Text

Request for a License Amendment to Delete Obsolete Licensee Conditions and Revise Technical Specifications
	ML082550530
Person / Time
Site:	LaSalle
Issue date:	09/11/2008
From:	Simpson P; Exelon Nuclear
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RS-08-022
	Download: ML082550530 (78)
	v • d • e

RS-08-022 September 11, 2008 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 LaSalle County Station, Units 1 and 2 Facility Operating License Nos. NPF-11 and NPF-18 NRC Docket Nos. 50-373 and 50-374

Subject:

Request for a License Amendment to Delete Obsolete License Conditions and Revise Technical Specifications In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (EGC) requests an amendment to Facility Operating License Nos. NPF-11 and NPF-18 for LaSalle County Station (LSCS) Units 1 and 2, respectively. The proposed amendment removes time, cycle, or modification-related items from the Operating Licenses and Technical Specifications (TS). Additionally, the proposed amendment corrects a typographical error introduced into the TS in a previous amendment. The time, cycle, or modification-related items have been implemented or superseded, are no longer applicable, and no longer need to be maintained in their associated Operating Licenses (OLs) or TS. The attached amendment request is subdivided as shown below. Exellon Nuclear 10 CFR 50.90 " Attachment 1 provides an evaluation of the proposed changes. " Attachments 2 through 4 include marked-up copies of the OLs and TS pages with the proposed changes indicated. " Attachment 5 provides marked-up copies of the TS Bases pages with the proposed changes indicated. The TS Bases pages are provided for information only and do not require NRC approval. EGC requests approval of the proposed change by September 11, 2009, with the amendment being implemented within 30 days of issuance. The proposed changes have been reviewed by the LSCS Plant Operations Review Committee and approved by the Nuclear Safety Review Board in accordance with the requirements of the EGC Quality Assurance Program.

September 8, 2008 U. S. Nuclear Regulatory Commission Page 2 In accordance with 10 CFR 50.91, "Notice for public comment; State consultation," EGC is notifying the State of Illinois of this application for changes to the OLs and TS by transmitting a copy of this letter and its attachments to the designated State Official. There are no regulatory commitments contained in this letter. Should you have any questions concerning this letter, please contact Ms. Tricia Mattson at (630) 657-2813. I declare under penalty of perjury that the foregoing is true and correct. Executed on the 11th day of September 2008. Re,caectfully, K Patrick R. Simpson Manager - Licensing Attachment 1: Evaluation of Proposed Changes Attachment 2: Markup of OL Pages for LaSalle County Station, Unit 1 Attachment 3: Markup of OL Pages for LaSalle County Station, Unit 2 Attachment 4: Markup of TS Pages for LaSalle County Station, Units 1 and 2 Attachment 5: Markup of TS Bases Pages for LaSalle County Station, Units 1 and 2 ATTACHMENT 1 Evaluation of Proposed Changes

Subject:

Request for a License Amendment to Delete Obsolete License Conditions and Revise Technical Specifications 1.0

SUMMARY

DESCRIPTION 5.0 DETAILED DESCRIPTION

3.0 BACKGROUND

4.0 TECHNICAL EVALUATION

5.0 REGULATORY EVALUATION

5.1 No Significant Hazards Consideration 5.2 Applicable Regulatory Requirements/Criteria 5.3 Conclusions 6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

Page 1 of 18 1.0

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (EGC) requests an amendment to Facility Operating License Nos. NPF-11 and NPF-18 for LaSalle County Station (LSCS) Units 1 and 2, respectively. The proposed amendment removes time, cycle, or modification-related items from the Operating Licenses (OLs) and Technical Specifications (TS). Additionally, the proposed amendment corrects a typographical error introduced into the TS in a previous amendment. The time, cycle, or modification-related items have been implemented or superseded, are no longer applicable, and no longer need to be maintained in their associated OLs or TS. Unit 1 License ATTACHMENT 1 Evaluation of Proposed Changes Specifically, the proposed amendment deletes obsolete License Conditions and removes conditional Notes related to TS associated with the Core Standby Cooling System (CSCS) valve replacement project. License Conditions proposed for deletion pertain to actions that have been completed and are no longer applicable. The refueling outages related to the extension of the Completion Times associated with the TS Sections 3.7.1, "Residual Heat Removal Service Water (RHRSW) System," 3.7.2, "Diesel Generator Cooling Water (DGCW) System," and 3.8.1, "AC Sources - Operating," are complete and the added Conditions are no longer needed. Additionally, there is an administrative typographical correction to Reference 1 in TS Section 5.6.5, "Core Operating Limits Report (COLR)." 2.0 DETAILED DESCRIPTION Delete Unit 1 Operating License Condition (OLC) 2.C(3), "Conduct of Work Activities During Fuel Load and Initial Startup," which was closed in NRC Inspection Report 50-373/88018(DRP), page 4, dated August 16, 1988 (Reference 1). Delete Unit 1 OLC 2.C(4), "Resolution of Rebar Damage and Adequacy of Off-Gas Building Roof," which was closed in letter from Harold R. Denton to Cordell Reed, "LaSalle County Station, Unit 1 - Approval to Proceed above Zero Power Physics Testing," dated July 19, 1982 (Reference 2). Delete Unit 1 OLC 2.C(5)(a), "Snubbers," which was closed in NRC Inspection Report 50-373/88018(DRP), page 5, dated August 16, 1988 (Reference 1). Delete Unit 1 OLC 2.C(5)(b), "Snubbers," which was closed in NRC Inspection Report 50-373/84-10(DPRP), page 3, dated May 10, 1984 (Reference 3). Letter dated March 23, 1984, submitted a proposed amendment to License NPF-11 to delete the snubber list in its entirety. Amendment 18 to License NPF-11, which approved the deletion of the snubber list, was issued August 8, 1984 (Reference 4). The requirement in the License Condition to replace snubbers that were removed with rigid strut and rod assemblies was carried as a long term Unresolved Item (373/82-15-01) that was closed in N RC Inspection Report 50-373/86010(DRP), page 3, dated April 7, 1986 (Reference 5). Delete Unit 1 OLC 2.C(6), "Deferred Preoperational Deficiencies," which was closed in NRC Inspection Report 50-373/82-30(DPRP), page 2, dated August 16, 1982 (Reference 6). Page 2 of 18 ATTACHMENT 1 Evaluation of Proposed Changes Delete Unit 1 OLC 2.C(7), "Surveillance of Tendons (Section 3.8.1,SSER #3 (NUREG-0519))," which was closed in NRC Inspection Report 50-373/83-12(DPRP), page 4, dated June 8, 1983 (Reference 7). Delete Unit 1 OLC 2.C(8)(a), "Masonry Wall (Section 3.8.3, SER, SSER #2 (NUREG-0519))," which was closed in NRC Inspection Report 50-373/83-34(DPRP), page 5, dated October 24, 1983 (Reference 8). Delete Unit 1 OLC 2.C(8)(b), "Masonry Wall (Section 3.8.3, SER, SSER #2 (NUREG-0519))," which was closed in NRC Inspection Report 50-373/83-20 (DPRP), page 2, dated July 14, 1983 (Reference 9). Delete Unit 1 OLC 2.C(9), "Inservice Testing of Pumps and Valves (Section 3.9.6, SER (NUREG-0519))," which was closed in SSER #8 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 8," page 1-2, dated March 1984 (Reference 10). Delete Unit 1 OLC 2.C(10)(a), "Dynamic Qualification (Section 3.10, SER, SSER #1, SSER #2 (NUREG-0519))," which was closed in SSER #6 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 6," page 3-2, dated November 1983 (Reference 11). Delete Unit 1 OLC 2.C(1 0)(b), "Dynamic Qualification (Section 3.10, SER, SSER #1, SSER #2 (NUREG-0519))," which was closed in NRC Inspection Report 50-373/82-52(DPRP), page 2, dated January 18, 1983 (Reference 12). Delete Unit 1 OLC 2.C(1 1)(a), "Environmental Qualifications (Section 3.11, SER, SSER #1, SSER #2 (NUREG-0519))," which was closed in NRC Inspection Report 50-373/87003(DRS), page 5, dated March 13, 1987 (Reference 13). Delete Unit 1 OLC 2.C(1 1)(b), "Environmental Qualifications (Section 3.11, SER, SSER #1, SSER #2 (NUREG-0519))," which was closed in NRC Inspection Report 50-373/87003(DRS), page 5, dated March 13, 1987 (Reference 13). Delete Unit 1 OLC 2.C(1 2)(a), "Seismic and Loss-of-Coolant Accident Loads (Section 4.2.3.4, SER (NUREG-0519), and Supplements 1 and 2)," which was closed in NRC Inspection Report 50-373/82-41(DPRP), page 2, dated October 4, 1982 (Reference 14). Delete Unit 1 OLC 2.C(12)(b), "Seismic and Loss-of-Coolant Accident Loads (Section 4.2.3.4, SER (NUREG-0519), and Supplements 1 and 2)," which was closed in SSER #5 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 5," page 4-2, dated August 1983 (Reference 15). Delete Unit 1 OLC 2.C(13), "Surveillance of Control Blade (Section 4.2.3.14, SER (NUREG-0519))," which was closed in NRC Inspection Report 50-373/86044(DRP), page 3, dated January 28, 1987 (Reference 16). Delete Unit 1 OLC 2.C(14)(a), "Scram Discharge Volume (Section 4.6.2, SER and 6.3.2.3, SSER #2 (NUREG-0519))," which was closed in NRC Inspection Report 50-373/86017(DRS), page 9, dated June 24, 1986 (Reference 17). Reference 17 refers to closing out OLC 2.C(14)(b), however, the Inspection Report actually closes out the current OLC 2.C(14)(a). Page 3 of 18 ATTACHMENT 1 Evaluation of Proposed Changes Delete Unit 1 OLC 2.C(14)(b), "Scram Discharge Volume (Section 4.6.2, SER and 6.3.2.3, SSER #2 (NUREG-0519))," which was closed in SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," page 6-6, dated July 1982 (Reference 18). Delete Unit 1 OLC 2.C(15), "Low Pressure in Pump Discharge of the Control Rod Drive (Section 4.6.2, SSER #2 (NUREG-0519))," which was closed in NRC Inspection Report 50-373/86017(DRS), pages 9 and 10, dated June 24, 1986 (Reference 17). Reference 17 refers to closing out OLC 2.C(12), however, the Inspection Report actually closes out the current OLC 2.C(15). Delete Unit 1 OLC 2.C(16), "Containment Long Term Program Load Specifications (Section 6.2.1.1, SSER #2 (NUREG-0519))," which was closed by SSER #6 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 6," page 3-2, dated November 1983 (Reference 11). Delete Unit 1 OLC 2.C(18), "Compliance with Regulatory Guide 1.97 (Sections 7.5.2, SER)," which was closed out by letter from C.W. Schroeder (Licensee) to A. Schwencer (NRC), "LaSalle County Station Units 1 and 2 Compliance with Regulatory Guide 1.97," dated June 29, 1982 (Reference 19). Delete Unit 1 OLC 2.C(19), "Additional Instrumentation and Control Concerns (Section 7.7.3.4, SSER #1 (NUREG-0519))," which was closed by SSER #7 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 7," page 7-11, dated December 1983 (Reference 20). Delete Unit 1 OLC 2.C(20), "Low and/or Degraded Grid Voltage (Section 8.2.2.2, SER (NUREG-0519))," which was closed in NRC Inspection Report 50-373/86017(DRS), page 9, dated June 24, 1986 (Reference 17). Delete Unit 1 OLC 2.C(21)(a), "Reliability of Diesel-Generators (Sections 8.3.1.1, SER and 9.6.3.4, SER (NUREG-0519))," which was closed in NRC Inspection Report 50-373/86044(DRP), pages 2-3, dated January 28, 1987 (Reference 16). Delete Unit 1 OLC 2.C(21)(b), "Reliability of Diesel-Generators (Sections 8.3.1.1, SER and 9.6.3.4, SER (NUREG-0519))," which was closed in SSER #5 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 5," page 9-5, dated August 1983 (Reference 15). Delete Unit 1 OLC 2.C(21)(c), "Reliability of Diesel-Generators (Sections 8.3.1.1, SER and 9.6.3.4, SER (NUREG-0519))," which was closed in NRC Inspection Report 50-373/86017(DRS), page 9, dated June 25, 1986 (Reference 21). Delete Unit 1 OLC 2.C(22), "Direct Current Power Systems (Section 8.3.1.2, SER (NUREG-0519))," which was closed in NRC Inspection Report 50-373/86033(DRP), page 2, dated September 15, 1986 (Reference 22). Delete Unit 1 OLC 2.C(23), "Reactor Containment Electrical Penetrations (Section 8.4.1, SER (NUREG-0519))," which was closed In NRC Inspection Report 50-373/86033(DRP), page 2, dated September 15, 1986 (Reference 22). Page 4 of 18 ATTACHMENT 1 Evaluation of Proposed Changes Delete Unit 1 OLC 2.C(24), "Separation of Class 1 E and Non-Class 1 E Cable Trays (Section 8.4.6.1, SER, SSER #1 and SSER #2 (NUREG-0519))," which was closed by SSER #5 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 5," page 8-1, dated August 1983 (Reference 15). Delete Unit 1 OLC 2.C(28), "Initial Test Program (Section 14, SER (NUREG-0519))

." The Startup Test Program was approved by the NRC and completed in the final initial test program report submitted to the NRC by letter from C. W. Schroeder (Licensee) to James G. Keppler (NRC), dated December 6, 1983 (Reference 23). Delete Unit 1 OLC 2.C(29), "Assurance of Proper Design and Construction (Section 17.4, SSER #2 (NUREG-0519))," which was closed by SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," page 1-2, dated July 1982 (Reference 18). Delete Unit 1 OLC 2.C(30)(b), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))," which was closed in NRC Inspection Report 50-373/82-32(DETP), page 3, dated July 16, 1982 (Reference 24). Delete Unit 1 OLC 2.C(30)(c), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))," which was closed in NRC Inspection Report 50-373/82-18(DPRP), page 6, dated April 16, 1982 (Reference 25). Delete Unit 1 OLC 2.C(30)(d), "Control Room Design Review (I.D.1, SER, SSER#2)," which was closed in letter from P. C. Shemanski (NRC) to T. J. Kovach (Licensee), "Safety Evaluation Report for Commonwealth Edison's LaSalle County Station Units 1 and 2 Detailed Control Room Design Review (TAC Nos. 51172 and 57498)," dated June 28, 1989 (Reference 26). Delete Unit 1 OLC 2.C(30)(e), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))," which was closed in SSER #6 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 6," page 22-2, dated November 1983 (Reference 11). Delete Unit 1 OLC 2.C(30)(f), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))," which was closed in SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," page 1-1, dated July 1982 (Reference 18). Delete Unit 1 OLC 2.C(30)(g), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))," which was closed in NRC Inspection Report 373/84-05(DPRP), page 2, dated April 6, 1984 (Reference 27). Delete Unit 1 OLC 2.C(30)(h), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Additional Accident Monitoring Instrumentation (II.F.1, SER, SSER #2))," which was closed in SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," page 1-1, dated July 1982 (Reference 18). Delete Unit 1 OLC 2.C(30)(i), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Instrumentation for Detection of Inadequate Core Cooling (II.F.2, SER, SSER #1, SSER #2)," Page 5 of 18 ATTACHMENT 1 Evaluation of Proposed Changes which was closed in NRC Inspection Report 50-373/83-12(DPRP), page 3, dated June 6, 1983 (Reference 28). Delete Unit 1 OLC 2.C(30)(j), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Proper Functioning of Heat Removal Systems (II.K.1.22, SER, SSER #2, and II.K.3.13, SER, SSER #2)," which was closed in NRC Inspection Report 50-373/84-33(DRP), page 3, dated February 25, 1985 (Reference 29). Delete Unit 1 OLC 2.C(30)(k), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Modify Break Detection Logic to Prevent Spurious Isolation of High Pressure Coolant Injection and Reactor Core Isolation Cooling System (II.K.3.15, SER, SSER #2)," which was closed in NRC Inspection Report 50-373/86035(DRP), page 3, dated October 23, 1986 (Reference 30). Delete Unit 1 OLC 2.C(30)(I)(a), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Modification of Automatic Depressurization System Logic - Feasibility for Increased Diversity for Some Event Sequences (II.K.3.18, SER, SSER #1, SSER #3)," which was closed in NRC Inspection Report 50-373/82-49(DPRP), page 11, dated November 18, 1982 (Reference 31). Delete Unit 1 OLC 2.C(30)(I)(b), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Modification of Automatic Depressurization System Logic - Feasibility for Increased Diversity for Some Event Sequences (II.K.3.18, SER, SSER #1, SSER #3)," which was closed in NRC Inspection Report 50-373/86033(DRP), page 9, dated September 15, 1986 (Reference 22). Delete Unit 1 OLC 2.C(30)(m), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Restart of Core Spray and Low Pressure Core Injection System (II.K.3.21, SER, SSER #2)," which was closed in NRC Inspection Report 50-373/84-33(DRP), page 3, dated February 25, 1985 (Reference 29). Delete Unit 1 OLC 2.C(30)(n), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Automatic Switchover of Reactor Core Isolation Cooling System Suction - Verify Procedures and Modify Design (II.K.3.22, SER)," which was closed in NRC Inspection Report 50-373/83-25(DPRP), page 2, dated August 2, 1983 (Reference 32). Delete Unit 1 OLC 2.C(30)(o), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Upgrade Emergency Support Facilities (III.A.1.2, SER, SSER #1)," which was closed in NRC Inspection Report 50-373/83-21(DRMSP), page 2, dated July 15, 1983 (Reference 33). Delete Unit 1 OLC 2.C(30)(p)(1), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Improving Licensee's Emergency Preparedness - Long Term(III.A.2, SER, SSER #1, SSER #2)," which was closed in SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," page 22-1, dated July 1982 (Reference 18). Delete Unit 1 OLC 2.C(30)(p)(2), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Improving Licensee's Emergency Preparedness - Long Term (III.A.2, SER, SSER #1, SSER #2)," which was closed in SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," page 22-1, dated July 1982 (Reference 18). Delete Unit 1 OLC 2.C(30)(p)(3), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Improving Licensee's Emergency Preparedness - Long Term (III.A.2, SER, SSER #1, SSER Page 6 of 18 ATTACHMENT I Evaluation of Proposed Changes #2)," which was closed in NRC Inspection Report 50-373/88018(DRP), page 5, dated August 16, 1988 (Reference 1). Delete Unit 1 OLC 2.C(30)(p)(4), "NUREG-0737 Conditions (Section 22.2, SER (NUREG-0519))

Improving Licensee's Emergency Preparedness - Long Term (III.A.2, SER, SSER #1, SSER #2)," which was closed in SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," page 22-2 dated July 1982 (Reference 18). Delete Unit 1 OLC 2.C(31), "Bolting of Valves," which was closed in NRC Inspection Report 50-373/83-12(DPRP), page 3, dated June 8, 1983 (Reference 7). Delete Unit 1 OLC 2.C(32), "Vacuum Breaker Valves," which was closed in NRC Inspection Report 50-373/82-52(DPRP), page 2, dated January 18, 1983 (Reference 12). Delete Unit 1 OLC 2.C(33)(a), "Heating - Ventilation and Air Conditioning Systems," which was closed in NRC Inspection Report 50-373/83-01(DPRP), page 3, dated February 25, 1983 (Reference 34). Delete Unit 1 OLC 2.C(33)(b), "Heating - Ventilation and Air Conditioning Systems," which was closed in NRC Inspection Report 50-373/83-01(DPRP), page 3, dated February 25, 1983 (Reference 34). Delete Unit 1 OLC 2.C(35), "Surveillance Interval Extension," which is a time-specific interval extension for Surveillance Requirements (SRs) coinciding with the seventh refueling outage. This extension was approved in letter from Robert M. Latta (NRC) to D. L. Farrar (Licensee), "Issuance of Amendments (TAC Nos. M92053 and M92054)," dated September 27, 1995 (Reference 35). This outage was completed as planned; therefore, this extension is no longer required and can be removed from this section of the OL. Delete Unit 1 OLC 2.C(36), "Relocated Technical Specifications," which allowed certain TS requirements to be relocated to the licensee-controlled UFSAR. This relocation was approved in letter from Donna M. Skay (NRC) to Irene Johnson (Licensee), " Issuance of Amendments (TAC Nos. M97174 AND M97175)," dated January 29, 1997 (Reference 36). Those TS requirements were moved and have been maintained in the LaSalle County Station UFSAR and therefore condition 2.C(36) is considered closed. Delete Unit 1 OLC 2.C(42), which allowed certain TS requirements to be relocated to licensee-controlled documents. This condition was approved by the NRC in letter from Stewart N. Bailey (NRC) to Oliver D. Kingsley (Licensee), "Issuance of Amendments (TAC Nos. MA8388 and MA8390)," dated March 30, 2001 (Reference 37). Those TS requirements were moved and have been maintained in licensee controlled documents and therefore condition 2.C(42) is considered closed. Delete Unit 1 OLC 2.C(43), which revised the schedule for performance of several SRs due to a change in the surveillance intervals of the SRs during conversion to Improved Standard Technical Specifications. The condition was approved by the NRC in letter from Stewart N. Bailey (NRC) to Oliver D. Kingsley (Licensee), "Issuance of Amendments (TAC Nos. MA8388 and MA8390)," dated March 30, 2001 (Reference 37). The revision of the schedule for SRs became effective March 30, 2001 and therefore condition 2.C(43) is considered closed. Page 7 of 18 ATTACHMENT 1 Evaluation of Proposed Changes Delete Unit 1 OLC 2.D(b), which allowed a one-time exemption from the requirements of 10 CFR 70.24. This exemption was requested until the completion of the first refueling of LaSalle County Station. This exemption was approved by the NRC in SSER #2 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 2," page 22-1 dated February 1982 (Reference 38). This outage was completed as planned; therefore, this exemption is obsolete and can be removed from this section of the OL. Delete Unit 1 OLC 2.D(c), which allowed a one-time exemption from 10 CFR 50, Appendix E that requires performing a full-scale exercise within one year before the issuance of an OL. This exemption was approved by the NRC in SSER #2 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 2," page 22-1 dated February 1982 (Reference 38). The exemption required that all participants perform a small-scale exercise again within the months prior to issuance of the full power OL. Because this was a one-time exemption, this condition is considered closed. Delete Unit 1 OLC 2.D(d), which allowed a one-time exemption from 10 CFR 50.44 until either the required 100 percent rated thermal power trip startup test was completed or the reactor operated for 120 effective full power days. The exemption was approved by the NRC in letter from Darrell G. Eisenhut (NRC) to Louis L. DelGeorge (Licensee), "Amendment No. 12 to OL No. NPF LaSalle County Station, Unit 1," dated December 20, 1982 (Reference 39). This was a one-time only exemption and is therefore obsolete and should be deleted. Delete Unit 1 OL Attachment 1 in its entirety. Attachment 1 identified certain preoperational tests, system demonstrations and other items that were required to be completed to the satisfaction of the NRC prior to proceeding to Mode 2 (i.e., initial criticality of 212°F). LSCS was not permitted to proceed beyond this Operational Mode without written confirmation from the NRC that the items contained in Attachment 1 were completed. In a letter from the NRC to Commonwealth Edison dated June 19, 1982 (Reference 40), the NRC confirmed that they have reviewed items identified in Attachment 1 to FOL NPF-11 and determined that they were completed in accordance with the conditions. Reference 39 also allowed LSCS Unit 1 to proceed with reactor operations in Mode 2 to initial criticality and zero power physics testing. Further confirmation of the completion of all preoperational tests, startup tests, and other items identified in Attachment 1 to NPF-11 is documented in the July 1982 issuance of the Safety Evaluation Report for LSCS Units 1 and 2 (Reference

18) and therefore Attachment 1 to NPF-11 is obsolete and should be deleted. Page 8 of 18 Deletion of Unit 2 License Conditions ATTACHMENT 1 Evaluation of Proposed Changes Delete Unit 2 OLC 2.C(3), "Conduct of Work Activities During Fuel Load and Initial Startup." The NRC closed out preoperational and startup tests in SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," Section 1.1, dated July 1982 (Reference 18). Delete Unit 2 OLC 2.C(4), "Inservice Testing of Pumps and Valves (Section 3.9.6, SER'`)," which granted a one-time relief request from the pump and valve testing requirements of 10 CFR 50.55, Sections 55.55a(g)(2) and (g)(4)(i). The condition was closed in letter from P.C. Shemanski t o H.E. Bliss, "LaSalle County Station Units 1 and 2 Response to Questions from the Safety Evaluation Report and Relief of the Inservice Testing Program for Pumps and Valves NRC Docket No. 50-373 & 50-374," dated August 16, 1988 (Reference 41). This was a one-time relief request and therefore, is obsolete and can be deleted. Delete Unit 2 OLC 2.C(5), "Environmental Qualifications (Section 3.11, SER, SSER #1, SSER #5)," which was closed in NRC Inspection Report 50-374/87003(DRS), page 5, dated March 13, 1987 (Reference 42). Delete Unit 2 OLC 2.C(6), "Surveillance of Control Blade (Section 4.2.3.14, SER)," which was closed in NRC Inspection Report 50-374/87019(DRP), page 3, dated August 20, 1987 (Reference 43). Delete Unit 2 OLC 2.C(7), "Low Pressure in Pump Discharge of the Control Rod Drive (Section 4.6.2, SSER #2, and Section 7.2.3.2, SSER #7)," which was closed in NRC Inspection Report 50-374/84-33(DRP), page 3, dated November 26, 1984 (Reference 44). Delete Unit 2 OLC 2.C(8), "Containment Isolation System (Section 6.2.1.1, SSER#2 and Section 3.9.3.1, SSER #5, SSER #6)," which was closed in NRC Inspection Report 50-374/87018(DRP), page 10, dated July 8, 1987 (Reference 45). Delete Unit 2 OLC 2.C(9), "Standby Liquid Control System Cable Termination (Section 7.2.3.2, SSER #7)," which was closed in NRC Inspection Report 50-374/83-56(DPRP), page 2, dated January 30, 1984 (Reference 46). Delete Unit 2 OLC 2.C(10), "Cable Separation Concerns (Section 7.3.3.2, SSER #7)," which was closed in NRC Inspection Report 50-374/86044(DRP), page 2, dated January 28, 1987 (Reference 16). Delete Unit 2 OLC 2.C(11), "Low and/or Degraded Grid Voltage (Section 8.2.2.2, SER)," which was closed in NRC Inspection Report 50-374/87018(DRP), page 3, dated July 8, 1987 (Reference 45). Delete Unit 2 OLC 2.C(12), "Reliability of Diesel-Generators (Sections 8.3.1.1 and 9.6.3.4, SER, SSER #5)," which was closed in NRC Inspection Report 50-374/87018(DRP), page 3, dated July 8, 1987 (Reference 45). Delete Unit 2 OLC 2.C(13), "Direct Current Power Systems (Section 8.3.1.2, SER)," which was closed in NRC Inspection Report 50-374/84-26(DRP), page 2, dated October 1, 1984 (Reference 47). Page 9 of 18 ATTACHMENT 1 Evaluation of Proposed Changes Delete Unit 2 OLC 2.C(14), "Control of Heavy Loads (Section 9.1, SSER #1, SSER #5)," which was closed in NRC Inspection Report 50-374/85009(DRP), page 2, dated April 17, 1985 (Reference 48). Delete Unit 2 OLC 2.C(17), "Initial Test Program (Section 14, SER, SSER #7)." The Startup Test Program was approved by the NRC and completed in the final initial test program report submitted to the NRC by letter from C. W. Schroeder (Licensee) to James G. Keppler (NRC), dated December 6, 1983 (Reference 23). Delete Unit 2 OLC 2.C(18)(a), "NUREG-0737 Conditions (Section 22.2)," which was closed in SSER #8 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 8," page 1-2, dated March 1984 (Reference 10). Delete Unit 2 OLC 2.C(18)(b), "NUREG-0737 Conditions (Section 22.2)," which was closed in NRC Inspection Report 50-374/84-26(DRP), page 2, dated October 1, 1984 (Reference 47). Delete Unit 2 OLC 2.C(18)(c), "NUREG-0737 Conditions (Section 22.2)," which was closed in NRC Inspection Report 50-374/88003(DRP), page 9, dated February 5, 1988 (Reference 49). Delete Unit 2 OLC 2.C(18)(d), "NUREG-0737 Conditions (Section 22.2)," which was closed in NRC Inspection Report 50-374/87018(DRP), page 9, dated July 8, 1987 (Reference 45). Delete Unit 2 OLC 2.C(19), "Surveillance Interval Extension," which is a time-specific interval extension for surveillance requirements coinciding with the seventh refueling outage. This extension was approved by the NRC in letter from Robert M. Latta (NRC) to D. L. Farrar (Licensee), "Issuance of Amendments (TAC Nos. M92053 and M92054)," dated September 27, 1995 (Reference 35). This outage was completed as planned; therefore, this exemption is obsolete and should be deleted. Delete Unit 2 OLC 2.C(20), "Relocated Technical Specifications," which allowed certain TS requirements to be relocated to the licensee-controlled UFSAR. This relocation was approved by the NRC in letter from Donna M. Skay (NRC) to Irene Johnson (Licensee), "Issuance of Amendments (TAC Nos. M97174 AND M97175)," dated January 29, 1997 (Reference 36). Those TS requirements were moved and have been maintained in the LaSalle County Station UFSAR and therefore condition 2.C(20) is considered closed. Delete Unit 2 OLC 2.C(26) which allowed certain TS requirements to be relocated to licensee-controlled documents. The condition was approved by the NRC in letter from Stewart N. Bailey (NRC) to Oliver D. Kingsley (Licensee), "Issuance of Amendments (TAC Nos. MA8388 and MA8390)," dated March 30, 2001 (Reference 50). Those TS requirements were moved and have been maintained in licensee controlled documents and therefore, OLC 2.C(26) is considered complete. Delete Unit 2 OLC 2.C(27) which revised the schedule for performance of several SRs due to a change in the surveillance intervals of the SRs during conversion to Improved Standard Technical Specifications. The condition was approved by the NRC in letter, "Issuance of Amendments (TAC Nos. MA8388 and MA8390)," from Stewart N. Bailey (NRC) to Oliver D. Kingsley (Licensee), dated March 30, 2001 (Reference 50). The revision of the schedule for SRs became effective March 30, 2001 and therefore, OLC 2.C(27) is considered complete. Page 10 of 18 ATTACHMENT 1 Evaluation of Proposed Changes Delete Unit 2 OLC 2.D(b) which allowed a one-time exemption from the requirements of 10 CFR 70.24. This exemption was requested until the completion of the first refueling of LaSalle County Station. This exemption was approved by the NRC in SSER #2 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 2," page 22-1 dated February 1982 (Reference 38). This outage was completed as planned; therefore, this exemption is obsolete and can be removed from this section of the OL. Delete Unit 2 OLC 2.D(d) which allowed a one-time exemption from the requirements of paragraph IILD of Appendix J to conduct the third Type A test of each ten-year schedule of three times in ten years. The exemption was approved by the NRC in letter from William D. Reckley (NRC) to D. L. Farrar (Licensee), "Issuance of Amendments (TAC Nos. M90702 and M90703)," dated March 16, 1995 (Reference 51). This was a one-time exemption and therefore, is obsolete and can be deleted. Delete Unit 2 OL Attachment 1 in its entirety. Attachment 1 identified certain preoperational tests, system demonstrations and other items that were required to be completed to the satisfaction of the NRC prior to proceeding to Mode 2. Condition A1 was completed and closed in NRC Inspection Report 50-374/84-05(DPRP), page 9, dated April 18, 1984 (Reference 51). Condition A2 was completed and closed in NRC Inspection Report 50-374/83-52(DPRP), page 7, dated January 6, 1984 (Reference 52). Condition B was completed and closed in NRC Inspection Report 50-374/84-05(DPRP), page 11, dated April 18, 1984 (Reference 51). Condition C was completed and closed in NRC Inspection Report 50-374/84-13(DPRP), page 3, dated May 10, 1984 (Reference 53). Condition D was completed and closed in NRC Inspection Report 50-374/84-13(DPRP), page 3, dated May 10, 1984 (Reference 53). Delete Unit 2 OIL Attachment 2 in its entirety. Condition 1(a) was completed and closed in the enclosure of a letter from A. Schwencer (NRC) to D. Farrar (Licensee), "Order Confirming Licensee Commitments on Emergency Response Capability," dated February 21, 1984 (Reference 54). Condition 1(b) was completed and closed in NRC Inspection Report 50-374/84-26(DRP), page 2, dated October 1, 1984 (Reference 47). Condition 2(b) was completed and closed in NRC Inspection Report 50-374/83-52(DPRP), page 3, dated January 4, 1984 (Reference 55). Condition 3(b) was completed and closed in letter from D. R. Muller (NRC) to L. D. Butterfield, Jr. (Licensee), "Emergency Response Capability, Conformance to Regulatory Guide 1.97, Revision 2, LaSalle County Station, Units 1 and 2 (TAC Nos. 51102 and 56407)," dated August 20, 1987 (Reference 56). Page 1 1 of 18 Conditions 5(a) and 5(c) were closed by letter to Mr. Harold R. Denton (NRC) from C.M. Allen (Licensee), subject, "LaSalle County Station Units 1 and 2, Human Factors Review of R.R. 1.97 Instrumentation, NRC Docket Nos. 50-373 and 50-374," dated August 1, 1986 (Reference 58). TS Sections 3.7.1, 3.7.2 and 3.8.1 ATTACHMENT I Evaluation of Proposed Changes Conditions 4(a) and 4(b) were completed and closed in NRC Inspection Report 50-373/86046(DRP), page 2, dated February 17, 1987 (Reference 57). Delete from LCO 3.7.1 the Note above Condition A, "One RHRSW subsystem inoperable," and delete from LCO 3.7.1 the extension to the Completion Time (CT) for Required Action B.1, "Restore RHRSW subsystem to OPERABLE status," from 7 days to 10 days. This change was used during the Unit 1 Spring 2006 Refueling Outage. Delete from LCO 3.7.2 the Notes above Condition A, "One or more DGCW subsystems inoperable

." Remove the 6 day (for Division 2 Core Standby Cooling System (CSCS) maintenance) and 10 day (for Division 1 CSCS maintenance)

CT for TS Section 3.7.2 when one or more required DGCW subsystem(s) are inoperable. This change was used during the Unit 1 Spring 2006, Unit 2 Spring 2007, and Unit 1 Spring 2008 refueling outages. Delete from LCO 3.8.1 the Notes above Condition C, "Required Division 3 DG inoperable

." Delete from LCO 3.8.1 the Notes above Condition F, "Two required Division 1, 2, or 3 DGs inoperable

." Delete from LCO 3.8.1 the extension to the CT for Required Action G.1, "Restore required Division 2 DG to OPERABLE status," from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 6 days, and delete the corresponding Condition I, "Required Action and associated Completion Time of Condition G not met." This change was used during the Unit 2 Spring 2007 and Unit 1 Spring 2008 refueling outages. This revision will result in various editorial and formatting changes. TS Section 5.6.5 Revise Reference 1 in TS Section 5.6.5 to align with the title used in the COLR. This administrative change will correct the title of the referenced document.

3.0 BACKGROUND

Historically, conditions, exceptions, or exemptions that are date, cycle, or modification-related have been captured in the OL. Over time, the actions or requirements that these items contain are implemented, and the issues no longer need to be reflected in the OL. In an effort to clarify, and avoid any confusion regarding the current requirements contained in the OL, EGC is proposing the administrative removal of these items from the OL and TS for LaSalle County Station. 4.0 TECHNICAL EVALUATION All proposed changes are administrative in nature and require no technical analysis. Page 1 2 of 18

5.0 REGULATORY EVALUATION

ATTACHMENT 1 Evaluation of Proposed Changes 5.1 No Significant Hazards Consideration In accordance with 10 CFR 50.90, " Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (EGC) is requesting an amendment to Operating License (OL) Nos. NPF-11 and NPF-18 for LaSalle County Station. The proposed amendment provides for the administrative removal of time, cycle, or modification-related items from the OLs at both stations. These items have been implemented or superseded, are no longer applicable, and therefore, no longer need to be maintained in their associated OL. According to 10 CFR 50.92, "Issuance of amendment," paragraph (c), a proposed amendment to an OL involves no significant hazards consideration if operation of the facility in accordance with the proposed amendment would not: Involve a significant increase in the probability or consequences of an accident previously evaluated; or Create the possibility of a new or different kind of accident from any accident previously evaluated; or Involve a significant reduction in a margin of safety. In support of this determination, an evaluation of each of the three criteria set forth in 10 CFR 50.92 is provided below regarding the proposed license amendment. 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The initial conditions and methodologies used in the accident analyses remain unchanged. The proposed changes do not change or alter the design assumptions for the systems or components used to mitigate the consequences of an accident. Therefore, accident analyses results are not impacted. All changes proposed by EGC in this amendment request are administrative in nature, and are removing one-time requirements that have been satisfied or items that are no longer applicable. There are no physical changes to the facilities, nor any changes to the station operating procedures, limiting conditions for operation, or limiting safety system settings. Based on the above discussion, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated. 2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Page 1 3 of 18 Response: No None of the proposed changes affect the design or operation of any system, structure, or component in the plant. The safety functions of the related structures, systems, or components are not changed in any manner, nor is the reliability of any structure, system, or component reduced by the revised surveillance or testing requirements. The changes do not affect the manner by which the facility is operated and do not change any facility design feature, structure, system, or component. No new or different type of equipment will be installed. Since there is no change to the facility or operating procedures, and the safety functions and reliability of structures, systems, or components are not affected, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated. Based on this evaluation, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated. 3. Does the proposed amendment involve a significant reduction in a margin of safety? Response: No 5.3 Conclusions ATTACHMENT I Evaluation of Proposed Changes The proposed changes to the Facility Operating Licenses and TS are administrative in nature and have no impact on the margin of safety of any of the TS. There is no impact on safety limits or limiting safety system settings. The changes do not affect any plant safety parameters or setpoints. The OLCs have been satisfied as required. Based on this evaluation, the proposed change does not involve a significant reduction in a margin of safety. Therefore, EGC concludes that the proposed changes do not involve a significant hazards consideration under the criteria set forth in 10 CFR 50.92(c). 5.2 Applicable Regulatory Requirements/Criteria 10 CFR 50.36 details the information that must be included in each station's TS. The proposed changes modify or delete time, cycle, or modification-related items that have been implemented or superseded, and are no longer applicable. The proposed changes have no impact on current Safety Limits, Limiting Safety System Settings, Limiting Control Settings, Limiting Conditions for Operation, Surveillance Requirements, Design Features, or Administrative Controls. Therefore, EGC concludes that the methods used to comply with 10 CFR 50.36 are not modified by the proposed changes, and the requirements continue to be met. In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Page 1 4 of 18 6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

ATTACHMENT 1 Evaluation of Proposed Changes Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public. Portions of the proposed amendment change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, "Standards for protection against radiation," or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in paragraph (c)(9) of 10 CFR 51.22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review." Therefore, in accordance with 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment. Portions of the proposed amendment are confined to (i) changes to surety, insurance, and/or indemnity requirements, or (ii) changes to recordkeeping, reporting, or administrative procedures or requirements. Accordingly, these portions of the proposed amendment meet the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(10). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with these portions of the proposed amendment. 1. NRC Inspection Report 50-373/88018(DRP), dated August 16, 1988 2. Letter from Harold R. Denton (NRC) to Cordell Reed (Licensee), "LaSalle County Station, Unit 1 - Approval to Proceed above Zero Power Physics Testing," dated July 19, 1982 3. NRC Inspection Report 50-373/84-10(DPRP), dated May 10, 1984 4. Letter from A. Schwencer (NRC) to Dennis L. Farrar (Licensee), "Amendment No. 18 to Facility Operating License No. NPF-11 LaSalle County Station, Unit 1," dated August 8, 1984 5. NRC Inspection Report 50-373/86010(DRP), dated April 7, 1986 6. NRC Inspection Report 50-373/82-30(DPRP), dated August 16, 1982 7. NRC Inspection Report 50-373/83-12(DPRP), dated June 8, 1983 8. NRC Inspection Report 50-373/83-34(DPRP), dated October 24, 1983 9. NRC Inspection Report 50-373/83-20 (DPRP), dated July 14, 1983 Page 15 of 18 ATTACHMENT I Evaluation of Proposed Changes 10. SSER #8 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 8," dated March 1984 11. SSER #6 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 6," dated November 1983 12. NRC Inspection Report 50-373/82-52(DPRP), dated January 18, 1983 13. NRC Inspection Report 50-373/87003(DRS), dated March 13, 1987 14. NRC Inspection Report 50-373/82-41(DPRP), dated October 4, 1982. 15. SSER #5 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 5," dated August 1983 16. NRC Inspection Report 50-374/86044(DRP), dated January 28, 1987 17. NRC Inspection Report 50-373/86017(DRS), dated June 24, 1986 18. SSER #4 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 4," dated July 1982 19. Letter from C.W. Schroeder (Licensee) to A. Schwencer (NRC), "LaSalle County Station Units 1 and 2 Compliance with Regulatory Guide 1.97," dated June 29, 1982 20. SSER #7 (NUREG-0519), "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 7," dated December 1983 21. NRC Inspection Report 50-373/86017(DRS), June 25, 1986 22. NRC Inspection Report 50-373/86033(DRP), dated September 15, 1986 23. Letter from C. W. Schroeder (Licensee) to James G. Keppler (NRC), dated December 6, 1983 24. NRC Inspection Report 50-373/82-32(DETP), dated July 16, 1982 25. NRC Inspection Report 50-373/82-18(DPRP), dated April 16, 1982 26. Letter from P. C. Shemanski (NRC) to T. J. Kovach (Licensee), "Safety Evaluation Report for Commonwealth Edison's LaSalle County Station Units 1 and 2 Detailed Control Room Design Review (TAC Nos. 51172 and 57498)," dated June 28, 1989 27. NRC Inspection Report 373/84-05(DPRP), dated April 6, 1984 28. NRC Inspection Report 50-373/83-12(DPRP), dated June 6, 1983 29. NRC Inspection Report 50-373/84-33(DRP), dated February 25, 1985 30. NRC Inspection Report 50-373/86035(DRP), dated October 23, 1986 Page 1 6 of 18 ATTACHMENT 1 Evaluation of Proposed Changes 31. NRC Inspection Report 50-373/82-49(DPRP), dated November 18, 1982 32. NRC Inspection Report 50-373/83-25(DPRP), dated August 2, 1983 33. NRC Inspection Report 50-373/83-21(DRMSP), dated July 15, 1983 34. NRC Inspection Report 50-373/83-01(DPRP), dated February 25, 1983 35. Letter from Robert M. Latta (NRC) to D. L. Farrar (Licensee), "Issuance of Amendments (TAC Nos. M92053 and M92054)," dated September 27, 1995 36. Letter from Donna M. Skay (NRC) to Irene Johnson (Licensee), "Issuance of Amendments (TAC Nos. M97174 AND M97175)," dated January 29, 1997 37. Letter from Stewart N. Bailey (NRC) to Oliver D. Kingsley (Licensee), "Issuance of Amendments (TAC Nos. MA8388 and MA8390)," dated March 30, 2001 38. SSER #2 (NUREG-0519) "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2, Supplement No. 2," dated February 1982. 39. Letter from Darrell G. Eisenhut (NRC) to Louis L. DelGeorge (Licensee), "Amendment No. 12 to Facility Operating License No. NPF LaSalle County Station, Unit 1," dated December 20, 1982 40. Letter from J. G. Keppler (NRC) to Cordell Reed (Licensee), dated June 19, 1982. 41. Letter from P.C. Shemanski t o H.E. Bliss, "LaSalle County Station Units 1 and 2 Response to Questions from the Safety Evaluation Report and Relief of the Inservice Testing Program for Pumps and Valves NRC Docket No. 50-373 & 50-374," dated August 16, 1988 42. NRC Inspection Report 50-374/87003(DRS), dated March 13, 1987 43. NRC Inspection Report 50-374/87019(DRP), dated August 20, 1987 44. NRC Inspection Report 50-374/84-33(DRP), dated November 26, 1984 45. NRC Inspection Report 50-374/87018(DRP), dated July 8, 1987 46. NRC Inspection Report 50-374/83-56(DPRP), dated January 30, 1984 47. NRC Inspection Report 50-374/84-26(DRP), dated October 1, 1984 48. NRC Inspection Report 50-374/85009(DRP), dated April 17, 1985 49. NRC Inspection Report 50-374/88003(DRP), dated February 5, 1988 50. Letter from Stewart N. Bailey (NRC) to Oliver D. Kingsley (Licensee), "Issuance of Amendments (TAC Nos. MA8388 and MA8390)," dated March 30, 2001 51. NRC Inspection Report 50-374/84-05(DPRP), dated April 18, 1984 Page 1 7 of 18 ATTACHMENT 1 Evaluation of Proposed Changes 52. NRC Inspection Report 50-374/83-52(DPRP), dated January 6, 1984 53. NRC Inspection Report 50-374/84-13(DPRP), dated May 10, 1984 54. Letter from A. Schwencer (NRC) to D. Farrar (Licensee), "Order Confirming Licensee Commitments on Emergency Response Capability," dated February 21, 1984 55. NRC Inspection Report 374/83-52(DPRP), dated January 4, 1984 56. Letter from D. R. Muller (NRC) to L. D. Butterfield, Jr. (Licensee), "Emergency Response Capability, Conformance to Regulatory Guide 1.97, Revision 2, LaSalle County Station, Units 1 and 2 (TAC Nos. 51102 and 56407)," dated August 20, 1987 57. NRC Inspection Report 50-373/86046(DRP), dated February 17, 1987 58. Letter to Mr. Harold R. Denton (NRC) from C.M. Allen (Licensee), subject, "LaSalle County Station Units 1 and 2, Human Factors Review of R.R. 1.97 Instrumentation, NRC Docket Nos. 50-373 and 50-374," dated August 1, 1986 Page 1 8 of 18 ATTACHMENT 2 Markup of Operating License Pages for LaSalle County Station, Unit 1 LaSalle County Station, Unit 1 Facility Operating License No. NPF-11 REVISED OPERATING LICENSE PAGES 3-8 11-17 Attachment 1

Am. 146 (4) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 01/12/01 30, 40, and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components

and Am. 146 (5) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR 01/12/01 Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of LaSalle County Station, Units 1 and 2. C. This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below: (1) Maximum Power Level Am. 188 (2) Technical Specifications and Environmental Protection Plan 03/10/08 3 - 03!10/08 License No. NPF-11 The licensee is authorized to operate the facility at reactor core power levels not in excess of full power (3489 megawatts thermal). The Technical Specifications contained in Appendix A, as revised through Amendment No. 188, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. duct of Work Activities Durin g F uel Load and_ Initial Start all review by committee all Unit 1 JP~ perational s Demonstration activities performed concurrently ng or with the U ' 1 Startup Test Program t aff he safe performance of the e Unit 1 Startup Program being minimum, system d health physics, tly with the Unit 1 fuel erformed. The embers, or The license Testing and Sy with Unit 1 initial fuel Id to assure that the activity wi Unit 1 fuel loading or the portio performed. The review sha interaction, span of co with respect to p loading or ~h committeefor the review shall be composed of at least three knowledgeable in the above areas, and who meet the qualifcatio .rf)rofessional-technical personnel specified by ddress, a bl, staffing, security rmance of the activity concuf ortion of the Unit 1 Startup Program be pPUETED CA -. L V--- I -'F- D (4) R The licensee shall comp drilling and coring the concrete building roof. The re approval 03/03/01 License No. NPF-11 Section 4.4 of ANSI N18.7-1971. At least one of these three shall be a senior member of the Assistant Superintendent of Operation's staff. ton of Rebar Damacge and Adequacy of Off-Gas Buildi all be reported to t 6 -power operation following initial criticality physics testing. e rebar damaged due to ctural adequacy of the off-gas staff for review and ro Prior 'ticality, the licensee shall submit for revised list f-6afety-related snubbers to 3.7.9-1 of the Technical Specifica on lines 3 inches in diam less. approval, a ontained in Table to include such snubbers (b) Prior to start er the first refueling e, the licensee shall provi s necessary, a revision to the Tec " I Specifications emove snubbers that are determined to be unn sary and replace them with rigid strut and rod assemblies. The licensee shall sail rily resol~evt~roe deficiencies which were deferred from the proper ' rogram on a schedule that shall assure that thg,cap~5i ity of a system requir e operable by pecification is not degraded. ed Preoperational Deficiencies Section 3.8.1", SSER #3) Prior to full power, the licensee yy the predicted lift-off forces required to co m e e-~atSTes 4.6.1.5-1 and 4. .." . ..af the Technical ons. nrv Wall (Section 3.8.3, SER, SSER #2) Based on the i ' s of our preliminary review o icensee's submittals and its com ' nts related to sonry wall evaluation, the following actions are required censee: (a) The prese s for modifications imp nted shall not preclude the n of implementing additional modifica i if directed by our future review of the licensee's design criteria.

(10) rr to startup after the first refueling outage, the lic resolve t7i~tti#areeces between our i used by the licensee to impleme such a resolution. ief that the licensee has and valve tests ' ements of 10 CFR ion 55.55 (g)(2) and (g)(4)(i) is granted or rtion of the initial 120-month period during which we complete our review. ~°`---- Pursuant to 10 CFR Part requested from -t Pa P comple result of the document the o into the suppression factors calculated for typi up-to-date, and report to occurs due to any saf ironmental Qualifications No with the Environmeri Equipment," for s harsh environment. Complete and auditabi_

at a central locatio methods use sufficient NU 5 - 03/30/01 License No. NPF-11 of Pumps and Valves (Section 3.9.6 3.10 SER SSER#1 SSER#2) to startup after the first refueling outage, the Ii any modifications or replacement of e tigue evaluation. In the interi rrences of every sa I; the assgei a eria and the criteria of the staff and shall that might result see shall pment as a he licensee shall relief valve actuation ated cumulative damage esentative equipment and kept malfunction of equipment that e. after the first refueling outage, Fnodify the NSSS equipment (interm ~, C51-K-601A/H and two-inch air-operated glo 1-17011) if the results of the requalification tests indicate change is required. e licensee shall range valve, i1her er than March 31, 1985, the licensee shall be i ;ovisions of NUREG-0588, "Interim Qualification of Safety-Rel ty-related electri Section 3.11. SER. SSER#1. SSER# compliance Position of d Electrical equipment exposed to a ust be available and maintained environmental qualification equipment in liance with aintained se or hich describe r all safety-related elect ail to document the degree of co -0588. Such records shall be updated an rent as equipment is replaced, further tested, or otfi further qualified to document complete compliance no later March 31, 1985. (b) (11) Am. 4 (a) 08/13/82 Am. 4 (b) 08/13/82 DE LE TC- D (12) SSE (a) (b) Pri By July 30, description of the a results necessary to sho Appendix A to the St (NUREG-0800 03/30/01 License No. NPF-11 SSER #2 the licensee shall sut)Xti icaI metho6 .- long Plan, Section 4.2 a. u and Re mic and Loss-of-Coolant Accident Loads regard to fuel ass Section 4.2.3.4, SE startup after the first refueling outage, the f el assembly liftoff issue must be satisfactorily resolved satisfaction of the staff. Section 4.2.3.14. SER) w of the e IE Bulletin No. 79-26,"Revasion 1, "Bor s from BWR Control Blades," describes certain actions to ` licensees to determine boron loss from BWR co ides. The licensee comply with items 1, 2 and 3 of ' etin and submit a written response on within 30 after plant startup following the first refueling outage. (14) 'dam Discharge Volume (Section 4.6.2, SER and 6.3.2.3, SSER Pn to startup after the first refueling outage, the incorporate the following additional modificati discharge v me system; (ii) Diverse and re dint s m instrumentation for each instrume volume, include both delta pressure sensors and t sensors. r to startup after the first refueling outage, tfi complete system or procedural modifications, if requ result of the staffs completion of its review of the license response to NUREG-0803. (15) -°CDwgcessure in Pump Discharge of the Control Rod Drive (Secfion~2, SSER #2) Prior to startup after the first instrumentation f in the ng, the-licensee shall install utomatic scram that woul wn the reactor low control rod drive pump discharge pressure Etivated during startup and refueling modes only.

DELETED radiance with Re `Laantainment Long Term Program Load Specifications (21) Prior to October 1, 198 assessment of the cont (chugging, y on By July 1, 1982, the lice modifications necessa omply` 1.97, "Instrum on for Light Water Coole Asses nt Conditions During and Following an Accid6 ember 1980. 7 - 03/30/01 License No. NPF-11 submit its confirmatory

_acy for pool dynamic loads developed in esig r'al and diaphragm reverse pr'e with the Long Term Program and reported in N ulatory Guide 1.97 (Sections "vide a plan for implementing

!_vision 2 of Regulatory Guide r Power Plants to ed itional Instrumentation and Control Concerns (Section 7.7.3 The licensee shall re the following cone to the NRC staffs satisfaction prior to startup a the fir ueling outage: (a) whether common_oedrical power sees or sensor malfunctions ether high energy line breaks will result in unacceptab`

consequential control system failures. The license e sha er the first refueling outage. ~, Prior to startup after the firs implement the f " &libility: pie control systems failure§~apd Sections 8.3.1.1. SER, and_9:6:~': ) outage, the licensee shall esign modificatio wittt_respect to diesel- (16) DG LETED Am.10 (17) 12/09/82 (18) (19)

(22) (23) (24) A heavy duty turbocharger gear drive assembly be installe iesel-generators. (b) A prelu supply, be i engine-driven lub NRC shall be installe engine. hitoring instruments engine skid, except instrume n. The non-qualified control and monito all be installed on a free standing floor mounted located on a vibration free floor area. If the floor is not J free, the panel shall be equipped with vibration mounts. ct Current Power Systems (Section 8.3.1.2. SER) Prior to sta direct current sys direct current system, provided in the control room: charge/discharge), (2) Bg Battery charger ou alarm, and shall i current (ammeter); ettery charger trouble alarm. Iri ement approved procedures to monitor batt rger output voltage, and batter charger output current a panels at least once per eight hour shift. Containment Electrical Penetrations (Section 8.4.1 Prior to startup after the device (circuit breakers or fus circuit that would li which th D E L G Prior to startu ump, powered from a reliable dir Iled in the system to op il pump, or a pre after the first refueling outage for the for Divisions 1 and 2 a Ilowing ad n of Class 1 E and Non-Class 1 E Cable Tra 03/30/01 License No. NPF-11 current power e in parallel with the emative acceptable to the e dry-starting of the diesel- be removed from the qualified for this instruments el and tion and 250-volt e 125-volt Division 3 al instrumentation shall be ery current (ammeter-utput voltage (voltmeter), (3) Battery high discharge rate interim, the licensee urrent, battery local a redundant fault current vided on each penetrating the surge for eling o a ault current surge to be ration is qualified except for low energy (millia ument systems. first refueling outag`e,~' see shall provide separation of barriers between Class 1 E and adja - Class 1 E cable trays.

(29) (28) 'tgitial Test Program (Section 14, SER) The lid forth in Se amended) wit modifications haV Major modifications a (b) Modification of test any test identif Analysis R Prior to exceeding 5 pe conducted an independ of the loo 03130/01 License No. NPF-11 see shall conduct the post-fuel-loading initial test pr on 14 of the licensee's Final Safety Analysis ut making any major modifications of t een identified and have receiv defined as: Elimination of any to 'dentifie ' Section 14 of the licensee's Final Safety Analysis Rejpq~ as amended as being essential; jectives, thods or acceptance criteria for in Section 14 of licensee's Final Safety brt, as amended as being , essential; (c) PeO&mance of any test at a power level diffe escnbed in the program; and Failure to complete any tests included in the described P (planned or scheduled for power levels up to the authorized level). -Assuzance of Proper Design and Construction (Section 17.4 fn (set rt, as program unless prior NRC approval. f full , e licensee shall have ew echanical and structural design heat removal system, e'~ all branch piping an 3 inches, in the functioning mode of the low pres .igjection system using loads resulting from Am. 128 (a) 06/26/98 the op designed and c requirements. This veri inspection, testing, and' any oth conformance with the independentl and co The the N 22.2, "T Licenses," NUREG-051

_actuation of the automatic depressurization system in conjun basis earthquake to verify that this system cted in accordance with al review s °n. This review `s e licensee and its contractors w ction activities for the LaSalle County Station, an pleted to the satisfaction of NRC. 737 Conditions (Section censee shall complete the following conditions to the satisf . These conditions referenced the appropriate items Action Plan Requirements for Applicants for Op the Safety Evaluation Report and Supple (I.C.7, SER) Prior to beginning low-that the General Elect procedures has be recommendatio 03/30101 License No. NPF-11 With een vent NRC onsider design, installation, is necessary to ensure e performed ormed design all be nsee shall have an on-site indep (d) 0' Control Room Design Review (I.D.1. SER, SS er testing, the licensee must assure view of the power-ascension test ed and the General Electric orporated. The licensee shall correct the design deficiencies id Appendix C of Supplement No. 1 to the Safety Evaluat NUREG-0519 on the schedule prescribed therein. ton of Section ating nts 1, 2 and 3,

.:: :;. ent 2, Sam the first re f valv5 n ds,3 ic~rfity, the licensee shale 7~e NRC for noble gas nt pathways. ~ th and Analvsis of Por to criticality, the licensee shall install an~ proved by the NRC for radioiodine and parti analysis system at plant effluent pathways. Instrumentation for Detection of Inad uate Core C Traini_nct-Durina Low-Power Testing (I.G.I, SER. SSER #2) At least 4 weeks prior to performing the Special Test, Simul Loss of Onsite and Offsite Alternating-Current Power Test licensee shall provide a safety analysis for the test and i rocedures to NRC for review and approval. P t Accident Sam Prior sampli atmosph without ex Direct Indi cati SSER #2) in criticality, the licensee shall install and system for obtaining reactor coola e sampling under degraded cor ssive exposure. of S Prior to startup aft& replace the safety/re meets the IEEE Stan f Additiona l Accident-Mo SSER#2) Attachment 1, b Prior to crit approved plant effl Attac 03/30/01 License No. NPF-11 N SER. SSER #1, SSER#2) II.B.3, SSER #2) Relief Val m eling outage, the licensee shall osition indicator to a model that 23-1974 and 344-1975. Instrumentation (II.F.1, SER Monitor Position (ILD.3. SER, ant Effluents olin e st a high radiation and containment accident conditions install and have procedures ffluent monitoring system at have procedures late sampling and By July 31, 1982, the licensee shall submit a report addr analysis performed by the BWR Owners Group regarding additional instrumentation relative to inadequate core coolin that the licensee shall implement the staffs requirements aft& completion of the staffs review of this report. d II.F.2 ssing the and the (j) Proper Functioning of Heat Removal Systems (II.K.1.22, SER, SSER#2 and II.K.3.13 SER SSER#2) The license shall implement the logic to restart automatically core isolation cooling system prior to startup after the first *fueling outage. (k) M ' Break Detec fion Logic to Prev ent Spurious Is Hi h ress ure C oo lant Injectio n and R ea ctor Core Coolin S stem II.K.3.15 SER SSER #2 Prior to s up after the first refueling outage he licensee shall implement a ircuit modification to assure t t transients monitored by essure instruments to sen e flow in these two systems actual/ sense continuous high team flow. Modification of Au t atic Deure ssu ' _a tion System Logic Fea sibility for Increa d Diver i r Som e Event Seque nces II.K.3.18 SER SSER 1 SSE #3) (m) Restart of' I,(I.K.3.2 SER. SSER#2) "' forhe . uch ev. ew and ap rtup after the first lement the approved( utomatic depressurizatio s ~'to startup after the first refueling outage, thi~ ide an auto start for the high pressure core sp Prio pr t By October 1, 198 alternative design relative to the I system, submi to NRC for re Prior to shall im of the 03/30/01 License No. NPF-11 e licensee shall evaluate the difications of the BWR Owners Group automatic depressurization luation, and propose modification roval. fueling outage, the licensee temative logic modification system. re lniection Svstem licensee shall y. S s tem SER Prior to startup after the first refueling outage, the licensee implement the automatic switchover of the reactor core isola cooling system suction from the condensate storage tank to tH suppression pool when the condensate storage tank is low. hall on Upgrade Emergency Support Facilities (III.A.1.2. SER,,SSER#1) The licensee shall complete its Emergency Response Facilities follows: Safety Parameter Display System (ii)\ Emergency Operations Facility (p) Im rovin Licensee's Emergency Preparedness III.A.2 S SSER#1 SSER#2 (1) Prior t exceeding five percent powe, comple a successful emergency facility a LaSalle County. (3) Prior to exceedi demonstrate the s assurance that ade taken in the event CFR 50.4(s)(2) to, actions must be emergency pr finds that th in the Fed rule set f substa adeq spe. F pe aken t paredness ack of progre al Emergency M rth in 44 CFR Part 3 ive problems exist in a to state of preparedness. ified will relate to substantiate eral Emergency Management A The licensee shall provide the interim improvement and shall provide the mech term improvements as follows: alerting/notification system. scent power, the licensee shall offsite preparedness provides to protective measures can and will be radiological emergency. The use of 10 fy a period within which corrective assure an adequate state of ill include instances where NRC s in completion of the procedures nagement Agency's proposed 0 is an indication that major ieving or maintaining an ny corrective period roblems identified by the ncy. Prior to exceeding five percent power, t install a process computer with the capa meteorological information that provides means for data access. 03/30/01 License No. NPF-11 kercise with the LaSalle licensee shall ity to retrieve dundant Prior to exceeding five percent power, the licensee shall propose a plan for meeting the meteorological aN dose assessment capability guidance of Appendix 2, NUREG-0654, Revision 1 as follows:

Prior to January 15, 1983, t pressure boundarvb+Ats Prior to November 1, 1982, submit its evalu va the 03/30/01 License No. NPF-11 Valves installation of hardware and software capabili escribed above by July 1, 1982; and (iii) Prior to exceedi shall includ meth m meteorological measurement preven corrective maintenance program in the ra emergency plan. descriptid ogy with a Class A le, and description of an ac IVr.77.. u C :]OW.-Me reaker Valves shall complete a test and shall e results which con e'aker valves to withstand the opening and closing associated with pool swell. -Ventilation and Air Condition Svstems tional capability descd above by 83. ercent power, the licensee f the dose calculation sport and diffusion table e and ogical all check the torque on all non-- . rability of ability of the Prio xceeding five percent power op on, the licensee must provide for documentation of inf ation regarding HVAC design fabrication installs ' , discussed in meeting with the NRC on August 2 and , 2. 9 50% power opera the licensee shall submit f an independent review acceptable to the NRC staff VAC system, including design changes, i ation, and stallation, The review shall encompass all safety-vela VAC systems and the effect of non-safety related HVAC system fai on safety systems. Am. 3 (31) 07/15/82 Am. 4 (32) 0811318 2 Am. 103 (34) DELETED 04/13/95 Am. 106 (35) `Saaceillance Interval Extension 09/27/95 The performance in~e or those surveill vfequirements identified in the licensee's request for surve interval extension dated April 11, 1995, shall be ex~te , n' tb'Rpril 5, 19966, C~ide with the Unit 1 seventh gM~g outage schedule. The extended in hall not a total of 25.1 months for 18 month surveillances. n L m DELETED The liceri licensee-cont requirements shal - 16a - 03/30/01 License No. NPF-11 (a) This license conditio specification requiremen (UFSAR), as described i 1 31, 1996. The apps evaluation dat effective shall shall relocate certain technical specification req ed documents as described below. The retained by the licensee. elocation of certain technical nsee-controlled documents nsee's application dated October d in the staffs safety cerise condition is ent No. 117 and of issuance. is docume anuary 29, 1997. Th of its date of issuance by Ameri implemented within 90 days from the d lementation shall include the relocation of techni specifications requirements to the appropriate licensee-6 document as identified in the licensee's application dated Oct 31, 1996. Exelon Generation Company, LLC shall provide the Director of the Office of Nuclear Reactor Regulation a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from Exelon Generation Company, LLC to its direct or indirect parent, or to any other affiliated company, facilities for the production, transmission, or distribution of electric energy having a depreciated book valve exceeding ten percent (10%) of Exelon Generation Company, LLC's consolidated net utility plant, as recorded on Exelon Generation Company, LLC's books of account. Exelon Generation Company, LLC shall have decommissioning trust funds, for LaSalle Unit 1, in the following minimum amountwhen LaSall Unit 1, is transferred to Exelon Generation Company, LLC: LaSalle, Unit 1 $226,262,522 FAm. 146 (38) 01/12/01 Am. 146 (39) 01/12/01 , , Am. 146 36) 01/12/01 Am. 147 (37) 03/30/01

- 16al - 08/0 9/07 License No. NPF-11 The decommissioning trust agreement for LaSalle, Unit 1, at the time the transfer of the unit to Exelon Generation Company (EGC), LLC is effected and thereafter, is subject to the following: (a) The decommissioning trust agreement must be in a form acceptable to the NRC. (b) With respect to the decommissioning trust fund, investments in the securities or other obligations of Exelon Corporation or affiliates thereof, or their successors or assigns are prohibited. Except for investments tied to market indexes or other non-nuclear sector mutual funds, investments in any entity owning one or more nuclear power plants are prohibited. (c) The decommissioning trust agreement for LaSalle, Unit 1, must provide that no disbursements or payments from the trust shall be made by the trustee unless the trustee has first given the Director of the Office of Nuclear Reactor Regulation, 30 days prior written notice of payment. The decommissioning trust agreement shall further contain a provision that no disbursements or payments from the trust shall be made if the trustee receives prior written notice of objection from the NRC. (d) The decommissioning trust agreement must provide that the agreement can not be amended in any material respect without 30 days prior written notification to the Director of the Office of Nuclear Reactor Regulation. (e) The appropriate section of the decommissioning trust agreement shall state that the trustee, investment advisor, or anyone else directing the investments made in the trust shall adhere to a "prudent investor" standard, as specified in 18 CFR 35.32(a)(3) of the Federal Energy Regulatory Commission's regulations. Exelon Generation Company, LLC shall take all necessary steps to ensure that the decommissioning trust is maintained in accordance with the application for approval of the transfer of the LaSalle, Unit 1, license and the requirements of the Order approving the transfer, and consistent with the safety evaluation supporting the Order. --shal relocate certain Technical SpecificaegGirements to EGC-controlle e0ts upon jrg~i6tation of Amendment No. 147. The items and appropriate en described in Table LA, "Removal of Details MaUix;~Mn_d Table R, "Relocated Speci " that are attached to the s Safety Evaluation enclosed with Amendment No. 14 . Am. 146 (40) 01/12/01 Am. 146 01/12/01 Am. 146 (41) 01/12/01 Am. 147 (42) 03/30/01 Letter dated 08/09/07 r ,:.7 Am. 147 (43) 03/30/01 e schedule for performing Surveillance Requirements (SRs) that are r revised in Amendment No. 147 shall be as follows: For SRs that exis prior to this amen performance are bein educed, th begins upon completion h implementation of Amendm- For SRs that existed acceptance crite surveillance i performe ,Rs that are new in this amendment, the first pert f the first surveillance interval that begins ion of Amendment No. 147. Letter dated (44) Mitigation Strategy License Condition 08/09/07 - 16a 1 a - 08/09107 License No. NPF-11 or to this am the first performan rval that began on the date rior to the implementation of Amen ent whose intervals of ~st reduced surveillance interval surveillance performed after o.147. dment that have modified s due at the end of the first e surveillance was last ent No. 147. Rs that existed prior to this amendment whose in als of erformance are being extended, the first extended su[vei nce interval begins upon completion of the last surveillance performed pri o implementation of Amendment No. 147. Develop and maintain strategies for addressing large fires and explosions and that include the following key areas: (b) Operations to mitigate fuel damage considering the following: 1. Protection and use of personnel assets 2. Communications

3. Minimizing fire spread 4. Procedures for implementing integrated fire response strategy 5. Identification of readily-available pre-staged

6. Training or integrated fire response strategy 7. Spent fuel pool mitigation measures (c) Actions to minimize release to include consideration of: 1. Water spray scrubbing

2. Dose to onsite responders (a) Fire fighting response strategy with the following elements: 1. Pre-defined coordination fire response strategy and guidance 2. Assessment of mutual aid fire fighting assets 3. Designated staging areas for equipment and materials

4. Command and control 5. Training of response personnel DIE UETE D ~-°--.--~ - 16a2 - 10/31/07 License No. NPF-11 Am. 186 (45) Upon implementation of Amendment No. 186 adopting TSTF-448, 10/31/07 Revision 3, the determination of control room envelope (CRE) unfiltered air inleakage as required by SR 3.7.4.5, in accordance with TS 5.5.15.c.(i), the assessment of CRE habitability as required by Specification 5.5.15.c.(ii), and the measurement of CRE pressure as required by Specification 5.5.15.d, shall be considered met. Following Implementation

(a) The first performance of SR 3.7.4.5, in accordance with Specification 5.5.15.c.(i), shall be within the specified Frequency of 6 years, plus the 18-month allowance of SR 3.0.2, as measured from 1998, the date of the most recent successful tracer gas test, as stated in the December 9, 2003 letter response to Generic Letter 2003-01, or within the next 18 months if the time period since the most recent successful tracer gas test is greater than 6 years. (b) The first performance of the periodic assessment of CRE habitability, Specification 5.5.15.c.(ii), shall be within 3 years, plus the 9-month allowance of SR 3.0.2, as measured from 1998, the date of the most recent successful tracer gas test, as stated in the December 9, 2003 letter response to Generic Letter 2003-01, or within the next 9 months if the time period since the most recent successful tracer gas test is greater than 3 years. (c) The first performance of the periodic measurement of CRE pressure, Specification 5.5.15.d, shall be within 24 months, plus 6 months allowed by SR 3.0.2, as measured from the date of the most recent successful pressure measurement test, or within 6 months if not performed previously. Am. 102 D. The facility requires exemptions from certain requirements of 10 CFR Part 50, 03/16/95 10 CFR Part 70, and 10 CFR Part 73. These include: (a) Exemptions from certain requirements of Appendices G, H and J and 10 CFR Part 73 are described in the Safety Evaluation Report and Supplement No. 1, No. 2, No. 3 to the Safety Evaluation Report. from 10 CFR Part 50, Appendix E from exercise within one eay exemptions uat of n Report. -jfuTs a e operating license, both the Safety DELc-TED - 16b - 03/30/0 1 License No. NPF-11 tion was requested from the requirements of 10 CF ercent rated therma~ fi1 startup test has _ed for 120 effective full power Lion (d) is been completed or the reactor days as specifi the safety evaluation of License Amendment No. Am. 178 F. Deleted 06/14/06 (e) An exemption from the requirement of paragraph III.D of Appendix J to conduct the third Type A test of each ten-year service period when the plant is shutdown for the 10-year plant inservice inspections. Exemption (e) is described in the safety evaluation accompanying amendment No. 102 to this License. Am. 112 (f) An exemption was granted to remove the Main Steam Isolation Valves 04/05/96 (MSIVs) from the acceptance criteria for the combined local leak rate test (Type B and C), as defined in the regulations of 10 CFR Part 50, Appendix J, Option B, Paragraph III.B. Exemption (f) is described in the safety evaluation accompanying Amendment No. 112 to this License. These exemptions are authorized by law and will not endanger life or property or the common defense and security and are otherwise in the public interest. Therefore, these exemptions are hereby granted. The facility will operate, to the extent authorized herein, in conformity with the application, as amended, and the rules and regulations of the Commission (except as hereinafter exempted there from), and the provisions of the Act. E. This license is subject to the following additional condition for the protection of the environment

(d) either the requi Before engaging in additional construction or operational activities which may result in a significant adverse environmental impact that was not evaluated or that is significantly greater than that evaluated in the Final Environmental Statement and its Addendum, the licensee shall provide a written notification to the Director of the Office of Nuclear Reactor Regulation and receive written approval from that office before proceeding with such activities.

G. The licensee shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims. Am. 4 H. This license is effective as of the date of issuance and shall expire April 17, 2022. 08/13/82 Attachment

1. AX-aehmen' 2. Appendix A - Technical Specifications (NUREG-0861)

3. Appendix B - Environmental Protection Plan Date of Issuance: April 17, 1982 03/30101 License No. NPF-11 FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By HAROLD R. DENTON, DIRECTOR OFFICE OF NUCLEAR REACTOR REGULATION This attachni which must be Mode 2 (initial ce Operational Mode completed in accord ATTACHMENT 1 TO LICENSE NPF-11 nt identifies certain preoperational tests, system demonstrations and other mpleted to the Commission's satisfaction prior to proceeding to Operati cality of 212°F as applicable). The license shall not proceed beyond ithout written confirmation from the NRC that the following items ce with the conditions set forth below: ng Preoperational Tests shall be completed, includi 2. The following System Demonstra

3. Commonwealth Edis communications s 4. Commonwealt EOF. (373/814-31) ment Monitoring System (PT-CM-101)

b. Drywell PXeumatic System (PT-IN-101)

c. Traversing In6gre Probe (PT-NR-102) (Prigs to Entering Test Condition

1) f. Pipe Vibration Monitoring

a. High Radiation Samp}(ng System n Company must install a em. (373/81-14-25) 04/17/82 '-101) I-102) shall be completed, including all reviews: SD-PS-102) test the microwave voice channel Edison Company must install radiatiolq measurement equipment in the ealth Edison Company must assure the followinkcommitments per TMI an Requirements III.D.3.3 are met: Availability of 5 PING-3 (2A special) particulate, iodine, monitoring systems mounted on carts. Availability of Eberline Instrument Corporation SAM-2 iodine silver zeolite cartridges. Availability of a low background, low contamination area for analyzi cartridges. (373/81-00-102)

7. Co onwealth Edison Company must conduct a site assembly drill (373/8Q-53-03)

8. Common requiremen surrounding

9. Commonwealth ison Company must develop proc Gas Radioiodine Re ase Rates required by Table Requirement II.F.1. (3'P/81-00-104)

10. Commonwealth Edison C affecting systems for which required to be completed prior' the licensee's procedure)

11. Commonwealth Edison Company verify there are no outstanding d) 12. Commonwealth Edison Co standby gas treatment sys)6m monitors. (373(81-14-20)

13. Commonwealth Ediso HVAC system to m the counting room, 14. Commonwea closure tim modificati

15. Com stre gth steel bolting. (373/81-48-06)

Commonwealth Edison Company must assure that results from Preoperational Test PT-RP-101 for response time of the scram signals for the turbine stop val and turbine control valve fast closure are added to the results obtained in Preoperational Test PT-RR-101 to obtain correct scram time for these 373/80-15-1

2) pany must satisf, eoperational o initial cr, 04/17/82 ealth Edison Company must include in Startup Tes rocedure STP-17 for measuring GAP clearances between the p cess pipe and the e whip restraint structural assemblies. (37X81-29-01) ures for estimating Noble .F.1-2 per TMI Action Plan ctorily resolve those deficiencies ests or System Demonstrations are icality. (Category 4 deficiencies as per t review the Cable Pan Loading Report to crep~kncies. (373/79-34-01)

Company must complet t design criteria requirements nd surrounding areas. (373/81-4 Edison Company must review the stop a cceptance criteria basis to determine if it me s. (373/81-43-06) rate high range station vent and odifications to the laboratory f positive pressure between X 03) nwealth Edison Company must conduct a 100% reinspe ommonwealth Edison Company must develop a written technical bas4 for the practice of installing high strength bolts without torquing requirements. (373/81-48-07)

Commonwealth Edison Company must complete a testing program for vibratio monitoring of the Low Pressure Core Spray IA and Residual Heat Removal System IB pumps. (373/82-10-15 and 373/82-18-01)

ATTACHMENT 3 Markup of Operating License Pages for LaSalle County Station, Unit 2 LaSalle County Station, Unit 2 Facility Operating License No. NPF-18 REVISED OPERATING LICENSE PAGES 3-6 8-11 Attachment 1 Attachment 2

Am. 34 12/08/87 Am. 125 05/09/00 Am. 175 03/10/08 DP-LF.T V=D (1) Maximum Power Level onduct of Work Activities Durin The liceri and Syste initial fuel loading the activity the portion shall address, as a minimum, sys security and health physics, wi concurrently with the Unit Program being perfo be composed of areas, and w person the peration's staff. of the Unit 2 Sta -~ Progra 3 - 03/10/08 License No. NPF-18 Pursuant to the Act and 10 CFR Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of LaSalle County Station, Units 1` and 2. C. The license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below: The licensee is authorized to operate the facility at reactor core power levels not in excess of full power (3489 megawatts thermal). Items in Attachment 1 shall be completed as specified. Attachment 1 is hereby incorporated into this license. (2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 175, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. .::_ s e shall review by committee all Unit 2 Preoper m~L onstration activities performed cone oading r3lwiith the Unit 2 Startup Test will not affec e safe performan sing performed. The review Fuel Load and Initial Startu nal Testing ently with Unit 2 gram to assure that of the Unit 2 fuel loading or nteraction, span of control, staffing, to performance of the activity portion of the Unit 2 Startup eview shall in the above ical esp el loading or d. The committee for th east three members, knowledge meet the qualifications for professional-td "specified by Section 4.4 of ANSI N18.7-1971. At lea hree shall be a senior member of the Assistant Superintends ne of of SSER #2 - " - - " ne pump arn ac~y - ion 55.55a(g)(2) and (g)(4)(i itial 120-month period during which the staff co`m a . ".:r~9itaR.~~a tal Qualification r .ne;i:c. M=!: ance of Control Blade Section 3.11, SER Section 4.2.3.14. SER) on 1, "Boron ce Testin Prior to November electri of Pum IE Bulletin No. 79-2 describes certain actions to be loss from BWR contr and 3 of thi d ressure in Pum Prior to completion oft he startu instrumentation that w event of low scr Prior to startup after the first the eight 26-inch valves 4-031301 01 License No. NPF-18 s and Valves (Section 3.9.6, SER") es. The license` n and submit a written response o er plant startup following the first refueling outage. in the submittals and November 12, 1983 that Ive testing requirements ted for that SER #5 ronmentally qualify all nom BWR Control Blades," licensees to determine boron comply with items 1, 2 3 within 30 ction 7.2.3.2, SSER #7) Se ogram, the licensee shall install the reactor in the automatic omatically sh rod drive pump discharge pressure all be activated during startup and refueling modes only. its ' ment Isolation System Section 6.2.1.1 SSER#2 and 3.9.3.1 S SSER#6) the licensee shall replace 68-inch vent and pure. ' tion valves with n close in 10-seconds or less and that do n-3ti9QWire AC wer to close. Am. 8 (5) 03/28/85 (6) DE LETE .~ Am. 4 (7) 09/21/84 DELEFFF1:~) (8)

DELETED EP E:LeTED --- Liquid Control System Cable Terminations (Section 7.2.3. Prior to initial criticality, the licen at least six inches b standb s. erminations at term' ontrol system circuits in both local and con Prior to startup after the the deficien on between redundant cables. Fng outage, the licensee shall resolve ER #7 regarding Degraded Grid Voltage (Section 8.2.2.2, SER ~_:.._ +.. ........... ater .r.- undervoltage protection on Divisions 1 a`n 03/30101 License No. NPF-18 rovide physical separation of cks for redundant izi up se after the first refueling outage, the licensee shall t~llowing design modifications with respect to m oring instrumen Wskid, ngi Prior to implement th generator reliabili of Di r o The controls and and from the engine and e this location. The non-qualif shall be installed on a fre manner (including t necessary) tha fatigue fail shall d ions tandin se of vibration i y induced vibrations will ri for the expected life of the instrum init an evaluation for NRC staff approval that onstrates this design objective has been achieved. The EMD MI 9644 manufacturer's modification. (13) 1~ife ,current Power Systems (Section 8.3.1.2. SER) Prior to completion of the s instrumentation shall be volt direct curs 3 stems for Divisions 1 and 2 an urrent system: .3.1.1 and 9.6.3.4. SER. SSER sel- on shall be removed ept instruments qualified for ontrol and monitoring instruments oor mounted panel in such a tion mounts if esult in cyclic The licensee t ~' am, the following additional oom for the 125 and 250-ovolt Division (10) DELETED (11) DE~ LIETEP .. (12) DEL E TIE D

~lETE1~1. Am. 112 06/10/98 (14) voltage battery high discFia In the interim, the licensee s monitor battery curr_e charger o attery current (ammeter-chargeldischarge), (2) battery char oter), (3) battery charger output current e alarm, and (5 6- ery charger o' Orrent at the local panels at least on Prior to startup after the firs commitments a gh 5.1.6 of NUREG-0612. (15) Fire Protection Program Section 9.1, SSER #1, SER#5 03/30/01 License No. NPF-18 er), (4) charger trouble alarm. ment approved procedures to oltage, and battery eight-hour the licensee shall have made uidelines of Section The licensee shall implement and maintain all provisions of the approved Fire Protection Program as described in the Final Safety Analysis Report for LaSalle County Station, and as approved in NUREG-0519, "Safety Evaluation Report related to the operation of LaSalle County Station, Units 1 and 2," dated March 1981; Supplement 2 dated February 1982; Supplement 3 dated April 1982; Supplement 5 dated August 1983; Supplement 7 dated December 1983; Supplement 8 dated March 1984; and SERs for the following: LaSalle Unit 2 License Amendment 11, dated May 22, 1985; LaSalle Unit 2 License Amendment 14, dated October 2, 1985; LaSalle Unit 2 License Amendment 112, dated June 10, 1998; and NRC Evaluation of the Consequences of Postulated Failures of 1 Hour Fire Rated Darmatt KM-1 Fire Barrier under Seismic Loading at LaSalle County Station, dated March 29, 1996. The Licensee may make changes to the approved Fire Protection Program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

LPE-LETED1 8- (17) '`JOitial Test Program (Section 14, SER, SSER #7) The I Section without ma are in accorda the licensee shall unless modifications approval. Major modified nsee shall conduct the initial startup test program (set of the licensee's Final Safety Analysis Report, a g modifications of this program unless sue e with provisions of 10 CFR Section t make any major modificatio, ve been identified and ns are defined Elimination of any test Final Safety Analysis Re (b) Modification of test criteria for any t Safety Anal The licens the NRC. Thes 22.2, "TMI Action Pla Licenses," in the Safety E and 7, NUREG-0519. jectives, m 't identified in Secti Report, as amended, a (c) Perfo jibed in the program; and REG-0737 Conditions ance of any test at a power level diffe shall complete the following conditions to nditions reference the appropri equirements for Ap ation Re License Failure to complete any tests included in the described program (planned or scheduled) for power levels up to authorized power level. e licensee shall correct the design deficiencies fo room and complete the other related emergency respons` capabilities as required by Attachment 2 of this license. 03130101 No. NPF-18 h in mended) modifications

.59. In addition, to this program received prior NRC d in Section 14 of the licensee's as mended, as being essential; ods or Level 1 acceptance 14 of the licensee's Final eing essential; satisfaction of items in Section nts for Operating and Supplements 1, 2, 3, 4, 5, Am. 92 09/27195 (19) 9 \(b) Direct Indication of Safety/Relief Valve Position (II.D.3, SER-, SSER#2 and Section 3.10, SSER #7) Prior to completion of the startup test program, the license, qualify the safety/relief valve position indicator. (c) Ins! mentation for Detection of Inadequate Core C SER S ER #1, SSER#5) The licens regarding up additional inst based on the N Reports SLI-8211 evaluation report ad Owners Group reports. completed on a schedule e shall implement the NRC staffs, Fading the liquid level instru entation for detecting i staffs review of the d SLI-8218 and ssing the r ny req cc 03130101 License No. NPF-18 equirements ntation or inclusion of dequate core cooling WR Owners Group e licensee's plant-specific mmendations of the BWR ed modifications shall be table to the NRC staff. (d) Modification of Automatic e ssurization System Logic Feasibility for Increase iversi for Some Event nce II.K.3.18 SER SER 1 SSER#3 SSER #5) modifications to the Automat Depressurization em described in the licensee's le r dated July 1, 83. The final circuit diagrams and an nalysis of the bypass timer time delay shall be submitte for NRC staff review and approval prior to installation. Incorporate into the Plant Abnormal Procedures`the usage of the inhibit switch; and (iii) Modify the Technical Specifications to provide the byp timer and manual inhibit switch. The performance i the licensee's request for su 1995, shall be s er the first refueling 6ytage, the licensee shall: for those surve' equirements identified in e interval extension dated April 11, to April 5, 19 , oincide with the Unit 1 efueling outage schedule. The extende ' al shall not exceed a total of 25.1 months for 18 month surveillances.

Am. 132 (20) 01/12/01 [ DELETED Am. 133 (21) Deleted. 03/30/01 The lice licensee-con requirements sha - 9a - 03/30/01 License No. NPF-18 e shall relocate certain technical specification re fled documents as described below. The retained by the licensee. (a) This license conditi specification requireme (UFSAR), as described 31, 1996. The app evaluation da effective sha LaSalle, Unit 2 $221,885,059 (a) The decommissioning trust agreement must be in a form acceptable to the NRC. elocation of certain technical ensee-controlled documents ensee's application dated October d in the staffs safety icense condition is ent No. 102 and of issuance. al is docume January 29, 1997. T of its date of issuance by Amen e implemented within 90 days from the da plementation shall include the relocation of techni specifications requirements to the appropriate licensee-co document as identified in the licensee's application dated Octo 31, 1996. Am. 132 (22) EGC shall provide the Director of the Office of Nuclear Reactor 01/12/01 Regulation a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from EGC to its direct or indirect parent, or to any other affiliated company, facilities for the production, transmission, or distribution of electric energy having a depreciated book valve exceeding ten percent (10%) of EGC's consolidated net utility plant, as recorded on EGC's books of account. Am. 132 (23) EGC shall have decommissioning trust funds for LaSalle, Unit 2, in the 01/12/01 following minimum amount, when LaSalle, Unit 2, is transferred to EGC: Am. 132 (24) The decommissioning trust agreement for LaSalle, Unit 2, at the time the 01/12/01 transfer of the unit to EGC is effected and thereafter, is subject to the following:

Am. 133 (26) 03/30/01 controlled doc items and appropriate docum Details Matrix," an the LV -I.CTI E D I relocate certain Technical Specification requiremen on implementation of A "Relocated Sp 'ety Evaluation enclosed with Amendment Am. 133 (27) e schedule for performing Surveillance Requirements (SRs) that are 03/30/01 ne r revised in Amendment No. 133 shall be as follows: Fo)k,~Rs that are new in this amendment, the first perf , due at4be end of the first surveillance interval that date of imlementation of Amendment No. 133 For SRs that ex performance are b interval begins upon c after implementation of For SRs that existed pri have modified acce the end of the fir surveillance Amendm - 9c - 03/30/01 License No. NPF-18 ed prior to this amend reduced, the pletion o to this nce criteria, t surveillance interval s last performed prior to No. 133. No. 133. The escribed in Table LA, "Removal of s," that are attached to `o nt whose intervals of reduced surveillance e first surveillance performed ent No. 133. endment that first performance is due at at began on the date the plementation of Rs that existed prior to this amendment whose ' tervals of erformance are being extended, the first extended su Ilance interval begins upon completion of the last surveillance pe ed prior to implementation of Amendment No. 133.

_10- 10/31/07 License No. NPF-18 (c) The first performance of the periodic measurement of CRE pressure, Specification 5.5.15.d, shall be within 24 months, plus the 6 months allowed by SR 3.0.2, as measured from the date of the most recent successful pressure measurement test, or within 6 months if not performed previously. Am. 87 D. The facility requires exemptions from certain requirements of 10 CFR Part 50, 03/16/95 10 CFR Part 70, and 10 CFR Part 73. These include: Exemptions from certain requirements of Appendices G, H and J to 10 CFR Part 50, and to 10 CFR Part 73 are described in the Safety Evaluation Report and Supplement Numbers 1, 2, 3, and 5 to the Safety Evaluation Report. An exemption from the requirement of paragraph III.D of Appendix J to conduct the third Type A test of each ten-year service period when the plant is shutdown for the 10-year plant nservice inspections. (d) exemption from the requirement of para Appendix J to resume o three times in ten years. Exemptions e described in the panying Amendment No. 87 to this license. These exemptions are authorized by law and will not endanger life or property or the common defense and security and are otherwise in the public interest. Therefore, these exemptions are hereby granted. The facility will operate, to the extent authorized herein, in conformity with the application, as amended, and the rules and regulations of the Commission (except as hereinafter exempted therefrom), and the provisions of the Act. E. Before engaging in additional construction or operational activities which may result in a significant adverse environmental impact that was not evaluated or that is significantly greater than that evaluated in the Final Environmental Statement and its Addendum, the licensee shall provide a written notification to the Director of the Office of Nuclear Reactor Regulation and receive written approval from that office before proceeding with such activities. Am. 97 (e) An exemption was granted to remove the Main Steam Isolation Valves 04/05196 (MSIVs) from the acceptance criteria for the combined local leak rate test (Type B and C), as defined in the regulations of 10 CFR Part 50, Appendix J, Option B, Paragraph III.B. Exemption (e) is described in the safety evaluation accompanying Amendment No. 97 to this License.

Am. 164 F. Deleted 06/14/06 Am. 164 G. Deleted 06/14/06 H. The licensee shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims. I. This license is effective as of the date of issuance and shall expire at Midnight on December 16, 2023. Attachment/Appen 1 2. -~4t e nt 2 - 3. Appendix A - Technica Specifications (NUREG-1013)

4. Appendix B - Environmental Protection Plan Date of Issuance: December 16, 1983 03/30/01 License No. NPF-18 FOR THE NUCLEAR REGULATORY COMMISSION Original signed by D.C. Eisenhut for HAROLD R. DENTON, DIRECTOR OFFICE OF NUCLEAR REACTOR REGULATION ATTACHMENT 1 TO LASALLE COUNTY UNIT 2 OPERATING LICENSE NPF-18 ttachment identifies certain preoperational tests, system demonstrations and other ite ust be completed to the Commission's satisfaction in accordance with the operat identified below. wing items must be completed prior to proceeding to operational Iyfode 2 (initial wing Preoperational Tests shall be completed, incl a. Cori b. Post l: c). Main Ste (PT-MS-20

d. Main Steam I (PT-MS-201B)

e. Off-Gas System f. Reactor Recirculatio

g. Post LOCA Hydrogen h. Transverse Incore Probe nment Monitoring System (PT-CM-201 CA Containment Monitoring System Isolation Valve Leakage Con ) Containment Vent ws prior to exceeding

2. leted by Amendment 112 dated June 10, 1998. Deleted by Amendment 112 dated June 10, 1998. T-RR-201) biners (PT-VP-202) stem (PT-NR-202)

Steam System Instrumentation e installed in the Reactor Building. tion System (PT-VP-203) shall be rimary system temperature of the Automatic Depressurization stem and Main Steam s (PT-MS-201 C) shall be complete rior to exceeding a 350 psig in Operational Mode 2. All r iews of this test shall ek of completed testing. for Pipe Vibration Monitoring (SD-SI-201) sh iews prior to exceeding 5% of rated full power B. The Preoperational Test for completed, including all rev, 200°F in Operational Mo C. The Preoperational est for System Safety/R of Valv primary syste ressure of be complete within one w D. The S m Demonstration comp ted, including all re E.

icensee shall complete the following Supplement No. 1 to NUREG-0737 requirements on le noted below; 5. Emergency Res Facilities

3. Regulatory Guide 1.97 Application to Emergency Response Facilities Requirements 1(a) 1(b) 2. Detailed Control Room 2(b) Design Review (DCRDR) t pro i ATTACHMENT 2 Submit Safety Analysis (i) Criteria for parameter selection including V&V description HFR of data display and functions Verify parameter sele, SPDS Operational as design, hardwar, software installat testing and initj training com 4. Upgrade Emergency Operati 4(a) Submit a Procedu Procedures (EOP's) to Generation Package BWROG Rev. 3 NRC 4(b) Implement the Upgraded Technical Support Center (TSC) fully functional Emergency Operations Facility (EOF) fully functional 3/ 12/16/83 07/01/86 07/01/86 efined Prior to completion and of startup test n, functional program operator 'summary report 1/, 2/ 11/01/85 RC, including a sed schedule for entation al report including a 08/01/86 foNnstallation 09/30/84 here are human engineering deficiencies associated with operational differences between nit 1 and 2 (the main turbine control valves opening sequence and position, and high pressure ccd~e spray initiation reset logic) and the licensee has not committed to change these. If such commitment is not made, a detailed analysis of such error shall be made during the DCRDR. 12/16/83 ensee shall perform a DCRDR analysis to determine the potential for o stem alarms found only one unit' 3/ Modifications and co o 00fi e structures have n~irsnsfdgle"d fully functional until the changes resulting from the Reg-wide-L1Z_and human factors reviews are implemented, and all testing and training are completed. eted. The TSC and EOF are ATTACHMENT 4 Markup of TS Pages for LaSalle County Station, Units 1 and 2 LaSalle County Station, Units 1 and 2 Facility Operating License Nos. NPF-11 and NPF-18 REVISED TECHNICAL SPE CIFICATION PAGES 3.7.1-1 through 3.7.1-3 3.7.2-2 through 3.7.2-3 3.8.1-4 3.8.1-6 through 3.8.1-8 5.6-3 3.7 PLANT SYSTEMS 3.7.1 Residual Heat Removal Service Water (RHRSW) System LCO 3.7.1 Two RHRSW subsystems shall be OPERABLE. APPLICABILITY

MODES 1, 2, and 3. ACTIONS REQUIRED ACTION A.1 --------NOTE---------

Enter applicable Conditions and Required Actions of LCO 3.4.9, "Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown," for RHR shutdown cooling subsystem made inoperable by RHRSW System. ---------------------

Restore RHRSW subsystem to OPERABLE status. CONDITION A. \--------NOTE--------

t applicable to,/ Uni 2 during repla ment o the Divisio 1 SCS isolatio alves durin Ref l i ng 11 w"fil e U t 1 is in Mod or defueled. RHRSW System 3.7.1 COMPLETION TIME 7 days (continued)

LaSalle 1 and 2 3.7.1-1 Amendment No. 175/161 ACTIONS RHRSW System 3.7.1 (continued)

LaSalle I and 2 3.7.1-2 Amendment No. 184/171 CONDITION REQUIRED ACTION COMPLETION TIME B, -------NOTE--------

B.1 --------NOTE---------

On pplicable to Enter applicable Unit 2 in g Conditions and replacemen

" f the Required Actions of Division 1 CSC LC0 3.4.9, "Reside isolation valves Heat Removal during Unit 1 Shutdown Co ng Refueling 11 while System- Unit 1 is in Mode 4,5, Shu wn," for RHR or defueled. down cooling ---------------------

subsy m made One RHRSW subsystem inoperab y RHRSW inoperable. System. -------- -------- --- Restore RHRSW days' subsystem to OPERABLE status. s'Required Action and -E:i- Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Conditions A or B not met. - Both RHRSW subsystems

-6t. -------- NOTE ---------

inoperable. Enter applicable Conditions and Required Actions of LCO 3.4.9 for RHR shutdown cooling subsystems made inoperable by RHRSW System. ---------------------

Restore one RHRSW 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months subsystem to OPERABLE status.

ACTIONS CONDITION Required Action and associated Completion Time of Condition-not met. SURVEILLANCE REQUIREMENTS SURVEILLANCE RHRSW System 3.7.1 REQUIRED ACTION / COMPLETION TIME f--1--~ Be i n MODE 3. AND Be in MODE 4. q. 2 SR 3.7.1.1 Verify each RHRSW manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours FREQUENCY 31 days LaSalle 1 and 2 3.7.1-3 Amendment No. 184/171 ACTIONS REQUIRED ACTION A.1 Declare supported component(s) inoperable. --------NOTES-------

Not applicable to, Division 1 durin replacement of ivision 1 CSC olation val ing Unit eling 1 1 is r d CONDITION LaSalle 1 and 2 cable to 2 during nt of the CSCS valves 2 ti on ng Uni ueling l it 2 is in ,5, or defue and during Uni Refueling 12 w Unit 1 is in MO 4,5, or defueled --------------------

One or more DGCW subsystems inoperable. DGCW System 3.7.2 COMPLETION TIME Immediately (continued) 3.7.2-2 Amendment No. 175/161 LaSalle 1 and 2 3.7.2-3 Amendment No. 175/161 ACTIONS CONDITION REQUIRED ACTION DGCW COMPLETION System 3.7.2 TIME -------- NOTES -_______ B.1 Restore DGCW 6 days l. Only applicable to subsystem to OPERABLE Division 1 during status. placement of the D i 'sion 1 CSCS 10 da if isol ion valves Di v ion 1 CSCS during it 1 i Cif perable Refueli ng 1 while Unit 1 is Made 4 ,, 5 or defue ~d . 2. Only applicable to Division 2 during replacement of the Division 2 CSCS isolation valves during Unit 2 Refueling 11 while Unit 2 is in MODE 4,5, or defueled and during Unit 1 Refueling 12 while Unit 1 is in MODE 4,5, or defueled -----------------

One or more DGC subsystems in erable. C. Requir Action and C.1 8e in MODE 3. 12 ho assn ated Completion Ti e of Condition B AND of met. C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ACTIONS CONDITION C\ -------- NOTES --------l. Not applicable t Unit 1 during replacement of the Unit Z Divisi n 2 CSCS isolati n alves dur' g Unit 2 Refueli g 11 wWe Un't 2 is in MOD 4, 5, or defu l d. 2. Not p licable to Uni 2 wring r lacem n t of the nit 1 Di ision 2 'CSCS isola ion valves du ri g Unit 1 Refueling 2 while Unit 1 MODE 4, 5, or defueled. Required Division 3 DG inoperable. One required Division 1, 2, or 3 OG inoperable and the required opposite unit Division 2 DG inoperable. LaSalle 1 and 2 AC Sources-Operating 3.8.1 (continued) 3.8.1-4 Amendment No. 1801167 REQUIRED ACTION COMPLETION TIME C.1 Perform SR 3.8.1.1 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for OPERABLE required offsite circuit(s). AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter AND C.2 Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from feature(s), supported discovery of by the inoperable Condition C DG(s), inoperable j concurrent with when the redundant inoperability required feature(s) of redundant are inoperable. required feature(s)

AND C.3.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(s) are not inoperable due to common cause failure. C.3.2 Perform SR 3.8.1.2 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for OPERABLE DG(s). AND C.4 Restore required 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months DG(s) to OPERABLE status. AND 17 days from discovery of failure to meet LCO 3.8.1.a or b ACTIONS F. ------ NOTES --------l\Not applicable to nit 1 during r placement of t Un't 2 Division CSC isolation valv s during: Refue ing 11 Unit is i 4,5, or 2. Not appl able to Unit 2 u 'ng repla men of the Unit Divi 'on 2 CSC isoIati va es during R fueling 12 wNi l e nit 1 is in MO 4,5, or defueled Division 2 DG and the required opposite unit Division 2 DG inoperable. AC Sources-Operating 3.8.1 (continued)

LaSalle 1 and 2 3.8.1-6 Amendment No. 4&~-~

ACTIONS AC Sources-Operating 3.8.1 (continued)

LaSalle I and 2 3.8.1-7 Amendment No. 184/171 CONDITION REQUIRED ACTION COMPLETION TIME ------NOTES---------

G.1 Restore required 6 days Division 2 DG to 1.0 applicable to OPERABLE status. Unit during , replac° nt of the Unit 2 Di %~ysi on 2 CSCS i sol ati~., 1~ valves during .1 it 2 Refueling 11 whi Unit 2 is in MODE 4,5, or defueled. 2. Only applicable to Unit 2 during replacement of the Unit 1 Division 2 CSCS isolation valves during Unit 1 Refueling 12 while Unit 1 is in MODE 4,5, or defuele . -------------

Division DG and the requi d opposite unit Div' ion 2 DG ' operable. ,-.W' Required Action and --Pt--I:- Be i n MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, B, C, D, E, or F not met. I. Require and I.1 Be in MODE 3. hours associated Completio Time of Condition G AND not met. ~' I I . 2 B e i n M O D E 4 . ~ rs ACTIONS REQUIRED ACTION Enter LCO 3.0.3. CONDITION Three or more required AC sources inoperable. SURVEILLANCE REQUIREMENTS

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

1. SR 3.8.1.1 through SR 3.8.1.20 are applicable only to the given unit's AC electrical power sources. 2. SR 3.8.1.21 is applicable to the required opposite unit's DG. ------------------------------------------------------------------------------

SR 3.8.1.1 Verify correct breaker alignment and indicated power availability for each required offsite circuit. SR 3.8.1.2 -------------------

NOTES -------___--------

l. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading. 2. SURVEILLANCE A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met. 3. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units. -------------------------------------------

Verify each required DG starts from standby conditions and achieves steady state voltage >_ 4010 V and <_ 4310 V and frequency

>_ 58.8 Hz and 5 61.2 Hz. AC Sources-Operating 3.8.1 COMPLETION TIME Immediately 7 days FREQUENCY 31 days (continued)

LaSalle 1 and 2 3.8.1-8 Amendment No. 184/171 5.6 Reporting Requirements 5.6.5 CARE OPERATING LIMITS REPORT L0L01 (continued)

ANF Reporting Requirements 5.6 4. The Rod Block Monitor Upscale Instrumentation Setpoint for the Rod Block Monitor-Upscale Function Allowable Value for Specification 3.3.2.1. 5. The OPRM setpoints for the trip function for SR 3.3.1.3.3. b. The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents: 1. )E N -524(P)(A), "ANF Critical Power Methodology for Boiling Water Reactors." ANF-913(P)(A), "COTRANSA 2: A Computer Program for Boiling Water Reactor Transient Analysis." 3. ANF-CC-33(P)(A), "HUXY: A Generalized Multirod Heatup Code with 10 CFR 50, Appendix K Heatup Option." 4. XN-NF-80-19(P)(A), "Advanced Nuclear Fuel Methodology for Boiling Water Reactors." 5. XN-NF-85-67(P)(A), "Generic Mechanical Design for Exxon Nuclear Jet Pump BWR Reload Fuel." 6. EMF-CC-074(P)(A), Volume 4 - "BWR Stability Analysis: Assessment of STAIF with input from MICROBURN-B2

." 7. XN-NF-81-58(P)(A), "RODEX2 Fuel Rod Thermal-Mechanical Response Evaluation Model." 8. XN-NF-84-105(P)(A), "XCOBRA-T: A Computer Code for BWR Transient Thermal-Hydraulic Core Analysis." (continued)

LaSalle 1 and 2 5.6-3 Amendment No. 181/168 ATTACHMENT 5 Markup of TS Bases Pages for LaSalle County Station, Units 1 and 2 LaSalle County Station, Units 1 and 2 Facility Operating License Nos. NPF-11 and NPF-18 REVISED TECHNICAL SPECIFICATION BASES PAGES B 3.7.1-4 through B 3.7.1-6 B 3.7.2-3 through B 3.7.2-5 B 3.8.1-13 B 3.8.1-19 B 3.8.1-21 B 3.8.1-22 BASES (continued)

ACTIONS A-1 LaSalle 1 and 2 Con Condition i the Division 1 CSCS 1 Refueling 11 while Unit 1 is When the Division 1 CSCS isola to Required Actions. A is modified by a Note indicating that this plicable to Unit 2 during r ion valves Required Action A.1 is intended to handle the inoperability of one RHRSW subsystem. The Completion Time of 7 days is allowed to restore the RHRSW subsystem to OPERABLE status. With the unit in this condition, the remaining OPERABLE RHRSW subsystem is adequate to perform the RHRSW heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE RHRSW subsystem could result in loss of RHRSW function. The Completion Time is based on the redundant RHRSW capabilities afforded by the OPERABLE subsystem and the low probability of an event occurring requiring RHRSW during this period. The Required Action is modified by a Note indicating that the applicable Conditions of LCO 3.4.9, be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components. Condition B-1 Condition is only appli the Division 1 CSCS i Outage 11 e Re of one RH allowed to restore With the unit in this RHRSW subsystem i removal f - red subsystem i lve maintenance, Condition ed by a Note indicatin oU va e outage unit is in MODE Action B.1 is intended to handle the bsystem. The Completio RHRSW su B 3.7.1-4 RHRSW System B 3.7.1 event of g` Unit 1 4, 5, or defueled. erable during the ides the "equate to p n. However, the overall cause a single failure in the OPERAS subsystem could result in loss of RHRSW function. rabi1ity e of 10 days is em to OPERABLE status. the remaining OPERABLE m the RHRSW heat ability is RSW The (continued)

Revision 21 BASES Completi that conclude specified configure modifi a Note indicating that itions of L CO 3. be entered and ons taken if the inoperable RSW subsystem in inoperable RHR shutdown cooling. 's is an ception to LCO 3.0.6 and ensures the proper acts are taken for these components. The Required Action_ the applicable Required res ime is based upon a risk-info at the associated r_ n is acc RHRSW System B 3.7.1 assessment with the unit in the able (Ref. 5). If one RHRSW subsystem is inoperable and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. With both RHRSW subsystems inoperable (e.g., both subsystems with inoperable pump(s) or flow paths, or one subsystem with an inoperable pump and one subsystem with an inoperable flow path), the RHRSW System is not capable of performing its intended function. At least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time for restoring one RHRSW subsystem to OPERABLE status, is based on the Completion Times provided for the RHR suppression pool cooling and spray functions. (continued)

LaSalle 1 and 2 B 3.7.1-5 Revision 32 BASES (continued)

D.1 orrd v. 1- FC I SURVEILLANCE SR 3.7.1.1 REQUIREMENTS RHRSW System B 3.7.1 The Required Action is modified by a Note indicating that the applicable Conditions of LCO 3.4.9, be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components. If any Required Action and associated Completion Time of Condition-4-is not met, the unit must be placed in a MODE in w ich the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. Verifying the correct alignment for each manual, power operated, and automatic valve in each RHRSW subsystem flow path provides assurance that the proper flow paths will exist for RHRSW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be realigned to its accident position. This is acceptable because the RHRSW System is a manually initiated system. This SR does not require any testing or valve manipulation

rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions. (continued)

LaSalle 1 and 2 B 3.7.1-6 Revision 32 BASES LCO subsystem is based on having an OPERABLE pump and an (continued) OPERABLE flow path capable of taking suction from the CSCS water tunnel and transferring cooling water to the associated diesel generator, LPCS pump motor cooling coils and ECCS cubicle area cooling coils, as required. An adequate suction source is not addressed in this LCO since the minimum net positive suction head of the DGCW pump and the maximum suction source temperature are covered by the requirements specified in LCO 3.7.3, "Ultimate Heat Sink (UHS)." APPLICABILITY In MODES 1, 2, and 3, the DGCW subsystems are required to support the OPERABILITY of equipment serviced by the DGCW subsystems and required to be OPERABLE in these MODES. In MODES 4 and 5, the OPERABILITY requirements of the DGCW subsystems are determined by the systems they support. Therefore, the requirements are not the same for all facets of operation in MODES 4 and 5. Thus, the LCOs of the systems supported by the DGCW subsystems will govern DGCW System OPERABILITY requirements in MODES 4 and 5. ACTIONS The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DGCW subsystem. This is acceptable, since the Required Actions for the Condition provide appropriate compensatory actions for each inoperable DGCW subsystem. Complying with the Required Actions for one inoperable DGCW subsystem may allow for continued operation, and subsequent inoperable DGCW subsystem(s) are governed by separate Condition entry application of associated Required Actions. n A is modified by two Notes i applicable dur, 0 Condition isolation valves du outage unit is specified is ting that this `replacement of CSCS "specified unit outages while the fueled. When the during the CSCS 4, 5-, subsystem(s) are inope on valve maintenance, Condition B provi appropriate Required Actions. DGCW System B 3.7.2 and (continued)

LaSalle 1 and 2 B 3.7.2-3 Revision 21 BASES LCO subsystem is based on having an OPERABLE pump and an (continued) OPERABLE flow path capable of taking suction from the CSCS water tunnel and transferring cooling water to the associated diesel generator, LPCS pump motor cooling coils, and ECCS cubicle area cooling coils, as required. An adequate suction source is not addressed in this LCO since the minimum net positive suction head of the DGCW pump and the maximum suction source temperature are covered by the requirements specified in LCO 3.7.3, "Ultimate Heat Sink (UHS)." APPLICABILITY In MODES 1, 2, and 3, the DGCW subsystems are required to support the OPERABILITY of equipment serviced by the DGCW subsystems and required to be OPERABLE in these MODES. In MODES 4 and 5, the- OPERABILITY requirements of the DGCW subsystems are determined by the systems they support. Therefore, the requirements are not the same for all facets of operation in MODES 4 and 5. Thus, the LCOs of the systems supported by the DGCW subsystems will govern DGCW System OPERABILITY requirements in MODES 4 and 5. ACTIONS The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DGCW subsystem. This is acceptable, since the Required Actions for the Condition provide appropriate compensatory actions for each inoperable DGCW subsystem. Complying with the Required Actions for one inoperable DGCW subsystem may allow for continued operation, and subsequent inoperable DGCW subsystem(s) are governed by separate Condition entry and application of associated Required Actions. Condition Condition is no isolation valves during outage unit is in MODE specified DGCW iso1at "r modified by two Notes indicatin Lcable during repl ystem(s) are inopera lve maintenance, Condition B provi opriate Required Actions. DGCW System B 3.7.2 his t of CSCS outages while the When the ring the CSCS (continued)

LaSalle 1 and 2 B 3.7.2-3 Revision 21 BASES ACTIONS BASES LaSalle 1 and 2 A,1 (continued)

If one or more DGCW subsystems are inoperable, the associated DG(s) and ECCS components supported by the affected DGCW loop, including LPCS pump motor cooling coils or ECCS cubicle area cooling coils, as applicable, cannot perform their intended function and must be immediately declared inoperable. In accordance with LCO 3.0.6, this also requires entering into the Applicable Conditions and Required Actions for LCO 3.4.9, "RHR Shutdown Cooling System -Hot Shutdown," LCO 3.5.1, "ECCS-Operating," LCO 3.5.3, "RCIC System," LCO 3.6.2.3, "RHR Suppression Pool Cooling," LCO 3.6.2.4, "RHR Suppression Pool Spray," and LCO 3.8.1, "AC Sources- Operating," as appropriate. tion B is modified by two Notes indicating that on is only applicable during replacement of valves during the specified unit outa is in MODE 4, 5, or defueled. If one or m or DGCW subsystems are inope associated s d ECCS components su affected DGCW loop, including LPCS pu or ECCS cubicle area ooling coils, perform their intende unction OPERABLE status within 6 2 CSCS isolation valves of the Division 1 CSCS reliability is reduced failure in one of the concurrent with a d system not being function. Thes informed asse with the un (Ref. 4) ~rf" the Required Action Condition B is not met which the LCO does not unit must be placed in B 3.7.2-4 this emaining ign basis LOC le to perform its Completion Times are b ment that concluded that t in the specified configuratio DGCW System B 3.7.2 le, the orted by the motor cooling coils as applicable, cannot d must be restored to ring replacement of Division in 10 days during replacement on valves. Overall ESF system ondition because a single ERABLE subsystems ay result in the DGCW tended safety ed upon a risk-associated risk is acceptable and associated Completion the unit must be placed in a MOM in apply. To achieve this status, the at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and (continued)

Revision 21 ACTIONS SURVEILLANCE SR 3.7.2.1 REQUIREMENTS SR_ 3.7.2.2 r opera Fit conditions from full po orderly manner and without challenging unit sy DGCW System B 3.7.2 lowed Completion Times are erience, to reach the ditions in an s Verifying the correct alignment for manual, power operated, and automatic valves in each DGCW subsystem flow path provides assurance that the proper flow paths will exist for DGCW subsystem operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet be considered in the correct position provided it can be automatically realigned to its accident position, within the required time. This SR does not require any testing or valve manipulation

rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions. This SR ensures that each DGCW subsystem pump will automatically start to provide required cooling to the associated DG, LPCS pump motor cooling coils, and ECCS cubicle area cooling coils, as applicable, when the associated DG starts and the respective bus is energized. For the Division 1 DGCW subsystem, this SR also ensures the DGCW pump automatically starts on receipt of a start signal for the unit LPCS pump. These starts may be performed using actual or simulated initiation signals. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based at the refueling cycle. Therefore, this Frequency is concluded to be acceptable from a reliability standpoint. (continued)

LaSalle 1 and 2 B 3.7.2-5 Revision 21 BASES ACTIONS B.4 (continued)

The "AND" connector between the 14 day and 17 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met. Similar to Required Action B.2, the Completion Time of Required Action B.4 allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of the time Condition B was entered. Condition C on C is modified by two Notes indicatin Condition i applicable during re CSCS isolation valve while the outage un the Divisio val ctions. n s are inoperable during ntenance, Condition G provides appropri AC Sources-Operating B 3.8.1 this ent of Division 2 cified unit outages or defueled. When CS isolation fired To ensure a highly reliable power source remains, it is necessary to verify the availability of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered. Required Action C.2 is intended to provide assurance that a loss of offsite power, during the period that the DG(s) is inoperable as described in Condition C, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related divisions (i.e., single division systems are not included, although, for this Required Action, Division 3 (HPCS System) is considered redundant to Division 1 and 2 ECCS). (continued)

LaSalle 1 and 2 B 3.8.1-13 Revision 28 BASES ACTIONS E.1 and E.2 (continued)

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition E for a period that should not exceed 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In Condition E, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition D (loss of both required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period. Condition F on F is modified by two Notes indic applicable Burin Condition i CSCS isolation valve while the outage un the Divisio val ctions. that this acement of Division 2 specified unit outages 5, or defueled. When CSCS isolation equired i s are inoperable duri ntenance, Condition G provides appropr AC Sources-Operating B 3.8.1 With two required unit DGs inoperable or both required Division 2 DGs inoperable, there is no more than two remaining standby AC sources. Thus, with an assumed loss of offsite electrical power, sufficient standby AC sources may not be available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation (continued)

LaSalle 1 and 2 B 3.8.1-19 Revision 28 BASES ACTIONS (continued)

With both requi more than two re with an assumed to standby AC sources required Division 2 ES electrical power system the Division 2 ESF equipm the risk associated wit Division 2 CSCS valve mitigated by the the availability online Unit. T pressure rati least one r OPERABLE This C ass n con eplacem of mechanic the Division line stops are de 9 and seismic design as quired Division 2 OG must b tatus within 6 days of entry in pletion Time is based upon a risk-i ment that concluded that the associate in the specified configuration is acceptab at least one Division 2 DG is not maintained while in this Condition, the assumptions of the assessment of Reference 13 are no longer valid and Condition H should be entered immediately. dition G is modified by two Notes indicating that tion is only applicable during replacement of isolation valves during the specified unit outage unit is in MODE 4, 5, or defue Division 2 DGs inop ining OPERABLE sta of offsite el not be av functi t able, there is no by AC sources. Thus, trical power, sufficient lable to power the minimum s. Since the offsite e only source of AC power for at this level of degradation, nued operation during the t maintenance must be 1 line stops to maintain 'CSCS system for the gned to the same he CSCS piping. At restored to Condition G. rmed isk with the e (Ref. 13). ailable s AC Sources-Operating B 3.8.1 If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the unit must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 14) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to (continued)

LaSalle 1 and 2 B 3.8.1-21 Revision 32 BASES ACTIONS (continued)

AC Sources-Operating B 3.8.1 reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems, of degradation in which lectrical power supplies has been _evel, any further losses se a loss of ied for verely degra electrical power system wi function. Therefore, no additional time is j continued operation. The unit is required by LCO 3 commence a controlled shutdown. SURVEILLANCE The AC sources are designed to permit inspection and REQUIREMENTS testing of all important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, GOC 18 (Ref. 8). Periodic component tests are supplemented by extensive functional tests during refueling outages under simulated accident conditions. The SRs for demonstrating the OPERABILITY of the DGs are consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) and Regulatory Guide 1.137 (Ref. 9). The Surveillances are modified by two Notes to clearly identify how the Surveillances apply to the given unit and opposite unit's Division 2 DGs. Note 1 states that SR 3.8.1.1 through SR 3.8.1.20 are applicable only to the given unit AC electrical power sources and Note 2 states that SR 3.8.1.21 is applicable to the opposite unit's Division 2 DG. These Notes are necessary since the opposite unit AC electrical power source is not required to meet all of the requirements of the given unit AC electrical power sources (e.g., the opposite unit DG is not required to start on the opposite unit's ECCS initiation signal to support OPERABILITY of the given unit). Where the SRs discussed herein specify voltage and frequency tolerances, the following summary is applicable. The minimum steady state output voltage of 4010 V is greater than 90% of the nominal 4160 V output voltage. This value, which is conservative with respect to the value specified in ANSI C84.1 (Ref. 10), allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90%, or 3600 V. It also allows for voltage (continued)

LaSalle 1 and 2 B 3.8.1-22 Revision 32

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RS-08-022, Request for a License Amendment to Delete Obsolete Licensee Conditions and Revise Technical Specifications

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RS-08-022, Request for a License Amendment to Delete Obsolete Licensee Conditions and Revise Technical Specifications

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