Text

Issuance of Amendment Nos. 330 and 309 Regarding Implementation of TSTF 505,Rev. 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4B
	ML24031A540
Person / Time
Site:	McGuire, Mcguire
Issue date:	03/26/2024
From:	Klos L; Plant Licensing Branch II
To:	Pigott E; Duke Energy Carolinas
	Klos L
References
	EPID L-2023-LLA-0021
	Download: ML24031A540 (115)
	v • d • e

March 26, 2024 Mr. Edward Pigott Site Vice President Duke Energy Carolinas, LLC McGuire Nuclear Station 12700 Hagers Ferry Road Huntersville, NC 28078-8985

SUBJECT:

MCGUIRE NUCLEAR STATION, UNITS 1 AND 2, ISSUANCE OF AMENDMENT NOS. 330 AND 309, REGARDING REVISION OF TECHNICAL SPECIFICATIONS TO ADOPT TECHNICAL SPECIFICATION TASK FORCE (TSTF) TRAVELER TSTF-505, REVISION 2, PROVIDE RISK-INFORMED EXTENDED COMPLETION TIMES - RITSTF INITIATIVE 4b, (EPID L-2023-LLA-0021)

Dear Mr. Pigott:

The Nuclear Regulatory Commission (NRC, the Commission) has issued the enclosed Amendment No. 330 to Renewed Facility Operating License NPF-9 and Amendment No. 309 to Renewed Facility Operating License NPF-17 for the McGuire Nuclear Station, Units 1 and 2 (McGuire), respectively. This license amendment request (LAR) consists of changes to the technical specifications (TS) in response to your application dated February 16, 2023, as supplemented by letter dated November 2, 2023.

The amendments modify the TS requirements to permit the use of Risk-Informed Completion Times (RICTs) for actions to be taken when limiting conditions for operation (LCOs) are not met. The proposed changes are based on Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF [Risk-Informed TSTF] Initiative 4b.

A copy of the related Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commission's monthly Federal Register notice.

E. Pigott If you have any questions, please contact me at john.klos@nrc.gov or call me at 301-415-5136.

Sincerely,

/RA/

John Klos, Project Manager Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-369 and 50-370

Enclosures:

1. Amendment No. 330 to NPF-9

2. Amendment No. 309 to NPF-17

3. Safety Evaluation cc: Listserv DUKE ENERGY CAROLINAS, LLC DOCKET NO. 50-369 MCGUIRE NUCLEAR STATION, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 330 Renewed License No. NPF-9 1.

The Nuclear Regulatory Commission (NRC, the Commission) has found that:

A.

The application for amendment to the McGuire Nuclear Station, Unit 1 (the facility), Renewed Facility Operating License No. NPF-9, filed by the Duke Energy Carolinas, LLC (licensee), dated February 16, 2023, as supplemented by letter dated November 2, 2023, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

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 set forth in 10 CFR Chapter I; D.

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 E.

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.

2.

Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-9 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 330, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

(5)

Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 330 are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 180 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to License No. NPF-9 and the Technical Specifications Date of Issuance: March 26, 2024 MICHAEL MARKLEY Digitally signed by MICHAEL MARKLEY Date: 2024.03.26 11:58:21 -04'00' DUKE ENERGY CAROLINAS, LLC DOCKET NO. 50-370 MCGUIRE NUCLEAR STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 309 Renewed License No. NPF-17 1.

The Nuclear Regulatory Commission (NRC, the Commission) has found that:

A.

The application for amendment to the McGuire Nuclear Station, Unit 1 (the facility), Renewed Facility Operating License No. NPF-9, filed by the Duke Energy Carolinas, LLC (licensee), dated February 16, 2023, as supplemented by letter dated November 2, 2023, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

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 set forth in 10 CFR Chapter I; D.

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 E.

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.

2.

Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-17 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 309, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

(5)

Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 309 are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 180 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to License No. NPF-17 and the Technical Specifications Date of Issuance: March 26, 2024 MICHAEL MARKLEY Digitally signed by MICHAEL MARKLEY Date: 2024.03.26 11:58:58 -04'00'

ATTACHMENT TO LICENSE AMENDMENT NO. 330 MCGUIRE NUCLEAR STATION, UNITS 1 AND 2 RENEWED FACILITY OPERATING LICENSE NO. NPF-9 DOCKET NO. 50-369 AND LICENSE AMENDMENT NO. 309 RENEWED FACILITY OPERATING LICENSE NO. NPF-17 DOCKET NO. 50-370 Replace the following pages of the Renewed Facility Operating Licenses, Appendix A Technical Specifications (TSs), and Appendix B Additional Conditions with the attached revised pages.

The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert License Pages License Pages NPF-9, page 3 NPF-9, page 3 NPF-17, page 3 NPF-17, page 3 Additional Conditions Additional Conditions NPF-9, page B-4 NPF-9, page B-4 NPF-17, page B-4 NPF-17, page B-4 TS Pages TS Pages 1.3-14 1.3-14 NA 1.3-15 3.3.1-1 3.3.1-1 3.3.1-2 3.3.1-2 3.3.1-3 3.3.1-3 3.3.1-4 3.3.1-4 3.3.1-5 3.3.1-5 3.3.1-6 3.3.1-6 3.3.1-7 3.3.1-7 3.3.1-8 3.3.1-8 3.3.1-9 3.3.1-9 3.3.1-10 3.3.1-10 3.3.1-11 3.3.1-11 3.3.1-12 3.3.1-12 3.3.1-13 3.3.1-13 3.3.1-14 3.3.1-14 Remove Insert TS Pages TS Pages 3.3.1-15 3.3.1-15 3.3.1-16 3.3.1-16 3.3.1-17 3.3.1-17 3.3.1-18 3.3.1-18 3.3.1-19 3.3.1-19 3.3.1-20 3.3.1-20 3.3.1-21 3.3.1-21 3.3.2-1 3.3.2-1 3.3.2-2 3.3.2-2 3.3.2-3 3.3.2-3 3.3.2-4 3.3.2-4 3.3.2-5 3.3.2-5 3.3.2-7 3.3.2-7 3.3.2-14 3.3.2-14 3.3.5-1 3.3.5-1 3.3.5-2 3.3.5-2 3.4.11-2 3.4.11-2 3.4.11-3 3.4.11-3 3.4.11-4 3.4.11-4 3.4.11-5 3.4.11-5 3.4.11-6 3.4.11-6 NA 3.4.11-7 NA 3.4.11-8 NA 3.4.11-9 3.5.2-1 3.5.2-1 3.6.2-4 3.6.2-4 3.6.3-1 3.6.3-1 3.6.3-2 3.6.3-2 3.6.3-3 3.6.3-3 3.6.6-1 3.6.6-1 3.6.9-1 3.6.9-1 3.6.11-1 3.6.11-1 3.6.14-1 3.6.14-1 3.7.2-1 3.7.2-1 3.7.5-1 3.7.5-1 3.7.6-1 3.7.6-1 3.7.7-1 3.7.7-1 3.7.7-2 3.7.7-2 3.8.1-2 3.8.1-2 3.8.1-4 3.8.1-4 3.8.1-5 3.8.1-5 3.8.1-7 3.8.1-7 3.8.1-8 3.8.1-8 3.8.1-9 3.8.1-9 3.8.1-10 3.8.1-10 3.8.1-11 3.8.1-11 3.8.1-12 3.8.1-12 3.8.1-13 3.8.1-13 Remove Insert TS Pages TS Pages 3.8.1-14 3.8.1-14 3.8.1-15 3.8.1-15 3.8.1-16 3.8.1-16 3.8.1-17 3.8.1-17 3.8.1-18 3.8.1-18 3.8.1-19 3.8.1-19 3.8.1-20 3.8.1-20 NA 3.8.1-21 3.8.4-1 3.8.4-1 3.8.7-1 3.8.7-1 3.8.7-2 3.8.7-2 3.8.9-1 3.8.9-1 3.8.9-2 3.8.9-2 5.5-16 5.5-16 NA 5.5-17

Renewed License No. NPF-9 Amendment No. 330 (4)

Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; (5)

Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproducts and special nuclear materials as may be produced by the operation of McGuire Nuclear Station, Units 1 and 2, and; (6)

Pursuant to the Act and 10 CFR Parts 30 and 40, to receive, possess and process for release or transfer such byproduct material as may be produced by the Duke Training and Technology Center.

C.

This renewed operating 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:

(1)

Maximum Power Level The licensee is authorized to operate the facility at a reactor core full steady state power level of 3469 megawatts thermal (100%).

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 330, are hereby incorporated into this renewed operating license.

The licensee shall operate the facility in accordance with the Technical Specifications.

(3)

Updated Final Safety Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on December 16, 2002, describes certain future activities to be completed before the period of extended operation.

Duke shall complete these activities no later than June 12, 2021, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.

The Updated Final Safety Analysis Report supplement as revised on December 16, 2002, described above, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71(e)(4), following issuance of this renewed operating license.

Until that update is complete, Duke may make changes to the programs described in such supplement without prior Commission approval, provided that Duke evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

Renewed License No. NPF-17 Amendment No. 309 (4)

Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; (5)

Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproducts and special nuclear materials as may be produced by the operation of McGuire Nuclear Station, Units 1 and 2, and; (6)

Pursuant to the Act and 10 CFR Parts 30 and 40, to receive, possess and process for release or transfer such byproduct material as may be produced by the Duke Training and Technology Center.

C.

This renewed operating 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:

(1)

Maximum Power Level The licensee is authorized to operate the facility at a reactor core full steady state power level of 3469 megawatts thermal (100%).

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 309, are hereby incorporated into this renewed operating license.

The licensee shall operate the facility in accordance with the Technical Specifications.

(3)

Updated Final Safety Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on December 16, 2002, describes certain future activities to be completed before the period of extended operation.

Duke shall complete these activities no later than March 3, 2023, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.

The Updated Final Safety Analysis Report supplement as revised on December 16, 2002, described above, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71(e)(4), following issuance of this renewed operating license.

Until that update is complete, Duke may make changes to the programs described in such supplement without prior Commission approval, provided that Duke evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

Completion Times 1.3 1.3 Completion Times (continued)

McGuire Units 1 and 2 1.3-14 Amendment Nos. 330/309 EXAMPLES EXAMPLE 1.3-7 (continued)

Condition A was initially entered. If Required Action A.1 is met after Condition B is entered, Condition B is exited and operation may continue in accordance with Condition A, provided the Completion Time for Required Action A.2 has not expired.

EXAMPLE 1.3-8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One subsystem inoperable.

A.1 Restore subsystem to OPERABLE status.

7 days OR In accordance with the Risk-Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours When a subsystem is declared inoperable, Condition A is entered.

The 7 day Completion Time may be applied as discussed in Example 1.3-2. However, the licensee may elect to apply the Risk-Informed Completion Time Program which permits calculation of a Risk-Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day Completion Time. The RICT cannot exceed 30 days. After the 7 day Completion Time has expired, the subsystem must be restored to OPERABLE status within the RICT or Condition B must also be entered.

Completion Times 1.3 1.3 Completion Times McGuire Units 1 and 2 1.3-15 Amendment Nos. 330/309 EXAMPLES EXAMPLE 1.3-8 (continued)

The Risk-Informed Completion Time Program requires recalculation of the RICT to reflect changing plant conditions. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

If the 7 day Completion Time clock of Condition A has expired and subsequent changes in plant condition result in exiting the applicability of the Risk-Informed Completion Time Program without restoring the inoperable subsystem to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start.

If the RICT expires or is recalculated to be less than the elapsed time since the Condition was entered and the inoperable subsystem has not been restored to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable subsystems are restored to OPERABLE status after Condition B is entered, Conditions A and B are exited, and therefore, the Required Actions of Condition B may be terminated.

IMMEDIATE When "Immediately" is used as a Completion Time, the COMPLETION TIME Required Action should be pursued without delay and in a controlled manner.

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-1 Amendment Nos. 330/309 3.3 INSTRUMENTATION 3.3.1 Reactor Trip System (RTS) Instrumentation LCO 3.3.1 The RTS instrumentation for each Function in Table 3.3.1-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.1-1.

ACTIONS

NOTE----------------------------------------------------------

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more Functions with one or more required channels inoperable.

A.1 Enter the Condition referenced in Table 3.3.1-1 for the channel(s).

Immediately B.

One Manual Reactor Trip channel inoperable.

B.1 Restore channel to OPERABLE status.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR In accordance with the Risk-Informed Completion Time Program C.

One channel or train inoperable.

C.1 Restore channel or train to OPERABLE status.

OR C.2 Open reactor trip breakers (RTBs).

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months 49 hours (continued)

RTS Instrumentation 3.3.1 ACTIONS (continued)

McGuire Units 1 and 2 3.3.1-2 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME D.

One channel inoperable.

NOTE-------------------

One 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 and setpoint adjustment.

D.1.1 ------------NOTE---------------

Only required to be performed when the Power Range Neutron Flux input to QPTR is inoperable Perform SR 3.2.4.2 AND D.1.2 Place channel in trip.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from discovery of THERMAL POWER

> 75% RTP AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

RTS Instrumentation 3.3.1 ACTIONS (continued)

McGuire Units 1 and 2 3.3.1-3 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME E.

One channel inoperable.

NOTE-------------------

One 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 trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program F.

THERMAL POWER

> P-6 and < P-10, one Intermediate Range Neutron Flux channel inoperable.

F.1 Reduce THERMAL POWER to < P-6.

OR F.2 Increase THERMAL POWER to > P-10.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 24 hours G.

THERMAL POWER

> P-6 and < P-10, two Intermediate Range Neutron Flux channels inoperable.

NOTE----------------

Limited boron concentration changes associated with RCS inventory control or limited plant temperature changes are allowed.

G.1 Suspend operations involving positive reactivity additions.

AND G.2 Reduce THERMAL POWER to < P-6.

Immediately 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months (continued)

RTS Instrumentation 3.3.1 ACTIONS (continued)

McGuire Units 1 and 2 3.3.1-4 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME H.

THERMAL POWER

< P-6, one or two Intermediate Range Neutron Flux channels inoperable.

H.1 Restore channel(s) to OPERABLE status.

Prior to increasing THERMAL POWER to > P-6 I.

One Source Range Neutron Flux channel inoperable.

NOTE-----------------

Limited boron concentration changes associated with RCS inventory control or limited plant temperature changes are allowed.

I.1 Suspend operations involving positive reactivity additions.

Immediately J.

Two Source Range Neutron Flux channels inoperable.

J.1 Open RTBs.

Immediately K.

One Source Range Neutron Flux channel inoperable.

K.1 Restore channel to OPERABLE status.

OR K.2 Open RTBs.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months 49 hours (continued)

RTS Instrumentation 3.3.1 ACTIONS (continued)

McGuire Units 1 and 2 3.3.1-5 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME L.

Required Source Range Neutron Flux channel inoperable.

NOTE-----------------

Plant temperature changes are allowed provided that SDM is maintained and Keff remains <

0.99.

L.1 Suspend operations involving positive reactivity additions.

AND L.2 Close unborated water source isolation valves.

AND L.3 Perform SR 3.1.1.1.

Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter (continued)

RTS Instrumentation 3.3.1 ACTIONS (continued)

McGuire Units 1 and 2 3.3.1-6 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME M.

One channel inoperable.

NOTE-------------------

One 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.

M.1 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program N.

Required Action and associated Completion Time of Condition M not met.

N.1 Reduce THERMAL POWER to < P-7.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months O.

One Reactor Coolant Flow - Low (Single Loop) channel inoperable.

NOTE--------------------

One 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.

O.1 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

RTS Instrumentation 3.3.1 ACTIONS (continued)

McGuire Units 1 and 2 3.3.1-7 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME P.

Required Action and associated Completion Time of Condition O not met.

P.1 Reduce THERMAL POWER to < P-8.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Q.

One Turbine Trip - Low Fluid Oil Pressure channel inoperable.

NOTE-------------------

One 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.

Q.1 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program R.

Required Action and associated Completion Time of Condition Q not met.

R.1 Reduce THERMAL POWER to < P-8.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months S.

One or more Turbine Trip - Turbine Stop Valve Closure channels inoperable.

S.1 Place channel(s) in trip.

OR S.2 Reduce THERMAL POWER to < P-8.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 76 hours (continued)

RTS Instrumentation 3.3.1 ACTIONS (continued)

McGuire Units 1 and 2 3.3.1-8 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME T.

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.

T.1 Restore train to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk-Informed Completion Time Program U.

One RTB 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.

U.1 Restore train to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk-Informed Completion Time Program V.

One or more channel(s) inoperable.

V.1 Verify interlock is in required state for existing unit conditions.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (continued)

RTS Instrumentation 3.3.1 ACTIONS (continued)

McGuire Units 1 and 2 3.3.1-9 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME W.

One or more channel(s) inoperable.

W.1 Verify interlock is in required state for existing unit conditions.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months X.

Required Action and associated Completion Time of Condition W not met.

X.1 Be in MODE 2.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Y.

One trip mechanism inoperable for one RTB.

Y.1 Restore trip mechanism to OPERABLE status.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR In accordance with the Risk-Informed Completion Time Program Z.

Required Action and associated Completion Time of Condition B, D, E, T, U, V, or Y not met.

Z.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AA.

Two RTS trains inoperable.

AA.1 Enter LCO 3.0.3.

Immediately

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-10 Amendment Nos. 330/309 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.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.2

NOTES----------------------------------

1.

Adjust NIS channel if absolute difference is > 2%

RTP.

2.

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is > 15% RTP.

Compare results of calorimetric heat balance calculation to Nuclear Instrumentation System (NIS) channel output.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.3

NOTES----------------------------------

1.

Adjust NIS channel if absolute difference is > 3%

AFD.

2.

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 the incore detector measurem ents to NIS AFD.

In accordance with the Surveillance Frequency Control Program (continued)

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.3.1-11 Amendment Nos. 330/309 SURVEILLANCE FREQUENCY SR 3.3.1.4

NOTES----------------------------------

This Surveillance must be performed on the reactor trip bypass breaker 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

NOTES----------------------------------

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 > 75% RTP.

Calibrate excore channels to agree with incore detector measurements.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.7

NOTES----------------------------------

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.

Perform COT.

In accordance with the Surveillance Frequency Control Program (continued)

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.3.1-12 Amendment Nos. 330/309 SURVEILLANCE FREQUENCY SR 3.3.1.8

NOTES----------------------------------

This Surveillance shall include verification that interlocks P-6 (for the Intermediate Range channels) and P-10 (for the Power Range channels) 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 or previous 184 days Prior to reactor startup AND Four hours after reducing power below P-10 for power and intermediate range instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND In accordance with the Surveillance Frequency Control Program (continued)

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.3.1-13 Amendment Nos. 330/309 SURVEILLANCE FREQUENCY SR 3.3.1.9

NOTES----------------------------------

Verification of setpoint is not required.

Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.10 ------------------------------NOTES----------------------------------

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 3.3.1.11 ------------------------------NOTES----------------------------------

1.

Neutron detectors are excluded from CHANNEL CALIBRATION.

2.

Power Range Neutron Flux high voltage detector saturation curve verification is not required to be performed prior to entry into MODE 1 or 2.

Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.12 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program (continued)

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-14 Amendment Nos. 330/309 SURVEILLANCE FREQUENCY SR 3.3.1.13 Perform COT.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.14 ------------------------------NOTES----------------------------------

Verification of setpoint is not required.

Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.15 ------------------------------NOTES----------------------------------

Verification of setpoint is not required.

Perform TADOT.

NOTE--------

Only required when not performed within previous 31 days Prior to reactor startup SR 3.3.1.16 ------------------------------NOTES----------------------------------

Neutron detectors are excluded from response time testing.

Verify RTS RESPONSE TIME is within limits.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.17 Verify RTS RESPONSE TIME for RTDs is within limits.

In accordance with the Surveillance Frequency Control Program

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-15 Amendment Nos. 330/309 Table 3.3.1-1 (page 1 of 7)

Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE NOMINAL TRIP SETPOINT 1.

Manual Reactor Trip 1,2 3(a), 4(a), 5(a) 2 2

B C

SR 3.3.1.14 SR 3.3.1.14 NA NA NA NA 2.

Power Range Neutron Flux a.

High b.

Low 1,2 1(b),2 4

4 D

E SR 3.3.1.1 SR 3.3.1.2 SR 3.3.1.7 SR 3.3.1.11 SR 3.3.1.16 SR 3.3.1.1 SR 3.3.1.8 SR 3.3.1.11 SR 3.3.1.16

< 110% RTP

< 26% RTP 109% RTP 25% RTP 3.

Power Range Neutron Flux Rate High Positive Rate 1,2 4

D SR 3.3.1.7 SR 3.3.1.11

< 5.5% RTP with time constant

> 2 sec 5% RTP with time constant

> 2 sec 4.

Intermediate Range Neutron Flux 1(b), 2(c) 2(d) 2 2

F,G H

SR 3.3.1.1 SR 3.3.1.8(j)(k)

SR 3.3.1.11(j)(k)

SR 3.3.1.1 SR 3.3.1.8(j)(k)

SR 3.3.1.11(j)(k)

< 38% RTP

< 38% RTP 25% RTP 25% RTP (continued)

(a)

With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.

(b)

Below the P-10 (Power Range Neutron Flux) interlocks.

(c)

Above the P-6 (Intermediate Range Neutron Flux) interlocks.

(d)

Below the P-6 (Intermediate Range Neutron Flux) interlocks.

(j)

If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(k)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-16 Amendment Nos. 330/309 Table 3.3.1-1 (page 2 of 7)

Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE NOMINAL TRIP SETPOINT 5.

Source Range Neutron Flux 2(d) 3(a), 4(a), 5(a) 3(e), 4(e), 5(e) 2 2

1 I,J J,K L

SR 3.3.1.1 SR 3.3.1.8(j)(k)

SR 3.3.1.11(j)(k)

SR 3.3.1.1 SR 3.3.1.7(j)(k)

SR 3.3.1.11(j)(k)

SR 3.3.1.1 SR 3.3.1.11

< 1.44 E5 cps

< 1.44 E5 cps N/A 1.0 E5 cps 1.0 E5 cps N/A 6.

Overtemperature T 1,2 4

E SR 3.3.1.1 SR 3.3.1.3 SR 3.3.1.6 SR 3.3.1.7 SR 3.3.1.12 SR 3.3.1.16 SR 3.3.1.17 Refer to Note 1 (Page 3.3.1-18)

Refer to Note 1 (Page 3.3.1-18) 7.

Overpower T 1,2 4

E SR 3.3.1.1 SR 3.3.1.3 SR 3.3.1.6 SR 3.3.1.7 SR 3.3.1.12 SR 3.3.1.16 SR 3.3.1.17 Refer to Note 2 (Page 3.3.1-19)

Refer to Note 2 (Page 3.3.1-19) 8.

Pressurizer Pressure a.

Low b.

High 1(f) 1,2 4

4 M

E SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16 SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16

> 1935 psig

< 2395 psig 1945 psig 2385 psig (continued)

(a)

With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.

(d)

Below the P-6 (Intermediate Range Neutron Flux) interlocks.

(e)

With the RTBs open. In this condition, source range Function does not provide reactor trip but does provide indication.

(f)

Above the P-7 (Low Power Reactor Trips Block) interlock.

(j)

If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(k)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-17 Amendment Nos. 330/309 Table 3.3.1-1 (page 3 of 7)

Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE NOMINAL TRIP SETPOINT 9.

Pressurizer Water Level - High 1(f) 3 M

SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10

< 93%

92%

10. Reactor Coolant Flow - Low a.

Single Loop b.

Two Loops 1(g) 1(h) 3 per loop 3 per loop O

M SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16 SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16

> 87%

88%

11. Undervoltage RCPs 1(f) 1 per bus M

SR 3.3.1.9 SR 3.3.1.10(j)(k)

SR 3.3.1.16

> 4870 V 5082 V

12. Underfrequency RCPs 1(f) 1 per bus M

SR 3.3.1.9 SR 3.3.1.10(j)(k)

SR 3.3.1.16

> 55.9 Hz 56.4 Hz

13. Steam Generator (SG) Water Level -

Low Low 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

> 15%

16.7%

14. Turbine Trip a.

Low Fluid Oil Pressure b.

Turbine Stop Valve Closure 1(g) 1(g) 3 4

Q S

SR 3.3.1.10 SR 3.3.1.15 SR 3.3.1.10 SR 3.3.1.15

> 42 psig

> 1% open 45 psig

> 1% open

15. Safety Injection (SI)

Input from Engineered Safety Feature Actuation System (ESFAS) 1,2 2 trains T

SR 3.3.1.5 SR 3.3.1.14 NA NA (continued)

(f)

Above the P-7 (Low Power Reactor Trips Block) interlock.

(g)

Above the P-8 (Power Range Neutron Flux) interlock.

(h)

Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock.

(j)

If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(k)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-18 Amendment Nos. 330/309 Table 3.3.1-1 (page 4 of 7)

Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE NOMINAL TRIP SETPOINT

16. Reactor Trip System Interlocks

a.

Intermediate Range Neutron Flux, P-6

b.

Low Power Reactor Trips Block, P-7

c.

Power Range Neutron Flux, P-8

d.

Power Range Neutron Flux, P-10

e.

Turbine Inlet Pressure, P-13 2(d) 1 1

1,2 1

2 1 per train 4

4 2

V W

W V

W SR 3.3.1.11 SR 3.3.1.13 SR 3.3.1.5 SR 3.3.1.11 SR 3.3.1.13 SR 3.3.1.11 SR 3.3.1.13 SR 3.3.1.12 SR 3.3.1.13

> 6.6E-6% RTP NA

< 49% RTP

> 7% RTP and

< 11% RTP

< 11% turbine inlet pressure equivalent 1E-5% RTP NA 48% RTP 10% RTP 10% turbine inlet pressure equivalent

17. Reactor Trip Breakers(i) 1,2 3(a), 4(a), 5(a) 2 trains 2 trains U, AA C

SR 3.3.1.4 SR 3.3.1.4 NA NA NA NA

18. Reactor Trip Breaker Undervoltage and Shunt Trip Mechanisms 1,2 3(a), 4(a), 5(a) 1 each per RTB 1 each per RTB Y

C SR 3.3.1.4 SR 3.3.1.4 NA NA NA NA

19. Automatic Trip Logic 1,2 3(a), 4(a), 5(a) 2 trains 2 trains T, AA C

SR 3.3.1.5 SR 3.3.1.5 NA NA NA NA (a)

With RTBs closed and Rod Control System capable of rod withdrawal.

(d) Below the P-6 (Intermediate Range Neutron Flux) interlocks.

(i) Including any reactor trip bypass breakers that are racked in and closed for bypassing on RTP.

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-19 Amendment Nos. 330/309 Table 3.3.1-1 (page 5 of 7)

Reactor Trip System Instrumentation Note 1: Overtemperature T The Overtemperature T Function Allowable Value shall not exceed the following NOMINAL TRIP SETPOINT by more than 4.3 % of RTP.

)

(

)

(

)

1

(

1

)

1

(

)

1

(

1 1

)

1

(

)

1

(

1 3

6 5

4 2

1 0

3 2

1 I

f P

P K

T s

s K

K T

s s

s T

Where:

T is measured RCS T by loop narrow range RTDs, °F.

T0 is the indicated T at RTP, °F.

s is the Laplace transform operator, sec-1.

T is the measured RCS average temperature, °F.

T' is the nominal Tavg at RTP, < the value specified in the COLR.

P is the measured pressurizer pressure, psig P' is the nominal RCS operating pressure, = the value specified in the COLR.

K1

= Overtemperature T reactor NOMINAL TRIP SETPOINT, as presented in the COLR, K2

= Overtemperature T reactor trip heatup setpoint penalty coefficient, as presented in the COLR, K3

= Overtemperature T reactor trip depressurization setpoint penalty coefficient, as presented in the COLR, 1,2

= Time constants utilized in the lead-lag controller for T, as presented in the

COLR,

3

= Time constants utilized in the lag compensator for T, as presented in the

COLR,

4, 5 = Time constants utilized in the lead-lag controller for Tavg, as presented in the

COLR,

6

= Time constants utilized in the measured Tavg lag compensator, as presented in the COLR, and, f1(I) = a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that:

(i) for qt - qb between the "positive" and "negative" f1(I) breakpoints as presented in the COLR; f1(I) = 0, where qt and qb are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RATED THERMAL POWER; (continued)

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-20 Amendment Nos. 330/309 Table 3.3.1-1 (page 6 of 7)

Reactor Trip System Instrumentation (ii) for each percent imbalance that the magnitude of qt - qb is more negative than the f1(I) "negative" breakpoint presented in the COLR, the T Trip Setpoint shall be automatically reduced by the f1(I) "negative" slope presented in the COLR; and (iii) for each percent imbalance that the magnitude of qt - qb is more positive than the f1(I) "positive" breakpoint presented in the COLR, the T Trip Setpoint shall be automatically reduced by the f1(I)

"positive" slope presented in the COLR.

Note 2: Overpower T The Overpower T Function Allowable Value shall not exceed the following NOMINAL TRIP SETPOINT by more than 2.6% of RTP.

)

(

1 1

(

)

1

(

2 6

6 6

7 7

5 4

0 3

2 1

I f

T s

T K

T s

s s

K K

T s

s s

T

Where:

T is measured RCS T by loop narrow range RTDs, °F.

T0 is the indicated T at RTP, °F.

s is the Laplace transform operator, sec-1.

T is the measured RCS average temperature, °F.

T" is the nominal Tavg at RTP, < the value specified in the COLR.

K4

= Overpower T reactor NOMINAL TRIP SETPOINT as presented in the

COLR, K5

= The value specified in the COLR for increasing average temperature and the value specified in the COLR for decreasing average temperature, K6

= Overpower T reactor trip heatup setpoint penalty coefficient as presented in the COLR for T > T" and K6 = the value specified in the COLR for T < T",

1, 2 = Time constants utilized in the lead-lag controller for T, as presented in the

COLR, 3

= Time constants utilized in the lag compensator for T, as presented in the

COLR, 6

= Time constants utilized in the measured Tavg lag compensator, as presented in the COLR, 7

= Time constant utilized in the rate-lag controller for Tavg, as presented in the COLR, and f2(I) = a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that:

(continued)

RTS Instrumentation 3.3.1 McGuire Units 1 and 2 3.3.1-21 Amendment Nos. 330/309 Table 3.3.1-1 (page 7 of 7)

Reactor Trip System Instrumentation (i) for qt - qb between the "positive" and "negative" f2(I) breakpoints as presented in the COLR; f2(I) = 0, where qt and qb are percent RATED THERMAL POWER in the top and bottom halves of the core respectively, and qt + qb is total THERMAL POWER in percent of RATED THERMAL POWER; (ii) for each percent imbalance that the magnitude of qt - qb is more negative than the f2(I) "negative" breakpoint presented in the COLR, the T Trip Setpoint shall be automatically reduced by the f2(I) "negative" slope presented in the COLR; and (iii) for each percent imbalance that the magnitude of qt - qb is more positive than the f2(I) "positive" breakpoint presented in the COLR, the T Trip Setpoint shall be automatically reduced by the f2(I) "positive" slope presented in the COLR.

ESFAS Instrumentation 3.3.2 McGuire Units 1 and 2 3.3.2-1 Amendment Nos. 330/309 3.3 INSTRUMENTATION 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation LCO 3.3.2 The ESFAS instrumentation for each Function in Table 3.3.2-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.2-1.

ACTIONS

NOTE-----------------------------------------------------------

Separate Condition entry is allowed for each Function.

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.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

McGuire Units 1 and 2 3.3.2-2 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME C.

One train inoperable.

C.1

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.

Restore train to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk-Informed Completion Time Program D.

One channel inoperable.

D.1

NOTE--------------

One 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.

Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

McGuire Units 1 and 2 3.3.2-3 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME E.

One Containment Pressure channel inoperable.

E.1

NOTE--------------

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.

Place channel in bypass.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months F.

One channel or train inoperable.

F.1 Restore channel or train to OPERABLE status.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR In accordance with the Risk-Informed Completion Time Program G.

One Steam Line Isolation Manual Initiation - individual channel inoperable.

G.1 Restore channel to OPERABLE status.

OR G.2 Declare associated steam line isolation valve inoperable.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months 48 hours (continued)

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

McGuire Units 1 and 2 3.3.2-4 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME H.

One train inoperable.

H.1

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.

Restore train to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk-Informed Completion Time Program I.

One train inoperable.

I.1

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.

Restore train to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk-Informed Completion Time Program (continued)

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

McGuire Units 1 and 2 3.3.2-5 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME J.

One channel inoperable.

J.1

NOTE--------------

One 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.

Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program K.

One Main Feedwater Pumps trip channel inoperable.

K.1 Place channel in trip.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months L.

One required channel in one train of Doghouse Water Level-High High inoperable.

L.1 Restore the inoperable train to OPERABLE status.

OR L.2 Perform continuous monitoring of Doghouse water level.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 73 hours M.

Two trains of Doghouse Water Level-High High inoperable.

M.1 Perform continuous monitoring of Doghouse water level..

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (continued)

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

McGuire Units 1 and 2 3.3.2-7 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME Q.

One channel inoperable.

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

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months R.

One or more Containment Pressure Control System channel(s) inoperable.

R.1 Declare affected supported system inoperable.

Immediately S.

Required Action and associated Completion Time of Condition B or C not met.

S.1 Be in MODE 3.

AND S.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours T.

Required Action and associated Completion Time of Condition D, E, F, H, P, or Q not met.

T.1 Be in MODE 3.

AND T.2 Be in MODE 4.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours U.

Required Action and associated Completion Time of Condition I, J, or K not met.

U.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months

ESFAS Instrumentation 3.3.2 McGuire Units 1 and 2 3.3.2-14 Amendment Nos. 330/309 Table 3.3.2-1 (page 5 of 6)

Engineered Safety Feature Actuation System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE NOMINAL TRIP SETPOINT

6. Auxiliary Feedwater (continued)

e.

Trip of all Main Feedwater Pumps 1,2 1 per MFW pump K

SR 3.3.2.7 SR 3.3.2.9 NA NA

f.

Auxiliary Feedwater Pump Suction Transfer on Suction Pressure - Low 1,2,3 2 per MDP, 4 per TDP N,O SR 3.3.2.7(a)(b)

SR 3.3.2.8(a)(b)

SR 3.3.2.9

> 6.5 psig

> 7.5 psig (2A MDP only) 7.0 psig 8.0 psig (2A MDP only)

7.

Automatic Switchover to Containment Sump

a.

Refueling Water Storage Tank (RWST) Level -

Low 1,2,3 3

P,T SR 3.3.2.1 SR 3.3.2.3(a)(b)

SR 3.3.2.8(a)(b)

SR 3.3.2.9

> 92.3 inches 95 inches Coincident with Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

(continued)

(a) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(b) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.

Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (field setting) to confirm channel performance. The methodologies used to determine the as-found and the as-left tolerances are specified in the UFSAR.

NOTE 1: The Trip Setpoint for the Containment Pressure Control System start permissive/termination (SP/T) shall be

> 0.3 psig and < 0.4 psig. The allowable value for the SP/T shall be > 0.25 psig and < 0.45 psig.

LOP DG Start Instrumentation 3.3.5 McGuire Units 1 and 2 3.3.5-1 Amendment Nos. 330/309 3.3 INSTRUMENTATION 3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation LCO 3.3.5 Three channels per bus of the loss of voltage Function and three channels per 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 Place channel in trip.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR In accordance with the Risk-Informed Completion Time Program B.

One or more Functions with two or more channels per bus inoperable.

B.1 Restore all but one channel to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OR

NOTE----------

Not applicable when a loss of function occurs In accordance with the Risk-Informed Completion Time Program (continued)

LOP DG Start Instrumentation 3.3.5 McGuire Units 1 and 2 3.3.5-2 Amendment Nos. 330/309 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C.

Required Action and associated Completion Time not met.

C.1 Enter applicable Condition(s) and Required Action(s) for the associated DG made inoperable by LOP DG start instrumentation.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.5.1 Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.2

NOTE-----------------------------------

A NOMINAL TRIP SETPOINT associated with this SR shall be set within the channel's calibartion tolerance band.

Perform CHANNEL CALIBRATION with NOMINAL TRIP SETPOINT and Allowable Value as follows:

a.

Loss of voltage Allowable Value > 3122 V (Unit

1) 3108 V (Unit 2) with a time delay of 8.5 +/- 0.5 second.

Loss of voltage NOMINAL TRIP SETPOINT 3174 V (Unit 1) 3157 V (Unit 2) +/- 45 V with a time delay of 8.5 +/- 0.5 second.

b.

Degraded voltage Allowable Value > 3661 V (Unit

1) > 3685.5 V (Unit 2) with a time delay of < 11 seconds with SI and < 600 seconds without SI.

Degraded voltage NOMINAL TRIP SETPOINT 3678.5 V (Unit 1) 3703 V (Unit 2) with a time delay of < 11 seconds with SI and < 600 seconds without SI.

In accordance with the Surveillance Frequency Control Program

Pressurizer PORVs 3.4.11 McGuire Units 1 and 2 3.4.11-2 Amendment Nos. 330/309 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C.

One Train A PORV inoperable and not capable of being manually cycled

NOTE--------------------

Required Actions C.1 and C.2 are not applicable to a PORV made inoperable by Required Action H.2.

C.1 Close associated block valve.

AND C.2 Remove power from associated block valve.

AND C.3 Restore PORV to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

Pressurizer PORVs 3.4.11 McGuire Units 1 and 2 3.4.11-3 Amendment Nos. 330/309 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.

Two Train B PORVs inoperable and not capable of being manually cycled.

NOTE-------------------

Required Actions D.1 and D.2 are not applicable to PORVs made inoperable by Required Action I.2.

D.1 Close associated block valves.

AND D.2 Remove power from associated block valves.

AND D.3 Restore one PORV to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

Pressurizer PORVs 3.4.11 McGuire Units 1 and 2 3.4.11-4 Amendment Nos. 330/309 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E.

Required Action and associated Completion Time of Condition A, B, C or D not met.

E.1 Be in MODE 3.

AND E.2 Be in MODE 4.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours F.

Three PORVs inoperable and not capable of being manually cycled.

F.1 Close associated block valves.

AND F.2 Remove power from associated block valves.

AND F.3 Be in MODE 3.

AND F.4 Be in MODE 4.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours G.

One Train B block valve inoperable.

NOTE-------------------

Required Actions G.1 and G.2 are not applicable to a block valve made inoperable by Required Action B.2.

G.1 Place associated PORV switch in closed position and verify PORV closed.

AND G.2 Remove power from associated PORV.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour (continued)

Pressurizer PORVs 3.4.11 McGuire Units 1 and 2 3.4.11-5 Amendment Nos. 330/309 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME H.

One Train A block valve inoperable.

NOTE-------------------

Required Actions H.1 and H.2 are not applicable to a block valve made inoperable by Required Action C.2.

H.1 Place associated PORV switch in closed position and verify PORV closed.

AND H.2 Remove power from associated PORV.

AND H.3 Restore block valve to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

Pressurizer PORVs 3.4.11 McGuire Units 1 and 2 3.4.11-6 Amendment Nos. 330/309 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME I.

Two Train B block valves inoperable.

NOTE-------------------

Required Actions I.1 and I.2 are not applicable to block valves made inoperable by Required Action D.2.

I.1 Place associated PORV switches in closed position and verify PORVs closed.

AND I.2 Remove power from associated PORVs.

AND I.3 Restore one block valve to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

Pressurizer PORVs 3.4.11 McGuire Units 1 and 2 3.4.11-7 Amendment Nos. 330/309 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME J.

One Train B PORV inoperable and not capable of being manually cycled AND The other Train B block valve inoperable.

J.1 Perform Required Actions B.1 and B.2.

AND J.2 Perform Required Actions G.1 and G.2.

AND J.3.1 Restore PORV to OPERABLE status.

OR J.3.2 Restore block valve to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

Pressurizer PORVs 3.4.11 McGuire Units 1 and 2 3.4.11-8 Amendment Nos. 330/309 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME K.

Three block valves inoperable.

NOTE-------------------

Required Action K.1 is not applicable to block valves made inoperable by Required Action F.2.

K.1 Place associated PORV switches in closed position and verify PORVs closed.

AND K.2 Restore one block valve to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 2 hours L.

Required Action and associated Completion Time of Condition G, H, I, J or K not met.

L.1 Be in MODE 3.

AND L.2 Be in MODE 4.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours

Pressurizer PORVs 3.4.11 McGuire Units 1 and 2 3.4.11-9 Amendment Nos. 330/309 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1 ------------------------------NOTE------------------------------------

Not required to be met with block valve closed in accordance with the Required Action of Condition A, B, C, D, or F.

Perform a complete cycle of each block valve.

In accordance with the Surveillance Frequency Control Program SR 3.4.11.2 ------------------------------NOTE------------------------------------

Required to be performed in MODE 3 or MODE 4 when the temperature of all RCS cold legs is > 300°F and the block valve closed.

Perform a complete cycle of each PORV.

In accordance with the Surveillance Frequency Control Program SR 3.4.11.3 Verify the nitrogen supply for each PORV is OPERABLE by:

a.

Manually transferring motive power from the air supply to the nitrogen supply,

b.

Isolating and venting the air supply, and

c.

Operating the PORV through one complete cycle.

In accordance with the Surveillance Frequency Control Program

ECCS Operating 3.5.2 McGuire Units 1 and 2 3.5.2-1 Amendment Nos. 330/309 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS Operating LCO 3.5.2 Two ECCS trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

NOTE------------------------------------------------

In MODE 3, both safety injection (SI) pump or RHR 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.

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 OR In accordance with the Risk-Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 4.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours

Containment Air Locks 3.6.2 ACTIONS (continued)

McGuire Units 1 and 2 3.6.2-4 Amendment No. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME C.

One or more containment air locks inoperable for reasons other than Condition A or B.

C.1 Initiate action to evaluate overall containment leakage rate per LCO 3.6.1.

AND C.2 Verify a door is closed in the affected air lock.

AND C.3 Restore air lock to OPERABLE status.

Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 24 hours OR In accordance with the Risk-Informed Completion Time Program D.

Required Action and associated Completion Time not met.

D.1 Be in MODE 3.

AND D.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours

Containment Isolation Valves 3.6.3 McGuire Units 1 and 2 3.6.3-1 Amendment Nos. 330/309 3.6 CONTAINMENT SYSTEMS 3.6.3 Containment Isolation Valves LCO 3.6.3 Each containment isolation valve shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS

NOTES--------------------------------------------------------

1.

Penetration flow path(s) except for containment purge supply and/or exhaust isolation valves for the lower compartment, upper compartment, and incore instrument room may be unisolated intermittently under administrative controls.

2.

Separate Condition entry is allowed for each penetration flow path.

3.

Enter applicable Conditions and Required Actions for systems made inoperable by containment isolation valves.

4.

Enter applicable Conditions and Required Actions of LCO 3.6.1, "Containment," when isolation valve leakage results in exceeding the overall containment leakage rate acceptance criteria.

CONDITION REQUIRED ACTION COMPLETION TIME A.

NOTE-----------

Only applicable to penetration flow paths with two containment isolation valves.

One or more penetration flow paths with one containment isolation valve inoperable except for purge valve or reactor building bypass leakage not within limit.

A.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, blind flange, or check valve inside containment with flow through the valve secured.

AND 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months OR In accordance with the Risk-Informed Completion Time Program (continued)

Containment Isolation Valves 3.6.3 ACTIONS McGuire Units 1 and 2 3.6.3-2 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.2

NOTES--------------

1. Isolation devices in high radiation areas may be verified by use of administrative means.

2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means.

Verify the affected penetration flow path is isolated.

Once per 31 days following isolation for isolation devices outside containment AND Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days for isolation devices inside containment B.

NOTE------------

Only applicable to penetration flow paths with two containment isolation valves.

One or more penetration flow paths with two containment isolation valves inoperable except for purge valve or reactor building bypass leakage not within limit.

B.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (continued)

Containment Isolation Valves 3.6.3 ACTIONS (continued)

McGuire Units 1 and 2 3.6.3-3 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME C.

NOTE------------

Only applicable to penetration flow paths with only one containment isolation valve and a closed system.

One or more penetration flow paths with one containment isolation valve inoperable.

C.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.

AND C.2

NOTES------------

1. Isolation devices in high radiation areas may be verified by use of administrative means.

2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means.

Verify the affected penetration flow path is isolated.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program Once per 31 days following isolation D.

Reactor building bypass leakage not within limit.

D.1 Restore leakage within limit.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months E.

One or more penetration flow paths with one or more containment purge valves not within purge valve leakage limits.

E.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.

AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (continued)

Containment Spray System 3.6.6 McGuire Units 1 and 2 3.6.6-1 Amendment Nos. 330/309 3.6 CONTAINMENT SYSTEMS 3.6.6 Containment Spray System LCO 3.6.6 Two containment spray trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One containment spray train inoperable.

A.1 Restore containment spray train to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 84 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.6.1

NOTE--------------------------------

Not required to be met for system vent flow paths opened under administrative control.

Verify each containment spray manual and power operated 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 (continued)

HMS 3.6.9 McGuire Units 1 and 2 3.6.9-1 Amendment Nos. 330/309 3.6 CONTAINMENT SYSTEMS 3.6.9 Hydrogen Mitigation System (HMS)

LCO 3.6.9 Two HMS trains shall be OPERABLE.

APPLICABILITY:

MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One HMS train inoperable.

A.1 Restore HMS train to OPERABLE status.

OR A.2 Perform SR 3.6.9.1 on the OPERABLE train.

7 days OR In accordance with the Risk-Informed Completion Time Program Once per 7 days B.

One containment region with no OPERABLE hydrogen ignitor.

B.1 Restore one hydrogen ignitor in the affected containment region to OPERABLE status.

7 days OR In accordance with the Risk-Informed Completion Time Program 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

ARS 3.6.11 McGuire Units 1 and 2 3.6.11-1 Amendment No. 330/309 3.6 CONTAINMENT SYSTEMS 3.6.11 Air Return System (ARS)

LCO 3.6.11 Two ARS trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One ARS train inoperable.

A.1 Restore ARS train to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 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 FREQUENCY SR 3.6.11.1 Verify each ARS fan starts on an actual or simulated actuation signal, after a delay of 8 minutes and 10 minutes, and operates for 15 minutes.

In accordance with the Surveillance Frequency Control Program (continued)

Divider Barrier Integrity 3.6.14 McGuire Units 1 and 2 3.6.14-1 Amendment No. 330/309 3.6 CONTAINMENT SYSTEMS 3.6.14 Divider Barrier Integrity LCO 3.6.14 Divider barrier integrity shall be maintained.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

NOTE------------

For this action, separate Condition entry is allowed for each personnel access door or equipment hatch.

One or more personnel access doors or equipment hatches (other than one pressurizer or one steam generator enclosure hatch addressed by Condition D) open or inoperable, other than for personnel transit entry.

A.1 Restore personnel access doors and equipment hatches to OPERABLE status and closed positions.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OR In accordance with the Risk-Informed Completion Time Program B.

Divider barrier seal inoperable.

B.1 Restore seal 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 Be in MODE 3.

AND C.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours D.

One pressurizer or one steam generator enclosure hatch open or inoperable.

D.1 Restore affected hatch to OPERABLE status and closed position.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months

MSIVs 3.7.2 McGuire Units 1 and 2 3.7.2-1 Amendment Nos. 330/309 3.7 PLANT SYSTEMS 3.7.2 Main Steam Isolation Valves (MSIVs)

LCO 3.7.2 Four MSIVs shall be OPERABLE.

APPLICABILITY:

MODE 1, MODES 2 and 3 except when MSIVs are closed and de-activated.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One MSIV inoperable in MODE 1.

A.1 Restore MSIV to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months OR In accordance with the Risk-Informed Completion Time Program B.

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

B.1 Be in MODE 2.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months C.

NOTE-----------

Separate Condition entry is allowed for each MSIV.

One or more MSIVs inoperable in MODE 2 or 3.

C.1 Close MSIV.

AND C.2 Verify MSIV is closed.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Once per 7 days (continued)

AFW System 3.7.5 McGuire Units 1 and 2 3.7.5-1 Amendment Nos. 330/309 3.7 PLANT SYSTEMS 3.7.5 Auxiliary Feedwater (AFW) System LCO 3.7.5 Three AFW trains shall be OPERABLE.

NOTE--------------------------------------------

Only one AFW train, which includes a motor driven pump, is required to be OPERABLE in MODE 4.

APPLICABILITY:

MODES 1, 2, and 3, MODE 4 when steam generator is relied upon for heat removal.

ACTIONS

NOTE------------------------------------------------------------------------

LCO 3.0.4.b is not applicable when entering MODE 1.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One steam supply to turbine driven AFW pump inoperable.

OR

NOTE------------

Only applicable if MODE 2 has not been entered following refueling.

One turbine driven AFW pump inoperable in MODE 3 following refueling.

A.1 Restore affected equipment to OPERABLE status.

7 days OR In accordance with the Risk-Informed Completion Time Program B.

One AFW train inoperable in MODE 1, 2 or 3 for reasons other than Condition A.

B.1 Restore AFW train to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

CCW System 3.7.6 McGuire Units 1 and 2 3.7.6-1 Amendment Nos. 330/309 3.7 PLANT SYSTEMS 3.7.6 Component Cooling Water (CCW) System LCO 3.7.6 Two CCW trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One CCW train inoperable.

A.1

NOTE--------------

Enter applicable Conditions and Required Actions of LCO 3.4.6, "RCS Loops MODE 4,"

for residual heat removal loops made inoperable by CCW.

Restore CCW train to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program B.

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

B.1 Be in MODE 3.

AND B.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours

NSWS 3.7.7 McGuire Units 1 and 2 3.7.7-1 Amendment Nos. 330/309 3.7 PLANT SYSTEMS 3.7.7 Nuclear Service Water System (NSWS)

LCO 3.7.7 Two NSWS trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One NSWS train inoperable.

A.1

NOTES------------

1.

Enter applicable Conditions and Required Actions of LCO 3.8.1, "AC Sources Operating,"

for emergency diesel generator made inoperable by NSWS.

2.

Enter applicable Conditions and Required Actions of LCO 3.4.6, "RCS LoopsMODE 4," for residual heat removal loops made inoperable by NSWS.

Restore NSWS train to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

NSWS 3.7.7 ACTIONS (continued)

McGuire Units 1 and 2 3.7.7-2 Amendment Nos. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME B.

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

B.1 Be in MODE 3.

AND B.2 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 FREQUENCY SR 3.7.7.1

NOTE----------------------------------

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

Verify each NSWS 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 NSWS automatic valve in the flow path servicing safety related equipment, 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 NSWS pump starts automatically on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 McGuire Units 1 and 2 3.8.1-2 Amendment No. 330/309 ACTIONS

NOTE-------------------------------------------------------------

LCO 3.0.4.b is not applicable to DGs.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One LCO 3.8.1.a offsite circuit inoperable.

A.1 Perform SR 3.8.1.1 for required OPERABLE offsite circuit(s).

AND A.2 Declare required feature(s) with no offsite power available inoperable when its redundant required feature(s) is inoperable.

AND A.3 Restore offsite circuit to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of no offsite power to one train concurrent with inoperability of redundant required feature(s) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

AC Sources - Operating 3.8.1 ACTIONS (continued)

McGuire Units 1 and 2 3.8.1-4 Amendment No. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME B.

(continued)

B.5 Restore DG to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

AC Sources - Operating 3.8.1 ACTIONS (continued)

McGuire Units 1 and 2 3.8.1-5 Amendment No. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME C.

One LCO 3.8.1.c offsite circuit inoperable.

NOTE--------------------

Enter applicable Conditions and Required Actions of LCO 3.8.9, Distribution Systems - Operating, when Condition C is entered with no AC power source to a train.

C.1 Perform SR 3.8.1.1 for the required offsite circuit(s).

AND C.2 Declare NSWS, CRAVS, CRACWS or ABFVES with no offsite power available inoperable when the redundant NSWS, CRAVS, CRACWS or ABFVES is inoperable.

AND C.3 Restore LCO 3.8.1.c offsite circuit to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of no offsite power to one train concurrent with inoperability of redundant required feature(s) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk-Informed Completion Time Program (continued)

AC Sources - Operating 3.8.1 ACTIONS (continued)

McGuire Units 1 and 2 3.8.1-7 Amendment No. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME D.

(continued)

D.4.1 Determine OPERABLE DG(s) is not inoperable due to common cause failures.

OR D.4.2 Perform SR 3.8.1.2 for OPERABLE DG(s).

AND D.5.1 Restore LCO 3.8.1.d DG to OPERABLE status.

OR D.5.2 Align NSWS, CRAVS, CRACWS and ABFVES supported by the inoperable LCO 3.8.1.d DG to an OPERABLE DG.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 24 hours 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 72 hours E.

Two LCO 3.8.1.a offsite circuits inoperable.

OR One LCO 3.8.1.a offsite circuit that provides power to the NSWS, CRAVS, CRACWS and ABFVES inoperable and one LCO 3.8.1.c offsite circuit inoperable.

OR Two LCO 3.8.1.c offsite circuits inoperable.

E.1 Declare required feature(s) inoperable when its redundant required feature(s) is inoperable.

AND E.2 Restore one offsite circuit to OPERABLE status.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from discovery of Condition E concurrent with inoperability of redundant required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk-Informed Completion Time Program (continued)

AC Sources - Operating 3.8.1 ACTIONS (continued)

McGuire Units 1 and 2 3.8.1-8 Amendment No. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME F.

One LCO 3.8.1.a offsite circuit inoperable.

AND One LCO 3.8.1.b DG inoperable.

NOTE-------------------

Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems Operating," when Condition F is entered with no AC power source to any train.

F.1 Restore offsite circuit to OPERABLE status.

OR F.2 Restore DG to OPERABLE status.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR In accordance with the Risk-Informed Completion Time Program 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR In accordance with the Risk-Informed Completion Time Program (continued)

AC Sources - Operating 3.8.1 ACTIONS (continued)

McGuire Units 1 and 2 3.8.1-9 Amendment No. 330/309 G.

Two LCO 3.8.1.b DGs Inoperable.

OR LCO 3.8.1.b DG that provides power to the NSWS, CRAVS, CRACWS and ABFVES inoperable and one LCO 3.8.1.d DG inoperable.

OR Two LCO 3.8.1.d DGs inoperable.

G.1 Restore one DG to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months H.

One automatic load sequencer inoperable.

H.1 Restore automatic load sequencer to OPERABLE status.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR In accordance with the Risk-Informed Completion Time Program (continued)

AC Sources - Operating 3.8.1 ACTIONS (continued)

McGuire Units 1 and 2 3.8.1-10 Amendment No. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME I.

Required Action and associated Completion Time of Condition A, C, E, F, G, or H not met.

OR Required Action and associated Completion Time of Required Action B.2, B.3, B.4.1, B.4.2, or B.5 not met.

OR Required Action and associated Completion Time of Required Action D.2, D.3, D.4.1, D.4.2, D.5.1, or D.5.2 not met.

I.1 Be in MODE 3.

AND I.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours J.

Three or more LCO 3.8.1.a and LCO 3.8.1.b AC sources inoperable.

OR Three or more LCO 3.8.1.c and LCO 3.8.1.d AC sources inoperable.

J.1 Enter LCO 3.0.3.

Immediately

AC Sources - Operating 3.8.1 McGuire Units 1 and 2 3.8.1-11 Amendment No. 330/309 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power availability for each offsite circuit.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.2

NOTES--------------------------------

1.

Performance of SR 3.8.1.7 satisfies this SR.

2.

All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.

3.

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 (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-12 Amendment No. 330/309 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 3600 kW and 4000 kW.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.4 Verify each day tank contains 39 inches of fuel oil.

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 Surveillance Frequency Control Program SR 3.8.1.6 Verify the fuel oil transfer system operates to automatically transfer fuel oil from storage tank to the day tank.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-13 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.7

NOTES--------------------------------

All DG starts may be preceded by an engine prelube period.

Verify each DG starts from standby condition and achieves in 11 seconds voltage of 3740 V and frequency of 57 Hz and maintains 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 SR 3.8.1.8

NOTES--------------------------------

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. Credit may be taken for unplanned events that satisfy this SR.

Verify automatic and manual transfer of AC power sources from the normal offsite circuit to each alternate offsite circuit.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-14 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.9 Verify each DG, when connected to its bus in parallel with offsite power and operating with maximum kVAR loading that offsite power conditions permit, rejects a load greater than or equal to its associated single largest post-accident load, and:

a.

Following load rejection, the frequency is 63 Hz;

b.

Within 3 seconds following load rejection, the voltage is 3740 V and 4320 V; and

c.

Within 3 seconds following load rejection, the frequency is 58.8 Hz and 61.2 Hz.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.10 Verify each DG does not trip and voltage is maintained 4784 V during and following a load rejection of 3600 kW and 4000 kW.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-15 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.11 --------------------------------NOTES--------------------------------

1.

All DG starts may be preceded by an engine prelube period.

2.

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated loss of offsite power signal:

a.

De-energization of emergency buses;

b.

Load shedding from emergency buses;

c.

DG auto-starts from standby condition and:

1.

energizes the emergency bus in 11 seconds,

2.

energizes auto-connected blackout loads through automatic load sequencer,

3.

maintains steady state voltage 3740 V and 4320 V,

4.

maintains steady state frequency 58.8 Hz and 61.2 Hz, and

5.

supplies auto-connected blackout loads for 5 minutes.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-16 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.12

NOTES--------------------------------

All DG starts may be preceded by prelube period.

Verify on an actual or simulated Engineered Safety Feature (ESF) actuation signal each DG auto-starts from standby condition and:

a.

In 11 seconds after auto-start signal achieves voltage of 3740 and during tests, achieves steady state voltage 3740 V and 4320 V;

b.

In 11 seconds after auto-start signal achieves frequency of 57 Hz and during tests, achieves steady state frequency 58.8 Hz and 61.2 Hz;

c.

Operates for 5 minutes; and

d.

The emergency bus remains energized from the offsite power system.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-17 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.13 Verify each DG's non-emergency automatic trips are bypassed on actual or simulated loss of voltage signal on the emergency bus concurrent with an actual or simulated ESF actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.14 --------------------------------NOTES--------------------------------

1.

Momentary transients outside the load range do not invalidate this test.

2.

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

Verify each DG, when connected to its bus in parallel with offsite power and operating with maximum kVAR loading that offsite power conditions permit, operates for 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s:

a.

For 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded 4200 kW and 4400 kW; and

b.

For the remaining hours of the test loaded 3600 kW and 4000 kW.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-18 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.15 --------------------------------NOTES--------------------------------

1.

This Surveillance shall be performed within 5 minutes of shutting down the DG after the DG has operated 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded 3600 kW and 4000 kW.

Momentary transients outside of load range do not invalidate this test.

2.

All DG starts may be preceded by an engine prelube period.

Verify each DG starts and achieves, in 11 seconds, voltage 3740 V, and frequency 57 Hz and maintains 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 SR 3.8.1.16 -------------------------------NOTES---------------------------------

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. Credit may be taken for unplanned events that satisfy this SR.

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 standby operation.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-19 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.17

NOTES--------------------------------

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ESF actuation signal overrides the test mode by:

a.

Returning DG to standby operation; and

b.

Automatically energizing the emergency load from offsite power.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.18 Verify interval between each sequenced load block is within design interval for each automatic load sequencer.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-20 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.19 --------------------------------NOTES--------------------------------

1.

All DG starts may be preceded by an engine prelube period.

2.

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ESF actuation signal:

a.

De-energization of emergency buses;

b.

Load shedding from emergency buses; and

c.

DG auto-starts from standby condition and:

1.

energizes the emergency bus in 11

seconds,

2.

energizes auto-connected emergency loads through load sequencer,

3.

achieves steady state voltage 3740 V and 4320 V,

4.

achieves steady state frequency 58.8 Hz and 61.2 Hz, and

5.

supplies auto-connected emergency loads for 5 minutes.

In accordance with the Surveillance Frequency Control Program (continued)

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

McGuire Units 1 and 2 3.8.1-21 Amendment No. 330/309 SURVEILLANCE FREQUENCY SR 3.8.1.20 --------------------------------NOTES--------------------------------

All DG starts may be preceded by an engine prelube period.

Verify when started simultaneously from standby condition, each DG achieves, in 11 seconds, voltage of 3740 V and frequency of 57 Hz and maintains 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

DC Sources - Operating 3.8.4 McGuire Units 1 and 2 3.8.4-1 Amendment No. 330/309 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC Sources Operating LCO 3.8.4 The four channels of DC sources shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One channel of DC source inoperable.

A.1 Restore channel of DC source to OPERABLE status.

OR A.2.1 Verify associated bus tie breakers are closed between DC channels.

AND A.2.2 Restore channel of DC source to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OR In accordance with the Risk-Informed Completion Time Program 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 72 hours OR In accordance with the Risk-Informed Completion Time Program B.

Required Action and Associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours

Inverters - Operating 3.8.7 McGuire Units 1 and 2 3.8.7-1 Amendment No. 330/309 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Inverters Operating LCO 3.8.7 The four required Channels of inverters shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One 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 OR In accordance with the Risk-Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours

Inverters - Operating 3.8.7 McGuire Units 1 and 2 3.8.7-2 Amendment No. 330/309 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct inverter voltage, and alignment to required AC vital buses.

In accordance with the Surveillance Frequency Control Program

Distribution Systems - Operating 3.8.9 McGuire Units 1 and 2 3.8.9-1 Amendment No. 330/309 3.8 ELECTRICAL POWER SYSTEMS 3.8.9 Distribution Systems Operating LCO 3.8.9 Train A and Train B AC, four channels of DC, and four AC vital buses electrical power distribution subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more AC electrical power distribution subsystem(s) inoperable.

A.1 Restore AC electrical power distribution subsystem(s) to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months OR In accordance with the Risk-Informed Completion Time Program B.

One AC vital bus 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 OR In accordance with the Risk-Informed Completion Time Program (continued)

Distribution Systems - Operating 3.8.9 ACTIONS (continued)

McGuire Units 1 and 2 3.8.9-2 Amendment No. 330/309 CONDITION REQUIRED ACTION COMPLETION TIME C.

One channel of DC electrical power distribution subsystem inoperable.

C.1 Restore DC channel of electrical power distribution subsystem to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OR In accordance with the Risk-Informed Completion Time Program D.

Required Action and associated Completion Time not met.

D.1 Be in MODE 3.

AND D.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours E.

Two trains with inoperable distribution subsystems that result in a loss of safety function.

E.1 Enter LCO 3.0.3.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.9.1 Verify correct breaker alignments and voltage to AC, DC, and AC vital bus electrical power distribution subsystems.

In accordance with the Surveillance Frequency Control Program

Programs and Manuals 5.5 (continued)

McGuire Units 1 and 2 5.5-16 Amendment No. 330/309 5.5 Programs and Manuals 5.5.17 Surveillance Frequency Control Program (continued)

c.

The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

5.5.18 Risk-Informed Completion Time Program This program provides controls to calculate a Risk-Informed Completion Time (RICT) and must be implemented in accordance with NEI 06-09-A, Revision 0, Risk-Managed Technical Specifications (RMTS) Guidelines. The program shall include the following:

a.

The RICT may not exceed 30 days;

b.

A RICT may only be utilized in MODE 1 and 2;

c.

When a RICT is being used, any change to the plant configuration, as defined in NEI 06-09-A, Appendix A, must be considered for the effect on the RICT.

1. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration.

2. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

3. Revising the RICT is not required if the plant configuration change would lower plant risk and would result in a longer RICT.

d.

For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:

1. Numerically accounting for the increased possibility of CCF in the RICT calculation; or

2. Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.

Programs and Manuals 5.5 McGuire Units 1 and 2 5.5-17 Amendment No. 330/309 5.5 Programs and Manuals 5.5.18 Risk-Informed Completion Time Program (continued) e.

The risk assessment approaches and methods shall be acceptable to the NRC. The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods approved for use with this program, or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 330 TO RENEWED FACILITY OPERATING LICENSE NPF-9 AND AMENDMENT NO. 309 TO RENEWED FACILITY OPERATING LICENSE NPF-17 DUKE ENERGY CAROLINAS, LLC MCGUIRE NUCLEAR STATION, UNITS 1 AND 2 DOCKET NOS. 50-369 AND 50-370

1.0 INTRODUCTION

By application dated February 16, 2023 (Reference 1), as supplemented by letter dated November 2, 2023 (Reference 2) Duke Energy Carolinas, LLC (the licensee), requested changes to the technical specifications (TS) and licenses for the McGuire Nuclear Station, Units 1 and 2 (McGuire).

Specifically, the licensee requested changes to the TS and licenses to adopt the use of Risk-Informed Completion Times (RICTs) for actions to be taken when limiting conditions for operation (LCOs) are not met. The proposed changes are based on Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF [Risk-Informed TSTF] Initiative 4b, dated July 2, 2018 (TSTF-505)

(Reference 3). The U.S. Nuclear Regulatory Commission (NRC, the Commission) issued a final revised model safety evaluation (SE) for use when preparing a plant-specific SE to adopt TSTF-505 on November 21, 2018 (Reference 4).

The amendments also include proposed variations from TS changes approved in TSTF-505 as provided in Section 2.3, Optional Variations, of Attachment 1, Description and Assessment of the Proposed Change," to its letter dated February 16, 2023.

The NRC staff conducted a regulatory audit from May 1 to December 8, 2023, to review the licensees supporting analysis and to finalize any requests for additional information (RAIs) that may need to be submitted on the docket. By letter dated November 2, 2023, that included additional information resulting from the audit. On January 25, 2024, the NRC staff issued an audit summary (Reference 5).

The supplement dated November 2, 2023, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the staffs original proposed no significant hazards consideration determination as published the Federal Register on May 16, 2023 (88 FR 31285).

2.0 REGULATORY EVALUATION

2.1 Regulatory Review 2.1.1 Applicable Regulations Title 10 of the Code of Federal Regulations (10 CFR) Part 50 provides the general provisions for Domestic Licensing of Production and Utilization Facilities. The general provisions include but are not limited to establishing the regulatory requirements that a licensee must adhere to for the submittal of a license application. The NRC staff has identified the following applicable sections within 10 CFR Part 50 for the staffs review of the licensees application to adopt TSTF-505, Revision 2.

Paragraph (c)(2)(i), Limiting conditions for operation, of 10 CFR 50.36 states, in part, "Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow remedial action permitted by the technical specifications until the condition can be met."

Paragraph (c)(5), Administrative controls, of 10 CFR 50.36, Technical specifications, states, in part, that administrative controls are "the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure operation of the facility in a safe manner."

Paragraph (h), Protection and safety systems, of 10 CFR 50.55a, Codes and standards, states, in part, that "Protection systems of nuclear power reactors of all types must meet the requirements specified in this paragraph."

Section 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants, (i.e., the Maintenance Rule) of 10 CFR requires licensees to monitor the performance or condition of structures, systems, or components (SSCs) against licensee-established goals in a manner sufficient to provide reasonable assurance that these SSCs are capable of fulfilling their intended functions. Section 50.65(a)(4) states, in part, that, Before performing maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The scope of the assessment may be limited to structures, systems, and components that a risk-informed evaluation process has shown to be significant to public health and safety.

10 CFR Part 50, Appendix A, General Design Criteria (GDC) for Nuclear Power Plants, Criterion 15, Reactor coolant system design, states, in part, that the reactor coolant system and associated auxiliary, control, and protection systems shall be designed with sufficient margin to assure that the design conditions of the reactor coolant pressure boundary are not exceeded during any condition of normal operation, including anticipated operational occurrences.

2.1.2 Regulatory Guidance NRC Regulatory Guides (RGs) provide one way for the licensee to ensure that the NRCs regulations continue to be met. The NRC staff considered the following guidance, along with industry guidance endorsed by the NRC, during its review of the proposed changes:

RG 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities (Reference 6).

RG 1.174, Revisions 2, An Approach for Using Probabilistic Risk Assessment in Risk Informed Decisions on Plant Specific Changes to the Licensing Basis (Reference 7).

RG 1.177, Revision 2, An Approach for Plant Specific, Risk Informed Decision making: Technical Specifications (Reference 8).

RG 1.160, Revision 0, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants (Reference 9) ML12216A016.

NUREG 1855, Revision 1, Guidance on the Treatment of Uncertainties Associated with PRAs [Probabilistic Risk Assessments] in Risk Informed Decisionmaking (Reference 10).

NUREG 0800, Standard Review Plan [SRP] for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR [Light-Water Reactor] Edition, Section 16.1, Risk-Informed Decision Making: Technical Specifications (Reference 11).

Nuclear Energy Institute (NEI) Topical Report NEI 06-09, Revision 0-A, Risk Informed Technical Specifications Initiative 4b, Risk Managed Technical Specifications (RMTS) Guidelines, dated October 2012 (NEI 06-09-A) (Reference 12), provides guidance for risk-informed TS. The NRC staff issued a final SE approving NEI 06-09 on May 17, 2007 (Reference 13).

2.2 Description of the RICT The TS LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO is not met, the licensee must shut down the reactor or follow any required action (e.g., testing, maintenance, or repair activity) permitted by the TS until the condition can be met. The required actions (i.e., ACTIONS) associated with an LCO contain conditions that typically describe the ways in which the requirements of the LCO can fail to be met. Specified with each stated condition are Required Action(s) and Completion Time(s) (CTs). The CTs are referred to as the front stops in the context of this SE. For certain conditions, the TS require exiting the Mode of Applicability of an LCO (i.e., shut down the reactor).

In Attachment 1 to its letter dated February 16, 2023, the licensee states, in part, that, The proposed amendment would modify the Technical Specifications (TS) requirements related to Completion Times (CTs) for Required Actions to provide the option to calculate a longer, risk-informed CT (RICT). A new program, the Risk-Informed Completion Time Program, is added to TS Section 5, Administrative Controls.

The methodology for using the RICT Program is described in NEI 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, Revision 0 (ADAMS Accession No. ML071200238), which was approved by the Nuclear Regulatory Commission (NRC) on May 17, 2007. Adherence to NEI 06-09-A is required by the RICT Program.

The proposed amendment is consistent with Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b. However, only those Required Actions described in and Enclosure 1, as reflected in the proposed TS mark-ups provided in, are proposed to be changed. This is because some of the modified Required Actions in TSTF-505 are not applicable to McGuire Nuclear Station (MNS),

Units 1 and 2, and there are some plant-specific Required Actions not included in TSTF-505 that are included in this proposed amendment.

The licensee is proposing no changes to the design of the plant or any operating parameter, and no changes to the design basis as described in the Updated Final Safety Analysis Report (UFSAR). The effect of the proposed changes, when implemented, will allow CTs to vary based on the risk significance of the given plant configuration (i.e., the equipment out of service at any given time), provided that the system(s) retain(s) the capability to perform the applicable safety function(s) without any further failures (e.g., one train of a two train system is inoperable). These restrictions on inoperability of all required trains of a system ensure that consistency with the defense-in-depth (DID) philosophy is maintained by following existing guidance when the capability to perform TS safety function(s) is lost.

The proposed RICT Program uses plant-specific operating experience for component reliability and availability data. Thus, the allowances permitted by the RICT Program are directly reflective of actual component performance in conjunction with component risk significance.

Example 1.3-8, will be added to TS 1.3, CTs, and will read as follows:

EXAMPLE 1.3-8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One subsystem inoperable.

A.1 Restore subsystem to OPERABLE status.

7 days OR In accordance with the Risk-Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours When a subsystem is declared inoperable, Condition A is entered.

The 7 day CT may be applied as discussed in Example 1.3-2.

However, the licensee may elect to apply the Risk-Informed Completion Time Program which permits calculation of a Risk-Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day CT. The RICT cannot exceed 30 days. After the 7 day Completion Time has expired, the subsystem must be restored to OPERABLE status or Condition B must also be entered.

The Risk-Informed Completion Time Program requires recalculation of the RICT to reflect changing plant conditions. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

If the 7 day Completion Time clock of Condition A has expired and subsequent changes in plant condition result in exiting the applicability of the Risk-Informed Completion Time Program without restoring the inoperable subsystem to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start.

If the RICT expires or is recalculated to be less than the elapsed time since the Condition was entered and the inoperable subsystem has not been restored to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable subsystems are restored to OPERABLE status after Condition B is entered, Conditions A and B are exited, and therefore, the Required Actions of Condition B may be terminated.

3.0 TECHNICAL EVALUATION

An acceptable approach for making risk-informed decisions about proposed TS changes, including both permanent and temporary changes, is to demonstrate that the proposed licensing basis changes meet the five key principles provided in RGs 1.174 and 1.177 and the three-tiered approach outlined in RG 1.177. As stated in RG 1.177, the key principles and tiers are:

Principle 1:

The proposed licensing basis change meets the current regulations unless it is explicitly related to a requested exemption.

Principle 2:

The proposed licensing basis change is consistent with the defense-in-depth [DID] philosophy.

Principle 3:

The proposed licensing basis change maintains sufficient safety margins.

Principle 4:

When the proposed licensing basis changes result in an increase in risk, the increase should be small and consistent with the intent of the Commissions policy statement on safety goals for the operations of nuclear power plants.

Tier 1: PRA Capability and Insights

Tier 2: Avoidance of Risk-Significant Plant Configurations

Tier 3: Risk-Informed Configuration Risk Management Principle 5:

The impact of the proposed licensing basis change should be monitored using performance measures strategies.

3.1 Method of NRC Staff Review Each of the key principles and tiers are addressed in NEI 06-09-A and approved in the final model SE issued by the NRC for TSTF-505, Revision 2 (Reference 4). NEI 06-09-A provides a methodology for extending existing CTs, and to thereby delay exiting the operational mode of applicability or taking Required Actions if risk is assessed and managed within the limits and programmatic requirements established by a RICT Program. The NRC staffs evaluation of the licensees proposed use of RICTs against the key safety principles of RGs 1.174 and 1.177 is discussed below.

3.2 Review of Key Principles 3.2.1 Key Principle 1: Evaluation of Compliance with Current Regulations Paragraph 50.36(c)(2) of 10 CFR requires that LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any required action permitted by the TS until the condition can be met.

The CTs in the current TS were established using experiential data, risk insights, and engineering judgement. The RICT Program provides the necessary administrative controls to permit extension of CTs and, thereby, delay reactor shutdown or Required Actions, if risk is assessed and managed appropriately within specified limits and programmatic requirements and the safety margins and DID remains sufficient. The option to determine the extended CT in accordance with the RICT Program allows the licensee to perform an integrated evaluation in accordance with the methodology prescribed in NEI 06-09-A and proposed TS 5.5.18, Risk-Informed Completion Time Program. The RICT is limited to a maximum of 30 days (termed the back stop).

The typical CT is modified by the application of the RICT Program as shown in the following example. The changed portion is indicated in italics.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One subsystem inoperable.

A.1 Restore subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program In Attachment 2, Proposed Technical Specification Changes (Mark-Up), to the licensees submittal dated February 16, 2023 (Reference 1), and Enclosure 1, List of Revised Required Actions to Corresponding PRA Functions, to the licensees letter dated November 2, 2023 (Reference 2), the licensee provided its proposed revision to the TS, associated LCOs, and Required Actions for the CTs that included modifications and variations from the approved TSTF-505, Revision 2 (Reference 4). The modifications and variations consisted of proposed changes to certain Required Actions and CTs. The NRC staff provides a detailed discussion below regarding the variation for TS 3.4.11, Pressurizer Power Operated Relief Valves (PORVs).

Consistent with Table 1 of TSTF-505, Revision 2 (Reference 3), and in its letter dated February 16, 2023 (Reference 2), Enclosure 1, Table E1-3, Identified Required Actions Which Require Additional Justification for Inclusion in TSTF-505 Application, the licensee provided additional justification to demonstrate acceptability for the following;

TS 3.3.1, Reactor Trip System (RTS) Instrumentation, Conditions 3.3.1.D, 3.3.1.U;

TS 3.3.5, Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation, Condition 3.3.5.B.;

TS 3.5.2, ECCS [Emergency Core Cooling System] - Operating, Condition 3.5.2.A.;

TS 3.6.2, Containment Air Locks, Condition 3.6.2.C.;

TS 3.6.6, Containment Spray System, Condition 3.6.6.A., and

TS 3.7.2, Main Steam Isolation Valves (MSIVs), Condition 3.7.2.A. in the RICT program.

In Attachment 4, Mark-up of McGuire Units 1 and 2 Renewed Facility Operating Licenses, of its letter dated November 2, 2023, the licensee requested to delete two license conditions added to Appendix B, Additional Conditions, in amendment numbers 314 and 293 (Reference 14), respectively, that are no longer necessary. These license proposed to add two new license conditions one associated with its submittal to adopt risk-informed treatment of structures, systems, and components in accordance with 10 CFR 50.69 (Reference 1, as edited, in Reference 2) and the second associated with this amendment to adopt TSTF-505. This SE only evaluates the elimination of the two license conditions for amendments 314 and 293, respectively, and addition of the proposed TSTF-505 license condition that would state, For the Risk-Informed Completion Time (RICT) calculations within the Risk-Informed Completion Time Program, a singular approach for the high winds external hazard will be specified and utilized for a given RICT. Either a high winds penalty or a high winds probabilistic risk assessment (PRA) will be utilized in the RICT Program calculations. A high winds PRA and high winds penalty shall not be used simultaneously to determine RICTs within the RICT Program.

The current license conditions associated with amendment 314 and 293 were for control of the turbine-driven auxiliary feedwater pump and other equipment as protected equipment to maintain PRA risk estimates per RG 1.174 and 1.177 concerning that amendments 14-day extended emergency diesel generator (DG) CT. Since the 14-day emergency DG CT is proposed to be eliminated as part of this proposed LARs RICT Program, the licensee proposed to eliminate these two license conditions.

The NRC staff reviewed the proposed changes to the TS, associated LCOs, Required Actions, and CTs provided by the licensee for the scope of the RICT Program and concluded that, with the incorporation of the RICT Program, the required performance levels of equipment specified in LCOs are not changed, only the required CT for the Required Actions are modified, such that 10 CFR 50.36(c)(2) will continue to be met. Based on the discussion provided above, the NRC staff finds that the TS program provided in section 2.0 of this SE, its LCOs, Required Actions, and CTs meet the first key principle of RGs 1.174 and 1.177.

The proposed new license condition for TSTF-505 regarding high winds external hazard is evaluated in Section 3.2.4.1 of this SE. The proposed 10 CFR 50.69 license condition is evaluated in a separate NRC review and SE.

3.2.1.1 Key Principle 1: Evaluation of Compliance with Current Regulations for TS 3.4.11, Pressurizer Power Operated Relief Valves (PORVs) Change Regarding the proposed TS 3.4.11 variation, the NRC staff notes that the McGuire pressurizer power operated relief valves (PORV) system consists of two separate trains with a total of three PORVs and three block valves per unit. This is set up in two trains: Train A with a single PORV and block valve and Train B with two PORVS, each with its own block valve. This design requires three PORVs to be OPERABLE to meet reactor coolant system pressure boundary requirements as stated in General Design Criteria (GDC) Criterion 15 of Appendix A to 10 CFR

Part 50. The block valves are available to isolate the flow path through either a failed open PORV or a PORV with excessive leakage.

In its letter dated February 16, 2023, the licensee states, in part, that, Condition J: One Train B PORV inoperable and not capable of being manually cycled AND The other Train B block valve inoperable. Each MNS unit has three PORVs, each with an associated block valve, that are powered from two separate safety trains. Train A constitutes one PORV and an associated block valve. Train B constitutes two PORVs, each with an associated block valve. The three PORVs and their associated block valves are required to be operable for manual operation to mitigate the effects associated with a steam generator tube rupture. By maintaining two PORVs, one from each train, and their associated block valves operable, the single failure criterion is satisfied. All three PORVs are required to be operable to meet RCS pressure boundary requirements. The block valves function to isolate the flow path through either a failed open PORV or a PORV with excessive leakage.

MNS TS 3.4.11 Condition J is a plant-specific Condition not in the NUREG-1431 STS

[Reference 15], and therefore not in TSTF-505, Revision 2.

Condition J applies to one Train B PORV and the other Train B block valve (i.e., block valve associated with the Train B PORV remaining operable) inoperable. Because one Train A PORV and associated block valve remain operable for this condition, Required Actions J.3.1 and J.3.2 allow 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to restore either the PORV or block valve to operable status. There is no loss of function for this condition because of the operable Train A PORV and associated block valve.

As indicated in Table E1-1 of Enclosure 1, the configuration associated with TS 3.4.11 Condition J is explicitly modeled in the MNS PRA. The PRA success criteria are also described in Enclosure 1.

Therefore, TS 3.4.11 Condition J meets the requirements for inclusion in the RICT Program.

Based on the above, the NRC staff finds the proposed variation to TS 3.4.11, Pressurizer PORVs, Condition TS 3.4.11.J. is acceptable as it is consistent with the NRC-approved guidance in NEI 06-09-A (Reference 13) and that the licensees proposed change to the TS implements RMTS guidelines appropriately. Further, the NRC staff concludes that the proposed TS change will continue to meet the requirements of 50.36(c)(2) because the proposed LCOs will continue to provide the lowest functional capability or performance levels of equipment required for safe operation of the facility; stipulate that if an LCO is not met, the facility must be shut down, or other acceptable remedial action must be taken. Therefore, the NRC staff concludes that the remedial actions, as amended by the proposed change, will ensure that facility operation remains safe during the time the LCOs are not met. Therefore, the proposed changes to the TS are acceptable.

3.2.2 Key Principle 2: Evaluation of DID RG 1.174, Revision 2, provides the following considerations for evaluation of a licensing basis (LB) change for consistency with the DID philosophy:

A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation.

Overreliance on programmatic activities as compensatory measures associated with the change in the LB 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).

Defenses against potential common cause failures [CCFs] are preserved, and the potential for new common cause failure mechanisms is assessed.

Independence of barriers is not degraded.

Defenses against human errors are preserved.

The intent of the plants design criteria is maintained.

The licensee requested to use the RICT Program to extend the existing CTs for the respective TS LCOs described in Reference 1, Attachment 2. For the TS LCOs in Reference 1, Enclosure 1, the licensee provided a description and assessment of the redundancy and diversity for the proposed changes. The NRC staffs evaluation of the proposed changes for these LCOs assessed McGuires redundant or diverse means to mitigate accidents to ensure consistency with the plant licensing basis requirements using the guidance in RGs 1.174, Revision 2, and 1.177, Revision 2, and TSTF-505, Revision 2 to ensure adequate DID (for each of the functions) to operate the facility in the proposed manner (i.e., that the changes are consistent with the DID criteria).

In Reference 2, Enclosure 1, the licensee provided supplemental information supporting the McGuire evaluation of the redundancy, diversity, and DID for each TS LCO and TS Required Action as it relates to instrumentation and control (I&C) and electrical power systems. The NRC confirmed that for the following TS LCOs, the above DID criteria were applicable -- except for the criteria for maintaining multiple fission product barriers --;

TS 3.3.1, Reactor Trip System (RTS) Instrumentation,

TS 3.3.2, Engineered Safety Features Actuation System (ESFAS) Instrumentation,

TS 3.8.1, AC Sources - Operating,

TS 3.8.4, DC Sources - Operating,

TS 3.8.7, Inverters - Operating, and

TS 3.8.9, Distribution Systems - Operating.

For the I&C TS LCOs the NRC staff reviewed the specific trip logic arrangements, redundancy, backup systems, manual actions, and diverse trips specified for each of the protective safety functions and associated instrumentation as described in the Updated Final Safety Analysis Report (UFSAR), (Reference 16), sections, as reflected in Reference 2, Enclosure 1, for each I&C LCO above. Based on this review, the NRC staff verified that a) when there is a loss of function in all applicable operating modes that the RICT program would not be applied and, b) that the affected protective feature performs its intended function by ensuring the ability to detect and mitigate the associated event or accident when the CT of a channel is extended.

Furthermore, the NRC staff concludes that there is sufficient I&C redundancy, diversity, and DID to protect against CCFs and potential single failure for the instrumentation systems evaluated in Reference 2, Enclosure 1, during a RICT. There is at least one diverse means, including manual actuations, specified by the licensee for initiating mitigating action for each accident event thus providing DID against a failure of instrumentation during the RICT for each TS LCO.

The NRC staff also confirmed that sufficient diversities exist for all the proposed changes and concludes that there is not over-reliance of programmatic activities as compensatory measures.

Therefore, the NRC staff finds that the DID principle for the I&C safety functions is maintained.

The licensee proposed to apply the RICT program to various TS Section 3.8 LCOs specific to electrical power systems if risk remains with the guidance of NEI06-09-A.

Per NEI 06-09-A, for cases where the total core damage frequency (CDF) or large early release frequency (LERF) is greater than 10 -3/year or 10 -4/year, respectively, the RICT Program will not be entered.

The NRC staff evaluated the potential loss of function for each proposed RICT associated with the electrical power system. According to the LAR, some systems in an opposite unit (e.g., see systems of opposite unit noted in TS 3.8.1) are shared systems during various modes of operation. If the shared system is inoperable, then it affects both units.

The NRC staff reviewed the docketed information and verified that the electrical power systems would continue to perform their safety functions assuming no additional failures other than those pertaining to the proposed RICTs. The staff finds that the McGuire electrical power systems would function as intended during the RICT implementation. The NRC staff verified that the design success criteria in Reference 2, Table E1-1, In-Scope TS LCO/Conditions to Corresponding PRA Functions, for each of the electrical TS LCO Conditions reflects the minimum operable electrical power sources to support their safety functions to mitigate postulated design-basis accidents (DBAs), but allow safe shutdown of the reactor, or maintain the reactor in a safe shutdown condition, and that the RICT estimates for each of those LCOs in Reference 2, Table E1-2, In-Scope TS LOC RICT Estimates are reasonable.

The NRC staff reviewed the risk management action (RMA) examples provided in the Reference 1, Enclosure 12, Risk Management Action Examples, Section 8.0, Example RMAs, as RMA examples that may be considered during a RICT program entry for the required actions to reduce the risk impact and ensure adequate DID.

The licensee provided sample RMAs for TS 3.8 ACTIONS which pertain to electrical power systems: TS 3.8.1, Condition A - One LCO 3.8.1.a offsite circuit inoperable; TS 3.8.1, Condition F, One LCO 3.8.1.a offsite circuit inoperable AND One TS 3.8.1.b DG [Diesel Generator]

inoperable; TS 3.8.1, Condition H - One automatic load sequencer inoperable. The example RMAs have the required level of detail to reduce risk impact and ensure adequate DID. Based

on its review, the NRC staff determined that the examples provide reasonable assurance that the RMAs that would be implemented to monitor and control risk during the actual RICT program implementation will be of adequate quality for the applicable LCO Condition.

The NRC staff notes that while in a TS LCO Condition, the redundancy of the affected system is temporarily relaxed and, consequently, the system reliability is degraded accordingly. The NRC staff examined the design information from Reference 15 and the risk-informed TS LCO conditions for the affected safety functions. Based on this information, the NRC staff finds that under any given DBA evaluated in Reference 15, the affected protective features maintain adequate DID.

The NRC staff reviewed the licensees proposed electrical TS LCO Condition changes and supporting documentation. Based on the above, the NRC staff finds that temporary reduced redundancy during various CT extensions, as allowed by the RICT Program, are acceptable because (a) the capacity and capability of the remaining operable electrical systems would remain adequate and (b) the licensees identification and implementation of RMAs as compensatory measures would provide additional DID.

Considering that the CT extensions would be implemented in accordance with the NEI 06-09-A guidance that also considers RMAs and the redundancies in the offsite and onsite power systems, the NRC staff finds that the plant would maintain adequate DID. Therefore, the NRC staff finds the proposed TS changes in Reference 1, Attachment 2, are acceptable for the RICT Program.

Based on the above, the NRC staff finds that the licensees proposed changes are consistent with the NRC-endorsed guidance prescribed in NEI 06-09-A and satisfy the second key principle in RGs 1.174 and 1.177. Additionally, the NRC staff concludes that the changes are consistent with the DID philosophy as described in RG 1.174.

3.2.3 Key Principle 3: Evaluation of Safety Margins Paragraph 50.55a(h) of 10 CFR (Codes and Standards) requires in part, that [p]rotection systems of nuclear power reactors of all types must meet the requirements specified in this paragraph. Section 2.2.2, Technical Specification Change Maintains Sufficient Safety Margin (Principle 3), of RG 1.177 states, in part, that sufficient safety margins are maintained when:

Codes and standards or alternatives approved for use by the NRC are met.

Safety analysis acceptance criteria in the final safety analysis report are met, or proposed revisions provide sufficient margin to account for analysis and data uncertainties.

The licensee is not proposing to change any quality standard, material, or operating specification in this application. Reference 1 states that the licensee proposed to add a new program, Risk-Informed Completion Time Program, in Section 5.0, Administrative Controls, of the TS which would require adherence to NEI 06-09-A. NEI 06-09-A, Condition 2, states, in part, that for the TS LCOs and action requirements to which the RMTS will apply, the LAR will provide comparison of the TS functions to the PRA modeled functions of the SSCs subject to those LCO actions to justify that the scope of the PRA model is consistent with the licensing-basis assumptions or an appropriate disposition or programmatic restriction will be provided.

The NRC staff evaluated the effect on safety margins when the RICT is applied to extend the CT up to a back stop of 30 days in a TS condition with sufficient trains remaining operable to fulfill the TS safety function. Although the licensee is able to have design basis equipment out of service longer than the current TS allowance, any increase in unavailability is expected to be insignificant and is addressed by the consideration of the single failure criterion in the design basis analyses. Acceptance criteria for operability of equipment are not changed and, if sufficient trains remain operable to fulfill the TS safety function, the operability of the remaining train(s) ensures that the current safety margins are maintained. The NRC staff finds that if the specified TS safety function remains operable, sufficient safety margins would be maintained during the extended CT of the RICT Program.

Safety margins are also maintained if PRA functionality is determined for the inoperable train, which would result in an increased CT. Credit for PRA functionality, as described in NEI 06 A, is limited to the inoperable train, subsystem, or component.

Based on the above, the NRC staff finds that the design basis analyses for McGuire remains applicable and unchanged, sufficient safety margins are maintained during the extended CT, and the proposed changes to the TS do not include any change in the standards applied or the safety analysis acceptance criteria. The NRC staff concludes that the proposed changes meet 10 CFR 50.55a(h), and therefore, the third key principle of RGs 1.174 and 1.177.

3.2.4 Key Principle 4: Change in Risk Consistent with the Safety Goal Policy Statement NEI 06-09-A provides a methodology for a licensee to evaluate and manage the risk impact of extensions to TS CTs. Permanent changes to the fixed TS CTs are typically evaluated by using the three-tiered approach described in section 16.1 of the SRP (Reference 11) and RG 1.177.

This approach addresses the calculated change in risk as measured by the change in CDF (CDF) and LERF (LERF), as well as the incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP), the use of compensatory measures to reduce risk, and the implementation of a Configuration Risk Management Program (CRMP) to identify risk significant plant configurations.

The NRC staff evaluated the licensees processes and methodologies for determining that the change in risk from implementation of RICTs is small and consistent with the intent of the Commissions Safety Goal Policy Statement (Reference 17). In addition, the NRC staff evaluated the licensees proposed changes against the three-tiered approach in RG 1.177, for the licensees evaluation of the risk associated with a proposed TS CT change. The results of the NRC staffs review are discussed below.

3.2.4.1 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed changes on plant operational risk. The Tier 1 review involves two aspects: (1) scope and acceptability of the PRA models and their application to the proposed changes, and (2) a review of the PRA results and insights described in the licensees application.

Reference 1, Enclosure 2, Information Supporting Consistency with Regulatory Guide 1.200, Revision 2 and Enclosure 4, Information Supporting Justification of Excluding Sources of Risk Not Addressed by the PRA Models, identified the following modeled hazards and alternate methodologies that the licensee proposed to be used in the McGuire RICT Program to assess the risk contribution for extending the CT of a TS LCO:

Internal Events PRA (IEPRA) model,

Internal Flooding PRA (FLPRA) model,

Internal Fire Events PRA (FPPRA) model,

Seismic Hazard: CDF penalty of 3.57 x 10-5 per year, and a LERF penalty of 2.29 x 10-6 per year,

Extreme Winds and Tornado Hazards: CDF penalty of 1 x 10 -5 per year, except for LCOs Conditions 3.3.2.H., 3.3.5.B., 3.8.4.A., and 3.8.9.C. where CDF penalty is 3 x 10-5 per year, and a LERF penalty of 1 x 10-6 per year, and

Other External Hazards screened out from RICT program based on Appendix 6-A of the American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) RA Sa 2009 PRA Standard (Reference 18).

Evaluation of IEPRA, FLPRA, and FPRA Models The IEPRA, FLPRA, and FPRA models supporting the RICT Program are discussed in Reference 1, Enclosure 2. In that enclosure, the licensee stated that the PRA models had been peer reviewed using the ASME/ANS RA Sa 2009 PRA Standard for the IEPRA, FLPRA, and FPRA. The licensee also stated in Enclosure 2 that the IEPRA, FLPRA, and FPRA models have been assessed and peer reviewed against RG 1.200, Revision 2. For the open facts and observations (F&Os) resulting from these peer reviews, the licensee stated that closure of the F&Os was performed using an independent assessment process. The NRC staff confirmed that the licensee performed closure of the F&Os consistent with the Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close-Out of Facts and Observations(Reference 19). The licensee also stated in Enclosure 2 that all the finding-level F&Os have been closed, all associated supporting requirements are met at capability category II or higher, and there are no PRA upgrades that have not been peer reviewed. Based on the above, the NRC staff finds the technical acceptability of the licensees PRA for internal events, internal flooding, and internal fire is sufficient for use in supporting this specific risk-informed application.

In Reference 1, Enclosure 9, Key Assumptions and Sources of Uncertainty, the licensee provided a discussion of the key assumptions and sources of uncertainty, along with treatment for the application of the RICT Program. The licensee also stated that the McGuire PRA models do not credit portable equipment used as part of the flexible and diverse coping (FLEX) strategy.

Therefore, the NRC staff finds that FLEX equipment will not impact the PRA results used in the RICT program. The licensee stated that the McGuire PRA models do not model digital instruments. As noted previously, the NRC staff finds that digital instruments will not impact the PRA results used in the RICT program.

The NRC staff reviewed the PRA models peer review history provided by the licensee in Reference 1, Enclosure 2. The licensee adequately applied the guidance for establishing PRA technical acceptability for the IEPRA, FLPRA, and FPRA models. The NRC staff further considered the key assumptions and key sources of uncertainty identified by the licensee, and the licensees proposed use of surrogates in the PRA models for specific TS functions. Based on its review, the NRC staff finds the McGuire IEPRA, FLPRA, and FPRA models to be acceptable for the RICT application because the licensees use of the PRA models in the integrated decision-making process is consistent with RG 1.174.

Evaluation of High Wind Events PRA (HWPRA) Model In its letter dated February 16, 2023, the licensee stated that the high winds (HW) penalty factors are currently applicable to the RICT calculation due to computer resource issues to incorporate the HWPRA. However, the licensee requested that the NRC staff review the HWPRA acceptability provided in Reference 1, Section 4 of Enclosure 2 for future use. The licensee also proposed a condition on the use of its RICT application in Reference 2, Enclosure 4, that stipulates that either a HW penalty or a HWPRA will be utilized in the RICT calculations and that a HWPRA and HW penalty will not be used simultaneously to determine RICTs.

The licensee confirmed that the McGuire HWPRA model received a full-scope peer review in October 2014 using the ASME PRA Standard ASME/ANS RA-Sb-2013 (Reference 20).

Although this version of PRA standard is not endorsed by RG 1.200, this was indicated in its peer review report and the issue was resolved in another NRC staff safety evaluation (Reference 20), which concluded that there are no substantive differences between ASME/ANS RA-Sa-2009 and ASME/ANS RA-Sb-2013 for HWPRA. Therefore, the NRC finds that the HWPRA is acceptable.

Subsequent to the peer review, an independent assessment for closure of F&Os was performed in December 2021, using the process documented in NEI 17-07 (Reference 21), which resulted in closure of all finding-level F&Os. Hence, the LAR does not identify any open finding-level F&Os. All PRA upgrades have been peer reviewed. In addition, there were no model assumptions or sources of uncertainty identified as key for high winds with respect to the RICT program.

Based on its review, the NRC staff finds that the McGuire HWPRA has been appropriately peer reviewed, and the F&Os have been closed using an NRC-approved approach. The NRC staff also finds that the licensees HWPRA model maintenance and integration of the HWPRA into the real-time risk monitor is acceptable. Based on the above, the NRC staff concludes that the McGuire HWPRA is acceptable for use in the RICT program. As noted previously, the licensee will use either the HWPRA or the HW penalty as part of its RICT program.

Evaluation of Seismic Hazard In its letter dated February 16, 2023, the licensee stated that its approach for including the seismic risk contribution in the RICT calculation was to add a penalty seismic CDF and a penalty seismic LERF to each RICT calculation. The licensee proposed a non-standard seismic bounding analysis in its LAR. During post-audit discussions conducted on June 27-28, 2023, the licensee agreed to use the standard seismic bounding analysis as shown in Reference 2. The updated bounding seismic CDF estimate was based on using the plant-specific mean seismic hazard curve developed in response to the Near-Term Task Force recommendation 2.1 (Reference 22), and a plant-level mean high confidence of low probability of failure (HCLPF) capacity of 0.17g referenced to peak ground acceleration (PGA). The uncertainty parameter for seismic capacity was represented by a composite beta factor (c) of 0.4. The calculated seismic CDF penalty was 3.57 x 10-5 per year based on an average of four frequencies, 1Hz, 5 Hz, 10Hz and PGA. The NRC staffs review finds the licensees method to determine the baseline seismic CDF acceptable because it is consistent with the approach used in NRC Generic Issue 199 (GI-199) (Reference 23). The licensee provided the justification for the plant level HCLPF of 0.17g which was developed based on the Individual Plant Examination for External Events (IPEEE) seismic PRA model with a composite beta factor of 0.4. The NRC staff finds that the HCLPF and its uncertainty c factor are acceptable because they were based on the licensees IPEEE seismic PRA model even though these values are not consistent with GI-199 Table C-2 for McGuire. The NRC staff also convolved the input parameters identified by the licensee to confirm the proposed bounding seismic CDF estimate.

Concerning the proposed bounding seismic LERF estimate, the licensee provided the justification for selecting the HCLPF value for the containment fragility based on its IPEEE report in Reference 2. The licensee selected the Solid State Protection System (SSPS) cabinet fragility as a surrogate to represent the containment isolation function fragility because it has a lower HCLPF value (more conservative) than other containment related SSCs, including containment vessel, internal structures, reactor building and containment penetrations. The licensee estimated the seismic LERF by convolving the estimated seismic CDF (as described above) with a limiting fragility for containment integrity, 0.5 PGA HCLPF, and a composite beta factor (c) of 0.486. The calculated seismic LERF is 2.29 x 10-6 per year. The NRC staff finds the licensees approach to determine a seismic LERF estimate acceptable for this application because the 0.5g PGA HCLPF is reasonably conservative as the fragility for containment integrity is based on site-specific data. The NRC staff convolved the input parameters identified by the licensee to confirm the proposed bounding seismic LERF estimate.

The licensee also calculated the seismically induced loss of offsite power (LOOP) frequency within the design basis which is about 2 percent of the total LOOP initiating event frequency in the IEPRA. The NRC staff evaluated the analysis and finds that the analysis adequately addresses the impact of seismically induced LOOP for very low magnitude seismic events and has an insignificant impact on the RICT program calculations.

In summary, the NRC staffs review finds that the licensees proposal to use the seismic CDF contributions of 3.57 x 10-5 per year and a seismic LERF contribution of 2.29 x 10-6 per year acceptable for the licensees RICT Program for McGuire, because (1) the licensee used the most current site-specific seismic hazard information for McGuire, (2) the licensee used an acceptably low plant HCLPF value of 0.17g and a combined beta factor of 0.4 consistent with the information for McGuire in the GI-199 evaluation in the convolution to develop the bounding seismic CDF, (3) the licensee used an acceptable HCLPF value of 0.5g and a combined beta factor of 0.486 for the containment integrity fragility based on its IPEEE report in the convolution to develop the bounding seismic penalty, and (4) adding baseline seismic risk to RICT calculations, which assumes fully correlated failures, is conservative for SSCs credited in seismic events, while any potential non-conservative results for SSCs that are not credited in seismic events are small or nonexistent.

Evaluation of Extreme Winds and Tornado Hazards In its letter dated February 16, 2023, the licensee stated that it has a HWPRA model as discussed previously. However, there is a computer resource issue to incorporate the HWPRA model into the plant real-time PRA model. Therefore, the licensee proposed a condition on the use of its RICT application in Reference 2, Enclosure 4, that stipulates that either a HW penalty or a HWPRA will be utilized in the RICT calculations and that a HWPRA and HW penalty will not be used simultaneously to determine RICTs. RICT calculations will include a risk contribution from high winds events using a penalty approach. This approach adds a HW CDF and HW LERF to each RICT calculation. HW CDF and HW LERF estimates were developed using the licensees HWPRA model to select conservative penalty factors.

In Reference 2, the licensee explained that the plant modification and HWPRA model improvement have significantly reduced HW risk from the McGuire IPEEE as compared to the current HWPRA model. The licensee provided detailed discussions on how the HW penalty factors were developed for the RICT program. To determine the penalty factor, each of the LCO configurations evaluated in Reference 1, Enclosure 1, are processed through the HWPRA model. The general approach is to select the highest case CDF and LERF, then round up the values to provide additional margin.

Therefore, one set of CDF penalty factors is assigned to most LCO configurations, and a higher set is used for a few specific LCO configurations. A single LERF penalty factor is used for all configurations for both units. The licensee selected a HW CDF penalty of 1 x 10-5 per year, except for LCOs 3.3.2.H, 3.3.5.B, 3.8.4.A, and 3.8.9.C, where the HW CDF penalty is 3 x 10-5 per year. The licensee also selected a HW LERF penalty of 1 x 10-6 per year for all LCOs.

The licensee discussed some conservatisms on the development of these penalty factors such as no offsite power recovery, no FLEX credited, and a single penalty factor applicable to all LCO configurations, even those with little to no risk increase.

The NRC staffs review finds the licensees proposal to use the HW CDF and HW LERF contributions reported in its LAR supplement acceptable for the licensees RICT program for McGuire because (1) the methodologies for developing the high wind penalty factors were based on the HWPRA which the staff finds acceptable for this application as discussed previously, (2) the HW CDF and HW LERF values were conservatively selected for all the relevant LCOs, and (3) the licensee will only use either the penalty method or HWPRA incorporated into the real-time PRA model when the computer resource issue is resolved.

Evaluation of Other External Hazards Besides seismic and extreme winds and tornado hazards discussed above, the licensee confirmed that other external hazards for McGuire have an insignificant contribution and proposed these hazards be screened out from the RICT program. In Reference 1, Enclosure 4, Table E4-6 Evaluation of Other External Hazards, the licensee provided the evaluation of the external flooding hazard risk. The external flooding hazards were screened using the screening criterion, C1 - design base, in Reference 18. The licensee further justified using the screening criteria C5 - adequate time to install temporary flood barrier in Reference 2. The NRC staffs review finds that the licensee has appropriately considered the risk from external flooding in the proposed RICTs and that the external flooding hazard has an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs.

The licensee provided its rationale for the insignificant impact of other external hazards for McGuire including consideration of the configuration in Table E4-6. The licensee further stated that this assessment included consideration of configuration-specific conditions. For all other external hazards, the NRC staffs review of the information in the submittal and supplement finds that the contributions from other external hazards have an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs because they either do not challenge the plant or they are bounded by the external hazards analyzed for the plant. The NRC staffs review notes that the preliminary screening criteria and progressive screening criteria used and presented in Reference 1, Enclosure 4, Table E4-7, Progressive Screening Approach for Addressing External Hazards, is the same criteria presented in supporting requirements for screening external hazards EXT-B1 and EXT-C1 of the ASME/ANS PRA Standard.

Application of PRA Models, Results and Insights in the RICT Program The McGuire base PRA models that have been determined to be acceptable in this SE are incorporated into an application-specific PRA model (i.e., CRMP tool) that is used to analyze the risk for an extended CT. The CRMP model produces results (i.e., risk metrics) that are consistent with the NEI 06-09-A guidance. Reference 1 and 2 provided all information needed to support the requested LCO actions proposed for the McGuire RICT Program consistent with the limitations and conditions detailed in section 4.0 of the NRCs final SE incorporated in NEI 06-09-A (Reference 4) as described below.

The NRC staff did not identify any insufficiencies in the licensees information or the CRMP tool as described in Reference 1, enclosure 8, Attributes of the Real-Time Model. Furthermore, as stated in Reference 1, Attachment 1, the proposed changes do not change the design, configuration, or method of operation of the plant. The proposed changes do not involve a physical alteration of the facility (no new or different kind of equipment will be installed). The NRC staff finds that the McGuire PRA models and CRMP tool used reflects the as-built, as-operated plant consistent with RG 1.200, Revision 2 (Reference 6), for ensuring PRA acceptability is maintained. Therefore, the NRC staff concludes that the proposed application of McGuire RICT Program is appropriate for use in the adoption of TSTF-505 for performing RICT calculations.

The licensee provided in Reference 1, Enclosure 5, Baseline CDF and LERF, the estimated mean total CDF and LERF of the base PRA models to demonstrate that McGuire meets the 10-4/year CDF and 10-5/year LERF criteria of RG 1.174 consistent with the guidance in NEI 06-09-A and that these guidelines are satisfied for implementation of a RICT.

The licensee has incorporated NEI 06-09-A into TS 5.5.18. The estimated current mean total CDF and LERF for McGuire meet RG 1.174 guidelines. Therefore, the NRC staff finds that the PRA results and insights used by the licensee in the RICT Program are consistent with NEI 06-09 A.

3.2.4.1.1 Tier 1 Conclusions Based on the above conclusions, the NRC staff finds that the licensee has satisfied the intent of Tier 1 in RG 1.177 and RG 1.174 for determining that the PRA is acceptable, and that the scope of the PRA models (i.e., IEPRA, FLPRA, FPRA), evaluated PRA hazards, high winds hazards, other external hazards, and seismic methodology is appropriate for this application.

3.2.4.2 Tier 2: Avoidance of Risk Significant Plant Configurations As described in RG 1.177, the second tier evaluates the capability of the licensee to identify and avoid risk-significant plant configurations that could result if equipment, in addition to that associated with the proposed change, is taken out of service simultaneously, or if other risk-significant operational factors, such as concurrent system or equipment testing, are also involved. Reference 1, Enclosure 12 identifies three kinds of RMAs (i.e., actions to provide increased risk awareness and control, actions to reduce the duration of maintenance activities, and actions to minimize the magnitude of the risk increase). In that enclosure, the licensee also explains that RMAs are implemented in accordance with current plant procedures and no later than the time at which the 10-6 ICCDP or 10-7 ICLERP threshold is reached and under emergent conditions when the instantaneous CDF and LERF thresholds are exceeded. The risk monitoring under 10 CFR 50.65(a)(4) will also assist in limiting the risk associated with the use of the RICT Program.

The NRC staff finds that the Tier 2 attributes of the proposed RICT Program, including limits established for entry into a RICT and implementation of RMAs, are consistent with NEI-06-09-A.

Therefore, the NRC staff finds that the proposed changes are consistent with the Tier 2 guidance of RG 1.177, and, therefore, the licensees Tier 2 program is acceptable and supports the proposed implementation of the RICT Program.

3.2.4.3 Tier 3: Risk-Informed Configuration Risk Management Tier 3 stipulates that a licensee should develop a program that ensures the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity. The proposed RICT Program establishes a CRMP based on the underlying PRA models. The CRMP is then used to evaluate configuration-specific risk for planned activities associated with the RMTS extended CT and emergent conditions which may arise during an extended CT. This required assessment of configuration risk, along with the implementation of compensatory measures and RMAs, is consistent with the principle of Tier 3 for assessing and managing the risk impact of out-of-service equipment.

Paragraph 50.36(c)(5) of 10 CFR identifies administrative controls as the provisions relating to organization and management, procedures, thereby assuring operation of the facility in a safe manner. In Reference 1, enclosure 8 the licensee confirmed that future changes made to the baseline PRA models and changes made to the online model (i.e., CRMP) are controlled and documented by plant procedures. In Reference 1, enclosure 10 the licensee provided the attributes that the RICT Program procedures will address which are consistent with NEI 06-09-A. The NRC staff finds that the licensee has identified appropriate administrative controls consistent with NEI 06-09-A and 10 CFR 50.36(c)(5).

Based on the licensees incorporation of NEI 06-09-A in the TS (discussed in Reference 1, ), and its use of RMAs (discussed in Reference 1, Enclosure 12), and because the proposed changes are consistent with the Tier 3 guidance of RG 1.177, the NRC staff finds the licensees Tier 3 program is acceptable and supports the proposed implementation of the RICT Program (Reference 9).

3.2.4.4 Key Principle 4: Conclusions The licensee has demonstrated the technical acceptability and scope of its PRA models and alternative methods. This includes considering the impact of seismic events, extreme winds and tornado hazards, and other external hazards, and that the models can support implementation of the RICT Program for determining extensions to CTs. The licensee has made proper consideration of key assumptions and sources of uncertainty. The risk metrics are consistent with the approved methodology of NEI 06-09-A and the acceptance guidance in RGs 1.174 and 1.177. The RICT Program is controlled administratively through plant procedures and training and follows the NRC-approved methodology in NEI 06-09-A. The NRC staff finds that the RICT Program satisfies the fourth key principle of RGs 1.174 and 1.177 and is, therefore, acceptable.

3.2.5 Key Principle 5: Performance Measurement Strategies - Implementation and Monitoring RG 1.177, Revision 2, and RG 1.174, Revision 2, establish the need for an implementation and monitoring program to ensure that extensions to TS CTs do not degrade operational safety over time and that no adverse degradation occurs due to unanticipated degradation or common cause mechanisms. An implementation and monitoring program is intended to ensure that the impact of the proposed TS change continues to reflect the availability of SSCs impacted by the change. Revision 2 of RG 1.174 states, in part, that monitoring performed in conformance with the Maintenance Rule, 10 CFR 50.65, can be used when the monitoring performed is sufficient for the SSCs affected by the risk-informed application. Reference 1, Enclosure 11, Monitoring Program, states that the SSCs in the scope of the RICT Program are also in the scope of 10 CFR 50.65 for the Maintenance Rule. The Maintenance Rule monitoring programs will provide for evaluation and disposition of unavailability impacts which may be incurred from implementation of the RICT Program (Reference 9).

NEI 06-09-A specifies that the cumulative risk associated with the use of RMTS beyond the front stop for equipment out of service is to be monitored. In Enclosure 11 the licensee also confirmed that the cumulative risk is calculated at least every refueling cycle, but the recalculation period does not exceed 24 months. The NRC staff finds this periodicity is consistent with NEI 06-09-A and is, therefore, acceptable.

The NRC staff concludes that the RICT Program satisfies the fifth key principle of RGs 1.174 and 1.177 because: (1) the RICT Program will monitor the average annual cumulative risk increase as described in NEI 06-09-A, thereby ensuring that the program, as implemented, will continue to meet RG 1.174 guidance for small risk increases; and (2) all affected SSCs are within the Maintenance Rule program, which monitors changes to the reliability and availability of these SSCs.

3.2.6 Proposed Changes to TS Not Associated with TSTF-505, Revision 2 In Reference 1, Attachment 1, Section 2.3 the licensee proposes the following revisions:

a.

TS 3.8.1, Required Action B.5 For TS 3.8.1, Condition B, Required Action B.6, McGuire license amendment numbers 314 and 293 (Reference 14) extended the front stop CT from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. The licensee proposes to return to the original front stop of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and delete TS 3.8.1, Required Action B.5, which provided defense-in-depth for the CT extension in accordance with Branch Technical Position 8-8.

Based on the above, the NRC staff concludes that TS 3.8.1 as amended by the proposed changes continues to meet the requirements of 10 CFR 50.36(c)(2) because the LCO continues to state the lowest functional capability or performance levels of equipment required for safe operation of the facility. The NRC staff concludes that the required actions, as amended by the proposed changes, provide reasonable assurance that facility operation remains safe during the time the LCO is not met. Therefore, the NRC staff finds the proposed changes acceptable.

b.

TS 3.4.11 TS 3.4.11 contains several pages where the ACTIONS table top row header (i.e., Condition, Required Action, Completion Time) is inadvertently missing. Duke Energy proposes to add the header to the appropriate pages.

This is an administrative variation from TSTF-505 with no impact on the NRC model safety evaluation Reference 4. The NRC staff finds that this proposed change is editorial because the change (1) does not involve any physical changes to the structures, systems, or components or the way that the unit is operated and controlled, (2) do not affect the technical content or operational requirements in the TS, and (3) do not affect provisions relating to organization and management, procedures, record keeping, review and audit, nor reporting necessary to assure operation of the facility in a safe manner.

Therefore, the NRC staff determined that the requirements of 10 CFR 50.36(c)(2)(i) for this TS LCO will continue to be met and that the remedial actions proposed in this TS can be followed by the licensee until the LCO can be met or if the remedial actions cannot be met within the CTs the licensee will be required to shut down the reactor. Therefore, the NRC staff finds the proposed change acceptable.

3.2.7 Technical Evaluation Conclusion The NRC staff evaluated the proposed changes against each of the five key principles in RGs 1.174 and 1.177, including the proposed variations from the approved TSTF-505, as discussed in Sections 3.2.1 through 3.2.6 of this SE. The NRC staff concludes that the changes proposed by the licensee satisfy the key principles of risk informed decision-making identified in RGs 1.174 and 1.177, and therefore, the requested adoption of the proposed changes to the TS and associated guidance, is acceptable to assure the paragraphs of 10 CFR Part 50 identified in Section 2.0 of this SE continue to be met.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the North Carolina State official was notified of the proposed issuance of the amendments on January 29, 2024. On February 5, 2024 the State official confirmed that the State of North Carolina had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change the requirement with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20 or would change an inspection or surveillance requirements. The NRC staff has determined that the amendments involve 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 amendments involve no significant hazards consideration published in the Federal Register on May 16, 2023 (88 FR 31285).and there has been no public comment on such finding. Accordingly, the amendments meet 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 amendments.

6.0 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) there is reasonable assurance that such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

7.0 REFERENCES

1.

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2.

Pigott, Edward, Duke Energy, letter to U.S. NRC, "Supplement to Application to Adopt Risk-Informed Completion Times TSTF-505, Revision 2 and Application to Adopt 10 CFR 50.69, Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors," November 2, 2023 (ML23306A032).

3.

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4.

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5.

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8.

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Technical Specifications," January 2021 (ML20164A034).

9.

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10.

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11.

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12.

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14.

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19.

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20.

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21.

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22.

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23.

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Principal Contributor(s): T. Hilsmeier, NRR A. Russell, NRR M. Patterson, NRR C. Ng, NRR D. Wu, NRR K. Tetter, NRR H. Kodali, NRR K. Nguyen, NRR N. Carte, NRR G. Bedi, NRR B. Lee, NRR D. Nold, NRR C. Jackson, NRR J. Ambrosini, NRR Date: March 26, 2024

ML24031A540

by email OFFICE NRR/LPL2-1/PM NRR/LPL2-1/LA*

NRR/DRA/APLA/BC*

NRR/DRA/APLC/BC*

NAME JKlos KGoldstein BPascarelli SVasavada DATE 01/25/2024 02/05/2024 12/22/2023 12/28/2023 OFFICE NRR/DEX/EEEB/BC*

NRR/DEX/EICB/(A)BC* NRR/DEX/EMIB/BC*

NRR/DSS/SCPB/BC(A)*

NAME WMorton MLi SBailey DScully DATE 01/09/2024 12/28/2023 01/05/2024 01/04/2024 OFFICE NRR/DSS/SNSB/BC*

NRR/DSS/STSB/BC(A)* OGC*

NRR/LPL2-1/BC*

NAME PSahd KWest AGhoshNaber MMarkley DATE 12/13/2023 12/27/2023 2/28/2024 03/26/2024 OFFICE NRR/LPL2-1/PM NAME JKlos DATE 03/26/2024

v t e Letter Sequence Approval
EPID:L-2023-LLA-0021, Technical Specifications Task Force (Approved, Closed)
Initiation Request, Request Acceptance Administration Questions Answers Results Approval, Approval Other: ML23094A183, ML24019A139
MONTHYEAR2023-04-18 [Table View]

ML24031A540

Text

SUBJECT:

Dear Mr. Pigott:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

7.0 REFERENCES

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