Text

Issuance of Amendments to Technical Specification 3.8.1, AC Sources-Operating
	ML19126A030
Person / Time
Site:	McGuire, Mcguire
Issue date:	06/28/2019
From:	Michael Mahoney; Plant Licensing Branch II
To:	Teresa Ray; Duke Energy Carolinas
	Mahoney M, NRR/DORL/LPL2-1, 415-3867
References
	CAC MF9669, CAC MF9670, CAC MF9672, CAC MF9673, EPID L-2017-LLA-0256, EPID L-2017-LLA-0257
	Download: ML19126A030 (104)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C. 20555-0001 June 28, 2019 Mr. Thomas D. Ray Vice President McGuire Nuclear Station Duke Energy Carolinas, LLC 12700 Hagers Ferry Road Huntersville, NC 28078-8985

SUBJECT:

MCGUIRE NUCLEAR STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT NOS. 314 AND 293 TO TECHNICAL SPECIFICATION 3.8.1, "AC SOURCES - OPERATING" (CAC NOS. MF9669, MF9670, MF9672, MF9673 AND EPID NOS. L-2017-LLA-0256 AND L-2017-LLA-0257)

Dear Mr. Ray:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 314 to Renewed Facility Operating License No. NPF-9 and Amendment No. 293 to Renewed Facility Operating License No. NPF-17 for the McGuire Nuclear Station, Units 1 and 2 (McGuire),

respectively. The amendments are in response to your application dated May 2, 2017, as supplemented by letters dated July 20 and November 21, 2017; July 10 and December 3, 2018; and March 7 and April 8, 2019.

The amendments revise McGuire Technical Specification (TS}, 3.8.1, "AC [Alternating Current]

Sources - Operating," to extend the Completion Time (CT) of Condition B for an inoperable emergency diesel generator (DG) from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. To support this request, McGuire will add a supplemental power source (i.e., two supplemental diesel generators (SDGs)) with the capability to power any emergency bus. The affected SDGs will have the capacity to bring the affected unit to cold shutdown. The supplemental AC power source will be referred to as the Emergency Supplemental Power Source (ESPS).

Additionally, TS Limiting Condition for Operation {LCO) 3.8.1 is being revised by adding two new requirements in order for the LCO to be met. The first new item reflects a qualified circuit between the offsite transmission network and the opposite unit's Onsite Essential Auxiliary Power System that is necessary to supply power to the Nuclear Service Water System (NSWS),

Control Room Area Ventilation System (CRAVS), Control Room Area Chilled Water System (CRACWS) and Auxiliary Building Filtered Ventilation Exhaust System (ABFVES) (i.e., shared systems). The second new item reflects a DG from the opposite unit that is necessary to supply power to the NSWS, CRA VS, CRACWS and ABFVES. Corresponding Conditions, Required Actions, and CTs are also being proposed for these new LCOs.

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

Docket Nos. 50-369 and 50-370

Enclosures:

1. Amendment No. 314 to NPF-9

2. Amendment No. 293 to NPF-17

3. Safety Evaluation cc w/enclosures: Listserv Sincerely, Michael Mahoney, Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 DUKE ENERGY CAROLINAS, LLC DOCKET NO. 50-369 MCGUIRE NUCLEAR STATION, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 314 Renewed License No. NPF-9

1.

The Nuclear Regulatory Commission (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 Duke Energy Carolinas, LLC (the licensee), dated May 2, 2017, as supplemented by letters dated July 20 and November 21, 2017; July 10 and December 3, 2018; and March 7 and April 8, 2019, 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 1 O 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) and 2.C.(5) 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. 314, 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. 314 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 120 days of issuance.

Attachment:

FOR THE NUCLEAR REGULATORY COMMISSION

~c.4 Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Changes to Renewed License No. NPF-9 and Technical Specifications Date of Issuance:

Ju11,~ 23, 2019

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 DUKE ENERGY CAROLINAS, LLC DOCKET NO. 50-370 MCGUIRE NUCLEAR STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 293 Renewed License No. NPF-17

1.

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

A The application for amendment to the McGuire Nuclear Station, Unit 2 (the facility), Renewed Facility Operating License No. NPF-17, filed by the Duke Energy Carolinas, LLC (the licensee), dated May 2, 2017, as supplemented by letters dated July 20 and November 21, 2017; July 10 and December 3, 2018; and March 7 and April 8, 2019, 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) and 2.C.(6) 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. 293, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

(6)

Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 293 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 120 days of issuance.

Attachment:

FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Changes to Renewed License No. NPF-17 and Technical Specifications Date of Issuance: June 2 a, 2 o 1 9

ATTACHMENT MCGUIRE NUCLEAR STATION, UNITS 1 AND 2 LICENSE AMENDMENT NO. 314 RENEWED FACILITY OPERATING LICENSE NO. NPF-9 DOCKET NO. 50-369 AND LICENSE AMENDMENT NO. 293 RENEWED FACILITY OPERATING LICENSE NO. NPF-17 DOCKET NO. 50-370 Replace the following pages of the Renewed Facility Operating Licenses with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove NPF-9, page 3 NPF-17, page 3 Insert NPF-9, page 3 NPF-17, page 3 Replace the following page of the Appendix 8, Additional Conditions, with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove Insert NPF-9, page 8-4 NPF-17, page 8-4 Replace the following pages of the Appendix A Technical Specifications (TSs) with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove TS 3.8.1-1 TS 3.8.1-2 TS 3.8.1-3 TS 3.8.1-4 TS 3.8.1-5 TS 3.8.1-6 TS 3.8.1-7 TS 3.8.1-8 TS 3.8.1-9 TS 3.8.1-10 Insert TS 3.8.1-1 TS 3.8.1-2 TS 3.8.1-3 TS 3.8.1-4 TS 3.8.1-5 TS 3.8.1-6 TS 3.8.1-7 TS 3.8.1-8 TS 3.8.1-9 TS 3.8.1-10 Remove TS 3.8.1-11 TS3.8.1-12 TS 3.8.1-13 TS 3.8.1-14 TS3.8.1-15 Insert TS 3.8.1-11 TS 3.8.1-12 TS 3.8.1-13 TS 3.8.1-14 TS 3.8.1-15 TS 3.8.1-16 TS 3.8.1-17 TS 3.8.1-18 TS3.8.1-19 TS 3.8.1-20 (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 1 O 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 1 O 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. 314, 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 1 O CFR 50.59 and otherwise complies with the requirements in that section.

Renewed License No. NPF-9 Amendment No. 314

48

c. Transition License Conditions

1)

Before achieving full compliance with 10 CFR 50.48(c), as specified by c.2) below, risk-informed changes to the licensee's fire protection program may not be made without prior NRC review and approval unless the change has been demonstrated to have no more than a minimal risk impact, as described in b.2) above.

2)

The licensee shall implement the items as listed in Attachment S, Table S-3, "Implementation Items," of Duke Energy letter dated November 21, 2016, within 180 days or 365 days after issuance of the license amendment unless that date falls within a scheduled refueling outage, then, implementation will occur 60 days after startup from that scheduled refueling outage. Implementation Item 19 is associated with thermoplastic cable analysis and will be completed by June 30, 2017.

Implementation Item 20, associated with the pressure boundary breach analysis, will be completed by December 31, 2017.

(5)

Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 314, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.

(6)

Antitrust Conditions The licensee shall comply with the antitrust conditions delineated in Appendix C of this renewed operating license.

(7)

Mitigation Strategy License Condition Develop and maintain strategies for addressing large fires and explosions and that include the following key areas:

A)

Fire fighting response strategy with the following elements:

1.

Pre-defined coordinated fire response strategy and guidance

2.

Assessment of mutual aid fire fighting assets

3.

Designated staging areas for equipment and materials

4.

Command and control

5.

Training of response personnel B)

Operations to mitigate fuel damage considering the following:

1.

Protection and use of personnel assets

2.

Communications

3.

Minimizing fire spread Renewed License No. NPF-9 Amendment No. 314

APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO. NPF-9 Duke Energy Carolinas, LLC comply with the following conditions on the schedules noted below:

Amendment Number 314 314 Additional Conditions lm12lementation Date During the extended DG Completion Times Upon implementation authorized by Amendment No. 314, the turbine-of Amendment No.

driven auxiliary feed water pump will not be 314 removed from service for elective maintenance activities. The turbine-driven auxiliary feed water pump will be controlled as "protected equipment" during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safe Shutdown Facility, Nuclear Service Water System, Chemical and Volume Control System, Diesel Air Compressors, Residual Heat Removal System, motor driven auxiliary feed water pumps, and the switchyard will also be controlled as "protected equipment."

The risk estimates associated with the 14-day Upon implementation EOG Completion Time LAR (including those results of Amendment No.

of associated sensitivity studies) will be updated, 314 as necessary to incorporate the as-built, as-operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance guidelines of RG 1.17 4 and RG 1.177.

Renewed License No. NPF-9 Amendment No. 314 B-4 (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 1 O CFR Parts, 30, 40 and 70, to possess, but not separate, such byproducts and special nuclear materials as my 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 by product 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 thereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1)

(2)

(3)

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%).

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 293, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

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.

Renewed License No. NPF-17 Amendment No. 293

48

c. Transition License Conditions

1)

Before achieving full compliance with 10 CFR 50.48(c), as specified by c.(2) below, risk-informed changes to the licensee's fire protection program may not be made without prior NRC review and approval unless the change has been demonstrated to have no more than a minimal risk impact, as described in (2) above.

2)

The licensee shall implement the items as listed in Attachment S, Table S-3, "Implementation Items," of Duke Energy letter dated November 21, 2016, within 180 days or 365 days after issuance of the license amendment unless that date falls within a scheduled refueling outage, then, implementation will occur 60 days after startup from that scheduled refueling outage. Implementation Item 19 is associated with thermoplastic cable analysis and will be completed by June 30, 2017.

Implementation Item 20, associated with the pressure boundary breach analysis, will be completed by December 31, 2017.

(5)

Protection of the Environment Before engaging in additional construction or operational activities, which may result in a significant adverse environmental impact that was not evaluated or that is significantly greater than the evaluated in the Final Environmental Statement dated April 1976, the licensee shall provide written notification to the Office of Nuclear Reactor Regulation.

(6)

Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 293, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.

(7)

Antitrust Conditions The licensee shall comply with the antitrust conditions delineated in Appendix C of this renewed operating license.

(7)

Mitigation Strategy License Condition Develop and maintain strategies for addressing large fires and explosions and that include the following key areas:

Renewed License No. NPF-17 Amendment No. 293

APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO. NPF-17 Duke Energy Carolinas, LLC comply with the following conditions on the schedules noted below:

Amendment Number 293 293 Additional Conditions I mQlementation Date During the extended DG Completion Times Upon authorized by Amendment No. 293, the turbine-implementation of driven auxiliary feed water pump will not be Amendment No.

removed from service for elective maintenance 293 activities during the extended CT. The turbine-driven auxiliary feed water pump will be controlled as "protected equipment" during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safe Shutdown Facility, Nuclear Service Water System, Chemical and Volume Control System, Diesel Air Compressors, Residual Heat Removal System, motor driven auxiliary feed water pumps, and the switchyard will also be controlled as "protected equipment."

The risk estimates associated with the 14-day Upon EOG Completion Time LAR (including those results implementation of of associated sensitivity studies) will be updated, Amendment No.

as necessary to incorporate the as-built, as-293 operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance guidelines of RG 1.17 4 and RG 1.177.

Renewed License No. NPF-17 Amendment No. 293 B-4

AC Sources - Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources-Operating LCO 3.8.1 The following AC electrical sources shall be OPERABLE:

a.

Two qualified circuits between the offsite transmission network and the Onsite Essential Auxiliary Power System; and

b.

Two diesel generators (DGs) capable of supplying the Onsite Essential Auxiliary Power Systems; and

c.

The qualified circuit(s) between the offsite transmission network and the opposite unit's Onsite Essential Auxiliary Power System necessary to supply power to the Nuclear Service Water System (NSWS), Control Room Area Ventilation System (CRAVS), Control Room Area Chilled Water System (CRACWS) and Auxiliary Building Filtered Ventilation Exhaust System (ABFVES); and

d.

The DG(s) from the opposite unit necessary to supply power to the NSWS, CRA VS, CRACWS and ABFVES; The automatic load sequencers for Train A and Train B shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

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

The opposite unit electrical power sources in LCO 3.8.1.c and LCO 3.8.1.d are not required to be OPERABLE when the associated shared systems are inoperable.

McGuire Units 1 and 2 3.8.1-1 Amendment Nos. 314/293

ACTIONS AC Sources - Operating 3.8.1

NO TE---------------------------------------------------------

L CO 3.0.4.b is not applicable to DGs.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One LCO 3.8.1.a offsite A.1 Perform SR 3.8.1.1 for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months circuit inoperable.

required OPERABLE offsite McGuire Units 1 and 2 circuit(s).

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

A.3 Restore offsite circuit to OPERABLE status.

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 17 days from discovery of failure to meet LCO 3.8.1.a or LCO 3.8.1.b 3.8.1-2 Amendment Nos. 314/293

ACTIONS (continued)

CONDITION B.

One LCO 3.8.1.b DG inoperable McGuire Units 1 and 2 AC Sources - Operating 3.8.1 REQUIRED ACTION 8.1 Verify LCO 3.8.1.d DG(s)

OPERABLE.

AND 8.2 Perform SR 3.8.1.1 for the required offsite circuit(s).

AND 8.3 Declare required feature(s) supported by the inoperable DG inoperable when its required redundant feature(s) is inoperable.

AND 8.4.1 Determine OPERABLE DG(s) is not inoperable due to common cause failure.

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

COMPLETION TIME 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter 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 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of Condition B concurrent with inoperability of redundant required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 24 hours (continued) 3.8.1-3 Amendment Nos. 314/293

ACTIONS (continued)

CONDITION B.

(continued) 8.5 REQUIRED ACTION AC Sources - Operating 3.8.1 COMPLETION TIME Evaluate availability of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Emergency Supplemental Power Source (ESPS).

AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter 8.6 Restore DG to OPERABLE 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from status.

discovery of unavailable ESPS **

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition B entry.:::

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months concurrent with unavailability of ESPS 14 days 17 days from discovery of failure to meet LCO 3.8.1.a or LCO 3.8.1.b

---------------------NO TE------------------------------------------------------------

- 'A' Train EDGs are allowed to be inoperable for a total of 14 days to address a non-conforming condition on the 'A' Train supply piping from the Standby Nuclear Service Water Pond (SNSWP). The 14 days may be taken consecutively or in parts until completion of the activity, or by March 31, 2019, whichever occurs first. During the period in which the 'A' Train NSWS supply piping from the SNSWP is not available, the 'A' Train NSWS will remain aligned to Lake Norman until the system is ready for post maintenance testing. Any maintenance that is performed on the remaining portions of 'A' Train NSWS during the period in which the 'A' NSWS from the SNSWP supply piping is not available will be limited to a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months completion time. The latter will not count against the 14 day completion time. Allowance of the extended Completion Time is contingent on meeting the Compensatory Measures as described in MNS LAR submittal correspondence letter MNS-17-031.

McGuire Units 1 and 2 3.8.1-4 Amendment Nos. 314/293

ACTIONS (continued)

CONDITION REQUIRED ACTION AC Sources - Operating 3.8.1 COMPLETION TIME C.

One LCO 3.8.1.c offsite

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

circuit inoperable.

McGuire Units 1 and 2 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 3.8.1-5 Amendment Nos. 314/293

ACTIONS (continued)

D.

CONDITION One LCO 3.8.1.d DG inoperable.

McGuire Units 1 and 2 AC Sources - Operating 3.8.1 REQUIRED ACTION

NO TE-------------------

Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems - Operating,"

when Condition D is entered with no AC power source to a train.

D.1 Verify both LCO 3.8.1.b DGs OPERABLE.

COMPLETION TIME 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter D.2 Perform SR 3.8.1.1 for the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required offsite circuit(s).

AND D.3 Declare NSWS, CRAVS, CRACWS or ABFVES supported by the inoperable DG inoperable when the redundant NSWS, CRAVS, CRACWS or ABFVES is inoperable.

Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of Condition D concurrent with inoperability of redundant required feature(s)

(continued) 3.8.1-6 Amendment Nos. 314/293

A CTIONS (continued)

CONDITION D.

(continued)

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.

McGuire Units 1 and 2 D.4.1 OR D.4.2 AND D.5.1 OR D.5.2 E.1 AND E.2 AC Sources - Operating 3.8.1 REQUIRED ACTION COMPLETION TIME Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(s) is not inoperable due to common cause failures.

Perform SR 3.8.1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE DG(s).

Restore LCO 3.8.1.d DG to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

Align NSWS, CRA VS, CRACWS and ABFVES supported by the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable LCO 3.8.1.d DG to an OPERABLE DG.

Declare required feature(s) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from inoperable when its discovery of redundant required Condition E feature(s) is inoperable.

concurrent with inoperability of redundant required feature(s)

Restore one offsite circuit 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to OPERABLE status.

3.8.1-7 Amendment Nos. 314/293

A CTIONS (continued)

CONDITION F.

One LCO 3.8.1.a offsite circuit inoperable.

AND One LCO 3.8.1.b DG inoperable.

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.

H.

One automatic load sequencer inoperable.

McGuire Units 1 and 2 AC Sources - Operating 3.8.1 REQUIRED ACTION COMPLETION TIME

--~--------~----NOTE--~-------------~

Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems -

Operating," when Condition Fis entered with no AC power source to any train.

F.1 Restore offsite circuit to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OPERABLE status.

OR F.2 Restore DG to OPERABLE 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months status.

G.1 Restore one DG to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OPERABLE status.

H.1 Restore automatic load 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months sequencer to OPERABLE status.

3.8.1-8 Amendment Nos. 314/293

A CTIONS (continued)

CONDITION I.

Required Action and associated Completion Time of Condition A, C, E, F, G, or Hnot met.

OR Required Action and associated Completion Time of Required Action 8.2, 8.3, B.4.1, B.4.2, or 8.6 not met.

OR Required Action and associated Completion Time of Required Action 0.2, 0.3, D.4.1, D.4.2, D.5.1, or D.5.2 not met.

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.

McGuire Units 1 and 2 REQUIRED ACTION 1.1 Be in MODE 3.

AND 1.2 Be in MODE 5.

J.1 Enter LCO 3.0.3.

3.8.1-9 AC Sources - Operating 3.8.1 COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours Immediately Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.1 Verify correct breaker alignment and indicated power availability for each offsite circuit.

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 :s; 4580 V, and frequency~ 58.8 Hz and :s; 61.2 Hz.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program (continued)

McGuire Units 1 and 2 3.8.1-10 Amendment Nos. 314/293

AC Sources - Operating

3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3. 8. 1. 3

NO TES--------------------*-----------

SR 3.8.1.4 SR 3.8.1.5 SR 3.8.1.6 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.

Verify each day tank contains ~ 39 inches of fuel oil.

Check for and remove accumulated water from each day tank.

Verify the fuel oil transfer system operates to automatically transfer fuel oil from storage tank to the day tank.

FREQUENCY In accordance with the Surveillance Frequency Control Proaram In accordance with the Surveillance Frequency Control Proaram In accordance with the Surveillance Frequency Control Proaram In accordance with the Surveillance Frequency Control Program (continued)

McGuire Units 1 and 2 3.8.1-11 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE SR 3. 8. 1. 7

NO TES------------------------------

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

Verify each DG starts from standby condition and achieves in$ 11 seconds voltage of 2:: 3740 V and frequency of 2:: 57 Hz and maintains steady state voltage 2:: 3740 V and$ 4580 V, and frequency 2:: 58.8 Hz and

$ 61.2 Hz.

SR 3. 8. 1. 8

NO TES------------------------------

Th is 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.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Proaram

( continued)

McGuire Units 1 and 2 3.8.1-12 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued}

SR 3.8.1.9 SURVEILLANCE 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::,; 4580 V; and

c.

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

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.

FREQUENCY In *accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program (continued)

McGuire Units 1 and 2 3.8.1-13 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SURVEILLANCE 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 $ 4580 V,

4.

maintains steady state frequency

~ 58.8 Hz and $ 61.2 Hz, and

5.

supplies auto-connected blackout loads for

~ 5 minutes.

FREQUENCY In accordance with the Surveillance Frequency Control Program (continued)

McGuire Units 1 and 2 3.8.1-14 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SURVEILLANCE SR 3.8.1.12

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

AII 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~ 4580 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.

FREQUENCY In accordance with the Surveillance Frequency Control Program (continued)

McGuire Units 1 and 2 3.8.1-15 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE 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.

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.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program (continued)

McGuire Units 1 and 2 3.8.1-16 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE 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 s 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 s 11 seconds, voltage~ 3740 V, and frequency~ 57 Hz and maintains steady state voltage~ 3740 V ands 4580 V and frequency~ 58.8 Hz ands 61.2 Hz.

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.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Program (continued)

McGuire Units 1 and 2 3.8.1-17 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE 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.

SR 3.8.1.18 Verify interval between each sequenced load block is within design interval for each automatic load sequencer.

FREQUENCY In accordance with the Surveillance Frequency Control Program In accordance with the Surveillance Frequency Control Prooram (continued)

McGuire Units 1 and 2 3.8.1-18 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SURVEILLANCE 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 $4580 V,

4.

achieves steady state frequency~ 58.8 Hz and$ 61.2 Hz, and

5.

supplies auto-connected emergency loads for~ 5 minutes.

FREQUENCY In accordance with the Surveillance Frequency Control Program (continued)

McGuire Units 1 and 2 3.8.1-19 Amendment Nos. 314/293

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued SURVEILLANCE SR 3. 8. 1. 20 ------------------------------NO TES-------------------------------

AII 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::; 4580 V, and frequency

~.58.8 Hz and::; 61.2 Hz.

FREQUENCY In accordance with the Surveillance Frequency Control Program McGuire Units 1 and 2 3.8.1-20 Amendment Nos. 314/293

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION FOR AMENDMENT NO. 314 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-9 AMENDMENT NO. 293 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-17 DUKE ENERGY CAROLINAS, LLC DOCKET NOS. 50-369 AND 50-370

1.0 INTRODUCTION

By letter to the U.S. Nuclear Regulatory Commission (NRC or the Commission) dated May 2, 2017 (Reference 1 ), as supplemented by letters dated July 20 (Reference 2) and November 21, 2017 (Reference 3); July 10 (Reference 4) and December 3, 2018 (Reference 5);

and March 7 (Reference 6) and April 8, 2019 (Reference 7), Duke Energy Carolinas, LLC (Duke Energy, the licensee) submitted an application to seek approval to change the Technical Specifications (TSs) for the McGuire Nuclear Station (McGuire), Units 1 and 2.

The supplements dated July 20 and November 21, 2017; July 10 and December 3, 2018; and March 7 and April 8, 2019, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staff's original proposed no significant hazards consideration determination as published in the Federal Register(FR) on February 27, 2018 (83 FR 8512).

The proposed amendment revises McGuire TS 3.8.1, "AC [Alternating Current] Sources -

Operating," to extend the Completion Time (CT) of Condition B for an inoperable emergency diesel generator (DG) from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. To support this request McGuire will add a supplemental power source (i.e., two supplemental diesel generators) with the capability to power any emergency bus. The supplemental AC power source will be referred to as the Emergency Supplemental Power Source (ESPS).

Additionally, TS 3.8.1 is being revised to reflect two new Limiting Conditions for Operation (LCOs) that are necessary to assure operability of the power sources from the opposite unit, which support necessary shared systems. The first new LCO adds qualified circuit(s) between the offsite transmission network and the opposite unit's Onsite Essential Auxiliary Power System necessary to supply power to systems shared between Units 1 and 2. The other new TS 3.8.1 LCO adds DG(s) from the opposite unit necessary to supply power to the shared systems. The following shared systems have shared components that receive power from Essential Motor Control Centers (MCCs) powered by both McGuire units:

Nuclear Service Water System (NSWS),

Control Room Area Ventilation System (CRAVS),

Control Room Area Chilled Water System (CRACWS), and Auxiliary Building Filtered Ventilation Exhaust System (ABFVES).

Corresponding Conditions, Required Actions (RAs), and CTs are revised for TS 3.8.1 to account for the new supplemental Alternating Current (AC) power source ESPS. Additionally, the licensee provided conforming changes to the TS Bases for the following TSs: TS 3.7.7, "Nuclear Service Water System (NSWS)", TS 3.7.9, "Control Room Area Ventilation System (CRA VS)", TS 3. 7. 10, "Control Room Area Chilled Water System (CRACWS)", and TS 3. 7.11, Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)"), and TS 3.8.2 "AC Sources -

Shutdown." The licensee plans to change its TS Bases by documenting a different description of normal and emergency power supplies to those systems. The licensee also provided proposed new and changed Bases for TS 3.8.1. The licensee indicated that the proposed changes would reflect what is required by the amended TS 3.8.1 and, further, that the changes would make the Bases for the unrevised TSs consistent with the amended TSs.

2.0

2.1 REGULATORY EVALUATION

System Descriptions and Requirements In Section 3.2, "McGuire AC Power Systems Description," of its letter dated May 2, 2017, the licensee provided the following description of McGuire's AC Power System:

[... ] an offsite power system and an onsite power system are provided for each unit at MNS [McGuire] to supply the unit auxiliaries during normal operation and the Reactor Protection System and Engineered Safety Features Systems during abnormal and accident conditions.

3.2.1 Offsite AC Power System Introduction Each MNS unit generates power at 24 kV [Kilovolt] and supplies power from the generator through isolated phase bus to two generator power circuit breakers which feed two independent half-size unit step-up transformers. After a voltage transformation from 24 kV to 230 kV, the power from Unit 1 is transmitted over two separate and independent overhead transmission lines to a common 230 kV switching station. Similarly, after a voltage transformation from 24 kV to 525 kV, the power from Unit 2 is transmitted over two separate and independent overhead transmission lines to a common 525 kV switching station.

The 230 kV switching station is tied into the Duke Energy 230 kV network by five double circuit overhead lines. The 525 kV switching station is tied into the Duke Energy 525 kV network by four single circuit overhead lines.

The breakers and switches in both the 230 kV and the 525 kV switching stations are arranged in a breaker and a half scheme. Any one of the 230 kV and 525 kV transmission lines are capable of supplying power to the station.

Switchyards The MNS 230 kV and 525 kV switchyards are each designed in a breaker-and-a-half scheme with Unit 1 feeding the 230 kV switching station and Unit 2 feeding the 525 kV switching station. This scheme allows any circuit breaker to be isolated from the grid without de-energizing any transmission line or affecting the integrity of the switchyard. MNS Unit 1 ties to the 230 kV switchyard through two half size feeders entering the switchyard at two separate bay locations. The two step-up transformers, feeders and switchyard breaker bays protect the integrity of the unit and system against single breaker, feeder or transformer failures.

Unit 2 ties to the 525 kV switchyard in the same manner Unit 1 ties to the 230 kV switch yard.

The transmission network and the MNS switchyards are designed to maintain stable operation of the MNS generators for faults in the switchyard or on transmission lines, and upon a sudden increase or decrease in system load or generation.

Station to Switchyard Interconnections There are two separate overhead transmission line circuits between Unit 1 and the 230 kV switching station that tie it to the 230 kV Transmission Network. Each line is 230 kV, three-phase with an average length of 4,000 ft. from the transformer yard to the switching station structure.

There are two separate overhead transmission line circuits between Unit 2 and the 525 kV switching station that tie it to the 525 kV Transmission Network. Each line is 525 kV, three-phase with an average distance of 3300 ft. from the transformer yard to the switching station structure.

Offsite Power System Operational Description Each MNS unit is provided with two independent immediate access circuits of offsite power from the Transmission System. For Unit 1, each circuit consists of a connection from the 230 kV switching station over an independent 230 kV overhead transmission line through one of the two half-sized step-up transformers to one of the two unit auxiliary transformers. For Unit 2, each circuit consists of a connection from the 525 kV switching station over an independent 525 kV overhead transmission line through one of the two half-sized step-up transformers to one of the two unit auxiliary transformers.

Prior to and during start-up of a MNS unit, the 6900VAC Normal Auxiliary Power System receives power from the Offsite Power System through the two independent circuits and step-up transformers and unit auxiliary transformers.

During this period, the generator PCBs [power circuit breakers] are open. The unit's generator can be manually connected to the system by synchronizing across and closing the generator PCBs. The nuclear unit generator is normally connected to the Duke transmission system through two independent power transport circuits resulting in high unit operational reliability and availability.

3.2.2 Onsite AC Power System Introduction The normal power supply for the MNS Unit 1 Onsite AC Power System is the 24 kV unit generator which feeds power to the auxiliary power transformers through isolated phase bus. The preferred power supply for Unit 1 is the 230 kV switching station which feeds power over two independent circuits through the two main step-up transformers and isolated phase bus to the two auxiliary power transformers.

The Onsite AC Power System for Unit 2 is identical to Unit 1 with the single exception that the preferred power supply is the 525 kV switching station.

Each MNS unit is provided with two full size auxiliary power transformers and are sized to carry all of the auxiliaries of one operating unit plus the safety shutdown loads of the other unit. Each auxiliary transformer has two secondary windings, with each winding normally energizing one 6900VAC Normal Auxiliary Power System switchgear assembly.

The Onsite Power System consists of all sources of electric power and their associated distribution systems in the generating unit. These sources are the main generator, two DGs and the batteries. The boundary between the Onsite Power System and the Offsite Power System is the main step-up transformer terminations on the low voltage side. The Offsite Power System, defined as the preferred power supply, consists of the main step-up transformers, the switching station and the transmission system.

Main Power System Each MNS unit generates power at 24 kV and feeds the generator output power through isolated phase bus and two generator PCBs. An independent full capacity unit auxiliary transformer is connected to the isolated phase bus between each unit step-up transformer and its generator PCB.

Control of the Main Power System is provided in two modes of operation, manual and automatic. During operation, the Main Power System control is in the automatic mode. The automatic mode contains elements of both the Offsite and Onsite Protective Relaying Systems and the Offsite and Onsite Monitoring Systems. The automatic mode allows a fast automatic sequence of events to take place in the event of abnormal occurrences. In these cases, the appropriate generator and the switchyard breakers are tripped to bring about a return to stable conditions.

Normal Power System The 6900 VAC Normal Auxiliary Power System of each MNS unit consists of four assemblies of station auxiliary switchgear with each assembly connected through a main breaker and bus to the two unit auxiliary power transformers. With the two power transformers available, two switchgear assemblies are energized by each transformer. In the event of the loss of one of the unit auxiliary transformers, the two 6900 volt switchgear assemblies that are normally energized from that transformer will automatically transfer to the alternate unit auxiliary transformer, which will then furnish power to the four switchgear assemblies. The automatic transfer circuitry will permit a rapid transfer (i.e., the outgoing source feeder circuit breakers are tripped and their interlocks close the incoming source feeder circuit breakers) if the two transformer power supplies are initially in synchronism.

If the transformer power supplies are initially out of synchronism, the automatic transfer initiated will be of the time-delayed type to allow the residual bus voltage to decay to an acceptable level.

Normal bus transfer between the two sources are initiated at the discretion of the operator from the Control Room. These transfers are "live bus" transfers (i.e.,

the incoming source feeder circuit breaker is closed onto the energized bus section and its interlocks trip the outgoing source feeder breaker which results in transfers without power interruption.

The 6900VAC Normal Auxiliary Power System furnishes power to all the large station auxiliary loads such as the reactor coolant pumps, condenser circulating water pumps and hotwell pumps. In addition, the system furnishes normal power to the redundant 4160VAC Essential Auxiliary Power System through unit auxiliary switchgear breakers and 6900/4160 volt transformers.

4160VAC Essential Auxiliary Power System Each MNS unit has two redundant and independent 4160VAC Essential Auxiliary Power System trains which normally receive power from the normal power distribution system. Under normal conditions, the control for the normal incoming feeder circuit breaker is manual in conjunction with a key interlock. After verification of a loss of offsite power or a sustained degraded offsite power condition, the normal and alternate incoming feeder circuit breakers automatically trip. On each MNS unit, all engineered safety equipment is assigned to two 4160VAC Essential Auxiliary Power System trains with capacities and quantities such that the failure of components in one of the two trains does not affect the other train.

With the arrangement of the DG power sources, distribution system and loads, complete redundancy of the entire 4160VAC Essential Auxiliary Power System is provided. The protection provided in the design of the 4160VAC Essential Auxiliary Power System is such that the two systems are not electrically tied together at the same time.

600VAC Essential Auxiliary Power System Each of the two 600VAC Essential Auxiliary Power System trains for each MNS unit includes two load centers, each of which is normally fed by a separate 4160/600 volt load center transformer connected to the 4160VAC Essential Auxiliary Power System buses. Feeder circuit breakers are provided on both the primary and secondary sides of the transformer.

The load centers supply power to large loads such as heater loads and 600 volt motor control centers. Connected to the motor control centers are all the 600 volt loads which require power during blackout or accident conditions. Complete redundancy of these loads is provided in order to assure proper operation of safety features in the event of the failure of any single component in the 600VAC Essential Auxiliary Power System.

Standby Power Supplies In addition to the normal power supplies described above, the redundant 4160VAC Essential Auxiliary Power System trains of each MNS unit are furnished with power from two independent DGs separately housed in Category 1 structures. Each DG is rated at 4000 kW, 0.8 PF [power factor], 4160 volts.

Each DG is rated for continuous operation at 4000 kW with added capacity to operate between 4200-4400 kW for a period of two hours out of every twenty-four hours of operation without adversely affecting the life of the unit.

DG Starting Circuits All Class 1 E switchgear and load center breakers that are required to function automatically following a safety injection actuation signal and/or blackout condition are controlled by a load sequencer associated with each DG. Load shedding of all loads at the 4160 and 600 volt level occurs whenever a blackout condition or a safety injection actuation signal concurrent with a blackout is experienced.

Following the load shedding operation, the DG load sequencer automatically sequences the required committed loads. The load sequencer circuitry energizes the required loads in a prescribed sequence to prevent momentarily overloading the DG or the auxiliary transformer. When the load sequencer is actuated by a safety injection actuation signal with normal auxiliary power available, the DG is started immediately and maintained running in a standby condition until manually shutdown. Also, when the load sequencer is actuated by an undervoltage condition (determined by a two-out-of-three logic scheme) on the 4160 volt essential bus, the DG is immediately started.

Section 9.2.1 of McGuire's Updated Final Safety Analysis Report (UFSAR) (Reference 8) provides a description of the Nuclear Service Water System (NSWS) and states, in part:

The Nuclear Service Water (NSW) System provides assured cooling water for various Auxiliary Building and Reactor Building heat exchangers during all phases of station operation. Each unit has two redundant "essential headers" serving two trains of equipment necessary for safe station shutdown, and a "non-essential header" serving equipment not required for safe shutdown. In conjunction with the Ultimate Heat Sink, comprised of the Standby Nuclear Service Water Pond (SNSWP), the NSW System is designed to meet design flow rates and heads for normal station operation and also those flow rates and heads required for safe station shutdown under the following conditions while sustaining a single failure:

Normal shutdown or shutdown as the result of a postulated (single unit) Loss of Coolant Accident {LOCA), or A LOCA on one unit with a controlled shutdown on the alternate unit concurrent with a loss-of-offsite power on both units and a seismic event (SSE), or A seismic event (greater than QBE) causing loss of Lake Norman resulting in controlled shutdown on both units concurrent with a loss-of-offsite power on both units....

The NSW System is made up of four sections, which when put together in series provide an assured source of water for all the station safety related water demands and some non-safety related demands. These sections are, in order of flow, the main supply section, the strainer/pump section, the heat exchanger section, and the main discharge section.

The Nuclear Service Water System is designed to meet single failure criteria, with two redundant channels per unit to serve components essential for safe station shutdown. Channel B components and piping provide 100% backup to channel A components. Engineered Safety Features provide for automatic valving and component actuation for both channels of the unit affected, while non-safety related components are isolated and shut off. Channel A and B crossover double valving is also closed as an Engineered Safety Feature, assuring channel integrity.

The main supply portion of the NSWS up to the NSWS pump inlet isolation valves and the shared discharge headers to Lake Norman and the SNSWP are shared between units. The strainer/pump section and the heat exchanger section are not shared and are unit-specific.

Figure 83.7.7-1 of the McGuire TS Bases 83.7.7 shows the shared and non-shared portions of the NSWS.

Section 6.4 of McGuire's UFSAR (Reference 9) provides a description of the Control Area (Habitability) Ventilation System, which includes the Control Room Area Ventilation System (CRAVS), and states, in part:

The Control Area Ventilation Systems are designed to maintain the proper temperatures and cleanliness in the Control Room, the Control Room Area and the Switchgear Rooms during plant operation, shutdown, post accident conditions and all feasible weather conditions. Ventilation provided to battery rooms by the Control Area Ventilation System is designed to maintain proper temperatures as specified in Section 16.9.23 and to maintain hydrogen concentrations below the lower flammability limit. The Control Room outside air pressure filter trains are designed to maintain the proper post accident pressurization of the Control Room.

Section 9.4.2 of McGuire's UFSAR provides a description of the Auxiliary Building Filtered Ventilation Exhaust System (ABFVES), it states, in part:

Each station unit is served by two independent exhaust subsystems, Auxiliary Building filtered ventilation exhaust and Auxiliary Building general ventilation exhaust subsystems. Each system consists of two 50 percent exhaust fans.

Auxiliary Building filtered ventilation exhaust system incorporates prefilters, absolute filters, carbon filters, bypass and associated duct work extending to areas subject to contamination. These contaminated areas will be maintained under a negative pressure.

The Auxiliary Building general ventilation exhaust subsystem serves areas that are not subject to contamination. These areas have ventilation rates based upon heat loads only. All the exhaust systems in the Auxiliary Building are of greater capacity than the supply systems, thus maintaining the Auxiliary Building at a negative pressure. During operation of either unit, all associated Auxiliary Building ventilation systems are activated to "normal" operation. During shutdown of either unit, associated Auxiliary Building ventilation systems may operate in part or in total to suit maintenance, inspection, testing or refueling conditions.

Section 6.4 of McGuire's UFSAR provides a description of the Control Area (Habitability)

Ventilation System, which includes the Control Room Area Chilled Water System (CRACWS),

and states, in part:

The Safety Class 3 air handling units for the Control Room, Control Room Area and Switchgear Rooms are supplied with chilled water by two 100 percent Safety Class 3 redundant chilled water systems, each with one 100 percent capacity chiller and one 100 percent chilled water pump...

There are two Essential MCCs per train at McGuire (for a total of four Essential MCCs) that supply all the shared components on both units. These Essential MCCs are 1 EMXG, 1 EMXH, 2EMXG and 2EMXH. The Essential MCCs that are designated as "Unit 1" supply the "A" train of shared equipment. The Essential MCCs that are designated as "Unit 2" supply the "B" train of shared equipment. Either 1A DG or 2A DG can be aligned as the emergency power supply for "A" train shared equipment, and either 1 B or 2B DG can be aligned as the emergency power supply for "B" train shared equipment. The A train components are redundant to the B train components. The components include the NSWS motor operated valves (MOV) in the NSWS suction and discharge portions of the NSWS system which is shared between units; the fans, dampers, and air handling units associated with the NSWS, CRA VS, CRACWS and ABFVES; and the chilled water and chiller oil pumps of the CRACWS. A listing of the MOV, dampers, fans, and pumps are itemized in the licensee's letter dated July 20, 2017.

2.2 Licensee's Proposed Changes In the May 2, 2017 letter, the licensee proposed to extend the current McGuire TS CT for an inoperable unit-specific emergency DG from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days with the condition that the ESPS is available and functional. The ESPS would be the backup power supplies for the 4160 VAC bus whose emergency DG is removed from service.

The ESPS will be a permanently installed, non-safety related, commercial-grade system consisting of the following major components: (1) two 6.9 kV Caterpillar C175-16 supplemental DG sets (SDGs), each rated at 2500 KWe at 0.8 PF continuous power and 2750 KWe@ 0.8 PF prime power, (2) ABB's ADVAC switchgear product line to allow the power output of the two SDGs to be synchronized to a common ESPS bus, individual output breakers are provided for connection to the 6900 VAC Normal Auxiliary Power Systems of each unit, (3) A 6.9 kV/480 V AC dry transformer for supplying auxiliary power while the SDGs are running, and (4) a 4000 kWe, 6.9 kV resistive load bank for periodic testing of the SDGs. The ESPS major components will be physically separated from the existing emergency DGs, the offsite and onsite power systems and the safety-related Class 1 E 4160 V essential busses. Each SDG will be located in its own weather enclosure mounted on top of an above grade sub-base fuel tank.

The sub-base fuel tanks are specified to contain sufficient usable fuel to allow for 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months of continuous operation at rated load. The total power output from the two SDGs will be 5000 kWe (5500 kWe at the prime rating).

The licensee stated that the primary reason for the request to extend the CT for an inoperable DG is to allow sufficient time to perform planned reliability improvement modifications and adequate preventative maintenance to ensure emergency DG reliability and availability.

Additionally, should conditions occur requiring emergency DG corrective maintenance, the proposed change also provides flexibility to resolve emergency DG deficiencies and avoid potential unplanned shutdowns, along with any potential attendant challenges to safety systems during an unplanned shutdown.

In the May 2, 2017 letter, the licensee stated that the AC power source operability requirements for the McGuire shared systems are currently located in the TS Bases and specify that both normal and emergency power sources are required for the operability of the shared systems.

The McGuire TS definition of operable/operability is:

A system, subsystem, train, component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication, and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform Its specified safety function( s) are also capable of performing their related support function(s).

The licensee proposed to revise the TS Bases to align with the McGuire TS definition of operable/operability for the McGuire shared systems' AC power source operability requirements.

In its December 3, 2018 letter, the licensee stated that McGuire has completed the installation of the ESPS equipment and facility tie-ins. In addition, the licensee proposed revising the existing TS 3.8.1 Required Actions (RAs) and associated CTs for an inoperable unit-specific emergency DG (Condition 8) to allow the 14-day CT extension for restoring the inoperable unit-specific emergency DG.

The licensee also proposed to add license conditions to Appendix 8, "Additional Conditions," of the facility operating licenses regarding control of the turbine-driven auxiliary feedwater pump as protected equipment and maintaining the risk estimates within the risk acceptance guidelines of Regulatory Guides 1.17 4 (Reference 12) and 1.177 (Reference 13).

2.2.a

Licensee's Proposed TS Changes

The licensee's proposed changes for TS 3.8.1 are shown as follows with additions shown in double-underline and deletions in double-strike-out.

The licensee proposed to revise LCO 3.8.1 as follows:

LCO 3.8.1 APPLICABILITY:

The following AC electrical sources shall be OPERABLE:

a.

b.

c.

d.

Two qualified circuits between the offsite transmission network and the Onsite Essential Auxiliary Power System; and Two diesel generators (DGs) capable of supplying the Onsite Essential Auxiliary Power Systems; and The qualified circuitls} between the offsite transmission network and the opposite unit's Onsite Essential Auxiliary Power System necessary to supply power to the Nuclear Service Water System

<NSWS}. Control Room Area Ventilation System <CRAYS}. Control Room Area Chilled Water System <CRACWS} and Auxiliary Building Filtered Ventilation Exhaust System <ABFVES}: and The DG<s} from the opposite unit necessary to supply power to the NSWS. CRA VS, CRACWS and ABFVES; The automatic load sequencers for Train A and Train B shall be OPERABLE.

MODES 1, 2, 3, and 4.

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

The opposite unit electrical power sources in LCO 3.8.1.c and LCO 3.8.1.d are not required to be OPERABLE when the associated shared systems are inoperable.

The licensee proposed to revise Condition A, as follows:

CONDITION REQUIRED ACTION COMPLETION TIME A.

One LCO 3.8.1.a offsite A.1 Perform SR 3.8.1.1 for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months circuit inoperable.

required OPERABLE offsite circuit(§).

AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter AND A.2 Declare required 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery feature( s) with no off site of no offsite power to one power available train concurrent with inoperable when its inoperability of redundant redundant required required feature(s) feature(s) is inoperable.

AND A.3 Restore offsite circuit to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

AND 617 days from discovery of failure to meet LCO 3 8 :I.a Q[ LCO 3.8.1,b The licensee proposed to revise Condition 8, Required Action 8.1 (with CT); renumber current Required Action 8.1 to 8.2 and add the word "required;" renumber Required Action 8.2 to 8.3, and 8.3.1 and 8.3.2 to 8.4.1 and 8.4.2; revise 8.4 to reflect multiple DGs; add new Required Action 8.5; and renumber current Required Action 8.4 to 8.6 with revised CTs, as follows:

CONDITION REQUIRED ACTION COMPLETION TIME B.

One LCO 3.8.1.b DG B.,1 Verif~ LCO 3.8, 1.d DG(sl 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable OPERABLE.

AND Once Qer 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.ii Perform SR 3.8.1.1 for the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required offsite circuit(s).

AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter AND B.~~

Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of feature( s) supported by Condition 8 concurrent the inoperable DG with inoperability of inoperable when its redundant required required redundant feature(s) feature(s) is inoperable.

B.~.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(§l is not inoperable due to common cause failure.

OR B.~.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE DG(§l.

AND (continued)

{The revised Condition 8 changes continue on the next page.)

CONDITION REQUIRED ACTION COMPLETION TIME B.

(continued) a..5 Evaluate availabilit~ of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Emecgency SuQQlemental Power Source <ESPS}.

AND Qnce Qer 12 houcs theceafter AND B.4§ Restore DG to OPERABLE 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from discove~

status.

of unavailable ESPS**

AND 6 08~8 fF8"1 Oi808¥8J¥ 8f feihalf8 t8

~est bCO 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discove~ of Condition B ent~ > 48 houcs concurrent with unavailability of ESPS AND 14 days AND 17 days fcom discove~

Qf failure to meet LCQ 3.8.1.a QC LCO 3.8.1.b The licensee proposed to add a new Condition C, as follows:

CONDITION REQUIRED ACTION COMPLETION TIME

.c.,_

Qne LCO 3.8. 1,c Qffsite

NOTE---------

circuit inQperable, Enter applicable CQnditiQns and Reguired ActiQnS Qf LCQ 3.8.9, "DistributiQn S~stems -

opecating/ wben CQnditiQn C is entered witb nQ AC pQwer SQurce tQ a train.

.c.,i PerfQrm SB 3.8. 1. 1 fQ[ the

I hQur reguired Qffsite circuit(s).

AND Qoce per 12 hQurs thereafter AND C2 Declare NSWS1 CRA VS, 24 bQurs frQm discQ~e~

CRACWS Qr ABE~ES with Qf OQ Qffsite pQwer tQ Qne nQ Qffsite pQwer available train CQncurreot with inQperable wben the ioQperabili~ Qf redundant redundant NSWS1 reguired feature(sl CRA VS 1 CRACWS Qr ABFVES is inQperable.

AND C.3 BestQre LCQ 3.8. 1.c 72 hQU[S Qffsite circuit tQ OPERABLE status.

The licensee proposed to revise current Condition C and rename as Condition E, as follows:

CONDITION REQUIRED ACTION COMPLETION TIME GE. Two LCO 3.8.1.a offsite G~.1 Declare required 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from discovery circuits inoperable.

feature( s) inoperable of Condition G~

when its redundant concurrent with QB required feature(s) is inoperability of redundant inoperable.

required feature(s)

Ooe LCO 3.8.1.a Qffsite circuit that prQ~ides pQwer tQ tbe NSWS, AND CRA VS 1 CRACWS and ABEVES inQperable G~.2 Restore one offsite circuit 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and to OPERABLE status.

Qne LCO 3.8.1.c Qffsite circuit ioQperable.

QB IWQ LCO 3.8.1.c Qffsite circuits inQperable.

The licensee proposed to revise current Condition D and rename it as Condition F, as follows:

CONDITION REQUIRED ACTION COMPLETION TIME QF.

One LCO 3.8.1.a offsite

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

circuit inoperable.

Enter applicable Conditions and Required AND Actions of LCO 3.8.9, 11 Distribution Systems -

One LCO 3.8.1.b DG Operating, 11 when inoperable.

Condition Qf is entered with no AC power source to any train.

Qf.1 Restore offsite circuit to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OPERABLE status.

AND Qf.2 Restore DG to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

The licensee proposed to add a new Condition D, as follows:

CONDITION REQUIRED ACTION COMPLETION TIME Q_,_

Qne LCQ 3.8. :1.d DG

~QTE-------------

inoperable.

Eater applicable Cooditioos and Reguired Actions of LCO 3.8.9, "Distribution S~stems -

Qperating 1" when Cooditioo D is entered with no AC power source to a train.

D. 1 Verif~ botb LCQ 3.8.1.b 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months DGs QPERABLE.

AND Qnce per 12 bours thereafter AND

.D.2 Eerform SR 3.8.1.1 for tbe

1 hour reguired offsite circuit(sl.

AJ",J__Q Qnce per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter AND D.3 Declare NSWS, CRA VS, 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discove~ of CRACWS or ABFVES Conditioo O concurrent supported b~ tbe with iooperabili~ of inoperable DG inoperable reduodant reguired wben the redundant feature(sl NSWS 1 CRA VS, CRACWS or ABFVES is inoperable.

AND (contiouedl (The new Condition D changes continue on the next page.)

CONDITION REQUIRED ACTION COMPLETION TIME D.

<Continued}

D.4.1 Determine oeERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG<s} is oot inoQerable due to common cause failures.

QB D.4.2 Perform SR 3.8. :1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE DG<s}.

AND D.5.1 Restore LCO 3.8. :1.d DG to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

QB D.5.2 Align ~SWS, CRA VS, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months CRACWS and ABE~ES suQported b~ tbe iDOQerable LCO 3.8.1.d DG to an OPERABLE DG, The licensee proposed to revise Condition E and rename it as Condition G as follows:

CONDITION REQUIRED ACTION COMPLETION TIME liG. Two LCO 3.8.1.b DGs li.G.1 Restore one DG to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months inoperable.

OPERABLE status.

QB LCO 3.8. 1.b DG that Qrovides power to tbe

~sws, CRA VS, CRACWS a!'.ld ABFVES iaoQerable and one LCO 3.8.1.d DG iaoperable.

QB Iwo LCO 3.8.1,d DGs iooQerable.

The licensee proposed to rename current Condition F as Condition H as follows.

CONDITION REQUIRED ACTION COMPLETION TIME J;;J:L One automatic load J;;H.1 Restore automatic load 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months sequencer inoperable.

sequencer to OPERABLE status.

The licensee proposed to revise Condition G and rename it as Condition I, as follows:

CONDITION REQUIRED ACTION COMPLETION TIME GL Required Action and G!-1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A, ~

AND

~Gi=E._F, G, or Hnot met.

G!.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months QB Beguired Action and associated ComQletion Iime of Reguired Action B.2, B.3, B.4.1, B.4.2, or B.6 not met.

QB Beguired Action and associated ComQletion Iime of Beguired Action D.2, D.3, 0.4.1, D.4.2, D.5.1, or D.5.2 not met.

The licensee proposed to revise Condition H and rename it as Condition J, as follows:

CONDITION REQUIRED ACTION COMPLETION TIME

~ Three or more LCO MJ.1 Enter LCO 3.0.3.

Immediately 3.8. :I.a and LCO 3.8.1.b AC sources inoperable QB Tbree or more LCO 3.8.1.c and LCQ 3.8.1.d AC sources inoQerable.

The licensee proposed conforming changes to the TS 3.8.1 page numbering.

Although the licensee did not propose changes to TS 3.7.7, "Nuclear Service Water System (NSWS)," TS 3.7.9, "Control Room Area Ventilation System (CRAVS)," TS 3.7.10, "Control Room Area Chilled Water System (CRACWS)," TS 3.7.11, "Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)," or TS 3.8.2; the licensee nonetheless provided proposed new bases for those TS. The licensee also provided proposed new and changed bases for TS 3.8.1. The licensee indicated that the proposed changes were to reflect what is required by the proposed amended TS 3.8.1 and, further, that the changes would make the bases for the unrevised TSs consistent with the amended TSs.

2.2.b Licensee's Proposed Changes to its Faciltiy Operating Licenses In its letter dated March 7, 2019, the licensee proposed the following license conditions to be added to Appendix B, "Additional Conditions," of the McGuire, Units 1 and 2, Facility Operating Licenses, NPF-9 and NPF-17, respectively, as follows on the next page (the format may differ in the operating licenses).

McGuire, Unit 1, Facility Operating License, NPF-9:

Amendment Additional Condition lm~lementation Number Date 314 During the extended DG Completion Times Upon implementation authorized by Amendment No. 314, the turbine-of Amendment No.

driven auxiliary feed water pump will not be removed 314 from service for elective maintenance activities. The turbine-driven auxiliary feed water pump will be controlled as "protected equipment" during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safe Shutdown Facility, Nuclear Service Water System, Chemical and Volume Control System, Diesel Air Compressors, Residual Heat Removal System, motor driven auxiliary feed water pumps, and the switchyard will also be controlled as "protected equipment."

314 The risk estimates associated with the 14-day EDG Upon implementation Completion Time LAR (including those results of of Amendment No.

associated sensitivity studies) will be updated, as 314 necessary to incorporate the as-built, as-operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance Quidelines of RG 1.17 4 and RG 1.177.

McGuire, Unit 2, Facility Operating License, NPF-17:

Amendment Additional Condition lm~lementation Number Date 293 During the extended DG Completion Times authorized Upon implementation by Amendment No. 314, the turbine-driven auxiliary of Amendment No.

feed water pump will not be removed from service for 293 elective maintenance activities during the extended CT. The turbine-driven auxiliary feed water pump will be controlled as "protected equipment" during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safe Shutdown Facility, Nuclear Service Water System, Chemical and Volume Control System, Diesel Air Compressors, Residual Heat Removal System, motor driven auxiliary feed water pumps, and the switchyard will also be controlled as "protected equipment."

293 The risk estimates associated with the 14-day EDG Upon implementation Completion Time LAR (including those results of of Amendment No.

associated sensitivity studies) will be updated, as 293 necessary to incorporate the as-built, as-operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance guidelines of RG 1.17 4 and RG 1.177.

2.3 Applicable Regulations and Guidance Regulations at 10 CFR 50.90 state that whenever a holder of a license wishes to amend the license, including technical specifications in the license, an application for amendment must be filed, fully describing the changes desired. Under 10 CFR 50.92(a), determinations on whether to grant an applied-for license amendment are to be guided by the considerations that govern the issuance of initial licenses or construction permits to the extent applicable and appropriate. Both the common standards for licenses and construction permits in 1 O CFR 50.40(a), and those specifically for issuance of operating licenses in 10 CFR 50.57(a)(3),

provide that there must be 'reasonable assurance' that the activities at issue will not endanger the health and safety of the public and that the licensee will comply with the Commission's regulations.

Per 10 CFR 50.36(a}(1 ), each applicant for a license authorizing operation of a utilization facility shall include in its application proposed technical specifications in accordance with the requirements of 10 CFR 50.36(a)(1). Significantly, per 10 CFR 50.36(a)(1), "A summary statement of the bases or reasons for such specifications, other than those covering administrative controls, shall also be included in the application, but shall not become part of the technical specifications."1 Per 10 CFR 50.36(b), each license will include technical specifications. Further, per 10 CFR 50.36(b), "[t]he technical specifications will be derived from the analyses and evaluation included in the safety analysis report, and amendments thereto, submitted pursuant to§ 50.34. The Commission may include such additional technical specifications as the Commission finds appropriate."

Regulation 10 CFR 50.63(a}, "Loss of all alternating current power," required that each light-water cooled nuclear power plant licensed to operate must be able to withstand for a specific duration and recover from a station blackout.

Regulation 10 CFR 50.65(a}, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," requires that the licensee shall monitor the performance or condition of 1 Although the Bases are not part of the TSs or otherwise made into part of the license, the TSs for McGuire Units 1 and 2 set forth a means for processing changes to the Bases that requires, under certain circumstances, review and approval by the NRC prior to implementation of the changes. Specifically, TS 5.5.14 "[TS] Bases Control Program," states:

a.

Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b.

Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1.

A change in the TS incorporated in the license; or

2.

A change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

c.

The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.

d.

Proposed changes that meet the criteria of Specification 5.5.14.b.1 or 5.5.14.b.2 above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

structures, systems, or components, against licensee-established goals, in a manner sufficient to provide reasonable assurance that these structures, systems, and components, as defined in paragraph (b) of this section, are capable of fulfilling their intended functions. These goals shall be established commensurate with safety and, where practical, take into account industrywide operating experience.

Regulation 10 CFR 50.36, "Technical specifications," states that the TSs include items in specific categories, including: (1) safety limits, limiting safety system settings, and limiting control settings; (2) Limiting Conditions for Operation; (3) surveillance requirements; (4) design features; and (5) administrative controls.

Regulation 10 CFR 50.36(c)(2), "Limiting conditions for operation," states:

(i) 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 any remedial action permitted by the technical specifications until the condition can be met.

Commission Policy Statements The Commission's Final Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors (58 FR 39132; July 22, 1993) presents the policy with respect to the scope and purpose of Technical Specifications. Further, it establishes a specific set of objective criteria as guidance2 for determining which regulatory requirements and operating restrictions should be included in Technical Specifications. It encourages licensees to implement a voluntary program to update their Technical Specifications to be consistent with improved vendor-specific Standard Technical Specifications (STS) issued by the NRC. Concerning bases, the policy statement says in part:

Each LCO, Action, and Surveillance Requirement should have supporting Bases.

The Bases should at a minimum address the following questions and cite references to appropriate licensing documentation (e.g., FSAR, Topical Report) to support the Bases.

2. What are the Bases for each LCO, i.e., why was it determined to be the lowest functional capability or performance level for the system or component in question necessary for safe operation of the facility and, what are the reasons for the Applicability of the LCO?

3. What are the Bases for each Action, i.e., why should this remedial action be taken if the associated LCO cannot be met; how does this Action relate to other Actions associated with the LCO; and what justifies continued operation of the system or component at the reduced state from the state specified in the LCO for the allowed time period?

2 The policy provided guidance; the regulations at 10 CFR 50.36(c)(2)(ii)(A)-(D) provide requirements via four criteria to be used to determine if technical specification limiting condition for operation must be established; 10 CFR 50.36(c)(2)(iii) makes clear that a licensee is not required to propose to modify technical specifications that are included in any license issued before August 18, 1995 in order to satisfy the criteria 10 CFR 50.36(c)(2)(ii)(A)-(D).

Plant Design Criteria Section 3.1, "Conformance with General Design Criteria [GDC]," of McGuire's UFSAR states that McGuire complies with GDC 5 by stating, in part:

Structures, systems, and components, which are either shared (a) between the two units or (b) among systems within a unit, are designed such that there is not interference with basic function and operability of these systems due to sharing.

This design protects the ability of shared structures, systems and components to perform all safety functions properly.

Section 3.1 states that McGuire complies with GDC 17 by stating, in part:

Reliability of electric power supply is assured through several independent connections and a redundant source of standby emergency power from two DGs per unit. The specific design criteria applied in the design of systems and components are in accordance with IEEE Criteria for Class IE Electrical Systems for Nuclear Power Generating Stations, IEEE No. 308, 1971.

Two separate 230 kV transmission lines for Unit 1 connect the 230 kV switchyard to two separate half size main transformers which transform the voltage to 24 kV.

Similarly, two separate 525 kV transmission lines for Unit 2 connect the 525 kV switchyard to two separate half size main transformers which transform the voltage to 24 kV. The separation of the two supplies at the 24 kV voltage level for each unit is maintained by the two generator breakers which open when the generator is disconnected from the system. The two supplies are further reduced in voltage to 6900 volts by two full sized unit auxiliary power transformers. The two supplies are then separately connected through breakers to the normal auxiliary switchgear where they are connected through breakers and separate cables to the essential auxiliary power system switchgear. Each of the supplies is normally available within seconds following the tripping of the reactor and the opening of the generator breakers.

In the event one of the unit auxiliary transformers is out of service for maintenance, the other transformer is sized to carry all auxiliaries of one operating nuclear unit plus the safety shutdown loads of the other nuclear unit.

In addition, a manually-initiated tie to the normal auxiliary busses of the other nuclear unit is available.

Two separate circuits from the transmission network are normally available to each nuclear unit. In the event one of the circuits is unavailable, a manual connection is provided to the other unit's Normal Auxiliary Power System to provide the required second circuit from the transmission network in compliance with GDC 17....

Section 3.1 states that McGuire complies with GDC 18 by stating; Provisions are made for periodic testing of all important components of the emergency power system. Further provision is made for periodic testing of the emergency diesel generators to assure their capability to start within design limits and to accept loads.

The 24 kV, 230 kV, and 525 kV circuit breakers and their protective relays are inspected, maintained and tested on a routine basis. The 6900 volt and 4160 volt circuit breakers and associated equipment are tested in-service by opening and closing the circuit breakers so as not to interfere with the operation of the station.

The 600 volt circuit breakers, motor contactors and associated equipment are tested in-service by opening and closing the circuit breakers or contactors so as not to interfere with operation of the station.

Systems are designed to allow as much testing of the various safety systems as is practical. The operation of the onsite power sources are [sic] conducted on a periodic basis and this includes starting each of the two diesel electric generating units assigned to each system and loading it to its continuous rating. Staggering of test periods is adhered to in order to avoid the testing of redundant equipment at the same time.

Regulatory Guides Regulatory Guide (RG) 1.93 (Reference 10), "Availability of Electric Power Sources,"

Revision 1, provides guidelines that the NRC staff considers acceptable when the number of available electric power sources are less than the number of sources required by the limiting conditions for operation (LCOs) for a facility.

Regulatory Guide (RG) 1.155 (Reference 11 ), "Station Blackout," describes a method acceptable to the NRC staff for complying with the Commission regulation that requires nuclear power plants to be capable of coping with a station blackout SBO event for a specified duration.

McGuire adheres to the guidelines of NUMARC 87-00, which is endorsed by RG 1.155.

RG 1.17 4 (Reference 12), "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed licensing basis changes by considering engineering issues and applying risk insights.

This RG also provides risk acceptance guidelines for evaluating the results of such assessments.

RG 1.177 (Reference 13), "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications," provides the guidance on acceptable methods for using risk information to evaluate changes to nuclear power plant technical specification completion times and surveillance frequencies in order to assess the impact of such proposed changes on the risk associated with plant operation. RG 1.177 identifies a three-tiered approach for the licensees' evaluation of the risk associated with a proposed CT TS change, as follows.

In Tier 1, the licensee should assess the impact of the proposed TS change on CDF, ICCDP, LERF, and ICLERP. To support this assessment, two aspects need to be considered: (1) the validity of the PRA and (2) the PRA insights and findings. The licensee should demonstrate that its PRA is valid for assessing the proposed TS changes and identify the impact of the TS change on plant risk.

In Tier 2, the licensee should provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is out of service consistent with the proposed TS change.

In Tier 3, the licensee program for compliance with 10 CFR 50.65(a)(4) ensures that the risk impact of out of service equipment is appropriately assessed and managed. To support TS changes, a viable program would be one able to uncover risk-significant plant equipment outage configurations in a timely manner during normal plant operation.

RG 1.200 (Reference 14), "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," describes an acceptable approach for determining whether the base probabilistic risk assessment (PRA), in total or the parts that are used to support an application, is acceptable for use in regulatory decisionmaking for light-water reactors (LWRs).

Standard Review Plan Section 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance," of the NRC Standard Review Plan (SRP},

NUREG-0800 (Reference 15), provides general guidance for evaluating the technical basis for proposed risk-informed changes. Section 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (Reference 16), provides guidance to the NRC staff on evaluating PRA acceptability for risk-informed activities. More specific guidance related to risk-informed TS changes is provided in SRP Section 16.1, "Risk-Informed Decisionmaking: Technical Specifications" (Reference 17), which includes CT changes as part of risk-informed decision making. Section 19.2 of the SRP states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following key principles in RG 1.17 4:

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

2. The proposed licensing basis change is consistent with the defense-in-depth philosophy.

3. The proposed licensing basis change maintains sufficient safety margins.

4. When proposed licensing basis changes result in an increase in risk, the increases should be small and consistent with the intent of the Commission's policy statement on safety goals for the operation of nuclear power plants.

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

Regulatory Issue Summary Regulatory Issue Summary (RIS) 2007-06 (March 2007) (Reference 18), "Regulatory Guide 1.200 Implementation," describes how the NRC will implement its technical adequacy review of plant-specific PRAs used to support risk-informed licensing actions after the issuance of RG 1.200.

Branch Technical Position NUREG-0800, Branch Technical Position (BTP) 8-8 (Reference 19), "Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions," dated February 2012 (ADAMS Accession No. ML113640138), provides guidance to the NRC staff in reviewing license amendment requests {LARs) for licensees proposing a one-time or permanent TS change to extend an Emergency Diesel Generator (EDG) Allowed Outage Time beyond 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

3.0 TECHNICAL EVALUATION

3.1 Shared Systems Considerations The current TS 3.8.1 LCO requires offsite power and emergency DGs of the associated unit, but do not require the opposite unit power sources. For example, TS LCO 3.8.1 for Unit 1 requires offsite power and DGs associated with Unit 1 only. In conjunction, current TS Bases, which are not part of the technical specifications, state that both normal and emergency power to a shared component must be operable for a shared component to be operable and also state that if either the normal or emergency power source is not operable, then the RAs of the affected shared component TS must be entered for each unit that is in the Mode of Applicability.

The licensee determined that the necessary normal and emergency power supplies to shared systems that come from the opposite unit must be added to the TS 3.8.1 LCO for each unit.

The licensee proposed additional TS 3.8.1 LCO requirements to state power operability requirements for shared systems. The additional LCOs would require operable qualified circuit(s) between the offsite transmission network and the opposite unit's Onsite Essential Auxiliary Power System that are necessary to supply power to the NSWS, CRAVS, CRACWS, and ABVES. Additional LCO requirements also include operable DGs from the opposite unit necessary to supply power to the same shared systems. The licensee submitted proposed changes to several TS Bases that would be made obsolete by the granting of the requested license amendment. Those bases are for TS 3.8.1 and TS 3.8.2, "AC Sources-Shutdown", TS 3.7.7, "Nuclear Service Water System (NSWS)", TS 3.7.9, "Control Room Area Ventilation System (CRAVS)", TS 3.7.10, "Control Room Area Chilled Water System (CRACWS)," and TS 3.7.11, Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)."

The following section is a detailed technical evaluation of the licensee's proposed changes to the LCO section of TS 3.8.1, "AC Sources-Operating."

McGuire, Units 1 and 2 share certain systems which are important to safety and, thus, are necessary to achieve safe shutdown in event of a design basis accident (DBA). Shared systems include the NSWS, CRA VS, CRACWS, and ABFVES. Operability of the shared systems are required by TS when either or both units are in Modes 1 through 4. Each shared system has redundant trains to meet the single failure criteria as described by the UFSAR implementation of the plant design criteria and GDCs. One train of a shared system is typically powered by one unit while the other train is powered by the other unit. For example, CRA VS has an A and B Train, each train necessary for either or both units in Modes 1 through 4.

Train A is normally powered by power sources from Unit 1 but can be powered from Unit 2.

Train B is normally powered by Unit 2 but can be powered from Unit 1.

The licensee proposes to add to the LCO for TS 3.8.1, the qualified circuit(s) between the offsite transmission network and the opposite unit's Onsite Essential Auxiliary Power System and the DG(s) from the opposite unit that are necessary to supply power to the shared systems.

The licensee's proposed changes to TS LCO 3.8.1 include all the of AC operability requirements for shared systems by including the opposite unit's power supplies required to support the shared systems. Under the proposed TS change, the shared system components would remain operable (shared systems LCOs would be met and RAs not entered), but the RAs for TS 3.8.1 for an inoperable opposite unit power source would be entered.

In summary, the licensee's proposed changes have added the qualified circuit(s) and DGs from the opposite unit that power shared systems to the TS LCO 3.8.1, as described above. The NRC staff finds that these new requirements address the lowest functional capability or performance levels of equipment required for safe operation of the facility.

The licensee has also proposed a Note added to the Applicability section which takes exception to the new requirements for opposite unit AC sources as specified in proposed LCOs 3.8.1.c and 3.8.1.d provided the associated shared systems are inoperable and the RAs are entered.

This exception is intended to allow declaring the shared systems supported by the opposite unit inoperable, either in lieu of declaring the LCO 3.8.1.c and LCO 3.8.1.d AC sources inoperable, or at any time subsequent to entering ACTIONS for an inoperable LCO 3.8.1.c or LCO 3.8.1.d AC source. The primary need for the Note is during Engineered Safeguards Features (ESF) testing. The testing is performed when one unit is in Modes 1 through 4 and the other unit is shutdown. A single train of shared systems (NSWS, CRAVS, CRACWS and ABFVES) is aligned to the outage unit. In this condition, the outage unit AC sources cannot support operability of the train of shared systems for the online unit. The Applicability Note allows McGuire to declare the entire train of shared systems (NSWS, CRAVS, CRACWS and ABFES) inoperable in lieu of applying proposed LCOs 3.8.1.c and 3.8.1.d for the online unit. The associated TS RAs for the inoperable shared systems will be entered.

This exception is acceptable since, with the shared systems supported by the opposite unit inoperable and the associated ACTIONS entered, the LCO 3.8.1.c and LCO 3.8.1.d AC sources provide no additional assurance that acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of abnormal transients and also provide no additional assurance that adequate core cooling is provided and containment operability and other vital functions are maintained in the event of a postulated OBA. There is no potential for McGuire to go back and forth between entering and exiting shared system LCOs and LCOs 3.8.1.c and 3.8.1.d such that operation could continue indefinitely with inoperable equipment.

The NRC staff has reviewed the regulatory requirements and guidelines associated with the power requirements for shared systems. Based on the above, the NRC staff concludes the following proposed changes are acceptable and meet the requirements 10 CFR 50.36(c)(2)(i),

to ensure that the LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. The summary of the changes is:

The addition of new TS 3.8.1 LCOs 3.8.1.c and 3.8.1.d which require operability of the normal and emergency power sources from the opposite unit necessary to supply shared systems; Conforming change for the removal of the statement from the TS Bases for the shared systems to have both an operable normal and emergency power supply for shared systems in order to be considered operable; The removal of the statements to enter the RAs of the shared system TS if either the normal or emergency power source became inoperable; and The addition of the Applicability Note as described above.

The licensee also requested approval of changes to the TS Bases associated with the electrical power and shared systems. Per 10 CFR 50.36(a)(1 ), Bases provide a summary statement of the bases or reasons for such specifications. The staff review considered if the Bases correctly reflected the revised TS, and if the bases associated with TS that were not being changed were likewise updated to reflect the revised TS. Consistent with the Commission's "Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors" (58 FR 39132), the licensee's proposed TS Bases changes contain supporting information which describe each LCO, Action, and Surveillance Requirement, as described in the licensee's proposed TSs. The TS Bases describe how the LCO is determined to be the lowest functional capability or performance level for the system or component necessary for safe operation of the facility. The TS Bases provide the supporting reasons for the Applicability of the LCO. The TS Bases provide the justification for the remedial actions that should be taken if the associated LCO cannot be met. The staff finds the proposed changes to the TS Bases acceptable, noting, however, that per 10 CFR 50.36(a)(1 ), bases are not and shall not become part of the amended TS being issued. The license requirement in TS 5.5.14 "Technical Specifications (TS) Bases Control Program" already requires the Bases Control Program to contain provisions to ensure that the Bases are maintained consistent with the UFSAR.

3.2 BTP 8-8 Considerations 3.2.1 Evaluation of DG 14-day CT Extension - Existing Condition B - Revised The NRC staff reviewed the proposed extended 14-day extended the Completion Time (CT) for an inoperable unit-specific emergency DG (TS 3.8.1 existing Condition B) in accordance with the BTP 8-8 guidance. Existing Condition B with associated RAs and CTs is proposed to be revised to allow the verification of an opposite unit DG and the extended 14-day CT.

Existing Condition B (one DG is inoperable) is revised by adding "LCO 3.8.1.b" to existing condition statement. The licensee stated that the "LCO 3.8.1.b" is added to Condition B to clarify that the condition pertains tc;> a unit-specific emergency DG rather than a DG from the opposite unit. The NRC staff finds the revised Condition B acceptable since the addition of "LCO 3.8.1.b" to the existing Condition B correctly specifies the unit-specific nature of the condition.

New RA B.1 is added to verify the operability of the opposite unit's LCO 3.8.1.d DG(s) necessary to supply power to the shared systems within a CT of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter when an LCO 3.8.1.b DG is inoperable. In its December 3, 2018 letter, the licensee stated that the new RA B.1 would be an administrative verification of the operability for the LCO 3.8.1.d DG(s). The licensee further stated that the 1-hour CT would allow sufficient time to perform RA B.1 if the inoperability of the LCO 3.8.1. b DG was unplanned, and the 12-hour CT was based on the McGuire operator shift of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . If the verification in RA B.1 resulted in the LCO 3.8.1.d DG(s) being inoperable in Condition B (one LCO 3.8.1.b DG inoperable), McGuire would enter either the proposed new Condition D and/or renumbered Condition G, as applicable (see sections 3.1.6 and 3.1.9 of this SE for the staff's evaluations of the proposed new Condition D and renumbered Condition G, respectively).

The NRC staff finds the new RA B.1 with associated CTs acceptable since it will help ensure that at least one train of shared systems has an operable DG.

Existing RAs 8.1, 8.2, B.3.1, B.3.2 are renumbered as RAs 8.2, B.3, B.4.1, and B.4.2, respectively. The term "required" is added to offsite circuits in the renumbered RA 8.2, and "(s)"

is added to DG in the renumbered RAs B.4.1 and B.4.2. Adding "required" to offsite circuits in the renumbered RA B.2 would indicate that the RA would be performed for all offsite circuits required by the LCO 3.8.1. In its July 10, 2018 letter, the licensee stated that changing "DG" to "DG(s)" in the renumbered RAs B.4.1 and B.4.2 would allow the RAs to be performed for the operable LCO 3.8.1.b DG and LCO 3.8.1.d DG(s).

The NRC staff finds the proposed changes to existing 8.1, 8.2, B.3.1, B.3.2 are editorial in nature and are, therefore, acceptable.

A new RA B.5 with associated CT is added to the revised Condition B; and the existing RA 8.4 with associated CT is revised and renumbered as RA 8.6 to allow the extension of the CT for an inoperable LCO 3.8.1.b DG from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days.

Branch Technical Position (BTP) 8-8 (Reference 19) recommends that the availability of the supplemental AC power source be verified within the last 30 days before entering extended CT by operating or bringing the power source to its rated voltage and frequency and ensuring all its auxiliary support systems are available or operational. In its July 10, 2018 letter, the licensee stated that the availability of the ESPS would require ( 1) performance of the load test within 30 days of entry into the extended CT; (2) verification of the fuel tank locally to be greater than or equal to a 24-hour supply; and (3) verification of the ESPS supporting system parameters for starting and operating to be within limits for functional availability.

The NRC staff notes that the performance of the load test for the ESPS will involve bringing the ESPS to its rated voltage and frequency, and the verification of the ESPS supporting systems parameters within limits will ensure that the support systems are functional. The NRC staff finds that since the availability of the ESPS and its auxiliary support systems will be verified within the last 30 days before entering extended CT, as recommended by BTP 8-8 and is, therefore, acceptable.

BTP 8-8 recommends that the time to make the supplemental power source available to supply the loads, including cross-connection, should be approximately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to enable restoration of battery chargers and control reactor coolant system inventory. BTP 8-8 also recommends that plants have approved procedures for connecting the supplemental power source to the safety buses.

In its May 2, 2017 letter, the licensee stated that, in order to meet the "approximately one hour" criterion, McGuire will utilize an existing Emergency Procedure (ECA-0.0, "Loss of All AC Power) that guides the control room operators through the appropriate steps to systematically cope with a total loss of AC Power (i.e., Station Blackout (SBO)). The licensee also stated that observations of the operators on the plant simulator showed that it would take about 20 minutes for the operators to get to the point in the procedure to attempt to restore power from any of the normal and emergency power sources (i.e., restoring an emergency DG, cross-tying the units or restoring offsite power). In a November 2, 2018 RAI (Reference 20), NRC staff requested the licensee (a) clarify the estimated time it would take to connect the ESPS power source (i.e., the two supplemental DGs) to the station's safety bus from the start of an SBO event and (b) provide a discussion that summarizes the calculations or analysis performed to assess the McGuire ability to cope with the loss of all AC power (i.e., SBO) for one hour or the plant specific period of time until the ESPS is connected to the shutdown buses, as stated in BTP 8-8. In its December 3, 2018 letter, in response to RAI 3a, the licensee clarified that the time it would take to restore power to a 4160 V safety bus using the ESPS from the time power would be lost to the 4160 V safety buses was validated at 70 minutes including margin.

The NRC staff finds that McGuire meets the intent of the BTP 8-8 guidance regarding the timeframe for making the supplemental power source available to supply the loads since the 70-minute timeframe to re-energize a 4160 VAC safety bus using the ESPS is within "approximately 1 (60 minutes) hour" timeframe.

To support the timeframe for making the supplemental power source available, BTP 8-8 recommends that plants assess their ability to cope with loss of all AC power (i.e., SBO) for this timeframe independent of a supplemental power source.

In its November 2, 2018 RAI 3b, the NRC staff requested the licensee to provide a discussion that summarizes the calculations or analysis performed to assess the McGuire ability to cope with the loss of all AC power (i.e., SBO) for one hour or the plant specific period until the ESPS is connected to the shutdown buses. In its December 3, 2018 letter, in response to RAI 3b, the licensee stated that Duke Energy has performed a calculation for McGuire that assessed its ability to cope with an SBO event without taking credit for the Safe Shutdown Facility (SSF).

The licensee further stated that ( 1) the calculation included a reactor coolant pump seal leakage, no primary mass addition, no secondary heat sink and assumed that the SSF is unavailable; and (2) the calculation concluded that the length of time between the SBO event initiation and the onset of significant core uncover is approximately 2.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . In Attachment 1 of its April 8, 2019 letter, the licensee provided a figure of core collapsed water level versus time from the calculation to support their initial response to RAI 3b. The figure shows that the core remains covered with minimal voiding until approximately 115 minutes (greater than 70 minutes) at which point the core collapsed level begins to decrease.

Since McGuire's SBO calculation takes no credit for the SSF and shows that the core will remain covered within the first 115-minute of an SBO event, the NRC staff finds that McGuire has sufficient time to cope with an SBO event without a supplemental AC power source for the 70-minute duration as noted above in response to RAI 3a until the ESPS is connected to a 4160V safety bus. Therefore, the NRC staff finds that McGuire's ability to cope with an SBO event without a supplemental AC power source for the 70-minute duration credited to connect the ESPS to a 4160V safety bus is consistent with the recommendations of BTP 8-8, and is therefore, acceptable.

BTP 8-8 recommended that the TS contains RAs and CTs to verify that the supplemental AC source is available before entering the extended CT and every 8-12 hours ( once per shift).

The McGuire 14-day extended CT begins after 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of continuous DG inoperability.

In its December 3, 2018 letter, the licensee proposed to add a new RA 8.5 to the TS 3.8.1 revised Condition B (inoperable LCO 3.8.1.b DG) to evaluate the availability of the ESPS within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. The licensee stated that the 12-hour CT was chosen because the McGuire operator shifts are 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In its May 2, 2017 letter, the licensee stated that the extended 14-day CT for one inoperable LCO 3.8.1.b DG will be applied only if there is a suitable ESPS available and functional.

The NRC staff finds that the 1-hour and 12-hour thereafter CT for RA 8.5 will allow the licensee to ensure that the ESPS is available before entering the time greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of continuous DG inoperability. Therefore, the NRC staff finds that the proposed RA B.5 and associated CTs are consistent with the recommendation provided in BTP, 8-8, and are, therefore, acceptable.

BTP 8-8 recommended that if the supplemental power source becomes unavailable any time during the extended CT, the unit shall enter the LCO 3.8.1 and start shutting down within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . In its December 3, 2018 letter, the licensee proposed to revise the existing RA B.4 (restore DG to operable status) and associated CTs to allow the proposed 14-day CT extension.

Existing RA B.4 is renumbered as RA 8.6. The NRC staff finds the renumbering of RA B.4 as RA B.6 is editorial in nature and is, therefore, acceptable.

The renumbered RA B.6 (restore DG to operable status) will have four CTs that state: "72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from discovery of unavailable ESPS AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition B entry ~ 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months concurrent with unavailability of ESPS AND 14 days AND 17 days from discovery of failure to meet LCO 3.8.1.a or LCO 3.8.1.b." The four CTs for the renumbered RA 8.6 are joined by an "AND" connector to indicate that all CTs apply simultaneously, and the more restrictive CT must be met.

The first two CTs (i.e., 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from discovery of unavailable ESPS AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition B entry~ 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months concurrent with unavailability of ESPS) would limit the time to restore the unit-specific emergency DG (i.e., LCO 3.8.1.b DG) to operable status without an available ESPS. The third CT (i.e., 14 days) would extend the total time to restore the LCO 3.8.1.b DG from the existing 72-hour CT up to 14 days provided that the ESPS is available. If the ESPS is found unavailable any time from initial entry into Condition B up to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , the first two CTs (72-hour CT and 24-hour CT) will limit the time to restore the LCO 3.8.1.b DG to operable status to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from entry into Condition B.

The NRC staff finds that if the ESPS becomes unavailable sometime after 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months from initial entry into Condition B, the licensee has 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to restore the LCO 3.8.1.b DG to operable status. But, before entering the time greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the licensee must ensure that the ESPS is available per RA B.5, as recommended by the BTP 8-8. Otherwise, if the ESPS remains unavailable per RA B.5 up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from initial entry into Condition B, the remaining time to restore the LCO 3.8.1.b DG to operable status is limited to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from initial entry into Condition B. The NRC staff finds that if the ESPS becomes unavailable sometime after 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from initial entry into Condition B (assuming that the ESPS was available prior to entering the time greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ), the time to restore the LCO 3.8.1.b DG to operable status is limited to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months provided that the total time does not exceed 14 days. If the LCO 3.8.1.b DG is not restored to operable status within this 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and/or within the 14-day CT, the licensee will enter the renumbered Condition I (revised Condition G) to shut down the affected McGuire unit (see section 3.3.2.8 of this SE for the NRC staff's evaluation of the proposed renumbered Condition I).

Based on the above, the NRC staff finds that the proposed 72-hour, 24-hour, and 14-day CTs for the renumbered RA B.6 are consistent with the guidance provided in the BTP 8-8 since the CTs will allow (1) 72-hour limit to restore the DG if the ESPS is unavailable during the first 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of DG inoperability, and (2) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to restore the DG if the ESPS is unavailable during the extended CT.

The fourth CT (i.e., "17 days from discovery of failure to meet LCO 3.8.1.a or LCO 3.8.1.b")

would limit the maximum time that LCO 3.8.1.a or LCO 3.8.1.b is not met while concurrently or simultaneously in the TS 3.8.1 revised Condition A (inoperable LCO 3.8.1.a offsite circuit) and revised Condition 8 (inoperable LCO 3.8.1.b DG). In its July 10, 2018 letter, the licensee clarified that the maximum 17 days would be the sum of the 72-hour CT for restoring an inoperable offsite circuit and the extended 14-day CT for restoring an inoperable LCO 3.8.1.b DG (renumbered RA 8.6).

The NRC staff finds the maximum 17-day CT for the renumbered RA 8.6 acceptable since it limits the allowable total time that any combination or required AC power sources will be inoperable at the same time.

8TP 8-8 recommends that a justification be provided for the duration of the requested extended CT (i.e., 14 days for McGuire) based on plant-specific past operating experience.

In its July 20, 2017 letter, the licensee provided a summary of projected major maintenance work hours for the emergency DGs in both units on a per-calendar year basis. The NRC staff finds that, based on the projected maintenance work hours, the proposed 14-day CT is acceptable because it is consistent with the 8TP 8-8 guidance.

In summary, the NRC staff determined that the licensee provided adequate justification for the proposed extended 14-day CT for an inoperable DG because the ESPS will be available prior to entering the extended CT and will be capable of supplying power to the loads necessary to bring the affected McGuire unit to a cold shutdown in the event of a loss of offsite power (LOOP) concurrent with a single failure. Therefore, based on the above, the NRC staff finds that the proposed change in the CT for one inoperable unit-specific emergency DG (revised Condition

8) from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days is acceptable.

3.2.2 Evaluation of Additional TS Changes 3.2.2.1 Existing Action A - Revised Existing Condition A applies when one of the two qualified offsite circuits between the offsite transmission network and the onsite essential auxiliary power system in LCO 3.8.1.a is inoperable.

Existing Condition A is proposed to be revised by adding "LCO 3.8.1.a" to existing statement; and the existing RA A.1 is revised by adding "required" to operable and "(s)" to circuit. In its letter dated July 10, 2018, the licensee stated that the addition of "LCO 3.8.1.a" to Condition A would clarify that the condition pertains to a qualified circuit between the offsite transmission network and the affected unit's onsite essential auxiliary power system. The licensee further stated that "required" and "(s)" would be added to RA A.1 to indicate that it could be necessary to verify the operability of more than one offsite circuit if the LCO 3.8.1.c offsite circuit was supplying power to a train of the shared systems when in Condition A.

The NRC staff notes that the proposed changes to existing Condition A and RA A.1 reflect the addition of the new LCO 3.8.1.c offsite circuit to the TS 3.8.1 and do not change the intent of the existing requirements. Therefore, the NRC staff finds the proposed revised Condition A with associated RA A.1 acceptable since the proposed changes do not change the intent of the existing requirements.

The existing maximum CT of "6 days from discovery of failure to meet LCO" for RA A.3 (restore off site circuit to operable status) is revised to "17 days from discovery of failure to meet LCO 3.8.1.a or LCO 3.8.1.b." Changing "LCO" to "LCO 3.8.1.a or LCO 3.8.1.b" would clarify the 17-day CT pertaining to the unit-specific AC power sources. In its July 10, 2018 letter, the licensee stated that the maximum 17-day CT for RA A.3 would limit the total time that the LCO 3.8.1 is not met while concurrently or simultaneously in the revised Condition A and revised Condition B (LCO 3.8.1.b DG). The CT for restoring the unit's DG to operable status (renumbered RA B.6) is being extended from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months up to 14 days (see section 3.1.2 of this SE for the staff's evaluation of the 14-day CT for the revised Condition B). Thus, the proposed new maximum 17-day CT for RA A.3 would be the sum of the existing 72-hour CT for RA A.3 and the proposed 14-day CT for RA B.6.

The NRC staff finds the proposed maximum 17-day CT for RA A.3 acceptable since it will limit the time for restoring the inoperable unit-specific AC power sources to meet the LCO 3.8.1 or take other remedial actions for the safe operation of the plant.

3.2.2.2 New Condition C The proposed new Condition C would apply when LCO 3.8.1.c offsite circuit is inoperable. The proposed new RAs C.1, C.2, and C.3 for new Condition C are modified by a Note.

The proposed Note states: "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." In its July 10, 2018 letter, the licensee stated that the note would allow the new Condition C to provide requirements for the loss of a LCO 3.8.1.c offsite circuit and LCO 3.8.1.d DG without regard to whether a train is de-energized, as the McGuire TS LCO 3.8.9, "Distribution Systems - Operating," provides the appropriate restrictions for a de-energized train. In its December 3, 2018 letter, the licensee further clarified that in the case where one LCO 3.8.1.c offsite circuit would be inoperable (proposed new Condition C) concurrently with one inoperable LCO 3.8.1.d DG (proposed new Condition D) associated with the same train of shared systems, the proposed Note would allow McGuire to enter the applicable TS LCO 3.8.9 actions to re-energize the affected train of shared systems.

The NRC staff observed that the proposed Note is consistent with the McGuire current TS Note for the condition (i.e., existing TS 3.8.1 Condition D) in which both the offsite circuit and the DG supplying the same train of distribution systems are inoperable. Therefore, the NRC staff finds that the proposed Note for the new Condition C is acceptable since it will allow actions to be taken for the safe operation of McGuire, and it is consistent with the McGuire current TS requirement for the concurrent inoperability of a unit DG and offsite circuit.

The proposed new RA C.1 would require the performance of SR 3.8.1.1 for the required offsite circuit(s) within CT of 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. The SR 3.8.1.1 verifies the operability of a required offsite circuit. In its July 10, 2018 letter, the licensee stated that the new RA C.1 would ensure that a highly reliable power source remains operable with one required LCO 3.8.1.c offsite circuit inoperable. The licensee also stated that the CTs (i.e., 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) for the new RA C.1 is consistent with the CT for the existing RA A.1 (perform SR 3.8.1.1 for operable offsite circuit). If a required offsite circuit failed the SR 3.8.1.1, McGuire would enter the revised Condition A and/or the proposed revised Condition E, as applicable.

The NRC staff finds that the proposed new RA C.1 and associated CTs for the new Condition C are acceptable because they are consistent with the McGuire TS requirements (i.e., RA A.1 with CT) for an inoperable required offsite circuit (i.e., Condition A).

The proposed new RA C.2 states "declare NSWS, CRAVS, CRACWS or ABFVES with no offsite power available inoperable when the redundant NSWS, CRA VS, CRACWS or ABFVES is inoperable" within a CT of "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)." In its July 10, 2018 letter, the licensee stated that the new RA C.2 would provide assurance that an event coincident with a single failure of the DG that is associated with the affected train would not result in a complete loss of safety function for the NSWS, CRA VS, CRACWS or the ABFVES. The licensee stated the 24-hour CT would allow time for restoration before subjecting the unit to transients associated with shutdown, and it takes into account factors such as the component operability of the redundant counterpart to the inoperable shared system, the capacity and capability of the remaining AC sources, and a reasonable time for repairs.

The NRC staff considered how the proposed new RA C.2 and associated 24-hour CT for the new Condition C are consistent with the intent of the existing RA A.2 and associated CT for one inoperable LCO 3.8.1.a offsite circuit (revised Condition A). In addition, the proposed RA C.2 will allow McGuire to enter the applicable TS conditions and RAs for the shared systems to take appropriate actions for the safe operation of the plant. Therefore, the NRC staff finds that the proposed RA C.2 and associated CT are acceptable because they meet the intent of the McGuire current TS requirements for an inoperable required offsite circuit.

The proposed new RA C.3 requires restoring the LCO 3.8.1.c offsite circuit to operable status within a CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In its December 3, 2018 letter, the licensee stated that the proposed new RA C.3 would allow McGuire to meet the LOC 3.8.1.c to comply with 10 CFR 50.36(c)(2).

The licensee further stated that with one required LCO 3.8.1.c offsite circuit inoperable, the reliability of the offsite power is degraded and the potential for a LOOP is increased, however, the remaining operable offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1 E distribution system.

RG 1.93 recommends power operation not to exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if one TS required offsite circuit is inoperable. Thus, the NRC staff finds the proposed new RA C.3 and associated 72-hour CT acceptable since they are consistent with the recommendations of RG 1.93 and provides an acceptable remedial action to meet LCO 3.8.1.c, as required by 10 CFR 50.36(c)(2), and is, therefore, acceptable.

3.2.2.3 New Condition D The proposed new Condition D would apply when LCO 3.8.1.d DG inoperable. A new Note and new RAs D.1, D.2, D.3, D.4.1, D.4.2, D.5.1, and D.5.2 with associated CTs are proposed for the new Condition D.

The proposed Note states: "Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems - Operating," when Condition Dis entered with no AC power source to a train." In its letter dated July 10, 2018, the licensee stated that the proposed Note would allow the new Condition D to provide requirements for the loss of an LCO 3.8.1.d DG and an LCO 3.8.1.c offsite circuit without regard to whether a train is de-energized, as McGuire LCO 3.8.9 provides the appropriate restrictions for a de-energized train. In its letter dated December 3, 2018, the licensee clarified that in the case the proposed one LCO 3.8.1.d DG would be inoperable (proposed new Condition D) concurrently with one inoperable LCO 3.8.1.c offsite circuit (proposed new Condition C) associated with the same train of shared systems, the proposed Note would allow McGuire to enter the applicable TS 3.8.9 actions to re-energize the affected train of shared systems.

The NRC staff considered how the proposed Note is consistent with the McGuire current TS Note for the condition (i.e., existing TS 3.8.1 Condition D) in which both the offsite circuit and the DG supplying the same train of safety-related systems are inoperable. Therefore, the NRC staff finds that the proposed Note for the new Condition D is acceptable since it will allow actions to be taken for the safe operation of McGuire, and it is consistent with the McGuire current TS requirement for the concurrent inoperability of a unit DG and offsite circuit.

The proposed new RA D.1 would verify both LCO 3.8.1.b DGs operable within a CT of "1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter." In its December 3, 2018 letter, the licensee stated that the new RA D.1 would be an administrative verification of the operability for the LCO 3.8.1.d DG(s).

In addition, the licensee stated that the 1-hour CT would allow sufficient time to perform RA D.1 if the inoperability of the LCO 3.8.1.b DG was unplanned, and the 12-hour CT was based on the McGuire operator shifts of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The NRC staff notes that if the verification in RA D.1 would result in one or two LCO 3.8.b DG(s) being inoperable, the plant would enter either the revised Condition B and/or the renumbered Condition G, as applicable (see sections 3.1.2 and 3.1.3.6 for the staff's evaluation of the revised Condition B and the renumbered Condition G, respectively). The NRC staff finds the new RA D.1 with associated CTs acceptable since it will provide assurance that the LCO 3.8.1.b DGs can supply the safety-related equipment.

The proposed new RA D.2 would require the performance of SR 3.8.1.1 for the required offsite circuit(s) within a CT of "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." In its July 10, 2018 letter, the licensee stated that the new RA D.2 would ensure that a highly reliable power source remains with one required LCO 3.8.1.d DG inoperable. The licensee also stated that the CTs (i.e., 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) for the new RA D.2 is consistent with the CTs for the existing RA A.1 as well as the existing RA B.1 (renumbered as RA B.2) for an inoperable LCO 3.8.1.b DG. If a required offsite circuit failed the SR 3.8.1.1, McGuire would enter the revised Condition A and/or the revised Condition E, as applicable.

The NRC staff finds that the new RA D.2 and associated CTs are acceptable because they are consistent with the McGuire TS requirements (i.e., renumbered RA B.2 with CT) for an inoperable required DG.

The proposed new RA D.3 would declare NSWS, CRA VS, CRACWS or ABFVES supported by the inoperable DG inoperable when the redundant NSWS, CRA VS, CRACWS or ABFVES is inoperable within a CT of "4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of Condition E concurrent with inoperability of redundant required feature(s)."

In its July 10, 2018 letter, the licensee stated that the new RA D.3 would provide assurance that a LOOP event concurrent with the inoperability of the LCO 3.8.1.d DG does not result in a complete loss of safety function for the NSWS, CRA VS, CRACWS or the ABFVES. The licensee further stated the 24-hour CT would allow time for restoration before subjecting the unit to transients associated with shutdown, and it takes into account factors such as the capacity and capability of the affected shared system and a reasonable time for repairs.

The NRC staff notes that the proposed RA D.3 and associated 4-hour CT for the new Condition D are consistent with the intent of the existing RA B.2 (renumbered as RA B.3) and associated CT for one inoperable LCO 3.8.1.b DG (revised Condition B). In addition, the proposed RA D.3 will allow McGuire to enter the applicable conditions and RAs for the affected shared systems' TS LCO to take appropriate actions for the safe operation of the plant. Therefore, the NRC staff finds that the proposed RA D.3 and associated CT are acceptable since they meet the intent of the McGuire current TS requirements for an inoperable required DG.

The proposed new RA D.4.1 and RA D.4.2 are joined by an "OR" connector so that either one or the other would apply. The proposed new RA D.4.1 would state: "determine operable DG(s) is not inoperable due to common cause failures," within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The proposed RA D.4.2 would state "Perform SR 3.8.1.2 for OPERABLE DG(s)" within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The SR 3.8.1.2 ensures the operability of the DG(s) by verifying that each DG can start from standby conditions and achieve required steady state voltage and frequency. In its July 10, 2018 letter, the licensee stated that the new RA D.4.1 would allow McGuire to avoid unnecessary testing of the operable DGs if the cause of the inoperability of the LCO 3.8.1.d DG could be determined not to exist on the operable DGs. The licensee further stated that if the cause of the inoperability of the LCO 3.8.1.d DG could not be confirmed not to exist on the operable DG(s), then the proposed new RA D.4.2 would be performed.

The NRC staff notes that the proposed RA D.4.1 and RA D.4.2 with associated CTs for the new Condition D (one LCO 3.8.1.d DG) are consistent with the existing RA B.3.1 (renumbered as RA B.4.1) and RA B.3.2 (renumbered as RA B.4.2) for one inoperable LCO 3.8.1.b DG (revised Condition B). Therefore, the NRC staff finds that the proposed RA D.4.1 and RA D.4.2 and associated CTs are acceptable since they are consistent with the McGuire current TS requirements for verifying the operability of the remaining DGs when a required DG is inoperable.

The proposed new RA D.5.1 and RA D.5.2 are joined by an "OR" connector so that either one or the other would apply. The proposed new RA D.5.1 would state "restore LCO 3.8.1.d DG to operable status" within a CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In its December 3, 2018 letter, the licensee stated that the proposed new RA D.5.1 would allow meeting LCO 3.8.1.d,to comply with 1 O CFR 50.36(c)(2). The licensee further stated that with one required LCO 3.8.1.d DG inoperable, the remaining operable DGs and offsite power circuits are adequate to supply electrical power to the onsite Class 1 E distribution system. When one TS required DG is inoperable, RG 1.93 recommends continue power operation not to exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , provided that the redundant DG is assessed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to be free from common-cause failure or is verified to be operable in accordance with plant-specific technical specifications. The proposed RA D.4.1 will assess the operable DG(s) to be free from common-cause failure within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and the proposed RA D.4.2 will verify the operability of the remaining DG(s) within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , as recommended by RG 1.93.

The NRC notes that the proposed RA D.4.1 and RA D.4.2 will provide the prerequisite actions for 72-hour power operation in Condition D, as recommended by RG 1.93. Therefore, the NRC staff finds the proposed RA D.5.1 and associated 72-hour CT acceptable since they are consistent with the recommendations of RG 1.93 and allow the LCO 3.8.1.c to be met, as required by 10 CFR 50.36(c)(2).

The proposed new RA D.5.2 states: "align NSWS, CRA VS, CRACWA and ABFVES supported by the inoperable LCO 3.8.1.d DG to an operable DG" within a 72-hour CT. The NRC staff notes that in case the LCO 3.8.1.d would require only one opposite unit's DG, the shared systems supported by the inoperable required LCO 3.8.1.d DG would be realigned to the non-required operable LCO 3.8.1.d DG within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This will meet the LCO 3.8.1.d requirements for an operable DG and satisfy the RG 1.93 allowance for continued power operation of 72-hours. Therefore, the NRC staff finds the proposed RA D.5.2 with associated 72-hour CT acceptable since it provides an acceptable remedial action to meet LCO 3.8.1.d, as required by 10 CFR 50.36(c)(2) and is, therefore, acceptable.

3.2.2.4 Existing Condition C - Revised and Renumbered as Condition E The existing Condition C is applicable to two inoperable offsite circuits. The existing Condition C is being revised by renumbering it as Condition E, and by adding "LCO 3.8.1.a" to the existing condition statement and two new alternative conditions. The existing RA C.1 and RA C.2 are renumbered as RA E.1 and RA E.2, respectively, and "Condition C" in the existing CT for RA C.1 is renumbered as "Condition E" in the CT for renumbered RA E.1. The NRC staff finds that the renumbering of existing Condition C, RA C.1, and RA C.2 as Condition E, RA E.1, and RA E.2, respectively, is an editorial change which is consistent with the addition of proposed new Conditions to the TS, and is, therefore, acceptable.

The renumbered Condition E would have three options joined by an "OR" connector so that either one of them would apply. The first option of Condition E would state "two LCO 3.8.1.a offsite circuits inoperable." In its letter dated July 10, 2018, the licensee stated that the addition of "LCO 3.8.1.a" to the existing Condition C clarifies that the portion of the condition pertains to the qualified circuits between the offsite transmission network and the unit-specific's onsite essential auxiliary power system. The NRC staff finds that the first option of the renumbered Condition E is acceptable because adding "LCO 3.8.1.a" to specify the unit's offsite circuit is consistent with the existing Condition C. The second option of the renumbered Condition E would apply when one LCO 3.8.1.a offsite circuit that provides power to the shared systems and one LCO 3.8.1.c offsite circuit are inoperable. The third option of the renumbered Condition E would apply when two LCO 3.8.1.c offsite circuits are inoperable. In its July 10, 2018 letter, the licensee stated that the third option of the renumbered Condition E would be applicable when both trains of shared systems are aligned to receive power from the same unit.

The NRC staff notes that the second and third options of the renumbered Condition E pertain to two offsite circuits that are credited to supply power to the redundant trains of shared systems and also reflect the addition of the opposite unit LCO 3.8.1.c offsite circuits to the TS LCO 3.8.1.

Therefore, the NRC staff finds that the second and third options of the renumbered Condition E are acceptable because they satisfy the intent of the existing Condition C for two inoperable offsite circuits supplying power to redundant trains of safety systems.

3.2.2.5 Existing Condition D - Revised and Renumbered as Condition F The existing Condition D is applicable to one offsite circuit inoperable and one DG inoperable.

The existing Condition Dis revised by adding "LCO 3.8.1.a" and "LCO 3.8.1.b" to the condition.

The revised Condition D is renamed as Condition F. In addition, the existing RA D.1 and RA D.2 are renumbered as RA F.1 and RA F.2, respectively; and "Condition D" in the existing note would be renumbered as "Condition F." The NRC staff finds that the renumbering of existing Condition D, RA D.1, and RA D.2 as Condition F, RA F.1, and RA F.2, respectively, is an editorial change which is consistent with the addition of proposed new Conditions to the TS, and is, therefore, acceptable.

The renumbered Condition F states, "one LCO 3.8.1.a offsite circuit inoperable and one LCO 3.8.1.b DG inoperable." In its July 10, 2018 letter, the licensee stated that the addition of "LCO 3.8.1.a" and "LCO 3.8.1.b" to the existing Condition D clarifies that the condition pertains to a qualified circuit between the offsite transmission network and the unit-specific's onsite essential auxiliary power system and to a unit-specific DG capable of supplying the unit's onsite essential auxiliary power systems. The NRC staff finds the renumbered Condition F acceptable since adding "LCO 3.8.1.a" and "LCO 3.8.1.b" to the existing condition to specify the unit's offsite circuit and DG is consistent with the existing Condition D.

3.2.2.6 Existing Condition E - Revised and Renumbered as Condition G The existing Condition E applies to two inoperable DGs. The existing Condition E is proposed to be revised by adding "LCO 3.8.1.b" to existing condition statement and two new alternative conditions. The revised Condition Eis renamed as Condition G. In addition, the existing RA E.1 (restore one DG to operable status) is renumbered as RA G.1. The NRC staff finds that the change existing Condition E and RA E.1 as Condition G and RA G.1, respectively, is an editorial change which is consistent with the addition of proposed new Conditions to the TS, and is, therefore, acceptable.

The renumbered Condition G would have three options joined by an "OR" connector so that either one of them would apply. The first option would state "two LCO 3.8.1.b DGs inoperable."

In its July 10, 2018 letter, the licensee stated that the addition of the "LCO 3.8.1.b" to the existing Condition E clarifies that the condition pertains to the unit-specific emergency DGs.

The TS requirement to restore one DG to operable status (renumbered RA G.1) within 2-hour CT remains unchanged. The NRC staff finds the first option of the renumbered Condition G acceptable since adding "LCO 3.8.1.b" to specify the unit's DG is consistent with the existing Condition E. The second option of the renumbered Condition G would apply when one LCO 3.8.1.b DG that provides power to the shared systems and one LCO 3.8.1.d DG are inoperable.

The third option of the renumbered Condition G would state "two LCO 3.8.1.d DGs inoperable."

In its July 10, 2018 letter, the licensee stated that the third option would be applicable when both trains of shared systems would be aligned to receive power from the same unit.

Since the second and third options of the renumbered Condition G pertain to two DGs that are credited to supply power to the trains of shared systems, the NRC staff finds that the second and third options for the renumbered Condition G satisfy the intent of the existing Condition E for two inoperable DGs, and are, therefore, acceptable.

The renumbered RA G.1 to restore one DG to operable status within a 2-hour CT would also apply to the second and third options of the renumbered Condition G. According to RG 1.93, power operation may continue for a period that should not exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months if two required onsite AC power sources that supply power to redundant trains of safety systems are not available.

Within these 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , one or both onsite AC power source(s) may be restored.

Since the second and third options of the renumbered Condition G address the inoperability of two DGs that supply power to the redundant trains of shared systems, the NRC staff finds that the RA G.1 (restore one DG to operable status) and associated 2-hour CT are consistent with RG 1.93 and are, therefore, acceptable.

3.2.2.7 Existing Condition F - Renumbered as Condition H The existing Condition F applies when one automatic load sequencer is inoperable. The existing Condition F and RA F.1 are renumbered as Condition Hand RA H.1, respectively. The NRC staff finds that the renumbering of existing Condition F and RA H.1 as Condition H and RA H.1 is an editorial change which is consistent with the addition of proposed new Conditions to the TS, and is, therefore, acceptable.

3.2.2.8 Existing Condition G - Revised and Renumbered as Condition I The existing Condition G applies when the RA and associated CT of Condition A, 8, C, D, E, or F are not met. The existing Condition G is revised by modifying the list of conditions in the statement and adding two new alternative conditions. The revised Condition G is renamed as Condition I. In addition, the existing RA G.1 and RA G.2 would be renumbered as RA 1.1 and RA 1.2, respectively. The requirements in RA 1.1 and RA 1.2 and associated CTs remain unchanged. The NRC staff finds that the change of existing Condition G, RA G.1, and RA G.2 as Condition I, RA 1.1, and RA 1.2, respectively, is an editorial change which is consistent with the addition of proposed new Conditions to the TS, and is, therefore, acceptable.

The renumbered Condition I would have three options joined by an "OR" connector so that either one of them would apply. The first option of the renumbered Condition I would apply when the RA and associated CT of Condition A (revised), C (new), E (revised Condition C), F (revised Condition D), G (revised Condition E), or H (existing Condition F) are not met. The second option of Condition I would state "Required Action and associated Completion Time of Required Action 8.2, 8.3, 8.4.1, 8.4.2, or 8.6 not met." The third option of the renumbered Condition I would state "Required Action and associated Completion Time of Required Action RA D.2, D.3, D.4.1, D.4.2, D.5.1, or D.5.2 not met."

In any of the above mentioned three options of the renumbered Condition I, if an RA and associated CT (except RA 8.1, RA 8.5, and RA D.1) would not be met, the renumbered RA 1.1 and RA 1.2 would require that the unit be brought to mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and mode 5 in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months , respectively. According to McGuire TS LCO 3.0.3, ifan LCO and associated actions are not met, the unit shall be placed in a mode or other specified condition in which the LCO is not applicable, and action shall be initiated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to place the unit, as applicable, in mode 3 within 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months and in mode 5 within 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months .

The NRC staff notes that when an RA and CT in the renumbered Condition I were not met, the LCO 3.8.1 would not be met. Since the LCO 3.8.1 and associated actions in the renumbered Condition I will not be met and the LCO 3.8.1 is applicable in Mode 1-4, the NRC staff finds that placing the unit in Mode 3 (RA 1.1) in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in Mode 5 (RA 1.2) in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months is consistent with the McGuire TS LCO 3.0.3 requirements. Therefore, the NRC staff finds that the renumbered Condition I and associated RA 1.1, RA 1.2, and CTs are acceptable since they will allow the affected unit to be place in safe shutdown conditions when the inoperable AC power sources cannot be restored within the required CTs.

The NRC staff notes that the new RA 8.1 (verify LCO 3.8.1.d DG(s) operable), new RA 8.5 (evaluate availability of ESPS), and new RA D.1 (verify both LCO 3.8.1.b DGs operable) with their respective associated CTs are not included in the renumbered Condition I. If one LCO 3.8.1.d DG or one LCO 3.8.1.b DG is found inoperable per RA 8.1 or RA D.1, respectively, the affected McGuire unit would enter applicable Conditions (i.e., new Condition D, revised Condition 8, and renumbered Condition G) to restore the inoperable DGs to operable status within the most limiting CT to meet the RA B.1 or RA D.1. Since the proposed TS include Conditions that will apply when RA B.1 or RA D.1 and associated CTs are not met, the NRC staff finds that excluding RA B.1 and RA D.1 from the renumbered Condition I is acceptable.

Furthermore, if RA B.5 and associated CT are not met (i.e., ESPS is unavailable), actions would be taken to restore the affected DG within the applicable CT of RA B.6. The unavailability of the ESPS only impacts the required CT for restoring the LCO 3.8.1.b DG to operable status, and not the operability requirements of LCO 3.8.1.b DG. Thus, since the failure to meet RA B.5 and associated CT would not be failure to meet the LCO 3.8.1.b, the NRC staff finds that excluding the RA B.5 and associated CT from the renumbered Condition I is acceptable.

3.2.2.9 Existing Condition H - Revised and Renumbered as Condition J The existing Condition H applies to three or more AC sources inoperable. The existing Condition H is revised by adding "LCO 3.8.1.a and LCO 3.8.1.b" to the existing condition statement and one new alternate condition. The revised Condition His renamed as Condition J.

In addition, the existing RA H.1 (enter LCO 3.0.3) would be renumbered as RA J.1. The NRC staff finds that the change of existing Condition H and RA H.1 as Condition J and RA J.1, respectively, is an editorial change and is, therefore, acceptable.

The renumbered Condition J would have two options. The first option of the renumbered Condition J would state "three or more LCO 3.8.1.a and LCO 3.8.1.b AC sources inoperable."

In its July 10, 2018 letter, the licensee stated that the addition of "LCO 3.8.1.a and LCO 3.8.1.b" to the existing Condition H statement clarifies that the condition would correspond to a level of degradation in which all redundancy in the unit-specific AC electrical power supplies (i.e.,

LCO 3.8.1.a and LCO 3.8.1.b) would be lost. Since the existing Condition H applies to the unit-specific AC power sources, the NRC staff finds that adding "LCO 3.8.1.a and LCO 3.8.1.b" to the existing Condition H does not change the intent of the condition. Therefore, the NRC staff finds the first option of the renumbered Condition J acceptable since the first option is consistent with the existing Condition H.

The second option of the renumbered Condition J states "Three or more LCO 3.8.1.c and LCO 3.8.1.d AC sources inoperable." In this condition, the RA J.1 (enter LCO 3.0.3) would be implemented immediately to shut down the plant. In its July 10, 2018 letter, the licensee stated that the second option of the renumbered Condition J would correspond to a level of degradation in which all redundancy in LCO 3.8.1.c and LCO 3.8.1.d AC electrical power supplies would be lost. The NRC staff notes that this condition could entail the loss of all power to both trains of shared systems in case of failure of the remaining operable LCO 3.8.1.c offsite circuit or LCO 3.8.1.d DG. Thus, it will be reasonable to enter LCO 3.0.3 to commence an orderly shutdown to place the affected unit in a safe shutdown condition. In addition, the RA to enter LCO 3.0.3 immediately for this condition are consistent with the McGuire current TS requirements to enter LCO 3.0.3 for three or more AC power sources inoperable (existing Condition H). Therefore, the NRC staff finds that the second option for the renumbered Condition J and associated RA J.1 and CT are acceptable because they satisfy the intent of the existing Condition H for three or more inoperable AC power sources.

3.2.3 Licensee Regulatory Commitments In its letter dated March 7, 2019, the licensee provided the following Regulatory Commitments (which superseded the commitments made in previous letters):

TYPE SCHEDULED COMMITMENT One-Continuing COMPLETION time Compliance DATE

1. The preplanned diesel generator (DG)

X Prior to maintenance will not be scheduled if severe implementing weather conditions are anticipated. Weather the approved conditions will be evaluated prior to intentionally Technical entering the extended DG Completion Time (CT)

Specification and will not be entered if its official weather 3.8.1 diesel forecasts are predicting severe weather conditions generator (i.e., thunderstorm, tornado or hurricane warnings).

Completion Operators will monitor weather forecasts each shift Time during the extended DG CT. If severe weather or extension.

grid instability is expected after a DG outage begins, station managers will access the conditions and determine the best course for returning the DG to operable status.

2. Component testing or maintenance of safety X

Prior to systems and importance non-safety equipment in implementing the offsite power systems that can increase the the approved likelihood of a plant transient (unit trip) of loss of Technical offsite power (LOOP) will be avoided during the Specification extended DG CT.

3.8.1 diesel generator Completion Time extension.

3. No discretionary switchyard maintenance will be X

Prior to performed during the extended DG CT.

implementing the approved Technical Specification 3.8.1 diesel generator Completion Time extension.

4. [This regulatory commitment was escalated to an obligation by the licensee via a license condition (see section 2.2.b of this safety evaluation).]

5. During the extended DG CT, the Emergency X

Prior to Supplemental Power Source (ESPS) will be implementing routinely monitored during operator rounds, with the approved monitoring criteria identified in the operator rounds.

Technical The ESPS will be monitored for fire hazards during Specification operator rounds.

3.8.1 diesel generator Completion Time extension.

TYPE SCHEDULED COMMITMENT One-Continuing COMPLETION time Compliance DATE

6. Licensing Operators and Auxiliary Operator will be X

Prior to trained on the purpose and use of the ESPS and implementing the revised emergency procedures (EP) actions.

the approved Personnel performing maintenance on the ESPS Technical will be trained.

Specification 3.8.1 diesel generator Completion Time extension.

7. The system load dispatcher will be contacted once X

Prior to per day to ensure no significant grid perturbations implementing (high grill loading unable to withstand a single the approved contingency of line or generation outage) are Technical expected during the extended DG CT.

Specification 3.8.1 diesel generator Completion Time extension.

8. TS required systems, subsystems, trains, X

Prior to components and devices that depend on the implementing remaining power source will be verified to be the approved operable and positive measures will be provided to Technical preclude subsequent testing or maintenance Specification activities on these systems, subsystems, trains, 3.8.1 diesel components and devices during the extended DG generator CT.

Completion Time extension.

9. Prior to entering the extended CT for an operable X

Prior to DG on one unit, when both units are in the TS 3.8.1 implementing Modes of APPLICABILITY, the station will ensure the approved that the shared systems are powered by an Technical operable Class 1 E AC Distribution Systems with an Specification operable CG, from opposite units.

3.8.1 diesel generator Completion Time extension.

10. [This regulatory commitment was escalated to an obligation by the licensee via a license condition (see section 2.2.b of this safety evaluation).]

The NRC staff concludes that these commitments are consistent with the NRC staffs position in BTP 8-8, which are expected to ensure maintenance of defense-in-depth during an extended CT. With the exception of Commitments 4 and 10, which were elevated to obligations via license conditions, the staff did not rely on these commitments to develop a conclusion about the acceptability of the proposed changes. Commitments 4 and 10 are no longer regulatory commitments and cannot be changed in the future by the licensee's commitment management program.

3.2.4 BTP 8-8 Considerations Summary The NRC staff reviewed the proposed changes to McGuire TS 3.8.1, "AC Sources - Operating,"

to extend the CT for one inoperable DG from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days based on the availability of the ESPS against the guidance in the BTP 8-8. The NRC staff also reviewed the proposed TS 3.8.1 actions for inoperable AC power sources required to supply power to the McGuire shared systems.

The NRC staff finds that McGuire's use of the ESPS during maintenance of one safety-related DG meets the NRC staff's position in BTP 8-8 since the ESPS provides an acceptable supplemental power source to the inoperable DG during the extended CT. The NRC staff also finds that the proposed remedial actions to meet the LCO 3.8.1 provide reasonable assurance that the activities as authorized (e.g., the longer CTs) will not endanger the health and safety of the public. Therefore, the NRC staff concludes that the proposed McGuire TS changes are acceptable because they provide acceptable remedial actions that allow McGuire to restore inoperable AC power sources within acceptable times to meet TS LCO 3.8.1, as required by 10 CFR 50.36(c)(2) to ensure when a LCO of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

3.3 Risk-Informed Considerations 3.3.1 Method of Review The LAR states the change in risk associated with the proposed TS CT extension of the emergency DG (EDG) was evaluated in accordance with the guidance of RG 1.177 and RG 1.17 4. Regulatory Guide 1.177 describes a risk-informed approach, acceptable to the NRC, for assessing proposed changes to TS CTs, which is based on meeting the following five key principles outlined in RG 1.17 4:

1.

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

2.

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

3.

The proposed licensing basis change maintains sufficient safety margins.

4.

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

5.

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

The last two key principles are centered on risk considerations and are evaluated below; whereas, the first three key principles focus on "traditional engineering" considerations and are summarized, as follows:

Key Principle 1 - Compliance with Current Regulations The NRC staff finds that the proposed TS change meets the requirements as stated in RG 1.177 and BTP 8-8. The NRC staff also reviewed whether the proposed TS changes will have any impact on the licensee's compliance 10 CFR 50.36(c)(2), to ensure when a LCO of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met. The NRC staff did not find any adverse impact on continued compliance with 10 CFR 50.36(c)(2). See Sections 3.2 and 3.3 of this safety evaluation for detailed discussions.

Key Principle 2 - Defense-in-Depth The licensee proposed a supplemental AC power source, ESPS, as a defense-in-depth measure to be consistent with BTP 8-8. See Section 3.3 of this safety evaluation for detailed discussions.

Key Principle 3 - Safety Margins In its letter dated May 2, 2017, the licensee stated, "The design and operation of the[... ] MNS DGs is not altered by the proposed CT extension or implementation of the ESPS modifications.

Redundancy and diversity of the electrical distribution system will be maintained." The licensee further stated, "The safety analyses acceptance criteria stated in the [... ] MNS UFSARs are not impacted by the proposed changes. The proposed changes will not allow plant operation in a configuration outside the design bases. The requirements regarding the DGs credited in the [... ]

MNS accident analyses will remain the same."

Since there are no changes in the design or operation of the DGs and the requirements for the DGs credited in accident analyses are not impacted, the NRC staff finds that the proposed TS changes will continue to meet the principle that safety-margins are maintained as discussed in Section 2.2.2 of RG 1.177.

3.3.2 Key Principle 4 (Proposed Increases in Risk are Small and Consistent with the Commission's Policy Statement on Safety Goals for the Operation of Nuclear Power Plants)

Regulatory Guide 1.177 addresses Key Principle 4 through a three-tiered approach for evaluating risk associated with proposed changes to TS CTs:

In Tier 1, the licensee should assess the impact of the proposed TS change on CDF, ICCDP, LERF, and ICLERP. To support this assessment, two aspects need to be considered: ( 1) the validity of the PRA and (2) the PRA insights and findings. The licensee should demonstrate that its PRA is valid for assessing the proposed TS changes and identify the impact of the TS change on plant risk.

In Tier 2, the licensee should provide reasonable assurance that risk-significant plant equipment outage configurations will not ccur when specific plant equipment is out of service consistent with the proposed TS change.

In Tier 3, the licensee program for compliance with 10 CFR 50.65(a)(4) ensures that the risk impact of out of service equipment is appropriately assessed and managed. To support TS changes, a viable program would be one able to uncover risk-significant plant equipment outage configurations in a timely manner during normal plant operation.

The NRC staff's assessment of the LAR, as supplemented, regarding Tier 1, Tier 2, and Tier 3 is presented in SE Sections 3.4.2.1, 3.4.2.2, and 3.4.2.3, respectively.

3.3.2.1 Tier 1 Evaluation (Risk Impact)

In accordance with Tier 1 outlined in RG 1.177, the licensee should evaluate the change in risk resulting from the proposed TS CT changes as represented by the f1CDF, ICCDP, f1LERF, and ICLERP. As part of this evaluation, the licensee should demonstrate that its PRA (or its qualitative analyses, bounding analyses, detailed analyses, or compensatory measures if a PRA of sufficient scope is not available) is acceptable for assessing the proposed TS CT changes.

Also, uncertainties should be appropriately considered in the analyses and interpretation of findings. This applies to Tier 1, as well as Tier 2 and Tier 3 to the extent that risk insights are used. The sections that follow present the NRC staff's assessment of the LAR, as supplemented, regarding:

PRA acceptability (SE Section 3.4.2.1.1 ),

PRA results and insights (SE Section 3.4.2.1.2), and PRA sensitivity and uncertainty analyses (SE Section 3.4.2.1.3).

3.3.2.1.1 PRA Acceptability and Completeness Uncertainty In accordance with Regulatory Position C.2.3 of RG 1.17 4, acceptability of the PRA analysis used to support an application is measured with respect to: (1) scope, (2) conformance with the technical elements, (3) level of detail, and (4) plant representation. These aspects of the PRA are to be commensurate with its intended use and the role the PRA results play in the integrated decision process. The more emphasis put on the risk insights and on PRA results in the decisionmaking process, the more requirements placed on the PRA in terms of both scope and how well the risk and the change in risk are assessed. Conversely, emphasis on the various aspects of the PRA can be reduced if a proposed change to the licensing basis results in a risk decrease or a very small change, or if the decision can be based mostly on traditional engineering arguments, or if compensating measures are proposed such that it can be convincingly argued the change is very small.

The sections that follow present the NRC staff's assessment of acceptability of the licensee's PRA (i.e., internal events, internal flooding, high winds, and fire PRAs), quantitative seismic analysis, and qualitative analyses of other external hazards relative to the four aspects of PRA:

Scope of PRA (SE Section 3.4.2.1.1.1)

Conformance of PRA with the technical elements, and acceptability of seismic and other external hazard analyses (SE Section 3.4.2.1.1.2)

Level of detail in PRA (SE Section 3.4.2.1.1.3)

Plant representation in PRA (SE Section 3.4.2.1.1.4)

These aspects of the PRA also address completeness uncertainty as discussed in NUREG-1855, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making" (March 2017) (Reference 21 ).

3.3.2.1.1.1 Scope of the PRA Regulatory Position C.2.3.2 of RG 1.177 states, the licensee should perform evaluations of core damage frequency (CDF) and large early release frequency (LERF) to support any risk-informed changes to TS. The scope of the PRA should include all hazard groups (i.e., internal events, internal flooding, high winds, fires, seismic events, and other external hazards) unless it can be shown the contribution from specific hazard groups does not affect the decision. In some cases, a PRA of sufficient scope may not be available. This will have to be compensated for by qualitative arguments, bounding analyses, or compensatory measures.

Based on the LAR, as supplemented by letters dated July 20, 2017, July 10, 2018, December 3, 2018, and March 7, 2019, the change in risk (i.e., ~CDF, ~LERF, ICCDP, and ICLERP) resulting from the proposed TS CT extension of the EDG (hereafter, "14-day CT" or "proposed TS CT change") is estimated utilizing PRAs for at-power internal events, internal flooding, high winds, and fire. A conservative quantitative seismic analysis was used to estimate the risk increase for seismic events. For other external hazards, qualitative assessments were used to screen these events from further consideration.

The PRAs for internal events, internal flooding, and high winds do not discern between units (i.e., for each hazard, a single unit PRA is assumed to represent both Unit 1 and Unit 2).

Therefore, the risk results for these hazards reported in the LAR, as supplemented, are unchanged across units. The response to RAI 18, dated December 3, 2018, provides a qualitative assessment demonstrating the single unit PRAs are representative of both units, because: (1) structures, systems and components (SSCs) that are shared between both units are modeled in the single unit PRAs, (2) there is a high level of symmetry between the units (e.g., similar SSC design and operation, spatial configuration, procedures, TS), and (3) the few identified differences between units were either accounted for in the single unit PRAs or would not impact the conclusions of the LAR.

The NRC staff finds use of single unit PRAs for internal events, internal flooding, and high winds is acceptable for this LAR because these PRAs are representative of both units.

Based on the review of the LAR, as supplemented, the NRC staff finds that, when compared to the regulatory positions contained in RGs 1.17 4 and 1.177, the licensee's risk assessment is of sufficient scope for use in this specific risk-informed application.

3.3.2.1.1.2 Conformance of PRA with the Technical Elements, and Acceptability of Seismic and Other External Hazard Analyses Regulatory Guide 1.200 endorses, with clarifications and qualifications, the use of the American Society of Mechanical Engineers/American Nuclear Society (ASME/ANS) PRA standard ASME/ANS RA-Sa-2009, "Addenda to ASME/ANS RA-S-2008, "Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications" (Reference 22). ASME/ANS RA-Sa-2009 is the industry consensus standard for PRAs for internal events, internal flooding, fires, and other external events (i.e., seismic, external flooding, high winds, and so on), and defines the technical elements needed to develop and quantify a PRA model. ASME/ANS RA-Sa-2009 provides technical supporting requirements (SRs) for each technical element in terms of "capability categories" (CCs). The CCs increase from a lower to a higher number (i.e., CC I, II, 111) depending on the degree of detail, plant specificity, and realism. In general, the NRC staff anticipates that current good practice (i.e., meeting CC II for the SRs in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200) is acceptable for most applications. However, for some applications, meeting a lower capability category may be sufficient for some requirements; for other applications, it may be necessary to meet a higher capability category for specific requirements.

The licensee should address conformance of the PRA with the technical elements of ASME/ANS RA-Sa-2009 by following the peer review and self-assessment processes in RG 1.200. In accordance with Regulatory Position C.2 of RG 1.200, the PRA should be peer reviewed according to an established process to determine whether the intent of the SRs and technical elements in the ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, have been met.

In addition, the peer review determines whether:

The methods used to develop the PRA are implemented correctly, The PRA represents the as-built and as-operated plant, The PRA assumptions and approximations are reasonable, and The licensee has procedures or guidelines in place for updating the PRA to reflect changes in plant design, operation, or experience.

The peer review identifies any issues or discrepancies (i.e., finding-level facts and observations (F&Os)) that impact conformance with the technical elements. Appendix X to Nuclear Energy Institute (NEI) 05-04/07-12/12-[13], "Close-Out of Facts and Observations (F&Os)" (hereafter, "NEI Appendix X") (Reference 23), as accepted with conditions by NRC letter dated May 3, 2017 (Reference 24), provides guidance for closing F&Os. The NEI Appendix X states in part,

"[o]nce an F&O is closed out, the utility is not required to present and explain them in peer reviews, NRC submittals, or other requests excluding NRC audits." The May 3, 2017 letter also states in part, "[t]he NRC also intends to periodically conduct audits of a licensee's implementation of the Appendix X F&O closure process, as well as review a sampling of the final independent assessment team reports."

The following present NRC staff's assessment of the internal events, internal flooding, high winds and fire PRAs and their conformance with the technical elements in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, for use in supporting this risk-informed application.

Also, the NRC staff's assessment of the quantitative seismic analysis and qualitative assessments for other external hazards are discussed.

Internal Events PRA (excluding LERF)

Section 6.1.3 of LAR Attachment 6 addresses acceptability of the non-LERF portion of the McGuire internal events PRA (IEPRA(non-LERF)). The IEPRA(non-LERF) received a full-scope peer review in June 2015 using the process defined in NEI 05-04, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard, Revision 2" (Reference 25). This peer review was performed against the applicable high-level requirements (HLRs) and SRs (excluding LERF) of ASME/ANS RA-Sa-2009 and RG 1.200, Revision 2. The PRA peer review resulted in a number of F&Os.

LAR Section 6.1.3, as supplemented by letter dated July 20, 2017, discusses the closure of the IEPRA(non-LERF) F&Os. In January 2016, an independent assessment of the IEPRA (non-LERF) F&Os was performed to determine whether the F&Os were resolved and the corresponding SRs are met at CC II or greater. However, this assessment was performed prior to NRC acceptance of NEI Appendix X on May 3, 2017. Upon NRC acceptance of NEI Appendix X, the licensee identified a deficiency between the 2016 independent assessment and NEI Appendix X (letter dated October 20, 2016 - Reference 26), as accepted by NRC letter dated May 3, 2017, where the 2016 assessment did not identify whether the F&O resolutions were PRA maintenance or PRA upgrades. To resolve this deficiency and meet the NEI Appendix X requirements, the same individuals who performed the 2016 independent assessment performed a second independent assessment in May 2017. The 2017 independent assessment included a review of whether each F&O resolution constituted a PRA maintenance or PRA upgrade, and an assessment of how each requirement of NEI Appendix X, as accepted by NRC, was met by the combined independent assessments in 2016 and 2017. The scope of the 2016 and 2017 independent assessments included all finding-level F&Os associated with the IEPRA(non-LERF), including those finding-level F&Os associated with SRs that were met at CC II. As a result, the licensee closed all but three IEPRA(non-LERF) finding-level F&Os. All changes made to the IEPRA(non-LERF) since the peer review in 2015, including those to resolve F&Os, were PRA maintenance; therefore, no subsequent peer review was required.

The three IEPRA(non-LERF) finding-level F&Os that remain open were included in the submittal.

Section 8.2 of LAR Attachment 8 provides the three IEPRA(non-LERF) finding-level F&Os that remain open after the 2017 independent assessment, and the licensee's disposition to these F&Os. Each F&O was dispositioned by either providing a description of how the F&O was resolved or providing an assessment of the impact of the F&O resolution on the LAR results.

The NRC staff evaluated each open F&O and the licensee's disposition to determine whether the F&O had any significant impact on the application. The NRC staff finds, with the exception of F&O 2-7 in LAR Attachment 8, the open IEPRA(non-LERF) F&Os were properly assessed and dispositioned to support the proposed TS CT change.

The NRC staff requested additional information to clarify the licensee's disposition of F&O 2-7.

F&O 2-7 states only one system alignment was modeled for most systems included in the internal events PRA. Whereas SR SY-AS of ASME/ANS RA-Sa-2009 requires both the normal and alternate alignments be modelled to the extent needed for CDF and LERF determinations.

This F&O impacts not only the IEPRA, but also impacts the fire PRA (FPRA), internal flooding PRA (IFPRA), and high winds PRA (HWPRA), because these PRAs are based on the IEPRA model.

The supplements dated July 10, 2018 and December 3, 2018 (in response to RAls 12 and 13),

addressed the risk impact of the single alignment PRA assumption. The licensee assessed the impact of system asymmetry for 23 systems (which were considered important to the proposed TS CT change or appear to be risk-significant based on the LAR risk insights) and identified four systems as having modeling asymmetries that could potentially challenge the validity of the single alignment assumption and impact the risk results. The licensee provided results of a sensitivity study to assess the impact on risk from modeling asymmetries (i.e., alternate alignments) of these four systems. This sensitivity study also modified the PRA to more realistically credit Train B of NSWS for non-seismic events where Train B remains aligned to Lake Norman; therefore, eliminating invalid failure combinations for NSWS Train B. For each hazard, risk values (i.e., ICCDP, ICLERP, ~CDF, and ~LERF) were calculated for various alignment configurations of the four systems. Based on these sensitivity results, the difference in risk between the more limiting configuration (i.e., that which resulted in the largest risk) and the less limiting configuration (i.e., that which resulted in the smallest risk) is small (i.e., the difference in total risk for all hazards ranged from 1 % to 4% ). Also, the aggregate risk results associated with the proposed TS CT change, which are compared to the risk acceptance guidelines in RG 1.177 and RG 1.17 4 ( see SE Section 3.4.2.1.2), are based on the more limiting alignment configuration for each hazard.

The NRC staff finds the issue of alternate alignments resolved for this application, because the licensee provided the results of a sensitivity study that showed the impact on risk of modeling alternate alignments to be small and the risk results associated with the proposed TS CT change are based on the more limiting configuration.

The LAR, as supplemented by letters dated July 10, 2018 and December 3, 2018 (in response to RAI 14 ), describes the failure rates used in the PRA for the EDGs. The licensee clarified the EOG failure rates are based on 2010 industry generic values in NUREG/CR-6928, "Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants" (2015 update) (Reference 27) that were Bayesian updated with plant-specific data. The EOG failure rates were consistently applied across the different hazard models. The response to RAI 14 states the EOG common cause failure (CCF) probabilities used in the FPRA model were appropriately updated to be consistent with that used in the other hazard PRAs.

The NRC staff finds the EOG failure probabilities used in the risk evaluation of the proposed TS CT change is acceptable, because the EOG failure rates were developed and applied consistent with ASME/ANS RA-Sa-2009, as endorsed by RG 1.200.

Based on the above, conformance of the internal events PRA (excluding LERF) to the applicable technical elements in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, is acceptable to the extent needed to support this application.

LERF Portion of Internal Events PRA Section 6.1.3 of LAR Attachment 6 addresses acceptability of the LERF portion of the McGuire internal events PRA (IEPRA(LERF)). The IEPRA(LERF) received a full-scope peer review in December 2012. This peer review was performed against the applicable HLRs and SRs of ASME/ANS RA-Sa-2009 and RG 1.200, Revision 2. The PRA peer review resulted in a number of F&Os.

LAR Section 6.1.3, as supplemented by letter dated July 20, 2017, discusses the closure of the IEPRA(LERF) F&Os. In June 2015, an independent assessment of the IEPRA{LERF) F&Os was performed to determine whether the F&Os were resolved. However, this assessment was performed prior to NRC acceptance of NEI Appendix X on May 3, 2017. Upon NRC acceptance of NEI Appendix X, the licensee identified a deficiency between the 2015 independent assessment and NEI Appendix X, as accepted by NRC letter dated May 3, 2017, where the 2015 assessment did not identify whether the F&O resolutions were PRA maintenance or PRA upgrades. To resolve this deficiency and meet the NEI Appendix X requirements, the same individuals who performed the 2015 independent assessment performed a second independent assessment in May 2017. The 2017 independent assessment included a review of whether each F&O resolution constituted a PRA maintenance or PRA upgrade, and an assessment of how each requirement of NEI Appendix X, as accepted by NRC, was met by the combined independent assessments in 2015 and 2017. The scope of the 2015 and 2017 independent assessments included all finding-level F&Os associated with the IEPRA(LERF), including those finding-level F&Os associated with SRs that were met at CC II. Because of this closure review, eight IEPRA(LERF) SRs were assessed at meeting CC I. All changes made to the IEPRA (LERF) since the peer review in 2012, including those to resolve F&Os, were PRA maintenance; therefore, no subsequent peer review was required.

Section 8.4 of LAR Attachment 8 provides the eight SRs assessed as meeting CC I and provides justification for each that CC I does not change the conclusions of the LAR. The NRC staff evaluated the licensee's justification for each of these SRs and found them to be reasonable to support the proposed TS CT change.

Based on the above, conformance of the LERF portion of the internal events PRA to the applicable technical elements in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, is acceptable to the extent needed to support this application.

Internal Flooding PRA Section 6.1.3 of LAR Attachment 6 addresses acceptability of the McGuire IFPRA. The IFPRA received a full-scope peer review in September 2011. This peer review was performed against the applicable HLRs and SRs of ASME/ANS RA-Sa-2009 and RG 1.200, Revision 2. The PRA peer review resulted in a number of F&Os.

LAR Section 6.1.3, as supplemented by letter dated July 20, 2017, discusses the closure of the IFPRA F&Os. In June 2015, an independent assessment of the IFPRA F&Os was performed to determine whether the F&Os were resolved and the corresponding SRs are met at CC II or greater. However, this assessment was performed prior to NRC acceptance of NEI Appendix X on May 3, 2017. Upon NRC acceptance of NEI Appendix X, the licensee identified a deficiency between the 2015 independent assessment and NEI Appendix X, as accepted by NRC letter dated May 3, 2017, where the 2015 assessment did not identify whether the F&O resolutions were PRA maintenance or PRA upgrades. To resolve this deficiency and meet the NEI Appendix X requirements, the same individuals who performed the 2015 independent assessment performed a second independent assessment in May 2017. The 2017 independent assessment included a review of whether each F&O resolution constituted a PRA maintenance or PRA upgrade, and an assessment of how each requirement of NEI Appendix X, as accepted by NRC, was met by the combined independent assessments in 2015 and 2017. The scope of the 2015 and 2017 independent assessments included all finding-level F&Os associated with the IFPRA, including those finding-level F&Os associated with SRs that were met at CC II. As a result, the licensee closed all but two IFPRA finding-level F&Os. All changes made to the IFPRA since the peer review in 2011, including those to resolve F&Os, were PRA maintenance; therefore, no subsequent peer review was required. The two open IFPRA finding-level F&Os were included in the submittal.

Section 8.6 of LAR Attachment 8 provides two IFPRA finding-level F&Os that remain open after the 2017 independent assessment and the licensee's disposition to these F&Os. Each F&O was dispositioned by either providing a description of how the F&O was resolved or providing an assessment of the impact of the F&O resolution on the LAR results.

The NRC staff evaluated each open F&O and the licensee's disposition to determine whether the F&O had any significant impact on the application. The NRC staff finds the open IFPRA F&Os were properly assessed and dispositioned to support the proposed TS CT change.

Based on the above, conformance of the internal flooding PRA to the applicable technical elements in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, is acceptable to the extent needed to support this application.

High Winds PRA Section 6.1.3 of LAR Attachment 6 addresses acceptability of the McGuire HWPRA. The HWPRA received a full-scope peer review in October 2014. This peer review was performed against the applicable HLRs and SRs of ASME/ANS RA-Sb-2013, "Addenda to ASME/ANS RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," dated September 30, 2013, and RG 1.200, Revision 2.

The peer review resulted in eight finding-level F&Os. NRC does not endorse ASME/ANS RA-Sb-2013. In response to RAI 03, associated with the NRC staff's review of the LAR to extend certain containment leak rate test frequencies at McGuire (letter dated December 12, 2017 - Reference 28), the licensee provided the results of an assessment of the differences between ASME/ANS RA-Sa-2009 and ASME/ANS RA-Sb-2013, which concluded there were no substantive differences between the two standards for HWPRA.

Based on the licensee's determination that there were no substantive differences between ASME/ANS RA-Sa-2009 and ASME/ANS RA-Sb-2013, the NRC staff concludes the licensee's peer review of the high winds PRA is acceptable.

Section 8.8 of LAR Attachment 8 provides the eight HWPRA finding-level F&Os that remain open after the 2014 peer review, and the licensee's disposition to these F&Os. Each F&O was dispositioned by either providing a description of how the F&O was resolved or providing an assessment of the impact of the F&O resolution on the LAR results.

The NRC staff evaluated each open F&O and the licensee's disposition to determine whether the F&O had any significant impact on the application. The NRC staff finds the open HWPRA F&Os were properly assessed and dispositioned to support the proposed TS CT change.

The IEPRA model used in this application is Revision 4 of the model of record (MOR). The response to RAI 20, dated December 3, 2018, clarifies the HWPRA model used in this application utilized Revision 4 of the internal events MOR. Because the HWPRA model utilized the most current internal events MOR, the NRC staff concludes the HWPRA represents the as-built, as-operated plant in accordance with RG 1.200.

Based on the above, conformance of the high winds PRA to the applicable technical elements in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, is acceptable to the extent needed to support this application.

Fire PRA Section 6.1.3 of LAR Attachment 6 addresses acceptability of the McGuire FPRA. The FPRA received a full-scope peer review in September 2009 using the process defined in NEI 07-12, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines, Revision O" (Reference 29). This peer review was performed against the applicable HLRs and SRs of ASME/ANS RA-Sa-2009 and RG 1.200, Revision 2. The FPRA peer review resulted in a number of finding-level F&Os and SRs meeting CC I.

Section 8.1 O of LAR Attachment 8 provides twenty-two FPRA finding-level F&Os that remain open after the 2009 peer review, the licensee's disposition to these F&Os, and justification for twelve SRs that meeting CC I does not impact the conclusions of the LAR. Each F&O was dispositioned by either providing a description of how the F&O was resolved or providing* an assessment of the impact of the F&O resolution on the LAR results.

The NRC staff evaluated each F&O and the licensee's disposition to determine whether the F&O had any significant impact on the application. The NRC staff finds the FPRA F&Os were properly assessed and dispositioned to support the proposed TS CT change. The NRC staff also reviewed the licensee's justification for each SR met at CC I and found these justifications to be reasonable to support the acceptability of the FPRA. In addition, the NRC staff reviewed the safety evaluation associated with the McGuire LAR to transition to National Fire Protection Association Standard 805 (NFPA 805), dated December 6, 2016 (Reference 30), and identified no issues related to the technical acceptability of the FPRA that could impact this application.

In its supplement dated July 10, 2018, the licensee stated the FPRA model used in this application utilized Revision 3 of the IEPRA MOR with minor changes. However, the IEPRA model used in this application is Revision 4 of the MOR, and there are significant internal events model changes between Revisions 3 and 4. Accordingly, it was not clear how the McGuire, Units 1 and 2, FPRA model addressed the modeling updates performed for the IEPRA (i.e.,

between Revisions 3 and 4 of MOR). The response to RAI 20, dated December 3, 2018, provides a complete list of changes between the internal events Revision 3 and 4 MORs, and reviewed these changes against the FPRA for potential impact on the conclusions of the LAR.

Except for several new human failure events (HFEs) that were added to Revision 4 of the IEPRA model, the licensee incorporated the relevant changes into the FPRA model used in this application. The new HFEs not incorporated into the FPRA were considered a conservative modeling choice since the addition of these HFEs would reduce risk.

The NRC staff finds the FPRA used in this application represents the as-built, as-operated plant in accordance with RG 1.200.

Based on the above, conformance of the fire PRA to the applicable technical elements in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, is acceptable to the extent needed to support this application.

Seismic Hazard Assessment The NRC staff reviewed the licensee's assessments of the impact of a seismic event on the proposed change in the context of this application and relevant guidance. Section C.2.3.2 of RG 1.177 states that, in some cases, a PRA of sufficient scope may not be available and such cases would have to be compensated by qualitative arguments, bounding analyses, or compensatory measures. The discussion in "Element 2: Perform Engineering Analysis" of Section B of RG 1.177 states the necessary scope and level of detail of the risk assessment performed to support the proposed change depends upon the systems and functions that are affected and recognizes both qualitative and quantitative risk analyses.

In its supplement dated July 10, 2018, the licensee provided a quantitative assessment of the impact of a seismic event on the proposed change. The assessment focused on the occurrence of a dual unit LOOP due to the seismic event. The frequency of occurrence of LOOP was determined based on the re-evaluated McGuire seismic hazard and a generic fragility (i.e., the conditional failure probability given a seismic acceleration) for off-site power sources from NUREG/CR-6544, "A Methodology for Analyzing Precursors to Earthquake-Initiated and Fire-Initiated Accident Sequences" (April 1998) (Reference 31 ). The base case value was determined by multiplying the seismically-induced LOOP initiating frequency with the conditional core damage probability (CCDP) obtained from the IEPRA model for the LOOP initiator. The

'change' case value was determined in the same manner but with one EDG unavailable due to test and maintenance. The ICCDP was obtained from the base and 'change' case for the requested completion time. Because the analysis did not appear to account for the seismic-induced failure of other SSCs that may occur coincident with the random failure of the EDGs, the NRG staff requested additional information on the approach. In its supplement dated December 3, 2018, the licensee explained that the assessment in the July 10, 2018 supplement did not account for either FLEX equipment or the ESPS diesel generator. The licensee further explained that majority of the SSCs necessary to mitigate LOOP would be correlated (i.e., have the same seismically-induced failure probability) and not including such failures would maximize the random failure contribution of those SSCs in the assessment.

In addition to the above described assessment, the licensee provided two revised estimates of ICCDP in Attachment 7 of the March 7, 2019 supplement. The approaches for determining those estimates are summarized as follows:

1. "Seismic Penalty" Assessment: This analysis assumed all non-EOG SSCs to be failed (probabilities set to 1.0), no credit for any operator action or off-site power recovery, and no credit for any mitigating equipment. The only failures considered in the assessment were the fragility of seismically-induced LOOP and the random failure of the EDGs. The frequency of occurrence of LOOP was determined as described above for the assessment in the July 10, 2018 supplement. The base case value was determined by multiplying the occurrence frequency of seismically-induced LOOP with the random failure of both EDGs (which did not vary based on the seismic acceleration). The

'change' case value was determined by multiplying the occurrence frequency of seismically-induced LOOP with the random failure of only one EOG (because the other EOG is unavailable due to test and maintenance). The ICCDP was obtained based on the base and 'change' case for the requested completion time.

2. Individual Plant Evaluation of External Events (IPEEE) Assessment: The licensee determined the base case value from the results of the seismic PRA (SPRA) developed for the McGuire IPEEE. The McGuire IPEEE SPRA is documented in the licensee's IPEEE submittal, "McGuire Nuclear Station, Units 1 and 2, Docket Nos.: 50-369 and 50-370, Individual Plant Examination of External Events (IPEEE) Submittal" (June 1, 1994) (non-public) (Reference 32). The 'change' case value was determined using the same IPEEE SPRA with one EOG unavailable. The ICCDP was obtained based on the base and 'change' case for the requested completion time. The licensee stated the IPEEE SPRA included both seismically-induced as well as random failure of SSCs, failures due to seismically-induced relay chatter, and failures of operator actions including those related to relay chatter recovery. The licensee explained that the EOG random failure rates in the IPEEE SPRA were a factor of nine higher than current failure rates and that the IPEEE SPRA did not credit FLEX equipment, the ESPS diesel generator, and the SSF.

The NRG staff's evaluation determined that the assessment in the July 10, 2018 supplement and the "seismic penalty" approach in the March 7, 2019 supplement to estimate the seismic GDF (SCDF), collectively (i.e., added together), addressed the prominent risk contributors during a seismic event that are of interest for this application. This is because the assessment in the July 10, 2018 supplement highlighted the impact of random failures of equipment, including the EDGs, during a seismically-induced LOOP while the "seismic penalty" approach in the March 7, 2019 supplement highlighted the impact of seismically-induced failures of equipment other than the EDGs during a seismically-induced LOOP. The EDGs would be seismically correlated, and therefore, would not contribute to the ICCDP for the requested CT change. The NRC staff notes the two approaches, when used collectively, would result in double counting of certain contributions which would be conservative. Further, neither the ESPS nor FLEX mitigating strategies were credited in assessments in the July 10, 2018 supplement or the "seismic penalty" approach in the March 7, 2019 supplement. The SSF, which provides alternate reactor coolant pump (RCP) seal cooling, primary makeup, and instrumentation and controls to support longer term operation of the turbine-driven auxiliary feedwater pump, was also not credited in the assessments. According to the March 7, 2019 supplement, the licensee identified the SSF as having low seismic capacity during the licensee's IPEEE evaluation. However, the NRC staff notes the SSF is expected to be available for earthquakes with low seismic accelerations, which have higher occurrence frequencies, where random failures would dominate the risk from the seismic event. In addition, the assessment in the July 10, 2018 supplement and the "seismic penalty" approach in the March 7, 2019 supplement use the re-evaluated seismic hazard for McGuire. The re-evaluated seismic hazard at McGuire exceeds the safe shutdown earthquake (SSE) in the high frequency range. The NRC staff has previously reviewed the re-evaluated hazard for McGuire and concluded the licensee conducted the hazard re-evaluation using present-day methodologies and regulatory guidance, appropriately characterized the site given the information available, and met the intent of the guidance for determining the reevaluated seismic hazard (Reference 33). Since the same hazard is used for the assessments in the July 10, 2018 supplement and the "seismic penalty" approach in the March 7, 2019 supplement, the previous staff conclusion is valid for this application.

The NRC staff's evaluation of the McGuire IPEEE SPRA submittal noted that both seismically-induced as well as random failure of SSCs, failures due to seismically-induced relay chatter, and failures of operator actions were included in that SPRA. The NRC staff's review determined that the SSC failure rates used in the IPEEE SPRA do not reflect the improved reliability of components (e.g., EDG random failure rates are a factor of nine higher than current failure rates) and represent a notable conservatism. In addition, neither the ESPS diesel generator, SSF, nor FLEX mitigating strategies were credited in the IPEEE SPRA. The IPEEE SPRA was developed using the EPRI hazard curves. Based on a comparison of the ground motion response spectrum (GMRS) from the EPRI hazard used for the IPEEE SPRA and the re-evaluated hazard shown in the March 7, 2019, supplement, the NRC staff determined that both those hazards exceeded the SSE in the high frequency range although the extent of exceedance for the re-evaluated hazard was higher. Relay chatter events typically occur at the high frequency range. Such events were included in the IPEEE SPRA. Further, the NRC staff's review of the licensee's high frequency evaluation due to the re-evaluated seismic hazard previously concluded that the licensee identified and evaluated the high frequency seismic capacity of certain key installed plant equipment to ensure critical functions will be maintained following a seismic event up to the re-evaluated GMRS.

The NRC staff's review of the licensee's IPEEE SPRA submittal shows that the IPEEE SPRA appears to capture major combinations of failure modes relevant to this application and includes conservatisms, such as the high random failure probabilities and the lack of credit for the ESPS diesel generator, SSF as well as FLEX equipment. However, since the IPEEE SPRA model was not developed in accordance with and peer-reviewed against ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, the NRC staff does not consider it to be technically acceptable for risk-informed applications consistent with the guidance in RG 1.200. Further, the technical evaluation report for the IPEEE SPRA, "Technical Evaluation Report on the "Submittal-Only" Review of the Individual Plant Examination of External Events at McGuire Nuclear Station, Units 1 and 2," noted the process used to develop the overall logic model for that SPRA as a weakness and that the human error probabilities were not adjusted to account for seismic events. Therefore, the NRC staff was unable to determine the extent to which the unquantified conservatisms in the IPEEE SPRA counteracted the unquantified uncertainties related to the technical acceptability as well as weaknesses of the IPEEE SPRA. As a result, the NRC staff used the results from the licensee's assessment for ICCDP using the IPEEE SPRA only to provide risk insights for the proposed change.

The NRC staff developed additional risk insights to support the evaluation of the seismic hazard assessment for this application. Sources for these insights included: (1) NRC's McGuire Standardized Plant Analysis Risk (SPAR) model, (2) comparison of representative fragilities for SSCs necessary to mitigate LOOP against that for the EDGs to determine whether seismically-induced failure of those SSCs would be expected prior to such failures for the EDGs, and (3) evaluation of the impact of a seismically-induced LOOP using a lower bound of the representative fragilities for SSCs necessary to mitigate LOOP in conjunction with the re-evaluated seismic hazard for McGuire using the approach from the analysis for Generic Issue (GI) -199, "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants" (Reference 34 ).

In summary, the NRC staff's review finds the assessment in the July 10, 2018 supplement and the "seismic penalty" approach in the March 7, 2019 supplement, when added together, result in a conservative estimate of ICCDP from a seismic event to support the integrated decisionmaking for this application, because: (1) taken together, the assessments capture the prominent risk contributors during a seismic event that are of interest for this application, (2) the assessments conservatively do not credit the ESPS diesel generator, SSF or FLEX mitigating strategies, and (3) the assessments use the re-evaluated seismic hazard at McGuire.

Furthermore, the NRC staff's consideration of insights from the licensee's IPEEE SPRA submittal as well as additional risk insights developed by the staff did not reveal any discrepancies that would invalidate the staff's decision in the context of this application.

The assessment in the July 10, 2018 supplement provided an estimate of ICLERP based on the LOOP event tree and LERF portion of the licensee's IEPRA. The licensee's approach for performing the assessment is discussed earlier. Based on the results provided by the licensee for the assessment, the fraction of core damage sequences that become large early release sequences due to the proposed change is about 37% (i.e., the ratio of the ICLERP and ICCDP values from the assessment is about 0.37). In Attachment 7 of the March 7, 2019 supplement, the licensee addressed ICLERP contribution from seismic events qualitatively. The licensee stated that although a seismic LERF (SLERF) model was unavailable, since the SCDF from the IPEEE was considered conservative, the SLERF would also be expected to be conservative.

The licensee further stated the seismic vulnerabilities were not identified for containment integrity, containment isolation, and containment response in the IPEEE. The licensee cited its relief request in its letter dated October 20, 2016 (Reference 26), in response to the March 12, 2012, 10 CFR 50.54(f) letter (Reference 35), in support of not performing a quantitative SLERF assessment for the approaches in the March 7, 2019 supplement.

The NRC staff's evaluation of the licensee's assessment of the impact of a seismic event on large early release for the proposed change included consideration of insights from: ( 1) the IPEEE SPRA submittal related to containment failure and containment isolation, (2) the request for relief from performing a SPRA in response to the 10 CFR 50.54(f) letter for post-Fukushima actions, and (3) the simplified LERF analysis in NUREG/CR-6595, "An Approach for Estimating the Frequencies of Various Containment Failure Modes and Bypass Events" (Reference 36) for McGuire.

The IPEEE SPRA did not include a quantification of LERF from seismic events and only provided a qualitative examination of the containment structure fragility and the containment isolation function. Based on such an examination, the licensee, in the IPEEE SPRA submittal, stated that the containment structure, including the ice condenser as well as the hydrogen igniters, and penetrations were seismically rugged, that containment isolation would occur in response to a seismic induced core damage accident, and that relays within the containment isolation circuit would function as designed. As part of the relief request, the licensee submitted information that showed high confidence of low probability of failure (HCLPF) containment pressure capacity was approximately 3. 7 times the design pressure for the containment. This means the containment is expected to remain intact and retain its pressure boundary integrity approximately 99 percent of the time when subjected to internal pressures reaching 3. 7 times is design pressure. NUREG/CR-6595 presents an approach that allows a subset of the core damage accidents identified in the Level 1 analysis to be allocated to a release category that is equivalent to a LERF using simplified event trees. The analysis performed for McGuire using the simplified event tree approach in NUREG/CR-6595 resulted in a conditional large early release probability (CLERP) of 0.2 due to seismic events.

Based on the above, the NRC staff finds that the licensee's assessment of the impact of seismic event on large early release for the proposed change is conservative for this application because: (1) it captures the dominant risk contributors to ICLERP during a seismic event that are of interest for this application, (2) the SSCs important for seismically-induced containment failure have high enough capacity to not dominate the ICLERP for large early release for this application, and (3) available margin to the acceptance guidelines for ICLERP for this application. Furthermore, the NRC staff's consideration of additional risk insights from the licensee's IPEEE SPRA submittal and NUREG/CR-6595 did not reveal any discrepancies that would invalidate the staffs decision in the context of this application.

Therefore, the risk estimates for consideration of the impact of seismic hazard on this application are ICCDP of 7.20E-08 and ICLERP of 9.44E-09.

Other External Event Hazards The LAR, as supplemented by letter dated July 10, 2018, evaluates other external hazards to determine whether they impact the application. The supplemented LAR provides a qualitative assessment of each of the following external hazards, which were evaluated in the IPEEE, and determined all screened from further consideration:

Avalanche Coastal Erosion Drought, High Summer Temperatures, Low Lake or River Water Level Fog Forest Fire Frost, Hail, Snow, Ice Cover Hurricane Landslide Lightning Meteorite River Diversion Sandstorm Seiche Soil Shrink-Well Consolidation Storm Surge Tsunami Turbine-Generated Missiles Volcanic Activity Waves Other external hazards evaluated in the IPEEE include: aircraft crashes, transportation events, impact of nearby military and industrial facilities, on-site storage of toxic materials, on-site storage of explosive materials, and gas pipeline ruptures. Each of these were screened from further consideration based on the screening criteria in Section 6 of ASME/ANS RA-Sa-2009.

The supplemented LAR also addresses external flooding hazards at McGuire. The external flooding hazards have been updated since the IPEEE in response to the external flooding portion of the NRC's letter to implement lessons learned from the accident at the Fukushima Dai-ichi nuclear plant, which included the following flooding sources:

Local Intense Precipitation Flooding in Reservoirs Dam Failures Storm Surge and Seiche Tsunami Ice-Induced Flooding Channel Diversion Combined Effects The supplemented LAR concludes these sources of external flooding screen from further consideration based on the screening criteria in Section 6 of ASME/ANS RA-Sa-2009.

Based on the supplemented LAR, where all other external hazards were screened from further consideration, the NRC staff finds the licensee has appropriately evaluated other external hazards to the extent needed to support this application in accordance with RG 1.177 and determined those hazards do not impact this application.

Conclusions for PRA Technical Elements and Acceptability of External Hazard Analyses Based on the above, the NRC staff finds: (1) the McGuire PRA (i.e., internal events, internal flooding, high winds, and fire PRAs) conforms to the applicable technical elements in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, at the appropriate capability category (considering the acceptable disposition of the peer review findings, acceptable justification for SRs meeting CC I, and NRC staff review findings) to predict the change in CDF and LERF for use in this risk-informed application; (2) the seismic assessment in the July 10, 2018 supplement and the "seismic penalty" approach in the March 7, 2019 supplement, when added together, result in a conservative estimate of change in SCDF and SLERF for use in this risk-informed application; and (3) the other external hazards not addressed using PRA were determined not to impact this application.

3.3.2.1.1 Level of Detail in PRA Section C.2.3.3 of RG 1.17 4 states, the level of detail required of the PRA is that which is sufficient to model the risk impact of the proposed change. If the impacts of the proposed change to the plant cannot be associated with elements of the PRA, the PRA should be modified accordingly, or the impact of the change should be evaluated qualitatively as part of the integrated decisionmaking process. In any case, the licensee should properly account for the effects of the changes on the reliability and unavailability of SSCs or on operator actions.

The LAR, as supplemented by letters dated July 10, 2018, December 3, 2018, and March 7, 2019, describes the assumptions and modifications to the integrated PRA (i.e., the internal events, internal flooding, high winds, and fire PRAs) necessary to model the risk impact of the proposed TS CT change. These assumptions and modifications include:

The risk evaluation assumed an EOG outage time of 14 days, consistent with the proposed TS CT change.

In calculating the ICCDP and ICLERP, the difference in risk between the 'change' case and base case is determined. The base case assumes both EDGs are available and does not credit ESPS. The 'change' case credits ESPS per TS 3.8.1. In addition, the following are assumed for the 'change' case: a single EOG is out-of-service; the opposite train EOG, NSWS and safety injection are available (i.e., not in test and maintenance) per TS 3.8.1, the protected equipment (see SE Section 3.4.2.2) are available per proposed license condition (regulatory commitment number 4 was escalated to an obligation by the licensee via a license condition) in letter dated March 7, 2019 and discussed in SE Section 2.2.b; and nominal unavailability (i.e., test and maintenance) values were assumed for all other components. Commitment 4 is longer a regulatory commitment and cannot be changed in the future by the licensee's commitment management program. Also, the common cause failure term of the EDGs was removed for the 'change' case, because TS 3.8.1 only allows entry into the 14-day CT if it has been determined the operable EDG is not inoperable due to common cause failure.

These assumptions are consistent with the regulatory positions in RG 1.177.

ESPS power is not expected to be available to the plant electrical power distribution systems for a period of up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after SBO occurs. Therefore, the ESPS system is modeled as failed by specific initiating events (e.g., large LOCAs or ATWS events) in the

'change' case, where it could not be shown core damage would not occur within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , assuming a complete loss of AC power and loss of secondary side heat removal (SSHR). For the remaining initiating events, thermal-hydraulic analyses performed for PRA success criteria demonstrated core damage will not occur prior to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months given a complete loss of AC power and a loss of SSHR. For these initiators, ESPS was credited in the PRA model. These assumptions are consistent with the ESPS design description detailed in the LAR, as supplemented.

Reactor coolant pump (RCP) seal LOCAs occur following a SBO with a failure of the SSF to provide RCP seal cooling. ESPS power is available for accident mitigation following a RCP seal LOCA, except in cases where ESPS power fails, but is not modeled as preventing the seal LOCA from occurring in the 'change case'. This is a conservative assumption.

Successful operation of both ESPS DGs is required for success of the ESPS system.

Therefore, a failure of either generator is a failure of the system. This assumption is consistent with the ESPS design description detailed in the LAR, as supplemented.

The ESPS sub-base fuel oil tanks will be administratively controlled to ensure the ESPS DGs have sufficient fuel to run fully loaded for the PRA 24-hour mission time without the need to be re-fueled. This assumption is consistent with the ESPS design description detailed in the LAR, as supplemented.

ESPS power can only be aligned to one of the four plants' 4.16kV buses at a time.

Therefore, for each hazard, the most limiting plant/system configuration (i.e., leading to the highest risk) was conservatively assumed.

The ESPS is not dependent upon ventilation. The ESPS DGs are expected to be air cooled. The ESPS switchgear and controls are not expected to be negatively affected by the temperatures in the separate switchgear and controls structure. This assumption is consistent with the ESPS design description detailed in the LAR, as supplemented.

The logic model for the ESPS system in the 'change' case did not require any new common cause events due to the system not having redundant components that would require multiple failures to fail the system function. Further, the ESPS system has no components which could have a common cause failure mode with existing installed plant equipment.

ESPS failure probabilities (failure to start and run) in the 'change' case are based on the generic failure rates for SBO generator in NUREG/CR-6928.

A new human error probability (HEP) associated with operators failing to start and align the ESPS was developed and incorporated into the PRA models for the 'change' case.

This HEP was consistently applied across the internal events (including internal flooding), fire, and high winds PRA models, because the HEP is not impacted by either fire or high winds as only minor timing adjustments were necessary for fire, and the operator actions take place within the plant structures and unaffected by wind. Since the installation, procedures, training, and walkthroughs of ESPS have not been completed, the HEP was developed using conservative assumptions regarding ESPS characteristics and operation (e.g., no recovery credit was applied in the HEP, even though the lack of power to required emergencies loads would be a clear indication that the initial attempt to use ESPS was not successful). The licensee performed a sensitivity study to address potential uncertainties associated with this HEP, and the NRC staff's assessment of this sensitivity study is discussed in SE Section 3.4.2.1.3. Also, the licensee proposed a license condition (regulatory commitment 10 was escalated by the license to an obligation via a license condition) in its letter dated March 7, 2019, that prior to implementing the 14-day CT, the risk estimates associated with this TS CT change (including those results of associated sensitivity studies) will be updated, as necessary, to incorporate the as-built, as-operated ESPS modification and confirm any updated risk estimates meet the risk acceptance guidelines of RG 1.17 4 and RG 1.177. Commitment 10 is no longer a regulatory commitment and cannot be changed in the future by the licensee's commitment management program. Refer to Section 2.2.. b of this safety evaluation for the proposed license condition.

As discussed in response to RAI 22.c.01, dated March 7, 2019, several PRA model refinements were made to ensure the ESPS was properly credited for mitigation capabilities.

Incorporated updated fire ignition frequencies in the FPRA from NUREG-2169, "Nuclear Power Plant Fire Ignition Frequency and Non-Suppression Probability Estimation Using the Updated Fire Events Database, United States Fire Event Experience Through 2009" (January 2015) (Reference 37).

The use of FLEX equipment was not credited in the risk evaluation. This is a conservative assumption.

Based on the above, the NRC staff finds the level of detail in the PRA models and the assumptions and modifications made to the PRA models are appropriate to evaluate the risk impact of the proposed TS CT change.

3.3.2.1.1.4 Plant Representation in PRA Section C.2.3.4 of RG 1.17 4 states, the PRA results used to support an application should be derived from a PRA that represents the as-built and as-operated plant to the extent needed to support the application. Consequently, the PRA should have been maintained and updated, where necessary, to ensure it represents the as-built and as-operated plant.

Section 6.2.4 of LAR Attachment 6 describes the licensee's PRA configuration and control program to maintain and update the McGuire PRA such that the PRA represents the as-built, as-operated plant. As part of this program, the licensee evaluates and prioritizes changes in PRA inputs, as well as address discovery of new information that could affect the PRA. The PRA models are reviewed whenever plant accident response characteristics are changed. Any identifiable plant change is analyzed for its risk significance. This includes plant physical modifications, changes to emergency or abnormal procedures, as well as Technical Specifications and Selected Licensee Commitment changes. Additionally, all plant changes not yet incorporated into the PRA (i.e., open items) are tracked and reviewed prior to the start of an application for their impact on that application. The licensee stated there were no open items for McGuire that have any impact on the proposed TS CT change application.

Based on the licensee's PRA configuration and control program to maintain and update the PRA and the NRC staff findings in SE Section 3.4.2.1.1.2, the NRC staff finds the PRA results used to support this application are derived from an integrated PRA that represents the as-built and as-operated plant to the extent needed to support the application.

3.3.2.1.1.5 Conclusions of PRA Acceptability and Completeness Uncertainty Based on its assessment of the McGuire LAR, as supplemented, the NRC staff concludes the McGuire PRA (i.e., internal events, internal flooding, high winds, and fire PRAs) and the seismic analysis are acceptable for assessing risk to the extent needed to support this application. The NRC staff based this conclusion on the findings that, for this risk-informed application and to the extent needed to support the application: (1) the licensee's risk assessment is of sufficient scope; (2) the McGuire internal events, internal flooding, high winds, and fire PRAs appropriately conform to the applicable technical elements in ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, to predict the change in CDF and LERF; (3) the seismic assessment in the July 10, 2018 supplement and the "seismic penalty" approach in the March 7, 2019 supplement, collectively, result in a conservative estimate of change in SCDF and SLERF; (4) the other external hazards not addressed using PRA were determined not to impact this application; (5) the level of detail in the PRA models and the assumptions and modifications made to the PRA models are appropriate to evaluate the risk impact; and (6) the PRA results are derived from an integrated PRA that represents the as-built and as-operated plant. Also, in accordance with Section 9.2 of NUREG-1855, the licensee's treatment of completeness uncertainty associated with the PRA is acceptable to the extent needed to support this application, because: (1) the PRA scope and level of detail and the licensee's use of screening analyses are appropriate to support this application; and (2) the PRA used is acceptable for the application.

3.3.2.1.2 PRA Results and Insights Based on RG 1.174 and Section 6.4 of NUREG-1855 for a CC II risk evaluation, the mean values of the risk metrics (i.e., CDF, LERF, ICCDP, ICLERP, ~CDF, and ~LERF) should be compared against the applicable risk acceptance guidelines. The mean values referred to are the means of the risk metric's probability distributions that result from the propagation of the uncertainties on the PRA input parameters. In general, the point estimate values of these risk metrics, obtained by quantification of the cutset probabilities using mean values for each basic event probability, does not produce a true mean value for these risk metrics.

The LAR, as supplemented, assesses the risk impact of the proposed TS CT change using the internal events, internal flooding, high winds, and fire PRAs and the quantitative seismic analysis. This risk assessment calculated point estimate values of CDF, LERF, ICCDP, ICLERP, ~CDF, and ~LERF, as opposed to the mean values, specific to the 14-day CT with all relevant configurations represented in the PRAs as described in SE Section 3.4.2.1.1.3. The licensee compared these point estimate values against applicable risk acceptance guidelines in RG 1.17 4 and RG 1.177. The response to RAI 21.b, dated December 3, 2018, provides the results of a parametric uncertainty assessment that compares point estimate and mean risk values (i.e., CDF and LERF) for the base case and 'change' case (which are used to calculate ICCDP, ICLERP, ~CDF, and ~LERF) for the internal events, internal flooding, high winds, and fire hazards. This assessment shows the point estimate risk values are within about 3% of the mean values and concludes the direct use of point estimate risk values, as compared to use of mean values, is acceptable for this application. Based on the NRC staff's review of the parametric uncertainty assessment, NRC staff finds use of point estimate risk values is acceptable to the extent needed to support this application, considering the margin by which the risk acceptance guidelines are met, and the small impact parametric uncertainties have on the risk results.

The response to RAI 22, dated December 3, 2018, provides updated risk evaluation results for the proposed TS CT change using the most limiting unit and system configurations. Table 1 below repeats these risk results. Table 2 compares these results against the risk acceptance guidelines in RG 1.17 4 and RG 1.177 for change in risk (i.e., ~CDF and ~LERF) and incremental increase in risk (i.e., ICCDP and ICLERP). The risk values in Table 2 meet the risk acceptance guidelines, and are, therefore, acceptable. The negative ~CDF and ~LERF in Table 2 indicate a risk reduction relative to the base case risk due to installation of the ESPS.

Table 2:

3.3.2.1.3 Table 1:

Risk Metric Results for 14-day CT (for most limiting unit and system configurations)

Hazard Group ICCDP ICLERP ilCDF ilLERF Internal Events 1.09E-08 1.40E-09

-1.61 E-07

-2.65E-08 Internal 6.42E-08 9.57E-09 4.38E-08 2.16E-09 Flooding High Winds 3.81E-07 3.25E-08

-3.57E-06

-3.88E-07 Fire 1.15E-07 1.04E-08 1.89E-08 7.40E-10 Seismic 7.20E-08*

9.44E-09*

7.20E-08**

9.44E-09**

Total 6.43E-07 8.99E-08

-3.60E-06

-3.76E-07

As discussed in Section 3.4.2.1.1.2 of this SE, the seismic risk values are based on the seismic assessment in the July 10, 2018 supplement and the "seismic penalty" approach in the March 7, 2019 supplement, added together, that result in a conservative estimate of change in SCDF and SLERF for use in this risk-informed application

- The t.CDF and t.LERF can be determined by the change in risk associated with the extended CT (i.e., one EOG in a 14-day outage), and the change in risk associated with not being in the extended CT (non-CT) where both EDGs are available. Since the seismic analysis does not credit ESPS, the change in risk associated with the non-CT case would not be a significant contributor to t.CDF and t.LERF.

Therefore, t.CDF and t.LERF can be estimated to be the same as the ICCDP and ICLERP, respectively.

Comparison of Risk Results to Risk Acceptance Guidelines Risk Metric Acceptance Guideline PRAResults

~GDF RG 1.174, Figure 4 (Region II or Ill)

-3.60E-06 (Region Ill)

~LERF RG 1.17 4, Figure 5 (Region II or Ill)

-4.02E-07 (Region Ill)

ICCDP

< 1.0E-06 6.43E-07 ICLERP

< 1.0E-07 6.33E-08 Sensitivity and Uncertainty Analyses Regulatory Guide 1.17 4 and NUREG-1855 identifies the following types of uncertainty that affect the results of PRAs: parameter uncertainty, model uncertainty, and completeness uncertainty. Regulatory Guides 1.17 4 and 1.177 require uncertainties be appropriately considered in the analysis and interpretation of findings. Also, RG 1.17 4 states, the results of the sensitivity studies should confirm the guidelines are still met even under the alternative assumptions.

LAR Attachment 6, as supplemented by letters dated July 10, 2018, December 3, 2018, and March 7, 2019, addresses parameter uncertainty, model uncertainty, and completeness uncertainty for the PRA used to evaluate the proposed TS CT change. The NRC staff's assessment of parameter and completeness uncertainties is provided in SE Sections 3.4.2.1.2 and 3.4.2.1.1, respectively. NRC staff's assessment of model uncertainty is presented below.

Section 6.2 of LAR Attachment 6, as supplemented by the response to RAI 21.a dated December 3, 2018, describes the approach used to identify and characterize key sources of model uncertainty and related assumptions associated with the risk evaluation of the proposed TS CT change. The licensee's approach is consistent with NUREG-1855, Revision 1, and evaluated sources of model uncertainty and related assumptions for the internal events, internal flooding, high winds, and fire PRAs with respect to the proposed TS change. This included assessing the plant-specific model uncertainties documented in the licensee's PRA notebooks and assessing the generic sources of uncertainty taken from Electric Power Research Institute (EPRI) report 1016737, "Treatment of Parameter and Modeling Uncertainty for Probabilistic Risk Assessments" (2008) (Reference 38), and EPRI report 1026511, "Practical Guidance on the Use of Probabilistic Risk Assessment in Risk-Informed Applications with a Focus on the Treatment of Uncertainty" (2012) (Reference 39). The licensee identified the following key source of uncertainty warranting further evaluation.

The HEP associated with operators failing to start and align the ESPS for the 14-day CT (and the assumption that this action has negligible dependency with other operator actions) is based on conservative assumptions regarding ESPS characteristics and operation. However, this HEP was not formally assessed, because the installation, procedures, training, and walkthroughs of ESPS have not been completed. Therefore, Section 6.2.5 of LAR Attachment 6, as supplemented by the response to RAls 15 and 22 dated December 3, 2018, presents a sensitivity study by doubling this HEP for internal events, internal flooding, high winds, and fire to assess its impact on the results. This sensitivity study was not performed on the seismic hazard results since the ESPS is not credited in the analysis. The results of this sensitivity study (i.e., ICCDP, ICLERP, LlCDF, and LlLERF) meet the risk acceptance guidelines in RG 1.177 and RG 1.17 4, and are, therefore, acceptable. In addition, the proposed TS CT change has an overall impact on reducing total plant risk due to installation of ESPS (i.e., LlCDF and LlLERF results are negative). The LAR, as supplemented, cites several sources of conservatism for its risk analysis, which provides additional confidence that any uncertainties associated with this analysis would not change the conclusions of the LAR. Among these conservatisms are:

The seismic hazard has been addressed using a conservative approach as discussed in SE Section 3.4.2.1.1.2 and does not credit the ESPS, FLEX, or SSF. It is expected that these SSCs would be available for earthquakes with low seismic accelerations, which have higher occurrence frequencies, where random failures would dominate the risk from the seismic event. The SSF is especially beneficial to SBO scenarios since it provides redundant AC power for RCP seal cooling.

of LAR supplement dated March 7, 2019 provides a number of regulatory commitments that are not necessarily credited in the risk evaluation. These regulatory commitments have the effect of mitigating the corresponding increase in risk during the 14-day CT through reducing the likelihood of a reactor trip, LOOP and SBO; increasing ESPS availability; and increasing availability of SSCs that are significant to risk for this application.

Also, since the installation, procedures, training, and walkthroughs of ESPS have not been completed, the licensee proposed a license condition in its supplement dated March 7, 2019, that prior to implementing the 14-day CT, the risk estimates associated with this TS change (including those results of associated sensitivity studies) will be updated, as necessary, to incorporate the as-built, as-operated ESPS modification and confirm any updated risk estimates meet the risk acceptance guidelines of RG 1.17 4 and RG 1.177. Refer to Section 2.4 of this safety evaluation for discussion on the change to the licensee's operating license for t~e proposed license condition.

Based on the above, the NRC staff finds the licensee performed its sensitivity and uncertainty analyses in accordance with RG 1.17 4 and NUREG-1855 and is, therefore, acceptable to the extent needed to support this application.

3.3.2.1.4 Conclusions of Tier 1 Evaluation Based on the review of the licensee's LAR, as supplemented, the NRC staff finds the licensee performed its Tier 1 risk evaluation in accordance with the regulatory position specified in RG 1.177 and is acceptable to the extent needed to support this application. The NRC staff based this conclusion on the findings that: (1) the McGuire internal events, internal flooding, high winds, and fire PRAs and seismic analysis are acceptable to the extent needed to support this application; (2) the incremental increase in risk (i.e., ICCDP and ICLERP) for this application, with consideration of uncertainties, are consistent with the RG 1.177 risk acceptance guidelines, indicating a small increase in risk; and (3) the associated total plant risk is reduced due to installation of ESPS (i.e., ~CDF and ~LERF results are negative.

3.3.2.2 Tier 2 Evaluation (Risk-Significant Plant Configurations)

Section 2.3 of RG 1.177 discusses Tier 2 of the three-tiered approach for evaluating risk associated with proposed changes to TS CT. According to Tier 2, the avoidance of risk-significant plant configurations limits potentially high-risk configurations that could exist if equipment, in addition to that associated with the proposed change, are simultaneously removed from service or other risk-significant operational factors, such as concurrent system or equipment testing, are involved. Therefore, a licensee's Tier 2 evaluation should identify the dominant risk-significant configurations relevant to the proposed TS CT change and ensure appropriate restrictions are placed on these configurations (e.g., assess whether certain enhancements to the TS or procedures are needed to avoid these plant configurations). In addition, compensatory measures that can mitigate any corresponding increase in risk should be identified and evaluated.

Table 2 in Section 3.12.2 of the LAR identifies twelve SSCs that are significant to risk during the McGuire EDG 14-day CT. These SSCs were identified based on configuration-specific risk insights provided by the McGuire IEPRA, FLPRA, HWPRA, and FPRA. Attachment 7 of LAR supplement dated March 7, 2019 proposes a license condition to control these SSCs as "protected equipment" during the 14-day CT utilizing the licensee's protected equipment and work management procedures. In addition, other mechanisms are used to ensure appropriate restrictions are placed on risk significant configurations during the 14-day CT and include: (1)

Technical Specifications and selected licensee commitments (SLC); (2) cycle schedules (i.e.,

testing and maintenance of plant systems are grouped in a rotating cycle of Work Weeks based on TS, PRA, and resource loading); and (3) Electronic Risk Assessment Tool (ERAT) that calculates the CDF and LERF for equipment out of service and requires the implementation of risk management actions to reduce risk when risk-significant configurations are entered. of LAR supplement dated March 7, 2019 provides regulatory commitments that are not necessarily credited in the risk evaluation, but limit plant vulnerabilities during the 14-day CT. These regulatory commitments have the effect of mitigating the corresponding increase in risk during the 14-day CT by reducing the likelihood of a reactor trip, LOOP and SBO; increasing ESPS availability; and increasing availability of SSCs that are significant to risk.

Based on the review of the licensee's LAR, as supplemented, the NRC staff finds the licensee performed its Tier 2 risk evaluation in accordance with the regulatory position specified in RG 1.177 and is acceptable to the extent needed to support this application.

3.3.2.3 Tier 3 Evaluation (Configuration Risk Management Program)

Section 2.3 of RG 1.177 discusses Tier 3 of the three-tiered approach for evaluating risk associated with proposed changes to TS CT. Tier 3 is the establishment of an overall CRMP to ensure other potentially lower probability, but nonetheless risk-significant, configurations resulting from maintenance and other operational activities are identified and managed.

Because the Maintenance Rule, as codified in 10 CFR 50.65(a)(4), requires licensees to assess and manage the potential increase in risk that may result from activities such as surveillance testing, and corrective and preventive maintenance, a licensee may use its existing Maintenance Rule program to satisfy Tier 3.

Section 3.12.2 of the LAR discusses how Tier 3 is met during the 14-day CT. Risk associated with unavailable plant equipment, such as EDGs, is assessed at McGuire as required by 10 CFR 50.65(a)(4). McGuire's CRMP is designed to minimize plant risk through a blended approach of quantitative and qualitative assessments. The blended approach concept uses the best information available that is based on both PRA studies and traditional deterministic approaches to assess and manage risk.

The NRC staff finds the licensee's Tier 3 CRMP is in accordance with the regulatory position specified in RG 1.177 and is acceptable to the extent needed to support this application.

3.3.2.4 Conclusions of Key Principle 4 The NRC staff finds the McGuire PRA (i.e., internal events, internal flooding, high winds, and fire PRAs) and seismic analysis are acceptable to the extent needed to support this application.

The other external hazards not addressed using PRA were determined not to impact this application. The incremental increase in risk (i.e., ICCDP and ICLERP) for this application, with consideration of uncertainties, are consistent with the RG 1.177 risk acceptance guidelines, indicating a small increase in risk due to extension of EDG CT from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. The total plant risk is reduced due to installation of ESPS (i.e., ~CDF and ~LERF results are negative). The NRC staff finds the licensee has followed the three-tiered approach outlined in RG 1.177 to evaluate the risk associated with the proposed TS CT change, and, therefore, the proposed change satisfies Key Principle 4 of RG 1.177.

3.3.3 Key Principle 5 (Performance Monitoring)

Section 3.2 of RG 1.177 states, to ensure extension of a TS CT does not degrade operational safety over time, the licensee should ensure, as part of its Maintenance Rule program ( 10 CFR 50.65), that when equipment does not meet its performance criteria, the evaluation required under the Maintenance Rule includes prior related TS changes in its scope. If the licensee concludes that the performance or condition of TS equipment affected by a TS change does not meet established performance criteria, appropriate corrective action should be taken, in accordance with the Maintenance Rule. Such corrective action could include consideration of another TS change to shorten the revised CT, or imposition of a more restrictive administrative limit, if the licensee determines this to be an important factor in reversing the negative trend.

Section 3.8 of the LAR states the reliability and availability of the EDGs and ESPS are monitored using its Maintenance Rule program. If the pre-established reliability or availability performance criteria are not achieved for the EDGs or ESPS, they are considered for 1 O CFR 50.65(a)(1) actions, which require increased management attention and goal setting to restore their performance to an acceptable level.

The NRC finds the implementation and monitoring program for the proposed TS CT change described by the licensee is consistent with Key Principle 5 of RG 1.177.

3.3.4 Risk-Informed Considerations Summary The NRC staff concludes the licensee's methodology for assessing the risk impact of the proposed TS CT change is accomplished using a PRA (i.e., internal events, internal flooding, high winds, and fire PRAs) and a quantitative seismic analysis that are acceptable to the extent needed to support this application. The other external hazards were determined not to impact this application. The incremental increase in risk (i.e., ICCDP and ICLERP) for this application, with consideration of uncertainties, are consistent with the RG 1.177 risk acceptance guidelines, indicating a small increase in risk due to extension of EOG CT from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 14 days. The total plant risk is reduced due to installation of ESPS (i.e., LlCDF and LlLERF results are negative). The NRC staff concludes the licensee has followed the three-tiered approach in RG 1.177 and meet Key Principles 4 and 5 outlined in RG 1.17 4.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, NRC staff notified the North Carolina State official of the proposed issuance of the amendments on April 23, 2019. The State official confirmed on April 30, 2019, that the State of North Carolina had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20. 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, and there has been no public comment on this finding (83 FR 8512: February 27, 2017). 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. Henderson, Kelvin, Duke Energy, letter to U.S. Nuclear Regulatory Commission, "License Amendment Request Proposing Changes to Catawba and McGuire Technical Specification 3.8.1, "AC Sources - Operating," May 2, 2017, Agencywide Document Access and Management System (ADAMS) Accession No. ML17122A116.

2. Henderson, Kelvin, Duke Energy, letter to U.S. Nuclear Regulatory Commission, "Supplement to License Amendment Request Proposing Changes to Catawba and McGuire Technical Specification 3.8.1, "AC Sources - Operating," July 20, 2017, ADAMS Accession No. ML17201Q132.

3. Henderson, Kelvin, Duke Energy, letter to U.S. Nuclear Regulatory Commission, "Supplement to License Amendment Request Proposing Changes to Catawba and McGuire Technical Specification 3.8.1, "AC Sources - Operating," November 21, 2017, ADAMS Accession No. ML17325A588.

4. Capps, Steven, Duke Energy, letter to U.S. Nuclear Regulatory Commission, "Supplement to License Amendment Request Proposing Changes to Catawba and McGuire Technical Specification 3.8.1, "AC Sources - Operating," July 10, 2018, ADAMS Accession No. ML18192A002 (package).

5. Capps, Steven, Duke Energy, letter to U.S. Nuclear Regulatory Commission, "Response to NRC Request for Additional Information (RAI) Regarding License Amendment Request Proposing Changes to the Technical Specification 3.8.1, for McGuire Nuclear Station," December 3, 2018, ADAMS Accession No. ML18337A277.

6. Snider, Steve, Duke Energy, letter to U.S. Nuclear Regulatory Commission, "Response to NRC Request for Additional Information (RAI) Regarding License Amendment Request Proposing Changes to the Technical Specification 3.8.1, for Catawba Nuclear Station, Units 1 and 2," March 7, 2019, ADAMS Accession No. ML19066A354.

7. Snider, Steve, Duke Energy, letter to U.S. Nuclear Regulatory Commission, "Supplement to Request for Additional Information (RAI) Responses Regarding License Amendment Request Proposing Changes to the Technical Specification 3.8.1, for Catawba Nuclear Station and McGuire Nuclear Station," April 8, 2019, ADAMS Accession No. ML19099A046.

8. U.S. Nuclear Regulatory Commission, McGuire Nuclear Station, Updated Final Safety Analysis Report, "Section 9.2 - Water Systems, Nuclear Water System," April 22, 2017, ADAMS Accession No. ML17310A611, Package No. ML17310A523.

9. U.S. Nuclear Regulatory Commission, McGuire Nuclear Station, Updated Final Safety Analysis Report, "Section 6.4 - Control Area (Habitability) Ventilation System, 6.4.1 -

Design Bases," April 22, 2017, ADAMS Accession No. ML17310A600, Package No.

ML17310A523.

10. U.S. Nuclear Regulatory Commission (NRC), Regulatory Guide (RG) 1.93, Revision 1, "Availability of Electric Power Sources," March 2012, ADAMS Accession No. ML090550661.

11. U.S. Nuclear Regulatory Commission (NRC), Regulatory Guide (RG) 1.155, "Station Blackout," August 1988, ADAMS Accession No. ML003740034.

12. U.S. Nuclear Regulatory Commission (NRC), Regulatory Guide (RG) 1.17 4, Revision 3, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," January 2018, ADAMS Accession No. ML17317A256.

13. U.S. Nuclear Regulatory Commission, Regulatory Guide (RG) 1.177, Revision 1, "An Approach For Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications,"

May 2011, ADAMS Accession No. ML100910008.

14. U.S. Nuclear Regulatory Commission (NRC), Regulatory Guide (RG) 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," March 2009, ADAMS Accession No. ML090410014.

15. U.S. Nuclear Regulatory Commission (NRC), Standard Review Plan - NUREG-0800, Section "19.2 - Review of Risk Information Used To Support Permanent Plant-Specific Changes To The Licensing Basis: General Guidance," June 2007, ADAMS Accession No. ML071700658.

16. U.S. Nuclear Regulatory Commission (NRC), Standard Review Plan - NUREG-0800, Section "19.1 - Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," June 2007, ADAMS Accession No. ML071700657.

17. U.S. Nuclear Regulatory Commission (NRC), Standard Review Plan - NUREG-0800, Section "16.1 - Risk-Informed Decision Making: Technical Specifications," June 2007, ADAMS Accession No. ML070380228.

18. U.S. Nuclear Regulatory Commission (NRC), Regulatory Issue Summary 2007-06, Regulatory Guide 1.200 Implementation," March 22, 2007, ADAMS Accession No. ML070650428.

19. U.S. Nuclear Regulatory Commission (NRC), Standard Review Plan, NUREG-0800, Branch Technical Position (BTP) 8 Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions," February 2012, ADAMS Accession No. ML113640138.

20. Mahoney, Michael, NRC, email to Art Zaremba, Duke Energy - McGuire Nuclear Station, November 2, 2018, ADAMS Accession No. ML18306A937.

21. U.S. Nuclear Regulatory Commission, NUREG-1855, Revision 1, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking,"

Final Report, March 2017, ADAMS Accession No. ML17062A466.

22. American Society of Mechanical Engineers, ASME/ANS RA-Sa-2009, "Standard for Probabilistic Risk Assessment for Nuclear Power Plants."

23. U.S. Nuclear Regulatory Commission, (NRC), Final Revision of Appendix X to NEI 05-04/07-12/12-16, "Close Out of Facts and Observations (F&Os)," February 21, 2017, ADAMS Accession No. ML17086A451, Package ML17086A431.

24. Ross-Lee, M.J and Giitter, Joseph, NRC letter to Greg Krueger, Nuclear Energy Institute, "U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance 05-04, 07-12 and 12-13, Closeout of Facts and Observations (F&O's), May 3, 2017, ADAMS Accession No. ML17079A427.

25. Nuclear Energy Institute (NEI) 05-04, Rev. 2, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," November 2008, ADAMS Accession No. ML083430462.

26. Kapopoulos, Jr., Ernest J., Duke Energy, Letter to NRC, "Supplemental Information Regarding Reevaluated Seismic Hazard Screening and Prioritization Results -

Response to NRC Request for Information Pursuant to 1 OCFR 50.54(f) Regarding Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident," October 20, 2016, ADAMS Accession No. ML16295A342.

27. U.S. Nuclear Regulatory Commission (NRC), NUREG/CR-6928, "Industry - Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants," February 2007, ADAMS Accession No. ML070650650.

28. Ray, Thomas D., Duke Energy, Letter to NRC, "Response to Request for Additional Information, License Amendment Request - Permanent Extension of Type A and Type C Leak Rate Test Frequencies," December 12, 2017, ADAMS Accession No. ML17353A208.

29. Nuclear Energy Institute (NEI) 07-12, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines, Draft Version F, Rev. O," December 2007, ADAMS Accession No. ML073551166.

30. Capps, Steven, Duke Energy, letter to U.S. Nuclear Regulatory Commission, "McGuire Nuclear Station, Units 1 and 2 - Issuance of Amendments Regarding National Fire Protection Association Standard (NFPA) 805," December 6, 2016, ADAMS Accession No. ML16077A135.

31. U.S. Nuclear Regulatory Commission (NRC), NUREG/CR-6544, "Finite Element Analyses for Seismic Shear Wall International Standard Problem," April 1998, ADAMS Accession No. ML13073A033.

32. McMeekin, T.C., Duke Power Company, letter to NRC, "McGuire Nuclear Station, Units 1 and 2 - Individual Plant Examination of External Events (IPEEE) Submittal," June 1, 1994, ADAMS Accession No. ML080770320.

33. Vega, Frankie G., NRC, Letter to Steven D. Capps, Duke Energy Carolinas, LLC, "McGuire Nuclear Station, Units 1 And 2 - Staff Assessment Of Information Provided Pursuant To Title 10 Of The Code Of Federal Regulations Part 50, Section 50.54(F),

Seismic Hazard Reevaluations For Recommendation 2.1 Of The Near-Term Task Force Review Of Insights From The Fukushima Dai-ichi Accident," July 20, 2015, ADAMC Accession No. ML15182A067.

34. U.S. Nuclear Regulatory Commission, Generic Issue 199 (Gl-199) "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants - Safety/Risk Assessment," August 2010, ADAMS Accession No. ML1000270639, Package No. ML100270582.

35. Leeds, Eric J., NRC, Letter to All Power Reactor Licensees and Holders of Construction Permits in Active or Deferred Status, "Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3 and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-Chi Accident,"

March 12, 2012, ADAMS Accession No. ML12053A340.

36. U.S. Nuclear Regulatory Commission (NRC), NUREG/CR-6595, Rev. 1, "An Approach for Estimating the Frequencies of Various Containment Failure Modes and Bypass Events," October 2004, ADAMS Accession No. ML043240040.

37. Electric Power Research Institute and U.S. Nuclear Regulatory Commission, NUREG-2169, "Nuclear Power Plant Fire Ignition Frequency and Non-Suppression Probability Estimation Using the Updated Fire Events Database, January 2015, ADAMS Accession No. ML15016A069.

38. Electric Power Research Institute - EPRI 1016737, "Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments," 2008.

39. Electric Power Research Institute - EPRI 1026511, "Practical Guidance on the Use of PRA in Risk-Informed Submittals with a Focus on the Treatment of Uncertainties," 2012.

Principal Contributors:

G. Purciarello, NRR A. Foli, NRR P. Snyder, NRR T. Hilsmeier, NRR S. Vasavada, NRR M. Mahoney, NRR Date of issuance: Ju 1e 2 a, 2 o 1 9

ML19126A030 OFFICE DORL/LPL2-1 /PM DORL/LPL2-1 /LA+

NAME MMahoney KGoldstein DATE 05/13/2019 05/16/2019 OFFICE DRA/APLA/BC+

DE/EEOB/BC+

NAME SRosenberg DWilliams DATE 05/14/2019 04/18/2019 OFFICE OGC (NLO)+

DORL/LPL2-1/BC NAME DRoth MMarkley DATE 06/13/19 6/28/19

+g E-mail DSS/SBPB/BC+

DSS/STSB/BC+

SAnderson PSnyder for VCusamano 05/03/2019 05/06/2019 DRA/APLB/TL+

DSS/SRXB/BC+

MReisiFard JWhitman 05/13/2019 04/22/2019 DORL/LPL2-1 /PM AKlett for MMahoney 6/28/19

v t e Letter Sequence Approval
CAC:MF9669, Control Room Habitability (Approved, Closed) CAC:MF9670, Control Room Habitability (Approved, Closed) CAC:MF9672, Control Room Habitability (Approved, Closed) CAC:MF9673, Control Room Habitability (Approved, Closed) EPID:L-2017-LLA-0256, Control Room Habitability (Approved, Closed) EPID:L-2017-LLA-0257, Control Room Habitability (Approved, Closed)
Initiation Request, Request, Request, Request, Request, Request Acceptance, Acceptance Supplement, Supplement, Supplement, Supplement, Supplement, Supplement Administration Meeting Questions 2 November 2018 9 January 2019 Answers 10 July 2018 3 December 2018 10 July 2019 Results Approval, Approval, Approval, Approval, Approval Other: ML17151A337, ML18046B077, ML18117A187, ML18249A046, ML19192A134, ML19196A213
MONTHYEAR2018-05-04 [Table View]

ML19126A030

Text

SUBJECT:

Dear Mr. Ray:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.1 REGULATORY EVALUATION

Licensee's Proposed TS Changes

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

7.0 REFERENCES

Navigation menu

Search