ML103050177

Technical Specification and Tech Spec Bases Manual

ML103050177
Person / Time
Site:	Mcguire, McGuire
Issue date:	10/19/2010
From:	Beaver B Duke Energy Carolinas
To:	Office of Nuclear Reactor Regulation
References
DUK102890003
Download: ML103050177 (110)

Text

DISPOSITIO N OF THE ORIGINAL DOCUMENT WILL BE TO PRIORITY Normal THE TRANS MITTAL SIGNATURE UNLESS RECIPIENT IS Date: 10/19/10

- OTHERWIS E IDENTIFIED BELOW Document Transmittal #: DUK102890003

1) 01820 J R ELKINS- ECO81

2) 02388 BOB SHOMAKER LYNCHBG, VA

3) 02532 RESIDENT NRC INSPECTOR MG01VP.

Duke Energy QA CONDITION E] Yes

• No DOCUMENT TRANSMITTAL FORM OTHER ACKNOWLEDGEMENT REQUIRED N Yes

4) 02546 WC LIBRARY - MG01WC IF QA OR OTHER ACKNOWLEDGEMENT REQUIRED, PLEASE

5) 03044 MCG DOC CNTRL MISC MAN MG05DM ACKNOWLEDGE RECEIPT BY RETURNING THIS FORM TO:

REFERENCE

6) 03614 MCG OPS PROCEDURE GP MG01OP

7) 03743 MCG CA TEC SUP MNT QC MG01MM MCGUIRE NUCLEAR STATION Duke Energy

8) 03744 OPS TRNG MGR. MG03OT McGuire

9) 03759 US NUC REG WASHINGTON, DC DCRM MGO2DM RECORD RETENTION # 581188

10) 03796 SCIENTECH DUNEDIN, FL 13225 Hagers Ferry Road

11) 04698 D EBORTZ ECO8G Huntersville, N.C. 28078

12) 04809 MCG PLANT ENG. LIBR. MG05SE TECHNICAL SPECIFICATIONS (TS)

13) 04834 LINDA KDAVILA MG01RP TECHNICAL SPECIFICATIONS

14) 05162 MCG SHIFT WORK MGRS MG01OP

15) 05262 J LFREEZE MG01IE BASES (TSB)---------- -----

Rec'd By Page 2 of 3 Date DOCUMENT NO CA COND REV #/ DATE DISTR CODE 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 TOTAL MEMO NA - 09/20/10 MADM-04B vl vl V1 V3 '11 vi vi Vl 43 TS LIST OF EFFECTIVE PAGES NA 088 09/20/10 TS 3.3.1-12 257/237 NA --- 09/01/10 TS 3.3.1 3.3.1-17 257/237 NA --- 09/01/10 TSB LIST OF EFFECTIVE SECTIONS NA 102 09/20/10 TSB 3.3.1 NA 99 03/09/09 TSB 3.3.1 ENTIRE DOC NA 108 09/01/10 TSB 3.9.3 ENTIRE DOC NA 108 09/01/10 UNIT #1 FOL NA --- 09/20/10 UNIT #2 FOL NA --- 09/20/10 REMARKS: PLEASE UPDATE ACCORDINLY R T REPKO

• BY:

VICE PRESIDENT MCGUIRE NUCLEAR STATION BC BEAVER MGO1RC BCB/TLC

.ýg-K

September 20, 2010 MEMORANDUM To: All McGuire Nuclear Station Technical Specification (TS) and Tech Spec Bases (TSB) Manual Holders

Subject:

McGuire TS and TSB Updates REMOVE INSERT TS Manual TS LOEP (Revision 87) TS LOEP (Revision 88)

TS 3.3.1-12 TS 3.3.1-12 (257/237)

TS 3.3.1-14 thru 3.3.1-17 TS 3.3.1-14 thru 3.3.1-17 (257/237)

TS Bases Manual TSB LOEP (Revision 101) TSB LOEP (Revision 102)

TSB 3.3.1 (Revision 99) TSB 3.3.1 (Revision 108)

TSB 3.9.3 (Revision 91) TSB 3.9.3 (Revision 108)

Attention: Facility Operating License (FOL) Included Included in this distribution is an updated copy of the Unit 1 and Unit 2 FOL. Please place the updated copies in the front of your Technical Specification book. Please recycle your old copies. The FOL was updated to reflect Amendment 258/238 Revision numbers may skip numbers due to Regulatory Compliance Filing System.

Please call me if you have questions.

Bonnie Beaver Regulatory Compliance 875-4180

McGuire Nuclear Station Technical Specifications LOEP Page Number Amendment Revision Date 184/166 9/30/98 ii 237/219 3/1/07 iii 184/166 9/30/98 iv 184/166 9/30/98 1.1-1 184/166 9/30/98 1.1-2 184/166 9/30/98 1.1-3 237/219 3/1/07 1.1-4 194/175 9/18/00 1.1-5 255/235 5/28/10 1.1-6 206/187 8/23/02 1.1-7 194/175 9/18/00 1.2-1 184/166 9/30/98 1.2-2 184/166 9/30/98 1.2-3 184/166 ..,9/30/98 1.3-1 184/166 9/30/98 1.3-2 184/166 9/30/98 1.3-3 184/166 9/30/98 1.3-4 184/166 9/30/98 1.3-5 184/166 9/30/98 1.3-6 184/166 9/30/98 1.3-7 184/166 9/30/98 1.3-8 184/166 9/30/98 1.3-9 184/166 9/30/98 1.3-10 184/166 9/30/98 1.3-11 184/166 9/30/98 1.3-12 184/166 9/30/98 1.3-13 184/166 9/30/98 1.4-1 184/166 9/30/98 1.4-2 184/166 9/30/98 1.4-3 184/166 9/30/98 1.4-4 184/166 9/30/98 2.0-1 219/201 1/14/04 McGuire Units 1 and 2 Page 1 Revision 88

Page Number Amendment Revision Date 238/220 3/29/07 3.0-1 221/203 4/29/04 3.0-2 238/220 3/29/07 3.0-3 205/186 8/12/02 3.0-4 221/203 4/29/04 3.0-5 184/166 9/30/98 3.1.1-1 184/166 9/30/98 311.2-1 184/166 9/30/98 3.1.2-2 184/166 9/30/98 3.1.3-1 184/166 9/30/98 3.1.3-2 184/166 9/30/98 3.1.3-3 184/166 9/30/98 3.1.4-1 184/166 9/30/98 3.1.4-2 184/166 9/30/98 3.1.4-3 186/167 9/8/99 3.1.4-4 184/166 9/30/98 3.1.5-1 184/166 9/30/98 3.1.5-2 184/166 9/30/98 3.1.6-1.

184/1 66 9/30/98 3.1.6-2 184/166 9/30/98 3.1.6-3 184/166 9/30/98 3.1.7-1 184/166 9/30/98 3.1.7-2 184/166 9/30/98 3.1.8-1 184/166 .9/30/98 3.1.8-2 184/166 9/30/98 3.2.1-1 184/166 9/30/98 3.2.1-2 184/166 9/30/98 3.2.1-3 188/169 9/22/99 3.2.1-4 188/169 9/22/99 3.2.1-5 184/166 9/30/98 3.2.2-1 184/166 9/30/98 3.2.2-2 184/166 9/30/98 3.2.2-3

,188/169 9/22/99 3.2.2-4 184/166 9/30/98 3.2.3-1 McGuire Units 1 and 2 Page 2 Revision 88

Page Number Amendment Revision Date 3.2.4-1 184/166 9/30/98 184/166 9/30/98 3.2.4-2 184/166 9/30198 3.2.4-3 184/166 9/30/98 3.2.4-4 184/166 9/30/98 3.3.1-1 248/228 3/9/09 3.3.1-2 248/228 3/9/09 3.3.1-3 216/197 7/29/03 3.3.1-4 250/230 3/9/09 3.3.1-5 248/228 3/9/09 3.3.1-6 248/228 3/9/09 3.3.1-7 184/166 9/30/98 3.3.1-8 184/166 9/30/98 3.3.1-9 248/228 3/9/09 3.3.1-10 248/228 3/9/09 3.3.1-11 257/237 8/2/10 3.3.1-12 184/166 9/30/98 3.3.1-13 257/237 8/2/10 3.3.1-14 257/237 8/2/10 3.3.1-15 257/237 8/2/10 3.3.1-16 257/237 8/2/10 3.3.1-17 219/201 1/14/04 3.3.1-18 219/201 1/14/04 3.3.1-19 184/166 9/30/98 3.3.1-20 184/166 9/30/98 3.3.2-1 250/230 3/9/09 3.3.2-2 248/228 3/9/09 3.3.2-3 248/228 3/9/09 3.3.2-4 248/228 3/9/09 3.3.2-5 198/179 4/12/01 3.3.2-6 198/179 4/12/01 3.3.2-7 250/230 3/9/09 3.3.2-8 184/166 9/30/98 3.3.2-9 McGuire Units I and 2 Page 3 Revision 88

Page Number Amendment Revision Date 3.3.2-10 220/202 3/18/04 3.3.2-11 220/202 3/18/04 3.3.2-12 224/206 1/27/05 3.3.2-13 220/202 3/18/04 3.3.2-14 220/202_ 3/18/04 3.3.3-1 221/203 4/29/04 3.3.3-2 227/209 4/4/05 3.3.3-3 227/209 4/4/05 3.3.3-4 227/209 4/4/05 3.3.4-1 221/203 4/29/04 3.3.4-2 184/1'66 9/30/98 3.3.4-3 184/166 9/30/98 3.3.5-1 184/166 9/30/98 3.3.5-2 194/175 9/18/00 3.3.6-1 Not Used - 243/224 7/26/07 3.4.1-1 219/201 1/14/04 3.4.1-2 219/201 1/14/04 3.4.1-3 184/166 9/30/98 3.4.1-4 219/201 1/14/04 3.4.2-1 184/166 9/30/98 3.4.3-1 214/195 7/3/03 3.4.3-2 184/166 9/30/98 3.4.3-3 214/195 7/3/03 3.4.3-4 214/195 7/3/03 3.4.3-5 214/195 7/3/03 3.4.3-6 214/195 7/3/03 3.4.3-7 214/195 7/3/03 3.4.3-8 214/195 7/3/03 3.4.4-1 184/166 9/30/98 3.4.5-1 216/197 7/29/03 3.4.5-2 216/197 7/29/03 3.4.5-3 184/166 9/30/98 3.4.6-1 216/197 7/29/03 3.4.6-2 216/197 7/29/03 McGuire Units I and 2 Page 4 Revision 88

Page Number Amendment Revision Date 3.4.7-1 216/197 7/29/03 3.4.7-2 216/197 7/29/03 3.4.7-3 216/197 7/29/03 3.4.8&1 216/197 7/29/03 3.4.8-2 216/197 7/29/03 3.4.9-1 184/166 9/30/98 3.4.9-2 184/166 9/30/98 3.4.10-1 184/166 9/30/98 3.4.10-2 184/166 *9/30/98 3.4-11-'1 221/203 4/29/04 3.4.11-2 184/166 9/30/98 3.4-11-3 184/166 9/30/98 3.4.11-4 184/166 9/30/98 3.4.12-1 184/166 9/30/98 3.4.12-2 221/203 4/29/04 3.4.12-3 214/195 7/3/03 3.4.12-4 214/195 7/3/03 3.4.12-5 184/166 9/30/98 3.4.12-6 184/166 9/30/98 3.4.13-1 237/219 3/1/07 3.4.13-2 237/219 3/1/07 3.4.14-1 184/166 9/30/98 3.4.14-2 184/166 9/30/98 3.4.14-3 184/166 9/30/98 3.4.14-4 184/166 9/30/98 3.4.15-1 235/217 9/30/06 3.4.15-2 235/217 9/30/06 3.4.15-3 235/217 9/30/06 3.4.15-4 235/217 9/30/06 3.4.16-1 221/203 4/29/04 3.4.16-2 184/166 9/30/98 3.4.,16-3 184/166 9/30/98 3.4.16-4 184/166 9/30/98 McGuire Units I and 2 Page 5 Revision 88

Page Number Amendment AendentRevision PageNumer Date 3.4.17-1 184/1 66 9/30/98 3.4.18-1 237/219 3/1/07 3.4.18-2 237/219 3/1/07 218/200 12/23/03 3.5.1-1 3.5.1-2 184/166 9/30/98 3.5.2-1 184/1 66 9/30/98 3.5.2-2 184/1 66 9/30/98 3.5.2-3 240/222 5/4/07 3.5.3-1 22 1/203 4/29/04 3.5.3-2 184/1 66 9/30/98 184/1 66 9/30/98 3.5.4-1 184/1 66 9/30/98 3.5.4-2 3.5.5-1 184/1 66 9/30/98 3.5.5-2 184/1 66 9/30/98 207/188 9/4/02 3.6.1-1 207/188 9/4/0 2 3.6.1-2 184/166 9/30/98 3.6.2-1 184/1 66 9/30/98 3.6.2-2 3.6.2-3 184/166 9/30/98 184/1 66 9/30/98 3.6.2-4 207/188 9/4/02 3.6.2-5 243/224 7/26/07 3.6.3-1 184/166 9/30/98 3.6.3-2 184/1 66 9/30/98 3.6.3-3 184/1 66 9/30/98 3.6.3-4 243/224 7/26/07 3.6.3-5 243/224 7/26/07 3.6.3-6 207/1 88 9/4/02 3.6.3-7 184/166 9/30/98 3.6.4-1 184/1 66 9/30/98 3.6.5-1 184/166 9/30/98 3.6.5-2 184/1 66 9/30/98 3.6.6-1 184/166 9/30/98 3.6.6-2 Not Used - 227/209 4/4/0 5 3.6.7-1 McGuire Units I and 2 Page 6 Page 6Revision 88

Page Number Amendment Revision Date 3.6.8-1 221/2,03 4/29/04 3.6.8-2 184/166 9/30/98 3.6.9-1 184/166 9/30/98 3.6.9-2 184/166 9/30/98 3.6.10-1 184/166 9/30/98 3.6.10-2 184/166 9/30/98 3.6.11-1 184/166 9/30/98 3.6.11-2 184/166 9/30/98 3.6.12-1 184/166 9/30/98 3.6.12-2 217/199 9/29/03 3.6.12-3 217/199 9/29/03 3.6.13-1 256/236 6/28/10 3.6.13-2 256/236 6/28/10 3.6.13-3 256/236 6/28/10 3.6.14-1 228/210 4/5/05 3.6.14-2 184/166 9/30/98 3.6.14-3 184/166 9/30/98 3.6.15-1 184/166 9/30/98 3.6.15-2 184/166 9/30/98 3.6.16-1 212/193 5/8/03 3.6.16-2 212/193 5/8/03 3.7.1-1 184/166 9/30/98 3.7.1-2 184/166 9/30/98 3.7.1-3 184/166 9/30/98 3.7.2-1 184/166 9/30/98 3.7.2-2 184/166 9/30/98 3.7.3-1 184/166 9/30/98 3.7.3-2 184/166 9/30/98 3.7.4-1 221/203 4/29/04 3.7.4-2 184/166 9/30/98 3.7.5-1 221/203 4/29/04 3.7.5-2 184/166 9/30/98 3.7.5-3 184/166 9/30/98 3.7.5-4 184/166 9/30/98 McGuir *Ve and 2 inits A1 *lA*

VAAA*

PNoe 7 Revision 88

Page Number Amendment Revision Date 3.7.6-1 184/166 9/30/98 3.7.6-2 184/166 9/30/98 3.7.7-1 184/166 9/30/98 3.7.7-2 184/166 9/30/98 3.7.8-1 184/166 9/30/98 3.7.8-2 184/166 9/30/98 3.7.9-1 249/229 1/30/09 3.7.9-2 249/229. 1/30/09 3.7.9-3 249/229 1/30/09 3.7.10-1 184/166 9/30/98 3.7.10-2 184/166 9/30/98 3.7.11-1 229/211 6/2/056 3.7.11-2 184/166 9/30/98 3.7.12-1 184/166 9/30/98 3.7.12-2 184/166 9/30/98 3.7.13-1 184/166 9/30/98 3.7,.14-1 184/166 9/30/98 3.7.15-1 225/207 3/17/05 3.7.15-2 225/207 3/17/05 3.7.15-3 225/207 3/17/05 3.7.15-4 / 225/207 3/17/05 3.7.15-5 225/207 3/17/05 3.7.15-6 225/207 3/17/05 3.7.15-7 225/207 3/17/05 3.7.15-8 225/207 3/17/05 3.7.15-9 225/207 3/17/05 3.7.15-10 225/207 3/17/05 3.7.15-11 225/207 3/17/05 3.7.15-12 225/207 3/17/05 3.7.15-13 225/207 3/17/05 3.7.15-14 225/207 3/17/05 3.7.15-15 225/207 3/17/05 3.7.15-16 225/207 3/17/05 3.7.15-17 225/207 3/17/05 McGuire Units 1 and 2 Page 8 1 .evislon 88

Page Number Amendment Revision Date 3.7.15-18 225/207 3/17/05 3.7.15-19 225/207 3/17/05 3.7.15-20 225/207 3/17/05 3.7.15-21 225/207 3/17/05 3.7.15-22 225/207 3/17/05 3.7.15-23 225/207 3/17/05 3.7.15-24 225/207 3/17/05 3.7.15-25 225/207 3/17/05 3.7.15-26 225/207 3/17/05 3.7.15-27 225/207 3/17/05 3.7.15-28 225/207 3/17/05 3.7.15-29 225/207 3/17/05 3.7.15-30 225/207 3/17/05 3.7.15-31 225/207 3/17/05 3.7.15-32 225/207 3/17/05 3.7.16-1 184/166 9/30/98 3.8.1-1 221/203 4/29/04 3.8.1-2 184/166 9/30/98 3.8.1-3 241/-, 06/08/07 3.8.1-4 184/166 9/30/98 3.8.1-5 184/166 9/30/98 3.8.1-6 254/234 05/05/10 3.8.1-7 184/166 9/30/98 3.8.1-8 192/173 3/15/00 3.8.1-9 184/166 9/30/98 3.8.1-10 184/166 9/30/98 3.8.1-11 .... 242/223 7/25/07 3.8.1-12 184/166 9/30/98 3.8.1-13 184/166 9/30/98 3.8.1-14 184/166 9/30/98 3.8.1-15 184/166 9/30/98 3.8.2-1 184/166 9/30/98 3.8.2-2 216/197 7/29/03 3.8.2-3 184/166 9/30/98 McGuire Units I and 2 Page 9 Revision 88

Page Number Amendment Revision Date 3.8.3-1 184/166 9/30/98 3.8.3-2 184/166 9/30/98 3.8.3-3 215/196 8/4/03 3.8.4-1 184/166 9/30/98 3.8.4-2 184/166 9/30/98 3.8.4-3 209/190 12/17/02 3.8.5-1 184/166 9/30/98 3.8.5-2 216/197 7/29/03 3.8.6-1 184/166 9/30/98 3.8.6-2 184/166 9/30/98 3.8.6-3 184/166 9/30/98 3.8.6-4 184/166 9/30/98 3.8.7-1 184/166 9/30/98 3.8.8-1 184/166 9/30/98 3.8.8-2 216/197 7/29/03 3.8.9-1 184/166 9/30/98 3.8.9-2 184/166 9/30/98 3.8.10-1 216/197 7/29/03 3.8.10-2 184/166 9/30/98 3.9.1-1 231/213 9/1/05 3.9.2-1 184/166 9/30/98 3.9.3-1 216/197 7/29/03 3.9.3-2 184/166 9/30/98 3.9.4-1 236/218 12/22/06 3.9.4-2 184/166 9/30/98 3.9.5-1 216/197 7/29/03 3.9.5-2 184/166 9/30/98 3.9.6-1 216/197 7/29/03 3.9.6-2 184/166 9/30/98 3.9.7-1 184/166 9/30/98 4.0.1 225/207 3/17/05 4.0.2 225/207 3/17/05 5.1-1 213/194 6/6/03 5.2-1 239/221 04/12/07 McGuire Units 1 and 2 Page 10 Revision 88

Amendment Revision Date Page Number 5.2-2 253/233 9/21/09 213/194 6/6/03 5.3-1 184/166 9/30/98 5.4-1 244/193 2/13108 5.5-1 212/193 5/8/03 5.5-2 184/166 9/30/98 5.5-3 184/166 9/30/98 5.5-4 223/205 8/5/04 5.5-5 252/232 8/17/09 5.5-6 237/219 3/1/07 5.5-7 237/219 3/1/07 5.5-8 237/219 3/1/07 5.5-9 237/219 3/1/07 5.5-10 237/219 3/1/07 5.5-11 2371219 3/1/07 5.5-12 237/219 3/1/07 5.5-13 249/229 1/30/09 5.5-14 249/229 1/30/09 5.5-15 226/208 3/1/07 5.6-1 226/208 3/1/07 5.6-2 226/208 3/1/07 5.6-3 230/212 8/23/05 5.6-4 237/219 3/1/07 5.6-5 213/194 6/6/03 5.7-1 5.7-2 184/166 9/30/98 McGuire Units 1 and 2 Page I I Revision 88

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.9 ------------------ NOTES ------------------

Verification of setpoint is not required.

Perform TADOT. 92 days SR 3.3.1.10 ------------------ NOTES ------------------

This Surveillance shall include verification that the time constants are adjusted to the prescribed values.

Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.11 ------------------------------ NOTES-------------------

1. Neutron detectors are excluded from CHANNEL CALIBRATION.

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

3. Intermediate Range Neutron Flux detector plateau voltage verification is not required to be performed prior to entry into MODE 1 or 2.* 18 months Perform CHANNEL CALIBRATION.

SR 3.3.1.12 Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.13 Perform COT. 18 months (continued)

• This note applies to the Westinghouse-supplied compensated ion chamber neutron

. detectors. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors which do not require detector plateau voltage verification. Therefore, this note does not apply to the fission chamber neutron detectors.

McGuire Units 1 and 2 3.3.1-12 Amendment Nos. 257/237

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page I of 7)

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

1. Manual Reactor Trip 1,2 2 B SR 3.3.1.14 NA NA 3(a), 4(a), 5(a) 2 C SR 3.3.1.14 NA NA

2. Power Range Neutron Flux

a. High 1,2 4 D SR 3.3.1.1 < 110% RTP 109% RTP SR 3.3.1.2 SR 3.3.1.7 SR 3.3.1.11 SR 3.3.1.16

b. Low 4 E SR 3.3.1.1 < 26% RTP 25% RTP SR 3.3.1.8 SR 3.3.1.11 SR 3.3.1.16

3. Power Range Neutron Flux Rate High Positive Rate 1,2 4 D SR 3.3.1.7 < 5.5% RTP 5% RTP SR 3.3.1.11 with time with time constant constant

> 2 sec > 2 sec

4. Intermediate Range 1(b), 2 F,G SR 3.3.1.1 < 30% RTP* 25% RTP 2 (c)

Neutron Flux SR 3.3.1.80)(k) < 38% RTP SR 3.3.1.1 0)(k)

(d) 2 H 25% RTP 2 SR 3.3.1.1 < 30% RTP*

< 38% RTP SR 3.3.1.80)(k)

SR 3.3.1.11 0)(k)

(continued)

• The < 30% RTP Allowable Value applies to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. The < 38% Allowable Value applies to the replacement fission chamber Intermediate Range neutron detectors.

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

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

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

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

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

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

McGuire Units 1 and 2 3.3.1-14 Amendment Nos. 257/237

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 2 of 7)

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

5. Source Range 2 (d) 2 I,J SR 3.3.1.1 < 1.3 E5 cps** 1.0 E5 cps Neutron Flux SR 3.3.1.80)(k) < 1.44 E5 cps SR 3.3.1.11(6)(k) 3(a), 4(a), 5 (a) 2 J,K 1.0 E5 cps SR 3.3.1.1 < 1.3 E5 cps**

SR 3.3.1.76)(k) < 1.44 E5 cps SR 3.3.1.11 0)(k) 3 (e) 4 (e), 5 (e) 1 L SR 3.3.1.1 N/A N/A SR 3.3.1.11

6. Overtemperature AT 1,2 4 E SR 3.3.1.1 Refer to Note 1 Refer to SR 3.3.1.3 (Page Note 1 (Page SR 3.3.1.6 3.3.1-18) 3.3.1-18)

SR 3.3.1.7 SR 3.3.1.12 SR 3.3.1.16 SR 3.3.1.17

,7. Overpower AT 1,2 4 E SR 3.3.1.1 Refer to Note 2 Refer to SR 3.3.1.3 (Page Note 2 (Page SR 3.3.1.6 3.3.1-19) 3.3.1-19)

SR 3.3.1.7 SR 3.3.1.12 SR 3.3.1.16 SR 3.3.1.17

8. Pressurizer Pressure

a. Low 1 (f) 4 M SR 3.3.1.1 > 1935 psig 1945 psig SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16

b. High 1,2 4 E SR 3.3.1.1 < 2395 psig 2385 psig SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16 (continued)

The < 1.3 E5 cps Allowable Value applies to the Westinghouse-supplied boron triflouride (BF 3) Source Range neutron detectors. The BF 3 neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. The < 1.44 E5 cps Allowable Value applies to the replacement fission chamber Source Range neutron detectors.

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

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

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

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

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

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

McGuire Units 1 and 2 3.3.1-15 Amendment Nos. 257/237

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 7)

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

9. Pressurizer Water 1 (f) 3 M SR 3.3.1.1 <93% 92%

Level - Highl SR 3.3.1.7 SR 3.3.1.10'

10. Reactor Coolant Flow- Low

a. Single Loop l(g) 3 per loop N SR 3.3.1.1 > 87% 88%

SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16

b. Two Loops 1 (h) 3 per loop M SR 3.3.1.1 > 87% 88%

SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16

11. Undervoltage RCPs 1 per bus M SR 3.3.1.9 > 5016 V 5082 V 1 (f)

SR 3.3.1.10 SR 3.3.1.16

12. Underfrequency 1 (f) 1 per bus M SR 3.3.1.9 > 55.9 Hz 56.4 Hz RCPs SR 3.3.1.10 SR 3.3.1.16

13. Steam Generator 1,2 4 per SG E SR 3.3.1.1 > 15% 16.7%

(SG) Water Level - SR 3.3.1.7 Low Low SR 3.3.1.10 SR 3.3.1.16

14. Turbine Trip

a. Low Fluid Oil i(g) 3 0 SR 3.3.1.10 > 42 psig 45 psig Pressure SR 3.3.1.15

b. Turbine Stop 1(g) 4 P SR 3.3.1.10 > 1%open > 1%open Valve Closure SR 3.3.1.15

15. Safety Injection (SI) 1,2 2 trains Q SR 3.3.1.5 NA NA Input from SR 3.3.1.14 Engineered Safety Feature Actuation System (ESFAS)

(continued)

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

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

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

McGuire Units 1 and 2 3.3.1-16 Amendment Nos. 257/237

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 7)

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

16. Reactor Trip System Interlocks

a. Intermediate (d) 2 S SR 3.3.1.11 > 4E-1 1 amp*** IE-10 amp***

2 Range Neutron SR 3.3.1.13 > 6.6E-6% RTP 1E-5% RTP Flux, P-6

b. Low Power 1 per train T SR 3.3.1.5 NA NA Reactor Trips Block, P-7 1

c. Power Range 4 T SR 3.3.1.11 < 49% RTP 48% RTP Neutron Flux, SR 3.3.1.13 P-8

d. Power Range 1,2 4 S SR 3.3.1.11 > 7% RTP and 10% RTP Neutron Flux, SR 3.3.1.13 < 11% RTP P-10

e. Turbine Impulse 1 2 T SR 3.3.1.12 < 11% turbine 10% turbine Pressure, P-13 SR 3.3.1.13 impulse impulse pressure pressure equivalent equivalent

17. Reactor Trip 1,2 2 trains R, V SR 3.3.1.4 NA NA Breakers(i) 3(a), 4 (a), 5 (a) 2 trains C SR 3.3.1.4 NA NA

18. Reactor Trip Breaker 1,2 1 each per U SR 3.3.1.4 NA NA Undervoltage and RTB Shunt Trip Mechanisms 3 (a), 4 (a), 5 (a) 1 each per C SR 3.3.1.4 NA NA RTB

19. Automatic Trip Logic 1,2 2 trains Q, V SR 3.3.1.5 NA NA 3(a), 4,(a), 5(a) 2 trains NA NA C SR 3.3.1.5

..

• The > 4E-1 1 amp Allowable Value and the 1E-10 amp NOMINAL TRIP SETPOINT value apply to the Westinghouse-supplied compensated ion chamber Intermediate Range neutron detectors. The compensated ion chamber neutron detectors are being replaced with Thermo Scientific-supplied fission chamber neutron detectors. The > 6.6E-6% RTP Allowable Value and the 1E-5% RTP NOMINAL TRIP SETPOINT value apply to the replacement fission chamber Intermediate Range neutron detectors.

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

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

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

McGuire Units 1 and 2 3.3.1-17 Amendment Nos. 257/237

McGuire Nuclear Station Technical Specification Bases LOES TS Bases are revised by section Page Number Revision Revision Date BASES (Revised per section) i Revision 87 8/15/07 ii Revision 87 8/15/07 iii Revision 87 8/15/07 B 2.1.1 Revision 51 1/14/04 B 2.1.2 Revision 102 8/17/09 B 3.0 Revision 81 3/29/07 B 3.1.1 Revision 73 3/6/06 B 3.1.2 Revision 10 9/22/00 B 3.1.3 Revision 10 9/22/00 B 3.1.4 Revision 0 9/30/98 B 3.1.5 Revision 19 1/10/02 B 3.1.6 Revision 0 9/30/98 B 3.1.7 Revision 58 06/23/04 B 3.1.8 Revision 0 9/30/98 B 3.2.1 Revision 74 5/3/06 B 3.2.2 Revision 10 9/22/00 B 3.2.3 Revision 34 10/1/02 B 3.2.4 Revision 10' 9/22/00 B 3.3.1 Revision 108 8/2/10 B 3.3.2 Revision 99 3/9/09 B 3.3.3 Revision 100 4/13/09 B 3.3.4 Revision 57 4/29/04 B 3.3.5 Revision 11 9/18/00 B 3.3.6 Not Used - Revision 87 6/29/06 B 3.4.1 Revision 51 1/14/04 B 3.4.2 Revision 0 9/30/98 B 3.4.3 Revision 44 7/3/03 B 3.4.4 Revision 86 6/25/07 B 3.4.5 Revision 86 6/25/07 McGuire Units 1 and 2 Page I Revision 102

Page Number Amendment Revision Date B 3.4.6 Revision 86 6/25/07 B 3.4.7 Revision 86 6/25/07 B 3.4.8 Revision 41 7/29/03 B 3.4.9 Revision 0 9/30/98 B 3.4.10 Revision 102 8/17/09 B 3.4.11 Revision 102 8/17/09 B 3.4.12 Revision 102 8/17/09 B 3.4.13 Revision 86 6/25/07 B 3.4.14 Revision 102 8/17/09 B 3.4.15 Revision 82 9/30/06 B 3.4.16 Revision 57 4/29/04 B 3.4.17 Revision 0 9/30/98 B 3.4.18 Revision 86 6/25/07 B 3.5.1 Revision 70 10/5/05 B 3.5.2 Revision 102 8/17/09 B 3.5.3 Revision 57 4/29/04 B 3.5.4 Revision 70 10/5/04 B 3.5.5 Revision 0 9/30/98 B 3.6.1 Revision 53 2/17/04 B 3.6.2 Revision 98 3/24/09 B 3.6.3 Revision 87 6/29/06 B 3.6.4 Revision 0 9/30/98 B 3.6.5 Revision 0 9/30/98 B 3.6.5-2 Revision 6 10/6/99 B 3.6.6 Revision 102 8/17/09 B 3.6.7 Not Used - Revision 63 4/4/05 B 3.6.8 Revision .63 4/4/05 B 3.6.9 Revision 63 4/4/05 B 3.6.10 Revision 43 5/28/03 B 3.6.11 Revision 78 9/25/06 B 3.6.12 Revision 53 2/17/04 B 3.6.13 Revision 104 6/28/10 B 3.6.14 Revision 64 4/23/05 B 3.6.15 Revision 0 9/30/98 McGuire Units 1 and 2 Page 2 Revision 102

Page Number Amendment Revision Date B 3.6.16 Revision 40 5/8/03 B 3.7.1 Revision 102 8/17/09 B 3.7.2 Revision 105 2/22/10 B 3.7.3 Revision 102 8/17/09 B 3.7.4 Revision 57 4/29/04 B 3.7.5 Revisionl02 8/17/09 B 3.7.6 Revision 0 9/30/98 B 3.7.7 Revision 101. 9/17/09 B 3.7.8 Revision 107 6/23/10 B 3.7.9 Revision 97 1/30/09 B 3.7.10 Revision 75 6/12/06 B 3.7.11 Revision 65 6/2/05 B 3.7.12 Revision 28 5/17/02 B 3.7.13 Revision 85 2/26/07 B 3.7.14 Revision 66 6/30/05 B 3.7.15 Revision 66 6/30/05 B 3.7.16 Revision 0 9/30/98 B 3.8.1 Revision 106 10/16/08 B 3.8.2 Revision 92 1/28/08 B 3.8.3 Revision 103 12/15/08 B 3.8.4 Revision 100 4/13/09 B 3.8.5 Revision 41 7/29/03 B 3.8.6 Revision 0 9/30/98 B 3.8.7 Revision 20 1/10/02 B 3.8.8 Revision 41 7/29/03 B 3.8.9 Revision 24 2/4/02 B 3.8.10 Revision 41 7/29/03 B 3.9.1 Revision 68 9/1/05 B 3.9.2 Revision 41 7/29/03 B 3.9.3 Revision 108 8/2/10 B 3.9.4 Revision 84 2/20/07 B 3.9.5 Revision 59 7/29/04 B 3.9.6 Revision 41 7/29/03 B 3.9.7 Revision 88 9/5/07 McGuire Units I and 2 Page 3 Revision 102

-RT6instrumentation B 3.3.1 B 3.3 INSTRUMENTATION

. B 3.3.1 Reactor Trip System (RTS) Instrumentation BASES BACKGROUND The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and Reactor Coolant System (RCS) pressure boundary during anticipated operational occurrences (AOOs) and to assist the Engineered Safety Features (ESF) Systems in mitigating accidents.

The protection and monitoring systems have been designed to assure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RTS, as well as specifying LCOs on other reactor system parameters and equipment performance.

The LSSS, defined in this specification as the Allowable Values, in conjunction with the LCOs, establish the threshold for protective system action to prevent exceeding acceptable limits during Design Basis Accidents (DBAs).

During AOOs, which are those events expected to occur one or more times during theunit life, the acceptable limits are:

1. The Departure from Nucleate Boiling Ratio (DNBR) shall be maintained above the Safety Limit (SL) value to prevent departure from nucleate boiling (DNB);

2. Fuel centerline melt shall not occur; and

3. The RCS pressure SL of 2735 psig shall not be exceeded.

Operation within the SLs of Specification 2.0, "Safety Limits (SLs)," also maintains the above values and assures that offsite dose will be within the 10 CFR 20 and 10 CFR 100 criteria during AOOs.

Accidents are events that are analyzed even though they are not expected to occurduringthe unit life. The acceptable limit during accidents is that offsite dose shall be maintained within an acceptable fraction of 10 CFR 100 limits. Different accident categories are allowed a different fraction of these limits, based on probability of occurrence.

Meeting the acceptable dose limit for an accident category is considered having acceptable consequences for that event.

0 McGuire Units 1 and 2 B 3.3. 1-1 Revision No. 108

r~TS instrumentation B 3.3.1 BASES BACKGROUND (continued)

The RTS instrumentation is segmented into four distinct but interconnected categories as illustrated in UFSAR, Chapter 7 (Ref. 1),

and as identified below:

1. Field transmitters or process sensors: provide a measurable electronic signal based upon the physical characteristics of the parameter being measured-

2. Process monitoring systems, including the Process Control System, the Nuclear Instrumentation System (NIS), and various field contacts and sensors: monitors various plant parameters, provides any required signal processing, and provides digital outputs when parameters exceed predetermined limits. They may also provide outputs for control, indication, alarm, computer input, and recording;

3. Solid State Protection System (SSPS), including input, logic, and output bays: combines the input signals from the process monitoring systems per predetermined logic and initiates a reactor trip and ESF actuation when warranted by the process monitoring systems inputs; and

4. Reactor trip switchgear, including reactor trip breakers (RTBs) and bypass breakers: provides the means to interrupt power to the control rod drive mechanisms (CRDMs) and allows the rod Cluster control assemblies (RCCAs), or "rods," to fall into the core and shut down the reactor. The bypass breakers allow testing of the RTBs at power.

Field Transmitters or Sensors To meet the design demands for redundancy and reliability, more than one, and often as many as four, field transmitters or sensors are used to measure unit parameters. To account for the calibration tolerances and instrument drift, which are assumed to occur between calibrations, statistical allowances are provided NOMINAL TRIP SETPOINT Values.

The OPERABILITY of each transmitter or sensor can be evaluated when its "as found" calibration data are compared against its documented acceptance criteria.

McGuire Units 1 and 2 B 3.3.1-2 Revision No. 108

.. -S nstrumentation B 3.3.1 BASES O BACKGROUND (continued)

Process Monitoring Systems Generally, three or four channels of process control equipment are used for the signal processing of unit parameters measured by the field instruments. The process control equipment provides signal conditioning, compatible output signals for instruments located on the main control board, and comparison of measured input signals with setpoints established by safety analyses. These setpoints are defined in UFSAR, Chapter 7 (Ref. 1), Chapter 6 (Ref. 2), and Chapter 15 (Ref. 3). If the measured value of a unit parameter exceeds the predetermined setpoint, an output from a bistable is forwarded to the SSPS for decision logic processing. Channel separation is maintained up to and through the input bays. However, not all unit parameters require four channels of sensor measurement and signal processing. Some unit parameters provide input only to the SSPS, while others provide input to the SSPS, the main control board, the unit computer, and one or more control systems.

Generally, if a parameter is used only for input to the protection circuits, three channels with a two-out-of-three logic are sufficient to provide the required reliability and. re.1undancy. If one channel fails in a direction that would not result in a partial Function trip, the Function is still OPERABLE

ýinth a two-out-of-two logic. If one channel fails, such that a partial Function trip occurs, a trip will not occur and the Function is still OPERABLE with a one-out-of-two logic.

Generally, if a parameter is used for input to the SSPS and a control function, four channels with a two-out-of-four logic are sufficient to provide the required reliability and redundancy. The circuit must be able to withstand both an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. Again, a single failure will neither cause nor prevent the protection function actuation.

These requirements are described in IEEE-279-1971 (Ref. 4). The actual number of channels required for each unit parameter is specified in Reference 1.

Two logic channels are required to ensure no single random failure of a logic channel will disable the RTS. The logic-channels are designed such that testing required while the reactor is at power may be accomplished without causing a trip. Provisions to allow removing logic channels from service during maintenance ,are unnecessary because of the logic system's designed reliability.

McGuire Units 1 and 2 B 3.3.1-3 Revision No. 108

RTS Instrumentation B 3.3.1 BASES

. BACKGROUND (continued)

Trip Setpoints and Allowable Values The NOMINAL TRIP SETPOINTS are the nominal values at which the bistables are set. Any bistable is considered to be properly adjusted when the "as left" value is within the band for CHANNEL CALIBRATION tolerance.

The NOMINAL TRIP SETPOINTS used in the bistables are based on the analytical limits (Ref. 1, 2, and 3). The selection of these NOMINAL TRIP SETPOINTS is such that adequate protection is provided when all sensor and processing time delays, calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those RTS channels that must function in harsh environments as defined by 10 CFR 50.49 (Ref. 5) are taken into account. The actual as-left Setpoint of the bistable assures that the actual trip occurs in time to prevent an analytical limit from being exceeded.

The Allowable Value accounts for changes in random measurement errors between COTs. One example of such a change in measurement error is drift during the surveillance interval. If the COT demonstrates that the loop trips.within the Allowable Value, the loop is OPERABLE. A trip within the Allowable Value ensures that the predictions of equipment performance used to develop the NOMINAL TRIP SETPOINT are still valid, and that the equipment will initiate a trip in response to an AOO in time to prevent an analytical limit from being exceeded (and that the consequences of DBAs will be acceptable, providing the unit is operated from within the LCOs at the onset of the AOO or DBA and the equipment functions as designed). Note that in the accompanying LCO 3.3.1, the Allowable Values of Table 3.3.1-1 are the LSSS.

Each channel of the process control equipment can be tested on line to verify that the signal or setpoint accuracy is within the specified allowance requirements. Once a designated channel is taken out of service for testing, a simulated signal is injected in place of the field instrument signal. The process equipment for the channel in test is then tested, verified, and calibrated. SRs for the channels are specified in the SRs section.

Determination of the NOMINAL TRIP SETPOINTS and Allowable Values listed in Table 3.3.1-1 incorporate all of the known uncertainties applicable for each channel. The magnitudes of these uncertainties are factored into the determination of each NOMINAL TRIP SETPOINT. All field sensors and signal processing equipment for these channels are assumed to operate within the allowances of these uncertainty magnitudes.

McGuire Units 1 and 2 B 3.3.1-4 Revision No. 108

. RTS Instrumentation B 3.3.1 BASES

. BACKGROUND (continued)

Solid State Protection System The SSPS equipment is used for the decision logic processing of outputs from the signal processing equipment bistables. To meet the redundancy requirements, two trains of SSPS, each performing the same functions, are provided. If one train is taken out of service for maintenance or test purposes, the second train will provide reactor trip and/or ESF actuation for the unit. If both trains are taken out of service or placed in test, a reactor trip will result. Each train is packaged in its own cabinet for physical and electrical separation to satisfy separation and independence requirements. The system has been designed to trip the reactor in the event of a loss of power, directing the unit to a safe shutdown condition.

The SSPS performs the decision logic for actuating a reactor trip or ESF actuation, generates the electrical output signal that will initiate the required trip or actuation, and provides the status, permissive, and annunciator output signals to the main control room of the unit.

The outputs from the process monitoring systems are sensed by the SSPS equipment and combined into logic matrices that represent combinations indicative of various unit upset and accident transients. If a logic matrix combination is completed, the system will initiate a reactor trip or send actuation signals via master and slave relays to those components whose aggregate Function best serves to alleviate the condition and restore the unit to a stable condition. Examples are given in the Applicable Safety Analyses, LCO, and Applicability sections of this Bases.

Reactor Trip Switchgear The RTBs are in the electrical power supply line from the control rod drive motor generator set power supply to the CRDMs. Opening of the RTBs interrupts power to the CRDMs, which allows the shutdown rods and control rods to fall into the core by gravity. Each RTB is equipped with a bypass breaker to allow testing of the RTB while the unit is at power.

During normal operation the output from the SSPS is a voltage signal that energizes the undervoltage coils in the RTBs and bypass breakers, if in use. When the required logic matrix combination is completed, the SSPS output voltage signal is removed, the undervoltage coils are de-energized, the breaker trip lever is actuated by a compressed spring that is released by de-energizing the undervoltage coil, and the RTBs and bypass breakers are tripped open. This allows the shutdown rods and control rods to fall into the core. In addition to the de-energization of the 0

McGuire Units 1 and 2 B 3.3.1-5 Revision No. 108

RTS Instrumentation B 3.3.1 BASES BACKGROUND (continued) undervoltage coils, each breaker is also equipped with a shunt trip device that is energized to trip the breaker open upon receipt of a reactor trip signal from the SSPS. Either the undervoltage coil or the shunt trip mechanism is sufficient by itself, thus providing a diverse trip mechanism.

The decision logic matrix Functions are described in the functional diagrams included in Reference 1. In addition to the reactor trip or ESF, these diagrams also describe the various "permissive interlocks" that are associated with unit conditions. Each train has a built in testing device that can test the decision logic matrix Functions and the actuation devices while the unit is at power. When any one train is taken out of service for testing, the other train is capable of providing unit monitoring and protection until the testing has been completed. The testing device is semiautomatic to minimize testing time.

APPLICABLE The RTS functions to maintain the SLs during all AOOs and mitigates SAFETY ANALYSES,the consequences of DBAs in all MODES in which the RTBs are closed.

LCO, and APPLICABILITY Each of the analyzed accidents and transients can be detected by one or more RTS Functions. The accident analysis described in Reference 3 takes credit for most RTS trip Functions. RTS trip Functions not specifically credited in the accident analysis are qualitatively credited in the safety analysis and the NRC staff approved licensing basis for the unit. These RTS trip Functions may provide protection for conditions that do not require dynamic transient analysis to demonstrate Function performance. They may also serve as backups to RTS trip Functions that were credited in the accident analysis.

The LCO requires all instrumentation performing an RTS Function, listed in Table 3.3.1-1 in the accompanying LCO, to be OPERABLE. Failure of any instrument renders the affected channel(s) inoperable and reduces the reliability of the affected Functions.

The LCO generally requires OPERABILITY of three or four channels in each instrumentation Function, two channels of Manual Reactor Trip in each logic Function, and two trains in each Automatic Trip Logic Function.

Four OPERABLE instrumentation channels in a two-out-of-four configuration are required when one RTS channel is also used as a control system input. This configuration accounts for the possibility of the shared channel failing in such a manner that it creates a transient that requires RTS action. -In this case, the RTS will still provide protection, McGuire Units 1 and 2 B 3.3.1-6 Revision No. 108

RT S Instrumentation B 3.3.1 BASES

. APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) even with random failure of one of the other three protection channels.

Three operable instrumentation channels in a two-out-of-three configuration are generally required when there is no potential for control system and protection system interaction that could simultaneously create a need for RTS trip and disable one RTS channel. The two-out-of-three and two-out-of-four configurations allow one channel to be tripped during maintenance or testing without causing a reactor trip. Specific exceptions to the above general philosophy exist and are discussed below.

Reactor Trip System Functions /

The safety analyses and OPERABILITY requirements applicable to each RTS Function are discussed below:

1. Manual Reactor Trip The Manual Reactor Trip ensures that the control room operator can initiate a reactor trip at any time by using either of two reactor trip switches in the control room. A Manual Reactor Trip accomplishes the same results as any one of the automatic trip Functions. It may be used by the reactor operator to shut down the reactor whenever any parameter is rapidly trending toward its Trip Setpoint.

The LCO requires two Manual Reactor Trip channels to be OPERABLE. Each channel is controlled by a manual reactor trip switch. Each channel actuates one ormore reactor trip breakers in both trains. Two independent channels are required to be OPERABLE so that no single random failure will disable the Manual Reactor Trip Function.

In MODE 1 or 2, manual initiation of a reactor trip must be OPERABLE. These are the MODES in which the shutdown rods and/or control rods are partially or fully withdrawn from the core. In MODE 3, 4, or 5, the manual initiation Function must also be OPERABLE if the shutdown rods or control rods are withdrawn or the Control Rod Drive (CRD) System is capable of withdrawing the shutdown rods or the control rods. In this condition, inadvertent control rod withdrawal is possible. In MODE 3, 4, or 5, manual initiation of a reactor trip does not have to be OPERABLE if the CRDSystem is not capable of withdrawing the shutdown rods or control rods. If the rods cannot be withdrawn from the core, there McGuire Units 1 and 2 B 3.3.1-7 Revision No. 108

1M 179 Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) is no need to be able to trip the reactor because all of the rods are inserted. In MODE 6, the CRDMs are disconnected from the control rods and shutdown rods. Therefore, the manual initiation Function is not required.

2. Power Range Neutron Flux The NIS power range detectors are located external to the reactor vessel and measure neutrons leaking from the core. The NIS power range detectors' provide input to the Rod Control System and the Steam Generator (SG) Water Level ControlSystem. Therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. Note that this Function also provides a signal to prevent automatic and manual rod withdrawal prior to initiating a reactor trip. Limiting further rod withdrawal may terminate the transient and eliminate the need to trip the reactor.

a. Power Range Neutron Flux-High The Power Range Neutron Flux-High trip Function ensures that protection is provided, from all power levels, against a positive reactivity excursion leading to DNB during power operations. These can be caused by rod withdrawal or reductions in RCS temperature.

The LCO requires all four of the Power Range Neutron Flux-High channels to be OPERABLE.

In MODE 1 or 2, when a positive reactivity excursion could occur, the Power Range Neutron Flux-High trip must be OPERABLE. This Function will terminate the reactivity excursion and shut down the reactor prior to reaching a power level that could damage the fuel. In MODE 3, 4, 5, or 6, the NIS power range detectorscannot detect neutron levels in this range. In these MODES, the Power Range Neutron Flux-High does not have to be OPERABLE because the reactor is shut down and reactivity excursions into the power range are extremely unlikely. Other RTS Functions and administrative controls provide protection against reactivity additions when in MODE 3, 4, 5, or 6.

McGuire Units 1 and 2 B 3.3.1-8 Revision No. 108

RTS Instrumentation B 3.3.1

. BASES APPLICABLE SAFETY ANALYSES, LCO and APPLICABILITY (continued)

b. Power Range Neutron Flux-Low The LCO requirement for the Power Range Neutron Flux-Low trip Function ensures that protection is provided against a positive reactivity excursion from low power or subcritical conditions.

The LCO requires all four of the Power Range Neutron Flux-Low channels to be OPERABLE.

In MODE 1, below the Power Range Neutron Flux (P-1 0 setpoint), and in MODE 2, the Power Range Neutron Flux-Low trip must be OPERABLE. This Function may be manually blocked by the operator when two out of four power range channels are greater than approximately 10% RTP (P-10 setpoint). This Function is automatically unblocked when three out of four power range channels are below the P-10 setpoint. Above the P-10 setpoint, positive reactivity additions are mitigated by the Power Range Neutron Flux-High trip Function.

In MODE 3, 4, 5, or 6, the Power Range Neutron Flux-Low trip Function does not have to be OPERABLE because the reactor is shut down and the NIS power range detectors cannot detect neutron levels in this range. Other RTS trip Functions and administrative controls provide protection against positive reactivity additions or power excursions in MODE 3, 4, 5, or 6.

3. Power Range Neutron Flux-High Positive Rate The Power Range Neutron Flux - High Positive Rate trip uses the same channels as discussed for Function 2 above.

The Power Range Neutron Flux-High Positive Rate trip Function ensures that protection is provided against rapid increases in neutron flux that are characteristic of an RCCA drive rod housing rupture and the accompanying ejection of the RCCA. This Function complements the Power Range Neutron Flux-High and Low Setpoint trip Functions to ensure that the criteria are met for a rod ejection from the power range.

The LCO requires all four of the Power Range Neutron Flux-High Positive Rate channels to be OPERABLE.

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In MODE 1 or 2, when there is a potential to add a large amount of positive reactivity from a rod ejection accident (REA), the Power Range Neutron Flux-High Positive Rate trip must be OPERABLE.

In MODE 3, 4, 5, or 6, the Power Range Neutron Flux-High Positive Rate trip Function does not have to be OPERABLE because other RTS trip Functions and administrative controls will provide protection against positive reactivity additions. In MODE 6, no rods are withdrawn and the SDM is increased during refueling operations. The reactor vessel head is also removed or the closure bolts are detensioned preventing any pressure buildup. In addition, the NIS power range detectors cannot detect neutron levels present in this mode.

4A. Intermediate Range Neutron Flux (Westingqhouse-supplied Instrumentation)

The Westinghouse-supplied Intermediate Range excore detector systems (utilizing compensated ion chamber detectors) are being replaced with Thermo Scientific-supplied 300i neutron flux monitoring systems (utilizing fission chamber detectors). This section of the Bases applies to the Westinghouse-supplied instrumentation. The next section of the Bases applies to the Thermo Scientific-supplied instrumentation.

The Intermediate Range Neutron Flux trip Function ensures that protection is provided against an uncontrolled RCCA bank rod withdrawal accident from a subcritical condition during startup. This trip Function provides redundant protection to the Power Range Neutron Flux-Low Setpoint trip Function. The NIS intermediate range detectors are located external to the reactor vessel and measure neutrons leaking from the core. Note that this Function also provides a signal to prevent automatic and manual rod withdrawal prior to initiating a reactor trip. Limiting further rod withdrawal may terminate the transient and eliminate the need to trip the reactor.

The LCO requires two channels of Intermediate Range Neutron Flux to be OPERABLE. Two OPERABLE channels are sufficient to ensure no single random failure will disable this trip Function.

Because this trip Function is important only during startup, there is generally no need to disable channels for testing while the Function is required to be OPERABLE. Therefore, a third channel is unnecessary.

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RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

In MODE 1 below the P-10 setpoint, and in MODE 2, when there is a potential for an uncontrolled RCCA bank rod withdrawal accident during reactor startup, the Intermediate Range Neutron Flux trip must be OPERABLE. Above the P-10 setpoint, the Power Range Neutron Flux-High Setpoint trip and the Power Range Neutron Flux-High Positive Rate trip provide core protection for a rod withdrawal accident. In MODE 3, 4, or 5, the Intermediate Range Neutron Flux trip does not have to be OPERABLE because other RTS trip functions provide protection against positive reactivity additions. The reactor cannot be started up in this condition. The core also has the required SDM to mitigate the consequences of a positive reactivity addition accident. In MODE 6, all rods are fully inserted and the core has a required increased SDM. Also, the NIS intermediate range detectors cannot detect neutron levels present in this MODE.

4B. Intermediate Range Neutron Flux (Thermo Scientific-supplied Instrumentation)

The Westinghouse-supplied Intermediate Range excore detector systems (utilizing compensated ion chamber detectors) are being replaced with Thermo Scientific-supplied 300i neutron flux monitoring systems (utilizing fission chamber detectors). This section of the Bases applies to the Thermo Scientific-supplied instrumentation. The previous section of the Bases applies to the Westinghouse-supplied instrumentation.

The Intermediate Range Neutron Flux trip Function ensures that protection is provided against an uncontrolled RCCA bank rod withdrawal accident from a subcritical condition during startup. This trip Function provides redundant protection to the Power Range Neutron Flux-Low Setpoint trip Function. The NIS intermediate range detectors are located external to the reactor vessel and measure neutrons leaking from the core. Note that this Function also provides a signal to prevent automatic and manual rod withdrawal prior to initiating a reactor trip. Limiting further rod withdrawal may terminate the transient and eliminate the need to trip the reactor.

The LCO requires two channels of Intermediate Range Neutron Flux to be OPERABLE. Two OPERABLE channels are sufficient to ensure no single random failure will disable this trip Function.

Because this trip Function is important only during startup, there is

_ generally no need to disable channels for testing while the Function McGuire Units 1 and 2 B 3.3.1-11 Revision No. 108

RTS Instrumentation B 3.3.1 BASES

. APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) is required to be OPERABLE. Therefore, a third channel is unnecessary.

In MODE 1 below the P-10 setpoint, and in MODE 2, when there is a potential for an uncontrolled RCCA bank rod withdrawal accident during reactor startup, the Intermediate Range Neutron Flux trip must be OPERABLE. Above the P-10 setpoint, the Power Range Neutron Flux-High Setpoint trip and the Power Range Neutron Flux-High Positive Rate trip provide core protection for a rod withdrawal accident. In MODE 3, 4, or 5, the Intermediate Range Neutron Flux trip does not have to be OPERABLE because other RTS trip functions provide protection against positive reactivity additions. The reactor cannot be started up in this condition. The core also has the required SDM to mitigate the consequences of a positive reactivity addition accident. In MODE 6, all rods are fully inserted and the core has a required increased SDM.

5A. Source Range Neutron Flux (Westinghouse-supplied Instrumentation)

The Westinghouse-supplied Source Range excore detector systems (utilizing boron triflouride detectors) are being replaced with Thermo Scientific-supplied 300i neutron flux monitoring systems (utilizing fission chamber detectors). This section of the Bases applies to the Westinghouse-supplied instrumentation. The next section of the Bases applies to the Thermo Scientific-supplied instrumentation.

The LCO requirement for the Source Range Neutron Flux trip Function ensures that protection is provided against an uncontrolled RCCA bank rod withdrawal accident from a subcritical condition during startup. This trip Function provides redundant protection to the Power Range Neutron Flux-Low Setpoint and Intermediate Range Neutron Flux trip Functions. In MODES 3, 4, and 5, administrative controls also prevent the uncontrolled withdrawal of rods. The NIS source range detectors are located external to the reactor vessel and measure neutrons leaking from the core. The NIS source range detectors do not provide any inputs to control systems. The source range trip is the only RTS automatic protection function required in MODES 3, 4, and 5 with the CRD System capable of rod withdrawal. Therefore, the functional capability at the specified Trip Setpoint is assumed to be available.

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The LCO requires two channels of Source Range Neutron Flux to be OPERABLE. Two OPERABLE channels are sufficient to ensure no single random failure will disable this trip Function. The LCO also requires one channel of the Source Range Neutron Flux to be OPERABLE in MODE 3, 4, or 5 with RTBs open. In this case, the source range Function is to provide control room indication. The outputs of the Function to RTS logic are not required OPERABLE when the RTBs are open.

The Source Range Neutron Flux Function provides protection for control rod withdrawal from subcritical, boron dilution, and control rod ejection events. The Function also provides visual neutron flux indication in the control room.

In MODE 2 when below the P-6 setpoint during a reactor startup, the Source Range Neutron Flux trip must be OPERABLE. Above the P-6 setpoint, the Intermediate Range Neutron Flux trip and the Power Range Neutron Flux-Low Setpoint trip will provide core protection for reactivity accidents. Above the P-6 setpoint, the NIS source range detectors are de-energized and inoperable.

In MODE 3,4, or 5 with the reactor shut down, the Source Range Neutron Flux trip Function must also be OPERABLE. If the CRD System is capable of rod withdrawal, the Source Range Neutron Flux trip must be OPERABLE to provide core protection against a rod withdrawal accident. If the unit is to be in MODE 3 with the RTBs closed for > 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> the Surveillance requirement SR 3.3.1.7 must be completed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after entry into MODE 3. The surveillance shall include verification of the high flux at shutdown alarm, setpoint of less than or equal to five times background of the average CPS Neutron Level Reading (the average CPS Reading is the most consistent value between highest and lowest CPS Neutron Level Reading).

If the CRD System is not capable of rod withdrawal, the source range detectors are not required to trip the reactor. However, their monitoring Function must be OPERABLE to monitor core neutron levels and provide indication of reactivity changes that may occur as a result of events like a boron dilution.

The neutron detector's high flux at shutdown alarm setpoint of less than or equal to five times background, in Mode 3, 4, or 5, shall be verified. Once the High Flux at Shutdown Alarm setpoints are set at five times background above steady state neutron count rate the re-verification/re-adjustment of the high flux at shutdown is not

• required. The neutron count rate will decrease as Mode changes McGuire Units 1 and 2 B 3.3.1-13 Revision No. 108

RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) are made from 3 to 4 to 5 as the system temperature decreases.

Any subsequent changes in the count rate are an indication of gamma flux (due to movement of irradiated particles in the system) which may cause the source range response to vary. Upon increase in the neutron count rate due to activities that add positive reactivity to the core, the presence of gamma flux will cease to be a factor in detector count rate.

A CHANNEL CHECK provides a comparison of the parameter indicated on one channel to a similar parameter on other channels.

This is based on the assumption that the two indicating channels should be consistent. Significant differences between the indicating source range channels can occur due to core geometry, decreasing.

neutron count rate as temperature is decreasing in the system, the location of the Source Assemblies (distance from the Source Detectors), and large amounts of gamma. Each channel should be consistent with its local condition.

The requirements for the NIS source range detectors in MODE 6 are addressed in LCO 3.9.3, "Nuclear Instrumentation."

5B. Source Range Neutron Flux (Thermo Scientific-supplied Instrumentation)

The Westinghouse-supplied Source Range excore detector systems (utilizing boron triflouride detectors) are being replaced with Thermo Scientific-supplied 300i neutron flux monitoring systems (utilizing fission chamber detectors). This section of the Bases applies to the Thermo Scientific-supplied instrumentation.

The previous section of the Bases applies to the Westinghouse-supplied instrumentation.

The LCO requirement for the Source Range Neutron Flux trip Function ensures that protection is provided against an uncontrolled RCCA bank rod withdrawal accident from a subcritical condition during startup. This trip Function provides redundant protection to the Power Range Neutron Flux-Low Setpoint and Intermediate Range Neutron Flux trip Functions. In MODES 3, 4, and 5, administrative controls also prevent the uncontrolled withdrawal of rods. The NIS source range detectors are located external to the reactor vessel and measure neutrons leaking from the core. The NIS source range detectors do not provide any inputs to control systems. The source range trip is the only RTS automatic protection function required in MODES 3, 4, and 5 with

__ the CRD System capable of rod withdrawal. Therefore, the McGuire Units 1 and 2 B 3.3.1-14 Revision No. 108

RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) functional capability at the specified Trip Setpoint is assumed to be available.

The LCO requires two channels of Source Range Neutron Flux to be OPERABLE. Two OPERABLE channels are sufficient to ensure no single random failure will disable this trip Function. The LCO also requires one channel of the Source. Range Neutron Flux to be OPERABLE in MODE 3, 4, or 5 with RTBs open. In this case, the source range Function is to provide control room indication. The outputs of the Function to RTS logic are not required OPERABLE when the RTBs are open.

The Source Range Neutron Flux Function provides protection for control rod withdrawal from subcritical, boron dilution, and control rod ejection events. The Function also provides visual neutron flux indication in the control room.

In MODE 2 when below the P-6 setpoint during a reactor startup, the Source Range Neutron Flux trip must be OPERABLE. Above the P-6 setpoint, the Intermediate Range Neutron Flux trip and the Power Range Neutron Flux-Low Setpoint trip will provide core protection for reactivity accidents. Above the P-6 setpoint, the Source Range Neutron Flux trip is blocked.

In MODE 3, 4, or 5 with the reactor shut down, the Source Range Neutron Flux trip Function must also be OPERABLE. If the CRD System is capable of rod withdrawal, the Source Range Neutron Flux trip must be OPERABLE to provide core protection against a rod withdrawal accident. If the unit is to be in MODE 3 with the RTBs closed for > 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> the Surveillance requirement SR 3.3.1.7 must be completed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after entry into MODE 3.

If the CRD System is not capable of rod withdrawal, the source range detectors are not required to trip the reactor. However, their monitoring Function must be OPERABLE to monitor core neutron levels and provide indication of reactivity changes that may occur as a result of events like a boron dilution.

A CHANNEL CHECK provides a comparison of the parameter indicated on one channel to a similar parameter on other channels.

This is based on the assumption that the two indicating .channels should be consistent. Significant differences- between the indicating source range channels can occur due to core geometry, decreasing neutron count rate as temperature is decreasing in the system, the 0 location of the Source Assemblies (distance from the Source McGuire Units 1 and 2 B 3.3.1-15 Revision No. 108.

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. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Detectors), and large amounts of gamma. Each channel should be consistent with its local condition.

The requirements for the NIS source range detectors in MODE 6 are addressed in LCO 3.9.3, "Nuclear Instrumentation."

6. Overtemperature AT The Overtemperature AT trip Function is provided to ensure that the design limit DNBR is met. This trip Function also limits the range over which the Overpower AT trip Function must provide protection. The inputs to the Overtemperature AT trip include pressurizer pressure, coolant temperature, axial power distribution, and reactor power as indicated by loop AT assuming full reactor coolant flow. Protection from violating the DNBR limit is assured for those transients that are slow with respect to delays from the core to the measurement system. The Function monitors both variation in power and flow since a decrease in flow has the same effect on AT as a power increase. The Overtemperature AT trip Function uses each loop's AT as a measure of reactor power and is compared with a setpoint that is ait6matically varied with the following parameters:

reactor coolant average temperature-the Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; pressurizer pressure-the Trip Setpoint is varied to correct for changes in system pressure; and axial power distribution-f(AI), the Trip Setpoint is varied to account for imbalances in the axial power distribution as detected by the NIS upper and lower power range detectors.

If axial peaks are greater than the design limit,. as indicated by the difference between the upper and lower NIS power range detectors, the Trip Setpoint is reduced in accordance with Note 1 of Table 3.3.1-1.

Dynamic compensation is included for system piping delays from the core to the temperature measurement system.

The Overtemperature AT trip Function is calculated for each loop as described in Note 1 of Table 3.3.1-1. Trip occurs if Overtemperature AT is indicated in two loops. The pressure and temperature signals are used for other control functions, therefore,

• the actuation logic must be able to withstand an input failure to the McGuire Units 1 and 2 B 3.3.1-16 Revision No. 108

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. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. Note that this Function also provides a signal to generate a turbine runback prior to reaching the Trip Setpoint. A turbine runback will reduce turbine power and reactor power. A reduction in power will normally alleviate the Overtemperature AT condition and may prevent a reactor trip.

The LCO requires all four channels of the Overtemperature AT trip Function to be OPERABLE. Note that the Overtemperature AT Function receives input from channels shared with other RTS Functions. Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions.

In MODE 1 or 2, the Overtemperature AT trip must be OPERABLE to prevent DNB. In MODE 3, 4, 5, or 6, this trip Function does not have to be OPERABLE because the reactor is not operating and there is insufficient heat production to be concerned about DNB.

7. Overpower AT

• The Overpower AT trip Function ensures that protection is provided to ensure the integrity of the fuel (i.e., no fuel pellet melting and less than 1% cladding strain) under all possible overpower conditions.

This trip Function also limits the required range of the Overtemperature AT trip Function and provides a backup to the Power Range Neutron Flux-High Setpoint trip. The Overpower AT trip Function ensures that the allowable heat generation rate (kW/ft) of the fuel is not exceeded. It uses the AT of each loop as a measure of reactor power with a setpoint that is automatically varied with the following parameters:

. reactor coolant average temperature-the Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; and

• rate of change of reactor coolant average temperature-including dynamic compensation for the delays between the core and the temperature measurement system.

The Overpower AT trip Function is calculated for each loop as per Note 2 of Table 3.3.1-1. Trip occurs if Overpower AT is indicated in two loops. The temperature signals are used for other control functions, therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the McGuire Units 1 and 2 B 3.3.1-17 Revision No. 108

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. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) protection function actuation, and a single failure in the remaining channels providing the protection function actuation. Note that this Function also provides a signal to generate a turbine runback prior to reaching the Trip Setpoint. A turbine runback will reduce turbine power and reactor power. A reduction in power will normally alleviate the Overpower AT condition and may prevent a reactor, trip.

The LCO requires four channels of the Overpower. AT trip Function to be OPERABLE. Note that the Overpower AT trip Function receives input from channels shared with other RTS Functions.

Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions.

In MODE 1 or 2, the Overpower AT trip Function must be OPERABLE. These are the only times that enough heat is generated in the fuel to be concerned about the heat generation rates and overheating of the fuel. In MODE 3, 4, 5, or 6, this trip Function does not have to be OPERABLE because the reactor is not operating and there is insufficient heat production to be concerned alout fuel overheating and fuel damage.

8. Pressurizer Pressure The same sensors provide input to the Pressurizer Pressure-High and -Low trips and the Overtemperature AT trip. The Pressurizer Pressure channels are also used to provide input to the Pressurizer Pressure Control System, therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation.

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RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

a. Pressurizer Pressure-Low The Pressurizer Pressure-Low trip Function ensures that protection is provided against violating the DNBR limit due to low pressure.

The LCO requires four channels of Pressurizer Pressure-Low to be OPERABLE.

In MODE 1, when DNB is a major concern, the Pressurizer Pressure-Low trip must be OPERABLE. This trip Function is automatically enabled on increasing power by the P-7 interlock (NIS power range P-1 0 or turbine impulse pressure greater than approximately 10% of full power equivalent (P-13)). On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, power distributions that would cause DNB concerns are unlikely.

b. Pressurizer Pressure-High The Pressurizer Pressure-High trip Function ensures that protection is provided against overpressurizing the RCS.

This trip Function operates in conjunction with the pressurizer relief and safety valves to prevent RCS overpressure conditions.

The LCO requires four channels of the Pressurizer Pressure-High to be OPERABLE.

The Pressurizer Pressure-High LSSS is selected to be below the pressurizer safety valve actuation pressure and above the power operated relief valve (PORV) setting. This setting minimizes challenges-to safety valves while avoiding unnecessary reactor trips for those pressure increases that can be controlled by the PORVs.

In MODE 1 or 2, the Pressurizer Pressure-High trip must be OPERABLE to help prevent RCS overpressurization and minimize challenges to the safety valves. In MODE 3, 4, 5, or 6, the Pressurizer Pressure-High trip Function does not have to be OPERABLE because transients that could cause an overpressure condition will be slow to occur. Therefore, the operator will have sufficient time to evaluate unit McGuire Units 1 and 2 B 3.3.1-19 Revision No. 108

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. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) conditions and take corrective actions. Additionally, low temperature overpressure protection systems provide overpressure protection when below MODE 4.

9. Pressurizer Water Level-High The Pressurizer Water Level-High trip Function provides a backup signal for the Pressurizer Pressure-High trip and also provides protection against water relief through the pressurizer safety valves.

These valves are designed to pass steam in order to achieve their design energy removal rate. A reactor trip is actuated prior to the pressurizer becoming water solid. The setpoints are based on percent of instrument span. The LCO requires three channels of Pressurizer Water Level-High to be OPERABLE. The pressurizer level channels are used as input to the Pressurizer Level Control System. A fourth channel is not required to address control/protection interaction concerns. The level channels do not actuate the safety valves, and the high pressure reactor trip is set below the safety valve setting. Therefore, with the slow rate of charging available, pressure overshoot due to level channel failure cannot cause the safety valve to lift before reactor high pressure trip.

In MODE 1, when there is a potential for overfilling the pressurizer, the Pressurizer Water Level-High trip must be OPERABLE. This trip Function is automatically enabled on increasing power by the P-7 interlock. On decreasing power, this trip Function is automatically

.blocked below P-7. Below the P-7 setpoint, transients that could raise the pressurizer water level will be slow and the operator will have sufficient time to evaluate unit conditions and take corrective actions.

10. Reactor Coolant Flow-Low

a. Reactor Coolant Flow-Low (Single Loop).

The Reactor Coolant Flow-Low (Single Loop) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in one or more RCS loops, while avoiding reactor trips due to normal variations in loop flow.

Above the P-8 setpoint, which is approximately 48% RTP, a loss of flow in any RCS loop will actuate a reactor trip. The setpoints are based on the minimum flow specified in the McGuire Units 1 and 2 B 3.3.1-20 Revision No. 108

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. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

COLR. Each RCS loop has three flow detectors to monitor flow. The flow signals are not used for any control system input.

The LCO requires three Reactor Coolant Flow-Low channels per loop to be OPERABLE in MODE 1 above P-8.

In MODE 1 above the P-8 setpoint, a loss of flow in one RCS loop could result in DNB conditions in the core. In MODE 1 below the P-8 setpoint, a loss of flow in two or more loops is required to actuate a reactor trip (Function 10.b) because of the lower power level and the greater margin to the design limit DNBR.

b. Reactor Coolant Flow-Low (Two Loops)

The Reactor Coolant Flow-Low (Two Loops) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in two or more RCS loops while avoiding reactor trips due to normal variations in loop flow.

Above the P-7 setpoint and below the P-8 setpoint, a loss of flow in two or more loops will initiate a reactor trip. The setpoints are based on the minimum flow specified in the COLR. Each loop has three flow detectors to monitor flow.

The flow signals are not used for any control system input.

The LCO requires three Reactor Coolant Flow-Low channels per loop to be OPERABLE.

In MODE 1 above the P-7 setpoint and below the P-8 setpoint, the Reactor Coolant Flow-Low (Two Loops) trip must be OPERABLE. Below the P-7 setpoint, all reactor trips on low flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely. Above the P-7 setpoint, the reactor trip on low flow in two or more RCS loops is automatically enabled. Above the P-8 setpoint, a loss of flow in any one loop will actuate a reactor trip because of the higher power level and the reduced margin to the design limit DNBR.

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RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

11. Undervoltaqe Reactor Coolant Pumps The Undervoltage RCPs reactor trip Function ensures that protection is provided against violating the DNBR limit due to a loss of flow in two or more RCS loops. The voltage to each RCP is monitored. Above the P-7 setpoint, a loss of voltage detected on two or more RCP buses will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow-Low (Two Loops) Trip Setpoint is reached. Time delays are incorporated into the Undervoltage RCPs channels to prevent reactor trips due to momentary electrical power transients.

The LCO requires a total of four Undervoltage RCPs channels (one per bus) to be OPERABLE.

In MODE 1 above the P-7 setpoint, the Undervoltage RCP trip must be OPERABLE. Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely. Above the P-7 setpoint, the reactor trip on loss of flow in two or more RCS loops is automatically enabled.

12. Underfrequency Reactor Coolant Pumps The Underfrequency RCPs reactor trip Function ensures that protection is provided against violating the DNBR limit due to a loss of flow in two or more RCS loops from a major network frequency disturbance. An underfrequency condition will slow down the pumps, thereby reducing their coastdown time following a pump trip. The proper coastdown time is required so that reactor heat can be removed immediately after reactor trip. The frequency of each RCP bus is monitored. Above the P-7 setpoint, a loss of frequency detected on two or more RCP buses will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow-Low (Two Loops) Trip Setpoint is reached.

Time delays are incorporated into the Underfrequency RCPs channels to prevent reactor trips due to momentary electrical power transients.

The LCO requires a total of four Underfrequency RCPs channels (one per bus) to be OPERABLE.

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In MODE 1 above the P-7 setpoint, the Underfrequency RCPs trip must be OPERABLE. Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely.

Above the P-7 setpoint, the reactor trip on loss of flow in two or more RCS loops is automatically enabled.

13. Steam Generator Water Level-Low Low The SG Water Level-Low Low trip Function ensures that protection is provided against a loss of heat sink and actuates the AFW System prior to uncovering the SG tubes. The SGs are the heat sink for the reactor. In order to act as a heat sink, the SGs must contain a minimum amount of water. A narrow range low low level in any SG is indicative of a loss of heat sink for the reactor. The level transmitters provide input to the SG Level Control System.

Therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. This Function also performs the ESFAS function of starting the AFW pumps on low low SG level.

The LCO requires four channels of SG Water Level-Low Low per SG to be OPERABLE since these channels are shared between protection and control.

In MODE 1 or 2, when the reactor requires a heat sink, the SG Water Level-Low Low trip must be OPERABLE. The normal source of water for the SGs is the Main Feedwater (MFW) System (not safety related). The MFW System is normally in operation in MODES 1, 2, 3, or 4. The AFW System is the safety related backup source of water to ensure that the SGs remain the heat sink for the reactor. In MODE 3, 4, 5, or 6, the SG Water Level-Low Low Function does not have to be OPERABLE because the reactor is not operating or even critical. Decay heat removal is accomplished by the steam generators in MODE 3 and 4 and by the Residual Heat Removal (RHR) System in MODE 4, 5, or 6.

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14. Turbine Trip

a. Turbine Trip-Low Fluid Oil Pressure The Turbine Trip-Low Fluid Oil Pressure trip Function anticipates the loss of heat removal capabilities of the secondary system following a turbine trip. This trip Function acts to minimize the pressure/temperature transient on the reactor. Any turbine trip from a power level below the P-8 setpoint, approximately 48% power, will not actuate a reactor trip. Three pressure switches monitor the control oil pressure in the Turbine Electrohydraulic Control System. A low pressure condition sensed by two-out-of-three pressure switches will actuate a reactor trip. These pressure switches do not provide any input to the control system. The unit is designed to withstand a complete loss of load and not sustain core damage or challenge the RCS pressure limitations. Core protection is provided by the Pressurizer Pressure-High trip Function and RCS integrity is ensured by the pressurizer safety valves. Turbine Trip-Low fluid oil pressure is diverse to the Turbine Trip-Turbine Stop Valve

• Closure Function.

The LCO requires three channels of Turbine Trip-Low Fluid Oil Pressure to be OPERABLE in MODE 1 above P-8.

Below the P-8 setpoint, a turbine trip does not actuate a reactor trip. In MODE 2, 3, 4, 5, or 6, there is no potential for a turbine trip, and the Turbine Trip-Low Fluid Oil Pressure trip Function does not need to be OPERABLE.

b. Turbine Trip-Turbine Stop Valve Closure The Turbine Trip-Turbine Stop Valve Closure trip Function anticipates the loss of heat removal capabilities of the secondary system following a turbine trip from a power level above the P-8 setpoint, approximately 48% power. The trip Function anticipates the loss of secondary heat removal capability that occurs when the stop valves close. Tripping the reactor in anticipation of loss of secondary heat removal acts to minimize the pressure and temperature transient on the reactor. This trip Function will not and is not required to operate in the presence of a single channel failure. The unit is designed to withstand a complete loss of load and not McGuire Units 1 and 2 B 3.3.1-24 Revision No. 108

RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) sustain core damage or challenge the RCS pressure limitations. Core protection is provided by the Pressurizer Pressure-High trip Function, and RCS integrity is ensured by the pressurizer safety valves. This trip Function is diverse to the Turbine Trip-Low Fluid Oil Pressure trip Function.

Each turbine stop valve is equipped with one limit switch that inputs to the RTS. If all four limit switches indicate that the stop valves are closed, a reactor trip is initiated.

The LSSS for this Function is set to assure channel trip occurs when the associated stop valve is completely closed.

The LCO requires four Turbine Trip-Turbine Stop Valve Closure channels, one per valve, to be OPERABLE in MODE 1 above P-8. All four channels must trip to cause reactor trip.

Below the P-8 setpoint, a load rejection can be accommodated by the Steam Dump System. In MODE 2, 3, 4, 5, or 6, there is no potential for a load rejection, and the Turbine Trip-Stop Valve Closure trip Function does not

• need to be OPERABLE.

15. Safety Injection Input from Engineered Safety Feature Actuation System The Sl Input from ESFAS ensures that if a reactor trip has not already been generated by the RTS, the ESFAS automatic actuation logic will initiate a reactor trip upon any signal that initiates SI. This is a condition of acceptability for the LOCA.

However, other transients and accidents take credit for varying levels of ESF performance and rely upon rod insertion, except for the most reactive rod that is assumed to be fully withdrawn, to ensure reactor shutdown. Therefore, a reactor trip is initiated every time an SI signal is present.

Trip Setpoint and Allowable Values are not applicable to this Function. The SI Input is provided by a manual switch or by the automatic actuation logic. Therefore, there is no measurement signal with which to associate an LSSS.

The LCO requires two trains of SI Input from ESFAS to be OPERABLE in MODE 1 or 2.

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RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

A reactor trip is initiated every time an SI signal is present.

Therefore, this trip Function must be OPERABLE in MODE 1 or 2, when the reactor is critical, and must be shut down in the event of an accident. In MODE 3, 4, 5, or 6, the reactor is not critical, and this trip Function does not need to be OPERABLE.

16. Reactor Trip System Interlocks Reactor protection interlocks are provided to ensure reactor trips are in the correct configuration for the current unit status. They back up operator actions to ensure protection system Functions are not bypassed during unit conditions under which the safety analysis assumes the Functions are not bypassed. Therefore, the interlock Functions do not need to be OPERABLE when the associated reactor trip functions are outside the applicable MODES. These are:

al. Intermediate Range Neutron Flux, P-6 (Westinghouse-supplied Instrumentation)

The Westinghouse-supplied Intermediate Range excore detector systems (utilizing compensated ion chamber detectors) are being replaced with Thermo Scientific-supplied 300i neutron flux monitoring systems (utilizing fission chamber detectors). This section of the Bases applies to the,,

Westinghouse-supplied instrumentation. The next section of the Bases applies to the Thermo Scientific-supplied instrumentation.

The Intermediate Range Neutron Flux, P-6 interlock is actuated when any NIS intermediate range channel goes approximately one decade above the minimum channel reading. If both channels drop below the. setpoint, the permissive will automatically be defeated. The LCO requirement for the P-6 interlock ensures that the following Functions are performed:

on increasing power, the P-6 interlock allows the manual block of the NIS Source Range, Neutron Flux reactor trip. This prevents a premature block of the source range trip and allows the operator to ensure that the intermediate range is OPERABLE prior to leaving the source range. When the source range trip is blocked, the high voltage to the detectors is also

• removed; and McGuire Units 1 and 2 B 3-3.1-26 Revision No. 108

RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) on decreasing power, the P-6 interlock automatically energizes the NIS source range detectors and enables the NIS Source Range Neutron Flux reactor trip.

The LCO requires two channels of Intermediate Range Neutron Flux, P-6 interlock to be OPERABLE in MODE 2 when below the P-6 interlock setpoint.

Above the P-6 interlock setpoint, the NIS Source Range Neutron Flux reactor trip will be blocked, and this Function will no longer be necessary.

In MODE 3, 4, 5, or 6, the P-6 interlock does not have to be OPERABLE because the NIS Source Range is providing core protection.

a2. Intermediate Range Neutron Flux, P-6 (Thermo Scientific-supplied Instrumentation)

The Westinghouse-supplied Intermediate Range excore detector systems (utilizing compensated ion chamber detectors) are being replaced with Thermo Scientific-supplied 300i neutron flux monitoring systems (utilizing fission chamber detectors). This section of the Bases applies to the Thermo Scientific-supplied instrumentation. The previous section of the Bases applies to the Westinghouse-supplied instrumentation.

The Intermediate Range Neutron Flux, P-6 interlock is actuated when any NIS intermediate range channel goes approximately three decades above the minimum channel reading. If both channels drop below the setpoint, the permissive will automatically be defeated. The LCO requirement for the P-6 interlock ensures that the following Functions are performed:

McGuire Units 1 and 2 B 3.3.1-27 Revision No. 108

RTS Instrumentation B 3.3.1

. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

• on increasing power, the P-6 interlock allows the manual block of the NIS Source Range, Neutron Flux reactor trip.

This prevents a premature block of the source range trip and allows the operator to ensure that the intermediate range is OPERABLE prior to leaving the source range; and

• on decreasing power, the P-6 interlock automatically enables the NIS Source Range Neutron Flux reactor trip.

The LCO requires two channels of Intermediate Range Neutron Flux, P-6 interlock to be OPERABLE in MODE 2 when below the P-6 interlock setpoint.

Above the P-6 interlock setpoint, the NIS Source Range Neutron Flux reactor trip will be blocked, and this Function will no longer be necessary.

In MODE 3, 4, 5, or 6, the P-6 interlock does not have to be OPERABLE because the NIS Source Range is providing core protection.

b. Low Power Reactor Trips Block, P-7 The Low Power Reactor Trips Block, P-7 interlock is actuated by input from either the Power Range Neutron Flux, P-i 0, or the Turbine Impulse Pressure, P-13 interlock. The LCO requirement for the P-7 interlock ensures that the following Functions are performed:

(1) on increasing power, the P-7 interlock automatically enables reactor trips on the following Functions:

Pressurizer Pressure-Low; Pressurizer Water Level-High; Reactor Coolant Flow-Low (Two Loops);

• Undervoltage RCPs; and

-Underfrequency RCPs.

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RTS Instrumentation B 3.3.1 BASES

. APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

These reactor trips are only required when operating above the P-7 setpoint (approximately 10% power).

The reactor trips provide protection against violating the DNBR limit. Below the P-7 setpoint, the RCS is capable of providing sufficient natural circulation without any RCP running.

(2) on decreasing power, the P-7 interlock automatically blocks reactor trips on the following Functions:

• Pressurizer Pressure-Low;

• Pressurizer Water Level-High; a Reactor Coolant Flow-Low (Two Loops);

0 Undervoltage RCPs; and Underfrequency RCPs.

Trip Setpoint and Allowable Value are not applicable to the P-7 interlock because it is a logic Function and thus has no parameter with which to associate an LSSS.

The P-7 interlock is a logic Function with train and not channel identity. Therefore, the LCO requires one channel per train of Low Power Reactor Trips Block, P-7 interlock to be OPERABLE in MODE 1.

The low power trips are blocked below the P-7 setpoint and unblocked above the P-7 setpoint. In MODE 2, 3, 4, 5, or 6, this Function does not have to be OPERABLE because the interlock performs its Function when power level drops below 10% power, which is in MODE 1.

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RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

c. Power Rangqe Neutron Flux, P-8 The Power Range Neutron Flux, P-8 interlock is actuated at approximately 48% power as determined by two-out-of-four NIS power range detectors. The P-8 interlock automatically enables the Reactor Coolant Flow-Low (Single Loop) reactor trip on low flow in one or more RCS, loops, and the Turbine Trip-Low Fluid Oil Pressure and Turbine Trip-Turbine Stop Valve Closure reactor trips on increasing power. The LCO requirement for the Reactor Coolant Flow - Low Function ensures that protection is provided against a loss of flow in any RCS loop.that could result in DNB conditions in the core when greater than approximately 48% power.

Above the P-8 setpoint, a turbine .trip will cause a load rejection beyond the capacity of the Steam Dump System. A reactor trip is automatically initiated on a turbine trip when it is above the P-8 setpoint, to minimize the transient on the reactor. On decreasing power below the P-8 setpoint, the reactor trip on low flow in any loop is automatically blocked.

The LCO requires four channels of Power Range Neutron Flux, P-8 interlock to be OPERABLE in MODE 1.

In MODE 1, a loss of flow in one RCS loop could result in DNB conditions and, a turbine trip could cause a load rejection beyond the capacity of the Steam Dump System, so the Power Range Neutron Flux, P-8 interlock must be OPERABLE. In MODE 2, 3, 4, 5, or 6, this Function does not have to be OPERABLE because the core is not producing sufficient power to be concerned about DNB conditions and the reactor is not.at a power level sufficient to have a load rejection beyond the capacity of the Steam Dump System.

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RTS Instrumentation B 3.3.1

. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

d. Power Range Neutron Flux, P-10 The Power Range Neutron Flux, P-10 interlock is actuated at approximately 10% power, as determined by two-out-of-four NIS power range detectors. If power level falls below 10% RTP on 3 of 4 channels, the nuclear instrument trips will be automatically unblocked. The LCO requirement for the P-10 interlock ensures that the following Functions are.

performed:

" on increasing power, the P-1 0 interlock allows the operator to manually block the Intermediate Range Neutron Flux reactor trip. Note that blocking the reactor trip also blocks the signal to prevent automatic and manual rod withdrawal;

" on increasing power, the P-10 interlock allows the operator to manually block the Power Range Neutron Flux-Low reactor trip;

• on increasing power, the P-10 interlock automatically provides a backup signal to block the Source Range Neutron Flux reactor trip, and also to de-energize the NIS Westinghouse-supplied source range detectors (the Westinghouse-supplied source range detectors are being replaced with Thermo Scientific-supplied detectors that remain energized);

" the P-1 0 interlock provides one of the two inputs to the P-7 interlock; and

" on decreasing power, the P-10 interlock automatically enables the Power Range Neutron Flux-Low reactor trip and the Intermediate Range Neutron Flux reactor trip (and rod stop).

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RTS Instrumentation B 3.3.1 BASES

. APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

The LCO requires four channels of Power Range Neutron Flux, P-10 interlock to be OPERABLE in MODE 1 or 2.

OPERABILITY in MODE 1 ensures the Function is available to perform its decreasing power Functions in the event of a reactor shutdown. This Function must be OPERABLE in MODE 2 to ensure that core protection is provided during a startup or shutdown by the Power Range Neutron Flox-Low and Intermediate Range Neutron Flux reactor trips. In MODE 3, 4, 5, or 6, this Function does not have to be OPERABLE because the reactor is not at power and the Source Range Neutron Flux reactor trip provides core protection.

e. Turbine Impulse Pressure, P-13 The Turbine Impulse Pressure, P-13 interlock is actuated when the pressure in the first stage of the high pressure turbine is greater than approximately 10% of the rated full power pressure. This is determined by one-out-of-two pressure detectors. The LCO requirement for this Function ensures that one of the inputs to the P-7 interlock is available.

The LCO requires two channels of Turbine Impulse Pressure, P-13 interlock to be OPERABLE in MODE 1.

The Turbine Impulse Chamber Pressure, P-13 interlock must be OPERABLE when the turbine generator is operating. The interlock Function is not required OPERABLE in MODE 2, 3, 4, 5, or 6 because the turbine generator is not operating.

17. Reactor Trip Breakers This trip Function applies to the RTBs exclusive of individual trip mechanisms. The LCO requires two OPERABLE trains of trip breakers. A trip breaker train consists of all trip breakers associated with a single RTS logic train that are racked in, closed, and capable of supplying power to the CRD System. Thus, the McGuire Units 1 and 2 B 3.3.1-32 Revision No. 108

RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) train may consist of the main breaker, bypass breaker, or main breaker and bypass breaker, depending upon the system configuration. Two OPERABLE trains ensure no single random failure can disable the RTS trip capability.

These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs or associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.

18. Reactor Trip Breaker Undervoltage and Shunt Trip Mechanisms The LCO requires both the Unde-voltage and Shunt Trip Mechanisms to be OPERABLE for each RTB that is in service. The trip mechanisms are not required to be OPERABLE for trip breakers that are open, racked out, incapable of supplying power to the.CRD System,.or declared inoperable under Function 17 above.

OPERABILITY of both trip mechanisms on each breaker ensures that no single trip mechanism failure will prevent opening any breaker on a valid signal.

These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs or associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.

19. Automatic Trip Logic The LCO requirement for the RTBs' (Functions 17 and 18) and Automatic Trip Logic (Function 19) ensures that means are provided to interrupt the power to allow the rods to fall into the reactor core. Each RTB is equipped with an undervoltage coil and a shunt trip coil to trip the breaker open when needed. Each train RTB has a bypass breaker to allow testing of the trip breaker while the unit is at power. The reactor trip signals generated by the RTS Automatic Trip Logic cause the RTBs and associated bypass breakers to open and shut down the reactor.

The LCO requires two trains of RTS Automatic Trip Logic to be OPERABLE. Having two OPERABLE channels ensures that random failure of a single logic channel will not prevent reactor trip.

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RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs and associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.

The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).

ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1. When the Required Channels in Table 3.3.1-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.

A channel shall be OPERABLE if the point at which the channel trips is found equal to or more conservative than the Allowable Value. In the event a channel's trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected. Unless otherwise specified, if plant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINTS. If the trip setpoint is found outside the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.

When the number of inoperable channels in a trip Function exceed those specified in one or other related Conditions associated with a trip Function, then the unit is outside the safety analysis. Therefore, LCO 3.0.3 must be immediately entered if applicable in the current MODE of operation.

A.1 Condition A applies to all RTS protection Functions. Condition A addresses the situation where one or more required channels for one or more Functions are inoperable at the same time. The Required Action is to refer to Table 3.3.1-1 and to take the Required Actions for the protection functions affected. The Completion Times are those from the

• referenced Conditions and Required Actions.

McGuire Units 1 and 2 B 3.3.1-34 Revision No. 108

RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)

B1 and B.2 Condition B applies to the Manual Reactor Trip in MODE 1 or 2. This action addresses the train orientation of the SSPS for this Function. With one channel inoperable, the inoperable channel must be restored to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. In this Condition, the remaining OPERABLE channel is adequate to perform the safety function.

The Completion Time of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is reasonable considering that there are two automatic actuation trains and another manual initiation channel OPERABLE, and the low probability of an event occurring during this interval..

If the Manual Reactor Trip Function cannot be restored to OPERABLE status within the allowed 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> Completion Time, the unit must be brought to a MODE in which the requirement does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 additional hours (54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> total time). The 6 additional hours are reasonable, based on operating experience, to reach MODE 3 from full power operation in an orderly manner and without challenging unit systems. With the unit in MODE 3, the MODES 1 and 2 requirements for this trip Function are no longer required and Condition C is entered.

C.1 and C.2 Condition C applies to the following reactor trip Functions in MODE. 3, 4, or 5 with the RTBs closed and the CRD System capable of rod withdrawal:

• Manual Reactor Trip;

• RTBs;

• RTB Undervoltage and Shunt Trip Mechanisms; and

• Automatic Trip Logic.

This action addresses the train orientation of the SSPS for these Functions. With one Channel or train inoperable, the inoperable channel or train must be restored to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. If the affected Function(s) cannot be restored to OPERABLE status within the allowed 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> Completion Time, the unit must be placed in a condition in which the requirement does not apply. To achieve this status, the RTBs must be opened within the next hour. The additional hour provides McGuire Units 1 and 2 B 3.3.1-35 Revision No. 108

RTS Instrumentation B 3.3.1

. BASES ACTIONS (continued) sufficient time to accomplish the action in an orderly manner. With the RTBs open, these Functions are no longer required.

The Completion time is reasonable considering that in this Condition, the remaining OPERABLE train is adequate to perform the safety function,

.and given the low probability of an event occurring during this interval..

D.1.1, D.1.2, and D.2 Condition D applies to the Power Range Neutron Flux-High and Power Range Neutron Flux-High Positive Rate Functions.

The NIS power range detectors provide input to the CRD System and the SG Water Level Control System and, therefore, have a two-out-of-four trip logic. A known inoperable channel must be placed in the tripped condition. This results in a partial trip condition requiring only one-out-of-three logic for actuation. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to place the inoperable channel in the tripped condition is justified in WCAP-14333-P-A (Ref. 10).

With one of the NIS power range detectors inoperable, 1/4 of the radial power distribution monitoring capability is lost. Therefore, SR 3.2.4.2 must be performed (Required Action D.1.1) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of THERMAL POWER exceeding 75% RTP and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.

Calculating QPTR every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> compensates for the lost monitoring capability due to the inoperable NIS power range channel and allows continued unit operation at power levels > 75% RTP. At power levels <

75% RTP, operation of the core with radial power distributions beyond the design limits, at a power level where DNB conditions may exist, is prevented. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is consistent with the surveillance Requirement Frequency in LCO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR)." Required Action D.1.1 has been modified by a Note which only requires SR 3.2.4.2 to be performed if the Power Range Neutron Flux input to QPTR becomes inoperable. Failure of a component in the Power Range Neutron Flux Channel which renders the High Flux Trip Function inoperable may not affect the capability to monitor QPTR. As such, determining QPTR using movable incore detectors may not be necessary.

As an alternative to the above Actions, the plant must be placed in a MODE where this Function is no longer required OPERABLE. Seventy eight (78) hours are allowed to place the plant in MODE 3. The 78 hour9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> completion time includes 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for channel corrective maintenance and an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for the MODE reduction as required by Required Action D.2. This is a reasonable time, based on operating experience, to reach MODE 3 from full power in an orderly manner and McGuire Units 1 and 2 B 3.3.1-36 Revision No. 108

RTS Instrumentation B 3.3.1 BASES ACTIONS (continued) without challenging plant systems. If Required Actions cannot be completed within their allowed Completion Times, LCO 3.0.3 must be entered.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypass condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance testing of other channels. The Note also allows placing the inoperable channel in the bypass condition to allow setpoint adjustments of other channels when required to reduce the setpoint in accordance with other Technical Specifications. The note also

.allows an OPERABLE channel to be placed in bypass without entering the Required Actions for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for testing of the bypassed channel. However, only one channel may be placed in bypass at any one time. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 10.

E.1 and E.2 Condition E applies to the following reactor trip Functions:

Power Range Neutron Flux-Low; Overtemperature AT; Overpower AT; Pressurizer Pressure-High; and

• SG Water Level-Low Low.

A known inoperable channel must be placed in the tripped condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Placing the channel in the tripped condition results in a partial trip condition requiring only one-out-of-three logic for actuation of the two-out-of-four trips. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to place the inoperable channel in the tripped condition is justified in Reference 10.

If the operable channel cannot be placed in the trip condition within the specified Completion Time, the unit must be placed in a MODE where these Functions are not required OPERABLE. An additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is allowed to place the unit in MODE 3. Six hours is a reasonable time, based on operating experience, to place the unit in MODE 3 from full power in an orderly manner and without challenging unit systems.

McGuire Units 1 and 2 B 3.3.1-37 Revision No. 108

RTS Instrumentation B 3.3.1 BASES O ACTIONS (continued)

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance testing of the other channels. The note also allows an OPERABLE channel to be placed in bypass without entering the Required Actions for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for testing of the bypassed channel.

However, only one channel may be placed in bypass at any one time. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 10.

F.1 and F.2' Condition F applies to the Intermediate Range Neutron Flux trip when THERMAL POWER is above the P-6 setpoint and below the P-10 setpoint and one channel is inoperable. Above the P-6 setpoint and below the P-10 setpoint, the NIS intermediate range detector performs the monitoring Functions. If THERMAL POWER is greater than the P-6 setpoint but less than the P-10 setpoint, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed to reduce THERMAL POWER below the P-6 setpoint or increase to THERMAL POWER above the. P-10 setpoint. The NIS Intermediate Range Neutron Flux channels must be OPERABLE when the power level is above the capability of the source range, P-6, and below the capabilityof the power range, P-1 0. If THERMAL POWER is greater than the P-10 setpoint, the NIS power range detectors perform the monitoring and protection functions and the intermediate range is not required. The Completion Times allow for a slow and controlled power adjustment above P-10 or below P-6 and take into account the redundant capability afforded by the redundant OPERABLE channel, and the low probability of its failure during this period. This action does not require the inoperable channel to be tripped because the Function uses one-out-of-two logic. Tripping one channel would trip the reactor.

Thus, the Required Actions specified in this Condition are only applicable when channel failure does not result in reactor trip.

G. 1 and G.2 Condition G applies to two inoperable Intermediate Range Neutron Flux trip channels in MODE 2 when THERMAL POWER is above the P-6 setpoint and below the P-10 setpoint. Required Actions specified in this Condition are only applicable when channel failures do not result in reactor trip.

Above the P-6 setpoint and below the P-10 setpoint, the NIS intermediate range detector performs the monitoring Functions. With no intermediate range channels OPERABLE, the Required Actions are to suspend operations involving positive reactivity additions immediately. This will preclude any power level increase since there are no McGuire Units 1 and 2 B 3.3.1-38 Revision No. 108

• RTS Instrumentation B 3.3.1

. BASES ACTIONS (continued)

OPERABLE Intermediate Range Neutron Flux channels. The operator must also reduce THERMAL POWER below the P-6 setpoint within two hours. Below P-6, the Source Range Neutron Flux channels will be able to monitor the core power level. The Completion Time of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> will allow a slow and controlled power reduction to less than the P-6 setpoint and takes into account the low probability of occurrence of an event during this period that may require the protection afforded by the NIS Intermediate Range Neutron Flux trip. Required Action G.1 is modified by a note to indicate that normal plant control operations that individually add limited positive reactivity (e.g., temperature or boron fluctuations associated with RCS inventory management or temperature control) are not precluded by this Action.

H.1 Condition H applies to the Intermediate Range Neutron Flux trip when THERMAL POWER is below the P-6 setpoint and one or two channels are inoperable. Below the P-6 setpoint, the NIS source range performs the monitoring and protection.functions. The inoperable NIS intermediate range channel(s) must be returned to OPERABLE status prior to increasing power above the P-6 setpoint. The NIS intermediate range channels must be OPERABLE when the power level is above the capability of the source range, P-6, and below the capability of the power range, P-10.

1.1 Condition I applies to one inoperable Source Range Neutron Flux trip channel when in MODE 2, below the P-6 setpoint, and performing a reactor startup. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With one of the two channels inoperable, operations involving positive reactivity additions shall be suspended immediately.

This will preclude any power escalation. With only one source range channel OPERABLE, core protection is severely reduced and any actions that add positive reactivity to the core must be suspended immediately.

Required Action 1.1 is modified by a note to indicate that normal plant control operations that individually add limited positive reactivity (e.g.,

temperature or boron fluctuations associated with RCS inventory management or temperature control) are not precluded by this Action.

McGuire Units 1 and.2 B 3.3-1-39 Revision No. 108

RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)

J.1 Condition J applies to two inoperable Source Range Neutron Flux trip channels when in MODE 2, below the P-6 setpoint, and performing a reactor startup, or in MODE 3, 4, or 5 with the RTBs closed and the CRD System capable of rod withdrawal. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With both source range channels inoperable, the RTBs must be opened immediately. With the RTBs open, the core is in a more stable condition and the unit enters Condition L.

K.1 and K.2 Condition K applies to one inoperable source range channel in MODE 3, 4, or 5 with the RTBs closed and the CRD System capable of rod withdrawal. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With one of the source range channels inoperable, 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is allowed to restore it to an OPERABLE status. If the channel cannot be returned to an OPERABLE status, 1 additional hour is allowed to open the RTBs. Once the RTBs are open, the core is in a more stable condition and the unit enters Condition L. The allowance of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to restore the channel to OPERABLE status, and the additional hour to open the RTBs, are justified in Reference 7.

L.1, L.2, and L.3 Condition L applies when the required number of OPERABLE Source Range Neutron Flux channels is not met in MODE 3, 4, or 5 with the RTBs open. With the unit in this Condition, the NIS source range performs a monitoring function. With less than the required number of source range channels OPERABLE, operations involving positive reactivity additions shall be suspended immediately. In addition to suspension of positive reactivity additions, all valves that could add unborated water to the RCS must be closed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as specified in LCO 3.9.2. The isolation of unborated water sources will preclude a boron dilution accident.

Also, the SDM must be verified within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter as per SR 3.1.1.1, SDM verification. With no source range channels OPERABLE, core monitoring is severely reduced. Verifying the SDM within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> allows sufficient time to perform the calculations and determine that the SDM requirements are met. The SDM must also be verified once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter to ensure that the core reactivity has not changed. Required Action L.1 precludes any positive reactivity McGuire Units 1 and 2 B 3.3.1-40 Revision No. 108

RTS Instrumentation B 3.3.1

. BASES ACTIONS (continued) additions; therefore, core reactivity should not be increasing, and a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is adequate. The Completion Times of within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> are based on operating experience in performing the Required Actions and the knowledge that unit conditions will change slowly. Required Action L.1 is modified by a note which permits plant temperature changes provided the temperature change is accounted for in the calculated SDM and that Keff remains < 0.99. Introduction of temperature changes including temperature increases when a positive MTC exists, must be evaluated to ensure they do not result in a loss of required SDM or adequate margin to criticality.

M.1 and M.2 Condition M applies to the following reactor trip Functions:

• Pressurizer Pressure-Low;

• Pressurizer Water Level-High; 0 Reactor Coolant Flow-Low (Two Loops);

• Undervoltage RCPs; and

• Underfrequency RCPs.

With one channel inoperable, the inoperable channel must be placed in the tripped condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Placing the channel in the tripped condition results in a partial trip condition requiring only one additional channel to initiate a reactor trip above the P-7 setpoint (and below the P-8 setpoint for the Reactor Coolant Flow-Low (Two Loops) Function). These Functions do not have to be OPERABLE below the P-7 setpoint because, for the Pressurizer Water Level-High function, transients are slow enough for manual action; and for the other functions, power distributions that would cause a DNB concern at this low power level are unlikely. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to place the channel in the tripped condition is justified in Reference 10. An additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is allowed to reduce THERMAL POWER to below P-7 if the inoperable channel cannot be restored to OPERABLE status or placed in trip within the specified Completion Time.

Allowance of this time interval takes into consideration the redundant capability provided by the remaining redundant OPERABLE channel, and the low probability of occurrence of an event during this period.that may require the protection afforded by the Functions associated with

___ Condition M.

McGuire Units 1 and 2 B 3.3.1-41 .Revision No. 108

RTS Instrumentation B 3.3.1 BASES

. ACTIONS (continued)

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance testing of the other. channels.' The note also allows an OPERABLE channel to be placed in bypass without entering the Required Actions for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for testing of the bypassed channel. However, only one channel may be placed in bypass at any one time. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 10.

N.1 and N.2 Condition N applies to the Reactor Coolant Flow-Low (Single Loop) reactor trip Function. With one channel inoperable, the inoperable channel must be placed in trip within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. If the channel cannot be restored to OPERABLE status or the channel placed in trip within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, then THERMAL POWER must be reduced below the P-8 setpoint within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This places the unit in a MODE where the LCO is no longer applicable. This trip Function does not have to be OPERABLE below the P-8 setpoint because other RTS trip Functions provide core protection below the P-8 setpoint. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to restore the channel to OPERABLE status or place in trip and the 4 additional hours allowed to reduce THERMAL POWER to below the P-8 setpoint are justified in Reference 10.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance'testing of the other channels. The note also allows an OPERABLE channel to be placed in bypass without entering the Required Actions for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for testing of the bypassed channel. However, only one channel may be placed in bypass at any one time. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 10.

0.1, 0.2, P.1, and P.2 Condition 0 and P apply to Turbine Trip on Low Fluid Oil Pressure or on Turbine Stop Valve Closure. With a channel inoperable, the inoperable channel must be placed in the trip condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. If placed in the tripped condition, this results in a partial trip condition requiring fewer additional channel to initiate a reactor trip. If the channel cannot be restored to OPERABLE status or placed in the trip condition, then power must be reduced below the P-8 setpoint within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to place the inoperable channel in the tripped condition and the 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> allowed for reducing power are justified in Reference 10.

McGuire Units 1 and 2 B 3.3.1-42 Revision No. 108

RTS Instrumentation B 3-3.1

. BASES ACTIONS (continued)

The Required Actions of Condition 0 have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance testing of the other channels. The note also allows an OPERABLE channel to be placed in bypass without entering the Required Actions for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for testing of the bypassed channel. However, only one channel may be placed in bypass at any one time. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 10.

Q.1 and Q.2 Condition Q applies to the SI Input from ESFAS reactor trip and the RTS Automatic Trip Logic in MODES 1 and 2. These actions address the train orientation of the RTS for these Functions. With one train inoperable, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> are allowed to restore the train to OPERABLE status (Required Action Q.1) or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (Required Action Q. 1) is reasonable considering that in this Condition, the remaining OPERABLE train is adequate to perform the safety function and given the low probability of an event during this interval. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed to restore the inoperable RTS Automatic Trip Logic train to OPERABLE status is justified in Reference 10. The additional Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (Required Action Q.2) is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems.

The Required Actions have been modified by a Note that allows bypassing one train up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing, provided the other train is OPERABLE. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit for testing the RTS Automatic Trip Logic train may include testing the RTB also, if both the Logic test and RTB test are conducted within the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit is justified in Reference 10.

R.1 and R.2 Condition R applies to the RTBs in MODES 1 and 2. These actions address the train orientation of the RTS for the RTBs. With one train inoperable, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed for train corrective maintenance to restore the train to OPERABLE status or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is justified in Reference 11. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems. Placing the unit in MODE 3 removes the requirement for this particular Function.

McGuire Units 1 and 2 B 3.3.1-43 Revision No. 108

RTS Instrumentation B 3.3.1

. BASES ACTIONS (continued)

The Required Actions have been modified by a Note. The Note allows one RTB to be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing, provided the other RTB is OPERABLE. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit is justified in Reference 11.

S.1 and S.2 Condition S applies to the P-6 and P-10 interlocks. With one or more channel(s) inoperable for one-out-of-two or two-out-of-four coincidence logic, the associated interlock must be verified to be in its required state for the existing unit condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Verifying the interlock status, by visual observation of the control room status lights, manually accomplishes the interlock's Function. The Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is based on operating experience and the minimum amount of time allowed for manual operator actions. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Times are equal to the time allowed by LCO 3.0.3 for shutdown actions in the event of a complete loss of RTS Function.

T.1 and T.2 Condition T applies to the P-7, P-8, and P-13 interlocks. With one or more channel(s) inoperable for one-out-of-two or two-out-of-four coincidence logic, the associated interlock must be verified to be in its required state for the existing unit condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or the unit must be placed in MODE 2 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. These actions are conservative for the case where power level is being raised. Verifying the interlock status, by visual observation of the control room status lights, manually accomplishes the interlock's Function. The Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is based on operating experience and the minimum amount of time allowed for manual operator actions. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 2 from full power in an orderly manner and without challenging unit systems.

McGuire Units 1 and 2 B 3.3.1-44 Revision No. 108

RTS Instrumentation B 3.3.1

. BASES ACTIONS (continued)

U.1 and U.2 Condition U applies to the RTB Undervoltage and Shunt Trip Mechanisms, or diverse trip features, in MODES 1 and 2. With one of the diverse trip features inoperable, it must be restored to an OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or the unit must be placed in a MODE where the requirement does not apply. This is accomplished by placing the unit in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> total time). With both diverse trip features inoperable, the reactor trip breaker is inoperable and Condition R is entered. The Completion Time of,6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is a reasonable time, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems.

With the unit in MODE 3, the MODES 1 and 2 requirement for this function is no longer required and Condition C is entered. The affected RTB shall not be bypassed while one of the diverse features is inoperable except for the time required to perform maintenance to one of the diverse features. The allowable time for performing maintenance of the diverse features is 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for the reasons stated under Condition R.

The Completion Time of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> for Required Action U.1 is reasonable considering that in this Condition there is one remaining diverse feature for the affected RTB, and one OPERABLE RTB capable of performing the safety function and given the low probability of an event occurring during this interval.

V.1 With two RTS trains inoperable, no automatic capability is available to shut down the reactor, and immediate plant shutdown in accordance with LCO 3.0.3 is required.

SURVEILLANCE The SRs for each RTS Function are identified by the SRs column of REQUIREMENTS Table 3.3.1-1 for that Function.

A Note has been added to the SR Table stating that Table 3.3.1-1 determines which SRs apply to which RTS Functions.

Note that each channel of process protection supplies both trains of the RTS. When testing Channel I, Train A and Train B must be examined.

Similarly, Train A and Train B must be examined when testing Channel II, McGuire Units 1 and 2 B 3.3.1 -4 5 Revision No. 108

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)

Channel III, and Channel IV (if applicable). The CHANNEL CALIBRATION and COTs are performed in a manner that is consistent with the assumptions used in analytically calculating the required channel accuracies.

Performing the Neutron Flux Instrumentation surveillances meets the License Renewal Commitments for License Renewal Program for Neutron Flux Instrumentation Circuits per UFSAR Chapter 18, Table 18-1 and License Renewal Commitments Specification MCS-1274.00-00-0016, Section 4.44.

SR 3.3.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> ensures that gross failure of instrumentation has not occurred. A CHANNELCHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the unit staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the LCO required channels.

SR 3.3.1.2 SR 3.3.1.2 compares the calorimetric heat balance calculation to the NIS channel output every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If the calorimetric exceeds the NIS channel output by > 2% RTP, the NIS is not declared inoperable, but must be adjusted. If the NIS channel output cannot be properly adjusted, the channel is declared inoperable.

McGuire Units 1 and 2 B'3.3.1-46 Revision No. 108

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)

Two Notes modify SR 3.3.1.2. The first Note indicates that the NIS channel output shall be adjusted consistent with the calorimetric results if the absolute difference between the NIS channel output and the calorimetric is > 2% RTP. The second Note clarifies that this Surveillance is required only if reactor power is >_15% RTP and that 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is allowed for completing the first Surveillance after reaching 15% RTP. At lower power levels, calorimetric data are inaccurate.

The Frequency of every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is adequate. It is based on unit operating experience, considering instrument reliability and operating history data for instrument drift. Together these factors demonstrate the change in the absolute difference between NIS and heat balance calculated powers rarely exceeds 2% in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. Maintaining the 2% agreement is only applicable during equilibrium conditions.

In addition, control room operators periodically monitor redundant indications and alarms to detect deviations in channel outputs.

SR 3.3.1.3 SR 3.3.1.3 compares the incore system tothe NIS channel output every 31 EFPD. If the absolute difference in AFD is > 3%, the NIS channel is still OPERABLE, but must be readjusted.

If the NIS channel cannot be properly readjusted, the channel is declared inoperable. This Surveillance is performed to verify the f(AI) input to the overtemperature AT Function and overpower AT Function.

Two Notes modify SR 3.3.1.3. Note 1 indicates that the excore NIS channel shall be adjusted if the absolute difference between the incore and excore AFD is > 3%. Note 2 clarifies that the Surveillance is required only if reactor power is > 15% RTP and that 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed for completing the first Surveillance after reaching 15% RTP.

The Frequency of every 31 EFPD is adequate. It is based on unit operating experience, considering instrument reliability and operating history data for instrument drift. Also, the slow changes in neutron flux during the fuel cycle can be detected during this interval.

SR 3.3.1.4 SR 3.3.1.4 is the performance of a TADOT every 62 days on a STAGGERED TEST BASIS. This test shall verify OPERABILITY by aactuation of the end devices.

McGuire Units 1 and 2 B 3.3.1-47 Revision No. 108

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The RTB test shall include separate verification of the undervoltage and shunt trip mechanisms. Independent verification of RTB undervoltage and shunt trip Function is not required for the bypass breakers. No capability is provided for performing such a test at power. The independent test for bypass breakers is included in SR 3.3.1.14. The bypass breaker test shall include a local shunt trip. A Note has been added to indicate that this test must be performed on the bypass breaker prior to placing it in service.

The Frequency of every 62 days on a STAGGERED TEST BASIS is justified in Reference 11.

SR 3.3.1.5 SR 3.3.1.5 is the performance of an ACTUATION LOGIC TEST. The SSPS is tested every 92 days on a STAGGERED TEST BASIS, using the semiautomatic tester. The train being tested is placed in the bypass condition, thus preventing inadvertent actuation. Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 11.

SR 3.3.1.6 SR 3.3.1.6 is a calibration of the excore channels to the incore channels.

If the measurements do not agree, the excore channels are not declared inoperable but must be calibrated to agree with the incore detector measurements. If the excore channels cannot be adjusted, the channels are declared inoperable. This Surveillance is performed to verify the f(AI) input to the overtemperature AT Function and overpower AT Function.

At Beginning of Cycle (BOC), the excore channels are compared to the incore detector measurements. This comparison is typically performed prior to exceeding 75% power. Excore detectors are adjusted as necessary. This low power surveillance satisfies the initial performance of SR 3.3.1.6 with subsequent surveillances conducted at least every 92 EFPD.

At BOC, after reaching full power steady state conditions, additional incore and excore measurements are taken at various Al conditions to determine the M factors. The M factors are normally only determined at BOC, but they may be changed at other points in the fuel cycle if the McGuire Units 1 and 2 B 3.3.1-48 Revision No. 108

RTS Instrumentation RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) relationship between excore and incore measurements changes significantly.

A Note modifies SR 3.3.1.6. The Note states that this Surveillance is required only if reactor power is > 75% RTP and that 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed for completing the first surveillance after reaching 75% RTP.

The Frequency of 92 EFPD is adequate. It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift.

SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT every 184 days.

A COT is performed on each required channel to ensure the channel will perform the intended Function.

The tested portion of the Loop must trip within the Allowable Values specified in Table 3.3.1-1.

The setpoint shall be left set consistent with the assumptions of the setpoint methodology.

SR 3.3.1.7 is modified by a Note that provides a4 hour delay in the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the RTBs are open and SR 3.3.1.7 is no longer required to be performed. If the unit is to be in, MODE 3 with the RTBs closed for > 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> this Surveillance must be completed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after entry into MODE 3. The surveillance shall include verification of the high flux at shutdown alarm setpoint of less than or equal to the average CPS Neutron Level reading (most consistent value between highest and lowest CPS Neutron Level reading) at five times background.

The Frequency of 184 days is justified in Reference 11.

For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" (Reference 12) has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.

Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and McGuire Units 1 and 2 B 3.3.1-49 Revision No. 108

RTS Instrumentation RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. The performance of these channels will be evaluated under the station's Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition for continued OPERABILITY.

The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second NOTE applies.

SR 3.3.1.8 SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7, except it is modified by a Note that this test shall include verification that the P-6, during the Intermediate Range COT, and P-10, during the Power Range COT, interlocks are in their required state for the existing unit condition. The verification is performed by visual observation of the permissive status light in the unit control room. The Frequency is modified by a Note that allows this surveillance to be satisfied if it has been performed within 184 days of the Frequencies prior to reactor startup and four hours after reducing power below P-10 and P-6. The Frequency of "prior to startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels. The Frequency of "4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reducing power below P-10" (applicable to intermediate and power range low channels) and "4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reducing power below P-6" (applicable to source range channels) allows a normal shutdown to be completed and the unit removed from the MODE of Applicability for this surveillance without a delay to perform the testing required by this surveillance. The Frequency of every 184 days thereafter applies ifthe plant remains in the MODE of Applicability after the initial performances of prior to reactor startup and four hours after reducing power below P-10 or P-6. The MODE of Applicability for this surveillance is < P-1 0 for the power range low and intermediate range channels and < P-6 for the source range McGuire Units 1 and 2 B 3.3.1-50 Revision No. 108

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) channels. Once the unit is in MODE 3, this surveillance is no longer required. If power is to be maintained < P-10 or < P-6 for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for periods > 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The Frequency of 184 days is justified in Reference 11.

For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology forLSSS Functions" (Reference 12).has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.

Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. The performance of these channels will be evaluated under the station's Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition for continued OPERABILITY.

The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second NOTE applies.

SR 3.3.1.9 SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 7.

McGuire Units 1 and 2 B 3.3*.1-51 Revision No. 108

RTS Instrumentation RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The-SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION.

SR 3.3.1.10 A CHANNEL CALIBRATION is performed every 18 months. The CHANNEL CALIBRATION may be performed at power or during refueling based on testing capability. Channel unavailability evaluations in References 10 and 11 have conservatively assumed that the CHANNEL CALIBRAITON is performed at power with the channel in bypass.

CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology.

The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.

SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time-constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.1-1.

SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. Two notes modify this SR.

Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP. The high voltage detector saturation curve is evaluated and compared to the manufacturer's data. The Westinghouse-supplied boron-triflouride (BF 3 )

source range'neutron detectors and compensated ion chamber intermediate range neutron detectors are being replaced with Thermo Scientific-supplied fission chamber source and intermediate range neutron detectors. The CHANNEL CALIBRATION for the BF 3 source McGuire Units 1 and 2 B 3.3.1-52 Revision No. 108

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) range neutron detectors consists of two methods. Method 1 consists of obtaining the discriminator curves for source range, evaluating those curves, and comparing the curves to the manufacturer's data (adjustments to the discriminator voltage are performed as required).

Method 2 consists of performing waveform analysis. This analysis process monitors the actual number and amplitude of the Neutron/Gamma pulses being generated by the SR detector. The high voltage is adjusted to optimize the amplitude of the pulses while maintaining as low as possible high voltage value in order to prolong the detector life. The discriminator voltage is then adjusted, as required, to reasonably ensure that the neutron pulses are being counted by the source range instrumentation and the unwanted gamma pulses are not being counted as neutron pulses.

The CHANNEL CALIBRATION for the compensated ion chamber intermediate range neutron detectors consists of the high voltage detector plateau for intermediate range, evaluating those curves, and comparing the curves to the manufacturer's data. The CHANNEL CALIBRATION for the fission chamber source and intermediate range neutron detectors consists of verifying that the channels respond correctly to test inputs with the necessary range and accuracy.

Note 2 states that this Surveillance is not required for the NIS power range detectors for entry into MODE 2 or 1. Note 3 applies to the compensated ion chamber intermediate range neutron detectors, and states that this Surveillance is not required to be performed for entry into MODE 2 or 1. Notes 2 and 3 are required because the unit must.be in at least MODE 2 to perform the test for the compensated ion chamber intermediate range detectors and MODE 1 for the power range detectors.

The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed on the 18 month Frequency.

For Functions for which TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions" (Reference 12) has been implemented,

.this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.

Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The.

purpose of the assessment is to ensure confidence in the channel McGuire Units 1 and 2 B 3.3.1-53 Revision No. 108

RTS Instrumentation RTS Instrumentation B 3.3.1 BASES

- SURVEILLANCE REQUIREMENTS (continued) performance prior to returning the channel to service. The performance of these channels will be evaluated under the station's Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition for continued OPERABILITY.

The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the Nominal Trip Setpoint (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second NOTE applies.

SR 3.3.1.12 SR 3.3.1.12 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. Calibration of the AT channels is required at the beginning of each cycle upon completion of the precision heat balance. RCS loop AT values shall be determined by precision heat balance measurements at the beginning of each cycle.

The Frequency is justified by the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.1.13 SR 3.3.1.13 is the performance of a COT of RTS interlocks every 18 months.

The Frequency is based on the known reliability of the interlocks and the multichannel redundancy available, and has been shown to be acceptable. through operating experience.

SR 3.3.1.14 SR 3.3.1.14 is the performance of a TADOT of the Manual Reactor Trip and the Sl Input from ESFAS. This TADOT is performed every 18 months. The test shall independently verify the OPERABILITY of the McGuire Units 1 and 2 B 3.3.1-54 Revision No. 108

RTS Instrumentation B 3.3.1

. BASES SURVEILLANCE REQUIREMENTS (continued) undervoltage and shunt trip mechanisms for the Manual Reactor Trip Function for the Reactor Trip .Breakers and Reactor Trip Bypass Breakers. The Reactor Trip Bypass Breaker test shall include testing of the automatic undervoltage trip.

The Frequency is based on the known reliability of the Functions and the multichannel redundancy available, and has been shown to be acceptable through operating experience.

The SR is modified by a Note that excludes verification of setpoints from the TADOT. The Functions affected have no setpoints associated with them.

SR 3.3.1.15 SR 3.3.1.15 is the performance of a TADOT of Turbine Trip Functions.

This TADOT is as described in SR 3.3.1.4, except that this test is performed prior to reactor startup. A Note states that this Surveillance is not required if it has been performed within the previous 31 days.

Verification of the Trip Setpoint does not have to be performed for this Surveillance. Performance of this test will ensure that the turbine trip Function is OPERABLE prior to taking the reactor critical. This test cannot be performed with the reactor at power and must therefore be performed prior to reactor startup.

SR 3.3.1.16 and SR 3.3.1.17 SR 3.3.1.16 and SR 3.3.1.17 verify that the individual channel/train actuation response times are less than or equal to the maximum values assumed in the accident analysis. Response time testing acceptance criteria are included in the UFSAR (Ref. 1). Individual component response times are not modeled in the analyses.

The analyses model the overall or total elapsed time, from the point at which the parameter exceeds the trip setpoint value at the sensor to the point at which the equipment reaches the required functional state (i.e.,

control and shutdown rods fully inserted in the reactor core).

For channels that include dynamic transfer Functions (e.g., lag, lead/lag, rate/lag, etc.), the response time test may be performed with the transfer Function set to one, with the resulting measured response time compared to the appropriate UFSAR response time. Alternately, the response time test can be performed with the time constants set to their nominal value,

• provided the required response time is analytically calculated assuming McGuire Units 1 and 2 B 3.3.1-55 Revision No. 108

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) the time constants are set at their nominal values. The response time may be measured by a series of overlapping tests such that the entire response time is measured.

Response time may be verified by actual response time tests in any series of sequential, overlapping or total channel measurements, or by the summation of allocated sensor, signal processing and actuation logic response times with actual response time tests on the remainder of the channel. Allocations for sensor response times may be obtained from:

(1) historical records based on acceptable response time tests (hydraulic, noise, or power interrupt tests), (2) in place, onsite, or offsite (e.g.,

vendor) test measurements, or (3) utilizing vendor engineering specifications. WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" provides the basis and methodology for using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP. Response time verification for other sensor types must be either demonstrated by test, or their equivalency to those listed in WCAP-13632-P-A, Revision 2. Any demonstration of equivalency must have been determined to be acceptable by NRC staff review.

WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests' provides the basis and methodology for using allocated signal processing and actuation logic response times in the overall verification of the protection system channel response time.

The allocations for sensor, signal conditioning, and actuation logic response times must be verified prior to placing the component in operational service and re-verified following maintenance that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. Specific components identified in the WCAP may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter.

As appropriate, each channel's response must be verified every 18 months on a STAGGERED TEST BASIS. Testing of the final actuation devices is included in the testing. Testing of the RTS RTDs is performed on an 18 month frequency. Response times cannot be determined during unit operation because equipment operation is required to measure response times. Experience has shown that these components usually pass this surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

McGuire Units 1 and 2 B 3.3.1-56 Revision No. 108

RTS Instrumentation B 3.3.1

. BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.16 is modified by a Note stating that neutron detectors are excluded from RTS RESPONSE TIME testing. This Note is necessary because of the difficulty in generating an appropriate detector input signal. Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response. The response time of the neutron flux signal portion of the channel shall be measured from detector output or input of the first electronic component in the channel.

REFERENCES 1. UFSAR, Chapter 7.

2. UFSAR, Chapter 6.

3. UFSAR, Chapter 15.

4. IEEE-279-1971.

5. 10 CFR 50.49.

6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

7. WCAP-10271-P-A, Supplement 2, Rev. 1, June 1990.

8. WCAP 13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" Sep., 1995.

9. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" Oct., 1998.

10. WCAP-14333-P-A, Revision 1, October 1998.

11. WCAP-15376-P-A, Revision 1, March 2003.

12. Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions", Revision 4.

McGuire Units 1 and 2 B 3.3.1-57 Revision No. 108

Nuclear Instrumentation B 3.9.3 B 3.9 REFUELING OPERATIONS B 3.9.3 Nuclear Instrumentation BASES BACKGROUND The source range neutron flux monitors are used during refueling operations to monitor the core reactivity condition. The installed source range neutron flux monitors are part of the Nuclear Instrumentation System (NIS) while the Wide Range Neutron Flux Monitoring System (Gamma-Metrics) are not. Source range indication is provided via the NIS source range channels and the Gamma-Metrics shutdown monitors using detectors located external to the reactor vessel. These detectors monitor neutrons leaking from the core. Neutron flux indication for these monitors are provided in counts per second.

The Westinghouse-supplied boron triflouride (BF3 ) detectors used for the NIS Source Range Channels are being replaced with Thermo Scientific-supplied fission chamber detectors. The Westinghouse NIS Source Range Channels utilizing BF 3 detectors have a range of 1 to 1 E6 cps.

The repl~acement Thermo Scientific NIS Source Range Channels utilizing fission chamber detectors have a range of 0.1 to 1 E6 cps. The Wide Range (Gamma-Metrics) channels are fission chambers with a range of 0.1 to 1E5 cps (in the startup range). The NIS source range channels and the Gamma-Metrics shutdown monitors provide continuous visible count rate indication in the control room and a high flux control room alarm to alert operators to any unexpected positive reactivity additions.

Since TS 3.9.2 requires isolation of unborated water sources, the shutdown monitors (Gamma-Metrics) audible alarm, NIS source range audible indication and audible alarm are not required for OPERABILITY in Mode 6.

The NIS source range detectors and the Gamma-Metrics are designed in accordance with the criteria presented in Reference 1.

APPLICABLE Two OPERABLE source range neutron flux monitors (any combination of SAFETY ANALYSES the two NIS source range monitors and the two Gamma-Metrics wide range monitors) are required to provide an indication to alert the operator to unexpected changes in core reactivity such as with a boron dilution accident (Ref. 2) or an improperly loaded fuel assembly.

The source range neutron flux monitors satisfy Criterion 3 of 10 CFR 50.36 (Ref. 3).

McGuire Units 1 and 2 B 3.9.3-1 Revision No. 108

Nuclear Instrumentation B 3.9.3 BASES LCO This LCO requires that two source range neutron flux monitors be OPERABLE to ensure that redundant monitoring capability is available to detect changes in core reactivity. To be operable, each monitor must provide a visual indication in the Control Room. The visual indication can be, but not limited to, either a gauge, chart recorder, CRT, or some other recording device. The two required source range neutron flux monitors may consist of any combination of the two NIS source range monitors and the two Gamma-Metrics wide range shutdown monitors.

As required by LCO 3.9.2, "Unborated water source isolation valves", all isolation valves for reactor makeup water sources containing unborated water that are connected to the Reactor Coolant System (RCS) must be closed to prevent unplanned boron dilution of the reactor coolant during MODE 6 and thus avoid a reduction in shutdown margin. As such, the required source range monitors OPERABILITY includes only a visual monitoring function. A high flux alarm is not a required function for OPERABILITY.

APPLICABILITY In MODE 6, the source range neutron flux monitors must be OPERABLE to determine changes in core reactivity. There are no other direct means available to check core reactivity levels. In MODES 2, 3, 4, and 5, the NIS source range detectors and circuitry are also required to be OPERABLE by LCO 3.3.1, "Reactor Trip System (RTS) Instrumentation."

The Gamma-Metrics wide range shutdown monitors do not provide an automatic reactor trip protective function.

ACTIONS A.1 and A.2 With only one required source range neutron flux monitor OPERABLE, redundancy has been lost. Since these instruments are the only direct means of monitoring core reactivity conditions, CORE ALTERATIONS and introduction of coolant into the RCS with boron concentration less than required to meet the minimum boron concentration of LCO 3.9.1 must be suspended immediately. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation. Introduction of coolant inventory must be from sources that have a boron concentration greater than that which would be required in the RCS for minimum refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation. Performance of Required Action A.1 shall not preclude completion of movement of a component to a safe position.

McGuire Units 1 and 2 B 3.9.3-2 Revision 108

Nuclear Instrumentation B 3.9.3 BASES

. ACTIONS (continued)

B.1 With no required source range neutron flux monitor OPERABLE, action to restore a monitor to OPERABLE status shall be initiated immediately.

Once initiated, action shall be continued until a source range neutron flux monitor is restored to OPERABLE status.

B.2 With no required source range neutron flux monitor OPERABLE, there are no direct means of detecting changes in core reactivity. However, since CORE ALTERATIONS and positive reactivity additions are not to be made, the core reactivity condition is stabilized until the source range neutron flux monitors are OPERABLE. This stabilized condition is determined by performing SR 3.9.1.1 to ensure that the required boron concentration exists.

The Completion Time of once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient to obtain and analyze a reactor coolant sample for boron concentration and ensures that unplanned changes in boron concentration would be identified. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is reasonable, considering the low probability of a

• change in core reactivity during this time period.

SURVEILLANCE SR 3.9.3.1 REQUIREMENTS SR 3.9.3.1 is the performance of a CHANNEL CHECK, which is a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that the two indication channels should be consistent with core conditions. Changes in fuel loading and core geometry can result in significant differences between source range channels, but each channel should be consistent with its local conditions.

The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is consistent with the CHANNEL CHECK Frequency specified similarly for the same instruments in LCO 3.3.1.

SR 3.9.3.2 SR 3.9.3.2 is the performance*0Ra CHANNEL CALIBRATION every 18 months. The CHANNEL CALIBRATION ensures that the monitors are calibrated. This SR is modified by a Note stating that neutron detectors are excluded from the CHANNEL CALIBRATION. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage. Operating experience has shown these components usually pass the Surveillance when performed

___ at the 18 month Frequency.

McGuire Units 1 and 2 B 3.9.3-3 Revision 108

Nuclear Instrumentation B 3.9.3 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 13, GDC 26, GDC 28, and GDC 29.

2. UFSAR, Sections 4.2, 15.4.6.

3. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

McGuire Units 1 and 2 B 3.9.3-4 Revision 108

)F-6 I-,-

DUKE ENERGY CAROLINAS, LLC DOCKET NO. 50-369 MCGUIRE NUCLEAR STATION, UNIT 1 RENEWED FACILITY OPERATING LICENSE Renewed License No. NPF-9

1. The U.S. Nuclear Regulatory Commission (Commission), having previously made the findings set forth in License No. NPF-9 issued on June 12, 1981, has now found that:

A. The application for renewed operating license filed by the Duke Energy Corporation* complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I and all required notifications to other agencies or bodies have been duly made; B. Actions have been identified and have been or will be taken with respect to (1) managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21 (a)(1), and (2) time-limited aging analyses that have been identified to require review under 10 CFR 54.21 (c), such that there is reasonable assurance that the activities authorized by the renewed operating license will continue to be conducted in accordance with the current licensing basis, as defined in 10 CFR 54.3, for the McGuire Nuclear Station, Unit 1 (facility or plant), and that any changes made to the plant's current licensing basis in order to comply with 10 CFR 54.29(a) are in accord with the Act and the Commission's regulations; C. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the regulations of the Commission; D. There is reasonable assurance: (i) that the activities authorized by this renewed operating license can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; E. The licensee is technically and financially qualified to engage in the activities authorized by this renewed operating license in accordance with the Commission's regulations set forth in 10 CFR Chapterl; Duke Energy Corporation converted to Duke Power Company LLC on April 3, 2006 and was re-named Duke Energy Carolinas, LLC as of October 1, 2006. Duke Energy Carolinas, LLC is the owner and operator of McGuire Nuclear Station, Unit 1. References to the "licensee" or "Duke" are to Duke Energy Carolinas, LLC.

Renewed License No. NPF-9 Amendment No. 245

F. The licensee has satisfied the applicable provisions of 10 CFR Part 140, "Financial Protection Requirements and Indemnity Agreements," of the Commission's regulations; G. The issuance of this renewed operating license will not be inimical to the common defense and security or to the health and safety of the public; H. After weighing the environmental, economic, technical, and other benefits of the facility against environmental and other costs and considering available alternatives, the issuance of this Renewed Facility Operating License No. NFP-9 is in accordance with 10 CFR Part 51, of the Commission's regulations and all applicable requirements have been satisfied; and,

1. The receipt, possession, and use of source, byproduct and special nuclear material as authorized by this renewed operating license will be in accordance with the Commission's regulations in 10 CFR Parts 30, 40 and 70.

2. Based on the foregoing findings, and pursuant to approval by the Nuclear Regulatory Commission at a meeting on June 9, 1981, the License for Fuel-Loading and Zero Power Testing issued on January 23, 1981, as amended, is superseded by Renewed Facility Operating License No. NPF-9 which is hereby issued to Duke Energy Carolinas, LLC to read as follows:

A. This renewed operating license applies to the McGuire Nuclear Station, Unit 1, a pressurized water reactor and associated equipment (the facility) owned and operated by Duke Energy Carolinas, LLC. The facility is located on the licensee's site in Mecklenburg County, North Carolina, on the shore of Lake Norman approximately 17 miles northwest of Charlotte, North Carolina and is described in the Updated Final Safety Analysis Report, as supplemented and amended, and in the Environmental Report, as supplemented and amended.

B. Subject to the conditions and requirements incorporated herein, the Commission hereby licenses Duke Energy Carolinas, LLC:

(1) Pursuant to Section 103 of the Act and 10 CFR Part 50, to possess, use, and operate the facility at the designated location in Mecklenburg County, North Carolina, in accordance with the procedures and limitations set forth in the renewed operating license; (2) Pursuant to the Act and 10 CFR Part 70 to receive, possess and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Updated Final Safety Analysis Report, as supplemented and amended; (3) Pursuant to the Act and 10 CFR Parts 30, 40 and 70 to receive, possess and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; Renewed License No. NPF-9 Amendment No. 245

(4) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; (5) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproducts and special nuclear materials as may be produced by the operation of McGuire Nuclear Station, Units 1 and 2, and; (6) Pursuant to the Act and 10 CFR Parts 30 and 40, to receive, possess and process for release or transfer such byproduct material as may be produced by the Duke Training and Technology Center.

C. This renewed operating license shall be deemed to contain and is Subject to the conditions specified in the Commission'sregulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level The licensee is authorized to operate the facility at a reactor core full steady state power level of 3411 megawatts thermal (100%).

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 258, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

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

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

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

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

Renewed License No. NPF-9 Amendment No. 258

(4) Fire Protection Program Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report for the facility and as approved in the SER dated March 1978 and Supplements 2, 5 and 6 dated March 1979, April 1981, and February 1983, respectively, and the safety evaluation dated May 15, 1989, subject to the following provision:

Duke 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.

(5) Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 200, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.

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

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

A) Fire fighting response strategy with the following elements:

1. Pre-defined coordinated fire response strategy and guidance

2. Assessment of mutual aid fire fighting assets

3. Designated staging areas for equipment and materials

4. Command and control

5. Training of response personnel B) Operations to mitigate fuel damage considering the following:

1. Protection and use of personnel assets

2. Communications

3. Minimizing fire spread

4. Procedures for implementing integrated fire response strategy

5. Identification of readily-available pre-staged equipment

6. Training on 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 Renewed License No. NPF-9 Amendment No. 245

-4A-D. Physical Protection Duke Energy Carolinas, LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains safeguards information protected under 10 CFR 73.21, is entitled: "Duke Energy Physical Security Plan" submitted by letter dated September 8, 2004, and supplemented on September 30, 2004, October 15, 2004, October 21, 2004, and October 27, 2004.

E. Deleted by Amendment No. 233.

Renewed License No. NPF-9 Amendment No. 245

F. 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.

G. The licensee is authorized to receive from the Oconee Nuclear Station, Units 1, 2, and 3, possess, and store irradiated Oconee fuel assemblies containing special nuclear material, enriched to not more than 3.24% by weight U-235 subject to the following conditions:

a. Oconee fuel assemblies may not be placed in the McGuire Nuclear Station, Unit 1 and 2, reactors.

b. Irradiated fuel shipped to McGuire Nuclear Station, Units 1 and 2, from Oconee shall have been removed from the Oconee reactor no less than 270 days prior to shipment.

c. No more than 300 Oconee irradiated fuel assemblies shall be received for storage at McGuire Nuclear Station.

d. Burnup of Oconee fuel shipped shall be no greater than 36,000 MW days per metric ton.

e. Receipt of irradiated Oconee fuel shall be limited by the use of the NFS-4 (NAC-1), NLI-1/2, TN-8, or TN-8L spent fuel casks.

f. The spent fuel pool crane travel shall be restricted by administrative controls to the paths required by Selected Licensee Commitment 16.9.20 whenever a spent fuel cask is being handled.

g. Oconee fuel assemblies may not be transferred from one McGuire spent fuel pool to the other.

3. This renewed operating license is effective as of the date of issuance and shall expire at midnight on June 12, 2041.

FOR THE NUCLEAR REGULATORY COMMISSION J.E. Dyer, Director Office of Nuclear Reactor Regulation

Attachment:

1. Appendix A - Technical Specifications

2. Appendix B - Additional Conditions

3. Appendix C - Antitrust Conditions Date of Issuance: December 5, 2003 Renewed License No. NPF-9

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

Amendment Additional Implementation Number Conditions Date 184 The schedule for the performance of new and. Within 90 days of revised surveillance requirements shall be as the date of this follows: amendment.

For surveillance requirements (SRs) that are new in Amendment No. 184 the first performance is due at the end of the first surveillance interval that begins at implementation of Amendment No. 184. For SRs that existing prior to Amendment No. 184, including SRs with modified acceptance criteria and SRs whose intervals of performance are being extended, the first performance is due at the end of the first surveillance interval that begins on the date the surveillance was last performed prior to implementation of amendment No. 184. For SRs that existed prior to Amendment No. 184, whose intervals of performance are being reduced, the first reduced surveillance interval begins upon completion of the first surveillance performed after implementation of Amendment No. 184.

Renewed License No. NPF-9 Amendment No. 258

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

Amendment Additional Number Conditions 249 Upon implementation of the Amendment adopting TSTF-448, Revision 3, the determination of control room envelope (CRE) unfiltered inleakage as required by SR 3.7.9.4, in accordance with TS 5.5.16.c.(i), the assessment of CRE habitability as required by TS 5.5.16.c.(ii), and the measurement of CRE pressure as required by TS 5.5.16.d, shall be considered met.

Following implementation:

(a) The first performance of SR 3.7.9.4 in accordance with TS 5.5.16.c.(i), shall be within the specified Frequency of 6 years, plus the 18 month allowance of SR 3.0.2, as measured from October 2003, the date of the most recent successful tracer gas test, as stated in the February 19, 2004 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, TS 5.5.16.c.(ii), shall be within 3 years, plus the 9 month allowance of SR 3.0.2 as measured from October 2003, the date of the most recent successful tracer gas test, as stated in the February 19, 2004 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, TS 5.5.16.d, shall be within 18 months, plus the 138 days allowed by SR 3.0.2, as measured from January 2007, the date of the most recent successful pressure measurement test, or within 138 days if not performed previously.

Renewed License No. NPF-9 Amendment No. 249 B-2

APPENDIX C ANTITRUST CONDITIONS Pursuant to an Order by the Atomic Safety and Licensing Board, dated April 23, 1975, the Nuclear Regulatory Commission incorporates in Renewed Operating License NPF-9 the following antitrust conditions:

a. The licensee makes the commitments contained herein, recognizing that bulk power supply arrangements between neighboring entities normally tend to serve the public interest. In addition, where there are net benefits to all participants such arrangements also serve the best interests of each of the participants.

Among the benefits of such transactions are increased electric system reliability, a reduction in the cost of electric power, and minimization of the environmental effects of the production and sale of electricity.

Any particular bulk power supply transaction may afford greater benefits to one participant than to another. The benefits realized by a small system may be proportionately greater than those realized by a larger system. The relative benefits to be derived by the parties from a proposed transaction, however, should not be controlling upon a decision with respect to the desirability of participating in the transaction. Accordingly, the licensee will enter into proposed bulk power transactions of the types hereinafter described which, on balance, provide net benefits to the licensee. There are net benefits in a transaction if the licensee recovers the cost of the transaction, (as defined in subparagraph (1)(d) hereof) and there is no demonstrable net detriment to the licensee arising from the transaction.

(1) As used herein:

(a) "Bulk Power" means electric power and any attendant energy, supplied or made available at transmission or sub-transmission voltage by one electric system to another.

(b) "Neighboring Entity" means a private or public corporation, a governmental agency or authority, a municipality, a cooperative, or a lawful association of any of the foregoing owning or operating, or proposing to own or operate, facilities for the generation and

• transmission of electricity which meets each of the following criteria:.

(1) its existing or proposed facilities are economically and technically feasible of interconnection with those of the licensee and (2) with the exception of municipalities, cooperatives, governmental agencies or authorities, and associations,. it is, or upon commencement of operations will be, a public utility and subject to regulation with respect to rates and service under the laws of North Carolina or South Carolina or under the Federal Power Act; provided, however, that as to associations, each member of such association is either a public utility as discussed in this clause (2) or a municipality, a cooperative or C-1

a governmental agency or authority.

(c) Where the phrase "neighboring entity" is intended to include entities engaging or proposing to engage only in the distribution of electricity, this is indicated by adding the phrase "including distribution systems."

(d) "Cost" means any appropriate operating and maintenance expenses, together with all other costs, including a reasonable return on the licensee's investment, which are reasonably allocable to a transaction.

However, no value shall be included for loss of revenue due to the loss of any wholesale or retail customer as a result of any transaction hereafter described.

(2) (a) The licensee will interconnect and coordinate reserves by means of the sale and exchange of emergency and scheduled maintenance bulk power with any neighboring entity(ies), when there are net benefits to each party, on terms that will provide for all of the licensee's properly assignable costs as may be determined by the Federal Energy Regulatory Commission and consistent with such cost assignment will allow the other party the fullest possible benefits of such coordination.

(b) Emergency service and/or scheduled maintenance service to be provided by each party will be furnished to the fullest extent available from the supplying party and desired by the party in need. The licensee and each party will provide to the other emergency service and/or scheduled maintenance service if and when available from its own generation and, in accordance with recognized industry practice, from generation of other to the extent it can do so without impairing service to its customers, including other electric systems to whom it has firm commitments.

(c) Each party to a reserve coordination arrangement will establish its own reserve criteria, but in no event shall the minimum installed reserve on each system be less than 15%, calculated as a percentage of estimated peak load responsibility. Either party, if it has, or has firmly planned, installed reserves in excess of the amount called for by its own reserve criterion, will offer any such excess as may in fact be available at the time for which it is sought and for such period as the selling party shall determine for purchase in accordance with reasonable industry practice by the other party to meet such other party's own reserve requirements. The parties will provide such amounts of.spinning reserve as may be adequate to avoid the imposition of unreasonable demands on the other part(ies) in meeting the normal contingencies of operating its (their) system(s). However, in no circumstances shall such spinning reserve requirement exceed the installed reserve requirement.

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(d) Interconnections will not be limited to low voltages when higher voltages are available from the licensee's installed facilities in the area where interconnection is desired and when the proposed arrangement is found to be technically and economically feasible.

(e) Interconnection and reserve coordination agreements will not embody provisions which impose limitations upon the use or resale of power and energy sold or exchanged pursuant to the agreement. Further, such arrangements will not prohibit the participants from entering into other interconnection and coordination arrangements, but may include appropriate provisions to assure that (i) the licensee receives adequate notice of such additional interconnection or coordination, (ii) the parties will jointly consider and agree upon such measures, if any, as are reasonably necessary to protect the reliability of the interconnected systems and to prevent undue burdens from being imposed on any system, and (iii) the licensee will be fully compensated for its costs. Reasonable industry practice as developed in the area from time to time will satisfy this provision.

(3) The licensee currently has on file, and may hereafter file, with the Federal Energy Regulatory Commission contracts with neighboring entity(ies) providing for the sale and exchange of short-term power and energy, limited term power and energy, economy energy, non-displacement energy, and emergency capacity and energy. The Licensee will enter into contracts providing for the same or for like transactions with any neighboring entity on terms which enable the licensee to recover the full costs allocable to such transaction.

(4) The licensee currently sells capacity and energy in bulk on a full requirements basis to several entities engaging in the distribution of electric power at retail. In addition, the licensee supplies electricity directly to ultimate users in a number of municipalities. Should any such entity(ies) or municipality(ies) desire to become a neighboring entity as defined in subparagraph (1)(b) hereof (either alone or through combination with others), the licensee will assist in facilitating the necessary transition through the sale of partial requirements firm power and energy to the extent that, except for such transition, the licensee would otherwise be supplying firm power and energy. The provision of such firm partial requirements service shall be under such rates, terms and conditions as shall be found by the Federal Energy Regulatory Commission to provide for the recovery of the licensee's cost. The licensee will sell capacity and energy in bulk on a full requirements basis to any municipality currently served by the licensee when such municipality lawfully engages in the distribution of electric power at retail.

(5) (a) The licensee will facilitate the exchange of electric power in bulk in wholesale transactions over its transmission facilities (1) between Or C-3

among two or more neighboring entities including distribution systems with which it is interconnected or may be interconnected in the future, and (2) between any such entity(ies) and any other electric system engaging in bulk power supply between whose facilities the licensee's transmission lines and other transmission lines would form a continuous electric path, provided that permission to utilize such other transmission lines has been obtained. Such transaction shall be undertaken provided that the particular transaction reasonably can be accommodated by the licensee's transmission system from a functional and technical standpoint and does not constitute the wheeling of power to a retail customer. Such transmission shall be on terms that fully compensate the licensee for its cost. Any entity(ies) requesting such transmission arrangements shall give reasonable notice of its (their) schedule and requirements.

(b) The licensee will include in its planning and construction program sufficient transmission capacity as required for the transactions referred to in subparagraph (a) of this paragraph, provided that (1) the neighboring entity(ies) gives the licensee sufficient advance notice as may be necessary reasonably to accommodate its (their) requirements from a functional and technical standpoint and (2) that such entity(ies) fully compensate the licensee for its cost. In carrying out this subparagraph (b), however, the licensee shall not be required to construct or add transmission facilities which (a) will be of no demonstrable present or future benefit to the licensee, or (b) which could be constructed by the requesting entity(ies) without duplicating any portion of the licensee's existing transmission lines, or (c) which would jeopardize the licensee's ability to finance or construct on reasonable terms facilities needed to meet its own anticipated system requirements. Where regulatory or environmental approvals are required for the construction or addition of transmission facilities needed for the transactions referred to in subparagraph (a) of this paragraph it shall be the responsibility of the entity(ies) seeking the transaction to participate in obtaining such approvals, including sharing in the cost thereof.

(6) To increase the possibility of achieving greater reliability and economy of electric generation and transmission facilities, the licensee will discuss load projections and system development plans with any neighboring entity(ies).

(7) When the licensee's plans for future nuclear generating units (for which application will hereafter be made to the Nuclear Regulatory commission) have reached the stage of serious planning, but before firm decisions have been made as to the size and desired completion date of the proposed nuclear units, the licensee will notify all neighboring entities including distribution systems with peak loads smaller than the licensee's that the licensee plans to construct such C-4

nuclear units. Neither the timing nor the information provided need be such as to jeopardize obtaining the required site at the lowest possible cost.

(8) The foregoing commitments shall be implemented in a manner consistent with the provisions of the Federal Power Act and all other lawful local, state and Federal regulation and authority. Nothing in these commitments is intended to determine in advance the resolution of issues which are properly raised at the Federal Energy Regulatory Commission concerning such commitments, including allocation of costs or the rates to be charged. The licensee will negotiate (including the execution of a contingent statement of intent) with respect to the foregoing commitments with any neighboring entity including distribution systems where applicable engaging in or proposing to engage in bulk power supply transactions, but the licensee shall not be required to enter into any final arrangement prior to resolution of any substantial questions as to the lawful authority of an entity to engage in the transactions.

In addition, the licensee shall not be obligated to enter into a given bulk power supply transaction if: (1) to do so would violate, or incapacitate it from performing, and existing lawful contracts it has with a third party; (2) there is contemporaneously available to it a competing or alternate arrangement which affords it greater benefits which would be mutually exclusive of such arrangement; (3) to do so would adversely affect its system operations or the reliability of power supply to its customers, or (4) if to do so would jeopardize the licensee's ability to finance or construct on reasonable terms facilities needed to meet its own anticipated system requirements.

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DUKE ENERGY CAROLINAS. LLC DOCKET NO. 50-370 MCGUIRE NUCLEAR STATION, UNIT 2 RENEWED FACILITY OPERATING LICENSE Renewed License No. NPF-17

1. The U.S. Nuclear Regulatory Commission (Commission), having previously made the findings set forth in License No. NPF-17 issued on March 3, 1983, has now found that:

A. The application for renewed operating license filed by the Duke Energy Corporation* complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I and all required notifications to other agencies or bodies have been duly made; B. Actions have been identified and have been or will be taken with respect to (1) managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21 (a)(1), and (2) time-limited aging analyses that have been identified to require review under 10 CFR 54.21 (c), such that there is reasonable assurance that the activities authorized by the renewed operating license will continue to be conducted in accordance with the current licensing basis, as defined in 10 CFR 54.3, for the McGuire Nuclear Station, Unit 2 (facility or plant), and that any changes made to the plant's current licensing basis in order to comply with 10 CFR 54.29(a) are in accord with the Act and the Commission's regulations; C. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the regulations of the Commission; D. There is reasonable assurance: (i) that the activities authorized by this renewed operating license can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; E. The licensee is technically qualified to engage in the activities authorized by this renewed operating license in accordance with the Commission's regulations set forth in 10 CFR Chapter I; Duke Energy Corporation converted to Duke Power Company LLC on April 3, 2006 and was re-named Duke Energy Carolinas, LLC as of October 1, 2006. Duke Energy Carolinas, LLC is the owner and operator of McGuire Nuclear Station, Unit 2. References to the "licensee" or "Duke" are to Duke Energy Carolinas, LLC.

Renewed License No. NPF-17 Amendment No. 225

F. The licensee has satisfied the applicable provisions of 10 CFR Part 140, "Financial Protection Requirements and Indemnity Agreements", of the Commission's regulations; G. The issuance of this renewed operating license will not be inimical to the common defense and security or to the health and safety of the public; H. After weighing the environmental, economic, technical, and other benefits of the facility against environmental and other costs and considering available alternatives, the issuance of this Renewed Facility Operating License No. NPF-17 is in accordance with 10 CFR Part 51, of the Commission's regulations and all applicable requirements have been satisfied; and, I. The receipt, possession, and use of source, byproduct and special nuclear material as authorized by this renewed operating license will be in accordance with the Commission's regulations in 10 CFR Parts 30, 40 and 70.

2. Based on the foregoing findings and the Initial Decisions issued by the Atomic Safety and Licensing Board dated April 18, 1979, and May 26, 1981, and the Decision of the Atomic Safety and Licensing Appeal Board dated March 30, 1982, regarding this facility, Renewed Facility Operating License No. NPF-17 is hereby issued to Duke Energy Carolinas, LLC to read as follows:

A. This renewed operating license applies to the McGuire Nuclear Station, Unit 2, a pressurized water reactor and associated equipment (the facility) owned and operated by Duke Energy Carolinas, LLC. The facility is located on the site in Mecklenburg County, North Carolina, on the shore of Lake Norman approximately 17 miles northwest of Charlotte, North Carolina, and is described in the Updated Final Safety Analysis Report, as supplemented and amended, and in the Environmental Report, as supplemented and amended.

B. Subject to the conditions and requirements incorporated herein, the Commission hereby licenses Duke Energy Carolinas, LLC:

(1) Pursuant to Section 103 of the Act and 10 CFR Part 50, to possess, use, and operate the facility at the designated location in Mecklenburg County, North Carolina, in 'accordance with the procedures and limitations set forth in this renewed operating license; (2) Pursuant to the Act and 10 CFR Part 70 to receive, possess and use at anytime special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Updated Final Safety Analysis Report, as supplemented and amended; (3) Pursuant to the Act and 10 CFR Parts 30, 40 and 70 to receive, possess and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; Renewed License No. NPF-17 Amendment No. 225

(4) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; (5) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproducts and special nuclear materials as may be produced by the operation of McGuire Nuclear Station, Units 1 and 2; and, (6) Pursuant to the Act and 10 CFR Parts 30 and 40, to receive, possess and process for release or transfer such byproduct material as may be produced by the Duke Training and Technology Center.

C. This renewed operating license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level The licensee is authorized to operate the facility at a reactor core full steady state power level of 3411 megawatts thermal (100%).

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 238, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

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

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

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

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

Renewed License No. NPF-17 Amendment No. 238

(4) Fire Protection Program Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report for the facility and as approved' in the SER dated March 1978 and Supplements 2, 5, and 6 dated March 1979, April 1981, and February 1983, respectively, and the safety evaluation dated May 15, 1989, subject to the following provisions:

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.

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

(6) Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 181, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.

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

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

A) Fire fighting response strategy with the following elements:

1. Pre-defined coordinated fire response strategy and guidance

2. Assessment of mutual aid fire fighting assets

3. Designated staging areas for equipment and materials

4. Command and control

5. Training of response personnel B) Operations to mitigate fuel damage considering the following:

1. Protection and use of personnel assets

2. Communications

3. Minimizing fire spread Renewed License No. NPF-17 Amendment No. 225

4. Procedures for implementing integrated fire response strategy

5. Identification of readily-available pre-staged equipment

6. Training on 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 D. Physical Protection Duke Energy Carolinas, LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains safeguards information protected under 10 CFR 73.21, is entitled: "Duke Energy Physical Security Plan" submitted by letter dated September 8, 2004, and supplemented on September 30, 2004; October 15, 2004, October 21, 2004, and October 27, 2004.

E. Deleted by Amendment No. 215.

F. 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.

G. In accordance with the Commission's direction in its Statement of Policy, Licensing and Regulatory Policy and Procedures for Environmental Protection:

Uranium Fuel Cycle Impacts, October 29, 1982, this renewed operating license is subject to the final resolution of the pending litigation involving Table S-3.

See, Natural Resources Defense Council v. NRC, No. 74-1586 (D.C. cir. April.

27, 1982).

H. The licensee is authorized to receive from the Oconee Nuclear Station, Units 1, 2, and 3, possess, and store irradiated Oconee fuel assemblies containing special nuclear material, enriched to not more than 3.24% by weight U-235 subject to the following conditions:

a. Oconee fuel assemblies may not be placed in the McGuire Nuclear Station, Unit 1 and 2, reactors.

b. Irradiated fuel shipped to McGuire Nuclear Station, Units 1 and 2, from Oconee shall have been removed from the Oconee reactor no less than 270 days prior to shipment.

Renewed License No. NPF-17 Amendment No. 225

c. No more than 300 Oconee irradiated fuel assemblies shall be received for storage at McGuire Nuclear Station.

d. Burnup of Oconee fuel shipped shall be no greater than 36,000 MW days per metric ton.

e. Receipt of irradiated Oconee fuel shall be limited by the use of the NFS-4 (NAC-1), NLI-1/2, TN-8, or TN-8L spent fuel casks.

f. The spent fuel pool crane travel shall be restricted by administrative controls to the paths required by Selected Licensee Commitment 16.9.20 whenever a spent fuel cask is being handled.

g. Oconee fuel assemblies may not be transferred from one McGuire spent fuel pool to the other.

3. This renewed operating license is effective as of the date of issuance and shall expire at midnight on March 3, 2043.

FOR THE NUCLEAR REGULATORY COMMISSION J.E. Dyer, Director Office of Nuclear Reactor Regulation

Attachment:

1. Appendix A - Technical Specifications

2. Appendix B - Additional Conditions

3. Appendix C - Antitrust Conditions Date of Issuance: December 5, 2003 Renewed License No. NPF-17

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

Amendment Additional Implementation Number Conditions Date 166 The schedule for the performance of new and Within 90 days of revised surveillance requirements shall be as the date of this follows: amendment.

For surveillance requirements (SRs) that are new in Amendment No. 166 the first performance is due at the end of the first surveillance interval that begins at implementation of Amendment No. 166. For SRs that existed prior to Amendment No. 166, including SRs with modified acceptance criteria and SRs whose intervals of performance are being extended, the first performance is due at the end of the first surveillance interval that begins on the date the surveillance was last performed prior to implementation of amendment No. 166. For SRs that existed prior to Amendment No. 166, whose intervals of performance are being reduced, the first reduced surveillance interval begins upon completion of the first surveillance performed after implementation of Amendment No. 166.

Renewed License No. NPF-17 Amendment No. 238 B-1

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

Amendment Additional Implementation Number Conditions Date 229 Upon implementation of the Amendment adopting See Condition TSTF-448, Revision 3, the determination of control room envelope (CRE) unfiltered inleakage as required by SR 3.7.9.4, in accordance with TS 5.5.16.c.(i), the assessment of CRE habitability as required by TS 5.5.16.c.(ii), and the measurement of CRE pressure as required by TS 5.5.16.d, shall be considered met.

Following implementation:

(a) The first performance of SR 3.7.9.4 in accordance with TS 5.5.16.c.(i), shall be within the specified Frequency of 6 years, plus the 18 month allowance of SR 3.0.2, as measured from October 2003, the date of the most recent successful tracer gas test, as stated in the February 19, 2004 letter response to Generic Letter 2003-01, or within the next 18 months ifthe 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, TS 5.5.16.c.(ii), shall be within 3 years, plus the 9 month allowance of SR 3.0.2 as measured from October 2003, the date of the most recent successful tracer gas test, as stated in the February 19, 2004 letter response to Generic Letter 2003-01, or within the next 9 months ifthe 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, TS 5.5.16.d, shall be within 18 months, plus the 138 days allowed by SR 3.0.2, as measured from January 2007, the date of the most recent successful pressure measurement test, or within 138 days if not performed previously.

Renewed License No. NPF-17 Amendment No. 229 B-2

APPENDIX C ANTITRUST CONDITIONS Pursuant to an Order by the Atomic Safety and Licensing Board, dated April 23, 1975, the Nuclear Regulatory Commission incorporates in Operating License NPF-17 the following antitrust conditions:

a. The licensee makes the commitments contained herein, recognizing that bulk power supply arrangements between neighboring entities normally tend to serve the public interest. In addition, where there are net benefits to all participants such arrangements also serve the best interests of each of the participants.

Among the benefits of such transactions are increased electric system reliability, a reduction in the cost of electric power, and minimization of the environmental effects of the production and sale of electricity.

Any particular bulk power supply transaction may afford greater benefits to one participant than to another. The benefits realized by a small system may be proportionately greater than those realized by a larger system. The relative benefits to be derived by the parties from a proposed transaction, however, should not be controlling upon a decision with respect to the desirability of participating in the transaction. Accordingly, the licensee will enter into proposed bulk power transactions of the types hereinafter described which, on balance, provide net benefits to the licensee. There are net benefits in a transaction if the licensee recovers the cost of the transaction (as defined in subparagraph (1)(d) hereof) and there is no demonstrable net detriment to the licensee arising from the transaction.

(1) As used herein:

(a) "Bulk Power" means electric power and any attendant energy, supplied or made available at transmission or sub-transmission voltage by one electric system to another.

(b) "Neighboring Entity" means a private or public corporation, a governmental agency or authority, a municipality, a cooperative, or a lawful association of any of the foregoing owning or operating, or proposing to own or operate, facilities for the generation and transmission of electricity which meets each of the following criteria:

(1) its existing or proposed facilities are economically and technically feasible of interconnection with those of the licensee and (2) with the exception of municipalities, cooperatives, governmental agencies or authorities, and associations, it is, or upon commencement of operations will be, a public utility and subject to regulation with respect to rates and service under the laws of North Carolina or South Carolina or under the Federal Power Act; provided, however, that as to associations, each member of such association is either a public utility as discussed in this clause (2) or C-1

a municipality, a cooperative or a governmental agency or authority.

(c) Where the phrase "neighboring entity" is intended to include entities engaging or proposing to engage only in the distribution of electricity, this is indicated by adding the phrase "including distribution systems."

(d) "Cost means any appropriate operating and maintenance expenses, together with all other costs, including a reasonable return on the licensee's investment, which are reasonably allocable to a transaction.

• However, no value shall be included for loss of revenue due to the loss of any wholesale or retail customer as a result of any transaction hereafter described.

(2) (a) The licensee will interconnect and coordinate reserves by means of the sale and exchange of emergency and scheduled maintenance bulk power with any neighboring entity(ies), when there are net benefits to each party, on terms that will provide for all of the licensee's properly assignable costs as may be determined by the Federal Energy Regulatory Commission and consistent with such cost assignment will allow the other party the fullest possible benefits of such coordination.:

(b) Emergency service and/or scheduled maintenance service to be provided by each party will be furnished to the fullest extent available from the supplying party and desired by the party in need. The licensee and each party will provide to the other emergency service and/or scheduled maintenance service if and when available from its own generation and, in accordance with recognized industry practice, from generation of other to the extent it can do so without impairing service to its customers, including other electric systems to whom it has firm commitments.

(c) Each party to a reserve coordination arrangement will establish its own reserve criteria, but in no event shall the minimum installed reserve on each system be less than 15%, calculated as a percentage of estimated peak load responsibility. Either party, if it has, or has firmly planned, installed reserves in excess of the amount called for by its own reserve criterion, will offer any such excess as may in fact be available at the time for which it is sought and for such period as the selling party shall determine for purchase in accordance with reasonable industry practice by the other party to meet such other party's own reserve requirements. The parties will provide such amounts of spinning reserve as may be adequate to avoid the imposition of unreasonable demands on the other part(ies) in meeting the normal contingencies of operating its (their) system(s). However, in no circumstances shall such spinning reserve requirement exceed the installed reserve requirement.

(d) Interconnections will not be limited to low voltages when higher voltages are C-2

• available from the licensee's installed facilities in the area where interconnection is desired and when the proposed arrangement is found to be technically and economically feasible.

(e) Interconnection and reserve coordination agreements will not embody provisions which impose limitations upon the use or resale of power and energy sold or exchanged pursuant to the agreement. Further, such arrangements will not prohibit the participants from entering into other interconnection and coordination arrangements, but may include appropriate provisions to assure that (i) the licensee receives adequate notice of such additional interconnection or coordination, (ii) the parties will jointly consider and agree upon such measures, if any, as are reasonably necessary to protect the reliability of the interconnected systems and to prevent undue burdens from being imposed on any system, and (iii) the licensee will be fully compensated for its costs. Reasonable industry practice as developed in the area from time to time will satisfy this provision.

(3) The licensee currently has on file, and may hereafter file, with the Federal Energy Regulatory Commission contracts with neighboring entity(ies) providing for the sale and exchange of short-term power and energy, limited term power and energy, economy energy, non- displacement energy, and emergency capacity and energy. The Licensee will enter into contracts providing for the same or for like transactions with any neighboring entity on terms which enable the licensee to recover the full costs allocable to such transaction.

(4) The licensee currently sells capacity and energy in bulk on a full requirements basis to several entities engaging in the distribution of electric power at retail. In addition, the licensee supplies electricity directly to ultimate users in a number of municipalities. Should any such entity(ies) or municipality(ie's) desire to become a neighboring entity as defined in subparagraph (1)(b) hereof (either alone or through combination with others), the licensee will assist in facilitating the necessary transition through the sale of partial requirements firm power and energy to the extent that, except for such transition, the licensee would otherwise be supplying firm power and energy. The provision of such firm partial requirements service shall be under such rates, terms and conditions as shall be fournd by the Federal Energy Regulatory Commission to provide for the recovery of the licensee's cost. The licensee will sell capacity and energy in bulk on a full requirements basis to any municipality currently served by the licensee when such municipality lawfully engages in the distribution of electric power at retail.

(5) (a) The licensee will facilitate the exchange of electric power in bulk in wholesale transactions over its transmission facilities (1) between or among two or more neighboring entities including distribution systems with which it is interconnected or may be interconnected in the future, and (2) between any such entity(ies) and any other electric system engaging in bulk power supply between whose facilities the licensee's transmission C-3

lines and other transmission lines would form a continuous electric path, provided that permission to utilize such other transmission lines has been obtained. Such transaction shall be undertaken provided that the particular transaction reasonably can be accommodated by the licensee's transmission system from a functional and technical standpoint and does not constitute the wheeling of power to a retail customer. Such transmission shall be on terms that fully compensate the licensee for its cost. Any entity(ies) requesting such transmission arrangements shall give reasonable notice of its (their) schedule and requirements.

(b) The licensee will include in its planning and construction program sufficient transmission capacity as required for the transactions referred to in subparagraph (a) of this paragraph, provided that (1) the neighboring entity(ies) gives the licensee sufficient advance notice as may be necessary reasonably to accommodate its (their) requirements from a functional and technical standpoint and (2) that such entity(ies) fully compensate the licensee for its cost. In carrying out this subparagraph (b), however, the licensee shall not be required to construct or add transmission facilities which (a) will be of no demonstrable present or future benefit to the licensee, or (b) which could be constructed by the requesting entity(ies) without duplicating any portion of the licensee's existing transmission lines, or (c) which would jeopardize the licensee's ability to finance or construct on reasonable terms facilities needed to meet its own anticipated system requirements. Where regulatory or environmental approvals are required for the construction or addition of transmission facilities needed for the transactions referred to in subparagraph (a) of this paragraph it shall be the responsibility of the entity(ies) seeking the transaction to participate in obtaining such approvals, including sharing in the cost thereof.

(6) To increase the possibility of achieving greater reliability and economy of electric generation and transmission facilities, the licensee will discuss load projections and system development plans with any neighboring entity(ies).

(7) When the licensee's plans for future nuclear generating units (for which application will hereafter be made to the Nuclear Regulatory commission) have reached the stage of serious planning, but before firm decisions have been made as to the size and desired completion date of the proposed nuclear units, the licensee will notify all neighboring entities including distribution systems with peak loads smaller than the licensee's that the licensee plans to construct such nuclear units. Neither the timing nor the information provided need be such as to jeopardize obtaining the required site at the lowest possible cost.

The foregoing commitments shall be implemented in a manner consistent with the provisions of the Federal Power Act and all other lawful local, state and Federal regulation and authority. Nothing in these commitments is intended to determine in advance the resolution of issues which are properly raised at the Federal Energy Regulatory Commission concerning such commitments, C-4

including allocation of costs or the rates to be charged. The licensee will negotiate (including the execution of a contingent statement of intent) with respect to the foregoing commitments with any neighboring entity including distribution systems where applicable engaging in or proposing to engage in bulk power supply transactions, but the licensee shall not be required to enter into any final arrangement prior to resolution of any substantial questions as to the lawful authority of an entity to engage in the transactions.

In addition, the licensee shall not be obligated to enter into a given bulk power supply transaction if: (1) to do so would violate, or incapacitate it from performing, and existing lawful contracts it has with a third party; (2) there is contemporaneously available to it a competing or alternate arrangement which affords it greater benefits which would be mutually exclusive of such arrangement; (3) to do so would adversely affect its system operations or the reliability of power supply to its customers, or (4) if to do so would jeopardize the licensee's ability to finance or construct on reasonable terms facilities needed to meet its own anticipated system requirements.

C-5