generator Water Level Low-Low (Normal Containment Environment) 4 per SG D SR 3:; 21 SR:U;)5 SR 3.32.9 SR 3.3.2.10 16.6%(5) of Narrow Range Instrument Span The Allowable Value defines the limiting safety system setting except for Functions 1 .e, 4.e.(1), 5.c, 5.e.(1), 5.e.(2), 6.d.(1), and 6.d.(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints. Except when the Containment Pressure -Environmental Allowance Modifier channels in the same protection sets are tripped. 1. Ifthe as-found instrument channel setpoint is conservative with respect to the Allowable Value, but outside its as-found test acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

2. The instrument channel setpoint shall be reset to a value that is within the as-left setpOint tolerance band on either side of the Nominal Trip Setpoint, or to a value that is more conservative than the Nominal Trip Setpoint; otherwise, the channel shall be declared inoperable.

The Nominal Trip Setpoints and the methodology used to determine the as-found test acceptance criteria band and the as-left setpoint tolerance band shall be specified in the Bases. CALLAWAY 3.3-47 Amendment No. 202 ,

3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page90f11)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VAlUE(a) Auxiliary Feedwater SG Water (3) Not used. (4) 1,2,3 4 N SR 3.3.2.1 <; 2.0 psig Pressure -SR 3.3.2.5 Environmental SF'< 3.3.2.9 Allowance SR 3.3.2.10 Modifier Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements. Loss of Offsite 1,2,3 2 trains R SR 3.3.2.7 NA Power SR 3.3.2.10 Trip of all Main 1 (v),2(n),(v) 4(u),(w) J,M SR 3.3.2.8 NA Feedwater Pumps Auxiliary 1,2,3 3 0 SR 3.3.2.1 2! 20.64 psia Feedwater Pump SR 3:329 Suction Transfer SR 3.:32.10 on Suction SR 3.3.2.12 Pressure -low The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(1), 5.c, 5.e.(1), 5.e.(2), 6.d.(1), and 6.d.(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints. Trip function may be blocked just before shutdown of the last operating main feedwater pump and restored just after the first main feedwater pump is put into service following performance of its startup trip test. During startup of the second main feedwater pump, the following exception applies: The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels are in the tripped condition on the second main feedwater pump. During removal of the first of two operating main feedwater pumps from service, the following exception applies: (1) LCO 3.0.3 is not applicable for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for the channels associated with the first main feedwater pump, OR The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels on the main feedwater pump to be removed from service are in the tripped condition. During removal of the first of two operating main feedwater pumps from service, the following exception applies: The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels on the main feedwater pump to be removed from service are in the tripped condition.

CALLAWAY 3.3-48 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 10 of 11) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(aJ Automatic Switch over to Containment Sump Automatic 1,2,3,4 2 trains C SR 33.2.2 NA Actuation Logic SR :U2A and Actuation SR 3.3.213 Relays (SSPS) Refueling Water 1,2,3,4 4 K Sf" 3.3.2.1 235.2% Storage Tank SR 3.3.25 (RWST) Level SH 3 329 Low Low SR 3.321 Coincident with Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Safety Injection ESFAS Interlocks Reactor Trip. P-4 1,2,3 2 per train, F SR 3.3.2.11 NA 2 trains Pressurizer 1,2,3 3 L 3.32.5 1981 psig Pressure, P-11 3.3.2.9 Automatic Pressurizer PORV Actuation Automatic 1,2,3 2 trains H SR 3.3.2.2 NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.14 Relays (SSPS) Pressurizer 1,2,3 4 D SR 3.3.2.1 ,.;2350 psig Pressure -High SR 33.2.5 3.3.2.9 The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(1), 5.c, 5.e.(1), 5.e.(2), 6.d.(1), and 6.d.(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints.

CALLAWAY 3.3-49 Amendment No. 202 I 3.3.2 ESFAS Instrumentation Table 3.3.2-1 (page 11 of 11 ) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a) 10. Steam Generator Blowdown and Sample Line Isolation

a. Manual Initiation 1(1), 2(t), 3(1) 2 trains (1 per MDAFW pump) P SR :U,2,a NA b. Automatic Actuation Logic and Actuation 1(1),2(1),3(1) 2 trains Q SR 3.3.2.3 NA Relays (BOP ESFAS) c. Safety Injection 1(1),2(1),3(1)

Refer to Function 1 (Safety Injection) for initiation functions and requirements.

d. Loss of Offsite Power 1(1),2(1),3(t) 2 trains R SR :U.2,7 NA The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(1), 5.c, 5.e.(1), 5.e.(2), 6,d,(1), and 6.d.(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions).

See the Bases for the Nominal Trip Setpoints. Except when all Steam Generator Slowdown and Sample Line Isolation Valves are: 1, Closed and de-activated, or 2. Closed and isolated by a closed manual valve, or 3. Isolated by a combination of closed manual valve{s) and closed de-activated automatic valve(s).

CALLAWAY 3.3-50 Amendment No. 202 I PAM Instrumentation 3.3.3 3.3 INSTRUMENTATION 3.3.3 Post Accident Monitoring (PAM) Instrumentation LCO The PAM instrumentation for each Function in Table 3.3.3-1 shall be OPERABLE.

MODES 1, 2 and 3. ACTIONS -----------------------------------------------------------

NOTE Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions with one required channel inoperable.

A.1 Restore required channel to OPERABLE status. 30 days B. Required Action and associated Completion Time of Condition A not met. B.1 Initiate action in accordance with Specification 5.6.8. Immediately (continued)

CALLAWAY 3.3-51 Amendment No. 202 I 3.3.3 PAM Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One or more Functions with two or more required channels inoperable.

C.1 Restore all but one channel to OPERABLE status. 7 days D. Required Action and associated Completion Time of Condition C not met. D.1 Enter the Condition referenced in Table 3.3.3-1 for the channel. Immediately E. As required by Required Action D.1 and referenced in Table 3.3.3-1. E.1 AND E.2 Be in MODE 3. Be in MODE 4. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours F. As required by Required Action D.1 and referenced in Table 3.3.3-1. F.1 Initiate action in accordance with Specification 5.6.S. Immediately CALLAWAY PLANT 3.3-52 Amendment No. 202 ,

3.3.3 PAM Instrumentation SURVEILLANCE REQUIREMENTS

NOT E SR 3.3.3.1 and SR 3.3.3.2 apply to each PAM instrumentation Function in Table 3.3.3-1. SURVEILLANCE FREQUENCY SR 3.3.3.1 Perform CHANNEL CHECK. I n accordance with the Surveillance Frequency Control Program SR 3.3.3.2 ---------------------------------

NOT E Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.3-53 Amendment No. 202 PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 1 of 2) Post Accident Monitoring Instrumentation CONDITION REFERENCED FROM REQUIRED REQUIRED FUNCTION CHANNELS ACTION D.1 Neutron Flux Reactor Coolant System (RCS) Hot Leg Temperature (Wide Range) RCS Cold Leg Temperature (Wide Range) RCS Pressure (Wide Range) Reactor Vessel Level Indicating System (RVLlS) Containment Normal Sump Water Level Containment Pressure (Normal Range) Steam Line Pressure Containment Radiation Level (High Range) Not Used Pressurizer Water Level Steam Generator Water Level (Wide Range) Steam Generator Water Level (Narrow Range) 2 E 2 E 2 E 2 E 2 F 2 E 2 E 2 per steam E generator 2 F 2 E 4 E 2 per steam E generator ( continued)

CALLAWAY 3.3-54 Amendment No. 202 I PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 2 of 2) Post Accident Monitoring Instrumentation CONDITION REFERENCED FROM REQUIRED REQUIRED FUNCTION CHANNELS ACTION D.1 14. Core Exit Temperature -

Quadrant 1 15. Core Exit Temperature -

Quadrant 2 16. Core Exit Temperature -

Quadrant 3 17. Core Exit Temperature -

Quadrant 4 18. Auxiliary Feedwater Flow Rate 19. Refueling Water Storage Tank Level 2(a) E 2(a) E 2(a) E 2(a) E 4 E 2 E (a) A channel consists of two core exit thermocouples (CETs). CALLAWAY PLANT 3.3-55 Amendment No. 202 I Remote Shutdown System 3.3.4 3.3 INSTRUMENTATION 3.3.4 Remote Shutdown System LCO The Remote Shutdown System Functions in Table 3,3.4-1 and the required auxiliary shutdown panel (ASP) controls shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and -----------------------------------------------------------

NOTE Separate Condition entry is allowed for each Function and required ASP CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required Functions inoperable.

One or more required ASP controls inoperable.

A.1 Restore required Function and required ASP controls to OPERABLE status. 30 days B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE4. , 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours CALLAWAY 3.3-56 Amendment No. 202 I 3.3.4 Remote Shutdown System SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.4.1 Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.2 ---------------------------------

NOTE Only required to be performed in MODES 1 and 2 for the turbine-driven AFW pump. Verify each required auxiliary shutdown panel control circuit and transfer switch is capable of performing the intended function.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.3 ---------------------------------

NOTE

1. Neutron detectors are excluded from CHANNEL CALIBRATION.

2. Reactor trip breaker and RCP breaker position indications are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION for each required instrumentation channel. In accordance with the i Surveillance Frequency Control Program ' CALLAWAY PLANT 3.3-57 Amendment No. 202 Remote Shutdown System 3.3.4 Table 3.3.4-1 (page 1 of 1) Remote Shutdown System Functions

1. Source Range Neutron Flux(a) 2. Reactor Trip Breaker Position 3. Pressurizer Pressure 4. RCS Wide Range Pressure 5. RCS Hot Leg Temperature

6. RCS Cold Leg Temperature

7. SG Pressure 8. SG Level 9. AFW Flow Rate 10. RCP Breaker Position 11. AFW Suction Pressure 12. Pressurizer Level 1 1 per trip 1 per 1 per 1 per (a) Not required OPERABLE in MODE 1 or in MODE 2 above the P-6 setpoint.

CALLAWAY PLANT 3.3-58 Amendment No. 202 I 3.3.5 LOP DG Start Instrumentation 3.3 INSTRUMENTATION 3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation LCO Four channels per 4.16-kV NB bus of the loss of voltage Function and four channels per 4.16-kV NB bus of the degraded voltage Function shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4, When associated DG is required to be OPERABLE by LCO 3.8.2, "AC Sources -Shutdown." ACTIONS -----------------------------------------------------------

NOTE Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions with one channel per bus inoperable.

A.1 ------------

NOTE The inoperable channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing of other channels.

_

...---------_

...

Place channel in trip. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months B. One or more Functions with two or more channels per bus inoperable.

QB Required Action and associated Completion Time of Condition A not met. B.1 Declare associated load shedder and emergency load sequencer (LSELS) inoperable.

Immediately CALLAWAY 3.3-59 Amendment No. 202 I 3.3.5 LOP DG Start Instrumentation SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.5.1 Tie breakers between 480 Vac buses NG01 and NG03 and between 480 Vac buses NG02 and NG04 shall be verified open. In accordance with the Surveillance Frequency Control Program SR 3.3.5.2 ---------------------------------

NOTE Verification of time delays is not required.

Perform TADOT. In accordance with the Surveillance Frequency Control Program SR 3.3.5.3 Perform CHANNEL CALIBRATION with nominal Trip Setpoint and Allowable Value as follows: a. Loss of voltage Allowable Value 83 +0, -8.3V (120V Bus) with a time delay of 1.0 + 0.2, -0.5 sec. Loss of voltage nominal Trip Setpoint 83V ( 120V Bus) with a time delay of 1.0 sec. In accordance with the Surveillance Frequency Control Program b. Degraded voltage Allowable Value 107.47 +/- 0.38V (120V Bus) with a time delay of 119 +/- 11.6 sec. Degraded voltage nominal Trip Setpoint 107.47V (120V Bus) with a time delay of 119 sec. SR 3.3.5.4 Verify LOP DG Start ESF RESPONSE TIMES are within limits. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.3-60 Amendment No. 202 Containment Purge Isolation Instrumentation 3.3.6 3.3 INSTRUMENTATION 3.3.6 Containment Purge Isolation Instrumentation 3.3.6 The Containment Purge Isolation instrumentation for each Function in Table 3.3,6-1 shall be OPERABLE.

According to Table 3.3.6-1. ACTIONS -----------------------------------------------------------

NOT E ------------------------------------------------------Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One radiation monitoring channel inoperable.

A.1 Restore the affected channel to OPERABLE status. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months (continued)

CALLAWAY 3.3-61 Amendment No. 202 I 3.3.6 Containment Purge Isolation Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. -------------

NOTE Only applicable in MODE 1, 2,3,or4. One or more F unctions with one or more manual channels or automatic actuation trains inoperable.

B.1 Place and maintain containment purge supply and exhaust valves in closed position.

Immediately Both radiation monitoring channels inoperable.

Required Action and associated Completion Time of Condition A not met. (cOntinUed)

CALLAWAY PLANT 3.3-62 Amendment No. 202 I 3.3.6 Containment Purge Isolation Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. -------------

NOTE C.1 Place and maintain Immediately Only applicable during containment purge CORE ALTERATIONS or supply and exhaust movement of irradiated fuel valves in closed position.

assemblies within containment.

OR C.2 Enter applicable Immediately One or more manual Conditions and Required channels inoperable.

Actions of LCO 3.9.4, "Containment Penetrations," for containment purge supply and exhaust valves made inoperable by isolation instrumentation.

CALLAWAY PLANT 3.3-63 Amendment No. 202 I 3.3.6 Containment Purge Isolation Instrumentation SURVEILLANCE REQUIREMENTS

NOTE Refer to Table 3.3.6-1 to determine which SRs apply for each Containment Purge Isolation Function.

SURVEILLANCE SR 3.3.6.1 Perform CHANNEL CHECK. I n accordance

with the Surveillance Frequency Control Program SR 3.3.6.2 ---------------------------------

NOT E The continuity check may be excluded.

Perform ACTUATION LOGIC TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.6.3 Perform COT. I n accordance with the Surveillance Frequency Control Program SR 3.3.6.4 ---------------------------------

NOTE Verification of setpoint is not required.

Perform TADOT. In accordance

with the

Surveillance Frequency Control Program CALLAWAY PLANT 3.3-64 Amendment No. 202 3.3.6 Containment Purge Isolation Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.6.5 Perform CHANNEL CALIBRATION. I n accordance with the Surveillance Frequency Control Program SR 3.3.6.6 Verify Containment Purge Isolation ESF RESPONSE TIMES are within limits. I n accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.3-65 Amendment No. 202 3.3.6 Containment Purge Isolation Instrumentation TABLE 3.3.6-1 (PAGE 1 OF 1) Containment Purge Isolation Instrumentation FUNCTION Manual Initiation Automatic Actuation Logic and Actuation Relays (BOP ESFAS) Containment Purge Exhaust Radiation Gaseous Containment Isolation Phase A APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE NOMINAL CONDITIONS CHANNELS REQUIREMENTS TRIP SETPOINT 1,2,3,4, 2 SR 3.3.6.4 NA (a). (b) 1,2.3,4 2 SR 3.36.2 NA SR 3.3.66 1,2,3,4 SR 3.3.6.1 (c) SR 3.3.6.3 SR 3.3.6.5 Refer to LCO 3.3.2, "ESFAS Instrumentation," Function 3.a, for all initiation functions and requirements. During CORE ALTERATIONS. During movement of irradiated fuel assemblies within containment. Set to ensure ODCM limits are not exceeded.

CALLAWAY 3,3-66 Amendment No. 202 I CREVS Actuation Instrumentation 3.3.7 3.3 INSTRUMENTATION 3.3.7 Control Room Emergency Ventilation System (CREVS) Actuation Instrumentation LCO The CREVS actuation instrumentation for each Function in Table 33.7-1 shall be OPERABLE.

APPLICABILITY:

According to Table -----------------------------------------------------------

NOTE Separate Condition entry is allowed for each CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions with one channel or train inoperable.

A.1 Place one CREVS train in Control Room Ventilation Isolation Signal (CRVIS) mode. 7 days (Continued)

CALLAWAY 3.3-67 Amendment No. 202 I 3.3.7 CREVS Actuation Instrumentation ACTIONS (continued) -------------

NOTE Not applicable to Function 3. One or more Functions with two channels or two trains inoperable.

B.1.1 AND B.1.2 OR B.2 REQUIRED ACTION Place one CREVS train in CRVIS mode. Enter applicable Conditions and Required Actions of LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS)", for one CREVS train made inoperable by inoperable CREVS actuation instrumentation.

Place both trains in CRVIS mode. COMPLETION TIME Immediately Immediately Immediately CALLAWAY 3.3-68 Amendment No. 202 I 3.3.7 CREVS Actuation Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Both radiation monitoring channels inoperable.

C.1.1 AND C.1.2 OR C.2 Enter applicable Conditions and Required Actions of LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS)," for one CREVS train made inoperable by inoperable CREVS actuation instrumentation.

Place one CREVS train in CRVIS mode. Place both trains in CRVIS mode. Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour D. Required Action and associated Completion Time for Conditions A, B, or C not met in MODE 1, 2, D.1 AND Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 3, or 4. D.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months E. Required Action and associated Completion Time for Conditions A, B, or C not met during CORE ALTERATIONS or during movement of irradiated fuel assemblies.

E.1 AND E.2 Suspend CORE ALTERATIONS.

Suspend movement of irradiated fuel assemblies.

Immediately Immediately CALLAWAY PLANT 3.3-69 Amendment No. 202 I 3.3.7 CREVS Actuation Instrumentation SURVEILLANCE REQUIREMENTS

NOT E Refer to Table 3.3.1-1 to determine which SRs apply for each CREVS Actuation Function.

SURVEILLANCE FREQUENCY SR 3.3.7.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.7.2 Perform COT. In accordance with the Surveillance Frequency Control Program SR 3.3.7.3 ---------------------------------

NOTE The continuity check may be excluded.

Perform ACTUATION LOGIC TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.7.4 ---------------------------------

NOT E Verification of setpoint is not required.

Perform TADOT. In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.3-70 Amendment No. 202 3.3.7 CREVS Actuation Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.7.5 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.7.6 ---------------------------------

NOTE Radiation monitor detectors are excluded from response time testing. Verify Control Room Ventilation Isolation ESF RESPONSE TIMES are within limits In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.3-71 Amendment No. 202 3.3.7 CREVS Actuation Instrumentation Table 3.3.7-1 (page 1 of 1) CREVS Actuation Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE TRIP FUNCTION CONDITIONS CHANNELS REQUIREMENTS SETPOINT Manual 1,2,3,4, 2 SR 33.7.4 NA Initiation (a), and (c) Automatic 1,2,3,4, 2 trains SR :3.3.7.3 NA Actuation (a), and (c) Logic and Actuation (a) 2 trains SR 33.7.6 NA Relays (BOP ESFAS) Control Room 1,2,3,4, 2 SR 3.3.7.1 (b) Radiation and (a) SR 3.3.7.2 Control Room SR 3.3.7.5 Air Intakes 2 SR 3.3.7.6 (b) Containment Refer to LCO 3.3.2, "ESFAS Instrumentation," Function 3.a, for all initiation functions and Isolation

-requirements.

Phase A Fuel Building Refer to LCO 3.3.8, "EES Actuation Instrumentation," for all initiation functions and Exhaust requirements.

Radiation-Gaseous During CORE ALTERATIONS or during movement of irradiated fuel assemblies within containment. Nominal Trip Setpoint concentration value (flCi/cm 3) shall be established such that the actual submersion dose rate would not exceed 2 mRlhr in the control room. During movement of irradiated fuel assemblies in the fuel building.

CALLAWAY 3.3-72 Amendment No. 202 I EES Actuation Instrumentation 3.3.8 3.3 INSTRUMENTATION 3.3.8 Emergency Exhaust System (EES) Actuation Instrumentation LCO The EES actuation instrumentation for each Function in Table 3.3.8-1 shall be OPERABLE.

According to Table 3.3.8-1. ACTIONS -----------------------------------------------------------

NOT E S

1. LCO 3.0.3 is not applicable.

2. Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions with one channel or train inoperable.

A.1 AND A.2 Place one EES train in the Fuel Building Ventilation Isolation Signal (FBVIS) mode. Place one CREVS train in Control Room Ventilation Isolation Signal (CRVIS) mode. 7 days 7 days (contlnuea)

CALLAWAY 3.3-73 Amendment No. 202 I 3.3.8 EES Actuation Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. -------------

NOTE Not applicable to Function 3. One or more Functions with two channels or two trains inoperable.

B.1.1 AND B.1.2 Place one EES train in the FBVIS mode and one CREVS train in the CRVIS mode. Enter applicable Conditions and Required Actions of LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS)," for one CREVS train made inoperable and enter applicable Conditions and Required Actions of LCO 3113, "Emergency Exhaust System (EES)," for one EES train made inoperable by inoperable EES actuation instrumentation.

Immediately Immediately B.2 Place both EES trains in the FBVIS mode and both CREVS trains in the CRVIS mode. Immediately CALLAWAY PLANT 3.3-74 Amendment No. 202 I 3.3.8 EES Actuation Instrumentation ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Both radiation monitoring channels inoperable.

C.1.1 AND C.1.2 OR C.2 Enter applicable Conditions and Required Actions of LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS}," for one CREVS train made inoperable and enter applicable Conditions and Required Actions of LCO 3.7.13, "Emergency Exhaust System (EES)," for one EES train made inoperable by inoperable EES actuation instrumentation.

Place one EES train in the FBVIS mode and one CREVS train in the CRVIS mode. Place both EES trains in the FBVIS mode and both CREVS trains in the CRVIS mode. Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour D. Required Action and associated Completion Time for Conditions A, B, or C not met during movement of irradiated fuel assemblies in the fuel building.

D.1 Suspend movement of irradiated fuel assemblies in the fuel building.

Immediately CALLAWAY PLANT 3.3-75 Amendment No. 202 I 3.3.8 EES Actuation Instrumentation SURVEILLANCE REQUIREMENTS

NOT E Refer to Table 3.3.8-1 to determine which SRs apply for each EES Actuation Function.

SU RVEI LLANCE FREQUENCY SR 3.3.8.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.8.2 Perform COT. In accordance with the Surveillance Frequency Control Program SR 3.3.8.3 ---------------------------------

NOTE The continuity check may be excluded.

Perform ACTUATION LOGIC TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.8.4 ---------------------------------

NOTE Verification of setpoint is not required.

Perform TADOT. In accordance with the Surveillance Frequency Control Program (continUed)

CALLAWAY PLANT 3.3-76 Amendment No. 202 3.3.8 EES Actuation Instrumentation SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.8.5 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.3-77 Amendment No. 202 EES Actuation Instrumentation 3.3.8 Table 3.3.8-1 (page 1 of 1) EES Actuation Instrumentation APPLICABLE MODES OR SPECIFIED REQUIRED SURVEILLANCE NOMINAL TRIP FUNCTION CONDITIONS CHANNELS REQUIREMENTS SETPOINT 1. Manual Initiation (a) 2 SR 3.3.8.4 NA 2. Automatic Actuation Logic and Actuation (a) 2 trains SR 3.:UU NA Relays (BOP ESFAS) 3. Fuel Building Exhaust Radiation

-Gaseous (a) 2 SR 3.3.8.1 SR 3.3.8.2 SR 3.3.8.5 (b) During movement of irradiated fuel assemblies in the fuel building. Nominal Trip Setpoint concentration value (I!Ci/cm 3) shall be established such that the actual submersion dose rate would not exceed 4 mRlhr in the fuel building.

CALLAWAY 3.3-78 Amendment No. 202 I BDMS 3.3.9 3.3 INSTRUMENTATION 3.3.9 Boron Dilution Mitigation System (BDMS) LCO Two trains of the BDMS shall be OPERABLE and one RCS loop shall be in operation.

MODES 2 (below P-6 (Intermediate Range Neutron Flux) interlock), 3, 4, and 5. --------------------------------------------

NOTE The boron dilution flux multiplication signal may be blocked: During subcritical physics testing; During control bank movement in MODE 2 (below P-6 (Intermediate Range Neutron Flux) interlock); During control bank movement in MODE 3; During shutdown bank movement in MODE 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One train inoperable.

A.1 Restore train to OPERABLE status. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (continued)

CALLAWAY 3.3-79 Amendment No. 202 I 3.3.9 BDMS ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Two trains inoperable.

Required Action and associated Completion Time of Condition A not met. B.1 **********.

NOTE _._-.__**__* Plant temperature changes are allowed provided the temperature change is accounted for in the calculated SDM. Suspend operations involving positive reactivity additions.

Immediately AND B.2 Perform SR 3.1.1.1. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.3.1 Close and secure unborated water source isolation valves. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months AND B.3.2 Verify unborated water source isolation valves are closed and secured. Once per 31 days (continued)

CALLAWAY PLANT 3.3-80 Amendment No. 202 I 3.3.9 BDMS ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. No RCS loop in operation.

C.1 AND C.2 Close and secure unborated water source isolation valves. Verify unborated water source isolation valves are closed and secured. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Once per 31 days CALLAWAY PLANT 3.3-81 Amendment No. 202 I 3.3.9 BDMS SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.9.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.9.2 ---------------------------------

NOTE Only required to be performed in MODE 5. Verify BGV0178 is secured in the closed position.

In accordance with the Surveillance Frequency Control Program SR 3.3.9.3 ---------------------------------

NOT E Not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power below P-6 interlock.

Perform COT and verify nominal flux multiplication setpoint of 1.7. In accordance with the Surveillance Frequency Control Program SR 3.3.9.4 ---------------------------------

NOTE Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.3-82 Amendment No. 202 3.3.9 BDMS SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.9.5 Verify the centrifugal charging pump suction valves from the RWST open and the CVCS volume control tank discharge valves close in less than or equal to 30 seconds on a simulated or actual actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.3.9.6 Verify one RCS loop is in operation.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.3-83 Amendment No. 202 3.4.1 RCS Pressure, Temperature, and Flow ONB Limits SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 Verify pressurizer pressure is greater than or equal to the limit specified in the COLR. In accordance with the Surveillance Frequency Control Program SR 3.4.1.2 Verify RCS average temperature is less than or equal to the limit specified in the COLR. In accordance with the Surveillance Frequency Control Program SR 3.4.1.3 Verify RCS total flow rate is 382,630 gpm. In accordance with the Surveillance Frequency Control Program SR ---------------------------------

NOTE Calculated rather than verified by precision heat balance when performed prior to THERMAL POWER exceeding 75% RTP. Verify by precision heat balance that RCS total flow rate is 382,630 gpm. Once after each refueling prior to THERMAL POWER exceeding 75% RTP In accordance with the Surveillance Frequency Control Program CALLAWAY Amendment No. 202 RCS Minimum Temperature for Criticality 3.4.2 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.2 RCS Minimum Temperature for Criticality LCO Each operating RCS loop average temperature (Tavg) shall be 551°F.

MODE 1, MODE 2 with keff 1.0. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Tavg in one or more operating RCS loops not within limit. A.1 Be in MODE 2 with keff < 1.0. 30 minutes SURVEILLANCE REQUIREMENTS SURVEILLANCE I FREQUENCY SR 3.4.2.1 Verify RCS Tavg in each operating loop 551°F. In accordance

with the I Surveillance I Frequency Program CALLAWAY 3.4-3 Amendment No. 202 3.4.3 RCS PIT Limits ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. -------------

NOTE Required Action C.2 shall be completed whenever this Condition is entered.

Requirements of LCO not met any time in other than MODE 1,2,3, or4. C.1 AN D C.2 Initiate action to restore parameter(s) to within limits. Determine RCS is acceptable for continued operation.

Immediately Prior to entering MODE4 SURVEILLANCE SR ---------------------------------

NOT E Only required to be performed during RCS heatup and cooldown operations and RCS inservice leak and hydrostatic testing. Verify RCS pressure, RCS temperature.

and RCS heatup and cooldown rates are within the limits specified in the PTLR.

In accordance with the Surveillance Frequency Control Program CALLAWAY 3.4-5 Amendment No. 202 RCS Loops -MODES 1 and 2 3.4.4 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.4 RCS Loops -MODES 1 and LCO 3.4.4 Four RCS loops shall be OPERABLE and in APPLICABILITY:

MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of LCO not met. A.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.4.1 Verify each RCS loop is in operation.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.4-6 Amendment No. 202 3.4.5 RCS Loops -MODE 3 SURVEILLANCE REQUIREMENTS SR 3.4.5.3 Verify correct breaker alignment and indicated power In accordance SURVEILLANCE FREQUENCY SR 3.4.5.1 Verify required RCS loops are in operation.

In accordance with the Surveillance Frequency Control Program SR 3.4.5.2 Verify steam generator secondary side narrow range water levels are 7% for required RCS loops. I n accordance with the Surveillance Frequency Control Program are available to the required pump that is not in with the operation.

I Surveillance Frequency Control Program I CALLAWAY PLANT 3.4-9 Amendment No. 202 3.4.6 RCS Loops -MODE 4 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required loops inoperable.

No RCS or RHR loop in operation.

B.1 AND B.2 Suspend operations that Immediately would cause introduction into the RCS, coolant with boron concentration less than required to meet SDM of LCO 3.1.1. Initiate action to restore one loop to OPERABLE status and operation.

I Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.4.6.1 Verify one RHR or RCS loop is in operation.

In accordance with the Surveillance Frequency Control Program SR 3.4.6.2 Verify SG secondary side narrow range water levels are 7% for required RCS loops. In accordance with the Surveillance Frequency Control Program SR Verify correct breaker alignment and indicated power are available to the required pump that is not in operation.

In accordance with the Surveillance Frequency Control Program CALLAWAY 3.4-11 Amendment No. 202 3.4.7 RCS Loops -MODE 5, Loops Filled SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.7.1 Verify one RHR loop is in operation.

In accordance with the Surveillance Frequency Control Program SR 3.4.7.2 Verify SG secondary side wide range water level is 86% in required SGs. In accordance with the Surveillance Frequency Control Program SR 3.4.7.3 Verify correct breaker alignment and indicated power are available to the required RHR pump that is not in operation.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.4-14 Amendment No. 202 3.4.8 RCS Loops -MODE 5, Loops Not Filled ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required RHR loops inoperable.

No RHR loop in operation.

B.1 AND B.2 Suspend operations that would cause introduction into the RCS, coolant with boron concentration less than required to meet SDM of LCO 3.1.1. Initiate action to restore one RHR loop to OPERABLE status and operation.

Immediately Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.4.8.1 Verify one RHR loop is in operation. I n accordance with the Surveillance Frequency Control Program SR 3.4.8.2 Verify correct breaker alignment and indicated power are available to the required RHR pump that is not in operation.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.4-16 Amendment No. 202 Pressurizer 3.4.9 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition B not AND met. C.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.4.9.1 Verify pressurizer water level is s; 92%. In accordance with the Surveillance Frequency Control Program SR 3.4.9.2 Verify capacity of each required group of backup pressurizer heaters is :?: 150 kW. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.4-18 Amendment No. 202 3.4.11 Pressurizer PORVs SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1 ---------------------------------

NOT E Not required to be performed with block valve closed in accordance with the Required Actions of this LCO. Perform a complete cycle of each block valve. In accordance with the Surveillance Frequency Control Program SR 3.4.11.2 Perform a complete cycle of each PORV. I n accordance with the Inservice Testing Program CALLAWAY PLANT 3.4-24 Amendment No. 202 COMS 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.1 Verify a maximum of zero safety injection pumps are capable of injecting into the RCS. In accordance with the Surveillance Frequency Control Program SR 3.4.12.2 Verify a maximum of one centrifugal charging pump is capable of injecting into the RCS. In accordance with the Surveillance Frequency Control Program SR 3.4.12.3 Verify each accumulator is isolated when accumulator pressure is greater than or equal to the maximum RCS pressure for the existing RCS cold leg temperature allowed by the PIT limit curves provided in the PTLR. In accordance with the Surveillance Frequency Control Program SR 3.4.12.4 Verify RHR suction isolation valves are open for each required RHR suction relief valve. In accordance with the Surveillance Frequency Control Program SR 3.4.12.5 Verify required RCS vent;::: 2.0 square inches open. In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.4-28 Amendment No. 202 3.4.12 COMS SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.4.12.6 Verify PORV block valve is open for each required PORV. In accordance with the Surveillance Frequency Control Program SR 3.4.12.7 Not used. SR 3.4.12.8 ---------------------------------

NOTE Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing any RCS cold leg temperature to 275°F. Perform a COT on each required PORV, excluding actuation.

In accordance with the Surveillance Frequency Control Program SR 3.4.12.9 Perform CHANNEL CALIBRATION for each required PORV actuation channel. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.4-29 Amendment No. 202 3.4.13 RCS Operational LEAKAGE SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1 --------------------------

NOT ES

1. Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

2. Not applicable to primary to secondary LEAKAGE Verify RCS operational LEAKAGE is within limits by performance of RCS water inventory balance. In accordance with the Surveillance Frequency Control Program SR 3.4.13.2 --------------------------

NOTE Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

Verify primary to secondary LEAKAGE is s 150 gallons per day through anyone SG. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.4-31 Amendment No. 202 3.4.14 RCS PIV Leakage SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.14.1 ---------------------------------

NOT E S Not required to be performed in MODES 3 and 4. Not required to be performed on the RCS PIVs located in the RHR flow path when in the shutdown cooling mode of operation. RCS PIVs actuated during the performance of this Surveillance are not required to be tested more than once if a repetitive testing loop cannot be avoided. Verify leakage from each RCS PIV is equivalent to 0.5 gpm per nominal inch of valve size up to a maximum of 5 gpm at an RCS pressure 2 2215 psig and 2255 psig. FREQUENCY In accordance with the I nservice Testing Program In accordance with the Surveillance Frequency Control Program Prior to entering MODE 2 whenever the unit has been in MODE 5 for 7 days or more and if leakage testing has not been performed in the previous 9 months (continued)

CALLAWAY 3.4-34 Amendment No. 202 3.4.14 RCS PIV Leakage SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR3.4.14.1 (c ontinued)

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months following check valve actuation due to flow through the valve SR 3.4.14.2 Verify RHR suction isolation valve interlock prevents the valves from being opened with a simulated or actual RCS pressure signal 425 psig except when In accordance with the Surveillance the valves are open to satisfy LCO 3.4.12. Frequency Control Program CALLAWAY PLANT 3.4-35 Amendment 202 RCS Leakage Detection Instrumentation 3.4.15 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.15.1 Perform CHANNEL CHECK of the required containment atmosphere particulate radioactivity monitor. I n accordance with the Surveillance Frequency Control Program SR 3.4.15.2 Perform COT of the required containment atmosphere particulate radioactivity monitor. In accordance with the Surveillance Frequency Control Program SR 3.4.15.3 Perform CHANNEL CALIBRATION of the required containment sump level and flow monitoring system. I n accordance with the Surveillance Frequency Control Program SR 3.4.15.4 Perform CHANNEL CALIBRATION of the required containment atmosphere particulate radioactivity monitor. In accordance with the Surveillance Frequency Control Program SR 3.4.15.5 Perform CHANNEL CALIBRATION of the required containment cooler condensate monitoring system. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.4-39 Amendment No. 202 3.4.16 RCS Specific Activity ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and associated Completion Time of Condition A or B not met. OR DOSE EQUIVALENT 1-131 > 60 J..lCi/gm.

C.1 AND C.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SURVEILLANCE SR

NOTE Only required to be performed in MODE 1. Verify reactor coolant DOSE EQUIVALENT XE-133 specific activity::;

225 mCi/gm.

In accordance with the Surveillance Frequency Control Program CALLAWAY 3.4-41 Amendment No. 202 3.4.16 RCS Specific Activity SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR

NOTE Only required to be performed in MODE 1. Verify reactor coolant DOSE EQUIVALENT 1-131 specific activity::;

1.0 FREQUENCY In accordance with the Surveillance Frequency Control Program Between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a THERMAL POWER change of 15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period CALLAWAY 3.4-42 Amendment No. 202 SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM 3.4.17 Steam Generator (SG) Tube LCO 3.4.17 SG tube integrity shall be All SG tubes satisfying the tube repair criteria shall be plugged in accordance with Steam Generator Program. APPLICABILITY:

MODES 1 2, 3, and 4. ACTIONS -----------------------------------------------------------

NOT E Separate Condition entry is allowed for each SG tube. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes satisfying the tube repair criteria and not plugged in accordance with the Steam Generator Program. A.1 AND A.2 Verify tube integrity of the affected tube(s) is maintained until the next refueling outage or inspection.

Plug the affected tube(s) in accordance with the Steam Generator Program. 7 days Prior to entering MODE 4 following the next refueling outage or SG tu be inspection (continued)

CALLAWAY PLANT 3.4-43 Amendment No. 202 I SG Tube Integrity 3.4.17 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and associated Completion Time of Condition A not met. SG tube integrity not maintained.

B.1 AND B.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours CALLAWAY PLANT 3.4-44 Amendment No. 202 ,

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the Steam Generator Program. In accordance with the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies the tube repair criteria is plugged in accordance with the Steam Generator Program. Prior to entering MODE 4 following a SG tube inspection CALLAWAY PLANT 3.4-45 Amendment No. 202 I 3.5.1 Accumulators SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify each accumulator isolation valve is fully open. In accordance with the Surveillance Frequency Control Program SR 3.5.1.2 Verify borated water volume in each accumulator is 6061 gallons and 6655 gallons. I n accordance with the Surveillance Frequency Control Program SR 3.5.1.3 Verify nitrogen cover pressure in each accumulator is 602 psig and 648 psig. I n accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.5-2 Amendment No. 202 3.5.1 Accumulators SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.4 Verify boron concentration in each accumulator is 2: 2300 ppm and:::; 2500 ppm. In accordance with the Surveillance Frequency Control Program AND -------NOTE Only required to be performed for affected accumulators Once within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution volume increase of 2: 70 gallons that is not the result of addition from the refueling water storage tank SR 3.5.1.5 Verify power is removed from each accumulator isolation valve operator when RCS pressure is > 1000 psig. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.5-3 Amendment No. 202 ECCS -Operating 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS -Operating LCO 3.5.2 Two ECCS trains shall be OPERABLE.

NOTES In MODE 3, both safety injection (SI) pump flow paths may be isolated by closing the isolation valves for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to perform pressure isolation valve testing per SR 3.4.14.1. Operation in MODE 3 with ECCS pumps made incapable of injecting, pursuant to LCO 3.4.12, "Cold Overpressure Mitigation System," is allowed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or until the temperature of all RCS cold legs exceeds 375°F, whichever comes first. APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more trains inoperable.

AND At least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available.

A.1 Restore train(s) to OPERABLE status. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours CALLAWAY 3.5-4 Amendment No. 202 I 3.5.2 ECCS -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.1 Number Verify the following valves are in the listed position with power to the valve operator removed. PO§jitioo Functioo BNHV8813 Open Safety Injection to RWST Isolation Valve EMHV8802A Closed SI Hot Legs 2 & 3 Isolation Valve EMHV8802B Closed SI Hot Legs 1 & 4 Isolation Valve EMHV8835 Open Safety Injection Cold Leg Isolation Valve EJHV8840 Closed RHRlSI Hot Leg Recirc Isolation Valve EJHV8809A Open RHR to Accum Inject Loops 1 & 2 Isolation Valve EJHV8809B Open RHR to Accum Inject Loops 3 & 4 Isolation Valve In accordance with the Surveillance Frequency Control Program SR 3.5.2.2 Verify each ECCS manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.5.2.3 Verify ECCS piping is full of water. In accordance with the Surveillance Frequency Control Program SR 3.5.2.4 Verify each ECCS pump's developed head at the test flow point is greater than or equal to the required developed head. In accordance with the Inservice Testing Program (continued)

CALLAWAY PLANT 3.5-5 Amendment No. 202 3.5.2 ECCS -Operating SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.2.5 SR 3.5.2.6 SR 3.5.2.7 SR 3.5.2.8 SURVEILLANCE Verify each ECCS automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal. Verify each ECCS pump starts automatically on an actual or simulated actuation signal. Verify, for each ECCS throttle valve listed below, each mechanical position stop is in the correct position.

EMV0095 EMV0096 EMV0097 EMV0098 Valve Number EMV0107 EMV0108 EMV0109 EMV0110 EMV0089 EMV0090 EMV0091 EMV0092 Verify, by visual inspection, each ECCS train containment sump suction inlet is not restricted by debris and the suction inlet strainers show no evidence of structural distress or abnormal corrosion.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.5-6 Amendment No. 202 3.5.3 ECCS -Shutdown 3.5 EMERGENCY CORE COOLING SYSTEMS 3.5.3 ECCS -

LCO 3.5.3 One ECCS train shall be

NOTE An RHR subsystem may be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned to the ECCS mode of operation.

APPLICABILITY:

MODE 4. ACTIONS ----------------------------------------------------------

NOTE LCO 3.0.4.b is not applicable to ECCS centrifugal charging pump subsystem.

CONDITION REQUIRED ACTION COMPLETION TIME A. Required ECCS residual heat removal (RHR) subsystem inoperable.

A.1 Initiate action to restore required ECCS RHR subsystem to OPERABLE status. Immediately B. Required ECCS Centrifugal Charging Pump subsystem inoperable.

B.1 Restore required ECCS Centrifugal Charging Pump subsystem to OPERABLE status. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months C. Required Action and associated Completion Time of Condition B not met. C.1 Be in MODE 5. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months CALLAWAY PLANT 3.5-7 Amendment No. 202 I 3.5.3 ECCS -Shutdown SURVEILLANCE REQUIREMENTS SR The following SRs are applicable for all equipment required to be OPERABLE:

SR 3.5.2.1 SR 3.5.2.7 SR 3.5.2.3 SR 3.5.2.8 SR 3.5.2,4 I n accordance with applicable SRs CALLAWAY 3.5-8 Amendment No. 202 I 3.5.4 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.4 Refueling Water Storage Tank (RWST) LCO 3.5.4 The RWST shall be OPERABLE.

APPLICABILITY:

MODES 1,2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RWST boron concentration not within limits. OR RWST borated water temperature not within limits. A.1 Restore RWST to OPERABLE status. 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months B. RWST inoperable for reasons other than Condition A. B.1 Restore RWST to OPERABLE status. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months C. Required Action and associated Completion Time not met. C.1 AND C.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours CALLAWAY PLANT 3.5-9 Amendment No. 202 I 3.5.4 RWST SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR ---------------------------------

NOTE Only required to be performed when ambient air temperature is < 3rF or > 100°F. Verify RWST borated water temperature is 37°F and s 100°F. In accordance with the Surveillance Frequency Control Program SR 3.5.4.2 Verify RWST borated water volume is 394,000 gallons. In accordance with the Surveillance Frequency Control Program SR 3.5.4.3 Verify RWST boron concentration is 2350 ppm and s 2500 ppm. In accordance with the Surveillance Frequency Control Program CALLAWAY 3.5-10 Amendment No. 202 Seal Injection Flow 3.5.5 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.5 Seal Injection Flow 3.5.5 Reactor coolant pump (RCP) seal injection flow shall be within the limits of Figure 3.5.5-1. APPLICABILITY:

MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Seal injection flow not within limit. A.1 Adjust manual seal injection throttle valves such that the RCP seal injection flow is within the limits of Figure 3.5.5-1. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months B. Required Action and associated Completion B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Time not AND B.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months CALLAWAY Amendment No. 202 I 3.5.5 Seal Injection Flow SURVEILLANCE REQUIREMENTS SR ---------------------------------

NOTE Not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the Reactor Coolant System pressure stabilizes at 2215 psig and 2255 psig. Verify manual seal injection throttle valves are adjusted to give a flow within the limits of Figure 3.5.5-1.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.5-12 Amendment No. 202

3.5.5 Seal Injection Flow Delta P from Charging Header to RCS vs. Total Seal Injection Line Flow 210 E! f,/) @:. 190 :! :::J 1/1 f f,/) 170 ... ;: 160 lil.. & 150

... 4'\1 ..c: 140 Ci 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 Total Seal Injection Line Flow IGPMI Figure 3.5.5-1 (page 1 of Delta P from Charging Header to RCS VS. Total Seal Injection Line CALLAWAY PLANT Amendment No. 202 ,

3.6.2 Containment Air Locks SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.1 ---------------------------------

NOT E S

1. An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test. 2. Results shall be evaluated against acceptance criteria applicable to SR 3.6.1.1. Perform required air lock leakage rate testing in accordance with the Containment Leakage Rate Testing Program. I n accordance with the Containment Leakage Rate Testing Program SR 3.6.2.2 Verify only one door in the air lock can be opened at a time. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.6-6 Amendment No. 202 3.6.3 Containment Isolation Valves SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.1 Verify each containment shutdown purge valve is sealed closed or closed and blind flange installed except for one purge valve in a penetration flow path while in Condition D of this LCO. In accordance with the Surveillance Frequency Control Program Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days for isolation devices inside containment SR 3.6.3.2 Verify each containment mini-purge valve is closed, except when the containment mini-purge valves are open for pressure control, ALARA or air quality considerations for personnel entry, or for Surveillances that require the valves to be open. In accordance with the Surveillance Frequency Control Program SR 3.6.3.3 ---------------------------------

NOTE Valves and blind flanges in high radiation areas may be verified by use of administrative controls.

Verify each containment isolation manual valve and blind flange that is located outside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls.

In accordance with the Surveillance Frequency Control Program (COntinued)

CALLAWAY PLANT 3.6-13 Amendment No. 202 3.6.3 Containment Isolation Valves SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.3.4 ***.**.**************************

NOTE *.***.**********************

Valves and blind flanges in high radiation areas may be verified by use of administrative means. Verify each containment isolation manual valve and blind flange that is located inside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls.

Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days SR 3.6.3.5 Verify the isolation time of each automatic power operated containment isolation valve is within limits. In accordance with the Inservice Testing Program SR 3.6.3.6 .**.*..*.************************

NOTE **..*...*.*.***..***.*****.*

Only required to be performed when containment shutdown purge valve blind flanges are installed.

Perform leakage rate testing for containment shutdown purge valves with resilient seals and associated blind flanges. In accordance with the Surveillance Frequency Control Program Following each reinstallation of the blind flange (continUed)

CALLAWAY PLANT 3.6-14 Amendment No. 202 3.6.3 Containment Isolation Valves SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.3.7 ---------------------------------

NOT E Only required to be performed for the containment shutdown purge valves when associated blind flanges are removed. Perform leakage rate testing for containment mini-purge and shutdown purge valves with resilient seals. In accordance with the Surveillance Frequency Control Program Within 92 days after opening the valve SR 3.6.3.8 Verify each automatic containment isolation valve that is not locked, sealed or otherwise secured in position, actuates to the isolation position on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.6-15 Amendment No. 202 Containment Pressure 3.6.4 3.6 CONTAINMENT SYSTEMS 3.6.4 Containment LCO 3.6.4 Containment pressure shall be -0.3 psig and + 1.5 APPLICABILITY:

MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Containment pressure not within limits. A.1 Restore containment pressure to within limits. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.4.1 Verify containment pressure is within limits. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.6-16 Amendment No. 202 3.6.5 Containment Air Temperature 3.6 CONTAINMENT SYSTEMS 3.6.5 Containment Air LCO 3.6.5 Containment average air temperature shall be APPLICABILITY:

MODES 1. 2. 3. and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Containment average air temperature not within limit. A.1 Restore containment average air temperature to within limit. 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.5.1 Verify containment average air temperature is within limit. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.6-17 Amendment No. 202 3.6.6 Containment Spray and Cooling Systems ACTIONS (continued)

CONDITION D. Required Action and associated Completion Time of Condition C not met. D.1 AND D.2 REQUIRED ACTION Be in MODE 3. Be in MODE 5. COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours E. Two containment spray trains inoperable.

OR Two containment cooling trains inoperable.

E.1 AND E.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SURVEILLANCE SR Verify each containment spray manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

SR 3.6.6.2 Operate each containment cooling train fan unit for 2: 15 minutes.

In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT Amendment No. 202 3.6.6 Containment Spray and Cooling Systems SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.6.3 Verify each containment cooling train cooling water flow rate is 2:: 2200 gpm. In accordance with the Surveillance Frequency Control Program SR 3.6.6.4 Verify each containment spray pump's developed head at the flow test point is greater than or equal to the required developed head. In accordance with the Inservice Testing Program SR 3.6.6.5 Verify each automatic containment spray valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.6.6.6 Verify each containment spray pump starts automatically on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.6.6.7 Verify each containment cooling train starts automatically and minimum cooling water flow rate is established on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.6.6.8 Verify each spray nozzle is unobstructed.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.6-20 Amendment No. 202 Recirculation Fluid pH Control System 3.6.7 3.6 CONTAINMENT SYSTEMS 3.6.7 Recirculation Fluid pH Control (RFPC) System LCO 3.6.7 The RFPC System shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RFPC System inoperable.

A.1 Restore RFPC System to OPERABLE status. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 84 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.7.1 Verify the integrity of the RFPC System. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.6-21 Amendment No. 202 3.6.7 Recirculation Fluid pH Control System SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.7.2 Verify the RFPC System ensures an equilibrium sump pH;:: 7.1. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.6-22 Amendment No. 202 3.7.2 MSIVs, MSIVBVs, and MSLPDIVs SURVEILLANCE REQUIREMENTS SURVEILLANCE I FREQUENCY SR 3.7.2.1 Verify isolation time of each MSIV is within limits. In accordance with the Inservice Testing Program SR 3.7.2.2 Verify each MSIV, each MSIVBV, and each MSLPDIV actuates to the isolation position on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.7.2.3 Verify isolation time of each MSIVBV and MSLPDIV is within limits. In accordance with the Inservice Testing Program CALLAWAY PLANT 3.7-8 Amendment No. 202 3.7.3 MFIVs, MFRVs, and MFRVBVs SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1 ---------------------------------

NOT E Only required to be performed in MODES 1 and 2. Verify the closure time of each MFRV and MFRVBV is within limits. I n accordance with the Inservice Testing Program SR 3.7.3.2 ---------------------------------

NOTE For the MFRVs and MFRVBVs, only required to be performed in MODES 1 and 2. Verify each MFIV, MFRV and MFRVBV actuates to the isolation position on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.7.3.3 Verify the closure time of each MFIV is within limits. In accordance with the Inservice Testing Program CALLAWAY PLANT 3.7-11 Amendment 202 3.7.5 AFW System SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 ---------------------------------

NOTE Only required to be performed for the AFW flow control valves when the system is placed in automatic control or when THERMAL POWER is > 10% RTP. Verify each AFW manual, power operated, and automatic valve in each water flow path, and in both steam supply flow paths to the steam turbine driven pump, that is not locked, sealed, or otherwise secured in position, is in the correct position. I n accordance with the Surveillance Frequency Control Program SR 3.7.5.2 ---------------------------------

NOTE Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after 2 900 psig in the steam generator.

Verify the developed head of each AFW pump at the flow test point is greater than or equal to the required developed head. I n accordance with the Inservice Test Program SR 3.7.5.3 Verify each AFW automatic valve that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program (continued)

CALLAWAY PLANT 3.7-17 Amendment No. 202 3.7.5 AFW System SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.7.5.4 ---------------------------------

NOTE ------

Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after 2 900 psig in the steam generator.

Verify each AFW pump starts automatically on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.7.5.5 Verify proper alignment of the required AFW flow paths by verifying flow from the condensate storage tank to each steam generator.

Prior to entering MODE 2 whenever unit has been in MODE 5 or 6 for> 30 days CALLAWAY PLANT 3.7-18 Amendment No. 202 3.7.6 CST SURVEILLANCE REQUIREMENTS SR 3.7.6.1 Verify the CST contained water volume is ;::. 281,000 gal.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.7-20 Amendment No. 202 3.7.7 CCWSystem SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 -----------------------------

NOTE Isolation of CCW flow to individual components does not render the CCW System inoperable.

Verify each CCW manual, power operated, and automatic valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.7.7.2 Verify each CCW automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.7.7.3 Verify each CCW pump starts automatically on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.7-22 Amendment No. 202 3.7.8 ESW SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.8.1 ---------------------------------

NOTE Isolation of ESW flow to individual components does not render the ESW inoperable.

Verify each ESW manual, power operated, and automatic valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.7.8.2 Verify each ESW automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal. I n accordance with the Surveillance Frequency Control Program SR 3.7.8.3 Verify each ESW pump starts automatically on an actual or simulated actuation signal. I n accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.7-25 Amendment No. 202 3.7.9 UHS SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.9.1 Verify water level of UHS is 831.25 ft mean sea level. In accordance with the Surveillance Frequency Control Program SR 3.7.9.2 Verify average water temperature of UHS is 90°F. In accordance with the Surveillance Frequency Control Program SR 3.7.9.3 Operate each cooling tower fan for 15 minutes in both the fast and slow speed. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.7-27 Amendment No. 202 CREVS 3.7.10 SURVEILLANCE REQUIREMENTS SU RVEI LLANCE FREQUENCY SR 3.7.10.1 Operate each CREVS train pressurization filter unit for 10 continuous hours with the heaters operating and each CREVS train filtration filter unit for 15 minutes. In accordance with the Surveillance Frequency Control Program SR 3.7.10.2 Perform required CREVS filter testing in accordance with the Ventilation Filter Testing Program (VFTP). In accordance with the VFTP SR 3.7.10.3 Verify each CREVS train actuates on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.7.10.4 Perform required unfiltered air inleakage testing of the CRE and CBE boundaries in accordance with the In accordance with the Control Room Control Room Envelope Habitability Envelope Habitability Program CALLAWAY 3.7-31 Amendment No. 202 3.7.11 CRACS SURVEILLANCE REQUIREMENTS SR 3.7.11.1 Verify each CRACS train has the capability to remove the assumed heat load.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.7-34 Amendment No. 202 3.7.13 Emergency Exhaust System SURVEILLANCE REQUIREMENTS SU RVEI LLANCE FREQUENCY SR 3.7.13.1 Operate each EES train for 10 continuous hours with the heaters operating.

In accordance with the Surveillance Frequency Control Program SR 3.7.13.2 Perform required EES filter testing in accordance with the Ventilation Filter Testing Program (VFTP). I n accordance with the VFTP SR 3.7.13.3 Verify each EES train actuates on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program SR 3.7.13.4 Verify one EES train can maintain a negative pressure 0.25 inches water gauge with respect to atmospheric pressure in the auxiliary building during the SIS mode of operation.

In accordance with the Surveillance Frequency Control Program SR 3.7.13.5 Verify one EES train can maintain a negative pressure 0.25 inches water gauge with respect to atmospheric pressure in the fuel building during the FBVIS mode of operation. I n accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.7-38 Amendment No. 202 Fuel Storage Pool Water Level 3.7.15 3.7 PLANT SYSTEMS 3.7.15 Fuel Storage Pool Water Level 3.7.15 The fuel storage pool water level shall be 23 ft over the top of the storage racks. APPLICABILITY:

During movement of irradiated fuel assemblies in the fuel storage pool. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Fuel storage pool water level not within limit. A.1 ------------

NOTE LCO 3.0.3 is not applicable.

Suspend movement of irradiated fuel assemblies in the fuel storage pool. Immediately SURVEILLANCE SR 3.7.15.1 Verify the fuel storage pool water level is 23 ft above the storage racks.

In accordance with the Surveillance Frequency Control Program CALLAWAY 3.7-40 Amendment No. 202 3.7.16 Fuel Storage Pool Boron Concentration SURVEILLANCE REQUIREMENTS SR 3.7.16.1 Verify the fuel storage pool boron concentration is within limit.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.7-42 Amendment No. 202 Secondary Specific Activity 3.7.18 3.7 PLANT SYSTEMS 3.7.18 Secondary Specific Activity LCO The specific activity of the secondary coolant shall be 5 0.10 IlCi/gm DOSE EQUIVALENT 1-131. APPLICABILITY:

MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Specific activity not within limit. A.1 AND A.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.18.1 Verify the specific activity of the secondary coolant is 50.10 IlCilgm DOSE EQUIVALENT 1-131. FREQUENCY In accordance with the Surveillance Frequency Control Program CALLAWAY 3.7-45 Amendment No. 202 SSIVs 3.7.19 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and Associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.7.19.1 Verify the isolation time of each automatic SSIV is within limits. In accordance with the Inservice Testing Program SR 3.7.19.2 Verify each automatic SSIV in the flow path actuates to the isolation position on an actual or simulated actuation signal. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.7-47 Amendment No. 202 3.8.1 AC Sources -Operating ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME G. Required Action and associated Completion Time of Condition A, B, C, 0, E, or F not met. G.1 AND G.2 Be in MODE 3. Bein MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours H. Three or more AC sources inoperable.

H.1 Enter LCO 3.0.3. Immediately SURVEILLANCE SR 3.8.1.1 Verify correct breaker alignment and indicated power availability for each required offsite circuit. I n accordance with the Surveillance Frequency Control Program (contlnueo)

CALLAWAY PLANT 3.8-6 Amendment No. 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.2 ---------------------------

NOTES Performance of SR 3.8.1.7 satisfies this SR. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.

When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met. Verify each DG starts from standby conditions and achieves steady state voltage 3740 V and 4320 V, and frequency 58.8 Hz and 61.2 Hz.

In accordance with the Surveillance Frequency Control Program CALLAWAY 3.8-7 Amendment No. 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 -------------------------

NOTES

1. DG loadings may include gradual loading as recommended by the manufacturer.

2. Momentary transients outside the load range do not invalidate this test. 3. This Surveillance shall be conducted on only one DG at a time. 4. This SR shall be preceded by and immediately follow without shutdown a successful performance of SR 3.8.1.2 or SR 3.8.1.7. Verify each DG is synchronized and loaded and operates for;?: 60 minutes at a load;?: 5580 kW and ::;; 6201 kW. In accordance with the Surveillance Frequency Control Program SR 3.8.1.4 Verify each fuel oil transfer pump starts on low level in the associated day tank standpipe.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.5 Check for and remove accumulated water from each day tank. In accordance with the

! Control Program SR 3.8.1.6 Verify each fuel oil transfer system operates to In accordance transfer fuel oil from storage tank to the day tank. with the Surveillance Frequency Control Program CALLAWAY PLANT 3.8-8 Amendment No. 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.7 ------------------------------

NOTE All DG starts may be preceded by an engine prelube period. Verify each DG starts from standby condition and achieves in s; 12 seconds, voltage 3740 V and s; 4320 V, and frequency 58.8 Hz and s; 61.2 Hz. In accordance with the Surveillance Frequency Control Program SR 3.8.1.8 Not used. SR 3.8.1.9 Not used. SR 3.8.1.10 Verify each DG operating at a power factor $ 0.9 and 0.8 does not trip and voltage is maintained s; 4784 V and frequency is maintained s; 65.4 Hz during and following a load rejection of 5580 kWand s; 6201 kW. In accordance with the Surveillance Frequency Control Program (contInued)

CALLAWAY PLANT 3.8-9 Amendment No. 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS (continued)

FREQUENCY SR 3.8.1.11 In accordance with the Surveillance Frequency Control Program SURVEILLANCE

NOTES All DG starts may be preceded by an engine prelube period. This Surveillance shall not normally be performed in MODE 1 or 2. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify on an actual or simulated loss of offsite power signal: De-energization of emergency buses; Load shedding from emergency buses; DG auto-starts from standby condition and: energizes permanently connected loads in s 12 seconds, energizes auto-connected shutdown loads through the shutdown load sequencer, maintains steady state voltage;;::

3740 V and s 4320 V, maintains steady state frequency

58.8 Hz and s 61.2 Hz, and supplies permanently connected and auto-connected shutdown loads for ;;

5 minutes. CALLAWAY 3.8-10 Amendment No. 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS continued)

FREQUENCY SR 3.8.1.12 In accordance with the Surveillance Frequency Control Program SURVEILLANCE

NOTES All DG starts may be preceded by prelube period. This Surveillance shall not normally be performed in MODE 1 or 2. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify on an actual or simulated safety injection signal each DG auto-starts from standby condition and: In s 12 seconds after auto-start and during tests, achieves voltage:::>:

3740 V and s 4320 V; In s 12 seconds after auto-start and during tests, achieves frequency:::>:

58.8 Hz and s 61.2 Hz; Operates for:::>: 5 minutes; Permanently connected loads remain energized from the offsite power system; and Emergency loads are auto-connected and energized through the LOCA load sequencer from the offsite power system. CALLAWAY 3.8-11 Amendment No. 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS (continued SR Verify each DG's automatic trips are bypassed on actual or simulated loss of voltage signal on the emergency bus concurrent with an actual or simulated safety injection signal except: a. Engine overspeed;

b. Generator differential current; c. Low lube oil pressure;

d. High crankcase pressure;

e. Start failure relay; and f. High jacket coolant temperature.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.8-12 Amendment No. 202 3.8.1 AC Sources

-Operating SURVEILLANCE REQUIREMENTS (continued)

SR SR

NOTE S Momentary transients outside the load and power factor ranges do not invalidate this test. The DG may be loaded to:2: 5580 kW and 6201 kW for the entire test period if connected design loads are less than 6201 kW. Verify each DG operating at a power factor 0.9 and :2: 0.8 operates for :2: 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s: a. For :2: 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded :2: 6600 kW and 6821 kW; and b. For the remaining hours of the test loaded :2: 5580 kW and 6201 kW. ---------------------------

NOTE S This Surveillance shall be performed within 5 minutes of shutting down the DG after the DG has operated :2: 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded :2: 5580 kW and 6201 kW. Momentary transients outside of load range do not invalidate this test. All DG starts may be preceded by an engine prelube period. Verify each DG starts and achieves, in 12 voltage :2: 3740 V, and 4320 V and

2: 58.8 Hz and 61.2 In accordance

with the

Surveillance Frequency Control Program In accordance with the

Surveillance Frequency Control Program CALLAWAY 3.8-13 Amendment No. 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.16 ------------------------------

NOT E This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify each DG: a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power; b. Transfers loads to offsite power source; and c. Returns to ready-to-Ioad operation.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.17 ------------------------------

NOTE This Surveillance shall not normally be performed in MODE 1 or 2. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify, with a DG operating in test mode and connected to its bus, an actual or simulated Safety Injection signal overrides the test mode by: a. Returning DG to ready-to-Ioad operation; and b. Automatically energizing the emergency load from offsite power. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.8-14 Amendment No. 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE

NOT E This Surveillance shall not normally be performed in MODE 1 or 2. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify interval between each sequenced load block is within +/- 10% of design interval for each LOCA and shutdown load sequencer.

FREQUENCY I n accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.8-15 Amendment 202 3.8.1 AC Sources -Operating SURVEILLANCE SURVEILLANCE

NOT E S All DG starts may be preceded by an engine prelube period. This Surveillance shall not normally be performed in MODE 1 or 2. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated Safety Injection signal: De-energization of emergency buses; Load shedding from emergency buses; and DG auto-starts from standby condition and: energizes permanently connected loads in 12 seconds, energizes auto-connected emergency loads through LOCA load sequencer, achieves steady state voltage 3740 V and 54320 V, achieves steady state frequency 58.8 Hz and 61.2 Hz, and supplies permanently connected and auto-connected emergency loads for 5 minutes. FREQUENCY In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT Amendment 202 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.20 ------------------------------

NOTE All DG starts may be preceded by an engine prelube period. Verify when started simultaneously from standby condition, each DG achieves, in 12 seconds, voltage:2':

3740 V and 4320 V, and frequency

58.8 Hz and 61.2 Hz. In accordance with the Surveillance Frequency Control Program SR 3.8.1.21 ------------------------------

NOTE The continuity check may be excluded from the actuation logic test. Perform ACTUATION LOGIC TEST for each train of the load shedder and emergency load sequencer.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.8-17 Amendment No. 202 3.8.2 AC Sources -Shutdown 3.8 ELECTRICAL POWER SYSTEMS 3.8.2 AC Sources -Shutdown LCO The following AC electrical power sources shall be OPERABLE: One qualified circuit between the offsite transmission network and the onsite Class 1 E AC electrical power distribution subsystem required by LCO 3.8.10, "Distribution Systems -Shutdown";

and One diesel generator (DG) capable of supplying one train of the onsite Class 1 E AC electrical power distribution subsystems required by LCO 3.8.10; and The shutdown portion of one Load Shedder and Emergency Load Sequencer (LSELS) associated with the required DC and AC electrical power distribution train.

MODES 5 and 6, During movement of irradiated fuel assemblies.

ACTIONS -----------------------------------------------------------

NOT E LCO 3.0.3 is not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. One required offsite circuit inoperable.

NOTE Enter applicable Conditions and Required Actions of LCO 3.8.10, with the required train de-energized as a result of Condition A. A.1 Declare affected required feature(s) with no offsite power available inoperable.

Immediately ( continued)

CALLAWAY 3.8-18 Amendment No. 202 I 3.8.2 AC Sources -Shutdown ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A One required offsite circuit inoperable. (continued)

A.2.1 Suspend CORE ALTERATIONS.

AND A.2.2 AND A.2.3 Suspend movement of irradiated fuel assemblies.

Suspend operations involving positive reactivity additions that could result in loss of required SDM or boron concentration.

A.2.4 Initiate action to restore Immediately Immediately Immediately required offsite power circuit to OPERABLE status. Immediately (continued)

CALLAWAY PLANT 3.8-19 Amendment 202 I 3.8.2 AC Sources -Shutdown ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One required DG inoperable.

B.1 AND B.2 AND B.3 AND B.4 Suspend CORE ALTERATIONS.

Suspend movement of irradiated fuel assemblies.

Suspend operations involving positive reactivity additions that could result in loss of required SDM or boron concentration. Initiate action to restore required DG to OPERABLE status. Immediately Immediately Immediately Immediately C. One required LSELS (shutdown portion) inoperable.

C.1 Declare the affected DG and offsite circuit inoperable.

Immediately CALLAWAY PLANT 3.8-20 Amendment No. 202 I 3.8.2 AC Sources -Shutdown SURVEILLANCE REQUIREMENTS SURVEILLANCE SR ---------------------------------

NOTE The following SRs are not required to be performed:

SR 3.8.1.3, 3.8.1.10 , SR 3.8.1.11 , SR 3,8.1.14 through SR 3.8.1.16, and SR 3,8.1.18 , (Shutdown Load Sequencer only). For AC sources required to be OPERABLE, the following SRs are applicable:

SR 3.8.1.1 SR 3.8.1.11 SR 3.8,1.2 SR 3.8.114 SR 3.8.1.3 SR 3,8.1.15 SR 3.8.1.4 SR 3.8.1.16 SR 3.8.1.5 SR 3.8.1.18 (shutdown load SR 3.8.1.6 sequencer only) SR 3,8.1.7 SR 3.8.1.21 (shutdown load SR 3.8.1.10 sequencer only) FREQUENCY In accordance with applicable SRs CALLAWAY 3.8-21 Amendment No. 202 I Diesel Fuel Oil, Lube Oil, and Starting Air 3.8.3 3.8 ELECTRICAL POWER SYSTEMS 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air 3.8.3 The stored diesel fuel oil, lube oil, and starting air subsystem shall be within limits for each required diesel generator (DG).

When associated DG is required to be OPERABLE.

ACTIONS -----------------------------------------------------------

NOTE Separate Condition entry is allowed for each DG. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more DGs with fuel level < 80,900 gal and > 69,800 gal in storage tank. A.1 Restore fuel oil level to within limits. 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months B. One or more DGs with lube oil inventory

< 750 gal and > 686 gal. B.1 Restore lube oil inventory to within limits. 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months C. One or more DGs with stored fuel oil total particulates not within limit. C.1 Restore fuel oil total particulates within limit. 7 days D. One or more DGs with new fuel oil properties not within limits. D.1 Restore stored fuel oil properties to within limits. 30 days (continued)

CALLAWAY 3.8-22 Amendment No. 202 I 3.8.3 Diesel Fuel Oil, Lube Oil. and Starting Air ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME One or more DGs with two starting air receivers in service with pressure < 435 psig and 2:: 250 psig. QB E.1 Restore two starting air receivers with pressure 2:: 435 psig. 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months One or more DGs with only E.2 Restore one starting air 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months one starting air receiver in receiver with pressure service with pressure 2:: 610 psig. < 610 psig and 2:: 300 psig. F. Required Action and associated Completion Time not met. QB One or more DGs diesel fuel oil, lube oil, or starting air subsystems not within limits for reasons other than Condition A, B, C, D. or E. F.1 Declare associated DG inoperable.

Immediately CALLAWAY PLANT 3.8-23 Amendment No. 202 I 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.3.1 Verify each fuel oil storage tank contains 80,900 gal of fuel. In accordance with the Surveillance Frequency Control Program SR 3.8.3.2 Verify lubricating oil inventory is 750 gal. In accordance with the Surveillance Frequency Control Program SR 3.8.3.3 Verify fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of. the Diesel Fuel Oil Testing Program. In accordance with the Diesel Fuel Oil Testing Program SR 3.8.3.4 Verify pressure in two starting air receivers is 435 psig or pressure in one starting air receiver is 610 psig, for each DG starting air subsystem.

In accordance with the Surveillance Frequency Control Program SR 3.8.3.5 Check for and remove accumulated water from each fuel oil storage tank. In accordance with the Surveillance Frequency Control Program SR 3.8.3.6 Not used. CALLAWAY PLANT 3.8-24 Amendment No. 202 3.8.4 DC Sources -Operating 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC Sources -Operating LCO The Train A and Train B DC electrical power subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One DC electrical power subsystem inoperable.

A.1 Restore DC electrical power subsystem to OPERABLE status. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months B. Require Action and Associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage is 130.2 V on float charge. In accordance with the Surveillance Frequency Control Program CALLAWAY 3.8-25 Amendment No. 202 3.8.4 DC Sources -Operating SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.4.2 Verify no visible corrosion at battery terminals and connectors.

Verify battery connection resistance is 69E-6 ohm for cell to cell connections and 69E-6 ohm for terminal connections.

In accordance with the Surveillance Frequency Control Program SR 3.8.4.3 Verify battery cells, cell plates, and racks show no visual indication of physical damage or abnormal deterioration that could degrade battery performance.

In accordance with the Surveillance Frequency Control Program SR 3.8.4.4 Remove visible terminal corrosion, verify battery cell to cell and terminal connections are clean and tight, and are coated with anti-corrosion material.

In accordance with the Surveillance Frequency Control Program SR 3.8.4.5 Verify battery connection resistance is 69E-6 ohm for cell to cell connections, and 69E-6 ohm for terminal connections.

In accordance with the Surveillance Frequency Control Program SR 3.8.4.6 Verify each battery charger supplies c 300 amps at c 130.2 V for c 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . In accordance with the Surveillance Frequency Control Program (contlnueo)

CALLAWAY PLANT 3.8-26 Amendment No. 202 3.8.4 DC Sources -Operating SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.4.7 -----------------------------

NOTES

1. The modified performance discharge test in SR 3.8.4.8 may be performed in lieu of the service test in SR 3.8.4.7. 2. This Surveillance shall not be performed in MODE 1, 2, 3, or4. Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test. In accordance with the Surveillance Frequency Control Program SR 3.8.4.8 -----------------------------

NOTE This Surveillance shall not be performed in MODE 1, 2,3, or 4. Verify battery capacity is 80% of the manufacturer's rating when subjected to a performance discharge test or a modified performance discharge test. In accordance with the Surveillance Frequency Control Program 18 months when battery shows degradation or has reached 85% of expected life CALLAWAY PLANT 3.8-27 Amendment No. 202 DC Sources -Shutdown 3.8.5 ELECTRICAL POWER SYSTEMS 3.8.5 DC Sources -Shutdown LCO The Train A or Train B DC electrical power subsystem shall be OPERABLE to support one train of the DC electrical power distribution subsystems required by LeO 3.8.10, "Distribution Systems -Shutdown."

MODES 5 and 6, During movement of irradiated fuel assemblies.

ACTIONS -----------------------------------------------------------

NOTE LCO 3.0.3 is not applicable. Required DC electrical power subsystem inoperable.

A.1 OR A.2.1 AND A.2.2 REQUIRED Declare affected required feature(s) inoperable.

Suspend CORE ALTERATIONS.

Suspend movement of irradiated fuel assemblies. Immediately Immediately Immediately ( continued)

CALLAWAY 3.8-28 Amendment No. 202 I 3.8.5 DC Sources -Shutdown ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Required DC electrical power subsystem inoperable. (continued)

A.2.3 A.2.4 Suspend operations involving positive reactivity additions that could result in loss of required SDM or boron concentration.

Initiate action to restore required DC electrical power subsystem to OPERABLE status. Immediately Immediately SURVEILLANCE SR SURVEILLANCE FREQUENCY

NOTE The following SRs are not required to be performed:

SR 3.8.4.6, SR 3.8.4.7, and SR 3.8.4.8. For DC sources required to be OPERABLE, the following SRs are applicable: I n accordance with applicable SRs SR 3.8.4.1 SR 3.8.4.2 SR 3.8.4.3 SR 3.8.4.4 SR 3.8.4.5 SR 3.8.4.6 SR 3,8.4,7 SR 3.8.4.8 CALLAWAY PLANT 3.8-29 Amendment 202 I Battery Cell Parameters 3.8.6 ELECTRICAL POWER SYSTEMS 3.8.6 Battery Cell Parameters LCO Battery cell parameters for Train A and Train B batteries shall be within the limits of Tabe 3.8.6-1.

When associated DC electrical power subsystems are required to be OPERABLE.

ACTIONS -----------------------------------------------------------

NOTE ----------------------------------------------------------.

Separate Condition entry is allowed for each battery. One or more batteries with one or more battery cell parameters not within Category A or B limits. COMPLETION REQUIRED ACTION TIME A1 Verify pilot cells electrolyte level and float voltage meet Table 3.8.6-1 Category C limits. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND A2 Verify battery cell parameters meet Table 3.8.6-1 Category C limits. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months AND Once per 7 days thereafter AND A3 Restore battery cell parameters to Category A and B limits of Table 3.8.6-1. 31 days (continued)

CALLAWAY 3.8-30 Amendment No. 202 I 3.8.6 Battery Cell Parameters ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and associated Completion Time of Condition A not met. One or more batteries with average electrolyte temperature of the representative cells < 60 OF. One or more batteries with one or more battery cell parameters not within Category C values. B.1 Declare associated battery inoperable.

Immediately SURVEILLANCE SU RVEI LLANCE SR 3.8.6.1 Verify battery cell parameters meet Table 3.8.6-1 In accordance Category A limits. with the Surveillance Frequency Control Program ( continued)

CALLAWAY PLANT 3.8-31 Amendment No. 202 3.8.6 Battery Cell Parameters SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.6.2 Verify battery cell parameters meet Table 3.8.6-1 Category B limits. In accordance with the Surveillance Frequency Control Program Once within 7 days after a battery discharge

< 110 V Once within 7 days after a battery overcharge

> 150 V SR 3.8.6.3 Verify average electrolyte temperature of representative cells is 2: 60°F. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT Amendment No. 202 3.8.6 Battery Cell Parameters TABLE 3.8.6-1 (PAGE 1 OF 1) BATTERY CELL PARAMETERS REQUIREMENTS PARAMETER CATEGORY A: LIMITS FOR EACH DESIGNATED PILOT CELL CATEGORY B: LIMITS FOR EACH CONNECTED CELL CATEGORYC:

ALLOWABLE LIMITS FOR EACH CONNECTED CELL Electrolyte Level > Minimum level indication mark, and :<::; 114 inch above maximum level indication mark(a) > Minimum level indication mark, and :<::; 114 inch above maximum level indication mark(a) Above top of plates, and not overflowing Float Voltage 2.13 V 2.13 V > 2.07 V Specific Gravity(b)(c) 1.200 1.195 AND Average of all connected cells > 1.205 Not more than 0.020 below average of all connected cells AND Average of all connected cells 1.195 It is acceptable for the electrolyte level to temporarily increase above the specified maximum during equalizing charges provided it is not overflowing. Corrected for electrolyte temperature and level. Level correction is not required, however, when battery charging is < 2 amps when on float charge. A battery charging current of < 2 amps when on float charge is acceptable for meeting specific gravity limits following a battery recharge, for a maximum of 7 days. When charging current is used to satisfy specific gravity requirements, specific gravity of each connected cell shall be measured prior to expiration of the 7 day allowance.

CALLAWAY 3.8-33 Amendment No. 202 I Inverters

-Operating 3.8.7 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Inverters

-

LCO 3.8.7 The required Train A and Train B inverters shall be APPLICABILITY:

MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required inverter inoperable.

A.1 ------------

NOTE Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems -Operating" with any vital bus de-energized.

Restore inverter to OPERABLE status. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 5. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours CALLAWAY PLANT 3.8-34 Amendment No. 202 I 3.8.7 Inverters

-Operating SURVEILLANCE REQUIREMENTS SR 3.8.7.1 Verify correct inverter voltage, and alignment to required AC vital buses.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.8-35 Amendment No. 202 3.8.8 Inverters

-Shutdown 3.8 ELECTRICAL POWER SYSTEMS 3.8.8 Inverters

-Shutdown LCO The Train A or Train B inverters shall be OPERABLE to support one train of the onsite Class 1 E AC vital bus electrical power distribution subsystems required by LeO 3.8.10, "Distribution Systems -Shutdown."

MODES 5 and 6, During movement of irradiated fuel assemblies.

ACTIONS -----------------------------------------------------------

NOTE LCO 3.0.3 is not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required inverters inoperable.

A.1 Declare affected required feature(s) inoperable.

Immediately OR A.2.1 Suspend CORE ALTERATIONS.

Immediately AND A.2.2 Suspend movement of irradiated fuel assemblies . Immediately ( continued)

CALLAWAY 3.8-36 Amendment No. 202 I 3.8.8 Inverters

-Shutdown ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required inverters inoperable. (continued)

A.2.3 A.2.4 Suspend operations involving positive reactivity additions that could result in loss of required SDM or boron concentration.

Initiate action to restore required inverters to OPERABLE status. Immediately Immediately SURVEILLANCE FREQUENCY SURVEILLANCE SR 3.8.8.1 Verify correct inverter voltage, and alignments to In accordance required AC vital buses. with the Surveillance Frequency Control Program Amendment 202 CALLAWAY PLANT Distribution Systems -Operating 3.8.9 3.8 ELECTRICAL POWER SYSTEMS 3.8.9 Distribution Systems -Operating LCO Train A and Train B AC, DC, and AC vital bus electrical power distribution subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One AC electrical power distribution subsystem inoperable.

A.1 Restore AC electrical power distribution subsystem to OPERABLE status. 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months 16 hours from discovery of failure to meet LCO B. One AC vital bus subsystem inoperable.

B.1 Restore AC vital bus subsystem to OPERABLE status. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 16 hours from discovery of failure to meet LCO (continued)

CALLAWAY 3.8-38 Amendment No. 202 I 3.8.9 Distribution Systems -Operating ACTIONS (continued) One DC electrical power distribution subsystem inoperable. Required Action and associated Completion Time not met. Two trains with inoperable distribution subsystems that result in a loss of safety function.

REQUIRED Restore DC electrical power distribution subsystem to OPERABLE status. Be in MODE 3. Be in MODE 5. E.1 Enter LCO 3.0.3. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 16 hours from discovery of failure to meet LCO 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours Immediately SURVEILLANCE SU RVEI SR Verify correct breaker alignments and voltage to required AC, DC, and AC vital bus electrical power distribution subsystems.

In accordance with the Surveillance Frequency Control Program CALLAWAY 3.8-39 Amendment No. 202 Distribution Systems -Shutdown 3.8.10 3.8 ELECTRICAL POWER SYSTEMS 3.8.10 Distribution Systems -Shutdown LCO The necessary portion of the Train A or Train B AC, DC, and AC vital bus electrical power distribution subsystems shall be OPERABLE to support one train of equipment required to be OPERABLE.

MODES 5 and 6, During movement of irradiated fuel assemblies.

ACTIONS -----------------------------------------------------------

NOT E LCO 3.0.3 is not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required AC, DC, or AC vital bus electrical power distribution subsystems inoperable.

A.1 OR Declare associated supported required feature(s) inoperable.

Immediately A.2.1 Suspend CORE ALTERATIONS.

Immediately AND A.2.2 Suspend movement of irradiated fuel assemblies.

Immediately (continued)

CALLAWAY 3.8-40 Amendment No. 202 I Distribution Systems -Shutdown 3.8.10 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required AC, DC, or AC vital bus electrical power distribution subsystems inoperable. (continued)

A.2.3 Suspend operations involving positive reactivity additions that could result in loss of required SDM or boron concentration.

Immediately A.2.4 Initiate actions to restore required AC, DC, and AC AND A.2.5 vital bus electrical power distribution subsystems to OPERABLE status. Declare associated required residual heat removal subsystem(s) inoperable and not in operation.

Immediately Immediately SURVEILLANCE SR Verify correct breaker alignments and voltage to required AC, DC, and AC vital bus electrical power distribution subsystems.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT Amendment 202 3.9.1 Boron Concentration SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.1.1 Verify boron concentration is within the limit. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.9-2 Amendment No. 202 3.9.2 Unborated Water Source Isolation Valves SURVEILLANCE REQUIREMENTS SR 3.9.2.1 Verify each valve that isolates unborated water sources is secured in the closed position.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.9-4 Amendment No. 202 3.9.3 Nuclear Instrumentation SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.3.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.9.3.2 ---------------------------------

NOTE Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.9-6 Amendment No. 202 3.9.4 Containment Penetrations SURVEILLANCE REQUIREMENTS SLI RVEI LLANCE FREQUENCY SR 3.9.4.1 Verify each required containment penetration is in the required status. In accordance with the Surveillance Frequency Control Program SR 3.9.4.2 ---------------------------------

NOTE Only required for an open equipment hatch. Verify the capability to install the equipment hatch. In accordance with the Surveillance Frequency Control Program SR 3.9.4.3 Verify each required containment purge isolation valve actuates to the isolation position on a manual actuation signal. In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.9-8 Amendment No. 202 3.9.5 RHR and Coolant Circulation

-High Water Level ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RHR loop requirements not met. (continued)

A.3 AND AA Initiate action to satisfy RHR loop requirements.

Close all containment penetrations providing direct access from containment atmosphere to outside atmosphere.

Immediately 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months SURVEILLANCE SR 3.9.5.1 Verify one RHR loop is in operation and circulating reactor coolant at a flow rate of 2 1000 gpm. I n accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.9-10 Amendment 202 3.9.6 RHR and Coolant Circulation

-Low Water Level ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. No RHR loop in operation.

B.1 AND B.2 AND B.3 Suspend operations that would cause introduction into the RCS, coolant with boron concentration less than required to meet the boron concentration of LeO 3.9.1. Initiate action to restore one RHR loop to operation.

Close all containment penetrations providing direct access from containment atmosphere to outside atmosphere.

Immediately Immediately 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.9.6.1 Verify one RHR loop is in operation and circulating reactor coolant at a flow rate of?: 1000 gpm. FREQUENCY In accordance with the Surveillance Frequency Control Program CALLAWAY PLANT 3.9-12 Amendment No. 202 3.9.6 RHR and Coolant Circulation

-Low Water Level SURVEILLANCE REQUIREMENTS (continued)

SR Verify correct breaker alignment and indicated power In accordance available to the required RHR pump that is not in operation.

with the CALLAWAY 3.9-13 Amendment No. 202 3.9.7 Refueling Pool Water Level 3.9 REFUELING OPERATIONS 3.9.7 Refueling Pool Water Level LCO Refueling pool water level shall be maintained

2 23 ft above the top of reactor vessel flange. APPLICABILITY:

During movement of irradiated fuel assemblies within containment.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Refueling pool water level not within limit. A.1 Suspend movement of irradiated fuel assemblies within containment.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.9.7.1 Verify refueling pool water level is :2 23 ft above the top of reactor vessel flange. FREQUENCY In accordance with the Surveillance Frequency Control Program CALLAWAY 3.9-14 Amendment No. 202 5.5 Programs and Manuals 5.5 Programs and Manuals 5.5.17 Control Room Envelope Habitability Program (continued) The quantitative limits on unfiltered air inleakage into CRE and CBE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph

c. The unfiltered air inleakage limit for radiological challenges is the inleakage -now rate assumed in the licensing basis analyses of DBA consequences.

Unfiltered air leakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE and CBE unfiltered inleakage, and measuring CRE pressure and assessing CRE and CBE as required by paragraphs c and d, respectively.

5.5.18 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies.

The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met. The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1. The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program. CALLAWAY PLANT Amendment 202 UNITED NUCLEAR REGULATORY WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 202 TO FACILITY OPERATING LICENSE NO. NPF-30 UNION ELECTRIC COMPANY CALLAWAY PLANT. UNIT 1 DOCKET NO. 50-483

1.0 INTRODUCTION

By letter dated August 5, 2010 (Reference 1), as supplemented by letters dated March May 3, and July 25, 2011 (References 2, 3, and 4, respectively), Union Electric Company the licensee) proposed changes to the Technical Specifications (TSs) for Callaway Plant, Unit The supplemental letters dated March 23, May 3, and July 25, 2011, provided information that clarified the application, did not expand the scope of the application as noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC) staff's proposed no significant hazards consideration determination as published in the Register on January 11, 2011 (76 FR The amendment would revise the TSs by relocating specific surveillance frequencies to licensee-controlled program with the guidance of Nuclear Energy Institute (NEI) 04-10, Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Frequencies" (Reference 5). The requested change is the adoption of TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Initiative 5b" (Reference 6). When implemented, TSTF-425 relocates most periodic of TS surveillances to a licensee-controlled program, the Surveillance Frequency Program (SFCP), and provides requirements for the new program in the Administrative section of the TSs. All surveillance frequencies can be relocated Frequencies that reference other approved programs for the specific interval (such as the In-Service Testing Program or the Primary Containment Leakage Rate Testing Program);

Frequencies that are purely event-driven (e.g., "each time the control rod is withdrawn to the 'full out' position");

Enclosure 2

-2

Frequencies that are event-driven, but have a time component for performing the surveillance on a one-time basis once the event occurs (e.g., "within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after thermal power reaching;;::

95% RTP [rated thermal power]");

and

Frequencies that are related to specific conditions (e.g., battery degradation, age and capacity) or conditions for the performance of a surveillance requirement (e.g., "drywell to suppression chamber differential pressure decrease").

A new program is added to the administrative controls of TS Section 5 as TS 5.5.8, "Surveillance Frequency Control Program." The new program is called the SFCP and describes the requirements for the program to control changes to the relocated surveillance frequencies.

The TS Bases for each of the affected surveillance requirements are revised to state that the frequency is set in accordance with the SFCP. Some surveillance requirements Bases do not contain a discussion of the frequency.

In these cases, the Bases describing the current frequency were added to maintain consistency with the Bases for similar surveillances.

These instances are noted in the markup along with the source of the text. The proposed licensee changes to the Administrative Controls of the TSs to incorporate the SFCP include a specific reference to Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," Revision 1 (Reference

5) as the basis for making any changes to the surveillance frequencies once they are relocated out of the TSs. By letter dated September 19,2007, the NRC staff approved NEI 04-10, Revision 1 (Reference 7), as acceptable for referencing in licensing actions to the extent specified and under the limitations delineated in NEI 04-10, and the safety evaluation providing the basis for NRC acceptance of NEI 04-10.

2.0 REGULATORY EVALUATION

In the "Final Policy Statement:

Technical Specifications for Nuclear Power Plants" published in the Federal Register on July 22, 1993 (58 FR 39132), the NRC addressed the use of Probabilistic Safety Analysis (PSA, currently referred to as Probabilistic Risk Assessment or PRA) in the Standard Technical Specifications (STS). In discussing the use of PSA in Nuclear Power Plant Technical Specifications, the Commission wrote in part: 1 The Commission believes that it would be inappropriate at this time to allow requirements which meet one or more of the first three criteria [of 10 CFR 50.36] to be deleted from Technical Specifications based solely on PSA (Criterion 4). However, if the results of PSA indicate that Technical Specifications can be relaxed or removed, a deterministic review will be performed

.... The Commission Policy in this regard is consistent with its Policy Statement on 'Safety Goals for the operation of Nuclear Power Plants,' 51 FR 30028, published on August 21, 1986. The Policy Statement on Safety Goals states in part, ,,* *

probabilistic results should also be reasonably balanced and supported through use of deterministic arguments.

In this way, judgments can be 1 The bracketed text is in the Federal Register.

-3 made * *

about the degree of confidence to be given these [probabilistic]

estimates and assumptions.

This is a key part of the process for determining the degree of regulatory conservatism that may be warranted for particular decisions.

This defense-in-depth approach is expected to continue to ensure the protection of public health and safety." The Commission will continue to use PSA, consistent with its policy on Safety Goals, as a tool in evaluating specific line-item improvements to Technical Specifications, new requirements, and industry proposals for risk-based Technical Specification changes. Approximately 2 years later, the NRC provided additional detail concerning the use of PRA in the "Final Policy Statement:

Use of Probabilistic Risk Assessment in Nuclear Regulatory Activities" published in the Federal Register on August 16, 1995 (60 FR 42622). The Commission, in discussing the deterministic and probabilistic approach to regulation, and the Commission's extension and enhancement of traditional regulation, wrote in part: The Commission believes that an overall policy on the use of PRA methods in nuclear regulatory activities should be established so that the many potential applications of PRA can be implemented in a consistent and predictable manner that would promote regulatory stability and efficiency.

In addition, the Commission believes that the use of PRA technology in NRC regulatory activities should be increased to the extent supported by the state-of-the-art in PRA methods and data and in a manner that complements the NRC's deterministic approach.

The Commission provided its new policy, stating: Although PRA methods and information have thus far been used successfully in nuclear regulatory activities, there have been concerns that PRA methods are not consistently applied throughout the agency, that sufficient agency PRAlstatistics expertise is not available, and that the Commission is not deriving full benefit from the large agency and industry investment in the developed risk assessment methods. Therefore, the Commission believes that an overall policy on the use of PRA in nuclear regulatory activities should be established so that the many potential applications of PRA can be implemented in a consistent and predictable manner that promotes regulatory stability and efficiency.

This policy statement sets forth the Commission's intention to encourage the use of PRA and to expand the scope of PRA applications in all nuclear regulatory matters to the extent supported by the state-of-the-art in terms of methods and data. Implementation of the policy statement will improve the regulatory process in three areas: Foremost, through safety decision making enhanced by the use of PRA insights; through more efficient use of agency resources; and through a reduction in unnecessary burdens on licensees.

-4 Therefore, the Commission adopts the following policy statement regarding the expanded NRC use of PRA: The use of PRA technology should be increased in all regulatory matters to the extent supported by the state-of-the-art in PRA methods and data and in a manner that complements the NRC's deterministic approach and supports the NRC's traditional defense-in-depth philosophy. PRA and associated analyses (e.g., sensitivity studies, uncertainty analyses, and importance measures) should be used in regulatory matters, where practical within the bounds of the state-of-the-art, to reduce unnecessary conservatism associated with current regulatory requirements, regulatory guides, license commitments, and staff practices.

Where appropriate, PRA should be used to support the proposal for additional regulatory requirements in accordance with [Title 10 of the Code of Federal Regulations (10 CFR)] 50.109 (Backfit Rule). Appropriate procedures for including PRA in the process for changing regulatory requirements should be developed and followed.

It is, of course, understood that the intent of this policy is that existing rules and regulations shall be complied with unless these rules and regulations are revised. PRA evaluations in support of regulatory decisions should be as realistic as practicable and appropriate supporting data should be publicly available for review. The Commission's safety goals for nuclear power plants and subsidiary numerical objectives are to be used with appropriate consideration of uncertainties in making regulatory judgments on the need for proposing and backfitting new generic requirements on nuclear power plant licensees.

In 10 CFR 50.36, "Technical specifications," the NRC established its regulatory requirements related to the content of TSs. Pursuant to 10 CFR 50.36, TS are required to include items in the following five specific categories related to station operation:

(1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation; (3) surveillance requirements; (4) design features; and (5) administrative controls.

The regulations in 10 CFR 50. 36(c)(3) , "Surveillance requirements," state that, Surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. These categories will remain in the TSs. The new TS SFCP provides the necessary administrative controls to require that surveillances relocated to the SFCP are conducted at a frequency to assure that the necessary quality of systems and components is maintained, that

-5 facility operation will be within safety limits, and that the limiting conditions for operation will be met. Changes to surveillance frequencies in the SFCP are made using the methodology contained in NEI 04-10, including qualitative considerations, results of risk analyses, sensitivity studies and any bounding analyses, and recommended monitoring of structures, systems, and components (SSCs), and are required to be documented.

Furthermore, changes to frequencies are subject to regulatory review and oversight of the SFCP implementation through the rigorous NRC review of safety-related SSC performance provided by the Reactor Oversight Program. Licensees are required by TSs to perform surveillance test, calibration, or inspection on specific safety-related system equipment (e.g., reactivity control, power distribution, electrical, and instrumentation) to verify system operability.

Surveillance frequencies, currently identified in TSs, are based primarily upon deterministic methods such as engineering judgment, operating experience, and manufacturer's recommendations.

The licensee's use of NRC-approved methodologies identified in NEI 04-10 provides a way to establish risk-informed surveillance frequencies that complement the deterministic approach and support the NRC's traditional defense-in-depth philosophy.

The licensee's SFCP ensures that surveillance requirements specified in the TSs are performed at intervals sufficient to assure the above regulatory requirements are met. Existing regulatory requirements, such as 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants" (the Maintenance Rule), and Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," to 10 CFR Part 50 (corrective action program), require licensee monitoring of surveillance test failures and implementing corrective actions to address such failures.

One of these actions may be to consider increasing the frequency at which a surveillance test is performed.

In addition, the SFCP implementation guidance in NEI 04-10 requires monitoring the performance of SSCs for which surveillance frequencies are decreased to assure reduced testing does not adversely impact the SSCs. These requirements, and the monitoring required by NEI 04-10, ensure that surveillance frequencies are sufficient to assure that the requirements of 10 CFR 50.36 are satisfied and that any performance deficiencies will be identified and appropriate corrective actions taken. NRC Regulatory Guide (RG) 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" (Reference 8), describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed permanent licensing-basis changes by considering engineering issues and applying risk insights.

This regulatory guide also provides risk acceptance guidelines for evaluating the results of such evaluations.

NRC RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications" (Reference 9), describes an acceptable risk-informed approach specifically for assessing proposed permanent TS changes. NRC RG 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (Reference 10), describes an acceptable approach for determining whether the quality of the PRA, in total or the parts that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decision making for light-water reactors.

-3.0 TECHNICAL EVALUATION 3.1 Proposed Changes The licensee's adoption of TSTF-425, Revision 3, for Callaway provides for administrative relocation of applicable surveillance frequencies, and for the addition of the SFCP to the administrative controls of TSs. TSTF-425, Revision 3, also requires the application of NEI 04-10 for any changes to surveillance frequencies within the SFCP. The licensee's application for the changes proposed in TSTF-425, Revision 3, included documentation regarding the PRA technical adequacy consistent with the requirements of RG 1.200, Revision 1 (Reference 10). In accordance with NEI 04-10, PRA methods are used, in combination with plant performance data and other considerations, to identify and justify modifications to the surveillance frequencies of equipment at nuclear power plants. This is in accordance with guidance provided in RG 1.174 (Reference

8) and RG 1.177 (Reference

9) in support of changes to surveillance test intervals.

In its letter dated August 5,2010, as supplemented by letter dated May 3, 2011 (References 1 and 3, respectively), the licensee proposed to remove the following surveillance frequencies and relocate them to the licensee-controlled program: 3.1.1.1 3.3.2.3 3.3.8.1 3.4.12.2 3.5.5.1 3.7.9.3 3.8.3.4 3.1.2.1 3.3.2.4 3.3.8.2 3.4.12.3 3.6.2.2 3.7.10.1 3.8.3.5 3.1.4.1 3.3.2.5 3.3.8.3 3.4.12.4 3.6.3.1 3.7.10.3 3.8.4.1 3.1.4.2 3.3.2.6 3.3.8.4 3.4.12.5 3.6.3.2 3.7.11.1 3.8.4.2 3.1.5.1 3.3.2.7 3.3.8.5 3.4.12.6 3.6.3.3 3.7.13.1 3.8.4.3 3.1.6.2 3.3.2.8 3.3.9.1 3.4.12.8 3.6.3.6 3.7.13.3 3.8.4.4 3.1.6.3 3.3.2.9 3.3.9.2 3.4.12.9 3.6.3.7 3.7.13.4 3.8.4.5 3.1.8.2 3.3.2.10 3.3.9.3 3.4.13.1 3.6.3.8 3.7.13.5 3.8.4.6 3.1.8.3 3.3.2.11 3.3.9.4 3.4.13.2 3.6.4.1 3.7.15.1 3.8.4.7 3.1.8.4 3.3.2.12 3.3.9.5 3.4.14.1 3.6.5.1 3.7.16.1 3.8.4.8 3.1.9.1 3.3.2.13 3.3.9.6 3.4.14.2 3.6.6.1 3.7.18.1 3.8.6.1 3.2.1.1 3.3.2.14 3.4.1.1 3.4.15.1 3.6.6.2 3.7.19.2 3.8.6.2 3.2.1.2 3.3.3.1 3.4.1.2 3.4.15.2 3.6.6.3 3.8.1.1 3.8.6.3 3.2.2.1 3.3.3.2 3.4.1.3 3.4.15.3 3.6.6.5 3.8.1.2 3.8.7.1 3.2.3.1 3.3.4.1 3.4.1.4 3.4.15.4 3.6.6.6 3.8.1.3 3.8.8.1 3.2.4.1 3.3.4.2 3.4.2.1 3.4.15.5 3.6.6.7 3.8.1.4 3.8.9.1 3.2.4.2 3.3.4.3 3.4.3.1 3.4.16.1 3.6.6.8 3.8.1.5 3.8.10.1 3.3.1.1 3.3.5.1 3.4.4.1 3.4.16.2 3.6.7.1 3.8.1.6 3.9.1.1 3.3.1.2 3.3.5.2 3.4.5.1 3.5.1.1 3.6.7.2 3.8.1.7 3.9.2.1 3.3.1.3 3.3.5.3 3.4.5.2 3.5.1.2 3.7.2.2 3.8.1.10 3.9.3.1 3.3.1.4 3.3.5.4 3.4.5.3 3.5.1.3 3.7.3.2 3.8.1.11 3.9.3.2 3.3.1.5 3.3.6.1 3.4.6.1 3.5.1.4 3.7.5.1 3.8.1.12 3.9.4.1 3.3.1.6 3.3.6.2 3.4.6.2 3.5.1.5 3.7.5.3 3.8.1.13 3.9.4.2 3.3.1.7 3.3.6.3 3.4.6.3 3.5.2.1 3.7.5.4 3.8.1.14 3.9.4.3 3.3.1.8 3.3.6.4 3.4.7.1 3.5.2.2 3.7.6.1 3.8.1.15 3.9.5.1 3.3.1.9 3.3.6.5 3.4.7.2 3.5.2.3 3.7.7.1 3.8.1.16 3.9.6.1 3.3.1.10 3.3.6.6 3.4.7.3 3.5.2.5 3.7.7.2 3.8.1.17 3.9.6.2 3.3.1.11 3.3.7.1 3.4.8.1 3.5.2.6 3.7.7.3 3.8.1.18 3.9.7.1 3.3.1.13 3.3.7.2 3.4.8.2 3.5.2.7 3.7.8.1 3.8.1.19 3.3.1.14 3.3.7.3 3.4.9.1 3.5.2.8 3.7.8.2 3.8.1.20 3.3.1.16 3.3.7.4 3.4.9.2 3.5.4.1 3.7.8.3 3.8.1.21 3.3.2.1 3.3.7.5 3.4.11.1 3.5.4.2 3.7.9.1 3.8.3.1 3.3.2.2 3.3.7.6 3.4.12.1 3.5.4.3 3.7.9.2 3.8.3.2

-7 The table of contents was modified to reflect the changes above. This affected pages 1, 2, 3, and 4. In addition, the licensee proposed to modify the Administrative Controls section of the Callaway TSs by adding new TS 5.5.18, which would state, 5.5.18 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies.

The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met. The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1. The provisions of Surveillance ReqUirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program. RG 1.177 Five Key Safety Principles RG 1.177 identifies five key safety principles required for risk-informed changes to TSs. Each of these principles is addressed by the industry methodology document, NEI 04-10. The Proposed Change Meets Current Regulations The regulations in 10 CFR 50.36(c)(3) require that TSs will include surveillances.

NE104-10 provides guidance for relocating the surveillance frequencies "from the TSs to a controlled program by providing an NRC-approved methodology for control of the surveillance frequencies.

The surveillances themselves would remain in the TSs. as required by 10 CFR 50.36(c)(3).

This change is consistent with other NRC-approved TS changes in which the surveillance frequencies are relocated to licensee-controlled documents, such as surveillances performed in accordance with the In-service Testing Program or the Primary Containment Leakage Rate Testing Program. Thus, this proposed change meets the first key safety principle of RG 1.177 by complying with current regulations.

-The Proposed Change Is Consistent With the Defense-in-Depth Philosophy Consistency with the defense-in-depth philosophy, the second key safety principle of RG 1.177, is maintained if: A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation. Over-reliance on programmatic activities to compensate for weaknesses in plant design is avoided. System redundancy, independence, and diversity are preserved commensurate with the expected frequency, consequences of challenges to the system, and uncertainties (e.g., no risk outliers).

Because the scope of the proposed methodology is limited to revision of surveillance frequencies, the redundancy, independence, and diversity of plant systems are not impacted. Defenses against potential common cause failures are preserved, and the potential for the introduction of new common cause failure mechanisms is assessed. Independence of barriers is not degraded. Defenses against human errors are preserved. The intent of the General Design Criteria in 10 CFR Part 50, Appendix A, is maintained, TSTF-425, Revision 3, requires the application of NEI 04-10 for any changes to surveillance frequencies within the SFCP, NEI 04-10 uses both the core damage frequency (CDF) and the large early release frequency (LERF) metrics to evaluate the impact of proposed changes to surveillance frequencies.

The guidance of RG 1.174 and RG 1.177 for changes to CDF and LERF is achieved by evaluation using a comprehensive risk analysis, which assesses the impact of proposed changes including contributions from human errors and common cause failures.

Defense-in-depth is also included in the methodology explicitly as a qualitative consideration outside of the risk analysis, as is the potential impact on detection of component degradation that could lead to an increased likelihood of common cause failures.

Both the quantitative risk analysis and the qualitative considerations assure a reasonable balance of defense-in-depth is maintained to ensure protection of public health and safety, satisfying the second key safety principle of RG 1.177. The Proposed Change Maintains Sufficient Safety Margins The engineering evaluation that will be conducted by the licensee under the SFCP when frequencies are revised will assess the impact of the proposed frequency change with the principle that sufficient safety margins are maintained.

The guidelines used for making that assessment will include ensuring the proposed surveillance test frequency change is not in

-9 conflict with approved industry codes and standards or adversely affects any assumptions or inputs to the safety analysis, or, if such inputs are affected, justification is provided to ensure sufficient safety margin will continue to exist. The design, operation, testing methods, and acceptance criteria for SSCs, specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis (including the Updated Final Safety Analysis Report and bases to TS), since these are not affected by changes to the surveillance frequencies.

Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis. Thus, safety margins are maintained by the proposed methodology, and the third key safety principle of RG 1.177 is satisfied. When Proposed Changes Result in an Increase in Core Damage Freguency or Risk. the Increases Should Be Small and Consistent With the Intent of the Commission's Safety Goal Policy Statement RG 1.177 provides a framework for evaluating the risk impact of proposed changes to surveillance frequencies.

This requires the identification of the risk contribution from impacted surveillances, determination of the risk impact from the change to the proposed surveillance frequency, and performance of sensitivity and uncertainty evaluations.

TSTF-425, Revision 3, requires application of NEI 04-10 in the SFCP. NEI 04-10 satisfies the intent of RG 1.177 requirements for evaluating the change in risk, and for assuring that such changes are small. 3.2.4.1 Quality of the PRA The quality of the Callaway PRA is compatible with the safety implications of the proposed TS change and the role the PRA plays in justifying the change. That is, the more the potential change in risk or the greater the uncertainty in that risk from the requested TS change, or both, the more rigor that must go into ensuring the quality of the PRA. The licensee used RG 1.200 to address the technical adequacy of the Callaway PRA. RG 1.200 is NRC's developed regulatory guidance, which in revision one endorsed with comments and qualifications the use of the American Society of Mechanical Engineers (ASME) RA-Sb-2005, "Addenda to ASME RA-S-2002 Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications" (Reference 11), NEI 00-02, Revision 1, "PRA Peer Review Process Guidelines" (Reference 12), and NEI 05-04, Revision 0, "Process for Performing Follow-on PRA Peer Reviews Using the ASME PRA Standard" (Reference 13). The licensee has performed an assessment of the PRA models used to support the SFCP against the requirements of RG 1.200 to assure that the PRA models are capable of determining the change in risk due to changes to surveillance frequencies of SSCs, using plant-specific data and models. Capability category II of ASME RA-Sb-2005 was applied as the standard, and any identified deficiencies to those requirements are assessed further to determine any impacts to proposed decreases to surveillance frequencies, including by the use of sensitivity studies where appropriate. (The NRC staff notes that in Revision 2, RG 1.200 endorsed with comments and qualifications an updated combined standard which includes requirements for fire, seismic, and other external events PRA models. The existing internal events standard was subsumed

-into the combined standard, but the technical requirements are essentially unchanged.

Since NEI 04-10, Revision 1, specifically identified the use of RG 1.200, Revision 1, to assess the internal events standard, the licensee's approach is reasonable and consistent with the approved methodology.)

The licensee identified that there are five open significant facts and observations (F&Os) remaining from its 2000 Industry PRA Peer Review. In 2006, a consultant review of the Callaway internal events PRA model was conducted using the ASME PRA Standard (Reference 13), which identified a number of supporting requirements which were not met at capability category II. The licensee provided a summary description and disposition of these items in Attachment 2, Tables 1 and 2, of its letter dated August 5,2010 (Reference 1), and provided additional information in its letter dated March 23, 2011 (Reference 3), in response to the NRC's staff request for additional information dated December 17, 2010 (Reference 14). The staff reviewed the licensee's assessment of each of these identified deficiencies.

The staff assessed these findings to determine whether they may be addressed and dispositioned for each surveillance frequency evaluation per the NEI 04-10 methodology.

The staff's assessment is provided below. 2000 Peer Review Findings IE-7: Two issues identified for interfacing systems loss-of-coolant accident (ISLOCA) events were that only containment bypass locations were addressed, and that quantification of these events did not correlate variables for basic events. The licensee does not agree with the first peer review issue and cited supporting requirement IE-A2 of the American Nuclear Society (ANS)/ASME PRA Standard which requires inclusion of events resulting in " ... uncontrolled loss of core coolant outside containment.

.. II The licensee further identified that low-pressure piping failures inside containment are adequately addressed by considering potential impacts of the piping failure on emergency core cooling system functionality.

The NRC staff concludes that the licensee's dispOSition of this issue is acceptable.

For the second issue regarding correlation of ISLOCA variables, the licensee has developed a revised ISLOCA model which addresses this issue, and stated that the updated analYSis would be applied for any evaluation of ISLOCA risk. The licensee confirmed that this revised ISLOCA model is completed and available to use for sensitivity studies. ST-1: State-of-the-art analyses were not used for determining the probability of failure of pressure piping for ISLOCA events. The licensee has developed a revised ISLOCA model which addresses this issue, and stated that the updated analysis would be applied for any evaluation of ISLOCA risk. The licensee confirmed that this revised ISLOCA model is completed and available to use for sensitivity studies. TH-3: The peer review recommended development of guidance for success criteria, which is considered a documentation issue which has no impact on this application.

L2-1: Containment isolation failure and internal flood initiators are not addressed in the LERF calculations.

The licensee stated that these items would be addressed by developing separate PRA analyses if required for evaluation of a speCific surveillance frequency change as a sensitivity analysis per NEI 04-10.

-11 L2-3: LERF calculations use split fractions to determine overall probability of a plant damage state, with no obvious relation of the split fractions to elementary phenomena or system failures.

The licensee stated that split fractions involving mitigating system failures were explicitly modeled, and that other split fractions are based on plant design features which do not usually change. 2006 Consultant Review Findings IE-3: A system-by-system review to identify initiating events was not found in the documentation.

The licensee stated that this review has now been completed and documented with no new initiators identified.

This deficiency can be addressed per the methodology of NEI04-10.

IE-4: Events occurring while the unit was not at power were not addressed in the initiating events analysis.

The licensee stated that such events have now been considered, and no new initiators were identified.

This deficiency can be addressed per the methodology of NEI 04-10. IE-6: Operating experience for Callaway was not reviewed for initiating event precursors.

The licensee stated that Callaway's experience has now been reviewed, and no new initiators were identified.

This deficiency can be addressed per the methodology of NEI 04-10. IE-?: Uncertainty bounds are not provided for initiating events. The licensee identified that uncertainty bounds have since been determined for the updated model, and so are available as needed to support this application.

Therefore, this deficiency can be addressed per the methodology of NEI 04-10. IE-8: Recovery events for loss of component cooling water and loss of service water are credited without sufficient analysis or data. The licensee discussed the basis for these events, which was a review of applicable cutsets by an individual with both PRA and system engineering experience and judgment as to the timeframes for repairs. A sensitivity study was also performed which showed that CDF increased by less than 2 percent if no credit is taken for any repairs. This deficiency is not significant, and can be addressed per the methodology of NEI04-10.

IE-lO: Plant availability is not factored into the initiating event frequencies.

The licensee identified that the updated model has accounted for plant availability, and discussed the results of a sensitivity study on the loss-of-offsite power initiator which showed only a small impact on the results. Therefore, this deficiency can be addressed per the methodology of NEI 04-10. IE-12: A comparison of the frequency of support system initiating event frequencies generated by fault tree models to generic data sources was not documented.

The licensee stated that such comparisons for all initiators has been completed and documented, and no outlier frequencies were identified.

Therefore, this deficiency can be addressed per the methodology of NEI 04-10. I E-13: A deficiency related to the age and documentation of the ISLOCA analysis was dispositioned by the licensee with a revised analysis for the updated model.

-12 IE-14: The initiating events documentation resides over several documents, which is not conducive to updates or peer reviews. The licensee stated that this is a documentation issue which has no effect on the application.

AS-2: The manual generation of transfer sequences, rather than using an event-tree structure, introduces the possibility of errors, although no errors were identified.

The licensee identified an extensive review of these sequences with no errors identified, and therefore has no impact on this application.

AS-1/AS-3/AS-5/AS-7:

Initiating event impacts may not be correctly captured.

The licensee provided a detailed description of the deficiencies in the model, its investigation of the scope of the deficiencies, and sensitivity studies to bound the potential impact. The licensee has concluded that where there are actual model logic errors, the impact is not significant based on sensitivity studies showing only a 1 percent increase in CDF and on the fact that the errors do not appear in cutsets reviewed for the baseline PRA model. In other cases involving support system impacts for initiating events involving service water and component cooling water initiators, and room cooling for the switchgear rooms, the licensee's investigation found that the existing model was correct or conservative, and that the finding was not valid. AS-4: The reactor coolant pump (RCP) sealloss-of-coolant accident (LOCA) model is out of date. The licensee provided a comparison of the probability of leakage for the existing model (based on WCAP-1 0541, "Reactor Coolant Pump Seal Performance Following a Loss of All AC [Alternating Current) Power" (Reference

15) and the currently accepted model (Westinghouse Owners' Group WOG2000).

A sensitivity study to the baseline PRA model to changes in the RCP seal failure probability was also provided which demonstrated the relative insensitivity of CDF. Therefore, this deficiency can be addressed per the methodology of NEI 04-10. SC-1: Success criteria are not documented in a single location.

The licensee identified this finding as a documentation issue which has no effect on the application.

SC-2: A check on the reasonableness of the success criteria was not documented.

The licensee identified comparisons with other similar plant designs, and stated that this finding is a documentation issue which has no effect on the application.

SY-1: Main feedwater system dependencies on instrument air are not modeled, and the specific data used for undeveloped events in the instrument air model could not be verified.

The licensee provided a sensitivity study using data from NUREG/CR-6928, "Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants" (Reference 16), for the instrument air system failure probability, and increasing the signal failure probabilities in undeveloped events by 10 percent. The result showed only a 0.59 percent increase in CDF, demonstrating that the results are not sensitive to this deficiency.

Therefore, this deficiency can be addressed per the methodology of NEI 04-10. SY-2: Common cause failure probabilities require updating, and battery chargers and breakers should be included in the scope of common cause failures modeled. The licensee identified sensitivity studies which demonstrate that the impact of these findings is not significant.

Specifically, the missing common cause failure modes were added to the model with no

-13 discernable change in the results, and the existing common cause failure events were increased by 10 percent with only a 3.54 percent increase in CDF. The NRC staff agrees that the impact of this finding is minimal and, therefore, this deficiency can be addressed per the methodology of NEI 04-10. HR-1/HR-2/HR-3:

These findings identify deficiencies in the documentation of human reliability analyses, including documentation of "reasonableness" checks and key sources of uncertainty.

The licensee identified this finding as a documentation issue which has no effect on the application.

DA-1: Documentation of data collection is lacking. The licensee identified this finding as a documentation issue which has no effect on the application.

DA-2: Component groupings did not consider the characteristics of usage. The licensee stated that the updated PRA model corrected this deficiency, and component grouping are similar to the existing model. Therefore, the impact is not expected to be significant and, therefore, this deficiency can be addressed per the methodology of NEI 04-10. DA-3: No justification was provided for the probabilities applied to three specific basic events. The licensee identified a sensitivity analysis which doubled the probabilities resulting in a 0.03 percent increase in CDF, and further stated the issues were documentation related only. Therefore, this deficiency can be addressed per the methodology of NEI 04-10. IF-1/IF-2/IF-3/IF-4/IF-5/IF-6:

The internal flood analysis has findings in the areas of treatment of operator responses, use of plant-specific information in pipe-break frequencies, screening criteria, and lack of treatment of LERF. The licensee is developing a revised internal flooding model which addresses these deficiencies.

Portions of this model, especially initiating event frequencies, are completed and can be directly used in the existing internal flood model to disposition items related to initiating events (IF-1, IF-3, IF-4, and IF-5) until the new internal flooding model is fully complete and able to be used. Item IF-2 deals with quantitative screening criteria, and the licensee identified that no areas were screened, but instead had been conservatively evaluated.

Internal flood areas will be reviewed for each specific surveillance frequency evaluation to determine if additional flood areas need to be evaluated.

Therefore, this deficiency can be addressed per the methodology of NEI 04-10. Item IF-6 addresses the lack of calculation of LERF for internal flooding events, and the licensee has identified that its existing CDF results will be evaluated using a conditional probability of a large early release to evaluate the increase in LERF for internal floods. Therefore, this deficiency can be addressed per the methodology of NEI 04-10. QU-1: The "state-of-knowledge" correlation is not included in the current PRA. The licensee stated that the correlation can be addressed for a given surveillance interval evaluation as necessary.

Therefore, this deficiency can be addressed per the methodology of NEI 04-10.

-14 QU-2: Support system initiating events may have missing dependencies.

The licensee stated that the peer review team identified that the supporting requirement from the standard (QU-B9) was met at capability category II and, therefore, this item is not an actual gap. QU-5: A review of non-significant sequences and cutsets was not documented.

The licensee stated that all sequences and non-significant cutsets are periodically reviewed as part of the normal PRA model update process or for specific applications and, therefore, this issue is a documentation issue which has no effect on the application.

QU-8: Separate quantification processes are applied to internal events, ISLOCA, and internal flooding, and should be considered to be integrated into a single process. The licensee stated that the risk contribution from each source is able to be determined, and so there is no effect on the application.

QU-9/QU-10/QU-11/QU-12:

These findings identify deficiencies in the documentation of model quantification, including documentation of key assumptions sources of uncertainty, limitations, and definitions of "significant." The licensee identified this finding as a documentation issue which has no effect on the application.

LE-1: Some LERF contributors, identified in Table 4.5.9-3 of the standard, may not be addressed in the PRA model. The licensee identified that the finding was related to the lack of treatment of undetected containment structural integrity issues, and also identified a minimal impact on LERF. Other deficiencies related to the split fractions for induced steam generator tube rupture and high-pressure melt ejection phenomena were determined to be considered in the current LERF model. Therefore, this deficiency can be addressed per the methodology of NEI04-10.

LE-2: Uncertainty and sensitivity analyses are not included.

The evaluation of uncertainty for each surveillance interval extension application can be accomplished as needed; therefore, this deficiency can be addressed per the methodology of NEI 04-10. LE-3: Plant-specific analyses of induced steam generator tube rupture and secondary side isolation capability is not addressed.

The licensee stated that this failure mode is not typically significant and would be addressed by sensitivity studies as needed. Therefore, this deficiency can be addressed per the methodology of NEI 04-10. Based on the licensee's assessment using the applicable PRA standard and RG 1.200, the NRC staff concludes that the level of PRA quality, combined with the proposed evaluation and disposition of the identified deficiencies, is sufficient to support the evaluation of changes proposed to surveillance frequencies within the SFCP, and is consistent with Regulatory Position 2.3.1 of RG 1.177. 3.2.4.2 Scope of the PRA The licensee is required to evaluate each proposed change to a relocated surveillance frequency using the guidance contained in NEI 04-10 to determine its potential impact on risk, due to impacts from internal events, fires, seismic, other external events, and from shutdown conditions.

Consideration is made of both CDF and LERF metrics. In cases where a PRA of

-15 sufficient scope or where quantitative risk models were unavailable, the licensee uses bounding analyses, or other conservative quantitative evaluations.

A qualitative screening analysis may be used when the surveillance frequency impact on plant risk is shown to be negligible or zero. The licensee proposes to use the Fire Induced Vulnerability Evaluation (FIVE) methodology, which was completed for the Individual Plant Examination of External Events (IPEEE). Similarly, the IPEEE Seismic Margins Assessment will be used to provide seismic insights.

Other external hazards were assessed as insignificant during the IPEEE assessment.

Therefore, the risk contribution from these sources will be assessed either qualitatively or by bounding analyses for evaluation of surveillance frequency changes. The NRC staff concludes that the licensee's evaluation methodology is sufficient to ensure the scope of the risk contribution of each surveillance frequency change is properly identified for evaluation, and is consistent with Regulatory Position 2.3.2 of RG 1.177. 3.2.4.3 PRA Modeling The licensee will determine whether the SSCs affected by a proposed change to a surveillance frequency are modeled in the PRA. Where the SSC is directly or implicitly modeled, a quantitative evaluation of the risk impact may be carried out. The methodology adjusts the failure probability of the impacted SSCs, including any impacted common cause failure modes, based on the proposed change to the surveillance frequency.

Where the SSC is not modeled in the PRA, bounding analyses are performed to characterize the impact of the proposed change to the surveillance frequency.

Potential impacts on the risk analyses due to screening criteria and truncation levels are addressed by the requirements for PRA technical adequacy consistent with guidance contained in RG 1.200, and by sensitivity studies identified in NEI 04-10. The licensee will perform quantitative evaluations of the impact of selected testing strategy (i.e., staggered testing or sequential testing) consistently with the guidance of NUREG/CR-6141, "Handbook of Methods for Risk-Based Analyses of Technical Specifications" (Reference 17), and NUREG/CR-5497, "Common-Cause Failure Parameter Estimations" (Reference 18), as discussed in NEI 04-10. Based on the above, the NRC staff concludes that, through the application of NEI 04-10, the Callaway PRA modeling is sufficient to ensure an acceptable evaluation of risk for the proposed changes in surveillance frequency, and is consistent with Regulatory Position 2.3.3 of RG 1.177. 3.2.4.4 Assumptions for Time-Related Failure Contributions The failure probabilities of SSCs modeled in the Callaway PRA include a standby time-related contribution and a cyclic demand-related contribution.

NEI 04-10 criteria adjust the time-related failure contribution of SSCs affected by the proposed change to a surveillance frequency.

This is consistent with RG 1.177, Section 2.3.3, which permits separation of the failure-rate contributions into demand and standby for evaluation of surveillance requirements.

If the available data do not support distinguishing between the time-related and demand-related failures, then the change to a surveillance frequency is conservatively assumed to impact the total failure probability of the SSC, including both standby and demand contributions.

The SSC failure rate (per unit time) is assumed to be unaffected by the change in test frequency, and will

-be confirmed by the required monitoring and feedback implemented after the change in a surveillance frequency is implemented.

The process requires consideration of qualitative sources of information with regard to potential impacts of test frequency on SSC performance, including industry and plant-specific operating experience, vendor recommendations, industry standards, and code-specified test intervals.

Thus, the process is not reliant upon risk analyses as the sole basis for the proposed changes. The potential beneficial risk impacts of reduced surveillance frequency, including reduced downtime, lesser potential for restoration errors, reduction of potential for test-caused transients, and reduced test-caused wear of equipment, are identified qualitatively, but are conservatively not required to be quantitatively assessed.

The NRC staff concludes that, through the application of NEI 04-10, the licensee has employed reasonable assumptions with regard to extensions of surveillance test intervals, and is consistent with Regulatory Position 2.3.4 of RG 1.177. 3.2.4.S Sensitivity and Uncertainty Analyses NEI 04-10 requires sensitivity studies to assess the impact of uncertainties from key assumptions of the PRA, uncertainty in the failure probabilities of the affected SSCs, impact to the frequency of initiating events, and of any identified deviations from capability category II of ASME PRA Standard (ASME RA-Sb-200S) (Reference 11). Where the sensitivity analyses identify a potential impact on the proposed change, revised surveillance frequencies are considered, along with any qualitative considerations that may bear on the results of such sensitivity studies. Required monitoring and feedback of SSC performance, once the revised surveillance frequencies are implemented, will also be performed.

The NRC staff concludes that, through the application of NEI 04-10, the licensee has appropriately considered the possible impact of PRA model uncertainty and sensitivity to key assumptions and model limitations, and is consistent with Regulatory Position 2.3.S of RG 1.177. 3.2.4.6 Acceptance Guidelines The licensee will quantitatively evaluate the change in total risk (including internal and external events contributions) in terms of CDF and LERF for both the individual risk impact of a proposed change in surveillance frequency and the cumulative impact from all individual changes to surveillance frequencies using the guidance contained in NRC-approved NEI 04-10 in accordance with the TS SFCP. Each individual change to a surveillance frequency must show a risk impact below 1 E-6 per year for a change to CDF, and below 1 E-7 per year for a change to LERF. These are consistent with the limits of RG 1.174 for very small changes in risk. Where the RG 1.174 limits are not met, the process either considers revised surveillance frequencies which are consistent with RG 1.174 or the process terminates without permitting the proposed changes. Where quantitative results are unavailable to permit comparison to acceptance guidelines, appropriate qualitative analyses are required to demonstrate that the associated risk impact of a proposed change to surveillance frequency is negligible or zero. Otherwise, bounding quantitative analyses are required which demonstrate the risk impact is at least one order of magnitude lower than the RG 1.174 acceptance guidelines for very small changes in risk. In addition to assessing each individual SSC surveillance frequency change, the cumulative impact of all changes must result in a risk impact below 'I E-S per year for a change to CDF, and below 1 E-6 per year for a change to LERF, and the total CDF and total

-17 LERF must be reasonably shown to be less than 1 E-4 per year and 1 E-5 per year. respectively.

These are consistent with the limits of RG 1.174 for acceptable changes in risk. as referenced by RG 1.177 for changes to surveillance frequencies.

The NRC staff interprets this assessment of cumulative risk as a requirement to calculate the change in risk from a baseline model utilizing failure probabilities based on the surveillance frequencies prior to implementation of the SFCP. compared to a revised model with failure probabilities based on changed surveillance frequencies.

The staff further notes that the licensee includes a provision to exclude the contribution to cumulative risk from individual changes to surveillance frequencies associated with insignificant risk increases (less than 5E-8 CDF and 5E-9 LERF) once the baseline PRA models are updated to include the effects of the revised surveillance frequencies.

The quantitative acceptance guidance of RG 1.174 is supplemented by qualitative information to evaluate the proposed changes to surveillance frequencies.

including industry and plant-specific operating experience, vendor recommendations, industry standards, the results of sensitivity studies, and SSC performance data and test history. The final acceptability of the proposed change is based on all of these considerations and not solely on the PRA results compared to numerical acceptance guidelines.

Post-implementation performance monitoring and feedback are also required to assure continued reliability of the components.

The licensee's application of NEI 04-10 provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies, consistent with Regulatory Position 2.4 of RG 1.177. Therefore, the NRC staff concludes that the licensee's proposed methodology satisfies the fourth key safety principle of RG 1.177 by assuring any increase in risk is small and consistent with the intent of the Commission's Safety Goal Policy Statement. The Impact of the Proposed Change Should Be Monitored USing Performance Measurement Strategies The licensee's adoption of TSTF-425, Revision 3, requires application of NEI 04-10 in the SFCP. NEI 04-10 requires performance monitoring of SSCs whose surveillance frequencies have been revised as part of a feedback process to assure that the change in test frequency has not resulted in degradation of equipment performance and operational safety. The monitoring and feedback includes consideration of Maintenance Rule monitoring of equipment performance.

In the event of degradation of SSC performance, the surveillance frequency will be reassessed in accordance with the methodology, in addition to any corrective actions which may apply as part of the Maintenance Rule requirements.

The performance monitoring and feedback specified in NEI 04-10 is sufficient to reasonably assure acceptable SSC performance and is consistent with Regulatory Position 3.2 of RG 1.177. Thus, the fifth key safety principle of RG 1.177 is satisfied. Addition of Surveillance Frequency Control Program to Administrative Controls The licensee has included the SFCP and specific requirements into the Administrative Controls, TS Section 5.5.18, Surveillance Frequency Control Program, as follows: This program provides controls for Surveillance Frequencies.

The program shall ensure that Surveillance Requirements specified in the Technical Specifications

-are performed at intervals sufficient to assure that the associated Conditions for Operation are The Surveillance Frequency Control Program shall contain a list of Frequencies of the Surveillance Requirements for which the Frequency is controlled by the program. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1. The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program. The NRC staff concludes that the licensee's proposed program is consistent with the model application of TSTF-425, Revision 3, and, therefore, is acceptable. Summary and Conclusions The NRC staff has reviewed the licensee's proposed relocation of certain surveillance frequencies to a licensee-controlled document, and controlling changes to surveillance frequencies in accordance with a new program, the SFCP, identified in the administrative controls of TSs. The SFCP and TS Section 5.5.18 reference NEI 04-10, which provides a informed methodology using plant-specific risk insights and performance data to revise surveillance frequencies within the SFCP. This methodology supports relocating surveillance frequencies from the TSs to a licensee-controlled document, provided those frequencies are changed in accordance with NEI 04-10 which is specified in the Administrative Controls of the TSs. The licensee's proposed adoption of TSTF-425, Revision 3, and risk-informed methodology of NEI 04-10, as referenced in the Administrative Controls of the TSs, satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174, in that: The proposed change meets current regulations; The proposed change is consistent with defense-in-depth philosophy; The proposed change maintains sufficient safety margins; Increases in risk resulting from the proposed change are small and consistent with the Commission's Safety Goal Policy Statement; and The impact of the proposed change is monitored with performance measurement strategies.

-The NRC staff concludes that with the proposed relocation of surveillance frequencies to a licensee-controlled document and administratively controlled in accordance with the TS SFCP, the licensee continues to meet the regulatory requirement of 10 CFR 50.36 and, specifically, 10 CFR 50.36(c)(3), surveillance requirements. REGULATORY COMMITMENTS In its letter dated August 5, 2010, the licensee made the following regulatory commitments: The existing Bases information describing the basis for the Surveillance Frequency will be relocated to the licensee-controlled Surveillance Frequency Control Program. [The licensee]

proposes ... an Independent Decision-making Panel of qualified individuals with appropriate experience for recommending the acceptability of proposed surveillance frequency changes, in lieu of the site Maintenance Rule Expert Panel. This panel will be comprised of individuals whose experience levels are equal to or exceed the requirements of those on the Maintenance Rule Expert Panel. The individuals who will make up this panel will be designated by the senior management team that provides process oversight.

The designated individuals will have expertise in the areas of probabilistic risk assessment, operations, maintenance, engineering, quality assurance, operating experience, and licensing.

At least three individuals will have a minimum of 5 years experience at Callaway Plant or similar nuclear plants, and at least one individual will have worked on the modeling and updating of the PRA for Callaway Plant or similar plants for a minimum of 3 years. This level of experience and expertise will ensure that recommendations are well-considered and safety-focused.

When developing potential changes, the panel will be augmented by the Surveillance Test Coordinator and at least one subject matter expert on the structure, system or component being evaluated. The Callaway Plant On-Site Review Committee (ORC) will review probabilistic and deterministic assessments to determine if a sufficient basis exists to support Surveillance Test Interval (STI) change proposals and to approve or disapprove proposed STI changes. During the interim period, i.e., from approval of this license amendment request until the availability of PRA Update 5, each of the F/Os (Table 1 of Attachment 2 [of the licensee's letter dated August 5,2010 (ULNRC-05725)])

and F&Os (Table 2 of Attachment 2 [of the licensee's letter dated August 5,2010 (ULNRC-05725)])

to Capability Category II of the Standard will be considered for each STI under evaluation, and, when appropriate, sensitivity studies will be performed to address selected F/Os or F&Os.

-The licensee stated a completion date of October 27,2011, for the four commitments.

This date was contingent upon NRC approval by April 30, 2011, and 180 days for implementation.

The NRC staff acknowledges that this completion date will be adjusted by the licensee to account for NRC approval having been granted after April 30, 2011; therefore, these regulatory commitments are acceptable. STATE CONSULTATION In accordance with the NRC's regulations, the Missouri State official was notified of the proposed issuance of the amendment.

The State official had no comments. ENVIRONMENTAL CONSIDERATION The amendment changes a requirement with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure.

The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration and there has been no public comment on such finding published in Federal Register on January 11, 2011 (76 FR 1649). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment. CONCLUSION The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public. REFERENCES Maglio, S., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (LDCN 10-0020)," dated August 5,2010 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML102250056). Maglio, S., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "License Amendment Application for a Technical Specification Change That Would Relocate Specific Surveillance Frequencies to a Licensee Controlled Program (LDCN 10-0020) (TAC No. ME4506)," dated March 23,2011 (ADAMS Accession No. ML110830010).

-21 Maglio, S., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "License Amendment Application Supplement for a Technical Specification Change That Would Relocate Specific Surveillance Frequencies to a Licensee Controlled Program (LDCN 10-0020) (TAC No. ME4506)," dated May 3,2011 (ADAMS Accession No. ML111240412). Graessle, L. H., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "License Amendment Application Supplement for a Technical Specification Change That Would Relocate Specific Surveillance Frequencies to a Licensee Controlled Program (LDCN 10-0020) (TAC No. ME4506)," dated July 25,2011 (ADAMS Accession No. ML112061672). Technical Specifications Task Force (TSTF) Improved Standard Technical Specifications Change Traveler TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control-RITSTF Initiative 5b," dated March 18, 2009 (ADAMS Accession No. ML090850642). Nuclear Energy Institute, NEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5B, Risk-Informed Method for Control of Surveillance Frequencies," April 2007 (ADAMS Accession No. ML071360456). Nieh, H. K., U.S. Nuclear Regulatory Commission, letter to B. Bradley, Nuclear Energy Institute, "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 04-10, Revision 1, "Risk-informed Technical Specification Initiative 5b, "Risk-Informed Method for Control of Surveillance Frequencies (TAC No. MD6111)," dated September 19, 2007 (ADAMS Accession No. ML072570267). U.S. Nuclear Regulatory Commission, Regulatory Guide 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Specific Changes to the Licensing Basis," November 2002 (ADAMS Accession No. ML023240437). U.S. Nuclear Regulatory Commission, Regulatory Guide 1.177, "An Approach for Specific, Risk-Informed Decisionmaking:

Technical Specifications," August 1998 (ADAMS Accession No. ML003740176). U.S. Nuclear Regulatory Commission, Regulatory Guide 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," January 2007 (ADAMS Accession No. ML070240001). American Society of Mechanical Engineers (ASME) PRA Standard ASME RA-S b-2 005 , "Addenda to ASME RA-S-2002, "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Application." Nuclear Energy Institute, NEI 00-02, Revision 1, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance," May 2006 (ADAMS Accession No. ML061510621).

-Nuclear Energy Institute, Revision 0, NEI 05-04, "Process for Performing Follow-On PRA Peer Reviews Using the ASME PRA Standard," August 2006. Polickoski, J. T., U.S. Nuclear Regulatory Commission, e-mail to T. B. Ellwood and S. Maglio, Union Electric Company, Callaway Plant, Unit 1, Email, Request for Additional Information, RE: License Amendment Request for Technical Specification Change Regarding Risk Informed Justification (TAC No. ME4506)," dated December 17, 2010 (ADAMS Accession No. ML103510674). Westinghouse Electric Corporation, "Reactor Coolant Pump Seal Performance Following Loss of All AC Power," WCAP-1 0541. U.S. Nuclear Regulatory Commission, "Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants," NUREG/CR-6928, February 2007 (ADAMS Accession No. ML070650650). U.S. Nuctear Regulatory Commission, "Handbook of Methods for Risk-Based Analyses of Technical Specifications," NUREG/CR-6141, December 1994 (non-publicly available). U.S. Nuclear Regulatory Commission, "Common-Cause Failure Parameter Estimations," NUREG/CR-5497, October 1998 (non-publicly available).

Principal Contributor:

A. Howe July 29, 2011 A. Heflin -2 A copy of the related Safety Evaluation is also enclosed.

The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice. Sincerely, IRA by Lauren Kate Gibson fori Mohan C. Thadani, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-483

Enclosures:

1. Amendment No. 202 to NPF-30 2. Safety Evaluation cc w/encls: Distribution via Listserv DISTRIBUTION:

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ADAMS Accession No. ML111661877

SE memo dated OFFICIAL RECORD COpy

v t e Letter Sequence Approval
TAC:ME4506, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5B (Approved, Closed)
Initiation Request, Request, Request Acceptance Supplement, Supplement Administration Questions 17 December 2010 3 March 2011 Answers Results Approval, Approval Other: ML14290A369
MONTHYEAR2011-05-03 [Table View]

ML111661877

Text

Dear Mr. Heflin:

Enclosures:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

Enclosures:

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