ML24151A384

– Issuance of Amendment Nos. 264 and 226 Support to Digital Modernization Project Installation (EPID L-2023-LLA-0025) and Exemption from the Requirements of 10 CFR 50.62

ML24151A384
Person / Time
Site:	Limerick
Issue date:	10/31/2024
From:	Marshall M Plant Licensing Branch 1
To:	Rhoades D Constellation Energy Generation, Constellation Nuclear
Klett, AL
References
EPID L-2023-LLA-0025, EPID L-2023-LLE-0005
Download: ML24151A384 (1)

Text

October 31, 2024

David P. Rhoades Senior Vice President Constellation Energy Generation, LLC264 President and Chief Nuclear Officer Constellation Nuclear 4300 Winfield Road Warrenville, IL 60555

SUBJECT:

LIMERICK GENERATING STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT NOS. 264 AND 226 RE: SUPPORT TO DIGITAL MODERNIZATION PROJECT INSTALLATION (EPID L-2023-LLA-0025 AND EXEMPTION FROM THE REQUIREMENTS OF 10 CFR 50.62 EPID L-2023-LLE-0005)

Dear David Rhoades:

The U.S. Nuclear Regulatory Commission (NRC, the Commission) has issued the enclosed Amendment Nos. 264 and 226 to Renewed Facility Operating License Nos. NPF-39 and NPF-85 for the Limerick Generating Station, Units 1 and 2, respectively. These amendments consist of changes to the Technical Specifications and Facility Operating Licenses.

In addition, NRC has approved the enclosed exemption from specific requirements of Title 10 of the Code of Federal Regulations (10 CFR) Section 50.62, Requirements for reduction of risk from anticipated transients without scram (ATWS) events for light-water-cooled nuclear power plants.

These actions are in response to your application dated February 17, 2023, as supplemented by letters dated July 21, 2023, July 31, 2023, August 16, 2023, October 19, 2023, April 18, 2024, May 28, 2024, and October 4, 2024. A publicly available version of each letter is in Agencywide Documents Access and Management Syst em under Accession Nos. ML23052A023, ML23202A219, ML23212B105, ML23228A094, ML23292A074, ML24109A070, ML24149A211, and ML24278A302, respectively.

The amendments (1) make changes to technical specifications related to postulated accidents during cold shutdown and refueling operations and (2) make temporary changes to the technical specifications related to anticipated transients without scram mitigation systems during power production operation for a period of 30 days.

A copy of our related safety evaluation is also enclosed. Notice of Issuance will be included in the Commissions monthly Federal Register notice.

D. Rhoades

Constellation also requested an exemption from:

the requirements for alternate rod insertion (ARI) capability under section 10 CFR 50.62(c)(3)

the automatic response capability requirement of section 10 CFR 50.62(c)(4) for standby liquid control system (SLCS)

the automatic response capability requirement of section 10 CFR 50.62(c)(5) for recirculation pumps trip (RPT)

Constellation requested the exemption for a period of 30 days prior to the calendar year 2027 refueling outage for Unit 2 and the calendar year 2026 refueling outage for Unit 1 with the following operational constraints:

reduced maximum thermal power limit

limited number of safety relief valves (SRVs) out of service

manual initiation of SLCS within five minutes

designated suppression pool water level

reactor water level 3 recirculation runback system operational

The operational constraints identified by Constellation by maximum thermal power limit are listed in the following table.

Exemptions Operational Constraints for a Period of 30-Days

Maximum Maximum Minimum Additional Reactor Number of SRVs Manual Initiation Suppression System Thermal Power Out of Service Time for SLCS Pool Water Credited Level

Level 3 90% 0 5 minutes 23 feet Recirculation Runback

Level 3 87% 0 5 minutes 22 feet Recirculation Runback

Level 3 84% 1 5 minutes 22 feet Recirculation Runback

D. Rhoades

A copy of the exemption is enclosed. The exemption has been forwarded to the Office of the Federal Register for publication.

Sincerely,

/RA/

Michael L. Marshall, Jr., Senior Project Manager Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Docket Nos. 50-352 and 50-353

Enclosures:

1. Amendment No. 264 to Renewed NPF-39

2. Amendment No. 226 to Renewed NPF-85

3. Safety Evaluation

4. Exemption

cc: Listserv CONSTELLATION ENERGY GENERATION, LLC

DOCKET NO. 50-352

LIMERICK GENERATING STATION, UNIT 1

AMENDMENT TO FACILITY OPERATING LICENSE

Amendment No. 264 Renewed License No. NPF-39

1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by Constellation Energy Generation, LLC (the licensee), dated February 17, 2023, as supplemented by letters dated July 21, 2023, July 31, 2023, August 16, 2023, October 19, 2023, April 18, 2024, May 28, 2024, and October 4, 2024, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations 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 Commissions regulations;

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 Commissions regulations and all applicable requirements have been satisfied.

Enclosure 1

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-39 is hereby amended to read as follows:

(2) Technical Specifications

The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 264, are hereby incorporated into this renewed license. Constellation Energy Generation, LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. This license amendment is effective as of its date of issuance and shall be implemented within 90 days.

FOR THE NUCLEAR REGULATORY COMMISSION

Hipólito González, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Facility Operating License

Date of Issuance: October 31, 2024 ATTACHMENT TO LICENSE AMENDMENT NO. 264

LIMERICK GENERATING STATION, UNIT 1

RENEWED FACILITY OPERATING LICENSE NO. NPF-39

DOCKET NO. 50-352

Replace the following page of the Renewed Facility Operating License with the revised page.

The revised page is identified by amendment number and contains marginal lines indicating the area of change.

Remove Insert Page 3 Page 3

Replace the following pages of the Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert 3/4 1-20 3/4 1-20 3/4 3-3 3/4 3-3 3/4 3-4 3/4 3-4 3/4 3-5 3/4 3-5 3/4 3-8 3/4 3-8 3/4 3-8a 3/4 3-8a 3/4 3-12 3/4 3-12 3/4 3-17 3/4 3-17 3/4 3-28 3/4 3-28 3/4 3-31 3/4 3-31 3/4 3-34 3/4 3-34 3/4 3-35 3/4 3-35 3/4 3-36 3/4 3-36 3/4 3-36a 3/4 3-36a 3/4 3-41 3/4 3-41 3/4 3-42 3/4 3-42 3/4 5-6 3/4 5-6 3/4 8-9 3/4 8-9 3/4 9-1 3/4 9-1 3/4 9-2 3/4 9-2 3/4 9-15 3/4 9-15 3/4 9-16 3/4 9-16 REACTIVITY CONTROL SYSTEMS

SURVEILLANCE REQUIREMENTS (Continued)

b. In accordance with the Surveillance Frequency Control Program by:

1. Verifying the continuity of the explosive charge.

2. Determining by chemical analysis and calculation* that theavailable weight of Boron-10 is greater than or equal to 185 lbs;

the concentration of sodium pentaborate in solution is less than or equal to 13.8% and within the limits of Figure 3.1.5-1 and; the following equation is satisfied:

13% wt. 29 atom % 86 gpmC x E x Q 1

where

C = Sodium pentaborate solution (% by weight)

Q = Two pump flowrate, as determined per surveillance requirement 4.1.5.c.

E = Boron 10 enrichment (atom % Boron 10)

3. Verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

4. Verifying that no more than two pumps are aligned for automatic operation.***

c. Demonstrating that, when tested pursuant to Specification 4.0.5, theminimum flow requirement of 37.0 gpm per pump at a pressure of greater

than or equal to 1230 +/- 25 psig is met.

d. In accordance with the Surveillance Frequency Control Program by:

e. Initiating at least one of the standby liquid control systemloops, including an explosive valve, and verifying that a flow

path from the pumps to the reactor pressure vessel is available by pumping demineralized water into the reactor vessel. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch which has been certified by having one of the batch success-fully fired. All injection loops shall be tested in 3 operating cycles.

2. Verify all heatsuction is unblocked-treated piping between storage tank and pump.**

e. Prior to addition of Boron to storage tank verify sodium pentaborate enrichment to be added is 49 atom % Boron 10.

• This test shall also be performed anytime water or boron is added to the solu-tion or when the solution temperature drops below the limits of Figure 3.1.5-1for the most recent concentration analysis, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after water or boron

addition or solution temperature is restored.

• • This test shall also be performed whenever suction piping temperature drops below the limits of Figure 3.1.5-1 for the most recent concentration analysis, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after solution temperature is restored.

• • • For a p of the 2026 refueling outage, no pumps are required to start automatically. eriod of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start

LIMERICK - UNIT 1 3/4 1-20 Amendment No. 59, 61, 66, 91, 106, 185264, 186, 201, 232 TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUME NTATION

APPLICABLE MINIMUM OPERATIONAL OPERABLE CHANNELS FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a) ACTION

6. DELETED DELETED DELETED DELETED

7. Drywell Pressure - High 1, 2(h) 2 1

8. Scram Discharge Volume Water Level - High

a. Lev el Trans mitter 1, 2 2 1 5(i) 2 3

b. Float Switch 1, 2 2 1 5(i) 2 3

9. Turbine Stop Valve - Closure 1(j) 4(k) 6

10. Turbine Control Valve Fast Closure, Trip Oil Pressure - Low 1(j) 2(k) 6

11. Reactor Mode Switch Shutdown Position 1, 2 2 1 3, 4 2 7 5(q) 2 3

12. Manual Scram 1, 2 2 1 3, 4 2 8 5(q) 2 9

LIMERICK - UNIT 1 3/4 3-3 Amendment No. 89 264 TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION

ACTION STATEMENTS

ACTION 1 - Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

ACTION 2 - Verify all insertable control rods to be inserted in the core and lock the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

ACTION 3 - Immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

ACTION 4 - Be in at least STARTUP within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

ACTION 5 - Be in STARTUP with the main steam line isolation valves closed within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

ACTION 6 - Initiate a reduction in THERMAL POWER within 15 minutes and reduce turbine first stage pressure until the function is automatically bypassed, within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

ACTION 7 - Verify all insertable control rods to be inserted within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

ACTION 8 - Lock the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

ACTION 9 - Immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

ACTION 10 - a. If the condition exists due to a common-mode OPRM deficiency*, then initiate alternate method to detect and suppress thermal-hydraulic instability oscillations within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> AND restore required channels to OPERABLE status within 120 days,

OR

b. Reduce THERMAL POWER to < 25% RATED THERMAL POWER within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

• Unanticipated characteristic of the instability detection algorithm or equipment that renders all OPRM channels inoperable at once.

LIMERICK - UNIT 1 3/4 3-4 Amendment No. 141, 149, 177, 200 264 TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE NOTATIONS

(a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> forrequired surveillance without placing the trip system in the tripped

condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) This function shall be automatically bypassed when the reactor mode switch is in the Run position.

(c) DELETED (d) The noncoincident NMS reactor trip function logic is such that all channels go to both trip systems. Therefore, when the "shorting links" are removed, the Minimum OPERABLE Channels Per Trip System is 6 IRMs.

(e) An APRM channel is inoperable if there are less than 3 LPRM inputs per level or less than 20 LPRM inputs to an APRM channel, or if more than 9 LPRM inputs to the APRM channel have been bypassed since the last APRM calibration (weekly gain calibration).

(f) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1.

(g) This function shall be automatically bypassed when the reactor mode switch is not in the Run position.

(h) This function is not required to be OPERABLE when PRIMARY CONTAINMENT INTEGRITY is not required.

(i) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

(j) This function shall be automatically bypassed when turbine first stage pressure is equivalent to a THERMAL POWER of less than 29.5 % of RATED THERMAL POWER.

(k) Also actuates the EOC-RPT system.

(l) DELETED

(m) Each APRM channel provides inputs to both trip systems.

(n) DELETED (o) With THERMAL POWER 25% RATED THERMAL POWER. The OPRM Upscale trip output shall be automatically enabled (not bypassed) when APRM Simulated Thermal Power is 29.5% and recirculation drive flow is < 60%. The OPRM trip output may be automatically bypassed when APRM Simulated Thermal Power is

< 29.5% or recirculation drive flow is 60%.

(p) A minimum of 23 cells, each with a minimum of 2 OPERABLE LPRMs, must be OPERABLE for an OPRM channel to be OPERABLE.

(q) With any control rod withdrawn from a core cell containing one or more fuels assemblies.

LIMERICK - UNIT 1 3/4 3-5 Amendment No. 41,53,141,177, 201 264

TABLE 4.3.1.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS

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

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

(q) With any control rod withdrawn from a core cell containing one more fuel assemblies.

LIMERICK - UNIT 1 3/4 3-8a Amendment No. 201 264 TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION

MINIMUM APPLICABLE ISOLATION OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b) CONDITION ACTION

3. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCS Flow - High J 1 1, 2, 3 23

b. RWCS Area Temperature - High J 6 1, 2, 3 23

c. RWCS Area Ventilation Temperature - High J 6 1, 2, 3 23

d. SLCS Initiation(h) Y(d) NA 1, 2, 3 23

e. Reactor Vessel Water Level -

Low, Low - Level 2 B 2 1, 2, 3 23

f. Manual Initiation NA 1 1, 2, 3 24

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line Pressure - High L 1 1, 2, 3 23

b. HPCI Steam Supply Pressure - Low LA 2 1, 2, 3 23

c. HPCI Turbine Exhaust Diaphragm Pressure - High L 2 1, 2, 3 23

d. HPCI Equipment Room Temperature - High L 1 1, 2, 3 23

e. HPCI Equipment Room Temperature - High L 1 1, 2, 3 23

LIMERICK - UNIT 1 3/4 3-12 Amendment No. 33, 264

~

TABLE 3.3.2-1 (Continued)

TABLE NOTATIONS

(c) Actuates secondary containment isolation valve. Signals B, H, S, and R also start the standby gas treatment system.

(d) RWCU system inlet outboard isolation valve closes on SLCS "B" initiation.

RWCU system inlet inboard isolation valve closes on SLCS "A" or SLCS "C" initiation.

(e) Manual initiation isolates the steam supply line outboard isolation valve and only following manual or automatic initiation of the system.

(f) In the event of a loss of ventilation the temperature - high setpoint may be raised by 50°F for a period not to exceed 30 minutes to permit restoration of the ventilation flow without a spurious trip. During the 30 minute period, an operator, or other qualified member of the technical staff, shall observe the temperature indications continuously, so that, in the event of rapid increases in temperature, the main steam lines shall be manually isolated.

(g) Wide range accident monitor per Specification 3.3.7.5.

(h) For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2026 refueling outage, the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

LIMERICK - UNIT 1 3/4 3-17 Amendment No. 28, 53, 112, 146 264 TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK(a)TEST(a) CALIBRATION(a) SURVEILLANCE REQUIRED

3. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCS Flow - High 1, 2, 3

b. RWCS Area Temperature - High 1, 2, 3

c. RWCS Area Ventilation Temperature - High 1, 2, 3

d. SLCS Initiation(b) N.A. N.A. 1, 2, 3

e. Reactor Vessel Water Level Low, Low, - Level 2 1, 2, 3

f. Manual Initiation N.A. N.A. 1, 2, 3

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line Pressure - High 1, 2, 3

b. HPCI Steam Supply Pressure, Low 1, 2, 3

c. HPCI Turbine Exhaust Diaphragm Pressure - High 1, 2, 3

d. HPCI Equipment Room Temperature - High 1, 2, 3

e. HPCI Equipment Room Temperature - High 1, 2, 3

f. HPCI Pipe Routing Area Temperature - High 1, 2, 3

g. Manual Initiation N.A. N.A. 1, 2, 3

h. HPCI Steam Line Pressure Timer N.A. 1, 2, 3

LIMERICK - UNIT 1 3/4 3-28 Amendment No. 53, 69, 186 264

TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION TABLE NOTATIONS

(a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) Also provides input to actuation logic for the associated emergency diesel generators.

(c) One trip system. Provides signal to HPCI pump suction valves only.

(d) On 1 out of 2 taken twice logic, provides a signal to trip the HPCI pump turbine only.

(e) The manual initiation push buttons start the respective core spray pump and diesel generator. The "A" and "B" logic manual push buttons also actuate an initiation permissive in the injection valve opening logic.

(f) A channel as used here is defined as the 127 bus relay for Item 1 and the 127, 127Y, and 127Z feeder relays with their associated time delay relays taken together for Item 2.

• DELETED

1. Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

• • DELETED

1. 1. Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.

1. 1. 1. The injection functions of Drywell Pressure - High and Manual Initiation are not required to be OPERABLE with reactor steam dome pressure less than 550 psig.

LIMERICK - UNIT 1 3/4 3-35 Amendment No. 53,224, 227 264 TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTIONSTATEMENTS

ACTION 30 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. With one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program, or declare the associated system inoperable.

b. With more than one channel inoperable, declare the associated system inoperable.

ACTION 31 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, declare the associated ECCS inoperable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 32 - DELETED

ACTION 33 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program*, or declare the associated ECCS inoperable.

ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. For one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program, or declare the HPCI system inoperable.

b. With more than one channel inoperable, declare the HPCI system inoperable.

ACTION 35 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program*, or declare the HPCI system inoperable.

ACTION 36 - With the number of OPERABLE channels less than the Total Number of Channels, declare the associated emergency diesel generator and the associated offsite source breaker that is not supplying the bus inoperable and take the ACTION required by Specification 3.8.1.1.

• Not applicable when trip capability is not maintained.

LIMERICK - UNIT 1 3/4 3-36 Amendment No. 11,53,158,227, 240 264 TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTION STATEMENTS

ACTION 37 - With the number of OPERABLE channels one less than the Total Number of Channels, place the inoperable device in the bypassed condition subject to the following conditions:

Inoperable Device Condition

127-11X0X 127Y-11X0X and 127Z-11X0X operable 127Y-11X0X 127-11X0X and 127Z-11X0X operable 127Z-11X0X 127-11X0X and 127Y-11X0X operable.

127Z-11Y0Y operable for the other 3 breakers monitoring that source, offsite source grid voltage for that source is maintained at or above 230kV (for the 101 Safeguard Bus Source) or 525kV (for the 201 Safeguard Bus Source),

Load Tap Changer for that source is in service and in automatic operation, and the electrical buses and breaker alignments are maintained within bounds of approved plant procedures.

or, place the inoperable channel in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and take the Action required by Specification 3.8.1.1.

Operation may then continue until performance of the next required CHANNEL FUNCTIONAL TEST.

LIMERICK - UNIT 1 3/4 3-36a Amendment No. 158 264

INSTRUMENTATION 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values shown in the Trip Setpoint column of Table 3.3.4.1-2.

APPLICABILITY: OPERATIONAL CONDITION 1.

Note: For a period of 30 days preceding exit of OPERATONAL CONDITION 1 at the start of the 2026 refueling outage, the LCO is not applicable when the following conditions are met.

THERMAL POWER Safety/Relieve Valves Pool Water Level Maximum Maximum Inoperable Minimum Suppression 90%RTP 0 of 14 23 feet 87%RTP 0 of 14 22 feet 84%RTP 1 of 14 22 feet Recirc Runback on Level 3 Function is Available and not in Bypass.

ACTION: a. With an ATWS recirculation pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.1-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel trip setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by theMinimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel(s) in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program*.

c. With the number of OPERABLE channels two or more less than requiredby the Minimum OPERABLE Channels per Trip System requirement for one trip system and:

1. If the inoperable channels consist of one reactor vessel waterlevel channel and one reactor vessel pressure channel, place both inoperable channels in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program, or if this action will initiate a pump trip, declare the trip system inoperable.

2. If the inoperable channels include two reactor vessel water levelchannels or two reactor vessel pressure channels, declare the trip system inoperable.

d. With one trip system inoperable, restore the inoperable trip systemto OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program, or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

e. With both trip systems inoperable, restore at least one trip systemto OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.3.4.1.1 Each of the required ATWS recirculation pump trip system instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillance Frequency Control Program.

4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed in accordance with the Surveillance Frequency Control Program.

• Not applicable when trip capability is not maintained.

LIMERICK - UNIT 1 3/4 3-42 Amendment No. 70,71,186, 240 264 EMERGENCY CORE COOLING SYSTEMS

3/4.5.2 REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

LIMITING CONDITION FOR OPERATION

3.5.2 DRAIN TIME of RPV water inventory to the top of active fuel (TAF) shall be > 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />

AND

At least one of the following shall be OPERABLE:

a. Core spray system (CSS) subsystem comprised of:

1. Two OPERABLE CSS pumps, and

2. An OPERABLE flow path capable of taking suction from at least one of the following water sources and transferring the water through the spray sparger to the reactor vessel:

a) From the suppression chamber, or

b) When the suppression chamber water level is less than the limit or is drained, from the condensate storage tank containing at least 135,000 available gallons of water, equivalent to a level of 29 feet.

b. Low pressure coolant injection (LPCI) system subsystem comprised of:

1. One OPERABLE LPCI pump, and

2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.**

APPLICABILITY: OPERATIONAL CONDITIONS 4 and 5.

ACTION:

a. With none of the above required subsystems OPERABLE, restore at least one subsystem to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Otherwise, initiate action to establish a method of water injection capable of operating without offsite electrical po wer.

b. DELETED

• • One LPCI subsystem may be considered OPERABLE during alignment and operation for d ecay heat removal if capable of being manually realigned and not otherwise inoperable.

LIMERICK - UNIT 1 3/4 5-6 Amendment No. 95, 227 264 ELECTRICAL POWER SYSTEMS

A.C. SOURCES - SHUTDOWN

LIMITING CONDITION FOR OPERATION

3.8.1.2 As a minimum, the following A.C. electrical power s ources shall be OPERABLE:

a. One circuit between the offsite transmission network and the onsite Class 1E distribution system, and

b. Two diesel generators each with:

1. A day fuel tank containing a minimum of 250 gallons of fuel.

2. A fuel stora ge system containing a minimum of 33,500 gallons of fuel.

3. A fuel transfer pump.

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5, and *.

ACTION:

a. With less than the above required A.C. electrical power sources OPERABLE, suspend CORE AL TERATIONS, handlin g of irradiated fuel in the secondary containment, and crane operations over the spent fuel storage pool when fuel assemblies are stored therein. In addition, when in OPERATIONAL CONDITION 5 with t he water level less than 22 feet above the reactor pressure vessel flange, immediately initiate corrective action to restore the required power sources to OPERABLE status as soon as practical.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS

4.8.1.2 At least the above required A.C. electrical power sources shall be demonstrated OPERABLE per Surveillance Requirements 4.8.1.1.1 and 4.8.1.1.2, except for 4.8.1.1.1.b, 4.8.1.1.2.e.4, 4.8.1.1.2.e.5, 4.8.1.1.2.e.6, 4.8.1.1.2.e.7, 4.8.1.1.2.e.8.b, 4.8.1.1.2.e.11, 4.8.1.1.2.e.12, 4.8.1.1.2.f, and 4.8.1.1.2.h.

• When handling irradiated fuel in the secondary containment.

LIMERICK - UNIT 1 3/4 8-9 Amendment No. 32, 192, 193, 227 264 3.4.9 REFUELING OPERATIONS

3/4.9.1 REACTOR MODE SWITCH LIMITING CONDITION FOR OPERATION

3.9.1 The reactor mode switch shall be OPERABLE and locked in the Refuel position.

When the reactor mode switch is locked in the Refuel position:

a. The Refuel position one-rod-out interlock shall be OPERABLE.

b. The following Refuel position interlocks shall be OPERABLE:

1. All rods in.

2. Refuel Platform (over-core) position.

3. Refuel Platform hoists fuel-loaded.

4. Service Platform hoist fuel-loaded (with Service Platform installed).

APPLICABILITY: OPERATIONAL CONDITION 5* **, OPERATIONAL CONDITIONS 3 AND 4.

ACTION:

a. With the reactor mode switch not locked in the Refuel position asspecified, suspend CORE ALTERATIONS and lock the reactor mode switch in the Refuel position.

b. With the one-rod-out interlock inoperable, fully insert all control rods and disable withdraw capabilities of all control rods ***.

c. With any of the above required Refuel Platform Refuel position interlocks inoperable, take one of the ACTIONS listed below, or suspend CORE ALTERATIONS.

1. Fully insert all control rods and disable withdraw capabilities ofall control rods***, or

2. Verify Refuel Platform is not over-core (limit switches not reached) and disable Refuel Platform travel over-core, or

3. Verify that no Refuel Platform hoist is loaded and disable all Refuel Platform hoists from picking up (grappling) a load.

d. With the Service Platform installed over the vessel and any of the aboverequired Service Platform Refuel position interlocks inoperable, take one of the ACTIONS listed below, or suspend CORE ALTERATIONS.

1. Fully insert all control rods and disable withdraw capabilities of all control rods***, or

2. Verify Service Platform hoist is not loaded and disable Service Platform hoist from picking up (grappling) a load.

• See Special Test Exceptions 3.10.1 and 3.10.3.

• • The reactor shall be maintained in OPERATIONAL CONDITION 5 whenever fuel isin the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.

• • • Except control rods removed per Specification 3.9.10.1 or 3.9.10.2.

LIMERICK - UNIT 1 3/4 9-1 Amendment No. 114, 149 264 REFUELING OPERATIONS

SURVEILLANCE REQUIREMENTS

4.9.1.1 The reactor mode switch shall be verified to be locked in the Refuel position as specified, in accordance with the Surveillance Frequency Control Program.

4.9.1.2 Each of the above required reactor mode switch Refuel position interlocks* shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST in accordance with the Surveillance Frequency Control Program during control rod withdrawal or CORE ALTERATIONS, as applicable.

4.9.1.3 Each of the above required reactor mode switch Refuel position interlocks* that is affected shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST prior to resuming control rod withdrawal or CORE ALTERATIONS, as applicable, following repair, maintenance or replacement of any component that could affect the Refuel position interlock.

• The reactor mode switch may be placed in the Run or Startup/Hot Standby position to test the switch interlock functions provided that all control rods are verified to remain fully inserted by a second licensed operator or other technically qualified member of the unit technical staff.

LIMERICK - UNIT 1 3/4 9-2 Amendment No. 109, 186 264 REFUELING OPERATIONS

MULTIPLE CONTROL ROD REMOVAL

LIMITING CONDITION FOR OPERATION

3.9.10.2 Any number of control rods and/or control rod drive mechanisms may be removed from the core and/or reactor pressure vessel provided that at least the following requirements are satisfied until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the core.

a. The reactor mode switch is OPERABLE and locked in the Refuel position per Specification 3.9.1, except that the Refuel position "one-rod-out" interlock may be bypassed, as required, for those control rods and/or control rod drive mechanisms to be removed, after the fuel assemblies have been removed as specified below.

b. The source range monitors (SRM) are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.

d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.

e. The four fuel assemblies surrounding each control rod or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

APPLICABILITY: OPERATIONAL CONDITION 5.

ACTION:

With the requirements of the above specification not satisfied, suspend removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and initiate action to satisfy the above requirements.

LIMERICK - UNIT 1 3/4 9-15 Amendment No. 264 REFUELING OPERATIONS

SURVEILLANCE REQUIREMENTS

4.9.10.2.1 Within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> prior to the start of removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and in accordance with the Surveillance Frequency Control Program thereafter until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the core, verify that:

a. The reactor mode switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Refuel position per Specification 3.9.1.

b. The SRM channels are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.

d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.

e. The four fuel assemblies surrounding each control rod and/or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

4.9.10.2.2 Following replacement of all control rods and/or control rod drive mechanisms removed in accordance with this specification, perform a functional test of the "one-rod-out" Refuel position interlock, if this function had been bypassed.

LIMERICK - UNIT 1 3/4 9-16 Amendment No. 186 264 CONSTELLATION ENERGY GENERATION, LLC

DOCKET NO. 50-353

LIMERICK GENERATING STATION, UNIT 2

AMENDMENT TO FACILITY OPERATING LICENSE

Amendment No. 226 Renewed License No. NPF-85

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

A. The application for amendment by Constellation Energy Generation, LLC (the licensee), dated February 17, 2023, as supplemented by letters dated July 21, 2023, July 31, 2023, August 16, 2023, October 19, 2023, April 18, 2024, May 28, 2024, and October 4, 2024, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations 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 Commissions regulations;

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 Commissions regulations and all applicable requirements have been satisfied.

Enclosure 2

- 2 -

2. Accordingly, the license is amended by changes to the Technical Specif ications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-85 is hereby amended to read as follo ws:

(2) Technical Specifications

The Technical Specifications contained in Appendix A and th e Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 226, are hereby incorporat ed into this renewed license. Constellation Energy Generation, LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protectio n Plan.

3. This license amendment is effective as of its date of issuance and shall be implemente d within 90 days.

FOR THE NUCLEAR REGULATORY COMMISSION

Hipólito González, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Facility Operating License

Date of Issuance: October 31, 2024 ATTACHMENT TO LICENSE AMENDMENT NO. 226

LIMERICK GENERATING STATION, UNIT 2

RENEWED FACILITY OPERATING LICENSE NO. NPF-85

DOCKET NO. 50-353

Replace the following page of the Renewed Facility Operating License with the revised page.

The revised page is identified by amendment number and contains marginal lines indicating the area of change.

Remove Insert

Page 3 Page 3

Replace the following pages of the Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert 3/4 1-20 3/4 1-20 3/4 3-3 3/4 3-3 3/4 3-4 3/4 3-4 3/4 3-5 3/4 3-5 3/4 3-8 3/4 3-8 3/4 3-8a 3/4 3-8a 3/4 3-12 3/4 3-12 3/4 3-17 3/4 3-17 3/4 3-28 3/4 3-28 3/4 3-31 3/4 3-31 3/4 3-34 3/4 3-34 3/4 3-35 3/4 3-35 3/4 3-36 3/4 3-36 3/4 3-36a 3/4 3-36a 3/4 3-41 3/4 3-41 3/4 3-42 3/4 3-42 3/4 5-6 3/4 5-6 3/4 8-9 3/4 8-9 3/4 9-1 3/4 9-1 3/4 9-2 3/4 9-2 3/4 9-15 3/4 9-15 3/4 9-16 3/4 9-16 REACTIVITY CONTROL SYSTEMS

SURVEILLANCE REQUIREMENTS (Continued)

b. In accordance with the Surveillance Frequency Control Program by:

1. Verifying the continuity of the explosive charge.

2. Determining by chemical analysis and calculation* that the to 185 lbs; the concentration of sodium pentaborate in solutiavailable weight of Boron-10 is greater than or equalon

is less than or equal to 13.8% and within the limits of Figure 3.1.5-1 and; the following equation is satisfied:

C x E x Q 1 where 13% wt. 29 atom % 86 gpm

C = Sodium pentaborate solution (% by weight)

Q = Two pump flowrate, as determined per surveillance requirement 4.1.5.c.

E = Boron 10 enrichment (atom % Boron 10)

3. Verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

4. Verifying that no more than two pumps are aligned for automatoperation.***ic

c. Demonstrating that, when tested pursuant to Specification 4.0.5, thminimum flow requirement of 37.0 gpm per pump at a pressure ofe

greater than or equal to 1230+/- 25 psig is met.

d. In accordance with the Surveillance Frequency Control Program by:

1. Initiating at least one of the standby liquid control systemloops, including an explosive valve, and verifying that a flow

path from the pumps to the reactor pressure vessel is available by pumping demineralized water into the reactor vessel. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch which has been certified by having one of the batch success-fully fired. All injection loops shall be tested in 3 operating cycles.

2. Verify all heat-treated piping between storage tank and pump suction is unblocked.**

e. Prior to addition of Boron to storage tank verify sodium pentaborate enrichment to be added is 49 atom % Boron 10.

• This test shall also be performed anytime water or boron is added to the solu-tion or when the solution temperature drops below the limits of Figure 3.1.5-1 for the most recent concentration analysis, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after water or boron addition or solution temperature is restored.

• • This test shall also be performed whenever suction piping temperature drops below the limits of Figure 3.1.5-1 for the most recent concentration analysis, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after solution temperature is restored.

• • • For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2027 refueling outage, no pumps are required to start automatically.

LIMERICK - UNIT 2 3/4 1-20 Amendment No. 24,26,34,48,51,146, 147, 163, 195 226

TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION

ACTIONSTATEMENTS

ACTION 1 - Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

ACTION 2 - Verify all insertable control rods to be inserted in the core and lock the reactor mode switch in the Shutdown position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

ACTION 3 - Immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

ACTION 4 - Be in at least STARTUP within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

ACTION 5 - Be in STARTUP with the main steam line isolation valves closed within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

ACTION 6 - Initiate a reduction in THERMAL POWER within 15 minutes and reduce turbine first stage pressure until the function is automatically bypassed, within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

ACTION 7 - Verify all insertable control rods to be inserted within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

ACTION 8 - Lock the reactor mode switch in the Shutdown position within 1hour.

ACTION 9 - Immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

ACTION 10 - a. If the condition exists due to a common-mode OPRM deficiency*,

then initiate alternate method to detect and suppress thermal-hydraulic instability oscillations within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> AND restore required channels to OPERABLE status within 120 days,

OR

b. Reduce THERMAL POWER to < 25% RATED THERMAL POWER within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

• Unanticipated characteristic of the instability detection algorithm or equipment that renders all OPRM channels inoperable at once.

LIMERICK - UNIT 2 3/4 3-4 Amendment No. 109,112,139, 161 226 TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> forrequired surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) This function shall automatically be bypassed when the reactor mode switch isin the Run position.

(c) DELETED (d) The noncoincident NMS reactor trip function logic is such that all channels goto both trip systems. Therefore, when the "shorting links" are removed, the Minimum OPERABLE Channels Per Trip System is 6 IRMs.

(e) An APRM channel is inoperable if there are less than 3 LPRM inputs per levelor less than 20 LPRM inputs to an APRM channel, or if more than 9 LPRM inputs to the APRM channel have been bypassed since the last APRM calibration (weekly gain calibration).

(f) This function is not required to be OPERABLE when the reactor pressurevessel head is removed per Specification 3.10.1.

(g) This function shall be automatically bypassed when the reactor mode switchis not in the Run position.

(h) This function is not required to be OPERABLE when PRIMARY CONTAINMENTINTEGRITY is not required.

(i) With any control rod withdrawn. Not applicable to control rods removed perSpecification 3.9.10.1 or 3.9.10.2.

(j) This function shall be automatically bypassed when turbine first stagepressure is equivalent to a THERMAL POWER of less than 29.5% of RATED THERMAL POWER.

(k) Also actuates the EOC-RPT system.

(l) DELETED (m) Each APRM channel provides inputs to both trip systems.

(n) DELETED (o) With THERMAL POWER shall be automatically enabled (not bypassed) when APRM Simulated Thermal Power 25% RATED THERMAL POWER. The OPRM Upscale trip output is 29.5% and recirculation drive flow is 60%. The OPRM trip output may be automatically bypassed when APRM Simulated Thermal Power is 29.5% or recirculation drive flow is 60%.

(p) A minimum of 23 cells, each with a minimum of 2 OPERABLE LPRMs, must beOPERABLE for an OPRM channel to be OPERABLE.

(q) With any control rod withdrawn from a core cell containing one or more fuelassemblies.

LIMERICK - UNIT 2 3/4 3-5 Amendment No. 7,17,109,139, 163 226

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION

MINIMUM APPLICABLE ISOLATION OPERABLE CHANNELS OPERATIONAL

TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b) CONDITION ACTION

3 REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCS Flow - High J 1 1, 2, 3 23

b. RWCS Area Temperature - High J 6 1, 2, 3 23

c. RWCS Area Ventilation Temperature - High J 6 1, 2, 3 23

d. SLCS Initiation(h) Y(d) NA 1, 2, 3 23

e. Reactor Vessel Water Level -

Low, Low - Level 2 B 2 1, 2, 3 23

f. Manual Initiation NA 1 1, 2, 3 24

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line Pressure - High L 1 1, 2, 3 23

b. HPCI Steam Supply Pressure - Low LA 2 1, 2, 3 23

c. HPCI Turbine Exhaust Diaphragm Pressure - High L 2 1, 2, 3 23

d. HPCI Equipment Room Temperature - High L 1 1, 2, 3 23

e. HPCI Equipment Room Temperature - High L 1 1, 2, 3 23

LIMERICK - UNIT 2 3/4 3-12 Amendment No. 3434 226 TABLE 3.3.2-1 (Continued)

TABLE NOTATIONS

(c) Actuates secondary containment isolation valves. Signal B, H, S, and R also start the standby gas treatment system.

(d) RWCU system inlet outboard isolation valve closes on SLCS "B" initiation.

RWCU system inlet inboard isolation valve closes on SLCS "A" or SLCS "C" initiation.

(e) Manual initiation isolates the steam supply line outboard isolation valve and only following manual or automatic initiation of the system.

(f) In the event of a loss of ventilation the temperature - high setpoint may be raised by 50°F for a period not to exceed 30 minutes to permit restoration of the ventilation flow without a spurious trip. During the 30 minute period, an operator, or other qualified member of the technical staff, shall observe the temperature indications continuously, so that, in the event of rapid increases in temperature, the main steam lines shall be manually isolated.

(g) Wide range accident monitor per Specification 3.3.7.5.

(h) For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2027 refueling outage, the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

LIMERICK - UNIT 2 3/4 3-17 Amendment No. 17, 74, 107 226 TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK (a) TEST (a) CALIBRATION(a) SURVEILLANCE REQUIRED

3. RE ACTOR WATE R CLE AN UP SYSTE M ISOLATION

a. RWCS Flow - High 1, 2, 3

b. RWCS Area Temp erature - High 1, 2, 3

c. RWCS Area Ventilation Temperature - High 1, 2, 3

d. SLCS Initiation(b) N.A. N.A. 1, 2, 3

e. Reactor Ves s el Water Lev el Low, Low, - Lev el 2 1, 2, 3

f. Manual Initiation N.A. N.A. 1, 2, 3

4. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION

a. HPCI Steam Line Pressure - High 1, 2, 3

b. HPCI Steam Supply Pressure, Low 1, 2, 3

c. HPCI Turbine Exhaust Diaphragm Pressure - High 1, 2, 3

d. HPCI Equipment Room Temperature - High 1, 2, 3

e. HPCI Equipment Room Temperature - High 1, 2, 3

f. HPCI Pipe Routing Area Temperature - High 1, 2, 3

g. Manual Initiation N.A. N.A. 1, 2, 3

h. HPCI Steam Line Pressure Timer N.A. 1, 2, 3

LIMERICK - UNIT 2 3/4 3-28 Amendment No. 17, 32, 147 226 TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS

CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK(a) TEST(a) CALIBRATION(a) SURVEILLANCE REQUIRED

7. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level Low, Low - Level 2 1, 2, 3

b. Drywell Pressure## - High 1, 2, 3

c.1. Refueling Area Unit 1 Ventilation Exhaust Duct Radiation - High *#

2. Refueling Area Unit 2 Ventilation Exhaust Duct Radiation - High *#

d. Reactor Enclosure Ventilation Exhaust Duct Radiation - High 1, 2, 3

e. Deleted

f. Deleted

g. Reactor Enclosure Manual Initiation N.A. N.A. 1, 2, 3

h. Refueling Area Manual Initiation N.A. N.A. *

(a) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

(b) For a period of 30 days preceding exit of OPERATIONAL CONDITION 1 at the start of the 2027 refueling outa ge, the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

• Required when handling RECENTLY IRRADIATED FUEL in the secondary containment.

• • When not administratively bypassed and/or when any turbine stop valve is open.

1. During operation of the associated Unit 1 or Unit 2 ventilation exhaust system.

1. 1. These trip functions (2a, 6b, and 7b) are common to the RPS actuation trip function.

LIMERICK - UNIT 2 3/4 3-31 Amendment No. 17, 32, 52, 74, 146, 147, 190 226 TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION

MINIMUM OPERABLE CHANNELS PER APPLICABLE TRIP OPERATIONAL TRIP FUNCTION FUNCTION (a) CONDITIONS ACTION

4. AUTOMATIC DEPRESSURIZATION SYSTEM#***

a. Reactor Vessel Water Level - Low Low Low, Level 1 2 1, 2, 3 30

b. Drywell Pressure - High 2 1, 2, 3 30

c. ADS Timer 1 1, 2, 3 31

d. Core Spray Pump Discharge Pressure - High (Permissive) 2 1, 2, 3 31

e. RHR LPCI Mode Pump Discharge Pressure High (Permissive) 4 1, 2, 3 31

f. Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1, 2, 3 31

g. Manual Initiation 2 1, 2, 3 33

h. ADS Drywell Pressure Bypass Timer 2 1, 2, 3 31

MINIMUM APPLICABLE TOTAL NO. CHANNELS CHANNELS OPERATIONAL OF CHANNELS(f) TO TRIP OPERABLE CONDITIONS ACTION

5. LOSS OF POWER

1. 4.16 kV Emergency Bus Under-voltage (Loss of Voltage) 1/bus 1/bus 1/bus 1, 2, 3 36

2. 4.16 kV Emergency Bus Under-voltage (Degraded Voltage) 1/source/ 1/source/ 1/source/ 1, 2, 3 37 bus bus bus

• • • The Minimum OPERABLE Channels Per Trip Function is per subsystem.

LIMERICK - UNIT 2 3/4 3-34 Amendment No.226 TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION TABLENOTATIONS

(a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) Also provides input to actuation logic for the associated emergency diesel generators.

(c) One trip system. Provides signal to HPCI pump suction valves only.

(d) On 1 out of 2 taken twice logic, provides a signal to trip the HPCI pump turbine only.

(e) The manual initiation push buttons start the respective core spray pump and diesel generator. The "A" and "B" logic manual push buttons also actuate an initiation permissive in the injection valve opening logic.

(f) A channel as used here is defined as the 127 bus relay for Item 1 and the 127, 127Y, and 127Z feeder relays with their associated time delay relays taken together for Item 2.

• DELETED

1. Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

• • DELETED

1. 1. Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.

1. 1. 1. The injection functions of Drywell Pressure - High and Manual Initiation are not required to be OPERABLE with reactor steam dome pressure less than 550 psig.

LIMERICK - UNIT 2 3/4 3-35 Amendment No. 17, 185, 190 226 TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTIONSTATEMENTS

ACTION 30 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. With one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program, or declare the associated system inoperable.

b. With more than one channel inoperable, declare the associated system inoperable.

ACTION 31 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, declare the associated ECCS inoperable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 32 - DELETED

ACTION 33 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program*, or declare the associated ECCS inoperable.

ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement:

a. For one channel inoperable, place the inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program, or declare the HPCI system inoperable.

b. With more than one channel inoperable, declare the HPCI system inoperable.

ACTION 35 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program*, or declare the HPCI system inoperable.

ACTION 36 - With the number of OPERABLE channels less than the Total Number of Channels, declare the associated emergency diesel generator and the associated offsite source breaker that is not supplying the bus inoperable and take the ACTION required by Specification 3.8.1.1.

• Not applicable when trip capability is not maintained.

LIMERICK - UNIT 2 3/4 3-36 Amendment No. 17,120,190, 203 226 TABLE 3.3.3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION ACTIONSTATEMENTS

ACTION 37 - With the number of OPERABLE channels one less than the Total Number of Channels, place the inoperable device in the bypassed condition subject to the following conditions:

Inoperable Device Condition

127-11X0X 127Y-11X0X and 127Z-11X0X operable 127Y-11X0X 127-11X0X and 127Z-11X0X operable 127Z-11X0X 127-11X0X and 127Y-11X0X operable.

127Z-11Y0Y operable for the other 3 breakers monitoring that source, offsite source grid voltage for that source is maintained at or above 230kV (for the 101 Safeguard Bus Source) or 525kV (for the 201 Safeguard Bus Source),

Load Tap Changer for that source is in service and in automatic operation, and the electrical buses and breaker alignments are maintained within bounds of approved plant procedures.

or, place the inoperable channel in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and take the Action required by Specification 3.8.1.1.

Operation may then continue until performance of the next required CHANNEL FUNCTIONAL TEST.

LIMERICK - UNIT 2 3/4 3-36a Amendment No. 120 226 TABLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL TRIP FUNCTION CHECK (a)CHANNEL FUNCTIONAL TEST (a) CALIBRATION(a)CHANNEL SURVEILLANCE REQUIREDCONDITIONS FOR WHICH

4. AUTOMATIC DEPRESSURIZATION SYSTEM#

a. Reactor Vessel Water Level -

b. Drywell Pressure Low Low Low, Level 1-High 1, 2, 3 1, 2, 3

c. ADS Timer N.A. 1, 2, 3

d. Core Spray Pump Discharge

e. RHR LPCI Mode Pump Discharge Pressure - High 1, 2, 3

f. Reactor Vessel Water Level Pressure - High 1, 2, 3 - Low,

g. Manual Initiation N.A. N.A. 1, 2, 3 Level 3 1, 2, 3

h. ADS Drywell Pressure Bypass Timer N.A. 1, 2, 3

5. LOSS OF POWER

a. 4.16 kV Emergency Bus Under voltage (Loss of Voltage)## N.A. N.A. 1, 2, 3

voltage (Degraded Voltage)b. 4.16 kV Emergency Bus Under-1, 2, 3

(a) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

• DELETED

• • D ELETED

• • • Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.

1. Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

1. 1. Loss of Voltage Relay 127-11X is not field setable.

LIMERICK - UNIT 2 3/4 3-41 Amendment No. 17, 147, 190 226 INSTRUMENTATION 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values shown in the Trip Setpoint column of Table 3.3.4.1-2.

APPLICABILITY: OPERATIONAL CONDITION 1.

Note: For a period of 30 days preceding exit of OPERATONAL CONDITION 1 at the start of the 2027 refueling outage, the LCO is not applicable when the following conditions are met.

Maxi mum Maximum InoperableMinimum Suppression THERMAL POW 90%RTP ER Safety/Relieve Valves 0 of 14 Pool Water Level23 feet 87%RTP 0 of 14 22 feet 84%RTP 1 of 14 22 feet Recirc Runback on Level 3 Function is Available and not in Bypass.

ACTION:

a. With an ATWS recirculation pump trip system instrumentation channetrip setpoint less conservative than the value shown in the Allowablle Values column of Table 3.3.4.1-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel trip setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by theMinimum OPERABLE Channels per Trip System requirement for one or both trip systems, place the inoperable channel(s) in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program*.

c. With the number of OPERABLE channels two or more less than requireby the Minimum OPERABLE Channels per Trip System requirement for oned trip system and:

1. If the inoperable channels consist of one reactor vessel watelevel channel and one reactor vessel pressure channel, place botrh inoperable channels in the tripped condition within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />sor in accordance with the Risk Informed Completion Time Program, or if this action will initiate a pump trip, declare the trip system inoperable.

2. If the inoperable channels include two reactor vessel water levelchannels or two reactor vessel pressure channels, declare the trip system inoperable.

d. With one trip system inoperable, restore the inoperable trip systeto OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk m Informed Completion Time Program, or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

e. With both trip systems inoperable, restore at least one trip systeto OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least STARTUP within m the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.3.4.1.1 Each of the required ATWS recirculation pump trip system instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillance Frequency Control Program.

4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed in accordance with the Surveillance Frequency Control Program.

• Not applicable when trip capability is not maintained.

LIMERICK - UNIT 2 3/4 3-42 Amendment No. 33,34,147, 203 226 EMERGENCY CORE COOLING SYSTEMS

3/4.5.2 REACTOR PRESSURE VESSEL (RPV) WATER INVENTORY CONTROL (WIC)

LIMITING CONDITION FOR OPERATION

3.5.2 DRAIN TIME of RPV water inventory to the top of active fuel (TAF) shall be > 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />

AND

At least one of the following shall be OPERABLE:

a. Core spray system (CSS) subsystem comprised of:

1. Two OPERABLE CSS pumps, and

2. An OPERABLE flow path capable of taking suction from at least one of the following water sources and transferring the water through the spray sparger to the reactor vessel:

a) From the suppression chamber, or

b) When the suppression chamber water level is less than the limit or is drained, from the condensate storage tank containing at least 135,000 available gallons of water, equivalent to a level of 29 feet.

b. Low pressure coolant injection (LPCI) system subsystem comprised of:

1. One OPERABLE LPCI pump, and

2. An OPERABLE flow path capable of taking suction from the suppression chamber and transferring the water to the reactor vessel.**

APPLICABILITY: OPERATIONAL CONDITIONS 4 and 5.

ACTION:

a. With none of the above required subsystems OPERABLE, restore at least one subsystem to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Otherwise, initiate action to establish a method of water injection capable of operating without offsite electrical power.

b. DELETED.

• • One LPCI subsystem may be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned and not otherwise inoperable.

LIMERICK - UNIT 2 3/4 5-6 Amendment No. 59, 190 226 ELECTRICAL POWER SYSTEMS

A.C. SOURCES - SHUTDOWN

LIMITING CONDITION FOR OPERATION

3.8.1.2 As a minimum, the following A.C. electrical power sources shall be OPERABLE:

a. One circuit between the offsite transmission network and the onsite Class 1E distribution system, and

b. Two diesel generators each with:

1. A day fuel tank containing a minimum of 250 gallons of fuel.

2. A fuel storage system containing a minimum of 33,500 gallons of fuel.

3. A fuel transfer pump.

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5, and *.

ACTION:

a. With less than the above required A.C. electrical power sources OPERABLE, suspend CORE ALTERATIONS, handling of irradiated fuel in the secondary containment, and crane operations over the spent fuel storage pool when fuel assemblies are stored therein. In addition, when in OPERATIONAL CONDITION 5 with the water level less than 22 feet above the reactor pressure vessel flange, immediately initiate corrective action to restore the required power sources to OPERABLE status as soon as practical.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS

4.8.1.2 At least the above required A.C. electrical power sources shall be demonstrated OPERABLE per Surveillance Requirements 4.8.1.1.1 and 4.8.1.1.2, except for 4.8.1.1.1.b, 4.8.1.1.2.e.4, 4.8.1.1.2.e.5, 4.8.1.1.2.e.6, 4.8.1.1.2.e.7, 4.8.1.1.2.e.8.b,4.8.1.1.2.e.11, 4.8.1.1.2.e.12, 4.8.1.1.2.f and 4.8.1.1.2.h.

• When handling irradiated fuel in the secondary containment.

LIMERICK - UNIT 2 3/4 8-9 Amendment No. 153, 154, 190 226 3.4.9 REFUELING OPERATIONS 3/4.9.1 REACTOR MODE SWITCH LIMITING CONDITION FOR OPERATION

3.9.1 The reactor mode switch shall be OPERABLE and locked in the Refuel position.

When the reactor mode switch is locked in the Refuel position:

a. The Refuel position one-rod-out interlock shall be OPERABLE.

b. The following Refuel position interlocks shall be OPERABLE:

1. All rods in.

2. Refuel Platform (over-core) position.

3. Refuel Platform hoists fuel-loaded.

4. Service Platform hoist fuel-loaded (with Service Platform installed).

APPLICABILITY: OPERATIONAL CONDITION 5* **, OPERATIONAL CONDITIONS 3 AND 4.

ACTION:

a. With the reactor mode switch not locked in the Refuel position asspecified, suspend CORE ALTERATIONS and lock the reactor mode switch in the Refuel position.

b. With the one-rod-out interlock inoperable, fully insert all control rods and disable withdraw capabilities of all control rods ***.

c. With any of the above required Refuel Platform Refuel position interlocks inoperable, take one of the ACTIONS listed below, or suspend CORE ALTERATIONS.

1. Fully insert all control rods and disable withdraw capabilities ofall control rods***, or

2. Verify Refuel Platform is not over-core (limit switches notreached) and disable Refuel Platform travel over-core, or

3. Verify that no Refuel Platform hoist is loaded and disable allRefuel Platform hoists from picking up (grappling) a load.

d. With the Service Platform installed over the vessel and any of the aboverequired Service Platform Refuel position interlocks inoperable, take one of the ACTIONS listed below, or suspend CORE ALTERATIONS.

1. Fully insert all control rods and disable withdraw capabilities ofall control rods***, or

2. Verify Service Platform hoist is not loaded and disable ServicePlatform hoist from picking up (grappling) a load.

• See Special Test Exceptions 3.10.1 and 3.10.3.

• • The reactor shall be maintained in OPERATIONAL CONDITION 5 whenever fuel is in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the head removed.

• • • Except control rods removed per Specification 3.9.10.1 or 3.9.10.2.

LIMERICK - UNIT 2 3/4 9-1 Amendment No. 76, 112 226 REFUELING OPERATIONS

SURVEILLANCE REQUIREMENTS

4.9.1.1 The reactor mode switch shall be verified to be locked in the Refuel position as specified in accordance with the Surveillance Frequency Control Program.

4.9.1.2 Each of the above required reactor mode switch Refuel position interlocks* shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST in accordance with the Surveillance Frequency Control Program during control rod withdrawal or CORE ALTERATIONS, as applicable.

4.9.1.3 Each of the above required reactor mode switch Refuel position interlocks* that is affected shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST prior to resuming control rod withdrawal or CORE ALTERATIONS, as applicable, following repair, maintenance or replacement of any component that could affect the Refuel position interlock.

• The reactor mode switch may be placed in the Run or Startup/Hot Standby position to test the switch interlock functions provided that all control rods are verified to remain fully inserted by a second licensed operator or other technically qualified member of the unit technical staff.

LIMERICK - UNIT 2 3/4 9-2 Amendment No. 72, 147 226 REFUELING OPERATIONS

MULTIPLE CONTROL ROD REMOVAL

LIMITING CONDITION FOR OPERATION

3.9.10.2 Any number of control rods and/or control rod drive mechanisms may be removed from the core and/or reactor pressure vessel provided that at least the following requirements are satisfied until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the core.

a. The reactor mode switch is OPERABLE and locked in the Refuel position per Specification 3.9.1, except that the Refuel position "one-rod-out" interlock may be bypassed, as required, for those control rods and/or control rod drive mechanisms to be removed, after the fuel assemblies have been removed as specified below.

b. The source range monitors (SRM) are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.

d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.

e. The four fuel assemblies surrounding each control rod or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

APPLICABILITY: OPERATIONAL CONDITION 5.

ACTION:

With the requirements of the above specification not satisfied, suspend removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and initiate action to satisfy the above requirements.

LIMERICK - UNIT 2 3/4 9-15 Amendment No. 147 226 REFUELING OPERATIONS

SURVEILLANCE REQUIREMENTS

4.9.10.2.1 Within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> prior to the start of removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and in accordance with the Surveillance Frequency Control Program thereafter until all control rods and control rod drive mechanisms are reinstalled and all control rods are inserted in the core, verify that:

a. The reactor mode switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Refuel position per Specification 3.9.1.

b. The SRM channels are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.

d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.

e. The four fuel assemblies surrounding each control rod and/or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

4.9.10.2.2 Following replacement of all control rods and/or control rod drive mechanisms removed in accordance with this specification, perform a functional test of the "one-rod-out" Refuel position interlock, if this function had been bypassed.

LIMERICK - UNIT 2 3/4 9-16 Amendment No. 147 226 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION

RELATED TO AMENDMENT NOS. 264 AND 226

TO RENEWED FACILITY OPERATING LICENSE NOS. NPF-39 AND NPF-85

CONSTELLATION ENERGY GENERATION, LLC

LIMERICK GENERATING STATION, UNITS 1 AND 2

DOCKET NOS. 50-352 AND 50-353

1.0 INTRODUCTION

By application dated February 17, 2023, as supplemented by letters dated July 21, 2023, July 31, 2023, August 16, 2023, October 19, 2023, April 18, 2024, May 28, 2024, and October 4, 2024 (Agencywide Documents Access and Management System (ADAMS)

Accession Nos. ML23052A023, ML23202A219, ML23212B105, ML23228A094, ML23292A074, ML24109A070, ML24149A211, and ML24278A302, respectively), Constellation Energy Generation, LLC (Constellation, the licensee), requested changes to the Technical Specifications (TSs) for Limerick Generating Station (Limerick), Units 1 and 2. The proposed amendments would revise the Applicability" of Technical Specification (TS) 3/4.3.4, ATWS (Anticipated Transient Without Scram) Recirculation Pump Trip (RPT) Actuation Instrumentation, to add a note stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), the limiting condition for operation (LCO) is not applicable if specified conditions are met. The proposed amendments would support the installation of digital modifications at Limerick Unit 1 and U nit 2 during aforementioned refueling outages.

The supplements dated July 21, 2023, July 31, 2023, August 16, 2023, October 19, 2023, April 18, 2024, May 28, 2024, and October 4, 2024 provided additional information that clarified the application, did not expand the scope of the application as originally noticed. The supplements dated July 21, 2023, July 31, 2023, and August16, 2023 were included in the Nuclear Regulatory Commission (NRC) staffs original proposed no significant hazards consideration determination as published in the Federal Register (FR) on October 27, 2023 (88 FR 73883), and the supplements dated October 19, 2023, April 18, 2024, May 28, 2024, and October 4, 2024 did not change the original no significant hazards consideration determination.

1.1 Description of Proposed Changes

In the license amendment request (LAR), the licensee proposed multiple changes to the plants technical specifications that are either: (1) applicable during cold shutdown and refueling or

Enclosure 3

(2) involve system or components needed to mitigate an ATWS. In the LAR, Constellation described the proposed changes as:

1. Incorporate additional TS changes associated with Technical Specification Task Force (TSTF) Traveler 542, Revision 2, Reactor Pressure Vessel Water Inventory Control, (TSTF-542), TSTF Traveler 582, Revision 0, RPV [reactor pressure vessel] WIC [water inventory control] Enhancements, (TSTF-582)

(ML19240A260), and TSTF Traveler 583-T, TSTF-582 Diesel Generator Variation (TSTF-583-T) which were not included when the licensee originally adopted TSTF-542 and TSTF-582:

a. Revise TS 3.5.2, Action a. to delete the requirement to suspend Core Alterations when the required low pressure Emergency Core Cooling System (ECCS) subsystem is inoperable.

b. Revise TS 3.3.3, Emergency Core Cooling System Actuation Instrumentation, and TS 3.8.1.2, A.C. [alternating current] Sources -

Shutdown, to not require automatic start and loading of a diesel generator (DG) and sequenced loading of the emergency electrical busses in OPERATIONAL CONDITION (OPCON) 4 and 5.

The combination of TSTF-582 and TSTF-583-T were originally approved by letter from Victor Cusumano to the Technical Specifications Task Force, Model Safety Evaluation of Technical Specifications Task Force Traveler TSTF-582, Revision 0, RPV WIC Enhancements and TSTF-583-T, Revision 0, TSTF-582 Diesel Generator Variation, Using the Consolidated Line Item Improvement Process, dated October 9, 2020 (ADAMS Package ML20266G291).

2. Revise TS 3.3.1, Reactor Protection System Instrumentation, OPCON 5 applicability for the Reactor Mode Swit ch - Shutdown Position and Manual Scram instrumentation functions to not require these functions to be operable unless any control rods are withdrawn from a core cell containing one or more fuel assemblies, which is consistent with the standard technical specification (STS) requirements. The TS Actions applicable when these functions are not operable in OPCON 5 are revised to be consistent with the STS requirements.

3. Revise TS 3.9.1, Reactor Mode Switch, to eliminate references to the Shutdown position of the reactor mode switch and make complimentary changes to TS 3.9.10.2, Multiple Control Rod Removal, to be consistent with the Limerick design and the STS requirements. In addition, to improve clarity, Actions b, c, and d would be revised to replace the phrase Verify control rods are fully inserted with Fully insert all control rods.

4. Revise the Applicability of TS 3/4.3.4, ATWS (Anticipated Transient Without Scram) Recirculation Pump Trip (RPT) Actuation Instrumentation, to add a note stating that for a License Amendment Request period of 30 days preceding exit of OPCON 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), the LCO is not applicable if specified conditions are met. A table with these conditions is included as part of the note.

5. Revise Surveillance Requirement (SR) 4. 1.5, Standby Liquid Control System to add a footnote stating that for a period of 30 days preceding exit from OPCON 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), no pumps are required to start automatically.

6. Revise TS Table 3.3.2-1, Isolation Instrumentation, Trip Function 3.d, SLCS

[standby liquid control system] Initiation, to add a footnote stating that for a period of 30 days preceding exit from OPCON 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

7. Revise SR Table 4.3.2.1-1, Isolation Actuation Instrumentation Surveillance Requirements, Trip Function 3.d, SLCS Initiation, to add a note stating that for a period of 30 days preceding exit from OPCON 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), the Reactor Water System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

Proposed changes 1 through 3 are the proposed changes to the plants technical specifications that are applicable during cold shutdown and refueling. Proposed changes 4 through 7 are the proposed changes to the plants technical specifications that involve system or components needed to mitigate an ATWS.

2.0 REGULATORY EVALUATION

2.1 Applicable Requirements

In Title 10 of the Code of Federal Regulation (10 CFR) Section 50.36, Technical Specifications, the NRC established its regulatory requirements related to the content of TSs. Pursuant to 10 CFR 50.36, TSs are required to include items in the following five specific categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) Limiting conditions of operation (LCO); (3) Surveillance requirements (SRs); (4) design features; and (5) administrative controls. The rule does not specify the specific requirements to be included in a plants TSs. The regulation also states, in part, that [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. As stated in 10 CFR Paragraph 50.36(c)(2)(i), the 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. Paragraph 50.36(c)(3) of 10 CFR requires TSs to include SRs, which are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the LCOs will be met.

By convention, the LCOs are contained in Sections 3.1 through 3.10 of the STS. For Limerick Unit 1 and Unit 2, this equates to Sections 3/4.1 through 3/4.12 in their plant TS.

TS Section 3/4.0, on LCO and SR Applicability, provides details or ground rules for complying with the LCOs. Each TS LCO contains the Applicability for the LCO, any Actions and associated

Completion Times that are allowed when the LCO is not met, and SRs that together provide the details or ground rules for complying with the LCOs.

Section 50.62 of 10 CFR, Requirements for reduction of risk from anticipated transients without scram (ATWS) events for light-water-cooled nuclear power plants, requires, in part, that each boiling water reactor:

(c)(3) Must have an alternate rod injection (ARI) system that is diverse (from the reactor trip system) from sensor output to the final actuation device.

(c)(4) Must have a standby liquid control system (SLCS) with the capability of injecting into the reactor pressure vessel a borated water solution at such a flow rate, level of boron concentration and boron-10 isotope enrichment, and accounting for reactor pressure vessel volume, that the resulting reactivity control is at least equivalent to that resulting from injection of 86 gallons per minute of 13 weight percent sodium pentaborate decahydrate solution. The SLCS initiation must be automatic and must be designed to perform its function in a reliable manner.

(c)(5) Must have equipment to trip the reactor coolant recirculating pumps (RPT) automatically under conditions indicative of an ATWS. This equipment must be designed to perform its function in a reliable manner.

The NRC staff reviewed the LAR to assess whet her the proposed change would be consistent with current regulations. The NRC staff noted that the licensee requested a specific exemption under 10 CFR 50.12 to allow for the proposed change to be implemented. The exemption request seeks a one-time per unit 30-day exemption from all requirements of 10 CFR 50.62(c)(3) and a partial exemption to the automatic requirements of 50.62(c)(4) and (c)(5). During the 30-day exemption period the plant will not be required to have ARI capability and will not be required to have automatic SLCS and RPT capability but will still be required to have manually actuated SLCS and RPT capability available to mitigate an ATWS.

2.2 Applicable Regulatory Guidance

The guidance that the NRC staff considered in its review of this LAR included the NRC staffs guidance for the review of TSs in Chapter 16.0, Technical Specifications, of NUREG-0800, Revision 3, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR [Light-Water Reactor] Edition (SRP), dated March 2010 (ML100351425). As described in the SRP, as part of the regulatory standardization effort, the NRC staff has prepared STSs for each of the light water reactor nuclear designs. Accordingly, the NRC staffs review includes consideration of whether the proposed changes are consistent with the applicable STSs (i.e., the current STS), as modified by NRC-approved changes called travelers.

In addition, the guidance states that comparing the change to previous STS can help clarify the TS intent. The current STS that are applicable to the licensees facility is NUREG-1433, Standard Technical Specifications, General Electric BWR/4 Plants, Volume 1, Specifications, and Volume 2, Bases, Revision 5.0, dated September 2021 (ML21272A357 and ML21272A358, respectively).

In conducting reviews of the human factors engineering (HFE) aspects of licensing submittals for light water reactor facilities, the NRC staff apply the guidance of NUREG-0800, specifically Chapter 18 of the SRP, Revision 3, Human Factors Engineering, which provides guidance for the review of HFE considerations of plant modifications and important human actions. SRP

Chapter 18 Section IV, Review Procedures, states, in part, that [t]he degree to which the NRC staff applies the review methodology in this SRP will reflect the specific circumstances of individual applications.

For circumstances involving both changes result ing from plant modifications and the evaluation of important human actions, SRP Chapter 18 provide guidance regarding the use of NUREG-1764, Guidance for the Review of Changes to Human Actions, Revision 1. This document provides guidance for reviewing changes in human actions, such as those that are credited in nuclear power plant safety analyses. Section 4.1 of NUREG-1764 provides review guidance for verifying that certain deterministic aspects of the change have been appropriately considered by the licensee. The criteria of this section include confirming that the licensee has provided adequate assurance that the change meets current regulations, except where specific exemptions are requested under 10 CFR 50.12. Additionally, criteria are also included for confirming that the licensee has provided adequate assurance that the change does not compromise defense-in-depth as it relates to the preservation of defenses against human errors.

While not directly applicable to the changes proposed under the LAR, NUREG-1852, Demonstrating the Feasibility and Reliability of Operator Manual Actions in Response to Fire, dated October 2007, provides reviewer guidance for assessing the adequacy of time margins associated with the completion of manual operator actions.

3.0 TECHNICAL EVALUATION

Some of the proposed changes in the LAR are related to a specified OPCON at Limerick.

OPCONs are used at Limerick instead of the operating Modes used in the STS. Accordingly, the NRC staff compared the Limerick TS OPCONs to the operating Modes in the STS. The NRC staff determined that each OPCON is equivalent to the corresponding Mode in the STS. For instance, OPCON 5 for Limerick is equivalent to Mode 5 in the STS.

The NRC staff reviewed the HFE-related aspects of the applicants LAR using the guidance of NUREG-1764.

3.1 Evaluation of Proposed Change 1

Proposed Revision to TS 3.5.2, RPV WIC Action a

Prior to the licensees adoption of TSTF-542, Section 3.5.2 of the licensees TS was entitled ECCS - Shutdown and contained requirements specifying which ECCS subsystems were required to be operable during shutdown. Action b in 3.5.2 of the licensees TS prior to adoption of TSTF-542 specified that if none of the required ECCS subsystems were operable, the licensee was required to suspend all operations with the potential to drain the reactor vessel (OPDRVs) and all CORE ALTERATIONS. These actions were consistent with the Actions specified in the NUREG-0123 General Electric Standard Technical Specifications on which the Limerick TSs were originally modeled. Howeve r, when the improved STS (NUREG-1433) were developed, this Required Action was changed to only require suspension of OPDRVs in the STS. This change to the STS was acceptable because if injection sources are unavailable, taking action to prevent a drain down event is an appropriate action. Suspension of CORE ALTERATIONS, on the other hand, does not support the restoration of coolant injection sources, so its removal was deemed to be acceptable. When the licensee adopted TSTF-542, TS 3.5.2 Action b of the licensees TS was revised to focus on reactor pressure vessel water

inventory control. As noted by the licensee, since the action to suspend core alterations had been removed in the original revision of the improved STS, TSTF-542 did not address removal of this action, and it was retained and moved to Action a in the licensees TS as part of their license amendment that adopted TSTF-542.

Limiting condition for operation 3.5.2, under TS 3/4.5.2, Reactor Pressure Vessel (RPV) Water Inventory Control (WIC), requires the licensee to maintain RPV water inventory such that the drain time to the top of active fuel (TAF) is at least 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> and that they must have at least one ECCS subsystem operable. Action a provides the actions to be taken when none of the required ECCS subsystems is operable. It currently requires the licensee to immediately suspend CORE ALTERATIONS and to restore a water injection source. The licensee is proposing to delete the requirement to suspend CORE ALTERATIONS and retain the requirement to restore a water injection source. The licensee asserted that removal of the suspension of CORE ALTERATIONS action from TS 3.5.2 would be acceptable because:

Suspension of Core Alterations would have no effect on the initiation of a draining event or the ability to respond to a draining event. All requirements necessary to maintain the RPV water level above the TAF are established with the combination of a new TS definition for Drain Time, a revised and renamed TS 3.5.2, Reactor Pressure Vessel (RPV) Water Inventory Control, and a new instrumentation TS 3.3.5.2, Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation. Therefore, the proposed elimination of the requirement to suspend Core Alterations does not affect the prevention or mitigation of an unplanned RPV draining event.

The NRC staff reviewed the licensees proposed change and associated technical justification and concluded that removal of the requirement to suspend CORE ALTERATIONS from Action a of TS 3.5.2 would have no impact on safety since the action to suspend CORE ALTERATIONS would neither prevent nor mitigate a loss of reactor pressure vessel water inventory or the loss of a required ECCS coolant injection source. In addition, the change is consistent with Revision 5 of the STS (NUREG-1433, Standard Technical Specifications, General Electric BWR/4 Plants, Revision 5, September 2021). The NRC staff concludes that the LCO 3.5.2 Actions will continue to provide acceptable re medial actions and LCO 3.5.2 will continue to provide for the lowest functional capability or performance levels of equipment required for safe operation of the facility. Therefore, the proposed change to LCO 3.5.2 meets the LCO requirements of 10 CFR 50.36(c)(2) and is acceptable.

The NRC staff also notes that requirements pertaining to suspension of CORE ALTERATIONS are appropriately addressed in other LCOs in the Limerick TS. For example, LCO 3.1.1 Action c requires suspension of CORE ALTERATIONS when shutdown margin is not within limits.

Proposed Revision to Adopt Portions of TSTF-582 and TSTF-583-T Related to TS 3.3.3 and 3.8.1.2

The licensee proposed changes to revise Limerick TS 3.3.3, Emergency Core Cooling System Actuation Instrumentation, and TS 3.8.1.2, A.C. Sources - Shutdown, to not require automatic start and loading capability of an emergency diesel generator (EDG) and sequenced loading of the emergency electrical busses in OPCON 4 and 5. These proposed changes were not previously included in their prior license amendment to adopt TSTF-582 and TSTF-583-T. The specific changes proposed are:

TS 3.3.3-1, Emergency Core Cooling System Actuation Instrumentation, Table 3.3.3-1 trip function 5.1, 4.16 kV Emergency Bus Under-Voltage (Loss of Voltage), and trip function 5.2, 4.1.6 kV Emergency Bus Under-voltage (Degraded Voltage), would be revised to remove the requirement for the loss of voltage and degraded voltage functions to be operable in OPCONs 4 and 5. The functions would still be required in OPCONs 1, 2, and 3. A corresponding change is proposed for the Table 3.3.3-1 Note **

that states, Required when ESF [engineered safety feature] equipment is required to be OPERABLE. This note only applies to trip functions 5.1 and 5.2 in OPCONs 4 and 5, so it would be removed.

TS Table 3.3.3-1, Actions 36 and 37, require the licensee to take the ACTION required by Specification 3.8.1.1 or 3.8.1.2, as appropriate. The Actions would be revised to only require the licensee to take the ACTION required by Specification 3.8.1.1.

Table 4.3.3.1-1, Emergency Core Cooling System Actuation Instrumentation Surveillance Requirements trip Function 5.a, 4.16 kV Emergency Bus Under-Voltage (Loss of Voltage), and Function 5.b, 4.1.6 kV Emergency Bus Under-voltage (Degraded Voltage), would be revised to remove the requirement for the loss of voltage and degraded voltage surveillances to be met in OPCONs 4 and 5. A corresponding change would be made to the Table 4.3.3.1-1, Note ** that states, Required OPERABLE when ESF equipment is required to be OPERABLE. The note only applies to trip functions 5.a and 5.b in OPCONs 4 and 5, so it would be removed.

Consistent with the proposed changes to the degraded and loss of voltage instrumentation functions listed above, SR 4.8.1.2 would be modified to identify SRs not required in OPCONs 4 and 5 and during refueling. SR 4.8.1.2 currently requires all required A.C. electrical sources to be demonstrated to operable by performing the surveillances in SRs 4.8.1.1.1 and 4.8.1.1.2. It approved, it would be modified to state, At least the above required A.C. electrical power sources shall be demonstrated OPERABLE per SR 4.8.1.1.1 and 4.8.1.1.2, except for 4.8.1.1.1.b, 4.8.1.1.2.e.4, 4.8.1.1.2.e.5, 4.8.1.1.2.e.6, 4.8.1.1.2.e.7, 4.8.1.1.2.e.8.b, 4.8.1.1.2.e.11, 4.8.1.1.2.e.12, 4.8.1.1.2.f, and 4.8.1.1.2.h. [Note: proposed changes to the SR 4.8.1.2 are shown in italics]

The licensee provided the following technical basis for the requested revisions for Tables 3.3.3-1 and 4.3.3.1-1:

The TSFT-582 and TSTF-583-T proposed changes will facilitate outage installation of the DMP [Digital Modernization Project] PPS [Plan Protection System] digital LAR when ECCS logic is out of service and complying with current TS requirements for Loss of Power (LOP) Instrumentation or Emergency Diesel Generator (EDG) auto start operability/SR performance during outage will become problematic. There are no accidents or transients analyzed in Mode 4 Cold Shutdown or Mode 5 Refueling which require the automatic start of a diesel generator. Therefore, the supporting instrumentation for the automatic start is not required in those modes of operation and the ability to manually start the diesel is the function which is maintained OPERABLE as a result of the proposed changes.

And

There are no accidents or transients postulated to occur in OPCONs 4 and 5 that assume a concurrent loss of offsite power and the automatic start of a DG.

TSTF-583-T revised the Applicability of these functions to not be applicable in Modes 4 and 5 because there is no assumption that the DG will automatically start on a loss of power in these modes. This logic is equally applicable to LGS

[Limerick Generating Station] in OPCONs 4 and 5. In these OPCONs, an operator can manually start a DG and connect the required loads assuming either a loss of all offsite power or a loss of all onsite DG power. Therefore, these functions should not be required to be operable in these OPCONs.

The NRC staff reviewed the Limerick, Units 1 and 2, Updated Final Safety Analysis Report (UFSAR) to determine if there are any accidents in OPCONS 4 and 5 and while moving fuel that require automatic start of the EDGs. The NRC staff finds that for Limerick, Units 1 and 2, there are no analyzed accidents or transients that assume a concurrent loss of offsite power or rely on automatic initiation of the EDGs. Therefore, consistent with the approved TSTF-583-T, the proposed revisions to Tables 3.3.3-1 and 4.3.3.1-1 to remove the requirement for the under-voltage and degraded voltage instrumentation to be operable in OPCONS 4 and 5 and during refueling is acceptable. The corresponding removal of the Note ** from Tables 3.3.3-1 and 4.3.3.1-1 and the proposed revisions to Actions 36 and 37 are also acceptable since the removed information in the Notes and Actions pertain to operability in OPCONS 4 and 5 that will no longer be applicable when the proposed changes to Tables 3.3.3-1 and 4.3.3.1-1 are incorporated into the Limerick TS. Based on the above, the NRC staff concludes that the proposed changes are consistent with the Limerick accident analysis and that the LCO applicability changes will continue to provide for the lowest functional capability or performance levels of equipment required for safe operation of the facility and, therefore, meet the LCO requirements of 10 CFR 50.36(c)(2).

Consistent with the removal of the EDG under-voltage and degraded voltage operability requirements during shutdown, TSTF-582 and TSTF-583-T modified STS SR 3.8.2.1 to exclude the requirement to perform those SRs that that tested EDG automatic start and loading during shutdown and refueling (i.e., during Modes 4 and 5 and during movement of [recently] irradiated fuel assemblies in the [secondary] containment). Specifically, STS SRs 3.8.1.8, 3.8.1.11, 3.8.1.12, 3.8.1.13, 3.8.1.15, 3.8.1.17, 3.8.1.18, 3.8.1.19, and 3.8.1.20 are excluded from being required during Modes 4 and 5 and during movement of fuel. Limerick does not have standard TS. Accordingly, in the LAR, Section 3.2, the licensee provided an evaluation comparing their surveillances in Limerick SR 4.8.1.2 with those in the STS SR 3.8.2.1. Table 1 in the LAR provides the results of their evaluation and is shown below:

Table 1 Comparison of LGS [Limerick Generating Station] and STS A.C. Sources SRs LGS SR STS Required to be Met Proposed Exception Equivalent SR by STS SR 3.8.2.1? to LGS SR 4.8.1.2?

4.8.1.1.1.a 3.8.1.1 Yes No 4.8.1.1.1.b 3.8.1.8 No Yes 4.8.1.1.2.a.1 3.8.1.4 Yes No 4.8.1.1.2.a.2 3.8.3.1 N/A No 4.8.1.1.2.a.3 3.8.1.6 Yes No 4.8.1.1.2.a.4 3.8.1.2 Yes No

Table 1 Comparison of LGS [Limerick Generating Station] and STS A.C. Sources SRs LGS SR STS Required to be Met Proposed Exception Equivalent SR by STS SR 3.8.2.1? to LGS SR 4.8.1.2?

4.8.1.1.2.a.5 3.8.1.3 Yes No 4.8.1.1.2.a.6 None N/A No 4.8.1.1.2.a.7 3.8.3.4 N/A No 4.8.1.1.2.b.1 3.8.1.5 Yes No 4.8.1.1.2.b.2 3.8.3.5 N/A No 4.8.1.1.2.c 3.8.3.3 N/A No 4.8.1.1.2.d 3.8.3.3 N/A No 4.8.1.1.2.e.1 (deleted) N/A N/A N/A 4.8.1.1.2.e.2 3.8.1.9 Yes No 4.8.1.1.2.e.3 3.8.1.10 Yes No 4.8.1.1.2.e.4 3.8.1.11 No Yes 4.8.1.1.2.e.5 3.8.1.12 No Yes 4.8.1.1.2.e.6 3.8.1.19 No Yes 4.8.1.1.2.e.7 3.8.1.13 No Yes 4.8.1.1.2.e.8.a 3.8.1.14 Yes No 4.8.1.1.2.e.8.b 3.8.1.15 No Yes 4.8.1.1.2.e.9 None N/A No 4.8.1.1.2.e.10 3.8.1.16 Yes No 4.8.1.1.2.e.11 3.8.1.17 No Yes 4.8.1.1.2.e.12 3.8.1.18 No Yes 4.8.1.1.2.e.13 None N/A No 4.8.1.1.2.f 3.8.1.20 No Yes 4.8.1.1.2.g None N/A No 4.8.1.1.2.h 3.8.1.7 No Yes 3.8.1.11 3.8.1.12 3.8.1.19 4.8.1.1.3 (deleted) N/A N/A N/A

The NRC staff compared the licensees SRs in 4.8.1.2 with the STS SRs in 3.8.2.1. and finds the results of the licensees comparison to be valid. Specifically, the identified Limerick SRs 4.8.1.1.1.b, 4.8.1.1.2.e.4, 4.8.1.1.2.e.5, 4.8.1.1.2.e.6, 4.8.1.1.2.e.7, 4.8.1.1.2.e.8.b, 4.8.1.1.2.e.11, 4.8.1.1.2.e.12, 4.8.1.1.2.f, and 4.8.1.1.2.h are equivalent to the STS SRs not required to be performed during Modes 4 and 5 and during fuel movement.

In its October 9, 2020 (ML20265A115), approval letter for TSTF-582 and TSTF-583-T, the NRC staff stated:

By letter dated August 28, 2019 (Agencywide Documents Access and Management System (ADAMS) Accessi on No. ML19240A260), the Technical Specifications Task Force (TSTF) submitted to the U.S. Nuclear Regulatory Commission (NRC) Traveler TSTF-582, Revision 0, RPV [Reactor Pressure Vessel] WIC [Water Inventory Control] Enhancements. On August 13, 2020, the NRC approved Traveler TSTF-582, Revision 0, as part of the consolidated line

item improvement process (CLIIP) (ADAMS Package Accession No. ML20223A000).

On September 3, 2020, you submitted TSTF-583-T, Revision 0, TSTF-582 Diesel Generator Variation (ADAMS Accession No. ML20248H330). Based on your feedback, the NRC staff expects most licensees to include the TSTF-583-T variation with their license amendment requests to adopt TSTF-582. Therefore, the NRC staff developed a model safety ev aluation of TSTF-582, that includes an evaluation of TSTF-583-T. License amendment requests to adopt TSTF-582 with or without the TSTF-583-T variation will be reviewed under the CLIIP. The NRC staffs model safety evaluation of TSTF-582 with the optional TSTF-583-T variation is enclosed.

Accordingly, the NRC staff approved TSTF-583-T as an optional variant of the approved TSTF-582. The NRC staff compared the licens ees proposed TS changes against the changes approved in TSTF-582 and TSTF-583-T. In accordance with the SRP Chapter 16.0, the NRC staff determined that the STS changes approved in TSTF-582 and TSTF-583-T are applicable to the Limerick TSs because Limerick is a BWR-4 design and the NRC staff approved the TSTF-582 and TSTF-583-T changes for BWR-4 designs. The licensee meets the TSTF-582 safety evaluation provision for adoption of TSTF-582 since it adopted traveler TSTF-542, Revision 2, dated February 27, 2018 (ML18017A201), and the licensee meets the technical basis for the changes approved in TSTF-582 and TSTF-583-T, as discussed above. Therefore, based on this, the NRC staff concludes that the licensees proposed changes to the Limerick TS Tables 3.3.3-1 and 4.3.3.1-1 and SR 4.8.1.2 are consistent with TSTF-582 and TSTF-583-T and the terms for use stated in the NRC staff SE of TSTF-582.

Based on the above evaluation, the NRC staff finds that the proposed changes to revise SR 4.8.1.2 are acceptable because the remaining applicable SRs will continue to demonstrate the operability of the required A.C. power sources and, as such, ensure the availability of the A.C. power required to operate the plant in a safe manner and mitigate postulated events during shutdown conditions. Therefore, the NRC staff fi nds the proposed changes to SR 4.8.1.2 are acceptable because the changes continue to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the associated LCO will continue to be met in accordance with 10 CFR 50.36(c)(3).

3.2 Evaluation of Proposed Change 2

Proposed Revision to Reactor Mode Switch and Manual Scram Requirements During Refueling

The licensee proposed to modify the operability requirements for Reactor Mode Switch -

Shutdown and Manual Scram functions during OPCON 5. In addition, the licensee proposed modifications to the requirements for the use of the Shutdown function of the Reactor Mode Switch during refueling. The specific changes proposed include:

TS 3.3.1.1, Reactor Protection System Instrumentation, Table 3.3.1-1, Functional Unit 11, Reactor Mode Switch Shutdown Position, and Functional Unit 12, Manual Scram, OPCON 5, would be revised by adding Note q which would state, With any control rod withdrawn from a core cell containing one or more fuel assemblies. The effect of Note q would be to not require Functional Units 11 or 12 to be operable when all control rods are inserted into core cells containing one or more fuel assemblies.

Action 3 for Functional Unit 11 and Action 9 for Functional Unit 12 state the Actions

required if the function is not operable. The current requirement for both functions states, Suspend all operations involving CORE ALTERATIONS and insert all insertable control rods within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The LAR proposes to revise these actions to state, Immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. The effect of this change in combination with the addition of Note q would be to require the licensee to exit the mode of applicability if the required function was not operable.

TS 3.4.9, Refueling Operations, LCO 3.9.1, Reactor Mode Switch, states, The reactor mode switch shall be OPERABLE and locked in the Shutdown or Refuel Position. The LAR proposes to revise it to state, The reactor mode switch shall be OPERABLE and locked in the Refuel Position. The current LCO 3.9.1 Applicability is OPCON 5 (as modified by footnotes

• and **) and OPCONs 3 and 4 when the reactor mode switch is in the Refuel Position. The LAR proposes to revise the Applicability to require the LCO to be met when the plant is in OPCON 5 (as modified by footnotes

• and **) and OPCONS 3 and 4. LCO 3.9.1, Actions a and b, and SR 4.9.1.1 are revised to eliminate references to the reactor mode switch in the Shutdown position. The effect of these changes is to only require the Reactor Mode Switch to be locked in the Refuel position during refueling operations. Locking the Reactor Mode Switch in the Shutdown position during refueling operations will no longer be an option.

LCO 3.9.1, Actions b, c.1 and d.1 are clarified. In all three Actions, the phrase requiring the licensee to verify control rods are fully inserted is replaced with fully insert all control rods. The effect of this change is to clarify what operator action is required if all controls rods are not fully inserted.

LCO 3.9.10.2, Multiple Control Rod Removal, and associated SR 4.9.10.2.1 refer to the reactor mode switch being locked in the Shutdown or Refuel position in accordance with Specification 3.9.1. Consistent with the proposed changes for LCO 3.9.1, the LAR proposes to remove references to the reactor mode switch being in the Shutdown position. The effect of these changes is to only require the Reactor Mode Switch to be locked in the Refuel position during refueling operations. Locking the Reactor Mode Switch in the Shutdown position during refueling operations will no longer be an option.

The NRC staff evaluated the proposed changes to the Applicability for TS 3.3.1.1, Reactor Protection System Instrumentation, Table 3.3.1-1 and Table 4.3.1.1-1, Functional Unit 11, Reactor Mode Switch Shutdown Position, and Functional Unit 12, Manual Scram. The NRC staff determined that the proposed changes are consistent with the STS. As stated in the STS Bases for Reactor Protection System (RPS) Instrumentation:

The RPS is required to be OPERABLE in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. Control rods withdrawn from a core cell containing no fuel assemblies do not affect the reactivity of the core and, therefore, are not required to have the capability to scram. Provided all other control rods remain inserted, the RPS function is not required. [ Emphasis added]

And

The Reactor Mode Switch - Shutdown Position Function is required to be OPERABLE in MODES 1 and 2, and MODE 5 with any control rod withdrawn

from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

And

Four channels of Manual Scram with two channels in each trip system arranged in a one-out-of-two logic are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.

The licensee provided the following technical justification for the change:

The purpose of the Functional Unit 11, Reactor Mode Switch - Shutdown, and Functional Unit 12, Manual Scram, in OPCON 5 is to provide a means for the reactor operator to rapidly insert all control rods into the reactor core. However, if all control rods are already inserted in all core cells that contain fuel assemblies, this function is not necessary. In the STS, these functions must be operable in Mode 5 only when any control rod is withdrawn from a core cell containing one or more fuel assemblies. The proposed change incorporates this STS allowance into the LGS [Limerick Generating Stati on] TS to provide additional flexibility during a refueling outage.

Based on the STS Bases and the licensees tec hnical justification, the NRC staff determined that when all control rods are fully inserted in the core and while in OPCON 5, there is no reason to require Functional Units 11 and 12 to be operable because the function of these instruments, which is to rapidly insert the control rods, is already accomplished. Therefore, this proposed change is acceptable.

The NRC staff evaluated the proposed revisions to Actions 3 and 9 of Table 3.3.1-1 which would be taken if either Functional Unit 11 or 12 were inoperable. As noted by the licensee in the LAR, the proposed revisions to the Actions would align the Limerick TS Actions with the STS Actions for these two instrument functions. The STS Bases state:

If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted.

Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted. [Emphasis added]

Accordingly, the required action in the STS for loss of either of these functions is to exit to a mode or specified condition where the LCO does not apply. As noted in the LAR:

Many actions to suspend Core Alterations were removed during the development of the STS, including the equivalent of the LGS [Limerick Generating Station] TS Action when the Reactor Mode Switch or Manual Scram Functions are

inoperable. The justification was that the refueling TS provide requirements to ensure safe operation during Core Alterations, including the required water level above the RPV flange. Inoperability of these functions does not affect safe performance of Core Alterations and prohibiting Core Alterations is not needed.

The NRC staff evaluated the proposed revision to the Functional Units 11 and 12 Applicability and Actions in combination with the controls provided in the Limerick Refueling Operations TS during OPCON 5 and determined that:

1. If any single control rod is removed, Functional Units 11 and 12 would still be required to be operable per Table 3.3.1-1. If either of them were not operable, then the licensee would be required to initiate action to drive rods in immediately in accordance with Actions 3 and 9 of Table 3.3.1-1.

2. Limerick LCO 3.9.3 requires all control rods to be inserted in OPCON 5, during CORE ALTERATIONS. If all controls rods are not inserted (except one under the control of the one-rod-out interlock), then the Actions in 3.9.3 require the licensee to suspend CORE ALTERATIONS.

3. LCO 3.9.1 requires the one-rod-out interlock to be operable. If it is inoperable, then the licensee is required to ensure all control rods are fully inserted and to disable withdraw capabilities on all control rods.

Based on this evaluation, the NRC staff determined that suspension of CORE ALTERATIONS is not a necessary action for a loss of Functional Units 11 or 12 operability. In addition, the proposed revisions to Actions 3 and 9 requiring the licensee to exit to a mode or specified condition where the LCO does not apply is an acceptable remedial action consistent with the STS. In addition, adequate protections are provided in the Limerick Refueling Operations TS in lieu of requiring suspension of CORE ALTERATIONS in Actions 3 and 9. Therefore the proposed changes to Actions 3 and 9 are acceptable.

Based on the evaluations above, the NRC staff c oncludes that the LCO applicability changes to Limerick TS 3.3.1.1 and the remedial actions provided by Actions 3 and 9 will continue to provide for the lowest functional capability or performance levels of equipment required for safe operation of the facility or acceptable remedial actions if the LCO is not met. Therefore, the proposed changes meet the LCO requirements of 10 CFR 50.36(c)(2).

3.3 Evaluation of Proposed Change 3

Proposed Revision to Reactor Mode Switch Requirements During Refueling

In the LAR, the licensee proposed to remove all references to the shutdown position of the reactor mode switch from TS 3.9.1, Reactor Mode Switch, and LCO 3.9.10.2 Multiple Control Rod Removal. In addition, the licensee proposed modifying the Actions in this TS 3/4.9.1 to clarify the actions required to be taken. The specific changes proposed are:

1) Actions b, c.1 and d.1 all require the licensee to Verify control rods are fully inserted and disable withdraw capabilities of all control rods. These Action would be revised to state fully insert all control rods and disable withdraw capabilities of all control rods.

2) LCO 3.9.1, which states, The reactor mode switch shall be OPERABLE and locked in the Shutdown or Refuel position would be re vised by deleting the words Shutdown or.

3) The Applicability for LCO 3.9.1 currently states that it is required in OPCON 5 (as modified by Footnotes

• and **) and during OPCONS 3 and 4 when the reactor mode switch is in the Refuel position. The applicability would be revised by deleting when the reactor mode switch is in the Refuel Position.

4) Action a, which states, With the reactor mode switch not locked in the Shutdown or Refuel position as specified, suspend CORE ALTERATIONS and lock the reactor mode switch in the Shutdown or Refuel position would be revised by deleting both occurrences of the words Shutdown or.

5) SR 4.9.1.1, which states, The reactor mode switch shall be verified to be locked in the Shutdown or Refuel position as specified, in accordance with the Surveillance Frequency Control Program would be revised by deleting the words Shutdown or.

6) LCO 3.9.10.2 defines the conditions under which multiple control rods may be removed.

Condition a which states The reactor mode switch is OPERABLE and locked in the Shutdown position or in the Refuel position per Specification 3.9.1, except that the Refuel position one-rod-out interlock may be bypassed, as required, for those control rods and/or control rod drive mechanisms to be removed, after the fuel assemblies have been removed as specified below would be revi sed by deleting Shutdown position or in the.

7) SR 4.9.10.2.1 verifies that the conditions required for multiple control rod removal are met. SR 4.9.10.2.1.a which requires the licensee to verify that The reactor mode switch is OPERABLE per SR 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Shutdown position or in the Refuel position per TS 3.9.1 would be revised by deleting Shutdown position or in the.

The licensee provided the following technical basis for the proposed changes:

The purpose of LGS [Limerick Generating Station] TS 3.9.1, Reactor Mode Switch, is to require the refueling equipment interlocks are operable, which ensures that the restrictions on control rod withdrawal and refueling platform movement during the refueling operations are properly activated. These conditions reinforce the refueling procedures and reduce the probability of inadvertent criticality, damage to reactor internals or fuel assemblies, and exposure of personnel to excessive radioactivity. TS 3.9.1 requires the reactor mode switch to be locked in the Shutdown or Refuel positions, which is consistent with the standard TS on which the LGS TS are based (NUREG-0123).

However, the LGS design only engages the refueling equipment interlocks when the reactor mode switch is in the Refuel position, and not in the Shutdown position. Locking the reactor mode switch in Shutdown does not satisfy the purpose of the TS.

As noted by the licensees, TS Bases for Limerick:

Locking the OPERABLE reactor mode switch in the Shutdown or Refuel position, as specified, ensures that the restrictions on control rod withdrawal and refueling

platform movement during the refueling operations are properly activated. These conditions reinforce the refueling procedures and reduce the probability of inadvertent criticality, damage to reactor internals or fuel assemblies, and exposure of personnel to excessive radioactivity.

The NRC staffs review of the Limerick UFSAR verified that the refueling interlocks are implemented with the reactor mode switch in the Refuel position. Accordingly, if placing the reactor mode switch in the Shutdown position doesnt ensure that the restrictions on control rod withdrawal and refueling platform movement during refueling operations are properly activated, then placing the reactor mode switch in the Shutdown position in LCO 3.9.1 does not meet the purpose of LCO 3.9.1. as stated above. Therefore, changes 2 through 7 above are acceptable because deleting the option of placing the reactor mode switch in the Shutdown position ensures that the refueling interlocks will be activated during refueling.

Actions b, c and d provide required operator actions when certain refueling interlocks are inoperable. Specifically, Action b provides the actions to be taken when the one-rod-out interlock is inoperable, Action c provides the actions to be taken when the Refuel Platform Refuel position interlocks are inoperable and Action d provides the actions to be taken when the Service Platform is installed over the reactor ve ssel with any of the required Service Platform Refuel position interlocks inoperable. With regard to the proposed revisions to these actions (proposed change 1 above), the licensee stated in its letter dated October 19, 2023:

CEG [Constellation Energy Generation, LLC] interprets verify all control rods are fully inserted to require verification or action to fully insert all control rods. For clarity, CEG has decided to reword the Limerick TS to require fully inserting all control rods, thereby making the action explicit instead of implied.

The NRC staff reviewed this change and considered it to be an editorial change as the revised wording clarifies the action required. Therefor e Change 1 is acceptable. In addition, the NRC staff concluded that the proposed LCO and Action changes to Limerick TS 3.9.1 and 3.9.10.2 will continue to provide for the lowest functional capability or performance levels of equipment required for safe operation of the facility or provide acceptable remedial actions and, therefore, meet the LCO requirements of 10 CFR 50.36(c)(2). In addition, the NRC staff finds the proposed changes to SR 4.9.12.1 and SR 4.9.10.2.1 are acceptable because the changes continue to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the associated LCO will continue to be met in accordance with 10 CFR 50.36(c)(3).

3.4 Evaluation of Proposed Changes 4, 5, 6, and 7

The licensee plans to remove both divisions of Limerick Unit 1 and Unit 2 redundant reactivity control system (RRCS) from service 30 days prior to the start of the Unit 1 and Unit 2 refueling outages in 2026 and 2027, respectively (i.e., just prior to the digital modernization project installation). As noted by the licensee in the LAR:

RRCS is credited for ATWS mitigation within the approved LGS [Limerick Generating Station] design and licensing-basis. During the Applicability Change period, the RRCS digital logic system in the Auxiliary Equi pment Room will be removed and space will be made to install new Plant Protection Syst em [PPS] equipment panels. The RRCS digital logic system will not be restored prior to entering the respective refueling outages.

Removal of the RRCS digital logic system will result in the loss of the RRCS-initiated

automatic functions for SLCS injection and associated RWCU [Reactor Water Clean Up]

isolation, ARI system actuation, ATWS-RPT actuation, and FWRB [feedwater runback]

actuation.

Since the loss of RRCS-initiated functions is governed by the Limerick TS the licensee is proposing to revise the following TS to enable this activity:

TS 3.3.4.1, ATWS Recirculation Pump Trip Actuation Instrumentation, Applicability, to add a note stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), the LCO is not applicable if specified conditions are met. A table with these conditions is included as part of the note.

SR 4.1.5.b.4 (i.e., Standby Liquid Control System) to add footnote (***) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), no pumps are required to start automatically.

TS Table 3.3.2-1, Isolation Instrumentation, Trip Function 3.d, SLCS Initiation, to add footnote (h) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

SR Table 4.3.2.1-1, Isolation Actuation Instrumentation Surveillance Requirements, Trip Function 3.d, SLCS Initiation, to add footnote (b) stating that for a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the 2026 refueling outage (Unit 1) and 2027 refueling outage (Unit 2), the RWCU Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

Section 3.5 states:

Although the evolution requiring the TS changes will result in loss of automatic RRCS-initiated functions that are credited for ATWS mitigation, [] the following automatic and manual functions will be available during the 30-day extended allowed outage time (AOT), and would be available to mitigate an ATWS event:

A non-safety related automatic reactor recirculation pump (RRP) runback on low reactor water Level 3 with more than the minimum analyzed 12 operable Main Steam Relief Valves (MSRVs) [(Safety Relief Valves (SRVs)] operable.

The Manual start of the SLCS pumps from the main control room no later than 5 minutes post-event [].

A redundant RWCU automatic isolation signal on low reactor water Level 2 will be available in lieu of the RRCS-initiated RWCU isolation function. RWCU isolation on manual SLCS initiation also will still function. When SLCS is manually initiated by the operator the RWCU isolation valves also will close as the isolation logic is directly in the pump breaker logic and is not impacted by RRCS being out of service. This ensu res that manual SLCS initiation boron is not

removed by RWCU demineralizers. With regards to RRP runback, operators can also manually trip the recirculation pumps from the control room.

ATWS Deterministic Supplemental Analysis

Section 3.5.1 of the LAR states:

The current ATWS analysis-of-record (AOR) for Limerick (LGS) is the Thermal Power Optimization (TPO) ATWS analysis (0000-0097-1195). CEG [the licensee] has performed a deterministic supplemental Limerick ATWS analysis to demonstrate compliance with ATWS acceptance criteria without RRCS. The purpose of the supplemental analysis is to deterministically justify removal of both divisions of RRCS from service while still satisfying all of the ATWS analysis acceptance criteria and identify any operating restrictions during end of cycle operation.

The TPO ATWS supplemental analysis is provided in Attachment 4 (proprietary version) and Attachment 5 (non-proprietary version) [of the LAR]. This supplemental analysis assumed that all automatic RRCS functions were not available during the 30 day-RRCS demolition period. []In addition, the sensitivity analysis utilized the following parameters:

1. The SLCS manual initiation timing was extended to 5 minutes post-event to provide adequate time to implement this operator manual action.

2. The suppression pool temperature limit assumed in the analysis was increased from 190°F to 200°F to remain within the bounds of the LGS [Limerick] Design Basis Accident (DBA) Loss of Coolant Accident (LOCA) containment analysis.

3. The non-safety related automatic RRP [reactor recirculation pump] runback on low reactor water Level 3 is functional.

4. The Residual Heat Removal (RHR) system heat removal effectiveness value (K) was increased from 289 to 305 BTU/sec-F to establish consistency with the LGS

[Limerick] DBA LOCA containment analysis.

Sensitivity studies were performed with 1 and 0 SRVOOS [SRVs out of service (OOS)] and at lower plant power levels during end-of-cycle operation to verify ATWS mitigation capability of the anticipated peak vessel pressure increase and the suppression pool temperature increase.

ATWS Sensitivity Analysis Results

Section 3.5.2 of the LAR states:

The Supplemental ATWS Analysis [... ] considered all potentially limiting ATWS scenarios from the LGS [Limerick] ATWS AOR for End-of-Cycle (EOC) operation due to planned duration of the proposed change just before the outage. These limiting events are the Main Steam Isolation Valve Closure (MSIVC), Pressure Regulator Failure (PRFO), and Loss of Offsite Power (LOOP) events. These events were reanalyzed, consistent with the ATWS AOR parameters, the additional inputs, and the constraints described above. The Supplemental ATWS Analysis documents the results for these scenarios with the required thermal

power set down and the SRV OOS flexibility assumed in the analysis (0 or 1 SRV OOS) to meet the 10 CFR 50.62 acceptance criteria [... ].

This Supplemental Analysis demonstrates that, with additional constraints imposed on operation, the station can meet all acceptance criteria and successfully mitigate an ATWS event. [LAR] Table 1 summarizes conclusions of this Supplemental Analysis. Table 1 as presented in the LAR:

Analysis Summary - Table 1: Required Operational Constraints Supported Number of Manual Suppression Additional Reactor SRVs Out of Initiation Time Pool Water System Thermal Service for SLCS Level Credited Power 87% 0 5 minutes 22 feet Level 3 Recirc Runback 84% 1 5 minutes 22 feet Level 3 Recirc Runback 90% 0 5 minutes 23 feet Level 3 Recirc Runback

The licensee states:

For the listed conditions in the Analysis Summary - Table 1, as long as the reactor thermal power level is less than or equal to the corresponding listed power level, the credited automatic Recirculation Runback (RRB) function on reactor water level (L3) is operational, and manual SLCS injection is started in 5 minutes, the [analysis demonstrates that the] station can mitigate an ATWS event and demonstrate compliance with the acceptance criteria with RRCS

[temporarily] out of service.

The licensee further states:

For the case with no SRV OOS, the limiting [most restrictive] PRFO event is limited by the suppression pool temperature. At 87% power, all acceptance criteria, including suppression pool temperature [safety limits] are met. At 88%

power, [], the suppression pool [temperature] limit of 200°F is exceeded.

Therefore, the maximum power level is set at 87% rated thermal power in conjunction with the other relevant operational constraints in this scenario.

The licensee states:

For the case with 1 [one] SRVOOS, the limiting PRFO event is limited by both peak vessel pressure and suppression pool temperature. At 84% power, all acceptance criteria are met. At 85% power, not shown, both the peak vessel pressure and suppression pool limits are exceeded. The same analysis also documents that if suppression pool level is maintained at or above 23 feet (i.e., mid-permissible TS operating band) instead of the assumed TS minimum

level of 22 feet, a reactor thermal power level of 90% is justified with all 14 MSRVs operable.

The licensee asserts that:

The results of the ATWS Supplemental Analysis are applicable to either LGS

[Limerick] Unit 1 or Unit 2 at the reactor power level with cores of fresh GNF3 fuel including mixed cores with GNF2 fuel, for the end-of-cycle operation only. These results are intended to apply during the [limited] time of when RRCS is out of service [during the 30-day RRCS demolition AOT], assuming no major plant changes. The results of this supporting ATWS analysis do not replace the current LGS ATWS AOR.

The results of this supporting ATWS analysis do not replace the current Limerick ATWS AOR [as this is a temporary maintenance action that is implemented to restore full qualification, when the RRPS is restored following the digital system modification, the existing ATWS AOR will be fully met.]

The NRC staff determined that the supplemental analysis provides appropriate operational guidance for the licensee to maintain the same level of ATWS mitigation capability during the 30-day RRCS demolition AOT. By maintaining power at or below 90% rated thermal power with additional down-powers should one SRV and suppression pool water level as contingencies as described in Table 3, the NRC staff finds that the licensees supplemental analysis demonstrates that the plant remains capable of successfully mitigating an ATWS with no net increase in the severity of an ATWS event during the 30-day RRCS demolition AOT, and the licensee continues to meet the maximum reactor vessel pressure and maximum suppression pool temperature acceptance criteria.

SRV Performance History

In Section 3.5.3 of the LAR, the licensee states:

Target Rock Stage 3 SRVs are installed at LGS [Limerick]. Regarding any potential for SRVs not operating within their setpoint bands, the GEHs ATWS methodology results in conservative modeling of the SRV setpoints (by modeling the opening setpoint at a conservative upper analytical limit). The treatment of the SRVs within the ODYN [One-Dimensional Core Transient Model] model is also plant specific. For Limerick, the SRV setpoints within the analysis model are statistically spread about the upper analytical limit setpoints, which accounts for in plant SRV functionality as well as instrument drift. variation in plant SRV functionality as well as instrument drift [within the analysis]. In the time since Limerick has installed the 3 stage SRVs, the licensee states that they have not experienced setpoint drift issues outside their prescribed set point tolerances.

The licensee further states:

This statistical treatment of SRV setpoints is approved in NEDC-24154P-A, Revision 1, (Supplement 1 - Volume 4), Qualification of the One-Dimensional Core Transient Model (ODYN) for Boiling Water Reactors, February 2000. The input selection, uncertainty in inputs, and direction of conservatism are all taken

care of within the approval basis of the applied methodology and captured in GE design procedures for ATWS.

The NRC staff determined that the SRV Performance History at Limerick has been appropriately evaluated and incorporated into the supplemental ATWS analysis. Specifically, the applicant uses an approved methodology NEDC-24154P-A, Revision 1 Qualification of the One-Dimensional Core Transient Model (ODYN) for Boiling Water Reactors, February 2000 which automatically assumes the worst case SRV (lowest opening setpoint) is the first to fail.

Furthermore, the licensees required ASME Code and Maintenance Rule programs have not noted any setpoint drift failures at Limerick.

Operator Actions during ATWS Conditions

The licensee states in section 3.5.4 of the LAR:

Symptom-based Emergency Operating Procedures (EOPs), titled Transient Response Implementation Procedures (TRIPs) at LGS [Limerick], provide appropriate response to an ATWS condition. One of the entry conditions to LGS

[Limerick] EOP T-101, RPV Control (Reference 17) is a reactor scram condition with power not downscale. The first action step in T-101 directs operators to manually scram the reactor if a scram has not occurred using all available means from the reactor control console. If reactor power remains above the downscale setpoint, manual ATWS mitigating actions are directed by the next T-101 step which include rapidly lowering RPV water level manually and ensuring SLCS injection and RWCU isolation. While the Recirculation pumps will not trip automatically, a low-speed runback will still automatically occur when RPV water level decreases below +12.5 inches which will reduce core flow and limit reactor power until subsequent EOP steps which direct ensuring the Reactor Recirculation Pumps are tripped.

Once initial ATWS actions are performed per T-101, operators are directed to enter T-117, ATWS RPV Control, (Reference 18) where additional guidance for inadequate automatic system operation is provided with the phrase: "Ensure as appropriate." The phrase "Ensure as appropriate" encompasses failure of automatic actions that should have occurred including ensuring the Reactor Recirculation pumps are tripped. During the 30-day demolition period where RRCS is inoperable there exists alternative manual operator actions, independent of RRCS, to trip the Recirculation Pumps, initiate SLCS and isolate RWCU, and manually lowering RPV water level. In addition, credit has been given in the supporting ATWS Analysis for the Recirculation Pump runback which will occur on reactor level 3, (+ 12.5 inches). Operations personnel will be briefed daily during the 30-day RRCS demolition period on T-101 and T-117 ATWS actions and the required manual operator actions that would be required, in lieu of RRCS automatic action, to trip the Recirculation Pumps, initiate SLCS and RWCU isolation, and to manually lower RPV water level.

Regarding the SLCS manual operator initiation extension to 5 minutes, there is currently not a credited manual operator action for manual initiation of SLCS in an ATWS condition in the LGS [Limerick] Operator Response Time Program per OP-AA-102-106. Operators are trained to manually initiate SLCS during initial and continuing training per the EOPs, but since it is not currently a credited

manual action no formal times were docum ented historically per the Operator Response Time Program. The LGS [Limerick] Operators Response Time Program defines a Time Critical Acti on (TCA) as time-constrained manual actions which are credited in the safety analyses as part of the primary success path for mitigating design basis accidents. Since the ATWS supplemental analysis performed to support the safety case of removing RRCS from service prior to the installation outage assumes that SLCS is manually initiated within 5 minutes of the event as a TCA (as defined in the LGS Operator Response Time Program), this manual action will be added to the LGS [Limerick] Operator Response Time Program per OP-AA-102-106 (Reference 16). Initial validation with an operating crew in the simulator showed that operators can reliably initiate SLCS within 5 minutes of the occurrence of an ATWS condition. Full validation of this new TCA will be completed per OP-AA-102-106 by May 31, 2023.

Operator actions to diagnose the ATWS condition and manually start this equipment will be able to be taken in a timely manner from the control room for the 30-day temporary exemption period. To successfully mitigate an ATWS Limerick will need SLCS and RPT capabilities to successfully mitigate an ATWS condition.

The NRC staff determined that the station review of EOPs and TCAs has appropriately evaluated the station impact of operator actions and incorporated them into the supplemental ATWS analysis.

The NRC staff determined that the proposed changes to allow a one-time 30-day outage time for RRCS instrumentation demolition is acceptable because it still provides the same level of ATWS mitigation, with no net increase of ATWS severity. Specifically, with the manual initiation of SLCS and redundant runback of the recirculation pumps, even without ARI capability, the operators will have the same ability to successfully mitigate an ATWS condition as the automatic systems required by 10 CFR 50.62(c)(3)-(5) provide. This conclusion is further supported by the supplemental ATWS sensitivity analysis.

In Section 3.5 of Attachment 1, Constellation states that the proposed change would result in the loss of automatic RRCS-initiated functions that are credited for ATWS mitigation and that, in part, manual SLCS actuation would replace automatic actuation of the SLCS to mitigate an ATWS event. Constellation further states that this manual start of the SLCS pumps would be initiated from the main control room no later than 5 minutes post-event. Furthermore, automatic RWCU isolation upon manual SLCS initiation also would also serve as a redundant actuation to the automatic RWCU isolation on low reactor water Level 2 which, itself, would replace the function of the RRCS-initiated RWCU isolation function during the per iod of the proposed change. The RWCU isolation ensures that the boron injected by the SLCS is not removed via the demineralizers of RWCU system. Section 3.5.2 indicates that SLCS initiation is credited to be manually initiated by an operator within 5 minutes to meet ATWS analyses while the proposed change is in effect. In section 3.5.4 it is noted that while there is not currently a credited manual operator action for manual initiation of SLCS included under OP-AA-102-106, LGS [Limerick Generating Station] Operator Response Time Program, operators are currently trained to manually initiate SLCS during initial and continuing training per the EOPs.

The licensee provided a description in the LAR of how specific measures would be maintained during the period of the proposed change. These measures are described under Attachment 1, section 3.5.4, as including, in part, the following:

Limerick EOP T-101, RPV Control, includes an entry criterion for a reactor scram condition with power not downscale. Should manual scram attempts subsequently be unsuccessful, manual ATWS mitigating actions are then directed by T-101. These actions include rapidly lowering RPV water level, manually initiating SLCS injection, and isolating RWCU.

Following completion of initial ATWS response actions under the T-101 procedure, operators are then directed to enter T-117, ATWS RPV Control, which contains additional guidance for inadequate automatic system operation.

During the period of the proposed change (i.e., RRCS demolition), operations personnel would be briefed daily on the ATWS response actions of T-101 and T-117, including the required manual operator actions to be taken, in lieu of automatic RRCS actuation, to trip Recirculation Pumps, initiate SLCS, isolate RWCU, and manually lower RPV water level.

In accordance with the guidance provided in Section 18 of the SRP, the NRC staff used a graded approach to evaluate the HFE considerations related to the changes described in the LAR. Because the licensee submitted a non-risk-informed LAR, the NRC staff used a qualitative approach in determining the risk significance of the proposed change and the corresponding level of review. In accordance with the generic risk categories established in Appendix A to NUREG-1764, the operator actions associated with both ATWS level control and standby liquid control initiation are classified as potentially risk-important human actions. Based upon this screening, the NRC staff determined that the preliminary level of review warranted under NUREG-1764 would be Level II. The NRC staff further consulted with a risk analyst to determine whether this screening was consistent with quantitative risk insights. The risk analyst assessment confirmed that a preliminary level of review more intensive than that of Level II would not be warranted. The NRC staff then performed a qualitative assessment of the human actions associated with the change request to determine whether the level of review should be elevated to Level I.

In conducting this qualitative assessment, key NRC staff areas of consideration included the following:

whether the requested change would introduce new human actions;

whether the requested change would give personnel a new functional responsibility that differs from their normal responsibilities;

whether the requested change would significantly modify the way in which personnel perform their tasks;

whether the requested changed change would create a new context for task performance; and

whether the requested change would significantly change any of the following:

o the human-system interfaces (HSIs) used by personnel to perform the task;

o the procedures that personnel use to perform the task; or

o the training associated with the task.

Based upon the information provided in the licensees submittal and responses to requests for additional information (RAIs), as detailed later in this evaluation, the NRC staff determined that significant changes were not expected to occur within these areas. From this qualitative assessment, the NRC staff then concluded that the review should not be elevated to Level I and should instead remain at Level II. Using the screening and review guidance of NUREG-1764, the NRC staff then subsequently determined that the appropriate Level II review criteria included deterministic, analysis, design, and human action verification criteria. The relevant Level II review criteria will be considered in the subsequent portions of this evaluation.

Preservation of Sufficient Defense Against Human Errors

Section 4.1 of NUREG-1764 provides review guidance for verifying that certain deterministic aspects of the change have been appropriately considered by the licensee. This includes a criterion for providing adequate assurance that the change does not compromise defense-in-depth as it relates to the preservation of defenses against human errors.

The NRC staff reviewed the licensees description of defenses against human errors within the context of defense-in-depth. In Section 3.5.4 of the LAR, the licensee states that during the period of the proposed change (i.e., RRCS demolition), operations personnel would be briefed daily on the ATWS response actions of T-101 and T-117, including the required manual operator actions to be taken, in lieu of automatic RRCS actuation, to trip Recirculation Pumps, initiate SLCS, isolate RWCU, and manually lower RPV water level.

Based on the information in the LAR, the NRC staff finds that the preservation of defenses against human errors aspect of defense-in-depth conforms to the applicable criterion of NUREG-1764 and is acceptable to the extent ne eded to support this application because the manner in which defenses against human errors w ill be preserved, using means such as daily briefings on compensatory actions provides adequate assurance that the change will not compromise defense-in-depth in this regard.

Functional and Task Analysis

The NRC staff reviewed the licensees description of how personnel will know when the required human actions are necessary, as well as that they are performed correctly. In response to RAI 1 (ML23202A219), the licensee confirmed that all required operator tasks that need to be implemented during an ATWS with concurrent loss of the RRCS system are already addressed as part of the current operator training pr ogram, including performance of manual operator actions in response the failure of automatic actions.

Based on the information in the LAR, responses to RAIs (ML23202A219), and the discussion above, the NRC staff finds that the functional and task analysis conforms to the applicable criteria of NUREG-1764 and is acceptable to the extent needed to support this application

because the relevant operator tasks as they exist now include manual operator procedures to appropriately address an ATWS event and will remain unchanged.

Staffing

The NRC staff reviewed the licensees descripti on of the effects of the changes in human actions upon the number, qualifications, and current staffing levels of operations personnel. In response to RAI 2 (ML23202A219), the licensee confirmed that, as no changes are being made to existing operator tasks, no associated changes in staffing are warranted. Furthermore, the licensee also clarified that no credited operator actions associated with the LAR would occur from outside of the Main Control Room or require a dedicated operator.

Based on the information in the LAR, responses to RAIs (ML23202A219), and the discussion above, the NRC staff finds that the staffing changes conform to the applicable criterion of NUREG-1764 and are acceptable to the extent needed to support this application because the relevant human actions to appropriately address an ATWS event does not require modification and consistent with that, the number and qualifications of the operations personnel does not require modification and will remain unchanged and, consistent with that, the number and qualifications of operations personnel will not require modification.

Human-System Interfaces

The NRC staff reviewed the licensees description of modifications to HSIs as they relate to changes in operator task requirements. In response to RAI 3 (ML23202A219), the licensee confirmed that no modifications will be made to any HSIs required for implementing those operator actions credited in the mitigation of an ATWS event.

Based on the information in the LAR, responses to RAIs (ML23202A219), and the discussion above, the NRC staff finds that no modifications to any human-system interfaces are required to implement the operator actions credited to mitigate the ATWS event. The existing human-system interfaces conform to the applicable criterion of NUREG-1764 and are acceptable to the extent needed to support this application and their ability to support operator task requirements will remain unchanged.

Procedures

The NRC staff reviewed the licensees description of modifications to plant procedures as they relate to changes in operator task requirements. In Section 3.5.4 of the LAR, the licensee states that Limerick EOP T-101 includes manual ATWS mitigating actions for rapidly lowering RPV water level, manually initiating SLCS injection, and isolating RWCU. Additionally, it is stated that, following completion of initial ATWS response actions under T-101, operators are then directed to enter T-117, which contains additional guidance for inadequate automatic system operation. In response to RAI 4 (ML23202A219), the licensee confirmed that no modifications will be made to any EOPs or EOP strategies and that the actions credited within the LAR for ATWS mitigation would be directed through the implementation of the EOPs as currently written.

Based on the information in the LAR, responses to RAIs (ML23202A219), and the discussion above, the NRC staff finds that the modifications to plant procedures conform to the applicable criterion of NUREG-1764 and are acceptable to the extent needed to support this application because they support the necessary human actions and will remain unmodified.

Training

The NRC staff reviewed the licensees description of modifications to operator training as they relate to operator task requirements. In Section 3.5.4 of the LAR, the licensee states that operators are trained to manually initiate SLCS per the EOPs during both initial and continuing training. In response to RAI 5 (ML23202A219), the licensee confirmed that the operator actions credited within the LAR are already included within the scope of both the initial and continuing operator training programs and that no training program modifications are expected in conjunction with the LAR. The licensee further clarified that current training covers the necessary actions for ATWS response without RRCS available, including manual SLCS initiation, lowering RPV water level, and tripping Reactor Recirculation pumps.

Based on the information in the LAR, responses to RAIs (ML23202A219), and the discussion above, the NRC staff finds that training conforms to the applicable criterion of NUREG-1764 and is acceptable to the extent needed to support this application because the current training supports the necessary human actions and will not be modified.

Availability and Accessibility

The NRC staff reviewed the licensees description of the availabili ty and accessibility of all required components. In response to RAI 6 (ML23202A219), the licensee confirmed that no changes to indications and controls will be needed to support operator actions required by the proposed change.

Based on the information in the LAR, responses to RAIs (ML23202A219), and the discussion above, the NRC staff finds that the existing avai lability and accessibility of required components conforms to the applicable criteria of NUREG-1764 and is acceptable to the extent needed to support this application.

Walkthroughs

The NRC staff reviewed the licensees description of walkthrough activities conducted for the human actions to determine that procedures are accurate and usable, that the training program appropriately addressed the changes, and that the human actions can be completed within the required time. In Attachment 1, section 3.5.4, Constellation stated the following:

Initial validation with an operating crew in the simulator showed that operators can reliably initiate SLCS within 5 minutes of the occurrence of an ATWS condition. Full validation of this new TCA will be completed per OP-AA-102-106 by May 31, 2023.

In response to RAI 7 (ML23202A219), the licensee confirmed that the new time critical action to manually initiate the SLCS within 5 minutes of an ATWS event was validated in accordance with OP-AA-102-106, Operator Response Time Program. The licensee described that the facility simulator was used to conduct validation scenarios, and included the following information:

the RRCS was simulated as being non-functional using simulator malfunctions;

an inadvertent Main Steam Isolation Valve (MSIV) closure (i.e., a Group 1 isolation)

ATWS scenario was used as it is one of the limiting analyzed cases; and

all operating crews participated in the validation scenarios and did so in their normal training teams.

The licensee stated that a total of 10 validation runs were completed with the following results:

all crews manually initiated the SLCS within the allowed time of five minutes (i.e., 300 seconds);

the longest time for any crew to manually initiate the SLCS was 129 seconds;

the average time taken for crews to manually initiate the SLCS was 79.5 seconds; and

no procedural or training issues associated with manual SLCS initiation were identified.

In reviewing the licensees validation results, the NRC staff supplemented the review criteria of NUREG-1764 with that of NUREG-1852. While not directly applicable to the changes proposed under the LAR, NUREG-1852 provides reviewer guidance for assessing the adequacy of time margins associated with the completion of m anual operator actions. Specifically, NUREG-1852 Appendix B, section B.4, identifies a guideline where available time being at least 100 percent greater than the time obtained in a demonstration (i.e., a margin factor of at least 2) is supportive of a manual action being reliable. The NRC staff applied this guideline to the licensees validation results as shown below:

Validation Max Allowed Time Validated SLCS Margin Factor =

Measure for SLCS Initiation Initiation Time Allowed Time /

Validated Time Average Crew 300 seconds 79.5 seconds 3.7 Slowest Crew 300 seconds 129 seconds 2.3

The NRC staff noted that even by the more conservative measure (i.e., the slowest SLCS initiation time observed across the 10 validation runs), the guideline of a margin factor of 2 was still met, with average crew validation times suggesting that a higher margin factor would likely be more reflective of typical crew performance.

Based on the information in the LAR, responses to RAIs (ML23202A219), and the discussion above, the NRC staff finds that the walkthrough acti vities conform to the applicable criterion of NUREG-1764 and are acceptable to the extent needed to support this application because walkthrough activities are described for determining that the human actions can be completed within the required time and are supported by procedures and training. Furthermore, licensee validation results support that the credited human actions can be reliably implemented within the required time.

The NRC staff finds that the discussed general dete rministic, analysis, procedures, training, and human action verification criteria collectively provide reasonable assurance that the health and safety of the public will not be endangered by the crediting of manual SLCS initiation during the licensees response to the occurrence of an ATWS.

3.5 Risk Insights

This license amendment request is not a risk-in formed request so a risk evaluation is not required. However, the licensee is providing risk insights related to the proposed change for additional information.

Section 3.5.5 of the LAR states:

The risk analysis demonstrated with reasonable assurance that the proposed TS changes are within the current risk acceptance guidelines in RG [Regulatory Guide] 1.177, An Approach for Plant-Specific, Risk-Informed Decision making:

Technical Specifications, Revision 2, January 2021, for one-time changes.

The changes proposed by this amendment meet the acceptance criteria for incremental conditional core damage probability of 1.0E-05, the actual value for Limerick Units 1 and 2 is 2E-08. The changes proposed by this amendment also meet the acceptance criteria for incremental conditional large early release probability of 1.0E-06, the actual value for Limerick Units 1 and 2 is 2E-09. The results meet acceptance guidelines and are applicable for configuration changes that require normal work controls.

Additional insights from probabilistic risk assessment modeling of three specific operator actions indicate that 5-minute operator action response time is within the bounds of existing scenarios.

While the NRC staff do not consider these risk insights to be the basis for approval of this license amendment request, the NRC staff acknowl edges that they align with and support the deterministic ATWS supplemental analysis.

3.6 Evaluation of Proposed Change 4

Proposed One-Time LCO 3.3.4.1 Applicability Change for ATWS Recirculation Pump Trip Actuation Instrumentation

To facilitate the new digital I&C installation, the LAR proposes to temporarily modify the following TS as discussed below:

TS 3.3.4.1, ATWS Recirculation Pump Trip Actuation Instrumentation, Applicability, the addition of a note is proposed that states, For a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the [2026 refueling outage for Unit 1 or 2027 refueling outage for Unit 2], the LCO is not applicable when the following conditions are met:

Table 2 Recirc Runback on Level 3 Function is Available and not in Bypass Maximum Maximum Inoperable Minimum Suppression THERMAL POWER SAFETY/RELIEF VALVES POOL WATER LEVEL 90% RTP 0 of 14 23 feet

87% RTP 0 of 14 22 feet

84% RTP 1 of 14 22 feet

SR 4.1.5.b.4 (i.e., Standby Liquid Control System), the addition of a footnote (***) is proposed that states For a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the [2026 refueling outage for Unit 1 or 2027 refueling outage for Unit 2], no pumps are required to start automatically.

TS Table 3.3.2-1, Isolation Instrumentation, Trip Function 3.d, SLCS Initiation, the addition of a footnote (h) is proposed that states, For a period of 30 days preceding exit from the start of the [2026 refueling outage for Unit 1 or 2027 refueling outage for Unit 2],

the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

SR Table 4.3.2.1-1, Isolation Actuation Instrumentation Surveillance Requirements, Trip Function 3.d, SLCS Initiation, the addition of a footnote (b) that states, For a period of 30 days preceding exit from OPERATIONAL CONDITION 1 at the start of the

[2026 refueling outage for Unit 1or 2027 refueling outage for Unit 2], the Reactor Water Cleanup System Isolation on SLCS Initiation Trip Function is not required to be OPERABLE.

As stated in the technical evaluation in Sections 3. 4 and 3.5 of this SE, the NRC staff found the operation of the plants in accordance with the proposed one-time changes to the ATWS Recirculation Pump Trip Actuation Instrumentation to be acceptable. Based on this, the NRC staff evaluated the proposed one-time revisions to the TS against the regulatory requirements of 10 CFR 50.36. The NRC staff determined that the proposed notes clearly articulated the operational requirements which the NRC staff evaluated in Section 3.4 of this SE, with clearly defined conditions and timeframe under which they are applicable. Therefore, the NRC staff concluded that the proposed LCO applicability changes to Limerick TS 3.3.4.1 and TS Table 3.3.2-1 will continue to provide for the lowest functional capability or performance levels of equipment required for safe operation of the facility and, therefore, meet the LCO requirements of 10 CFR 50.36(c)(2). In addition, the NRC staff finds the proposed changes to SR 4.1.5.b.4 and SR Table 4.3.2.1-1 are acceptable because the changes continue to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the associated LCO will continue to be met in accordance with 10 CFR 50.36(c)(3).

4.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Pennsylvania State official was notified of the proposed issuance of the amendments on February 16, 2024. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 and change surveillance requirements. The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (88 FR 73883). 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 env ironmental 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 Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors: Charley Peabody, NRR Robert Elliott, NRR Jesse Seymour, NRR Steven Alferink, NRR

Date: October 31, 2024 NUCLEAR REGULATORY COMMISSION

[Docket Nos. 50-352 and 50-353; NRC-2023-XXXX]

Constellation Energy Generation LLC; Limerick Generating Station

Units 1 and Unit 2

Unavailability of Automatic ATWS Activation Systems for 30 days

Exemption

I. Background

Constellation Energy Generation LLC. (Constellation, the licensee) is the holder of the

Renewed Facility Operating License Nos. NPF-39 and NPF-85, which authorize the operation of

Limerick Generating Station (Limerick), Units 1 and 2. The facilities consist of boiling water

reactors located in Pottstown, Pennsylvania and is located next to the Schuylkill River.

By letter dated February 17, 2023, as supplemented by letters dated July 21, 2023,

July 31, 2023, August 16, 2023, and May 28, 2024, Constellation has requested exemption from

specific requirements of Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Section

62,Requirements for reduction of risk from antic ipated transients without scram (ATWS) events

for light-water-cooled nuclear power plants. A publicly available version of each letter is in

Agencywide Documents Access and Management System (ADAMS) under Accession Nos.

ML23052A023, ML23202A219, ML23212B105, ML23228A094, and ML24149A211,

respectively. Constellation specifically requests an exemption from the requirements of

10 CFR 50.62(c)(3) and the automatic activation requirements of 10 CFR 50.62(c)(4) and (c)(5)

for a period of 30 days before the calendar year 2027 refueling outage for Unit 2 and for a

period of 30 days before the calendar year 2026 refueling outage for Unit 1. In conjunction with

this exemption request the licensee submi tted an associated license amendment request

(ML23052A023) to add operational constraints to the limiting conditions of operations in the

technical specifications (TSs) for each Limerick unit to be in effect during each respective

Enclosure 4

exemption period to ensure that there is no increase in the potential consequences of an ATWS.

In the license amendment request, the licensee also described additional ATWS mitigation

strategies (i.e., compensatory measures) they will implement in addition to the TS changes.

Specifically, in Attachment 7 of the license amendment request, the licensee stated, With the

additional compensatory measures being taken, the same level ATWS mitigation protection will

be achieved during the 30-day RRCS demolition period when the automatic systems designed

to meet compliance with 10 CFR 50.62 ATWS requirements are out of service.

II. Request/Action.

Pursuant to 10 CFR, Part 50 Section 50.62, the Commissions regulations establish

specific ATWS mitigation requirements for nuclear power plants, with paragraphs (c)(3), (c)(4),

and (c)(5) applicable to boiling water reactors like Limerick Units 1 and 2. The systems that are

required are to be operational are the alternate rod injection (ARI) system, the automatic

activation of the standby liquid control system (SLCS), and equipment to trip the reactor coolant

recirculation pumps automatically under conditions of an ATWS. Constellation requested an

exemption from all requirements for ARI capability in 10 CFR 50.62(c)(3) and only from the

automatic response capability in 10 CFR 50.62(c)(4) for SLCS and in 10 CFR 50.62(c)(5)

recirculation pumps trip (RPT) for a period of 30 days prior to the 2027 refueling outage for

Unit 2 and the 2026 refueling outage for Unit 1. During each 30 day period prior to the refueling

outage, referred to by Constellation as the 30-day redundant reactivity control system (RRCS)

demolition period, Constellation will begin upgr ading the RRCS by demolishing the existing

analog system and replacing it with a new digital system which will be completed during the

refueling outage. To support RRCS demolition period, Constellation submitted a license

amendment request to temporarily modify certain TS limiting conditions for operation to: 1) not

require operability of certain automatic initiation features of ATWS equipment that are in the

scope of work being performed, and 2) establish operating condition that ensure that there

would be no increase in the consequences of an ATWS event should one occur during the 30-

day RRCS demolition period. In addition, they also requested that certain surveillance

requirements related to the ATWS features within the scope of work not be required during the

RRCS demolition period. The limiting condition for operation changes temporarily limit the

maximum reactor thermal power during the 30-day RRCS demolition period based on

combination of operating parameters. Specifically, the maximum power at which the plant is

limited based on the number of out of safety relief valves, the ability to manually initiate SLCS

within five minutes, a minimum suppression pool water level, and the operability of the reactor

water level 3 recirculation runback system. The operational constraints identified by

Constellation for each identified maximum thermal power limit are listed in the following table.

Exemptions Operational Constraints for a Period of 30-Days Maximum Maximum Minimum Additional Reactor Number of SRVs Manual Initiation Suppression System Thermal Power Out of Service Time for SLCS Pool Water Credited Level

Level 3 90% 0 5 minutes 23 feet Recirculation Runback

Level 3 87% 0 5 minutes 22 feet Recirculation Runback

Level 3 84% 1 5 minutes 22 feet Recirculation Runback

In addition, as stated in their license amendment request, as evaluated by NRC staff in the SE

to the LAR, to reduce the risk from a potential ATWS event during the 30-day period, the

licensee will implement additional ATWS mitigation strategies to provide an equivalent level of

ATWS protection to their normal automatic ATWS mitigation capability.

III. Discussion.

Pursuant to 10 CFR 50.12, the Commission may, upon application by any interested

person or upon its own initiative, grant exemption from the requirements of 10 CFR Part 50

when: (1) the exemptions are authorized by law, (2) will not present an undue risk to public

health or safety, (3) are consistent with the common defense and security; and (4) when special

circumstances are present, as defined in 10 CFR 50.12(a)(2). This exemption would allow

Constellation to temporarily disable the AR I, and the automatic activation of the SLCS and

recirculation pumps at Limerick so that digital upgrades can be made leading up to the refueling

outages of each unit.

A. The Exemption is Authorized by Law

The Atomic Energy Act of 1954, as amended, does not require any specific systems to

reduce the risk from ATWS events. These system s are required by NRC regulation. The intent

of the regulations requires systems to mitigate the ATWS conditions, should they occur. The

NRC staff has determined that granting the exemption will not result in a violation of the Atomic

Energy Act of 1954, as amended, NRC regulations, or any other laws. Therefore, the requested

exemption is authorized by law.

B. The Exemption Presents no Undue Risk to Public Health and Safety

The NRC requires that an exemption demonstrate that it does not present undue risk to

public health and safety if it is granted. Cons tellation provided an analysis that with the

proposed systems offline, the lower power limit, the manual activation of the SLCS and the

recirculation runback pumps, that the disabling of the ATWS mitigation measures will not

present undue risk to public health and safety. The disabling of automatic ATWS mitigation

systems for 30-days potentially increases the severity of an ATWS event should it occur within

the window. An ATWS that is not successfully mitigated could result in core damage due to

excessive heat generation. ATWS events are unlikely events that are expected to occur once or

more during an operating reactors service life. The proposed changes to the reactor systems

do not change the likelihood of an ATWS event occurring. The consequences of an ATWS can

vary from a minor event that can be addressed with the available protection systems, to more

severe that require more significant measures leading to a sudden shutting down of a nuclear

reactor, if necessary to protect the core from damage.

The proposed ATWS mitigation strategies and TS limits presented by the licensee in the

analysis in its LAR in attachment 4 (propriety) and attachment 5 (non-proprietary) demonstrate

an effective strategy to mitigate the potential severity increase caused by disabling some of the

automatic functions of the reactor protection system so that there is no net increase in the

consequences of an ATWS during the 30-day RRCS demolition period. The NRC staff verified

in the SE to the LAR that the analysis demonstrates that the consequences of the ATWS are

not increased with the associated operational constraints included in the temporary

modifications to the LCOs proposed in the associated LAR to this exemption during the 30-day

RRCS demolition period. Based on a review of the licensees analysis as documented in the SE

to the associated LAR to this exemption, the NRC staff has determined that the requested

temporary exemption, with the licensees compliance with the TS limiting conditions of operation

requested by the licensee in the LAR, presents no undue risk to public health and safety.

C. The Exemption is consistent with the Common Defense and Security

The requested exemption does not change safeguards and security programs at

Limerick. Constellation stated those programs will remain in full effect during the 30-day RRCS

demolition period exemption time periods in 2027 for Unit 2 and 2026 for Unit 1. Therefore, the

NRC staff finds that the action is consist ent with the common defense and security.

D. Special Circumstances

Pursuant to 10 CFR 50.12(a)(2)(ii), special circumstances are present when application of the

regulation in the particular circumstances is not necessary to achieve the underlying purpose of

the rule. The underlying purpose of 10 CFR 50.62 is that there are systems available to

operators to sufficiently mitigate the consequences of an ATWS event, that are reliable,

independent and diverse from the reactor trip system. In 49 FR 26040, it makes this clear in

stating The equipment required by this amendment (10 CFR 50.62(c)) is for the purpose of

reducing the probability of unacceptable consequences following anticipated operational

occurrences. The systems that are required by 10 CFR 50.62 at BWRs are an alternative rod

insertion system, automatic SLCS, and automatic reactor coolant recirculation pump trip system

In 49 FR 26041, the Commission provided that some operating nuclear power plants

licensed to operate prior to August 22, 1969, may be granted a permanent exemption from

these requirements if they can demonstrate that their risk from an ATWS is sufficiently low. The

Commission provided guidance for the factors that it determined to be important to this such as,

power level, unique design features that could prevent or mitigate the consequences of an

ATWS, or the remaining plant lifetime. The Commission has granted these exemptions for

plants licensed to operate prior to 1969 based on the finding that the risk from an ATWS is

sufficiently low and therefore was not necessary to achieve the underlying purpose of the rule

for Haddam Neck (55FR 10124) and Yankee Nuclear Power Station (53 FR 20704).

While Limerick Units 1 and 2 were licensed to operate after August 22, 1969, they are seeking a

temporary, not a permanent exemption from thes e requirements. The NRC staff notes that this

30-day RRCS demolition period is temporary in nature, one time per unit, and that the resulting

RRCS modifications to upgraded, digital system s will restore permanent, full compliance with

10 CFR 50.62(c)(3) - (5) afterwards. This temporary nature of the exemption aligns with the

factor the Commission considered to be important to grant a permanent exemption of the

remaining plant lifetime. In addition, the licensee has proposed in the associated LAR to

impose operational controls including restrictions on the power level of the plant during the 30-

day RRCS demolition period, which in part is used by the licensee in its analysis to demonstrate

that there is no net increase in the severity of an ATWS. This aligns with the factor of power

level identified by the Commission as an important factor in granting such an exemption from

the ATWS rules because the power level of Limerick Units 1 and 2 will be limited by the plants

TS during their respective 30-day RRCS demolition period. Finally, while the licensee has not

identified any unique design features at Limerick Units 1 and 2, it has proposed unique limiting

conditions of operations such as reactor power less than or equal to 90% RTP, all 14 SRVs

operable, and suppression pool water level greater than or equal to 23 feet. If suppression pool

water level is less than 23 feet, but greater than 22 feet, reactor power must be reduced to less

than 87%. If one SRV becomes out of service reactor power must be further reduced to less

than or equal to 84% RTP. If two SRVs become inoperable or suppression pool water level

drops below 22 feet then LCO 3.3.4.1 would apply, and the licensee would have one hour to

restore at least one ATWS Recirculation Pump trip system to operable status within one hour or

place the plant in Startup Mode within the next six hours as required by Limerick TS Action

3.3.4.1.e. The licensee has demonstrated in its analysis that implementing these limiting

conditions for operations results in no net increase in the severity of an ATWS event. Finally,

while the rule requires automatic systems, the licensee has demonstrated that the relevant

human factors can sufficiently mitigate an ATWS event in the analysis, as documented by NRC

staff in the SE to the associated LAR. The NRC staff finds that the relevant human factors are

appropriate for a temporary exemption from t he requirement for automatic systems because the

licensee has demonstrated that the temporary limiting conditions for operation provide sufficient

time margin, in the event of an ATWS, for manual actuation of these systems to provide the

same level of ATWS mitigation as the automatic systems required by 10 CFR 50.62(c)(3) - (5),

as evaluated by NRC staff in the SE to the LAR associated with this exemption. Therefore, the

NRC staff finds that the risk of an ATWS is sufficiently low in support of this temporary

exemption request, using the factors the Commission previously identified for certain nuclear

power plants, not including Limerick Units 1 and 2, to be granted permanent exemptions from

the ATWS requirements in 10 CFR 50.62(c).

Specific to the application of the rule to Limerick, NRC staff notes that the Limerick

UFSAR and Tech Spec Bases provides specific descriptions of each system. As described in

the UFSAR Section 4.6.1.2.5.4 for Limerick, the purpose of the alternative rod insertion system

as required by 10 CFR 50.62(c)(3) is to provide independent solenoid valves to bleed air from

the scram valve pilot air header on low water level or high dome pressure in the RPV when

detected by the RRCS to increase the reliability of control rod insertion. As described in the

UFSAR Section 9.3.5 and TS 3/4.1.5 and associated TS basis for Limerick, the purpose of the

automatic SLCS as required by 10 CFR 50.62(c)(4) is to provide a backup capability for bringing

the reactor from full power to a cold, Xenon-free shutdown, assuming that the withdrawn control

rods remain fixed in the rated power pattern. As described in the UFSAR Section 7.1 and 7.6

and TS 3/4.3.4 and associated TS basis for Limerick, the purpose of the automatic reactor

coolant recirculation pump trip system as required by 10 CFR 50.62(c)(5) is to provide a means

of limiting the consequences of the unlikely occurrence of a failure to scram during an

anticipated transient.

The NRC staff notes that for 10 CFR 50.62(c)(3), the specific application of the rule over

these temporary 30-day exemption periods is not necessary to achieve the purpose as stated in

Limericks UFSAR section 4.6.1.2.5.4 here because the compensatory actions to manually start

the SLCS will provide the required negative reactivity to mitigate the ATWS. For

10 CFR 50.62(c)(4) - (5), the NRC staff notes that the licensee has demonstrated that the

reactor operators manual actuation of these systems will be able to provide the same level of

ATWS mitigation as the automatic systems dur ing the 30-day RRCS demolition period with the

associated limiting conditions for operation, as evaluated by NRC staff in Section 3.4

Walkthroughs in its SE to the LAR associated with this exemption. Therefore, the specific

application for automatic actuation of the systems required by the rule over these temporary 30-

day exemption periods is not necessary to achieve the purposes as stated in Limericks UFSAR

sections 9.3.5, and TS 3/4.1.5 for 10 CFR 50.62(c)(4) and as stated in Limericks UFSAR

Section 7.1, 7.6, and TS 3/4.3.4 for 10 CFR 50.62(c)(5).

Application of 10 CFR 50.62(c)(3) - (5) during 30-day RRCS demolition period is not

necessary to achieve the underlying purpose of the rule as Constellation stated that since the

provided analysis shows that when the operational constraints of the lower power limit, a higher

number of operable safety relief valves, an additional non-credited automatic action

(recirculation pump runback), and manual activation of the SLCS system within a 5-minute time

frame, an ATWS condition can be successfully mitigated using existing procedures. The NRC

staffs independent review of the analysis provided that the comparable level of ATWS

mitigation protection to the required systems in 10 CFR 50.62(c)(3) - (5) can be achieved with

these proposed operational constraints and that the mitigation measures provide sufficient time

margin for an operator to respond to an ATWS event in place of the required automatic systems

for the limited period of the 30-day RRCS demolition period. Therefore, the underlying purpose

of 10 CFR 50.62(c)(3) - (5), including the specific underlying purposes of each system as

described in the Limerick UFSAR and Tech Spec Bases, are achieved by the licensees

implementation of additional ATWS mitigation strategies identified in the LAR associated with

this exemption and compliance with the TS limiting conditions of operations proposed in LAR

while the licensee turns off the ACI, automatic SLCS, and automatic RTP during the 30-day

RRCS demolition period. Accordingly, compliance with the specific requirements of

10 CFR 50.62 is not necessary during the propos ed 30-day RRCS demolition period to achieve

the underlying purpose of the rule. The NRC staff finds that special circumstances are present

pursuant to 10 CFR 50.12(a)(2)(ii).

Constellation also proposed that 10 CFR 50.12(a)(2)(iv) and 10 CFR 50.12(a)(2)(vi) as

additional special circumstances that are applicable to the exemption request. The NRC staff

has considered their applicability but found that the circumstances discussed above in

10 CFR 50.12(a)(2)(ii) were adequate to address the necessity of special circumstances for the

exemption request.

E. Environmental Considerations

The NRCs approval of the exemption to 10 CFR Part 50.62(c)(3), (c)(4), and (c)(5) belongs to a

category of actions that the NRC, by rule or regulation, has declared to be a categorical

exclusion, after first finding that the category of actions does not individually or cumulatively

have a significant effect on the human environment. Specifically, the exemption is categorically

excluded from further environmental analysis under 10 CFR 51.22(c)(9).

Under 10 CFR 51.22(c)(9), the issuance of an amendment to a license for a reactor

under part 50 or part 52 that changes a requirement or issuance of an exemption from the

requirement of any regulation of 10 CFR is a categorical exclusion provided that:

The proposed action involves the exemption from a requirement for the use of a

facility component located within the restricted area, as defined in 10 CFR Part 20;

The exemption involves no significant haz ards consideration. The basis for the NRC

staffs determination is discussed in the no significant hazards consideration

published in the Federal Register on October 27, 2023 (88 FR 73883);

There is no significant change in the types or significant increase in the amounts of

any effluents that may be released offsite. There are no additional quantities nor

changes in effluents proposed to be released based on the proposed action;

There is no significant increase in individual or cumulative public or occupational

radiation exposure. All manual actions are proposed to be conducted from the main

control room and no local actions are required based on information provided by

Constellation in its letter dated August 16, 2023 (ML23228A094). The main control

room is shielded and staffed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day under normal circumstances;

Therefore, NRC staff has determined that thes e exemptions are categorically excluded

from environmental review pursuant to 10 CFR 51.22(c)(9), and therefore no environmental

assessment or environmental impact statement needs to be prepared in connection with the

- 11 -

proposed exemption request.

III. Conclusions

Accordingly, the NRC has determined that, pursuant to 10 CFR 50.12, the exemption is

authorized by law, will not present an undue risk to public health and safety, and is consistent

with the common defense and security. Special circumstances are also present at Limerick to

justify the exemption. Therefore, the NRC hereby grants Constellation exemptions from all

requirements for ARI capability under section 10 CFR 50.62(c)(3) and only from the automatic

response capability of 10 CFR 50.62(c)(4) for SLCS and 10 CFR 50.62(c)(5) for RPT for a

period of 30-days prior to the 2027 refueling outage for Unit 2 and the 2026 refueling outage for

Unit 1 (also referred to by Constellation as the 30-day RRCS demolition period) while operating

each respective Unit in accordance with the TS limiting conditions for operation and the

additional ATWS mitigation strategies requested in the associated LAR to this exemption

request dated February 17, 2023, as supplemented by letters dated July 21, 2023, July 31,

2023, August 16, 2023, and May 28, 2024 (ML23052A023, ML23202A219, ML23212B105,

ML23228A094, and ML24149A211, respectively). The exemption is authorized by law, will not

present an undue risk to the public health and safety, and is consistent with the common

defense and security. Also, special circumstances are present. Therefore, the Commission

hereby grants Constellation a one-time exemption from 10 CFR part 50, section 50.62(c)(3) and

only the automatic response capability of sections 50.62(c)(4) and 50.62(c)(5) during the 30-day

RRCS demolition period to support the instal lation of the digital upgrade at Limerick.

Dated at Rockville, Maryland, this 31st day of October, 2024

For the Nuclear Regulatory Commission,

Bo M. Pham, Director, Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

ML24151A384 OFFICE DORL/LPL1/PM DORL/LPL1/PM DORL/LPL1/LA NAME MMarshall JKim KZeleznock DATE 01/29/2024 05/30/2024 06/04/2024 OFFICE DRA/APLC/BC DRO/IOLB/BC DSS/SNSB/BC NAME SVasavada (ANeuhausen for) LNist (KMartin for) PSahd DATE 10/07/2024 09/14/2023 11/17/2023 OFFICE DSS/STSB/BC OGC - NLO DORL/LPL1/BC NAME SMehta(A) KBernstein HGonzález DATE 10/25/2023 08/21/2024 10/07/2024 OFFICE DORL/DD DORL/LPL1/PM NAME BPham MMarshall DATE 10/31/2024 10/31/2024