Text

Submittal of Revision 28 to Updated Final Safety Analysis Report, Technical Specifications Bases Revisions, Selected Licensee Commitment Revisions and 10CFR50.59 Evaluation Summary Report
	ML20181A118
Person / Time
Site:	Oconee
Issue date:	06/29/2020
From:	Burchfield J; Duke Energy Carolinas
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
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SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

r. DUKE UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

~ ENERGY J. Ed Burchfield, Jr.

Vice President Oconee Nuclear Station Duke Energy ON01VP l 7800 Rochester Hwy Seneca, SC 29672 o: 864.873.3478 f: 864.873.5791 Ed.Burchfield@duke-energy.com 10 CFR 50.71(e) 10 CFR 50.59(d) 10 CFR 54.37(b)

RA-20-0136 June 29, 2020 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Oconee Nuclear Station (ONS), Units 1, 2, and 3 Docket Numbers 50-269, 50-270, and 50-287 Renewed Facility Operating License Nos. DPR-38, DPR-47, and DPR-55

Subject:

Submittal of Updated Final Safety Analysis Report (UFSAR) Revision 28, Technical Specifications Bases Revisions, Selected Licensee Commitment Revisions, 10 CFR 50.59 Evaluation Summary Report, and 10 CFR 54.37 Update Ladies and Gentlemen:

Pursuant to 10 CFR 50.71(e), Duke Energy Carolinas, LLC (Duke Energy) hereby submits Revision 28 to the UFSAR for the Oconee Nuclear Station (ONS), Units 1, 2 and 3. The ONS UFSAR is included in this submission via two CD-ROMs (Enclosures 1 and 2). Enclosure 1 provides a copy of the UFSAR that has been redacted for public use. Enclosure 2 provides a copy of the UFSAR that contains sensitive information to be withheld from public disclosure per 10 CFR 2.390(d). Changes made since Revision 27 are identified by vertical lines in the margins of the pages that are indicated as Revision 28. The effective date of Revision 28 is December 31, 2019.

Attachment 1 provides the List of Effective Pages and the List of Changed Pages for UFSAR, Revision 28. Attachment 2 provides insertion instructions for those receiving hardcopy distribution. Attachment 3 provides a listing of items removed in the Revision 28 UFSAR update.

In accordance with 10 CFR 50.59(d)(2), Duke Energy is providing a report summarizing the 10 CFR 50.59 evaluations of changes, tests, and experiments implemented during the period from January 1, 2018 to December 31, 2019 for ONS. This report is included in Attachment 4.

SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

SECURITY-RELATED INFORMATION-WITHHOL D UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED U.S. Nuclear Regulatory Commission RA-20-0136 Page2 In accordance with ONS Technical Specification 5.5.15, "Technical Specifications (TS) Bases Control Program," Duke Energy is providing TS Bases revisions through December 31, 2019 in that have not previously been transmitted.

Additionally, pursuant to 10 CFR 50.71(e), Duke Energy is providing revisions to the ONS Selected Licensee Commitments (SLC) Manual through December 31, 2019 in Attachment 6.

The ONS SLC manual constitutes Chapter 16 of the UFSAR.

Finally, 10 CFR 54.37(b) requires that after the renewed license is issued, the UFSAR update must include any systems, structures, and components (SSCs) newly identified that would have been subject to an aging management review or evaluation of time-limited aging analysis in accordance with 10 CFR 54.21. The UFSAR update must describe how the effects of aging are managed such that the intended function(s) in 10 CFR 54.4(b) will be effectively maintained during the period of extended operation. A review was completed to determine whether any newly-identified SSCs existed in support of submitting UFSAR Revision 28. This review concluded that there were no newly-identified SSCs for which aging management reviews or time-limited aging analyses would apply.

There are no regulatory commitments contained in this letter.

If you have any questions regarding this submittal, please aontact Art Zaremba, Manager -

Nuclear Fleet Licensing, at (980) 373-2062.

I declare under penalty of perjury that the foregoing is true and correct. Executed on June 29, 2020.

Sincerely,

) G I ~/

J. Ed Burchfield, Jr.

Vice President Oconee Nuclear Station Attachments:

1. List of Effective Pages (LOEP) and List of Changed Pages (LOCP) for Text, Tables and Figures

2. Update Insertion Instructions (for hardcopy distribution only)

3. List of Removed Items 4 . 10 CFR 50.59 Evaluation Summary Report

5. Technical Specifications (TS) Bases Revisions

6. Selected Licensee Commitments (SLC) Manual Revisions

Enclosures:

1. Oconee Nuclear Station UFSAR 2019 Update - Rev. 28 Redacted Version, CD (Public Use Only)

2. Oconee Nuclear Station UFSAR 2019 Update - Rev. 28 CD (Non-Public Use)

SECURITY-RELATED INFORMATION -WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED U.S. Nuclear Regulatory Commission RA-20-0136 Page 3 xc:

L. Dudes, Regional Administrator U.S. Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, GA 30303-1257 J. Nadel, Senior Resident Inspector U.S. Nuclear Regulatory Commission Oconee Nuclear Station S. Williams, NRC Project Manager (Oconee)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Mailstop O-8B1A Rockville, MD 20852-2738 SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

U.S. Nuclear Regulatory Commission to RA-20-0136 Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, and 50-287 Renewed License Nos. DPR-38, DPR-47, and DPR-55 Submittal of Updated Final Safety Analysis Report (UFSAR) Revision 28, Technical Specifications Bases Revisions, Selected Licensee Commitments Revisions, 10 CFR 50.59 Evaluation Summary Report, and 10 CFR 54.37 Update Attachment 1 List of Effective Pages (LOEP) and List of Changed Pages (LOCP) for Text, Tables and Figures

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Chapter 1 1-i 31 DEC 2019 1-ii 31 DEC 2019 1-iii 31 DEC 2019 1-iv 31 DEC 2019 1-v 31 DEC 2019 1-vi 31 DEC 2019 1.0-1 31 DEC 2019 1.0-2 31 DEC 2019 1.1-1 31 DEC 2019 1.1-2 31 DEC 2019 1.2-1 31 DEC 2019 1.2-2 31 DEC 2019 1.2-3 31 DEC 2019 1.2-4 31 DEC 2019 1.3-1 31 DEC 2019 1.3-2 31 DEC 2019 1.4-1 31 DEC 2019 1.4-2 31 DEC 2019 Chapter 1 Tables Table 1-1 (Page 1 of 2) 31 DEC 2000 Table 1-1 (Page 2 of 2) 31 DEC 2000 Table 1-2 (Page 1 of 1) 31 DEC 2000 Table 1-3 (Page 1 of 1) 31 DEC 2000 Chapter 1 Figures Figure 1-1 (Page 1 of 1) 31 DEC 2000 Figure 1-2 (Page 1 of 1) 31 DEC 2000 Redacted in Enclosure 1 Figure 1-3 (Page 1 of 1) 31 DEC 2000 Redacted in Enclosure 1 Redacted in Enclosure 1 Figure 1-4 (Page 1 of 1) 31 DEC 2000 Redacted in Enclosure 1 Figure 1-5 (Page 1 of 1) 31 DEC 2004 Redacted in Enclosure 1 Figure 1-6 (Page 1 of 1) 31 DEC 2000 Redacted in Enclosure 1 Figure 1-7 (Page 1 of 1) 31 DEC 2007 Redacted in Enclosure 1 Figure 1-8 (Page 1 of 1) 31 DEC 2017 Page 1 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Redacted in Enclosure 1 Figure 1-9 (Page 1 of 1) 31 DEC 2000 Chapter 2 2-i 31 DEC 2019 2-ii 31 DEC 2019 2-iii 31 DEC 2019 2-iv 31 DEC 2019 2-v 31 DEC 2019 2-vi 31 DEC 2019 2-vii 31 DEC 2019 2-viii 31 DEC 2019 2-ix 31 DEC 2019 2-x 31 DEC 2019 2-xi 31 DEC 2019 2-xii 31 DEC 2019 2-xiii 31 DEC 2019 2-xiv 31 DEC 2019 2.0-1 31 DEC 2019 2.0-2 31 DEC 2019 2.1-1 31 DEC 2019 2.1-2 31 DEC 2019 2.1-3 31 DEC 2019 2.1-4 31 DEC 2019 2.2-1 31 DEC 2019 2.2-2 31 DEC 2019 2.3-1 31 DEC 2019 2.3-2 31 DEC 2019 2.3-3 31 DEC 2019 2.3-4 31 DEC 2019 2.3-5 31 DEC 2019 2.3-6 31 DEC 2019 2.3-7 31 DEC 2019 2.3-8 31 DEC 2019 2.3-9 31 DEC 2019 2.3-10 31 DEC 2019 2.3-11 31 DEC 2019 2.3-12 31 DEC 2019 2.3-13 31 DEC 2019 Page 2 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 2.3-14 31 DEC 2019 2.3-15 31 DEC 2019 2.3-16 31 DEC 2019 2.3-17 31 DEC 2019 2.3-18 31 DEC 2019 2.3-19 31 DEC 2019 2.3-20 31 DEC 2019 2.3-21 31 DEC 2019 2.3-22 31 DEC 2019 2.3-23 31 DEC 2019 2.3-34 31 DEC 2019 2.4-1 31 DEC 2019 2.4-2 31 DEC 2019 2.4-3 31 DEC 2019 2.4-4 31 DEC 2019 2.4-5 31 DEC 2019 2.4-6 31 DEC 2019 2.4-7 31 DEC 2019 2.4-8 31 DEC 2019 2.4-9 31 DEC 2019 2.4-10 31 DEC 2019 2.5-1 31 DEC 2019 2.5-2 31 DEC 2019 2.5-3 31 DEC 2019 2.5-4 31 DEC 2019 2.5-5 31 DEC 2019 2.5-6 31 DEC 2019 2.5-7 31 DEC 2019 2.5-8 31 DEC 2019 2.5-9 31 DEC 2019 2.5-10 31 DEC 2019 2.5-11 31 DEC 2019 2.5-12 31 DEC 2019 2.5-13 31 DEC 2019 2.5-14 31 DEC 2019 2.5-15 31 DEC 2019 2.5-16 31 DEC 2019 2.5-17 31 DEC 2019 2.5-18 31 DEC 2019 Page 3 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Chapter 2 Tables Table 2-1 (Page 1 of 1) 31 DEC 2000 Table 2-2 (Page 1 of 1) 31 DEC 2000 Table 2-3 (Page 1 of 1) 31 DEC 2000 Table 2-4 (Page 1 of 1) 31 DEC 2000 Table 2-5 (Page 1 of 1) 31 DEC 2000 Table 2-6 (Page 1 of 1) 31 DEC 2000 Table 2-7 (Page 1 of 1) 31 DEC 2008 Table 2-8 (Page 1 of 1) 31 DEC 2008 Table 2-9 (Page 1 of 1) 31 DEC 2008 Table 2-10 (Page 1 of 1) 31 DEC 2008 Table 2-11 (Page 1 of 1) 31 DEC 2008 Table 2-12 (Page 1 of 1) 31 DEC 2008 Table 2-13 (Page 1 of 1) 31 DEC 2008 Table 2-14 (Page 1 of 1) 31 DEC 2008 Table 2-15 (Page 1 of 1) 31 DEC 2008 Table 2-16 (Page 1 of 1) 31 DEC 2008 Table 2-17 (Page 1 of 1) 31 DEC 2008 Table 2-18 (Page 1 of 1) 31 DEC 2008 Table 2-19 (Page 1 of 1) 31 DEC 2008 Table 2-20 (Page 1 of 1) 31 DEC 2008 Table 2-21 (Page 1 of 1) 31 DEC 2008 Table 2-22 (Page 1 of 1) 31 DEC 2008 Table 2-23 (Page 1 of 1) 31 DEC 2008 Table 2-24 (Page 1 of 8) 31 DEC 2008 Table 2-24 (Page 2 of 8) 31 DEC 2008 Table 2-24 (Page 3 of 8) 31 DEC 2008 Table 2-24 (Page 4 of 8) 31 DEC 2008 Table 2-24 (Page 5 of 8) 31 DEC 2008 Table 2-24 (Page 6 of 8) 31 DEC 2008 Table 2-24 (Page 7 of 8) 31 DEC 2008 Table 2-24 (Page 8 of 8) 31 DEC 2008 Table 2-25 (Page 1 of 8) 31 DEC 2008 Table 2-25 (Page 2 of 8) 31 DEC 2008 Table 2-25 (Page 3 of 8) 31 DEC 2008 Table 2-25 (Page 4 of 8) 31 DEC 2008 Table 2-25 (Page 5 of 8) 31 DEC 2008 Table 2-25 (Page 6 of 8) 31 DEC 2008 Page 4 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 2-25 (Page 7 of 8) 31 DEC 2008 Table 2-25 (Page 8 of 8) 31 DEC 2008 Table 2-26 (Page 1 of 6) 31 DEC 2008 Table 2-26 (Page 2 of 6) 31 DEC 2008 Table 2-26 (Page 3 of 6) 31 DEC 2008 Table 2-26 (Page 4 of 6) 31 DEC 2008 Table 2-26 (Page 5 of 6) 31 DEC 2008 Table 2-26 (Page 6 of 6) 31 DEC 2008 Table 2-27 (Page 1 of 14) 31 DEC 2008 Table 2-27 (Page 2 of 14) 31 DEC 2008 Table 2-27 (Page 3 of 14) 31 DEC 2008 Table 2-27 (Page 4 of 14) 31 DEC 2008 Table 2-27 (Page 5 of 14) 31 DEC 2008 Table 2-27 (Page 6 of 14) 31 DEC 2008 Table 2-27 (Page 7 of 14) 31 DEC 2008 Table 2-27 (Page 8 of 14) 31 DEC 2008 Table 2-27 (Page 9 of 14) 31 DEC 2008 Table 2-27 (Page 10 of 14) 31 DEC 2008 Table 2-27 (Page 11 of 14) 31 DEC 2008 Table 2-27 (Page 12 of 14) 31 DEC 2008 Table 2-27 (Page 13 of 14) 31 DEC 2008 Table 2-27 (Page 14 of 14) 31 DEC 2008 Table 2-28 (Page 1 of 1) 31 DEC 2008 Table 2-29 (Page 1 of 1) 31 DEC 2008 Table 2-30 (Page 1 of 2) 31 DEC 2008 Table 2-30 (Page 2 of 2) 31 DEC 2008 Table 2-31 (Page 1 of 2) 31 DEC 2008 Table 2-31 (Page 2 of 2) 31 DEC 2008 Table 2-32 (Page 1 of 1) 31 DEC 2008 Table 2-33 (Page 1 of 2) 31 DEC 2008 Table 2-33 (Page 2 of 2) 31 DEC 2008 Table 2-34 (Page 1 of 1) 31 DEC 2008 Table 2-35 (Page 1 of 1) 31 DEC 2008 Table 2-36 (Page 1 of 1) 31 DEC 2008 Table 2-37 (Page 1 of 2) 31 DEC 2008 Table 2-27 (Page 2 of 2) 31 DEC 2008 Table 2-38 (Page 1 of 1) 31 DEC 2008 Table 2-39 (Page 1 of 4) 31 DEC 2008 Table 2-39 (Page 2 of 4) 31 DEC 2008 Page 5 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 2-39 (Page 3 of 4) 31 DEC 2008 Table 2-39 (Page 4 of 4) 31 DEC 2008 Table 2 2-43 (Page 1 of 31 DEC 2008 1)

Table 2-44 (Page 1 of 1) 31 DEC 2008 Table 2 2-92 (Page 1 of 31 DEC 2008 3)

Table 2 2-92 (Page 2 of 31 DEC 2008 3)

Table 2 2-92 (Page 3 of 31 DEC 2008 3)

Table 2-93 (Page 1 of 1) 31 DEC 2000 Table 2-94 (Page 1 of 6) 31 DEC 2000 Table 2-94 (Page 2 of 6) 31 DEC 2000 Table 2-94 (Page 3 of 6) 31 DEC 2000 Table 2-94 (Page 4 of 6) 31 DEC 2000 Table 2-94 (Page 5 of 6) 31 DEC 2000 Table 2-94 (Page 6 of 6) 31 DEC 2000 Table 2-95 (Page 1 of 1) 31 DEC 2000 Table 2-96 (Page 1 of 1) 31 DEC 2000 Chapter 2 Figures Figure 2-1 (Page 1 of 1) 31 DEC 2000 Figure 2-2 (Page 1 of 1) 31 DEC 2000 Figure 2-3 (Page 1 of 1) 31 DEC 2000 Figure 2-4 (Page 1 of 1) 31 DEC 2000 Figure 2-5 (Page 1 of 1) 31 DEC 2011 Figure 2-6 (Page 1 of 1) 31 DEC 2000 Figure 2-7 (Page 1 of 1) 31 DEC 2008 Figure 2-8 (Page 1 of 1) 31 DEC 2008 Figure 2-9 (Page 1 of 1) 31 DEC 2008 Figure 2-10 (Page 1 of 1) 31 DEC 2008 Figure 2-11 (Page 1 of 1) 31 DEC 2008 Figure 2-12 (Page 1 of 2) 31 DEC 2008 Figure 2-12 (Page 2 of 2) 31 DEC 2008 Figure 2-13 (Page 1 of 1) 31 DEC 2008 Figure 2-14 (Page 1 of 1) 31 DEC 2008 Figure 2-15 (Page 1 of 1) 31 DEC 2008 Figure 2-16 (Page 1 of 1) 31 DEC 2008 Figure 2-17 (Page 1 of 1) 31 DEC 2008 Figure 2-18 (Page 1 of 1) 31 DEC 2008 Page 6 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 2-19 (Page 1 of 1) 31 DEC 2008 Figure 2-20 (Page 1 of 1) 31 DEC 2008 Figure 2-21 (Page 1 of 1) 31 DEC 2008 Figure 2-22 (Page 1 of 1) 31 DEC 2008 Figure 2-23 (Page 1 of 1) 31 DEC 2008 Figure 2-24 (Page 1 of 1) 31 DEC 2008 Figure 2-25 (Page 1 of 1) 31 DEC 2008 Figure 2-26 (Page 1 of 1) 31 DEC 2008 Figure 2-27 (Page 1 of 1) 31 DEC 2008 Figure 2-28 (Page 1 of 1) 31 DEC 2008 Figure 2-29 (Page 1 of 1) 31 DEC 2008 Figure 2-30 (Page 1 of 1) 31 DEC 2008 Figure 2-31 (Page 1 of 1) 31 DEC 2008 Figure 2-32 (Page 1 of 1) 31 DEC 2008 Figure 2-33 (Page 1 of 1) 31 DEC 2008 Figure 2-34 (Page 1 of 1) 31 DEC 2008 Figure 2 2-36 (Page 1 of 31 DEC 2008 1)

Figure 2-37 (Page 1 of 1) 31 DEC 2008 Figure 2-38 (Page 1 of 1) 31 DEC 2008 Figure 2-39 (Page 1 of 1) 31 DEC 2000 Figure 2-40 (Page 1 of 1) 31 DEC 2000 Figure 2-41 (Page 1 of 1) 31 DEC 2000 Figure 2-42 (Page 1 of 1) 31 DEC 2000 Figure 2-43 (Page 1 of 1) 31 DEC 2000 Figure 2-44 (Page 1 of 1) 31 DEC 2000 Figure 2-45 (Page 1 of 1) 31 DEC 2000 Figure 2-46 (Page 1 of 1) 31 DEC 2000 Figure 2-47 (Page 1 of 1) 31 DEC 2000 Figure 2-48 (Page 1 of 1) 31 DEC 2000 Figure 2-49 (Page 1 of 1) 31 DEC 2000 Figure 2-50 (Page 1 of 1) 31 DEC 2000 Figure 2-51 (Page 1 of 1) 31 DEC 2000 Figure 2-52 (Page 1 of 1) 31 DEC 2000 Fiqure 2-53 (Page 1 of 1) 31 DEC 2000 Fiqure 2-54 (Page 1 of 1) 31 DEC 2000 Figure 2-55 (Page 1 of 1) 31 DEC 2000 Figure 2-56 (Page 1 of 1) 31 DEC 2000 Figure 2-57 (Page 1 of 1) 31 DEC 2000 Page 7 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 2-58 (Page 1 of 1) 31 DEC 2000 Figure 2-59 (Page 1 of 1) 31 DEC 2000 Figure 2-60 (Page 1 of 1) 31 DEC 2000 Fiqure 2-61 (Page 1 of 1) 31 DEC 2000 Figure 2-62 (Page 1 of 1) 31 DEC 2000 Figure 2-63 (Page 1 of 1) 31 DEC 2000 Figure 2-64 (Page 1 of 1) 31 DEC 2000 Figure 2-65 (Page 1 of 1) 31 DEC 2000 Figure 2-66 (Page 1 of 1) 31 DEC 2000 Figure 2-67 (Page 1 of 1) 31 DEC 2000 Figure 2-68 (Page 1 of 1) 31 DEC 2000 Figure 2-69 (Page 1 of 1) 31 DEC 2000 Figure 2-70 (Page 1 of 1) 31 DEC 2000 Figure 2-71 (Page 1 of 1) 31 DEC 2000 Figure 2-72 (Page 1 of 1) 31 DEC 2000 Figure 2-73 (Page 1 of 1) 31 DEC 2000 Figure 2-74 (Page 1 of 1) 31 DEC 2000 Figure 2-75 (Page 1 of 1) 31 DEC 2000 Figure 2-76 (Page 1 of 1) 31 DEC 2000 Figure 2-77 (Page 1 of 1) 31 DEC 2000 Figure 2-78 (Page 1 of 1) 31 DEC 2000 Figure 2-79 (Page 1 of 1) 31 DEC 2000 Figure 2-80 (Page 1 of 1) 31 DEC 2000 Figure 2-81 (Page 1 of 1) 31 DEC 2000 Figure 2-82 (Page 1 of 1) 31 DEC 2000 Figure 2-83 (Page 1 of 1) 31 DEC 2000 Figure 2-84 (Page 1 of 1) 31 DEC 2000 Figure 2-85 (Page 1 of 1) 31 DEC 2000 Figure 2-86 (Page 1 of 1) 31 DEC 2000 Figure 2-87 (Page 1 of 1) 31 DEC 2000 Figure 2-88 (Page 1 of 1) 31 DEC 2000 Figure 2-89 (Page 1 of 1) 31 DEC 2000 Figure 2-90 (Page 1 of 1) 31 DEC 2000 Figure 2-91 (Page 1 of 1) 31 DEC 2000 Figure 2-92 (Page 1 of 1) 31 DEC 2000 Figure 2-93 (Page 1 of 1) 31 DEC 2000 Figure 2-94 (Page 1 of 1) 31 DEC 2000 Figure 2-95 (Page 1 of 1) 31 DEC 2000 Figure 2-96 (Page 1 of 1) 31 DEC 2000 Page 8 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 2-97 (Page 1 of 1) 31 DEC 2000 Figure 2-98 (Page 1 of 1) 31 DEC 2000 Figure 2-99 (Page 1 of 1) 31 DEC 2000 Figure 2-100 (Page 1 of 1) 31 DEC 2000 Figure 2-101 (Page 1 of 1) 31 DEC 2000 Figure 2-102 (Page 1 of 1) 31 DEC 2000 Figure 2-103 (Page 1 of 1) 31 DEC 2000 Figure 2-104 (Page 1 of 1) 31 DEC 2000 Figure 2-105 (Page 1 of 1) 31 DEC 2000 Figure 2-106 (Page 1 of 1) 31 DEC 2000 Figure 2-107 (Page 1 of 1) 31 DEC 2000 Figure 2-108 (Page 1 of 1) 31 DEC 2000 Figure 2-109 (Page 1 of 1) 31 DEC 2000 Figure 2-110 (Page 1 of 1) 31 DEC 2000 Figure 2-111 (Page 1 of 1) 31 DEC 2000 Figure 2-112 (Page 1 of 1) 31 DEC 2000 Figure 2-113 (Page 1 of 1) 31 DEC 2000 Figure 2-114 (Page 1 of 1) 31 DEC 2000 Figure 2-115 (Page 1 of 1) 31 DEC 2000 Figure 2-116 (Page 1 of 1) 31 DEC 2000 Figure 2-117 (Page 1 of 1) 31 DEC 2000 Figure 2-118 (Page 1 of 1) 31 DEC 2000 Chapter 3 3-i 31 DEC 2019 3-ii 31 DEC 2019 3-iii 31 DEC 2019 3-iv 31 DEC 2019 3-v 31 DEC 2019 3-vi 31 DEC 2019 3-vii 31 DEC 2019 3-viii 31 DEC 2019 3-ix 31 DEC 2019 3-x 31 DEC 2019 3-xi 31 DEC 2019 3-xii 31 DEC 2019 3-xiii 31 DEC 2019 3-xiv 31 DEC 2019 3.0-1 31 DEC 2019 Page 9 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 3.0-2 31 DEC 2019 3.1-1 31 DEC 2019 3.1-2 31 DEC 2019 3.1-3 31 DEC 2019 3.1-4 31 DEC 2019 3.1-5 31 DEC 2019 3.1-6 31 DEC 2019 3.1-7 31 DEC 2019 3.1-8 31 DEC 2019 3.1-9 31 DEC 2019 3.1-10 31 DEC 2019 3.1-11 31 DEC 2019 3.1-12 31 DEC 2019 3.1-13 31 DEC 2019 3.1-14 31 DEC 2019 3.1-15 31 DEC 2019 3.1-16 31 DEC 2019 3.1-17 31 DEC 2019 3.1-18 31 DEC 2019 3.1-19 31 DEC 2019 3.1-20 31 DEC 2019 3.1-21 31 DEC 2019 3.1-22 31 DEC 2019 3.1-23 31 DEC 2019 3.1-24 31 DEC 2019 3.1-25 31 DEC 2019 3.1-26 31 DEC 2019 3.1-27 31 DEC 2019 3.1-28 31 DEC 2019 3.1-29 31 DEC 2019 3.1-30 31 DEC 2019 3.1-31 31 DEC 2019 3.1-32 31 DEC 2019 3.1-33 31 DEC 2019 3.1-34 31 DEC 2019 3.2-1 31 DEC 2019 3.2-2 31 DEC 2019 3.2-3 31 DEC 2019 3.2-4 31 DEC 2019 Page 10 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 3.2-5 31 DEC 2019 3.2-6 31 DEC 2019 3.2-7 31 DEC 2019 3.2-8 31 DEC 2019 3.3-1 31 DEC 2019 YES 3.3-2 31 DEC 2019 3.4-1 31 DEC 2019 YES 3.4-2 31 DEC 2019 YES 3.4-3 31 DEC 2019 YES 3.4-4 31 DEC 2019 YES 3.5-1 31 DEC 2019 3.5-2 31 DEC 2019 3.5-3 31 DEC 2019 3.5-4 31 DEC 2019 3.5-5 31 DEC 2019 3.5-6 31 DEC 2019 3.5-7 31 DEC 2019 YES 3.5-8 31 DEC 2019 3.6-1 31 DEC 2019 3.6-2 31 DEC 2019 3.7-1 31 DEC 2019 3.7-2 31 DEC 2019 3.7-3 31 DEC 2019 3.7-4 31 DEC 2019 3.7-5 31 DEC 2019 3.7-6 31 DEC 2019 3.7-7 31 DEC 2019 3.7-8 31 DEC 2019 3.7-9 31 DEC 2019 3.7-10 31 DEC 2019 3.7-11 31 DEC 2019 3.7-12 31 DEC 2019 3.7-13 31 DEC 2019 3.7-14 31 DEC 2019 3.7-15 31 DEC 2019 3.7-16 31 DEC 2019 3.8-1 31 DEC 2019 3.8-2 31 DEC 2019 3.8-3 31 DEC 2019 Page 11 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 3.8-4 31 DEC 2019 3.8-5 31 DEC 2019 3.8-6 31 DEC 2019 3.8-7 31 DEC 2019 3.8-8 31 DEC 2019 3.8-9 31 DEC 2019 3.8-10 31 DEC 2019 3.8-11 31 DEC 2019 3.8-12 31 DEC 2019 3.8-13 31 DEC 2019 3.8-14 31 DEC 2019 3.8-15 31 DEC 2019 3.8-16 31 DEC 2019 3.8-17 31 DEC 2019 3.8-18 31 DEC 2019 3.8-19 31 DEC 2019 3.8-20 31 DEC 2019 3.8-21 31 DEC 2019 3.8-22 31 DEC 2019 3.8-23 31 DEC 2019 3.8-24 31 DEC 2019 3.8-25 31 DEC 2019 3.8-26 31 DEC 2019 3.8-27 31 DEC 2019 3.8-28 31 DEC 2019 3.8-29 31 DEC 2019 3.8-30 31 DEC 2019 3.8-31 31 DEC 2019 3.8-32 31 DEC 2019 3.8-33 31 DEC 2019 3.8-34 31 DEC 2019 3.8-35 31 DEC 2019 3.8-36 31 DEC 2019 3.8-37 31 DEC 2019 3.8-38 31 DEC 2019 3.8-39 31 DEC 2019 3.8-40 31 DEC 2019 3.8-41 31 DEC 2019 3.8-42 31 DEC 2019 Page 12 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 3.8-43 31 DEC 2019 3.8-44 31 DEC 2019 3.8-45 31 DEC 2019 3.8-46 31 DEC 2019 3.8-47 31 DEC 2019 3.8-48 31 DEC 2019 3.8-49 31 DEC 2019 3.8-50 31 DEC 2019 3.8-51 31 DEC 2019 3.8-52 31 DEC 2019 3.8-53 31 DEC 2019 3.8-54 31 DEC 2019 3.8-55 31 DEC 2019 3.8-56 31 DEC 2019 3.8-57 31 DEC 2019 3.8-58 31 DEC 2019 3.8-59 31 DEC 2019 3.8-60 31 DEC 2019 3.8-61 31 DEC 2019 3.8-62 31 DEC 2019 3.8-63 31 DEC 2019 3.8-64 31 DEC 2019 3.8-65 31 DEC 2019 3.8-66 31 DEC 2019 3.8-67 31 DEC 2019 3.8-68 31 DEC 2019 3.8-69 31 DEC 2019 3.8-70 31 DEC 2019 3.8-71 31 DEC 2019 3.8-72 31 DEC 2019 3.8-73 31 DEC 2019 3.8-74 31 DEC 2019 3.8-75 31 DEC 2019 3.8-76 31 DEC 2019 3.9-1 31 DEC 2019 3.9-2 31 DEC 2019 3.9-3 31 DEC 2019 3.9-4 31 DEC 2019 3.9-5 31 DEC 2019 Page 13 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 3.9-6 31 DEC 2019 3.9-7 31 DEC 2019 3.9-8 31 DEC 2019 3.9-9 31 DEC 2019 3.9-10 31 DEC 2019 3.9-11 31 DEC 2019 3.9-12 31 DEC 2019 3.9-13 31 DEC 2019 3.9-14 31 DEC 2019 3.9-15 31 DEC 2019 3.9-16 31 DEC 2019 3.9-17 31 DEC 2019 3.9-18 31 DEC 2019 3.9-19 31 DEC 2019 3.9-20 31 DEC 2019 3.9-21 31 DEC 2019 3.9-22 31 DEC 2019 3.9-23 31 DEC 2019 3.9-24 31 DEC 2019 3.9-25 31 DEC 2019 3.9-26 31 DEC 2019 3.9-27 31 DEC 2019 3.9-28 31 DEC 2019 3.10-1 31 DEC 2019 3.10-2 31 DEC 2019 3.11-1 31 DEC 2019 YES 3.11-2 31 DEC 2019 3.12-1 31 DEC 2019 3.12-2 31 DEC 2019 3.13-1 31 DEC 2019 3.13-2 31 DEC 2019 Chapter 3 Tables Table 3-1 (Page 1 of 1) 31 DEC 2004 Table 3-2 (Page 1 of 6) 31 DEC 2014 Table 3-2 (Page 2 of 6) 31 DEC 2014 Table 3-2 (Page 3 of 6) 31 DEC 2014 Table 3-2 (Page 4 of 6) 31 DEC 2014 Table 3-2 (Page 5 of 6) 31 DEC 2014 Page 14 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 3-2 (Page 6 of 6) 31 DEC 2014 Table 3-3 (Page 1 of 1) 31 DEC 2004 Table 3-4 (Page 1 of 1) 31 DEC 2000 Table 3-5 (Page 1 of 1) 31 DEC 2014 Table 3-6 (Page 1 of 2) 31 DEC 2003 Table 3-6 (Page 2 of 2) 31 DEC 2003 Table 3-7 (Page 1 of 1) 31 DEC 2000 Table 3-8 (Page 1 of 1) 31 DEC 2000 Table 3-9 (Page 1 of 2) 31 DEC 2000 Table 3-9 (Page 2 of 2) 31 DEC 2000 Table 3-10 (Page 1 of 1) 31 DEC 2000 Table 3-11 (Page 1 of 1) 31 DEC 2000 Table 3-12 (Page 1 of 5) 31 DEC 2000 Table 3-12 (Page 2 of 5) 31 DEC 2000 Table 3-12 (Page 3 of 5) 31 DEC 2000 Table 3-12 (Page 4 of 5) 31 DEC 2000 Table 3-12 (Page 5 of 5) 31 DEC 2000 Table 3-13 (Page 1 of 1) 31 DEC 2000 Table 3-14 (Page 1 of 2 31 DEC 2000 Table 3-14 (Page 2 of 2) 31 DEC 2000 Table 3-15 (Page 1 of 1) 31 DEC 2000 Table 3-16 (Page 1 of 1) 31 DEC 2003 Table 3-17 (Page 1 of 1) 31 DEC 2000 Table 3-18 (Page 1 of 1) 31 DEC 2003 Table 3-19 (Page 1 of 1) 31 DEC 2003 Table 3-20 (Page 1 of 1) 31 DEC 2003 Table 3-21 (Page 1 of 1) 31 DEC 2003 Table 3-22 (Page 1 of 1) 31 DEC 2000 Table 3-23 (Page 1 of 1) 31 DEC 2009 Table 3-24 (Page 1 of 1) 31 DEC 2000 Table 3-25 (Page 1 of 1) 31 DEC 2000 Table 3-26 (Page 1 of 1) 31 DEC 2000 Table 3 3-67 (Page 1 of 31 DEC 2000 3)

Table 3 3-67 (Page 2 of 31 DEC 2000 3)

Table 3 3-67 (Page 3 of 31 DEC 2000 3)

Table 3-68 (Page 1 of 8) 31 DEC 2019 Table 3-68 (Page 2 of 8) 31 DEC 2019 Page 15 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 3-68 (Page 3 of 8) 31 DEC 2019 Table 3-68 (Page 4 of 8) 31 DEC 2019 YES Table 3-68 (Page 5 of 8) 31 DEC 2019 YES Table 3-68 (Page 6 of 8) 31 DEC 2019 Table 3-68 (Page 7 of 8) 31 DEC 2019 Table 3-68 (Page 8 of 8) 31 DEC 2019 Chapter 3 Figures Figure 3-1 (Page 1 of 1) 31 DEC 2000 Figure 3-2 (Page 1 of 1) 31 DEC 2000 Figure 3-3 (Page 1 of 1) 31 DEC 2000 Figure 3-4 (Page 1 of 1) 31 DEC 2000 Figure 3-5 (Page 1 of 1) 31 DEC 2000 Figure 3-6 (Page 1 of 1) 31 DEC 2000 Figure 3-7 (Page 1 of 1) 31 DEC 2000 Figure 3-8 (Page 1 of 1) 31 DEC 2000 Figure 3-9 (Page 1 of 1) 31 DEC 2006 Figure 3-10 (Page 1 of 1) 31 DEC 2006 Figure 3-11 (Page 1 of 1) 31 DEC 2006 Figure 3-12 (Page 1 of 1) 31 DEC 2006 Figure 3-13 (Page 1 of 1) 31 DEC 2006 Figure 3-14 (Page 1 of 1) 31 DEC 2006 Figure 3-15 (Page 1 of 1) 31 DEC 2006 Figure 3-16 (Page 1 of 1) 31 DEC 2000 Figure 3-17 (Page 1 of 1) 31 DEC 2000 Figure 3-18 (Page 1 of 1) 31 DEC 2000 Figure 3-19 (Page 1 of 3) 31 DEC 2000 Figure 3-19 (Page 2 of 3) 31 DEC 2000 Figure 3-19 (Page 3 of 3) 31 DEC 2000 Figure 3-20 (Page 1 of 1) 31 DEC 2011 Figure 3-21 (Page 1 of 1) 31 DEC 2000 Figure 3-22 (Page 1 of 1) 31 DEC 2000 Figure 3-23 (Page 1 of 1) 31 DEC 2000 Figure 3-24 (Page 1 of 1) 31 DEC 2000 Figure 3-25 (Page 1 of 4) 31 DEC 2000 Figure 3-25 (Page 2 of 4) 31 DEC 2000 Figure 3-25 (Page 3 of 4) 31 DEC 2000 Figure 3-25 (Page 4 of 4) 31 DEC 2000 Figure 3-26 (Page 1 of 6) 31 DEC 2000 Page 16 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 3-26 (Page 2 of 6) 31 DEC 2000 Figure 3-26 (Page 3 of 6) 31 DEC 2000 Figure 3-26 (Page 4 of 6) 31 DEC 2000 Figure 3-26 (Page 5 of 6) 31 DEC 2000 Figure 3-26 (Page 6 of 6) 31 DEC 2000 Figure 3-27 (Page 1 of 1) 31 DEC 2000 Figure 3-28 (Page 1 of 2) 31 DEC 2000 Figure 3-28 (Page 2 of 2) 31 DEC 2000 Figure 3-29 (Page 1 of 1) 31 DEC 2000 Figure 3-30 (Page 1 of 1) 31 DEC 2000 Figure 3-31 (Page 1 of 1) 31 DEC 2000 Figure 3-32 (Page 1 of 1) 31 DEC 2000 Figure 3-33 (Page 1 of 1) 31 DEC 2000 Figure 3-34 (Page 1 of 1) 31 DEC 2000 Figure 3-35 (Page 1 of 1) 31 DEC 2000 Figure 3-36 (Page 1 of 1) 31 DEC 2000 Figure 3-37 (Page 1 of 4) 31 DEC 2000 Figure 3-37 (Page 2 of 4) 31 DEC 2000 Figure 3-37 (Page 3 of 4) 31 DEC 2000 Figure 3-37 (Page 4 of 4) 31 DEC 2000 Figure 3-38 (Page 1 of 1) 31 DEC 2000 Figure 3 3-51 (Page 1 of 31 DEC 2000 1)

Figure 3-52 (Page 1 of 1) 31 DEC 2003 Fiqure 3 3-56 (Page 1 of 31 DEC 2003 1)

Figure 3-57 (Page 1 of 1) 31 DEC 2000 Figure 3-58 (Page 1 of 1) 31 DEC 2000 Figure 3-59 (Page 1 of 1) 31 DEC 2000 Figure 3-60 (Page 1 of 1) 31 DEC 2000 Chapter 4 4-i 31 DEC 2019 4-ii 31 DEC 2019 4-iii 31 DEC 2019 4-iv 31 DEC 2019 4-v 31 DEC 2019 4-vi 31 DEC 2019 4-vii 31 DEC 2019 4-viii 31 DEC 2019 Page 17 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 4.0-1 31 DEC 2019 4.0-2 31 DEC 2019 4.1-1 31 DEC 2019 4.1-2 31 DEC 2019 4.2-1 31 DEC 2019 4.2-2 31 DEC 2019 4.2-3 31 DEC 2019 YES 4.2-4 31 DEC 2019 4.2-5 31 DEC 2019 4.2-6 31 DEC 2019 4.2-7 31 DEC 2019 4.2-8 31 DEC 2019 4.2-9 31 DEC 2019 4.2-10 31 DEC 2019 4.2-11 31 DEC 2019 4.2-12 31 DEC 2019 4.2-13 31 DEC 2019 YES 4.2-14 31 DEC 2019 4.3-1 31 DEC 2019 4.3-2 31 DEC 2019 4.3-3 31 DEC 2019 4.3-4 31 DEC 2019 4.3-5 31 DEC 2019 4.3-6 31 DEC 2019 4.3-7 31 DEC 2019 4.3-8 31 DEC 2019 4.3-9 31 DEC 2019 4.3-10 31 DEC 2019 4.3-11 31 DEC 2019 4.3-12 31 DEC 2019 4.3-13 31 DEC 2019 4.3-14 31 DEC 2019 4.3-15 31 DEC 2019 4.3-16 31 DEC 2019 4.3-17 31 DEC 2019 4.3-18 31 DEC 2019 4.3-19 31 DEC 2019 4.3-20 31 DEC 2019 4.3-21 31 DEC 2019 Page 18 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 4.3-22 31 DEC 2019 4.4-1 31 DEC 2019 YES 4.4-2 31 DEC 2019 YES 4.4-3 31 DEC 2019 4.4-4 31 DEC 2019 YES 4.4-5 31 DEC 2019 4.4-6 31 DEC 2019 YES 4.4-7 31 DEC 2019 YES 4.4-8 31 DEC 2019 YES 4.5-1 31 DEC 2019 4.5-2 31 DEC 2019 YES 4.5-3 31 DEC 2019 4.5-4 31 DEC 2019 4.5-5 31 DEC 2019 4.5-6 31 DEC 2019 4.5-7 31 DEC 2019 4.5-8 31 DEC 2019 4.5-9 31 DEC 2019 4.5-10 31 DEC 2019 4.5-11 31 DEC 2019 4.5-12 31 DEC 2019 4.5-13 31 DEC 2019 4.5-14 31 DEC 2019 4.5-15 31 DEC 2019 4.5-16 31 DEC 2019 4.5-17 31 DEC 2019 4.5-18 31 DEC 2019 4.5-19 31 DEC 2019 4.5-20 31 DEC 2019 Chapter 4 Tables Table 4-1 (Page 1 of 5) 31 DEC 2009 Table 4-1 (Page 2 of 5) 31 DEC 2009 Table 4-1 (Page 3 of 5) 31 DEC 2009 Table 4-1 (Page 4 of 5) 31 DEC 2009 Table 4-1 (Page 5 of 5) 31 DEC 2009 Table 4-2 (Page 1 of 2) 31 DEC 2009 Table 4-2 (Page 2 of 2) 31 DEC 2009 Table 4-3 (Page 1 of 2) 31 DEC 2012 Page 19 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 4-3 (Page 2 of 2) 31 DEC 2012 Table 4-4 (Page 1 of 1) 31 DEC 2012 Table 4-5 (Page 1 of 1) 31 DEC 2000 Table 4-6 (Page 1 of 1) 31 DEC 2012 Table 4-7 (Page 1 of 1) 31 DEC 2009 Table 4-8 (Page 1 of 1) 31 DEC 2000 Table 4-9 (Page 1 of 1) 31 DEC 2012 Table 4-10 (Page 1 of 1) 31 DEC 2012 Table 4-11 (Page 1 of 1) 31 DEC 2012 Table 4-12 (Page 1 of 1) 31 DEC 2000 Table 4-13 (Page 1 of 1) 31 DEC 2000 Table 4-14 (Page 1 of 1) 31 DEC 2000 Table 4-15 (Page 1 of 1) 31 DEC 2000 Table 4-16 (Page 1 of 1) 31 DEC 2000 Table 4-17 (Page 1 of 2) 31 DEC 2000 Table 4-17 (Page 2 of 2) 31 DEC 2000 Table 4-18 (Page 1 of 1) 31 DEC 2000 Table 4-19 (Page 1 of 1) 31 DEC 2000 Table 4-20 (Page 1 of 1) 31 DEC 2012 Table 4-21 (Page 1 of 1) 31 DEC 2000 Table 4-22 (Page 1 of 1) 31 DEC 2013 Table 4-23 (Page 1 of 1) 31 DEC 2009 Table 4-24 (Page 1 of 1) 31 DEC 2013 Chapter 4 Figures Figure 4-1 (Page 1 of 1) 31 DEC 2000 Figure 4 4-3 (Page 1 of 1) 31 DEC 2000 Figure 4-4 (Page 1 of 1) 31 DEC 2000 Figure 4-5 (Page 1 of 1) 31 DEC 2012 Figure 4-6 (Page 1 of 1) 31 DEC 2012 Figure 4-7 (Page 1 of 1) 31 DEC 2000 Figure 4-8 (Page 1 of 1) 31 DEC 2000 Figure 4-9 (Page 1 of 1) 31 DEC 2000 Figure 4-10 (Page 1 of 1) 31 DEC 2000 Figure 4-11 (Page 1 of 1) 31 DEC 2000 Figure 4-12 (Page 1 of 1) 31 DEC 2000 Figure 4-13 (Page 1 of 1) 31 DEC 2000 Figure 4-14 (Page 1 of 1) 31 DEC 2000 Figure 4-15 (Page 1 of 1) 31 DEC 2000 Page 20 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 4-16 (Page 1 of 1) 31 DEC 2000 Figure 4-17 (Page 1 of 1) 31 DEC 2000 Figure 4-18 (Page 1 of 1) 31 DEC 2000 Figure 4 4-20 (Page 1 of 31 DEC 2000 1)

Figure 4-21 (Page 1 of 1) 31 DEC 2000 Figure 4-22 (Page 1 of 1) 31 DEC 2000 Figure 4-23 (Page 1 of 1) 31 DEC 2000 Figure 4-24 (Page 1 of 1) 31 DEC 2000 Figure 4-25 (Page 1 of 1) 31 DEC 2000 Figure 4-26 (Page 1 of 1) 31 DEC 2000 Figure 4-27 (Page 1 of 1) 31 DEC 2000 Figure 4-28 (Page 1 of 1) 31 DEC 2000 Figure 4-29 (Page 1 of 1) 31 DEC 2000 Figure 4-30 (Page 1 of 1) 31 DEC 2000 Figure 4-31 (Page 1 of 1) 31 DEC 2000 Figure 4-32 (Page 1 of 1) 31 DEC 2000 Figure 4-33 (Page 1 of 1) 31 DEC 2000 Figure 4-34 (Page 1 of 1) 31 DEC 2000 Figure 4 4-36 (Page 1 of 31 DEC 2000 1)

Figure 4-37 (Page 1 of 1) 31 DEC 2000 Figure 4-38 (Page 1 of 1) 31 DEC 2004 Chapter 5 5-i 31 DEC 2019 5-ii 31 DEC 2019 5-iii 31 DEC 2019 5-iv 31 DEC 2019 5-v 31 DEC 2019 5-vi 31 DEC 2019 5-vii 31 DEC 2019 5-viii 31 DEC 2019 5.0-1 31 DEC 2019 5.0-2 31 DEC 2019 5.1-1 31 DEC 2019 5.1-2 31 DEC 2019 5.1-3 31 DEC 2019 5.1-4 31 DEC 2019 5.1-5 31 DEC 2019 YES Page 21 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 5.1-6 31 DEC 2019 5.2-1 31 DEC 2019 5.2-2 31 DEC 2019 5.2-3 31 DEC 2019 5.2-4 31 DEC 2019 5.2-5 31 DEC 2019 5.2-6 31 DEC 2019 5.2-7 31 DEC 2019 5.2-8 31 DEC 2019 5.2-9 31 DEC 2019 5.2-10 31 DEC 2019 5.2-11 31 DEC 2019 5.2-12 31 DEC 2019 5.2-13 31 DEC 2019 5.2-14 31 DEC 2019 5.2-15 31 DEC 2019 5.2-16 31 DEC 2019 5.2-17 31 DEC 2019 5.2-18 31 DEC 2019 5.2-19 31 DEC 2019 5.2-20 31 DEC 2019 5.2-21 31 DEC 2019 5.2-22 31 DEC 2019 5.2-23 31 DEC 2019 YES 5.2-24 31 DEC 2019 5.2-25 31 DEC 2019 5.2-26 31 DEC 2019 5.2-27 31 DEC 2019 5.2-28 31 DEC 2019 5.2-29 31 DEC 2019 5.2-30 31 DEC 2019 5.2-31 31 DEC 2019 5.2-32 31 DEC 2019 5.2-33 31 DEC 2019 5.2-34 31 DEC 2019 5.2-35 31 DEC 2019 5.2-36 31 DEC 2019 5.2-37 31 DEC 2019 5.2-38 31 DEC 2019 Page 22 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 5.2-39 31 DEC 2019 5.2-40 31 DEC 2019 5.2-41 31 DEC 2019 5.2-42 31 DEC 2019 5.2-43 31 DEC 2019 5.2-44 31 DEC 2019 5.3-1 31 DEC 2019 5.3-2 31 DEC 2019 5.3-3 31 DEC 2019 5.3-4 31 DEC 2019 5.4-1 31 DEC 2019 5.4-2 31 DEC 2019 5.4-3 31 DEC 2019 5.4-4 31 DEC 2019 5.4-5 31 DEC 2019 5.4-6 31 DEC 2019 5.4-7 31 DEC 2019 5.4-8 31 DEC 2019 5.4-9 31 DEC 2019 5.4-10 31 DEC 2019 5.4-11 31 DEC 2019 5.4-12 31 DEC 2019 5.4-13 31 DEC 2019 5.4-14 31 DEC 2019 5.4-15 31 DEC 2019 5.4-16 31 DEC 2019 5.4-17 31 DEC 2019 5.4-18 31 DEC 2019 5.4-19 31 DEC 2019 5.4-20 31 DEC 2019 5.4-21 31 DEC 2019 5.4-22 31 DEC 2019 Chapter 5 Tables Table 5-1 (Page 1 of 1) 31 DEC 2000 Table 5-2 (Page 1 of 3) 31 DEC 2004 Table 5-2 (Page 2 of 3) 31 DEC 2004 Table 5-2 (Page 3 of 3) 31 DEC 2004 Table 5-3 (Page 1 of 1) 31 DEC 2010 Page 23 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 5-4 (Page 1 of 1) 31 DEC 2004 Table 5-5 (Page 1 of 2) 31 DEC 2019 Table 5-5 (Page 2 of 2) 31 DEC 2019 YES Table 5-6 (Page 1 of 1) 31 DEC 2000 Table 5-7 (Page 1 of 1) 31 DEC 2000 Table 5-8 (Page 1 of 1) 31 DEC 2004 Table 5-9 (Page 1 of 1) 31 DEC 2004 Table 5-10 (Page 1 of 5) 31 DEC 2004 Table 5-10 (Page 2 of 5) 31 DEC 2004 Table 5-10 (Page 3 of 5) 31 DEC 2004 Table 5-10 (Page 4 of 5) 31 DEC 2004 Table 5-10 (Page 5 of 5) 31 DEC 2004 Table 5-11 (Page 1 of 2) 31 DEC 2003 Table 5-11 (Page 2 of 2) 31 DEC 2003 Table 5-12 (Page 1 of 2) 31 DEC 2003 Table 5-12 (Page 2 of 2) 31 DEC 2003 Table 5-13 (Page 1 of 1) 31 DEC 2003 Table 5-14 (Page 1 of 2) 31 DEC 2000 Table 5-14 (Page 2 of 2) 31 DEC 2000 Table 5-15 (Page 1 of 1) 31 DEC 2004 Table 5-16 (Page 1 of 1) 31 DEC 2011 Table 5-17 (Page 1 of 1) 31 DEC 2001 Table 5-18 (Page 1 of 3) 31 DEC 2000 Table 5-18 (Page 2 of 3) 31 DEC 2000 Table 5-18 (Page 3 of 3) 31 DEC 2000 Table 5-19 (Page 1 of 1) 31 DEC 2000 Table 5-20 (Page 1 of 3) 31 DEC 2004 Table 5-20 (Page 2 of 3) 31 DEC 2004 Table 5-20 (Page 3 of 3) 31 DEC 2004 Table 5-21 (Page 1 of 2) 31 DEC 2004 Table 5-21 (Page 2 of 2) 31 DEC 2004 Table 5-22 (Page 1 of 1) 31 DEC 2006 Table 5-23 (Page 1 of 3) 31 DEC 2000 Table 5-23 (Page 2 of 3) 31 DEC 2000 Table 5-23 (Page 3 of 3) 31 DEC 2000 Table 5-24 (Page 1 of 2) 31 DEC 2000 Table 5-24 (Page 2 of 2) 31 DEC 2000 Table 5-25 (Page 1 of 1) 31 DEC 2000 Table 5-26 (Page 1 of 2) 31 DEC 2000 Page 24 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 5-26 (Page 2 of 2) 31 DEC 2000 Table 5-27 (Page 1 of 2) 31 DEC 2000 Table 5-27 (Page 2 of 2) 31 DEC 2000 Table 5-28 (Page 1 of 1) 31 DEC 2000 Table 5-29 (Page 1 of 1) 31 DEC 2000 Chapter 5 Figures Figure 5-1 (Page 1 of 1) 31 DEC 2000 Figure 5-2 (Page 1 of 1) 31 DEC 2000 Figure 5-3 (Page 1 of 1) 31 DEC 2000 Figure 5-4 (Page 1 of 1) 31 DEC 2000 Figure 5-5 (Page 1 of 1) 31 DEC 2004 Figure 5-6 (Page 1 of 1) 31 DEC 2017 Figure 5-7 (Page 1 of 1) 31 DEC 2004 Figure 5-8 (Page 1 of 1) 31 DEC 2004 Figure 5-9 (Page 1 of 1) 31 DEC 2004 Figure 5-10 (Page 1 of 1) 31 DEC 2000 Figure 5-11 (Page 1 of 1) 31 DEC 2004 Figure 5-12 (Page 1 of 1) 31 DEC 2000 Figure 5-13 (Page 1 of 1) 31 DEC 2000 Figure 5-14 (Page 1 of 1) 31 DEC 2003 Figure 5-15 (Page 1 of 1) 31 DEC 2003 Figure 5-16 (Page 1 of 1) 31 DEC 2003 Figure 5-17 (Page 1 of 1) 31 DEC 2019 YES Figure 5-18 (Page 1 of 1) 31 DEC 2000 Figure 5-19 (Page 1 of 1) 31 DEC 2000 Figure 5-20 (Page 1 of 1) 31 DEC 2000 Figure 5-21 (Page 1 of 4) 31 DEC 2004 Figure 5-21 (Page 2 of 4) 31 DEC 2004 Figure 5-21 (Page 3 of 4) 31 DEC 2004 Figure 5-21 (Page 4 of 4) 31 DEC 2004 Figure 5-22 (Page 1 of 1) 31 DEC 2004 Figure 5-22 (Page 2 of 4) 31 DEC 2004 Figure 5-22 (Page 3 of 4) 31 DEC 2004 Figure 5-22 (Page 4 of 4) 31 DEC 2004 Figure 5-23 (Page 1 of 1) 31 DEC 2000 Figure 5-24 (Page 1 of 1) 31 DEC 2000 Figure 5-25 (Page 1 of 1) 31 DEC 2004 Figure 5-26 (Page 1 of 1) 31 DEC 2004 Page 25 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 5-27 (Page 1 of 1) 31 DEC 2000 Figure 5-28 (Page 1 of 1) 31 DEC 2000 Figure 5-29 (Page 1 of 1) 31 DEC 2008 Figure 5-30 (Page 1 of 1) 31 DEC 2003 Figure 5-31 (Page 1 of 1) 31 DEC 2003 Figure 5-32 (Page 1 of 1) 31 DEC 2003 Figure 5-33 (Page 1 of 1) 31 DEC 2003 Chapter 6 6-i 31 DEC 2019 6-ii 31 DEC 2019 6-iii 31 DEC 2019 6-iv 31 DEC 2019 6-v 31 DEC 2019 6-vi 31 DEC 2019 6-vii 31 DEC 2019 6-viii 31 DEC 2019 6-ix 31 DEC 2019 6-x 31 DEC 2019 6.0-1 31 DEC 2019 6.0-2 31 DEC 2019 6.1-1 31 DEC 2019 6.1-2 31 DEC 2019 6.1-3 31 DEC 2019 6.1-4 31 DEC 2019 6.1-5 31 DEC 2019 6.1-6 31 DEC 2019 6.2-1 31 DEC 2019 6.2-2 31 DEC 2019 6.2-3 31 DEC 2019 6.2-4 31 DEC 2019 6.2-5 31 DEC 2019 6.2-6 31 DEC 2019 6.2-7 31 DEC 2019 6.2-8 31 DEC 2019 6.2-9 31 DEC 2019 6.2-10 31 DEC 2019 6.2-11 31 DEC 2019 6.2-12 31 DEC 2019 Page 26 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 6.2-13 31 DEC 2019 6.2-14 31 DEC 2019 6.2-15 31 DEC 2019 6.2-16 31 DEC 2019 6.2-17 31 DEC 2019 6.2-18 31 DEC 2019 6.2-19 31 DEC 2019 6.2-20 31 DEC 2019 6.2-21 31 DEC 2019 6.2-22 31 DEC 2019 6.2-23 31 DEC 2019 YES 6.2-24 31 DEC 2019 6.3-1 31 DEC 2019 6.3-2 31 DEC 2019 6.3-3 31 DEC 2019 6.3-4 31 DEC 2019 6.3-5 31 DEC 2019 6.3-6 31 DEC 2019 6.3-7 31 DEC 2019 6.3-8 31 DEC 2019 6.3-9 31 DEC 2019 6.3-10 31 DEC 2019 6.3-11 31 DEC 2019 6.3-12 31 DEC 2019 6.3-13 31 DEC 2019 6.3-14 31 DEC 2019 6.3-15 31 DEC 2019 6.3-16 31 DEC 2019 YES 6.3-17 31 DEC 2019 6.3-18 31 DEC 2019 6.4-1 31 DEC 2019 6.4-2 31 DEC 2019 YES 6.4-3 31 DEC 2019 6.4-4 31 DEC 2019 6.5-1 31 DEC 2019 6.5-2 31 DEC 2019 6.5-3 31 DEC 2019 6.5-4 31 DEC 2019 6.6-1 31 DEC 2019 Page 27 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 6.6-2 31 DEC 2019 Chapter 6 Tables Table 6-1 (Page 1 of 1) 31 DEC 2000 Table 6-2 (Page 1 of 1) 31 DEC 2000 Table 6-3 (Page 1 of 2) 31 DEC 2000 Table 6-3 (Page 2 of 2) 31 DEC 2000 Table 6-4 (Page 1 of 2) 31 DEC 2016 Table 6-4 (Page 2 of 2) 31 DEC 2016 Table 6-5 (Page 1 of 1) 31 DEC 2000 Table 6-6 (Page 1 of 1) 31 DEC 2000 Table 6-7 (Page 1 of 7) 31 DEC 2014 Table 6-7 (Page 2 of 7) 31 DEC 2014 Table 6-7 (Page 3 of 7) 31 DEC 2014 Table 6-7 (Page 4 of 7) 31 DEC 2014 Table 6-7 (Page 5 of 7) 31 DEC 2014 Table 6-7 (Page 6 of 7) 31 DEC 2014 Table 6-7 (Page 7 of 7) 31 DEC 2014 Table 6-8 (Page 1 of 2) 31 DEC 2005 Table 6-8 (Page 2 of 2) 31 DEC 2005 Table 6-9 (Page 1 of 1) 31 DEC 2009 Table 6-10 (Page 1 of 1) 31 DEC 2000 Table 6-11 (Page 1 of 2) 31 DEC 2005 Table 6-11 (Page 2 of 2) 31 DEC 2005 Table 6-12 (Page 1 of 1) 31 DEC 2000 Table 6-13 (Page 1 of 1) 31 DEC 2000 Table 6-14 (Page 1 of 2) 31 DEC 2000 Table 6-14 (Page 2 of 2) 31 DEC 2000 Table 6-15 (Page 1 of 1) 31 DEC 2005 Table 6 6-17 (Page 1 of 31 DEC 2000 1)

Table 6-18 (Page 1 of 1) 31 DEC 2000 Table 6-19 (Page 1 of 1) 31 DEC 2015 Table 6-20 (Page 1 of 1) 31 DEC 2000 Table 6-21 (Page 1 of 1) 31 DEC 2003 Table 6-22 (Page 1 of 1) 31 DEC 2017 Table 6-23 (Page 1 of 1) 31 DEC 2013 Table 6-24 (Page 1 of 1) 31 DEC 2017 Table 6-25 (Page 1 of 1) 31 DEC 2017 Page 28 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 6-26 (Page 1 of 2) 31 DEC 2013 Table 6-26 (Page 2 of 2) 31 DEC 2013 Table 6-27 (Page 1 of 1) 31 DEC 2008 Table 6-28 (Page 1 of 1) 31 DEC 2000 Table 6-29 (Page 1 of 15) 31 DEC 2003 Table 6-29 (Page 2 of 15) 31 DEC 2003 Table 6-29 (Page 3 of 15) 31 DEC 2003 Table 6-29 (Page 4 of 15) 31 DEC 2003 Table 6-29 (Page 5 of 15) 31 DEC 2003 Table 6-29 (Page 6 of 15) 31 DEC 2003 Table 6-29 (Page 7 of 15) 31 DEC 2003 Table 6-29 (Page 8 of 15 31 DEC 2003 Table 6-29 (Page 9 of 15) 31 DEC 2003 Table 6-29 (Page 10 of 15) 31 DEC 2003 Table 6-29 (Page 11 of 15) 31 DEC 2003 Table 6-29 (Page 12 of 15) 31 DEC 2003 Table 6-29 (Page 13 of 15) 31 DEC 2003 Table 6-29 (Page 14 of 15) 31 DEC 2003 Table 6-29 (Page 15 of 15) 31 DEC 2003 Table 6-30 (Page 1 of 40) 31 DEC 2003 Table 6-30 (Page 2 of 40) 31 DEC 2003 Table 6-30 (Page 3 of 10) 31 DEC 2003 Table 6-30 (Page 4 of 40) 31 DEC 2003 Table 6-30 (Page 5 of 40) 31 DEC 2003 Table 6-30 (Page 6 of 40) 31 DEC 2003 Table 6-30 (Page 7 of 40) 31 DEC 2003 Table 6-30 (Page 8 of 40) 31 DEC 2003 Table 6-30 (Page 9 of 40) 31 DEC 2003 Table 6-30 (Page 10 of 40) 31 DEC 2003 Table 6-30 (Page 11 of 40) 31 DEC 2003 Table 6-30 (Page 12 of 40) 31 DEC 2003 Table 6-30 (Page 13 of 10) 31 DEC 2003 Table 6-30 (Page 14 of 40) 31 DEC 2003 Table 6-30 (Page 15 of 40) 31 DEC 2003 Table 6-30 (Page 16 of 40) 31 DEC 2003 Table 6-30 (Page 17 of 40) 31 DEC 2003 Table 6-30 (Page 18 of 40) 31 DEC 2003 Table 6-30 (Page 19 of 40) 31 DEC 2003 Table 6-30 (Page 20 of 40) 31 DEC 2003 Page 29 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 6-30 (Page 21 of 40) 31 DEC 2003 Table 6-30 (Page 22 of 40) 31 DEC 2003 Table 6-30 (Page 23 of 10) 31 DEC 2003 Table 6-30 (Page 24 of 40) 31 DEC 2003 Table 6-30 (Page 25 of 40) 31 DEC 2003 Table 6-30 (Page 26 of 40) 31 DEC 2003 Table 6-30 (Page 27 of 40) 31 DEC 2003 Table 6-30 (Page 28 of 40) 31 DEC 2003 Table 6-30 (Page 29 of 40) 31 DEC 2003 Table 6-30 (Page 30 of 40) 31 DEC 2003 Table 6-30 (Page 31 of 40) 31 DEC 2003 Table 6-30 (Page 32 of 40) 31 DEC 2003 Table 6-30 (Page 33 of 10) 31 DEC 2003 Table 6-30 (Page 34 of 40) 31 DEC 2003 Table 6-30 (Page 35 of 40) 31 DEC 2003 Table 6-30 (Page 36 of 40) 31 DEC 2003 Table 6-30 (Page 37 of 40) 31 DEC 2003 Table 6-30 (Page 38 of 40) 31 DEC 2003 Table 6-30 (Page 39 of 40) 31 DEC 2003 Table 6-30 (Page 40 of 40) 31 DEC 2003 Table 6-31 (Page 1 of 2) 31 DEC 2017 Table 6-31 (Page 2 of 2) 31 DEC 2017 Table 6-32 (Page 1 of 5) 31 DEC 2003 Table 6-32 (Page 2 of 5) 31 DEC 2003 Table 6-32 (Page 3 of 5) 31 DEC 2003 Table 6-32 (Page 4 of 5) 31 DEC 2003 Table 6-32 (Page 5 of 5) 31 DEC 2003 Table 6-33 (Page 1 of 1) 31 DEC 2005 Table 6-34 (Page 1 of 1) 31 DEC 2008 Table 6-35 (Page 1 of 18) 31 DEC 2003 Table 6-35 (Page 2 of 18) 31 DEC 2003 Table 6-35 (Page 3 of 18) 31 DEC 2003 Table 6-35 (Page 4 of 18) 31 DEC 2003 Table 6-35 (Page 5 of 18) 31 DEC 2003 Table 6-35 (Page 6 of 18) 31 DEC 2003 Table 6-35 (Page 7 of 18) 31 DEC 2003 Table 6-35 (Page 8 of 18) 31 DEC 2003 Table 6-35 (Page 9 of 18) 31 DEC 2003 Table 6-35 (Page 10 of 18) 31 DEC 2003 Page 30 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 6-35 (Page 11 of 18) 31 DEC 2003 Table 6-35 (Page 12 of 18) 31 DEC 2003 Table 6-35 (Page 13 of 18) 31 DEC 2003 Table 6-35 (Page 14 of 18) 31 DEC 2003 Table 6-35 (Page 15 of 18) 31 DEC 2003 Table 6-35 (Page 16 of 18) 31 DEC 2003 Table 6-35 (Page 17 of 18) 31 DEC 2003 Table 6-35 (Page 18 of 18) 31 DEC 2003 Chapter 6 Figures Figure 6-1 (Page 1 of 1) 31 DEC 2019 YES Figure 6-2 (Page 1 of 1) 31 DEC 2002 Figure 6-3 (Page 1 of 1) 31 DEC 2017 Figure 6-4 (Page 1 of 1) 31 DEC 2006 Figure 6-5 (Page 1 of 1) 31 DEC 2000 Figure 6-6 (Page 1 of 1) 31 DEC 2000 Figure 6-7 (Page 1 of 1) 31 DEC 2000 Figure 6-8 (Page 1 of 1) 31 DEC 2000 Figure 6-9 (Page 1 of 3) 31 DEC 2009 Figure 6-9 (Page 2 of 3) 31 DEC 2009 Figure 6-9 (Page 3 of 3) 31 DEC 2009 Figure 6 6-15 (Page 1 of 31 DEC 2000 1)

Figure 6-16 (Page 1 of 1) 31 DEC 2000 Figure 6-17 (Page 1 of 1) 31 DEC 2000 Figure 6-18 (Page 1 of 1) 31 DEC 2000 Figure 6-19 (Page 1 of 1) 31 DEC 2007 Redacted in Enclosure 1 Figure 6-20 (Page 1 of 1) 31 DEC 2000 Redacted in Enclosure 1 Figure 6-21 (Page 1 of 1) 31 DEC 2000 Redacted in Enclosure 1 Figure 6-22 (Page 1 of 1) 31 DEC 2000 Figure 6-23 (Page 1 of 1) 31 DEC 2000 Redacted in Enclosure 1 Figure 6-24 (Page 1 of 1) 31 DEC 2000 Redacted in Enclosure 1 Figure 6-25 (Page 1 of 1) 31 DEC 2000 Figure 6-26 (Page 1 of 1) 31 DEC 2000 Figure 6-27 (Page 1 of 1) 31 DEC 2000 Figure 6-28 (Page 1 of 1) 31 DEC 2003 Figure 6-29 (Page 1 of 1) 31 DEC 2003 Figure 6-30 (Page 1 of 1) 31 DEC 2003 Figure 6-31 (Page 1 of 1) 31 DEC 2003 Page 31 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 6-32 (Page 1 of 1) 31 DEC 2003 Figure 6-33 (Page 1 of 1) 31 DEC 2003 Figure 6-34 (Page 1 of 1) 31 DEC 2003 Figure 6-35 (Page 1 of 1) 31 DEC 2003 Figure 6-36 (Page 1 of 1) 31 DEC 2013 Figure 6-37 (Page 1 of 1) 31 DEC 2013 Figure 6 6-41 (Page 1 of 31 DEC 2003 1)

Figure 6-42 (Page 1 of 1) 31 DEC 2008 Figure 6-43 (Page 1 of 1) 31 DEC 2008 Figure 6-44 (Page 1 of 1) 31 DEC 2000 Figure 6-45 (Page 1 of 1) 31 DEC 2000 Figure 6-46 (Page 1 of 1) 31 DEC 2000 Figure 6-47 (Page 1 of 1) 31 DEC 2000 Figure 6-48 (Page 1 of 1) 31 DEC 2000 Figure 6-49 (Page 1 of 1) 31 DEC 2003 Figure 6-50 (Page 1 of 1) 31 DEC 2000 Figure 6-51 (Page 1 of 1) 31 DEC 2000 Figure 6-52 (Page 1 of 1) 31 DEC 2000 Fiqure 6-53 (Page 1 of 1) 31 DEC 2000 Chapter 7 7-i 31 DEC 2019 7-ii 31 DEC 2019 7-iii 31 DEC 2019 7-iv 31 DEC 2019 7-v 31 DEC 2019 7-vi 31 DEC 2019 7-vii 31 DEC 2019 7-viii 31 DEC 2019 7-ix 31 DEC 2019 7-x 31 DEC 2019 7.0-1 31 DEC 2019 7.0-2 31 DEC 2019 7.1-1 31 DEC 2019 7.1-2 31 DEC 2019 7.1-3 31 DEC 2019 7.1-4 31 DEC 2019 7.2-1 31 DEC 2019 Page 32 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 7.2-2 31 DEC 2019 7.2-3 31 DEC 2019 7.2-4 31 DEC 2019 7.2-5 31 DEC 2019 7.2-6 31 DEC 2019 7.2-7 31 DEC 2019 7.2-8 31 DEC 2019 7.2-9 31 DEC 2019 7.2-10 31 DEC 2019 7.2-11 31 DEC 2019 7.2-12 31 DEC 2019 7.2-13 31 DEC 2019 7.3-1 31 DEC 2019 7.3-2 31 DEC 2019 7.3-3 31 DEC 2019 7.3-4 31 DEC 2019 7.3-5 31 DEC 2019 7.3-6 31 DEC 2019 7.3-7 31 DEC 2019 7.3-8 31 DEC 2019 7.3-9 31 DEC 2019 7.3-10 31 DEC 2019 7.4-1 31 DEC 2019 7.4-2 31 DEC 2019 7.4-3 31 DEC 2019 7.4-4 31 DEC 2019 7.4-5 31 DEC 2019 7.4-6 31 DEC 2019 7.4-7 31 DEC 2019 7.4-8 31 DEC 2019 7.4-9 31 DEC 2019 7.4-10 31 DEC 2019 7.4-11 31 DEC 2019 7.4-12 31 DEC 2019 7.4-13 31 DEC 2019 7.4-14 31 DEC 2019 7.4-15 31 DEC 2019 7.4-16 31 DEC 2019 7.4-17 31 DEC 2019 Page 33 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 7.4-18 31 DEC 2019 7.5-1 31 DEC 2019 7.5-2 31 DEC 2019 7.5-3 31 DEC 2019 7.5-4 31 DEC 2019 7.5-5 31 DEC 2019 7.5-6 31 DEC 2019 7.5-7 31 DEC 2019 7.5-8 31 DEC 2019 7.5-9 31 DEC 2019 7.5-10 31 DEC 2019 7.5-11 31 DEC 2019 7.5-12 31 DEC 2019 7.5-13 31 DEC 2019 7.5-14 31 DEC 2019 7.5-15 31 DEC 2019 7.5-16 31 DEC 2019 7.5-17 31 DEC 2019 YES 7.5-18 31 DEC 2019 7.5-19 31 DEC 2019 7.5-20 31 DEC 2019 7.5-21 31 DEC 2019 YES 7.5-22 31 DEC 2019 7.5-23 31 DEC 2019 7.5-24 31 DEC 2019 7.5-25 31 DEC 2019 7.5-26 31 DEC 2019 7.5-27 31 DEC 2019 YES 7.5-28 31 DEC 2019 7.6-1 31 DEC 2019 7.6-2 31 DEC 2019 7.6-3 31 DEC 2019 7.6-4 31 DEC 2019 7.6-5 31 DEC 2019 7.6-6 31 DEC 2019 7.6-7 31 DEC 2019 7.6-8 31 DEC 2019 7.6-9 31 DEC 2019 7.6-10 31 DEC 2019 Page 34 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 7.6-11 31 DEC 2019 7.6-12 31 DEC 2019 7.6-13 31 DEC 2019 7.6-14 31 DEC 2019 7.6-15 31 DEC 2019 7.6-16 31 DEC 2019 7.6-17 31 DEC 2019 7.6-18 31 DEC 2019 7.7-1 31 DEC 2019 7.7-2 31 DEC 2019 7.7-3 31 DEC 2019 7.7-4 31 DEC 2019 7.7-5 31 DEC 2019 7.7-6 31 DEC 2019 7.8-1 31 DEC 2019 7.8-2 31 DEC 2019 7.8-3 31 DEC 2019 7.8-4 31 DEC 2019 7.9-1 31 DEC 2019 YES 7.9-2 31 DEC 2019 7.9-3 31 DEC 2019 7.9-4 31 DEC 2019 YES 7.9-5 31 DEC 2019 7.9-6 31 DEC 2019 7.10-1 31 DEC 2019 7.10-2 31 DEC 2019 7.11-1 31 DEC 2019 7.11-2 31 DEC 2019 Chapter 7 Tables Table 7-1 (Page 1 of 1) 31 DEC 2016 Table 7-2 (Page 1 of 1) 31 DEC 2012 Table 7-3 (Page 1 of 1) 31 DEC 2012 Table 7-4 (Page 1 of 1) 31 DEC 2013 Table 7-5 (Page 1 of 2) 31 DEC 2006 Table 7-5 (Page 2 of 2) 31 DEC 2006 Table 7-6 (Page 1 of 1) 31 DEC 2005 Chapter 7 Figures Page 35 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 7-1 (Page 1 of 16) 31 DEC 2013 Figure 7-2 (Page 2 of 16) 31 DEC 2013 Figure 7-1 (Page 3 of 16) 31 DEC 2013 Figure 7-1 (Page 4 of 16) 31 DEC 2013 Figure 7-1 (Page 5 of 16) 31 DEC 2013 Figure 7-1 (Page 6 of 16) 31 DEC 2013 Figure 7-1 (Page 7 of 16) 31 DEC 2013 Figure 7-1 (Page 8 of 16) 31 DEC 2013 Figure 7-1 (Page 9 of 16) 31 DEC 2013 Figure 7-1 (Page 10 of 16) 31 DEC 2013 Figure 7-1 (Page 11 of 16) 31 DEC 2013 Figure 7-1 (Page 12 of 16) 31 DEC 2013 Figure 7-1 (Page 13 of 16) 31 DEC 2013 Figure 7-1 (Page 14 of 16) 31 DEC 2013 Figure 7-1 (Page 15 of 16) 31 DEC 2013 Figure 7-1 (Page 16 of 16) 31 DEC 2013 Figure 7-2 (Page 1 of 1) 31 DEC 2000 Figure 7-3 (Page 1 of 1) 31 DEC 2003 Figure 7-4 (Page 1 of 1) 31 DEC 2012 Figure 7-5 (Page 1 of 8) 31 DEC 2013 Figure 7-5 (Page 2 of 8) 31 DEC 2013 Figure 7-5 (Page 3 of 8) 31 DEC 2013 Figure 7-5 (Page 4 of 8) 31 DEC 2013 Figure 7-5 (Page 5 of 8) 31 DEC 2013 Figure 7-5 (Page 6 of 8) 31 DEC 2013 Figure 7-5 (Page 7 of 8) 31 DEC 2013 Figure 7-5 (Page 8 of 8) 31 DEC 2013 Figure 7-6 (Page 1 of 1) 31 DEC 2013 Figure 7-7 (Page 1 of 1) 31 DEC 2000 Figure 7-8 (Page 1 of 1) 31 DEC 2013 Figure 7-9 (Page 1 of 1) 31 DEC 2011 Figure 7-10 (Page 1 of 1) 31 DEC 2013 Figure 7-11 (Page 1 of 1) 31 DEC 2000 Figure 7-12 (Page 1 of 1) 31 DEC 2019 YES Figure 7-13 (Page 1 of 1) 31 DEC 2009 Figure 7-14 (Page 1 of 1) 31 DEC 2000 Figure 7-15 (Page 1 of 1) 31 DEC 2000 Figure 7-16 (Page 1 of 1) 31 DEC 2000 Figure 7-17 (Page 1 of 1) 31 DEC 2000 Page 36 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 7-18 (Page 1 of 1) 31 DEC 2004 Figure 7-19 (Page 1 of 1) 31 DEC 2000 Figure 7-20 (Page 1 of 1) 31 DEC 2000 Figure 7-21 (Page 1 of 1) 31 DEC 2000 Figure 7 7-25 (Page 1 of 31 DEC 2000 1)

Figure 7-26 (Page 1 of 1) 31 DEC 2000 Chapter 8 8-i 31 DEC 2019 8-ii 31 DEC 2019 8-iii 31 DEC 2019 8-iv 31 DEC 2019 8-v 31 DEC 2019 8-vi 31 DEC 2019 8-4 31 DEC 2019 8.0-1 31 DEC 2019 8.0-2 31 DEC 2019 8.1-1 31 DEC 2019 8.1-2 31 DEC 2019 8.2-1 31 DEC 2019 8.2-2 31 DEC 2019 8.2-3 31 DEC 2019 8.2-4 31 DEC 2019 8.2-5 31 DEC 2019 8.2-6 31 DEC 2019 8.3-1 31 DEC 2019 8.3-2 31 DEC 2019 YES 8.3-3 31 DEC 2019 8.3-4 31 DEC 2019 8.3-5 31 DEC 2019 8.3-6 31 DEC 2019 YES 8.3-7 31 DEC 2019 YES 8.3-8 31 DEC 2019 8.3-9 31 DEC 2019 8.3-10 31 DEC 2019 8.3-11 31 DEC 2019 8.3-12 31 DEC 2019 YES 8.3-13 31 DEC 2019 YES Page 37 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 8.3-14 31 DEC 2019 8.3-15 31 DEC 2019 8.3-16 31 DEC 2019 8.3-17 31 DEC 2019 YES 8.3-18 31 DEC 2019 8.3-19 31 DEC 2019 8.3-20 31 DEC 2019 8.3-21 31 DEC 2019 8.3.22 31 DEC 2019 8.4-1 31 DEC 2019 8.4-2 31 DEC 2019 Chapter 8 Tables Table 8-1 (Page 1 of 2) 31 DEC 2019 YES Table 8-1 (Page 2 of 2) 31 DEC 2019 YES Table 8-2 (Page 1 of 2) 31 DEC 2000 Table 8-2 (Page 2 of 2) 31 DEC 2000 Table 8-3 (Page 1 of 2) 31 DEC 2019 YES Table 8-3 (Page 2 of 2) 31 DEC 2019 YES Table 8-4 (Page 1 of 1) 31 DEC 2014 Table 8-4 (Page 2 of 1) 31 DEC 2014 Table 8-5 (Page 1 of 4) 31 DEC 2000 Table 8-5 (Page 2 of 4) 31 DEC 2000 Table 8-5 (Page 3 of 4) 31 DEC 2000 Table 8-5 (Page 4 of 4 31 DEC 2000 Table 8-6 (Page 1 of 1) 31 DEC 2000 Table 8-7 (Page 1 of 1) 31 DEC 2000 Chapter 8 Figures Figure 8-1 (Page 1 of 1) 31 DEC 2019 YES Figure 8-2 (Page 1 of 1) 31 DEC 2015 Figure 8-3 (Page 1 of 2) 31 DEC 2015 Figure 8-3 (Page 2 of 2) 31 DEC 2015 Figure 8-4 (Page 1 of 3) 31 DEC 2015 Figure 8-4 (Page 2 of 3) 31 DEC 2015 Figure 8-4 (Page 3 of 3) 31 DEC 2015 Figure 8-5 (Page 1 of 1) 31 DEC 2017 Figure 8-6 (Page 1 of 1) 31 DEC 2013 Figure 8-7 (Page 1 of 1) 31 DEC 2006 Page 38 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 8-8 (Page 1 of 1) 31 DEC 2000 Figure 8-9 (Page 1 of 1) 31 DEC 2000 Chapter 9 9-i 31 DEC 2019 9-ii 31 DEC 2019 9-iii 31 DEC 2019 9-iv 31 DEC 2019 9-v 31 DEC 2019 9-vi 31 DEC 2019 9-vii 31 DEC 2019 9-viii 31 DEC 2019 9-ix 31 DEC 2019 9-x 31 DEC 2019 9.0-1 31 DEC 2019 9.0-2 31 DEC 2019 9.1-1 31 DEC 2019 9.1-2 31 DEC 2019 9.1-3 31 DEC 2019 9.1-4 31 DEC 2019 9.1-5 31 DEC 2019 9.1-6 31 DEC 2019 9.1-7 31 DEC 2019 9.1-8 31 DEC 2019 9.1-9 31 DEC 2019 9.1-10 31 DEC 2019 9.1-11 31 DEC 2019 9.1-12 31 DEC 2019 9.1-13 31 DEC 2019 YES 9.1-14 31 DEC 2019 9.1-15 31 DEC 2019 9.1-16 31 DEC 2019 YES 9.1-17 31 DEC 2019 9.1-18 31 DEC 2019 9.1-19 31 DEC 2019 YES 9.1-20 31 DEC 2019 9.1-21 31 DEC 2019 9.1-22 31 DEC 2019 9.1-23 31 DEC 2019 Page 39 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 9.1-24 31 DEC 2019 YES 9.1-25 31 DEC 2019 9.1-26 31 DEC 2019 9.1-27 31 DEC 2019 9.1-28 31 DEC 2019 9.1-29 31 DEC 2019 9.1-30 31 DEC 2019 9.2-1 31 DEC 2019 9.2-2 31 DEC 2019 9.2-3 31 DEC 2019 9.2-4 31 DEC 2019 9.2-5 31 DEC 2019 9.2-6 31 DEC 2019 9.2-7 31 DEC 2019 9.2-8 31 DEC 2019 9.2-9 31 DEC 2019 9.2-10 31 DEC 2019 9.2-11 31 DEC 2019 9.2-12 31 DEC 2019 9.2-13 31 DEC 2019 9.2-14 31 DEC 2019 9.3-1 31 DEC 2019 9.3-2 31 DEC 2019 9.3-3 31 DEC 2019 9.3-4 31 DEC 2019 9.3-5 31 DEC 2019 9.3-6 31 DEC 2019 9.3-7 31 DEC 2019 9.3-8 31 DEC 2019 9.3-9 31 DEC 2019 9.3-10 31 DEC 2019 9.3-11 31 DEC 2019 9.3-12 31 DEC 2019 9.3-13 31 DEC 2019 9.3-14 31 DEC 2019 9.3-15 31 DEC 2019 9.3-16 31 DEC 2019 9.4-1 31 DEC 2019 YES 9.4-2 31 DEC 2019 YES Page 40 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 9.4-3 31 DEC 2019 YES 9.4-4 31 DEC 2019 9.4-5 31 DEC 2019 9.4-6 31 DEC 2019 9.4-7 31 DEC 2019 9.4-8 31 DEC 2019 9.4-9 31 DEC 2019 9.4-10 31 DEC 2019 YES 9.4-11 31 DEC 2019 9.4-12 31 DEC 2019 9.4-13 31 DEC 2019 9.4.14 31 DEC 2019 9.5-1 31 DEC 2019 9.5-2 31 DEC 2019 9.5-3 31 DEC 2019 9.5-4 31 DEC 2019 9.5-5 31 DEC 2019 YES 9.5-6 31 DEC 2019 9.5-7 31 DEC 2019 9.5-8 31 DEC 2019 9.5-9 31 DEC 2019 9.5-10 31 DEC 2019 9.5-11 31 DEC 2019 9.5-12 31 DEC 2019 9.5-13 31 DEC 2019 9.5-14 31 DEC 2019 9.5-15 31 DEC 2019 9.5-16 31 DEC 2019 9.5-17 31 DEC 2019 9.5-18 31 DEC 2019 9.6-1 31 DEC 2019 9.6-2 31 DEC 2019 9.6-3 31 DEC 2019 YES 9.6-4 31 DEC 2019 YES 9.6-5 31 DEC 2019 9.6-6 31 DEC 2019 9.6-7 31 DEC 2019 9.6-8 31 DEC 2019 9.6-9 31 DEC 2019 Page 41 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 9.6-10 31 DEC 2019 YES 9.6-11 31 DEC 2019 9.6-12 31 DEC 2019 YES 9.6-13 31 DEC 2019 9.6-14 31 DEC 2019 9.6-15 31 DEC 2019 9.6-16 31 DEC 2019 9.6-17 31 DEC 2019 9.6-18 31 DEC 2019 9.6-19 31 DEC 2019 9.6-20 31 DEC 2019 9.7-1 31 DEC 2019 9.7-2 31 DEC 2019 9.7-3 31 DEC 2019 9.7-4 31 DEC 2019 9.7-5 31 DEC 2019 9.7-6 31 DEC 2019 9.7-7 31 DEC 2019 9.7-8 31 DEC 2019 9.7-9 31 DEC 2019 9.7-10 31 DEC 2019 9.7-11 31 DEC 2019 9.7-12 31 DEC 2019 Chapter 9 Tables Table 9-1 (Page 1 of 2) 31 DEC 2019 YES Table 9-1 (Page 2 of 2) 31 DEC 2019 Table 9-2 (Page 1 of 2) 31 DEC 2015 Table 9-2 (Page 2 of 2) 31 DEC 2015 Table 9-3 (Page 1 of 1) 31 DEC 2000 Table 9-4 (Page 1 of 2) 31 DEC 2000 Table 9-4 (Page 2 of 2) 31 DEC 2000 Table 9-5 (Page 1 of 3) 31 DEC 2006 Table 9-5 (Page 2 of 3) 31 DEC 2006 Table 9-5 (Page 3 of 3) 31 DEC 2006 Table 9-6 (Page 1 of 1) 31 DEC 2017 Table 9-7 (Page 1 of 2) 31 DEC 2005 Table 9-7 (Page 2 of 2) 31 DEC 2005 Table 9-8 (Page 1 of 1) 31 DEC 2000 Page 42 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 9-9 (Page 1 of 2) 31 DEC 2009 Table 9-9 (Page 2 of 2) 31 DEC 2009 Table 9-10 (Page 1 of 2) 31 DEC 2000 Table 9-10 (Page 2 of 2) 31 DEC 2000 Table 9-11 (Page 1 of 2) 31 DEC 2000 Table 9-11 (Page 2 of 2) 31 DEC 2000 Table 9-12 (Page 1 of 1) 31 DEC 2002 Table 9-13 (Page 1 of 2) 31 DEC 2000 Table 9-13 (Page 2 of 2) 31 DEC 2000 Table 9-14 (Page 1 of 4) 31 DEC 2019 YES Table 9-14 (Page 2 of 4) 31 DEC 2019 YES Table 9-14 (Page 3 of 4) 31 DEC 2019 Table 9-14 (Page 4 of 4) 31 DEC 2019 Table 9-15 (Page 1 of 2) 31 DEC 2010 Table 9-15 (Page 2 of 2) 31 DEC 2010 Table 9-16 (Page 1 of 1) 31 DEC 2011 Table 9-17 (Page 1 of 1) 31 DEC 2000 Table 9-18 (Page 1 of 1) 31 DEC 2000 Table 9-19 (Page 1 of 1) 31 DEC 2000 Table 9-20 (Page 1 of 1) 31 DEC 2015 Chapter 9 Figures Figure 9-1 (Page 1 of 1) 31 DEC 2000 Figure 9-2 (Page 1 of 1) 31 DEC 2000 Figure 9-3 (Page 1 of 1) 31 DEC 2000 Figure 9-4 (Page 1 of 1) 31 DEC 2000 Figure 9-5 (Page 1 of 1) 31 DEC 2019 YES Figure 9-6 (Page 1 of 1) 31 DEC 2000 Figure 9-7 (Page 1 of 2) 31 DEC 2017 Figure 9-7 (Page 2 of 2) 31 DEC 2017 Figure 9-8 (Page 1 of 1) 31 DEC 2000 Figure 9-9 (Page 1 of 1) 31 DEC 2000 Figure 9-10 (Page 1 of 1) 31 DEC 2016 Figure 9-11 (Page 1 of 1) 31 DEC 2017 Figure 9-12 (Page 1 of 1) 31 DEC 2015 Figure 9-13 (Page 1 of 1) 31 DEC 2000 Figure 9-14 (Page 1 of 1) 31 DEC 2000 Figure 9-15 (Page 1 of 1) 31 DEC 2003 Figure 9-16 (Page 1 of 1) 31 DEC 2007 Page 43 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 9-17 (Page 1 of 1) 31 DEC 2015 Figure 9-18 (Page 1 of 1) 31 DEC 2017 Figure 9-19 (Page 1 of 1) 31 DEC 2004 Figure 9-20 (Page 1 of 1) 31 DEC 2004 Figure 9-21 (Page 1 of 1) 31 DEC 2001 Figure 9-22 (Page 1 of 1) 31 DEC 2000 Figure 9-23 (Page 1 of 1) 31 DEC 2000 Figure 9-24 (Page 1 of 1) 31 DEC 2019 YES Figure 9-25 (Page 1 of 1) 31 DEC 2000 Figure 9-26 (Page 1 of 1) 31 DEC 2000 Figure 9-27 (Page 1 of 1) 31 DEC 2011 Figure 9-28 (Page 1 of 1) 31 DEC 2001 Figure 9-29 (Page 1 of 1) 31 DEC 2000 Figure 9-30 (Page 1 of 1) 31 DEC 2013 Redacted in Enclosure 1 Figure 9-31 (Page 1 of 1) 31 DEC 2013 Redacted in Enclosure 1 Figure 9-32 (Page 1 of 1) 31 DEC 2013 Redacted in Enclosure 1 Figure 9-33 (Page 1 of 1) 31 DEC 2013 Redacted in Enclosure 1 Figure 9-34 (Page 1 of 1) 31 DEC 2013 Redacted in Enclosure 1 Figure 9-35 (Page 1 of 1) 31 DEC 2000 Figure 9-36 (Page 1 of 1) 31 DEC 2013 Figure 9-37 (Page 1 of 1) 31 DEC 2013 Figure 9-38 (Page 1 of 1) 31 DEC 2013 Figure 9-39 (Page 1 of 1) 31 DEC 2000 Figure 9-40 (Page 1 of 1) 31 DEC 2013 Figure 9-41 (Page 1 of 1) 31 DEC 2000 Figure 9-42 (Page 1 of 1) 31 DEC 2000 Figure 9-43 (Page 1 of 1) 31 DEC 2000 Figure 9-44 (Page 1 of 1) 31 DEC 2015 Figure 9-45 (Page 1 of 1) 31 DEC 2015 Figure 9-46 (Page 1 of 1) 31 DEC 2015 Chapter 10 10-i 31 DEC 2019 10-ii 31 DEC 2019 10-iii 31 DEC 2019 10-iv 31 DEC 2019 10-v 31 DEC 2019 10-vi 31 DEC 2019 10.0-1 31 DEC 2019 Page 44 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 10.0-2 31 DEC 2019 10.1-1 31 DEC 2019 10.1-2 31 DEC 2019 10.2-1 31 DEC 2019 10.2-2 31 DEC 2019 10.2-3 31 DEC 2019 10.2-4 31 DEC 2019 10.3-1 31 DEC 2019 10.3-2 31 DEC 2019 10.3-3 31 DEC 2019 10.3-4 31 DEC 2019 YES 10.3-5 31 DEC 2019 10.3-6 31 DEC 2019 10.4-1 31 DEC 2019 10.4-2 31 DEC 2019 10.4-3 31 DEC 2019 10.4-4 31 DEC 2019 10.4-5 31 DEC 2019 10.4-6 31 DEC 2019 10.4-7 31 DEC 2019 10.4-8 31 DEC 2019 10.4-9 31 DEC 2019 10.4-10 31 DEC 2019 10.4-11 31 DEC 2019 10.4-12 31 DEC 2019 10.4-13 31 DEC 2019 10.4-14 31 DEC 2019 10.4-15 31 DEC 2019 YES 10.4-16 31 DEC 2019 10.4-17 31 DEC 2019 10.4-18 31 DEC 2019 10.4-19 31 DEC 2019 10.4-20 31 DEC 2019 10.4-21 31 DEC 2019 10.4-22 31 DEC 2019 10.4-23 31 DEC 2019 10.4-24 31 DEC 2019 Chapter 10 Tables Page 45 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 10-1 (Page 1 of 1) 31 DEC 2000 Table 10-2 (Page 1 of 1) 31 DEC 2009 Chapter 10 Figures Figure 10-1 (Page 1 of 1) 31 DEC 2007 Figure 10-2 (Page 1 of 1) 31 DEC 2015 Figure 10-3 (Page 1 of 1) 31 DEC 2000 Figure 10-4 (Page 1 of 1) 31 DEC 2015 Figure 10-5 (Page 1 of 1) 31 DEC 2000 Figure 10-6 (Page 1 of 1) 31 DEC 2007 Figure 10-7 (Page 1 of 1) 31 DEC 2015 Figure 10-8 (Page 1 of 1) 31 DEC 2015 Figure 10-9 (Page 1 of 2) 31 DEC 2004 Figure 10-9 (Page 2 of 2) 31 DEC 2004 Chapter 11 11-i 31 DEC 2019 11-ii 31 DEC 2019 11-iii 31 DEC 2019 11-iv 31 DEC 2019 11-v 31 DEC 2019 11-vi 31 DEC 2019 11.0-1 31 DEC 2019 11.0-2 31 DEC 2019 11.1-1 31 DEC 2019 11.1-2 31 DEC 2019 11.2-1 31 DEC 2019 11.2-2 31 DEC 2019 11.2-3 31 DEC 2019 11.2-4 31 DEC 2019 11.3-1 31 DEC 2019 11.3-2 31 DEC 2019 11.3-3 31 DEC 2019 11.3-4 31 DEC 2019 11.4-1 31 DEC 2019 11.4-2 31 DEC 2019 11.5-1 31 DEC 2019 11.5-2 31 DEC 2019 11.5-3 31 DEC 2019 Page 46 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 11.5-4 31 DEC 2019 11.5-5 31 DEC 2019 11.5-6 31 DEC 2019 11.6-1 31 DEC 2019 11.6-2 31 DEC 2019 11.6-3 31 DEC 2019 11.6-4 31 DEC 2019 11.6-5 31 DEC 2019 11.6-6 31 DEC 2019 11.6-7 31 DEC 2019 11.6-8 31 DEC 2019 11.6-9 31 DEC 2019 11.6-10 31 DEC 2019 11.6-11 31 DEC 2019 11.5-12 31 DEC 2019 11.7-1 31 DEC 2019 11.7-2 31 DEC 2019 11.8-1 31 DEC 2019 11.8-2 31 DEC 2019 Chapter 11 Tables Table 11-1 (Page 1 of 1) 31 DEC 2000 Table 11-2 (Page 1 of 1) 31 DEC 2000 Table 11-3 (Page 1 of 1) 31 DEC 2000 Table 11-4 (Page 1 of 1) 31 DEC 2004 Table 11-5 (Page 1 of 2) 31 DEC 2000 Table 11-5 (Page 2 of 2) 31 DEC 2000 Table 11-6 (Page 1 of 7) 31 DEC 2012 Table 11-6 (Page 2 of 7) 31 DEC 2012 Table 11-6 (Page 3 of 7) 31 DEC 2012 Table 11-6 (Page 4 of 7) 31 DEC 2012 Table 11-6 (Page 5 of 7) 31 DEC 2012 Table 11-6 (Page 6 of 7) 31 DEC 2012 Table 11-6 (Page 7 of 7) 31 DEC 2012 Table 11-7 (Page 1 of 4) 31 DEC 2004 Table 11-7 (Page 2 of 4) 31 DEC 2004 Table 11-7 (Page 3 of 4) 31 DEC 2004 Table 11-7 (Page 4 of 4) 31 DEC 2004 Page 47 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Chapter 11 Figures Figure 11-1 (Page 1 of 1) 31 DEC 2000 Figure 11-2 (Page 1 of 1) 31 DEC 2000 Figure 11-3 (Page 1 of 1) 31 DEC 2000 Figure 11-4 (Page 1 of 1) 31 DEC 2011 Figure 11-5 (Page 1 of 1) 31 DEC 2000 Figure 11-6 (Page 1 of 1) 31 DEC 2000 Chapter 12 12-i 31 DEC 2019 12-ii 31 DEC 2019 12-iii 31 DEC 2019 12-iv 31 DEC 2019 12.0-1 31 DEC 2019 12.0-2 31 DEC 2019 12.1-1 31 DEC 2019 12.1-2 31 DEC 2019 12.1-3 31 DEC 2019 12.1-4 31 DEC 2019 12.2-1 31 DEC 2019 12.2-2 31 DEC 2019 12.3-1 31 DEC 2019 12.3-2 31 DEC 2019 12.3-3 31 DEC 2019 12.3-4 31 DEC 2019 12.4-1 31 DEC 2019 12.4-2 31 DEC 2019 12.4-3 31 DEC 2019 12.4-4 31 DEC 2019 12.4-5 31 DEC 2019 12.4-6 31 DEC 2019 12.4-7 31 DEC 2019 12.4-8 31 DEC 2019 12.4-9 31 DEC 2019 12.4-10 31 DEC 2019 Chapter 12 Tables Table 12-1 (Page 1 of 1) 31 DEC 2000 Table 12-2 (Page 1 of 2) 31 DEC 2000 Page 48 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 12-2 (Page 2 of 2) 31 DEC 2000 Table 12-3 (Page 1 of 2) 31 DEC 2004 Table 12-3 (Page 2 of 2) 31 DEC 2004 Chapter 12 Figures No Figures in Chapter 12 Chapter 13 13-i 31 DEC 2019 13-ii 31 DEC 2019 13-iii 31 DEC 2019 13-iv 31 DEC 2019 13-v 31 DEC 2019 13-vi 31 DEC 2019 13.0-1 31 DEC 2019 13.0-2 31 DEC 2019 13.1-1 31 DEC 2019 13.1-2 31 DEC 2019 13.1-3 31 DEC 2019 13.1-4 31 DEC 2019 13.1-5 31 DEC 2019 13.1-6 31 DEC 2019 13.1-7 31 DEC 2019 13.1-8 31 DEC 2019 13.1-9 31 DEC 2019 13.1-10 31 DEC 2019 13.2-1 31 DEC 2019 YES 13.2-2 31 DEC 2019 YES 13.2-3 31 DEC 2019 YES 13.2-4 31 DEC 2019 13.2-5 31 DEC 2019 YES 13.2-6 31 DEC 2019 YES 13.2-7 31 DEC 2019 YES 13.2-8 31 DEC 2019 13.3-1 31 DEC 2019 13.3-2 31 DEC 2019 13.4-1 31 DEC 2019 13.4-2 31 DEC 2019 13.5-1 31 DEC 2019 Page 49 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 13.5-2 31 DEC 2019 13.5-3 31 DEC 2019 13.5-4 31 DEC 2019 13.5-5 31 DEC 2019 13.5-6 31 DEC 2019 13.5-7 31 DEC 2019 13.5-8 31 DEC 2019 13.6-1 31 DEC 2019 13.6-2 31 DEC 2019 Chapter 13 Tables Table 13-1 (Page 1 of 1) 31 DEC 2000 Table 13-2 (Page 1 of 1) 31 DEC 2000 Chapter 13 Figures Figure 13-1 (Page 1 of 1) 31 DEC 2014 Figure 13-2 (Page 1 of 1) 31 DEC 2000 Figure 13-3 (Page 1 of 1) 31 DEC 2014 Figure 13-4 (Page 1 of 1) 31 DEC 2014 Figure 13-5 (Page 1 of 1) 31 DEC 2000 Figure 13-6 (Page 1 of 1) 31 DEC 2000 Figure 13-7 (Page 1 of 1) 31 DEC 2012 Figure 13-8 (Page 1 of 1) 31 DEC 2014 Chapter 14 14-i 31 DEC 2019 14-ii 31 DEC 2019 14-iii 31 DEC 2019 14-iv 31 DEC 2019 14.0-1 31 DEC 2019 14.0-2 31 DEC 2019 14.1-1 31 DEC 2019 14.1-2 31 DEC 2019 14.1-3 31 DEC 2019 14.1-4 31 DEC 2019 14.2-1 31 DEC 2019 14.2-2 31 DEC 2019 14.3-1 31 DEC 2019 14.3-2 31 DEC 2019 Page 50 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 14.4-1 31 DEC 2019 14.4-2 31 DEC 2019 14.5-1 31 DEC 2019 14.5-2 31 DEC 2019 14.6-1 31 DEC 2019 14.6-2 31 DEC 2019 Chapter 14 Tables Table 14-1 (Page 1 of 1) 31 DEC 2000 Table 14-2 (Page 1 of 1) 31 DEC 2000 Chapter 14 Figures No Figures in Chapter 14 Chapter 15 15-i 31 DEC 2019 15-ii 31 DEC 2019 15-iii 31 DEC 2019 15-iv 31 DEC 2019 15-v 31 DEC 2019 15-vi 31 DEC 2019 15-vii 31 DEC 2019 15-viii 31 DEC 2019 15-ix 31 DEC 2019 15-x 31 DEC 2019 15-xi 31 DEC 2019 15-xii 31 DEC 2019 15-xiii 31 DEC 2019 15-xiv 31 DEC 2019 15-xv 31 DEC 2019 15-xvi 31 DEC 2019 15-xvii 31 DEC 2019 15-xviii 31 DEC 2019 15.0-1 31 DEC 2019 15.0-2 31 DEC 2019 15.1-1 31 DEC 2019 15.1-2 31 DEC 2019 YES 15.1-3 31 DEC 2019 15.1-4 31 DEC 2019 Page 51 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 15.1-5 31 DEC 2019 15.1-6 31 DEC 2019 15.1-7 31 DEC 2019 YES 15.1-8 31 DEC 2019 15.1-9 31 DEC 2019 YES 15.1-10 31 DEC 2019 YES 15.1-11 31 DEC 2019 15.1-12 31 DEC 2019 YES 15.2-1 31 DEC 2019 15.2-2 31 DEC 2019 15.3-1 31 DEC 2019 15.3-2 31 DEC 2019 15.4-1 31 DEC 2019 15.4-2 31 DEC 2019 15.5-1 31 DEC 2019 15.5-2 31 DEC 2019 15.6-1 31 DEC 2019 15.6-2 31 DEC 2019 15.6-3 31 DEC 2019 15.6-4 31 DEC 2019 15.6-5 31 DEC 2019 15.6-6 31 DEC 2019 15.7-1 31 DEC 2019 15.7-2 31 DEC 2019 15.8-1 31 DEC 2019 15.8-2 31 DEC 2019 15.9-1 31 DEC 2019 15.9-2 31 DEC 2019 15.9-3 31 DEC 2019 15.9-4 31 DEC 2019 15.9-5 31 DEC 2019 15.9-6 31 DEC 2019 15.10-1 31 DEC 2019 15.10-2 31 DEC 2019 15.11-1 31 DEC 2019 YES 15.11-2 31 DEC 2019 YES 15.11-3 31 DEC 2019 15.11-4 31 DEC 2019 YES 15.11-5 31 DEC 2019 Page 52 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 15.11-6 31 DEC 2019 YES 15.12-1 31 DEC 2019 15.12-2 31 DEC 2019 15.12-3 31 DEC 2019 15.12-4 31 DEC 2019 15.13-1 31 DEC 2019 15.13-2 31 DEC 2019 15.13-3 31 DEC 2019 15.13-4 31 DEC 2019 15.13-5 31 DEC 2019 15.13-6 31 DEC 2019 15.14-1 31 DEC 2019 15.14-2 31 DEC 2019 15.14-3 31 DEC 2019 15.14-4 31 DEC 2019 15.14-5 31 DEC 2019 15.14-6 31 DEC 2019 15.14-7 31 DEC 2019 15.14-8 31 DEC 2019 15.14-9 31 DEC 2019 15.14-10 31 DEC 2019 15.14-11 31 DEC 2019 15.14-12 31 DEC 2019 15.14-13 31 DEC 2019 15.14-14 31 DEC 2019 15.14-15 31 DEC 2019 15.14-16 31 DEC 2019 15.14-17 31 DEC 2019 15.14-18 31 DEC 2019 15.14-19 31 DEC 2019 15-14-20 31 DEC 2019 15.14-21 31 DEC 2019 15.14-22 31 DEC 2019 15.15-1 31 DEC 2019 15.15-2 31 DEC 2019 15.15-3 31 DEC 2019 15.15-4 31 DEC 2019 15.16-1 31 DEC 2019 15.16-2 31 DEC 2019 Page 53 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 15.16-3 31 DEC 2019 15.16-4 31 DEC 2019 15.16-5 31 DEC 2019 15.16-6 31 DEC 2019 15.16-7 31 DEC 2019 15.16-8 31 DEC 2019 15.17-1 31 DEC 2019 15.17-2 31 DEC 2019 15.17-3 31 DEC 2019 15.17-4 31 DEC 2019 15.18-1 31 DEC 2019 15.18-2 31 DEC 2019 Chapter 15 Tables Table 15-1 (Page 1 of 1) 31 DEC 2019 YES Table 15-2 (Page 1 of 1) 31 DEC 2013 Table 15-3 (Page 1 of 1) 31 DEC 2008 Table 15-4 (Page 1 of 1) 31 DEC 2004 Table 15-5 (Page 1 of 1) 31 DEC 2003 Table 15-6 (Page 1 of 1) 31 DEC 2000 Table 15 15-14 (Page 1 of 31 DEC 2000 1)

Table 15-15 (Page 1 of 4) 31 DEC 2012 Table 15-15 (Page 2 of 4) 31 DEC 2012 Table 15-15 (Page 3 of 4) 31 DEC 2012 Table 15-15 (Page 4 of 4) 31 DEC 2012 Table 15-16 (Page 1 of 2) 31 DEC 2019 YES Table 15-16 (Page 2 of 2) 31 DEC 2019 YES Table 15-17-15-27 (Page 1 of 31 DEC 2000 1)

Table 15-28 (Page 1 of 1) 31 DEC 2015 Table 15-29 (Page 1 of 1) 31 DEC 2015 Table 15-30 (Page 1 of 1) 31 DEC 2015 Table 15-31 (Page 1 of 1) 31 DEC 2008 Table 15-32 (Page 1 of 2) 31 DEC 2015 Table 15-32 (Page 2 of 2) 31 DEC 2015 Table 15-33 (Page 1 of 1) 31 DEC 2013 Table 15-34 (Page 1 of 8) 31 DEC 2016 Table 15-34 (Page 2 of 8) 31 DEC 2016 Table 15-34 (Page 3 of 8) 31 DEC 2016 Page 54 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 15-34 (Page 4 of 8) 31 DEC 2016 Table 15-34 (Page 5 of 8) 31 DEC 2016 Table 15-34 (Page 6 of 8) 31 DEC 2016 Table 15-34 (Page 7 of 8) 31 DEC 2016 Table 15-34 (Page 8 of 8) 31 DEC 2016 Table 15-35 (Page 1 of 2) 31 DEC 2019 Table 15-35 (Page 2 of 2) 31 DEC 2016 Table 15-36 (Page 1 of 1) 31 DEC 2013 Table 15-37 (Page 1 of 1) 31 DEC 2008 Table 15-38 (Page 1 of 1) 31 DEC 2003 Table 15-39 (Page 1 of 1) 31 DEC 2015 Table 15-40 (Page 1 of 1) 31 DEC 2008 Table 15-41 (Page 1 of 1) 31 DEC 2003 Table 15-42 (Page 1 of 1) 31 DEC 2003 Table 15-43 (Page 1 of 1) 31 DEC 2003 Table 15-44 (Page 1 of 1) 31 DEC 2008 Table 15-45 (Page 1 of 1) 31 DEC 2010 Table 15-46 (Page 1 of 1) 31 DEC 2013 Table 15-47 (Page 1 of 1) 31 DEC 2011 Table 15-48 (Page 1 of 1) 31 DEC 2003 Table 15-49 (Page 1 of 1) 31 DEC 2016 Table 15-50 (Page 1 of 2) 31 DEC 2009 Table 15-50 (Page 2 of 2) 31 DEC 2009 Table 15-51 (Page 1 of 1) 31 DEC 2009 Table 15-52-15-55 (Page 1 of 31 DEC 2003 1)

Table 15-56 (Page 1 of 1) 31 DEC 2014 Table 15-57 (Page 1 of 1) 31 DEC 2014 Table 15-58 (Page 1 of 1) 31 DEC 2003 Table 15-59 (Page 1 of 1) 31 DEC 2001 Table 15-60 (Page 1 of 1) 31 DEC 2014 Table 15-61 (Page 1 of 2) 31 DEC 2009 Table 15-61 (Page 2 of 2) 31 DEC 2009 Table 15-62 (Page 1 of 2) 31 DEC 2014 Table 15-62 (Page 2 of 2) 31 DEC 2014 Table 15-63 (Page 1 of 2) 31 DEC 2014 Table 15-63 (Page 2 of 2) 31 DEC 2014 Table 15-64 (Page 1 of 1) 31 DEC 2011 Table 15-65 (Page 1 of 1) 31 DEC 2012 Page 55 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Table 15-66 (Page 1 of 1) 31 DEC 2012 Table 15-67 (Page 1 of 1) 31 DEC 2014 Table 15-68 (Page 1 of 2) 31 DEC 2014 Table 15-68 (Page 2 of 2) 31 DEC 2014 Chapter 15 Figures Figure 15-1 (Page 1 of 1) 31 DEC 2013 Figure 15-2 (Page 1 of 1) 31 DEC 2013 Figure 15-3 (Page 1 of 1) 31 DEC 2013 Figure 15-4 (Page 1 of 1) 31 DEC 2013 Figure 15-5 (Page 1 of 1) 31 DEC 2013 Figure 15-6 (Page 1 of 1) 31 DEC 2013 Figure 15 15-10 (Page 1 31 DEC 2000 of 1)

Figure 15-11 (Page 1 of 1) 31 DEC 2003 Figure 15-12 (Page 1 of 1) 31 DEC 2003 Figure 15-13 (Page 1 of 1) 31 DEC 2003 Figure 15-14 (Page 1 of 1) 31 DEC 2003 Figure 15-15 (Page 1 of 1) 31 DEC 2003 Figure 15-16 (Page 1 of 1) 31 DEC 2003 Figure 15-17 (Page 1 of 1) 31 DEC 2003 Figure 15-18 (Page 1 of 1) 31 DEC 2015 Figure 15-19 (Page 1 of 1) 31 DEC 2008 Figure 15-20 (Page 1 of 1) 31 DEC 2008 Figure 15-21 (Page 1 of 1) 31 DEC 2008 Figure 15-22 (Page 1 of 1) 31 DEC 2008 Figure 15-23 (Page 1 of 1) 31 DEC 2008 Figure 15-24 (Page 1 of 1) 31 DEC 2013 Figure 15-25 (Page 1 of 1) 31 DEC 2003 Figure 15-26 (Page 1 of 1) 31 DEC 2010 Figure 15-27 (Page 1 of 1) 31 DEC 2010 Figure 15-28 (Page 1 of 1) 31 DEC 2010 Figure 15-29 (Page 1 of 1) 31 DEC 2013 Figure 15-30 (Page 1 of 1) 31 DEC 2013 Figure 15-31 (Page 1 of 1) 31 DEC 2013 Figure 15-32 (Page 1 of 1) 31 DEC 2013 Figure 15-33 (Page 1 of 1) 31 DEC 2013 Figure 15-34 (Page 1 of 1) 31 DEC 2013 Figure 15-35 (Page 1 of 1) 31 DEC 2013 Page 56 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 15-36 (Page 1 of 1) 31 DEC 2013 Figure 15-37-15-39 (Page 1 31 DEC 2000 of 1)

Figure 15-40 (Page 1 of 1) 31 DEC 2003 Figure 15-41 (Page 1 of 1) 31 DEC 2003 Figure 15-42 (Page 1 of 1) 31 DEC 2003 Figure 15-43 (Page 1 of 1) 31 DEC 2003 Figure 15-44 (Page 1 of 1) 31 DEC 2000 Figure 15-45-15-49 (Page 1 31 DEC 2000 of 1)

Figure 15-50 (Page 1 of 1) 31 DEC 2008 Figure 15-51-15-79 (Page 1 31 DEC 2000 of 2)

Figure 15-51-15-79 (Page 2 31 DEC 2000 of 2)

Figure 15-80 (Page 1 of 1) 31 DEC 2000 Figure 15-81-15-88 (Page 1 31 DEC 2000 of 1)

Figure 15-89 (Page 1 of 1) 31 DEC 2003 Figure 15-90-15-111(Page 1 31 DEC 2000 of 2)

Figure 15-90-15-111(Page 2 31 DEC 2000 of 2)

Figure 15-112 (Page 1 of 1) 31 DEC 2014 Figure 15-113 (Page 1 of 1) 31 DEC 2003 Figure 15-114 (Page 1 of 1) 31 DEC 2013 Figure 15-115 (Page 1 of 1) 31 DEC 2015 Figure 15-116 (Page 1 of 1) 31 DEC 2015 Figure 15-117 (Page 1 of 1) 31 DEC 2015 Figure 15-118 (Page 1 of 1) 31 DEC 2015 Figure 15-119 (Page 1 of 1) 31 DEC 2003 Figure 15-120 (Page 1 of 1) 31 DEC 2003 Figure 15-121 (Page 1 of 1) 31 DEC 2003 Figure 15-122 (Page 1 of 1) 31 DEC 2003 Figure 15-123 (Page 1 of 1) 31 DEC 2013 Figure 15-124 (Page 1 of 1) 31 DEC 2003 Figure 15-125 (Page 1 of 1) 31 DEC 2003 Figure 15-126 (Page 1 of 1) 31 DEC 2003 Figure 15-127 (Page 1 of 1) 31 DEC 2003 Figure 15-128 (Page 1 of 1) 31 DEC 2003 Figure 15-129 (Page 1 of 1) 31 DEC 2013 Figure 15-130 (Page 1 of 1) 31 DEC 2003 Page 57 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 15-131 (Page 1 of 1) 31 DEC 2003 Figure 15-132 (Page 1 of 1) 31 DEC 2003 Figure 15-133 (Page 1 of 1) 31 DEC 2003 Figure 15-134 (Page 1 of 1) 31 DEC 2003 Figure 15-135 (Page 1 of 1) 31 DEC 2008 Figure 15-136 (Page 1 of 1) 31 DEC 2008 Figure 15-137 (Page 1 of 1) 31 DEC 2008 Figure 15-138 (Page 1 of 1) 31 DEC 2008 Figure 15-139 (Page 1 of 1) 31 DEC 2008 Figure 15-140 (Page 1 of 1) 31 DEC 2008 Figure 15-141 (Page 1 of 1) 31 DEC 2011 Figure 15-142 (Page 1 of 1) 31 DEC 2000 Figure 15-143 (Page 1 of 1) 31 DEC 2010 Figure 15-144 (Page 1 of 1) 31 DEC 2013 Figure 15-145 (Page 1 of 1) 31 DEC 2013 Figure 15-146 (Page 1 of 1) 31 DEC 2013 Figure 15-147 (Page 1 of 1) 31 DEC 2013 Figure 15-148 (Page 1 of 1) 31 DEC 2013 Figure 15-149 (Page 1 of 1) 31 DEC 2013 Figure 15-150 (Page 1 of 1) 31 DEC 2011 Figure 15-151 (Page 1 of 1) 31 DEC 2011 Figure 15-152 (Page 1 of 1) 31 DEC 2011 Figure 15-153 (Page 1 of 1) 31 DEC 2011 Figure 15-154 (Page 1 of 1) 31 DEC 2011 Figure 15-155 (Page 1 of 1) 31 DEC 2011 Figure 15-156 (Page 1 of 1) 31 DEC 2011 Figure 15-157 (Page 1 of 1) 31 DEC 2003 Figure 15-158 (Page 1 of 1) 31 DEC 2003 Figure 15-159 (Page 1 of 1) 31 DEC 2003 Figure 15-160 (Page 1 of 1) 31 DEC 2003 Figure 15-161 (Page 1 of 1) 31 DEC 2003 Figure 15-162 (Page 1 of 1) 31 DEC 2003 Figure 15-163 (Page 1 of 1) 31 DEC 2003 Figure 15-164 (Page 1 of 1) 31 DEC 2003 Figure 15-165 (Page 1 of 1) 31 DEC 2003 Figure 15-166 (Page 1 of 1) 31 DEC 2003 Figure 15-167 (Page 1 of 1) 31 DEC 2013 Figure 15-168 (Page 1 of 1) 31 DEC 2016 Figure 15-169 (Page 1 of 1) 31 DEC 2016 Page 58 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update Figure 15-170 (Page 1 of 1) 31 DEC 2016 Figure 15-171 (Page 1 of 1) 31 DEC 2016 Figure 15-172 (Page 1 of 1) 31 DEC 2016 Figure 15-173 (Page 1 of 1) 31 DEC 2016 Figure 15-174 (Page 1 of 1) 31 DEC 2014 Figure 15-175 (Page 1 of 1) 31 DEC 2003 Figure 15-176 (Page 1 of 1) 31 DEC 2001 Figure 15-177 (Page 1 of 1) 31 DEC 2003 Figure 15-178-15-212(Pg 1 of 31 DEC 2014 2)

Figure 15-178-15-212(Pg 2 of 31 DEC 2014 2)

Figure 15-213 (Page 1 of 1) 31 DEC 2015 Figure 15-214 (Page 1 of 1) 31 DEC 2015 Figure 15-215 (Page 1 of 1) 31 DEC 2015 Figure 15-216 (Page 1 of 1) 31 DEC 2015 Figure 15-217 (Page 1 of 1) 31 DEC 2015 Figure 15-218 (Page 1 of 1) 31 DEC 2015 Figure 15-219 (Page 1 of 1) 31 DEC 2011 Figure 15-220 (Page 1 of 1) 31 DEC 2011 Figure 15-221 (Page 1 of 1) 31 DEC 2011 Figure 15-222 (Page 1 of 1) 31 DEC 2011 Figure 15-223 (Page 1 of 1) 31 DEC 2011 Figure 15-224 (Page 1 of 1) 31 DEC 2011 Figure 15-225 (Page 1 of 1) 31 DEC 2011 Figure 15-226 (Page 1 of 1) 31 DEC 2011 Figure 15-227 (Page 1 of 1) 31 DEC 2011 Figure 15-228 (Page 1 of 1) 31 DEC 2011 Figure 15-229 (Page 1 of 1) 31 DEC 2011 Figure 15-230 (Page 1 of 1) 31 DEC 2011 Figure 15-231 (Page 1 of 1) 31 DEC 2011 Figure 15-232 (Page 1 of 1) 31 DEC 2011 Chapter 16 16-i 31 DEC 2019 16-ii 31 DEC 2019 16.0-1 31 DEC 2019 16.0-2 31 DEC 2019 Chapter 17 Page 59 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 17-i 31 DEC 2019 17-ii 31 DEC 2019 17.0-1 31 DEC 2019 17.0-2 31 DEC 2019 Chapter 18 18-i 31 DEC 2019 18-ii 31 DEC 2019 18-iii 31 DEC 2019 18-iv 31 DEC 2019 18.0-1 31 DEC 2019 18.0-2 31 DEC 2019 18.1-1 31 DEC 2019 18.1-2 31 DEC 2019 18.2-1 31 DEC 2019 18.2-2 31 DEC 2019 18.2-3 31 DEC 2019 18.2-4 31 DEC 2019 18.2-5 31 DEC 2019 18.2-6 31 DEC 2019 18.2-7 31 DEC 2019 18.2-8 31 DEC 2019 18.2-9 31 DEC 2019 18.2-10 31 DEC 2019 18.2-11 31 DEC 2019 18.2-12 31 DEC 2019 18.3-1 31 DEC 2019 YES 18.3-2 31 DEC 2019 YES 18.3-3 31 DEC 2019 18.3-4 31 DEC 2019 18.3-5 31 DEC 2019 18.3-6 31 DEC 2019 18.3-7 31 DEC 2019 18.3-8 31 DEC 2019 18.3-9 31 DEC 2019 18.3-10 31 DEC 2019 18.3-11 31 DEC 2019 18.3-12 31 DEC 2019 18.3-13 31 DEC 2019 Page 60 of 61

Oconee Nuclear Station 2019 UFSAR List of Effective Pages and List of Changed Pages Page Effective Date Changed 2019 Update 18.3-14 31 DEC 2019 YES 18.3-15 31 DEC 2019 18.3-16 31 DEC 2019 18.3-17 31 DEC 2019 18.3-18 31 DEC 2019 18.3-19 31 DEC 2019 18.3-20 31 DEC 2019 18.3-21 31 DEC 2019 18.3-22 31 DEC 2019 18.3-23 31 DEC 2019 18.3-24 31 DEC 2019 YES 18.3-25 31 DEC 2019 YES 18.3-26 31 DEC 2019 YES 18.3-27 31 DEC 2019 18.3-28 31 DEC 2019 18.3-29 31 DEC 2019 18.3-30 31 DEC 2019 18.3-31 31 DEC 2019 18.3-32 31 DEC 2019 18.3-33 31 DEC 2019 18.3-34 31 DEC 2019 YES 18.3-35 31 DEC 2019 18.3-36 31 DEC 2019 18.4-1 31 DEC 2019 18.4-2 31 DEC 2019 Chapter 18 Tables Table 18-1 (Page 1 of 4) 31 DEC 2014 Table 18-1 (Page 2 of 4) 31 DEC 2014 Table 18-1 (Page 3 of 4) 31 DEC 2014 Table 18-1 (Page 4 of 4) 31 DEC 2014 Page 61 of 61

U.S. Nuclear Regulatory Commission to RA-20-0136 Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, and 50-287 Renewed License Nos. DPR-38, DPR-47, and DPR-55 Submittal of Updated Final Safety Analysis Report (UFSAR) Revision 28, Technical Specifications Bases Revisions, Selected Licensee Commitments Revisions, 10 CFR 50.59 Evaluation Summary Report, and 10 CFR 54.37 Update Attachment 2 Update Insertion Instructions (for hardcopy distribution only)

Update Insertion Instructions (for hardcopy distribution only)

1. Replace 2017 List of Effective Pages (LOEP) for Tables and Figures with the 2019 Tables and Figures.

2. Replace entire text portions for each chapter with the updated text portion (including the Table of Contents, List of Figures, and List of Tables).

3. Update Tables and Figures according to the instructions below:

Remove Insert Chapter 3 Table 3-68 (2017) Table 3-68 (2019)

Chapter 5 Table 5-5 (2014) Table 5-5 (2019)

Figure 5-17 (2000) Figure 5-17 (2019)

Chapter 6 Figure 6-1 (2005) Figure 6-1 (2019)

Chapter 7 Figure 7-12 (2009) Figure 7-12 (2019)

Chapter 8 Table 8-1 (2002) Table 8-1 (2019)

Table 8-3 (2014) Table 8-3 (2019)

Figure 8-1 (2015) Figure 8-1 (2019)

Chapter 9 Table 9-1 (2000) Table 9-1 (2019)

Table 9-14 (2010) Table 9-14 (2019)

Figure 9-5 (2017) Figure 9-5 (2019)

Figure 9-24 (2016) Figure 9-24 (2019)

Chapter 15 Table 15-1 (2016) Table 15-1 (2019)

Table 15-16 (2016) Table 15-16 (2019)

Attachment 2 - Page 1 of 1

U.S. Nuclear Regulatory Commission to RA-20-0136 Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, and 50-287 Renewed License Nos. DPR-38, DPR-47, and DPR-55 Submittal of Updated Final Safety Analysis Report (UFSAR) Revision 28, Technical Specifications Bases Revisions, Selected Licensee Commitments Revisions, 10 CFR 50.59 Evaluation Summary Report, and 10 CFR 54.37 Update Attachment 3 List of Removed Items

List of Removed Items

1. Section 15.1.2 - Topical Reports A paragraph describing topical report DPC-NE-2015-PA was deleted. The methodology for performing the UFSAR Chapter 15 non-LOCA transient analyses for the Mark-B-HTP fuel assembly design has been incorporated into several other methodology reports that are already described in this UFSAR section (DPC-NE-2003-PA, DPC-NE-2005-PA, DPC-NE-3000-PA and DPC-NE-3005-PA). Therefore, the DPC-NE-2015-PA methodology report no longer needs to be included in UFSAR Chapter 15. (Change Package 18-012)

2. Section 3.4.1.1 - Flood Protection Measures for Seismic Class 1 Structures The sandbag barriers described in this section were previously installed as probable maximum precipitation (PMP) response enhancements. The sandbags have been removed from the plant via the Engineering Change process and therefore no longer need to be discussed in the UFSAR. (Change Package 19-018)

Attachment 3 - Page 1 of 1

U.S. Nuclear Regulatory Commission to RA-20-0136 Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, and 50-287 Renewed License Nos. DPR-38, DPR-47, and DPR-55 Submittal of Updated Final Safety Analysis Report (UFSAR) Revision 28, Technical Specifications Bases Revisions, Selected Licensee Commitments Revisions, 10 CFR 50.59 Evaluation Summary Report, and 10 CFR 54.37 Update Attachment 4 10 CFR 50.59 Evaluation Summary Report

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 403752. Modify U2 SSF RCS Line to Support SSF Operability in All Modes of Applicability (AR 2050877)

Summary:

Design improvements are implemented to the Standby Shutdown Facility (SSF) letdown line for Oconee Unit 2 to enhance the capability of throttling SSF letdown flow to the Spent Fuel Pool (SFP) and quench tank for Reactor Coolant System (RCS) inventory control during specified SSF events, and to better ensure mixing and distribution of the borated makeup within the RCS that is provided by the SSF Reactor Coolant Makeup (RCM) System during SSF events that occur at low decay heat conditions. For Unit 2, this modification is performed by Engineering Change (EC) 403752, which implements the necessary reconfigurations of the SSF letdown and RCM flow paths, containment penetrations, and SSF System control schemes. The effects of the modifications proposed by EC 403752 necessitated that a 10 CFR 50.59 Evaluation be performed.

In performing the 10 CFR 50.59 Evaluation, the determination was made that the EC 403752 design does not result in more than a minimal increase in the frequency of occurrence of an accident previously evaluated in the UFSAR, since, concerning the UFSAR-described Small Break LOCA Accident, the design, material, and installation improvements function to increase piping reliability when compared against the reliability performance of the currently installed SSF letdown line and other equipment modified by EC 403752. The EC 403752 design reconfigures the origin of the SSF letdown line tap off of the RCS to be the primary boron dilution line upstream of 2LP-103 instead of the current tap off of the RCS cold leg, thereby improving the mixing of SSF borated makeup within the RCS. Use of a larger installed SSF letdown line (2 1/2 versus current 1 piping) along with newly procured throttle valves placed in a parallel arrangement improve the capability to throttle SSF letdown flow that for operation of the current SSF letdown line requires cycling of 2HP-426 open and closed to provide for proper RCS inventory control. The improved throttle valve performance, which can control over a range of flow rates, enables SSF letdown line operation with decreased water hammer frequency during an SSF event over the currently configured SSF letdown line/2HP-426.

In addition, improved SSF letdown line flow control allows pressurizer level to be controlled more precisely without the need to cycle pressurizer level within a range. This feature reduces the need for additional SSF controlled pressurizer heaters to offset the insurge of relatively cooler water into the pressurizer. Evaluations of these factors and considerations for configuration changes resulting from implementation of this engineering change concluded that the modifications implemented by EC 403752 do not result in more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety previously evaluated in the UFSAR. Implementation of EC 403752 does not introduce SSC failures which could increase dose consequences described in the UFSAR, and does not result in more than a minimal increase in the consequences of a malfunction of an SSC important to safety previously evaluated in the UFSAR.

With the enhancements to SSF letdown line performance and design for robust qualification and installation of the piping and components for the EC 403752 modifications, these activities do not introduce accident initiation mechanisms for accidents of a different type than any previously evaluated in the UFSAR, and ensure that the possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated in the UFSAR is not created.

Attachment 4 - Page 1 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report Although RCS design pressure and containment design pressure are identified as design basis limits for a fission product barrier (DBLFPBs), the RCS design pressure and the containment design pressure will ---

NOT be exceeded or altered as a result of implementation EC 403752.

EC 403752 calculations do not revise or replace an evaluation methodology described in the UFSAR that is used in establishing the design basis or is used in the safety analyses.

Attachment 4 - Page 2 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 409202, Keowee Auxiliary Power Manual Alignment (AR 02153837)

Summary:

Engineering Change (EC) 409202 is a no field work EC that credits operator action to align auxiliary power to the operable Keowee Hydro Unit (KHU) if necessary in support of the Protected Service Water (PSW) System when the KHU aligned to the overhead power path is unavailable, such as during the planned replacement of the generator stator in each KHU. During normal operation, with both KHUs operable, one unit is aligned to supply power to the overhead path (via the switchyard) and in turn, receive auxiliary power from the generator output connection. The other unit is aligned to the underground path and, for independence, would receive auxiliary power from the 1TC switchgear. The Keowee Load Centers 1X and 2X have an automatic transfer feature that aligns its load center to an alternate source, if one is available. This feature is not credited so operator action is necessary to verify that the KHU aligned to the underground receives auxiliary power. For a postulated Design Basis Event, a fire in the Turbine Building is not assumed and the KHU aligned to the underground would not loose auxiliary power as a result of this Turbine Building fire. The Bases for TS 3.7.10 will be revised to add additional/more restrictive equipment requirements on the underground assigned KHU when it is credited for providing power to PSW. A change is proposed for SLC Table 16.13.1-1 to require a Keowee Operator in the Keowee Control Room when one KHU is credited to support PSW operability. The effects of crediting operator actions proposed by EC 409202 necessitated that a 10 CFR 50.59 Evaluation be performed.

In performing the 10 CFR 50.59 Evaluation, the determination was made that the EC 409202 design does not result in more than a minimal increase in the frequency of occurrence of an accident previously evaluated in the UFSAR, since, neither the KHUs nor the PSW System is an initiator of accidents previously evaluated in the UFSAR. The KHUs are the emergency power source credited in the mitigation of certain Design Basis Events. The KHUs also serve as an assured power source for the PSW System. The PSW System serves as added defense-in-depth protection by serving as a backup to existing safety systems. Evaluations of the operator actions implemented by EC 409202 concluded that they do not result in more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety previously evaluated in the UFSAR. Implementation of EC 409202 does not introduce SSC failures which could increase dose consequences described in the UFSAR, and does not result in more than a minimal increase in the consequences of a malfunction of an SSC important to safety previously evaluated in the UFSAR.

With the credit for operator actions, these activities do not introduce accident initiation mechanisms for accidents of a different type than any previously evaluated in the UFSAR, and ensure that the possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated in the UFSAR is not created.

The fuel cladding, RCS design pressure, and containment design pressure are identified as design basis limits for a fission product barrier (DBLFPBs), the activity proposed by EC 409202 to credit operator action to align auxiliary power to a single operable Keowee unit does not affect the containment design basis pressure limit, the design basis pressure limit for the RCS boundary, or any fuel cladding parameter.

Attachment 4 - Page 3 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report EC 409202 calculations do not revise or replace an evaluation methodology described in the UFSAR that is used in establishing the design basis or is used in the safety analyses.

Attachment 4 - Page 4 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

Replace Chilled Water (WC) System Control Room Chiller A (AR 02161515)

Summary:

The existing Chiller A currently is a digital rotary screw chiller which is replaced with a new digitally controlled centrifugal chiller per Engineering Change (EC) 114675. The Chiller A replacement scope includes:

Chiller A replacement, including all associated support components and new digital controls

Modbus tie-in to the Operator Aide Computer (OAC)

New chiller refrigerant monitor to detect any released refrigerant in the Turbine Building

New digital controls for the Chiller A condenser cooling water recirculation control valve Partial turnover and testing of the new chiller are addressed in the 50.59 Screen and are not adverse to the applicable UFSAR design functions.

The Technical Specification Bases and Selected Licensing Commitments are reviewed in the 50.59 Screen for this activity and no changes were required.

This activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07, NEI 01-01, and EPRI TR-102348 (Ref. AR 02161515).

The proposed activity does not modify, delete, or add to the Technical Specifications.

The chiller design is being implemented to maintain existing plant capabilities. This change does not require any changes to the existing Technical Specifications. The Technical Specifications will continue to be met as they are currently written with the new chiller installed. Also, the applicable Technical Specifications will be met during installation, partial turnover, and testing of the new chiller.

The proposed activity does not change any existing UFSAR SSC design functions.

The new chiller will perform the same function as the existing chiller, does not introduce any new failure modes and does not change the results of the existing failure modes.

Thus there is no failure with a different result.

The new chiller has upgraded digital controls different than the existing digital chiller which perform existing chiller control functions and adds digital control of chiller condenser cooling water flow from the new chiller touch screen control panel. The new controls and status displays are upgraded from the previous manual pushbuttons and scrolling digital LED status display. The new chiller purge system, which removes refrigerant and non-condensables from chiller in-leakage, recovers refrigerant, and discharges the non-condensables, is also controlled via the chiller digital controller.

The new chiller does not require access to a computing network to perform its functions.

It uses a Modbus connection in order to provide for transmission of chiller status and alarm information to the OAC. The networked MODBUS connection is configured to send information from the chiller controller to the OAC to provide chiller status and alarm Attachment 4 - Page 5 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report data to the OAC; it is not configured to receive information from the OAC to the chiller and cannot be used to change chiller control configurations. Controller security features prevent unauthorized changes to the chiller controls.

The new stand-alone Turbine Building refrigerant monitoring instrumentation is also digitally controlled, but separate from the chiller controller. Other than the primary power supply, the monitor is independent from other systems. This instrumentation functions only for detection and alarm of refrigerant releases.

The WC chillers are not UFSAR accident initiators and there are no credible accidents which could possibly be created from this activity to replace the Chiller A.

Based on the evaluations performed in EC 114675, and as presented in this Evaluation, it is qualitatively concluded that any change in the likelihood of a malfunction is negligible (i.e., not discernable) as described in NEI 96-07, Section 4.3.2.

The WC chillers have no impact on UFSAR analyzed accidents for dose. There is nothing in the UFSAR dose analyses explicitly related to the WC chiller function or failure of the WC chillers.

Replacement of the Chiller A and changing control of chiller condenser water flow from a separate controller to control from the new chiller controls does not create a possibility for a malfunction of an SSC important to safety with a different result.

The proposed activity does not directly or indirectly involve the fuel, the reactor coolant system pressure boundary, the containment, or any of the design basis limits associated with these fission product barriers. Consequently, the activity cannot result in a design basis limit for a fission product barrier as described in the FSAR being exceeded or altered.

The proposed activity neither involves a change to any element of the analytical methods described in the UFSAR used to demonstrate the design meets the design bases or that the safety analyses are acceptable, nor involves use of a method or evaluation not already approved by the NRC. Therefore, the proposed activity will not result in a departure from a method of evaluation described in the UFSAR used in establishing the design bases or in the safety analyses.

This evaluation includes application of the guidance in EPRI TR-102348 to ensure that all concerns associated with any new or upgraded digital equipment within the scope of EC 114675 are addressed. These changes are not adverse to the UFSAR chiller design functions, a Licensing Amendment Request (LAR) is not required, and prior NRC approval is not required to implement these changes.

Therefore, this activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 6 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 405339 (Rev 001) Reroute the Keowee Turbine Sump Discharge Piping to the Keowee Station Sump to Prevent Oil Discharging to the Tailrace (AR 02177848)

Summary:

Engineering Change (EC) 405339 installs new piping and valves in the Keowee Turbine Sump Pump System to allow the discharge of each Keowee wheel pit sump pump to be directed to the Keowee station sump. A new pipe tee will be installed in each wheel pit sump pump discharge header to facilitate connecting the new pipe to the Keowee station sump. The Keowee station sump collects other miscellaneous leakage in the Keowee Powerhouse including groundwater in-leakage. The station sump has a skimmer that functions to collect oil and prevent its discharge to the environment. The station sump also discharges to the Keowee tailrace. The station sump pumps are not safety related.

The new valves and piping will allow the flow path to the station sump to be the normal operational alignment for the wheel pit pumps. Following an emergency start of Keowee, an operator will re-direct the discharge of the wheel pit sump pumps to the tail race. A new Time Critical Operator Action will be added to Appendix C of the Design Basis Event Design Basis Document for an operator to realign each wheel pit sump discharge to the tail race. Without the realignment, the station sump could fill to a level that would adversely impact operation of the Keowee units. The station sump pumps are not safety related and therefore not credited in a Design Basis Event (DBE).

In order to meet single failure criteria, two valves are added in series to ensure that the discharge path to the station sump can be isolated, and two valves are added in parallel to ensure a path to the tail race following an emergency Keowee start. The check valves in the discharge line from the AC and DC pumps will be replaced to improve component reliability and reduce line losses.

EC 405339 also removes the existing flow orifice and its test connection valves and installs a flow meter in each of the new piping runs from the Turbine Sump system to the station sump. These new flow instruments are for operational convenience during routine testing and are not relied upon in a DBE.

The effects of crediting operator actions proposed by EC 405339 necessitated that a 10 CFR 50.59 Evaluation be performed.

In performing the 10 CFR 50.59 Evaluation, the determination was made that the EC 405339 design does not result in more than a minimal increase in the frequency of occurrence of an accident previously evaluated in the UFSAR, since, neither the KHUs nor the PSW System is an initiator of accidents previously evaluated in the UFSAR. The KHUs are the emergency power source credited in the mitigation of certain Design Basis Events. The KHUs also serve as an assured power source for the PSW System. The PSW System serves as added defense-in-depth protection by serving as a backup to existing safety systems. Evaluations of the operator actions implemented by EC 405339 concluded that they do not result in more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety previously evaluated in the UFSAR. Implementation of EC 405339 does not introduce SSC failures which could increase dose consequences described in the UFSAR, and does not result in more than a minimal increase in the consequences of a malfunction of an SSC important to safety previously evaluated in the UFSAR.

Attachment 4 - Page 7 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report With the credit for operator actions, these activities do not introduce accident initiation mechanisms for accidents of a different type than any previously evaluated in the UFSAR, and ensure that the possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated in the UFSAR is not created.

The fuel cladding, RCS design pressure, and containment design pressure are identified as design basis limits for a fission product barrier (DBLFPBs), the activity proposed by EC 405339 to credit operator action to re-align the discharge of each wheel pit sump pump from the Keowee station sump to the Keowee tailrace does not affect the containment design basis pressure limit, the design basis pressure limit for the RCS boundary, or any fuel cladding parameter.

EC 405339 calculations do not revise or replace an evaluation methodology described in the UFSAR that is used in establishing the design basis or is used in the safety analyses.

Attachment 4 - Page 8 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 410362 Replace Molded Case Circuit Breaker in MCC 1XS3 (AR 02181733)

Summary:

EC 410362 will replace all obsolete molded case breakers (MCB) in safety-related MCC 1XS3 with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 410362 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 9 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 410376 Replace Molded Case Circuit Breakers in MCC 1XB (AR 02181735)

Summary:

EC 410376 will replace all obsolete molded case breakers (MCB) in non-safety-related MCC 1XB with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 410376 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 10 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 410371 Replace Molded Case Circuit Breakers in MCC 1XGA (AR 02181737)

Summary:

EC 410371 will replace all obsolete molded case breakers (MCB) in non-safety-related MCC 1XGA with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 410371 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 11 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 410375 Replace Molded Case Circuit Breakers in MCC 1XO (AR 02181738)

Summary:

EC 410375 will replace all obsolete molded case breakers (MCB) in non-safety-related MCC 1XO with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 410375 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 12 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 410374 Replace Molded Case Circuit Breakers in MCC 1XGB (AR 02181739)

Summary:

EC 410374 will replace all obsolete molded case breakers (MCB) in non-safety-related MCC 1XGB with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 410374 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10CFR50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10CFR50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 13 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 408957 (Rev 002) Unit 3 Replace Molded Case Circuit Breakers in 3XS3 (AR 02185045)

Summary:

EC 408957 will replace obsolete molded case breakers (MCB) in safety-related MCC 3XS3 with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 408957 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 14 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 408976 (Rev 002) Unit 3 Replace Molded Case Circuit Breakers in 3XSF (AR 02186990)

Summary:

EC 408976 will replace obsolete molded case breakers (MCB) in safety-related MCC 3XSF with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 408976 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 15 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 408833 (Rev 002) Unit 3 Replace Molded Case Circuit Breakers in 3XD (AR 02187093)

Summary:

EC 408833 will replace obsolete molded case breakers (MCB) in safety-related MCC 3XD with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 408833 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 16 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 408933 (Rev 002) Unit 3 Replace Molded Case Circuit Breakers in 3XT (AR 02188049)

Summary:

EC 408933 will replace obsolete molded case breakers (MCB) in non-safety-related MCC 3XT with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 408933 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 17 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 408898 (Rev 002) Unit 3 Replace Molded Case Circuit Breakers in 3XR (AR 02188603)

Summary:

EC 408898 will replace obsolete molded case breakers (MCB) in non-safety-related MCC 3XR with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 408898 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 18 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 408866 (Rev 002) Unit 3 Replace Molded Case Circuit Breakers in 3XP (AR 02188610)

Summary:

EC 408866 will replace obsolete molded case breakers (MCB) in non-safety-related MCC 3XP with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 408866 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 19 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 408850 (Rev 002) Unit 3 Replace Molded Case Circuit Breakers in 3XE (AR 02188645)

Summary:

EC 408850 will replace obsolete molded case breakers (MCB) in non-safety-related MCC 3XE with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 408850 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 20 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 407084 (Rev 001) Replace Molded Case Breaker in MCC 2XF (AR 02191064)

Summary:

EC 407084 will replace obsolete molded case breakers (MCB) in non-safety-related MCC 2XF with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 407084 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 21 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 405518 (Rev 001) Unit 2 Replace Molded Case Circuit Breakers in 2XS3 (AR 02191146)

Summary:

EC 405518 will replace obsolete molded case breakers (MCB) in safety-related MCC 2XS3 with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 405518 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 22 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 406760 (Rev 001) Replace Molded Case Circuit Breakers in MCC 2XB (AR 02191150)

Summary:

EC 406760 will replace obsolete molded case breakers (MCB) in non-safety-related MCC 2XB with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 406760 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 23 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 407031 (Rev 001) Replace Molded Case Breakers in MCC 2XE (AR 02191155)

Summary:

EC 407031 will replace obsolete molded case breakers (MCB) in non-safety-related MCC 2XE with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 407031 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 24 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 407097 (Rev 001) Replace Molded Case Breaker in MCC 2XO (AR 02191161)

Summary:

EC 407097 will replace obsolete molded case breakers (MCB) in non-safety-related MCC 2XO with GE Spectra breakers containing a digital trip unit.

The proposed activity replaces a thermal-magnetic breaker with a breaker containing an digital trip unit. The MCCB trip functions are controlled by an ASIC (application specific integrated circuit) chip, which is a solid state device, that contains a mix of totally fixed analog and digital circuitry that perform a specific set of functions related to the Spectra Breaker's overall function. The ASIC item used in the new breaker to select the trip type and trip threshold levels is a relatively simple device. It does not contain software or firmware to perform the MCCB trip functions.

EC 407097 does not add or remove any breakers nor add or remove any design functions for mitigating any design basis accident or transients. Existing tech specs cover the loads and design function for the loads in the power path from the breakers being replaced. Therefore, no new Tech Specs are required.

The failure modes of the new breaker are bounded by failure modes of the existing, and application of the new breaker is consistent with the design inputs. The new breaker meets the qualification and quality requirements for this application, and the breaker also meets the design inputs required for this application.

The activity has been evaluated per 10 CFR 50.59, in accordance with AD-LS-ALL-0008, and following the guidance provided in NEI 96-07 (Rev. 1) and NEI 01-01. The conclusion of the Evaluation is that the proposed activity may be implemented under 10 CFR 50.59 without requiring prior NRC review or approval.

Attachment 4 - Page 25 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 412034 Revise the RCS Design Basis Specification OSS-0254.00 1033 and SLC 16.5.12 to Change RCS Leak Testing Pressure (AR 02191856)

Summary:

Engineering Change (EC) 412034 is to revise the Reactor Coolant System (RCS)

Design Basis Specification OSS-0254.00-00-1033 to change the specified pressure for leak testing the system after it has been opened. Section 2.2.2.1 (RCS Pressure/Temperature Limits) of the RCS Design Basis Specification contains information that the leak test pressure is to be not less than 2200 psig. It has this requirement listed under a heading of Related Selected Licensee Commitments and the requirement references Selected Licensee Commitment (SLC) 16.5.12. The Design Basis Specification also lists the same requirement in Design Requirement Appendix B.39. This test pressure is to be changed from the not less than 2200 psig to a pressure not less than the pressure corresponding to 100% rated reactor power. This EC also is to revise Selected Licensee Commitment (SLC) 16.5.12, which addresses the RCS leak testing following the opening of the system. Currently, there is a surveillance requirement (SR) 16.5.12.1 to Perform RCS leakage test at not less than 2200 psig.

This SR is proposed to be changed to Perform RCS leakage test at a pressure not less than the pressure corresponding to 100% rated reactor power. This new wording is based on requirements in the American Society of Mechanical Engineers (ASME)

Section XI Codes for Inservice Inspection for this RCS leakage testing. The pressure that is listed in the UFSAR that corresponds to 100% rated reactor power is approximately 2155 psig.

Based on wording in the UFSAR and the Duke/NRC correspondence, the determination was made that the NRCs acceptance criteria for the pressure testing of the RCS after opening the system is that the pressure requirement is based on Oconee meeting Section XI for its specified test pressure. Thus, a reduction in the pressure for the Design Basis Testing Specification and SLC requirement to that of the wording in the Section XI codes is within the bounds of what the NRC has used as Inservice Inspection requirements for RCS pressure for test after opening the system.

Again, since the NRCs acceptance of the pressure testing is based on meeting Section XI codes, and the pressure of the proposed SLC change would be meeting Section XI requirements, there is no change in the dose consequences since the acceptance from the NRC and the SLC change are the same. Thus, there would not be an increase in the consequences of an accident or malfunction of equipment as previously evaluated.

No new accidents are postulated and no malfunctions with a different result are postulated. No changes are made to design basis limits for fission product barriers.

There are no methodology changes associated with this activity.

Attachment 4 - Page 26 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 408968 Unit 2 Start-up Transformer (CT2) Open Phase Protection Equipment Installation & Tie-ins (AR 02198545)

Summary:

This evaluation addresses the addition of an Open Phase Protection (OPP) System for ONS Unit 2 Startup Transformer CT2 implemented under Engineering Change (EC) 409968. Open phase detection is to be installed on the primary winding of Transformer CT2. To avoid potential damage to safety-related loads fed from the 4160-volt main feeder busses, actuation of the OPP system will separate the 230 kV source from CT2 to 6900 Volt and 4160 Volt busses the by actuating the lockout relay for Transformer CT2. In accordance with the NEI 13-12 initiative, an open phase condition will be alarmed in the control room. This change involves no digital components. It will not require a revision or addition to the Technical Specification. This change has been evaluated against the eight (8) questions required by 10 CFR 50.59. From this evaluation it is concluded that the change can be implemented under 10 CFR 50.59 without prior approval from the NRC.

Attachment 4 - Page 27 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 407343 Unit 3 Start-up Transformer (CT3) Open Phase Protection Equipment Installation & Tie-ins (AR 02198906)

Summary:

This evaluation addresses the addition of an Open Phase Protection (OPP) System for ONS Unit 3 Startup Transformer CT3 implemented under Engineering Change (EC) 407343. Open phase detection is to be installed on the primary winding of Transformer CT3. To avoid potential damage to safety-related loads fed from the 4160-volt main feeder busses, actuation of the OPP system will separate the 230 kV source from CT3 to 6900 Volt and 4160 Volt busses the by actuating the lockout relay for Transformer CT3. In accordance with the NEI 13-12 initiative, an open phase condition will be alarmed in the control room. This change involves no digital components. It will not require a revision or addition to the Technical Specification. This change has been evaluated against the eight (8) questions required by 10CFR50.59. From this evaluation it is concluded that the change can be implemented under 10CFR50.59 without prior approval from the NRC.

Attachment 4 - Page 28 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 407344 Unit 1 Start-up Transformer (CT1) Open Phase Protection Equipment Installation & Tie-ins (AR 02199933)

Summary:

This evaluation addresses the addition of an Open Phase Protection (OPP) System for ONS Unit 1 Startup Transformer CT1 implemented under Engineering Change (EC) 407344. Open phase detection is to be installed on the primary winding of Transformer CT1. To avoid potential damage to safety-related loads fed from the 4160-volt main feeder busses, actuation of the OPP system will separate the 230 kV source from CT1 to 6900 Volt and 4160 Volt busses the by actuating the lockout relay for Transformer CT1. In accordance with the NEI 13-12 initiative, an open phase condition will be alarmed in the control room. This change involves no digital components. It will not require a revision or addition to the Technical Specification. This change has been evaluated against the eight (8) questions required by 10CFR50.59. From this evaluation it is concluded that the change can be implemented under 10CFR50.59 without prior approval from the NRC.

Attachment 4 - Page 29 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 410355 Keowee Open Phase Protection Equipment Installation & Tie-ins (AR 02210339)

Summary:

This evaluation addresses the addition of an Open Phase Protection (OPP) System for the Keowee Main Step-up (KMSU) Transformer implemented under Engineering Change (EC) 410355. Open phase detection is to be installed on the primary winding of KMSU Transformer.

To avoid potential damage to safety-related loads fed from the 4160-volt main feeder busses, actuation of the OPP system will separate the 230 kV Keowee overhead line to the Yellow 230 kV buss the by actuating the lockout relay for the KMSU Transformer. In accordance with the NEI 13-12 initiative, an open phase condition will be alarmed in the Keowee control room. This change involves no digital components. It will not require a revision or addition to the Technical Specification. This change has been evaluated against the eight (8) questions required by 10CFR50.59. From this evaluation it is concluded that the change can be implemented under 10CFR50.59 without prior approval from the NRC.

Attachment 4 - Page 30 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

EC 404830 Transformer (CT5) Open Phase Protection Installation and Tie-ins (AR 0221964)

Summary:

This evaluation addresses the addition of an Open Phase Protection (OPP) System for ONS Transformer CT5 implemented under Engineering Change (EC) 405830. Open phase detection is to be installed on the primary winding of Transformer CT5. To avoid potential damage to safety-related loads fed from the 4160-volt main feeder busses, actuation of the OPP system will separate the 100 kV offsite power source from the standby busses by actuating the lockout relay for Transformer CT5. In accordance with the NEI 13-12 initiative, an open phase condition will be alarmed in the control room.

This change involves no digital components. It will not require a revision or addition to the Technical Specification. This change has been evaluated against the eight (8) questions required by 10CFR50.59. From this evaluation it is concluded that the change can be implemented under 10CFR50.59 without prior approval from the NRC.

Attachment 4 - Page 31 of 32

Oconee Nuclear Station 10 CFR 50.59 Summary Report

Title:

Revision to UFSAR Section 9.1.5 (AR 02246774)

Summary:

The method of inspection of the vessel head lifting rig and internals lifting rig will be changed to acoustic emissions testing. This new method of Non-destructive Examination (NDE) has previously been approved for use at Tennessee Valley Authority (TVA) and will save significant dose and effort by allowing the inspection to be performed as the rig is being used eliminating the need to disassemble and remove the lifting rig from the reactor building to perform the inspection.

Section 9.1.5.4.1 of the Oconee Nuclear Station UFSAR will also be revised to add "Acoustic emissions testing has been justified as an alternative NDE testing method for the reactor vessel head and reactor internals lifting rigs".

NRC Staff in the TVA Safety Evaluation Report concluded that the acoustic emission monitoring technique of the reactor vessel head and reactor internals lifting rigs provides adequate assurance for safe operation. The intent of the ANSI N14.6 and NUREG-0612 guideline is to detect potential cracks and or flaws rendering the special lifting equipment not operable. The technique associated with a type of NDE inspection is being changed, however the intent associated with detecting flaws and or cracks is not being altered. The frequency of inspection is based on formation and propagation of a crack. ONS will maintain the 10-year inspection frequency previously approved by the NRC for the NDE inspection techniques described in ANSI N14.6-1978. Therefore, the SER for Sequoyah related to this inspection technique is applicable to ONS.

Attachment 4 - Page 32 of 32

U.S. Nuclear Regulatory Commission to RA-20-0136 Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, and 50-287 Renewed License Nos. DPR-38, DPR-47, and DPR-55 Submittal of Updated Final Safety Analysis Report (UFSAR) Revision 28, Technical Specifications Bases Revisions, Selected Licensee Commitments Revisions, 10 CFR 50.59 Evaluation Summary Report, and 10 CFR 54.37 Update Attachment 5 Technical Specification (TS) Bases Revisions

OCONEE NUCLEAR STATION TECHNICAL SPECIFICATIONS-BASES REVISED 12/19/2019 LIST OF EFFECTIVE PAGES SECTION/PAGES REVISION NUMBER IMPLEMENTATION DATE TOC 000 09/03/14 B 2.1.1 001 06/08/17 B 2.1.2 000 02/06/14 B 3.0 004 05/22/19 B 3.1.1 000 05/16/12 B 3.1.2 000 05/16/12 B 3.1.3 000 06/02/99 B 3.1.4 000 07/23/12 B 3.1.5 000 05/16/12 B 3.1.6 000 07/23/12 B 3.1.7 000 07/23/12 B 3.1.8 000 05/16/12 B 3.2.1 000 05/16/12 B 3.2.2 000 05/16/12 B 3.2.3 001 10/30/18 B 3.3.1 004 11/28/18 B 3.3.2 000 12/14/04 B 3.3.3 000 12/10/14 B 3.3.4 000 12/10/14 B 3.3.5 000 12/10/14 B 3.3.6 000 12/10/14 B 3.3.7 000 12/10/14 B 3.3.8 000 05/16/12 B 3.3.9 000 05/16/12 B 3.3.10 000 05/16/12 B 3.3.11 001 01/17/17 B 3.3.12 000 05/16/12 Oconee Nuclear Station LOEP 1 Revision 027

OCONEE NUCLEAR STATION TECHNICAL SPECIFICATIONS-BASES REVISED 12/19/2019 LIST OF EFFECTIVE PAGES SECTION/PAGES REVISION NUMBER IMPLEMENTATION DATE B 3.3.13 000 05/16/12 B 3.3.14 001 01/17/17 B 3.3.15 000 05/16/12 B 3.3.16 000 05/16/12 B 3.3.17 000 05/16/12 B 3.3.18 000 05/16/12 B 3.3.19 000 05/16/12 B 3.3.20 000 05/16/12 B 3.3.21 000 05/16/12 B 3.3.22 000 05/16/12 B 3.3.23 000 05/16/12 B 3.3.24 000 09/26/01 B 3.3.25 000 11/05/03 B 3.3.26 000 11/05/03 B 3.3.27 000 12/10/14 B 3.3.28 000 05/16/12 B 3.4.1 000 05/16/12 B 3.4.2 000 12/16/98 B 3.4.3 001 01/17/17 B 3.4.4 002 12/19/19 B 3.4.5 000 05/16/12 B 3.4.6 001 04/18/17 B 3.4.7 001 04/18/17 B 3.4.8 001 04/18/17 B 3.4.9 000 05/16/12 B 3.4.10 002 11/28/18 B 3.4.11 000 10/12/12 B 3.4.12 000 06/13/14 Oconee Nuclear Station LOEP 2 Revision 027

OCONEE NUCLEAR STATION TECHNICAL SPECIFICATIONS-BASES REVISED 12/19/2019 LIST OF EFFECTIVE PAGES SECTION/PAGES REVISION NUMBER IMPLEMENTATION DATE B 3.4.13 001 01/17/17 B 3.4.14 001 09/21/15 B 3.4.15 001 11/24/15 B 3.4.16 001 08/23/16 B 3.5.1 000 05/16/12 B 3.5.2 004 11/28/18 B 3.5.3 004 11/28/18 B 3.5.4 000 05/16/12 B 3.6.1 001 01/17/17 B 3.6.2 001 01/17/17 B 3.6.3 001 11/28/18 B 3.6.4 000 05/16/12 B 3.6.5 003 11/28/18 B 3.7.1 003 11/28/18 B 3.7.2 000 11/13/12 B 3.7.3 002 11/28/18 B 3.7.4 002 01/17/17 B 3.7.5 002 11/28/18 B 3.7.6 000 05/16/12 B 3.7.7 000 12/10/14 B 3.7.8 000 05/16/12 B 3.7.9 001 09/26/18 B 3.7.10 004 11/28/18 B 3.7.10a 001 01/17/17 B 3.7.11 000 05/16/12 B 3.7.12 002 08/09/17 B 3.7.13 000 08/19/10 Oconee Nuclear Station LOEP 3 Revision 027

OCONEE NUCLEAR STATION TECHNICAL SPECIFICATIONS-BASES REVISED 12/19/2019 LIST OF EFFECTIVE PAGES SECTION/PAGES REVISION NUMBER IMPLEMENTATION DATE B 3.7.14 000 05/16/12 B 3.7.15 000 10/24/07 B 3.7.16 001 05/18/17 B 3.7.17 001 01/17/17 B 3.7.18 001 08/09/17 B 3.7.19 002 11/28/18 B 3.8.1 005 08/08/19 B 3.8.2 000 04/07/11 B 3.8.3 001 01/17/17 B 3.8.4 000 12/18/07 B 3.8.5 000 05/16/12 B 3.8.6 000 05/16/12 B 3.8.7 000 05/16/12 B 3.8.8 001 01/17/17 B 3.8.9 001 01/17/17 B 3.9.1 000 05/16/12 B 3.9.2 000 05/16/12 B 3.9.3 001 01/17/17 B 3.9.4 002 04/18/17 B 3.9.5 001 04/18/17 B 3.9.6 000 05/16/12 B 3.9.7 000 05/16/12 B 3.9.8 000 06/25/14 B 3.10.1 003 12/05/19 B 3.10.2 000 11/05/14 Note: With the introduction of Fusion in June 2015, all controlled documents require a three-digit revision number. Thus, the revision numbers were set to 000 in the summer of 2015. As such, the revision dates for Revision 000 are based on the implementation dates for revisions in effect prior to this change.

Oconee Nuclear Station LOEP 4 Revision 027

LCO Applicability B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY BASES LCOs LCO 3.0.1 through LCO 3.0.9 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

LCO 3.0.1 LCO 3.0.1 establishes the Applicability statement within each individual Specification as the requirement for when the LCO is required to be met (i.e., when the unit is in the MODES or other specified conditions of the Applicability statement of each Specification).

LCO 3.0.2 LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered, unless otherwise specified.

The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of an LCO are not met. This Specification establishes that:

a. Completion of the Required Actions within the specified Completion Times constitutes compliance with a Specification; and

b. Completion of the Required Actions is not required when an LCO is met within the specified Completion Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the LCO must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification is not applicable. (Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered upon entering ACTIONS.) The second type of Required Action specifies the remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time.

In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation.

OCONEE UNITS 1, 2, & 3 B 3.0-1 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.2 Completing the Required Actions is not required when an LCO is met or (continued) is no longer applicable, unless otherwise stated in the individual Specification.

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The individual LCO's ACTIONS specify the Required Actions where this is the case. An example of this is in LCO 3.4.3, "RCS Pressure and Temperature (P/T) Limits."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The ACTIONS for not meeting a single LCO adequately manage any increase in plant risk, provided any unusual external conditions (e.g., severe weather, offsite power instability) are considered. In addition, the increased risk associated with simultaneous removal of multiple structures, systems, trains or components from service is assessed and managed in accordance with 10 CFR 50.65(a)(4). Individual Specifications may specify a time limit for performing an SR when equipment is removed from service or bypassed for testing. In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment remains removed from service or bypassed.

When a change in MODE or other specified condition is required to comply with Required Actions, the unit may enter a MODE or other specified condition in which another Specification becomes applicable. In this case, the Completion Times of the associated Required Actions would apply from the point in time that the new Specification becomes applicable and the ACTIONS Condition(s) are entered.

LCO 3.0.3 LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and:

a. An associated Required Action and Completion Time is not met and no other Condition applies; or

b. The condition of the unit is not specifically addressed by the associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly OCONEE UNITS 1, 2, & 3 B 3.0-2 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.3 corresponds to the actual condition of the unit. Sometimes, (continued) possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the ACTIONS specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.

This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS.

Planned entry into LCO 3.0.3 should be avoided. If it is not practicable to avoid planned entry into LCO 3.0.3, plant risk should be assessed and managed in accordance with 10 CFR 50.65(a)(4), and the planned entry into LCO 3.0.3 should have less effect on plant safety than other practicable alternatives.

Upon entering LCO 3.0.3, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to prepare for an orderly shutdown before initiating a change in unit operation. This includes time to permit the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. If at the end of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , corrective measures which would allow exiting LCO 3.0.3 are not complete, but there is reasonable assurance that corrective measures will be completed in time to still allow for an orderly unit shutdown, commencing a load decrease may be delayed until that time. The time limits specified to enter lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times.

A unit shutdown required in accordance with LCO 3.0.3 may be terminated and LCO 3.0.3 exited if any of the following occurs:

a. The LCO is now met,

b. The LCO is no longer applicable,

c. A Condition exists for which the Required Actions have now been performed, or

d. ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited.

OCONEE UNITS 1, 2, & 3 B 3.0-3 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.3 The time limits of LCO 3.0.3 allow 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months for the unit to be in MODE 5 (continued) when a shutdown is required during MODE 1 operation. If the unit is in a lower MODE of operation when a shutdown is required, the time limit for entering the next lower MODE applies. If a lower MODE is entered in less time than allowed, however, the total allowable time to enter MODE 5, or other applicable MODE, is not reduced. For example, if MODE 3 is entered in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , then the time allowed for entering MODE 4 is the next 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months , because the total time for entering MODE 4 is not reduced from the allowable limit of 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months . Therefore, if remedial measures are completed that would permit a return to MODE 1, a penalty is not incurred by having to enter a lower MODE of operation in less than the total time allowed.

In MODES 1, 2, 3, and 4, LCO 3.0.3 provides actions for Conditions not covered in other Specifications. The requirements of LCO 3.0.3 do not apply in MODES 5 and 6 because the unit is already in the most restrictive Condition required by LCO 3.0.3. The requirements of LCO 3.0.3 do not apply in other specified conditions of the Applicability (unless in MODE 1, 2, 3, or 4) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken.

Exceptions to LCO 3.0.3 are provided in instances where requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the associated condition of the unit. An example of this is in LCO 3.7.11, "Spent Fuel Pool Water Level." LCO 3.7.11 has an Applicability of "During movement of irradiated fuel assemblies in the spent fuel pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.11 are not met while in MODE 1, 2, 3, or 4, there is no safety benefit to be gained by placing the unit in a shutdown condition. The Required Action of LCO 3.7.11 of "Suspend movement of irradiated fuel assemblies in spent fuel pool" is the appropriate Required Action to complete in lieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications.

LCO 3.0.4 LCO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCO is not met. It precludes placing the unit in a MODE or other specified condition stated in that Applicability (e.g., Applicability desired to be entered) when the following exist:

a. Unit conditions are such that the requirements of the LCO would not be met in the Applicability desired to be entered; and

b. Continued noncompliance with the LCO requirements, if the Applicability were entered, would result in the unit being required to OCONEE UNITS 1, 2, & 3 B 3.0-4 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.4 exit the Applicability desired to be entered to comply with the Required (continued) Actions. Compliance with ACTIONS that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the unit before or after the MODE change.

Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made and the Required Actions followed after entry into the Applicability. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

For example, the provisions of LCO 3.0.4 may be used when the Required Action to be entered states that an inoperable instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified condition in the Applicability may be made in accordance with LCO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicability is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION (Required Action and associated Completion Time not met) allows the OPERABLE train to be placed in operation, use of LCO 3.0.4 is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation) that permit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.

The provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown.

Exceptions to LCO 3.0.4 are stated in the individual Specifications. The exceptions allows entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time. Exceptions may apply to all the ACTIONS or to a specific Required Action of a Specification.

LCO 3.0.4 is only applicable when entering MODE 4 from MODE 5, MODE 3 from MODE 4, MODE 2 from MODE 3, or MODE 1 from MODE 2.

Furthermore, LCO 3.0.4 is applicable when entering any other specified condition in the Applicability associated with operating in MODES 1, 2, 3, or

4. The requirements of LCO 3.0.4 do not apply in MODES 5 and 6, or in other specified conditions of the Applicability (unless in MODES 1, 2, 3, or 4) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken.

OCONEE UNITS 1, 2, & 3 B 3.0-5 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.4 Surveillances do not have to be performed on the associated inoperable (continued) equipment (or on variables outside the specified limits), as permitted by SR 3.0.1. Therefore, changing MODES or other specified conditions while in an ACTIONS Condition, in compliance with LCO 3.0.4 or where an exception to LCO 3.0.4 is stated, is not a violation of SR 3.0.1 or SR 3.0.4 for those Surveillances that do not have to be performed due to the associated inoperable equipment. However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected LCO.

LCO 3.0.5 LCO 3.0.5 establishes the allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply with the applicable Required Action(s)) to allow the performance of required testing to demonstrate:

a. The OPERABILITY of the equipment being returned to service; or

b. The OPERABILITY of other equipment.

The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the required testing to demonstrate OPERABILITY. This Specification does not provide time to perform any other preventive or corrective maintenance. LCO 3.0.5 should not be used in lieu of other practicable alternatives that comply with Required Actions and that do not require changing the MODE or other specified conditions in the Applicability in order to demonstrate equipment is OPERABLE. LCO 3.0.5 is not intended to be used repeatedly.

An example of demonstrating equipment is OPERABLE with the Required Actions not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolation Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now within limit.

Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and indicate the appropriate response during performance of required testing OCONEE UNITS 1, 2, & 3 B 3.0-6 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.5 on the inoperable channel. Examples of demonstrating the OPERABILITY (continued) of other equipment are taking an inoperable channel or trip system out of the tripped condition 1) to prevent the trip function from occurring during the performance of required testing on another channel in the other trip system, or 2) to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same trip system.

The administrative controls in LCO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted while complying with the Required Actions.

This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS.

LCO 3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that have an LCO specified in the Technical Specifications (TS). This exception is provided because LCO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the unit is maintained in a safe condition are specified in the support system LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions. When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCOs' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the unit is maintained in a safe condition in the support system's Required Actions.

However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system. This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry in Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2.

OCONEE UNITS 1, 2, & 3 B 3.0-7 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.6 Specification 5.5.16, "Safety Function Determination Program (SFDP),"

(continued) ensures loss of safety function is detected and appropriate actions are taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperability and corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the requirements of LCO 3.0.6.

Cross train checks to identify a loss of safety function for those support systems that support multiple and redundant safety systems are required.

The cross train check verifies that the supported systems of the remaining OPERABLE support systems are OPERABLE, thereby ensuring safety function is retained.

a. A required system redundant to system(s) supported by the inoperable support system is also inoperable; or (EXAMPLE B3.06-1)

b. A required system redundant to system(s) in turn supported by the inoperable supported system is also inoperable; or (EXAMPLE B3.06-2)

c. A required system redundant to support system(s)for the supported systems (a) and (b) above is also inoperable. (EXAMPLE B3.06-3)

EXAMPLE B3.06-1 If System 2 of Train A is inoperable, and System 5 of Train B is inoperable, a loss of safety function exists in supported System 5.

EXAMPLE B3.06-2 If System 2 of Train A is inoperable, and System 11 of Train B is inoperable, a loss of safety function exists in System 11 which is in turn supported by System 5.

EXAMPLE B3.06-3 If System 2 of Train A is inoperable, and System 1 of Train B is inoperable, a loss of safety function exists in Systems 2, 4, 5, 8, 9, 10 and 11.

If this evaluation determines that a loss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

OCONEE UNITS 1, 2, & 3 B 3.0-8 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.6 (continued)

EXAMPLES TRAIN A TRAIN B System 4

[System 8 System 9 System 4

[

System 8 System 9

[ [

System 2 System 2 System 10 System 10 System 5 System 5 System 11 System 11 System 1 System 1

[ [

System 12 System 12 System 6 System 6 System 13 System 13

[ [

System 3 System 3 System 14 System 14 System 7 System 7 System 15 System 15 LCO 3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit. These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance activities, and to perform special evolutions.

Test Exception LCO 3.1.8 allows specified Technical Specification (TS) requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the requirements of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.

The Applicability of a Test Exception LCO represents a condition not necessarily in compliance with the normal requirements of the TS.

Compliance with Test Exception LCOs is optional. A special operation may be performed either under the provisions of the appropriate Test Exception LCO or under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Test Exception LCO, the requirements of the Test Exception LCO shall be followed.

OCONEE UNITS 1, 2, & 3 B 3.0-9 Rev. 004

LCO Applicability B 3.0 BASES (continued)

LCO 3.0.8 LCO 3.0.8 establishes conditions under which systems are considered to remain capable of performing their intended safety function when associated snubbers are not capable of providing their associated support function(s). This LCO states that the supported system is not considered to be inoperable solely due to one or more snubbers not capable of performing their associated support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing, or repair of one or more snubbers not capable of performing their associated support function(s) and appropriate compensatory measures are specified in the snubber requirements, which are located outside of the Technical Specifications (TS) under licensee control. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for control by the licensee.

If the allowed time expires and the snubber(s) are unable to perform their associated support function(s), the affected supported systems LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

LCO 3.0.8.a applies when one or more snubbers are not capable of providing their associated support function(s) to a single train of a multiple train or to a single train system. LCO 3.0.8.a allows 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to restore the snubber(s) before declaring the supported system inoperable. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function and due to the availability of the redundant train of the supported system.

LCO 3.0.8.b applies when one or more snubbers are not capable of providing their associated support function(s) to more than one train of a multiple train system. LCO 3.0.8.b allows 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to restore the snubber(s) before declaring the supported system inoperable. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function.

LCO 3.0.8 requires that risk be assessed and managed. Industry and NRC guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address seismic risk. However, use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of systems and components when one or more snubbers are not able to perform their associated support function.

OCONEE UNITS 1, 2, & 3 B 3.0-10 Rev. 004

LCO Applicability B 3.0 BASES (continued)

LCO 3.0.9 LCO 3.0.9 establishes conditions under which systems described in the Technical Specifications are considered to remain OPERABLE when required barriers are not capable of providing their related support function (s).

Barriers are doors, walls, floor plugs, curs, hatches, installed structures or components, or other devices, not explicitly described in Technical Specifications, that support the performance of the safety function of systems described in the Technical Specifications. This LCO states that the supported system is not considered to be inoperable solely due to required barriers not capable of performing their related support function(s) under the described conditions. LCO 3.0.9 allows 30 days before declaring the supported system(s) inoperable and the LCO(s) associated with the supported system(s) not met. A maximum time is placed on each use of this allowance to ensure that as required barriers are found or are otherwise made unavailable, they are restored. However, the allowable duration may be less than the specified maximum time based on the risk assessment.

If the allowed time expires and the barriers are unable to perform their related support function(s), the supported systems LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

This provision does not apply to barriers which support ventilation systems or to fire barriers. The Technical Specifications for ventilation systems provide specific Conditions for inoperable barriers. Fire barriers are addressed by other regulatory requirements and associated plant programs. This provision does not apply to barriers which are not required to support system OPERABILITY (see NRC Regulatory Issue Summary 2001-09, Control of Hazard Barriers, dated April 2, 2001.

The provisions of LCO 3.0.9 are justified because of the low risk associated with required barriers not being capable of performing their related support function. This provision is based on consideration of the following initiating event categories:

Loss of coolant accidents,

High energy line breaks,

Feedwater line breaks,

Internal flooding,

External flooding,

Turbine missile ejection, and

Tornado or high wind The risk impact of the barriers which cannot perform their related support function(s) must be addressed pursuant to the risk assessment and OCONEE UNITS 1, 2, & 3 B 3.0-11 Rev. 004

LCO Applicability B 3.0 BASES LCO 3.0.9 management provision of the Maintenance Rule, 10 CFR 50.65 (a)(4),

(continued) and the associated implementation guidance, Regulatory Guide 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.

Regulatory guide 1.160 endorses the guidance in Section 11 of NUMARC 93-01, Revision 4A, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. This guidance provides for the consideration of dynamic plant configuration issues, emergent conditions, and other aspects pertinent to plant operation with the barriers unable to perform their related support function(s). These considerations may result in risk management and other compensatory actions being required during the period that barriers are unable to perform their related support function(s).

LCO 3.0.9 may be applied to one or more trains or subsystems of a system supported by barriers that cannot provide their related support function(s), provided that risk is assessed and managed (including consideration of the effects on Large Early Release and from external events). If applied concurrently to more than one train or subsystem of a multiple train or subsystem supported system, the barriers supporting LCO 3.0.9 each of these trains or subsystems must provide their related support function(s) for different categories of initiating events. For example, LCO 3.0.9 may be applied for up to 30 days for more than one train of a multiple train supported system if the affected barrier for one train protects against internal flooding and the affected barrier for the other train protects against tornado missiles. In this example, the affected barrier may be the same physical barrier but serve different protection functions for each train.

If during the time that LCO 3.0.9 is being used, the required OPERABLE train or subsystem becomes inoperable, it must be restored to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Otherwise, the train(s) or subsystem(s) supported by barriers that cannot perform their related support function(s) must be declared inoperable and the associated LCOs declared not met. This 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period provides time to respond to emergent conditions that would otherwise likely lead to entry into LCO 3.0.3 and a rapid plant shutdown, which is not justified given the low probability of an initiating event which would require the barrier(s) not capable of performing their related support function(s). During this 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period, the plant risk associated with the existing conditions is assessed and managed in accordance with 10 CFR 50.65(a)(4).

OCONEE UNITS 1, 2, & 3 B 3.0-12 Rev. 004

SR Applicability B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated. SR 3.0.2 and SR 3.0.3 apply in Chapter 5 only when invoked by a Chapter 5 Specification.

SR 3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when:

a. The systems or components are known to be inoperable, although still meeting the SRs; or

b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.

Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with an Exception LCO are only applicable when the Exception LCO is used as an allowable exception to the requirements of a Specification.

Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given SR. In this case, the unplanned event may be credited as fulfilling the performance of the SR. This allowance includes those SRs whose performance is normally precluded in a given MODE or other specified condition.

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status.

OCONEE UNITS 1, 2, & 3 B 3.0-13 Rev. 004

SR Applicability B 3.0 BASES SR 3.0.1 Upon completion of maintenance, appropriate post maintenance testing is (continued) required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed.

Some example of this process are:

a. Emergency feedwater (EFW) pump turbine maintenance during refueling that requires testing at steam pressures > 300 psi.

However, if other appropriate testing is satisfactorily completed, the EFW System can be considered OPERABLE. This allows startup and other necessary testing to proceed while the plant reaches the steam pressure required to perform the EFW pump testing.

b. High Pressure Injection (HPI) maintenance during shutdown that requires system functional tests at a specified pressure. Provided other appropriate testing is satisfactorily completed, startup can proceed with HPI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary post maintenance testing.

SR 3.0.2 SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action on a "once per..."

interval.

SR 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities).

When a Section 5.5, "Programs and Manuals," specification states that the provisions of SR 3.0.2 are applicable, a 25% extension of the testing interval, whether stated in the specification or incorporated by reference, is permitted.

OCONEE UNITS 1, 2, & 3 B 3.0-14 Rev. 004

SR Applicability B 3.0 BASES SR 3.0.2 The 25% extension does not significantly degrade the reliability that results (continued) from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the SRs.

The exceptions to SR 3.0.2 are those Surveillances for which the 25%

extension of the interval specified in the Frequency does not apply. These exceptions are stated in the individual Specifications. The requirements of regulations take precedence over the TS. Examples of where SR 3.0.2 does not apply are the Containment Leakage Rate Testing Program required by 10 CFR 50, Appendix J, and the inservice testing of pumps and valves in accordance with applicable American Society of Mechanical Engineers Operation and Maintenance Code, as required by 10 CFR 50.55a. These programs establish testing requirements and Frequencies in accordance with the requirements of the regulations. The TS cannot, in and of themselves, extend a test interval specified in the regulations directly or by reference.

As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per..."basis. The 25% extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.

The provisions of SR 3.0.2 are not intended to be used repeatedly to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified.

SR 3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been performed within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or up to the limit of the specified Frequency, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time that the specified Frequency was not met.

When a Section 5.5, "Programs and Manuals," specification states that the provisions of SR 3.0.3 are applicable, it permits the flexibility to defer declaring the testing requirement not met in accordance with SR 3.0.3 when the testing has not been completed within the testing interval (including the allowance of SR 3.0.2 if invoked by Section 5.5 specification).

OCONEE UNITS 1, 2, & 3 B 3.0-15 Rev. 004

SR Applicability B 3.0 BASES SR 3.0.3 This delay period provides an adequate time to perform Surveillances that (continued) have been missed. This delay period permits the performance of a Surveillance before complying with Required Actions or other remedial measures that might preclude performance of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements.

When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillance. However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

SR 3.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.

SR 3.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when performed. Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance, or a portion thereof, has ever been performed, and any other indications, tests, or activities that might support the expectation that the Surveillance will be met when performed. An example of the use of SR 3.0.3 would be a relay contact that was not tested as required in accordance with a particular SR, but previous successful performances of the SR included the relay contact; the adjacent, physically connected relay contacts were tested during the SR performance; the subject relay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the performance of similar equipment. The rigor of determining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed. For Surveillances that have not been performed for a long OCONEE UNITS 1, 2, & 3 B 3.0-16 Rev. 004

SR Applicability B 3.0 BASES SR 3.0.3 period or that have never been performed, a rigorous evaluation based on (continued) objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.

Failure to comply with specified Frequencies for SRs is expected to be an infrequent occurrence. Use of the delay period established by SR 3.0.3 is a flexibility which is not intended to be used repeatedly to extend Surveillance intervals. While up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the Surveillance. This risk impact should be managed through the program in pIace to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, 'Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants.' This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component.

Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the licensee's Corrective Action Program.

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon the failure of the Surveillance.

Satisfactory completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0.1.

OCONEE UNITS 1, 2, & 3 B 3.0-17 Rev. 004

SR Applicability B 3.0 BASES (continued)

SR 3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the Applicability.

This Specification ensures that system and component OPERABILITY SR 3.0.4 requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

However, in certain circumstances, failure to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change.

When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability. However, since the LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes.

The provisions of SR 3.0.4 shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown.

The precise requirements for performance of SRs are specified such that exceptions to SR 3.0.4 are not necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCO Applicability would have its Frequency specified such that it is not "due" until the specific conditions needed are met. Alternately, the Surveillance may be stated in the form of a Note, as not required (to be met or performed) until a particular event, condition, or time has been reached.

Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency.

OCONEE UNITS 1, 2, & 3 B 3.0-18 Rev. 004

SR Applicability B 3.0 BASES SR 3.0.4 SR 3.0.4 is only applicable when entering MODE 4 from MODE 5, MODE 3 (continued) from MODE 4, MODE 2 from MODE 3, or MODE 1 from MODE 2.

Furthermore, SR 3.0.4 is applicable when entering any other specified condition in the Applicability associated with operation in MODES 1, 2, 3, or 4. The requirements of SR 3.0.4 do not apply in MODES 5 and 6, or in other specified conditions of the Applicability (unless in MODES 1, 2, 3, or

4) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken.

OCONEE UNITS 1, 2, & 3 B 3.0-19 Rev. 004

RCS Loops - MODES 1 and 2 B 3.4.4 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.4 RCS Loops - MODES 1 and 2 BASES BACKGROUND The primary function of the reactor coolant is removal of the heat generated in the fuel due to the fission process, and transfer of this heat, via the steam generators (SGs), to the secondary plant.

The secondary functions of the reactor coolant include:

a. Moderating the neutron energy level to the thermal state, to increase the probability of fission;

b. Improving the neutron economy by acting as a reflector;

c. Carrying the soluble neutron poison, boric acid;

d. Providing a second barrier against fission product release to the environment; and

e. Removing the heat generated in the fuel due to fission product decay following a unit shutdown.

The RCS configuration for heat transport uses two RCS loops. Each RCS loop contains an SG and two reactor coolant pumps (RCPs). An RCP is located in each of the two SG cold legs. The pump flow rate has been sized to provide core heat removal with appropriate margin to departure from nucleate boiling (DNB) during power operation and for anticipated transients originating from power operation. This Specification requires two RCS loops with either three or four pumps to be in operation. With three pumps in operation the reactor power level is restricted to 75% RTP to preserve the core power to flow relationship, thus maintaining the margin to DNB. The intent of the specification is to require core heat removal with forced flow during power operation. Specifying the minimum number of pumps is an effective technique for designating the proper forced flow rate for heat transport, and specifying two loops provides for the needed amount of heat removal capability for the allowed power levels. Specifying two RCS loops also provides the minimum necessary paths (two SGs) for heat removal.

The Reactor Protection System (RPS) trip setpoint based on flux/flow/imbalance is automatically reduced when one pump is taken out of service; manual resetting is not necessary.

OCONEE UNITS 1, 2, & 3 B 3.4.4-1 Rev. 002

RCS Loops-MODES 1 and 2 B 3.4.4 BASES (continued)

APPLICABLE Safety analyses contain various assumptions for the accident analyses SAFETY ANALYSES initial conditions including: RCS pressure, RCS temperature, reactor power level, core parameters, and safety system setpoints. The important aspect for this LCO is the reactor coolant forced flow rate, which is represented by the number of pumps in service.

Both transient and steady state analyses have been performed to establish the effect of flow on DNB. The transient or accident analysis for the plant has been performed assuming either three or four pumps are in operation.

The majority of the plant safety analysis is based on initial conditions at high core power or zero power. The analyses that are of most importance to RCP operation are the two pump coastdown, single pump locked rotor, and single pump broken shaft (Ref. 1).

Steady state DNB analysis has been performed for four, and three pump combinations. For four pump operation, the steady state DNB analysis, which generates the pressure and temperature protective limit (i.e., the departure from nucleate boiling ratio (DNBR) limit), assumes a maximum power level equal to the Nuclear Overpower - High Setpoint - 4 reactor coolant pumps running trip setpoint plus instrument uncertainty and conservatism. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.

The three pump pressure temperature limit is tied to the steady state DNB analysis, which is evaluated each cycle. The flow used is the minimum allowed for three pump operation. The actual RCS flow rate will exceed the assumed flow rate. With three pumps operating, overpower protection is automatically provided by the power to flow ratio of the RPS nuclear overpower trip setpoint based on flux/flow/imbalance and the Nuclear Overpower - High Setpoint - 3 reactor coolant pumps running once it has been reset by the operators. The maximum power level for three pump operation is 75% RTP and is based on the three pump flow as a fraction of the four pump flow at full power.

Continued power operation with two RCPs removed from service is not allowed by this Specification.

RCS Loops - MODES 1 and 2 satisfy Criterion 2 of 10 CFR 50.36 (Ref. 2).

LCO The purpose of this LCO is to require adequate forced flow for core heat removal. Flow is represented by the number of RCPs in operation in both RCS loops for removal of heat by the two SGs. To meet safety analysis acceptance criteria for DNB, four pumps are required at rated power; if only three pumps are available, power must be reduced as must the Nuclear Overpower - High Setpoint - 3 reactor coolant pumps.

OCONEE UNITS 1, 2, & 3 B 3.4.4-2 Rev. 002

RCS Loops-MODES 1 and 2 B 3.4.4 BASES (continued)

APPLICABILITY In MODES 1 and 2, the reactor is critical and has the potential to produce maximum THERMAL POWER. To ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.

The decay heat production rate is much lower than the full power heat rate.

As such, the forced circulation flow and heat sink requirements are reduced for lower, noncritical MODES as indicated by the LCOs for MODES 3, 4, and 5.

Operation in other MODES is covered by:

LCO 3.4.5, "RCS Loops - MODE 3";

LCO 3.4.6, "RCS Loops - MODE 4";

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled";

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled";

LCO 3.9.4, "Decay Heat Removal (DHR) and Coolant Circulation - High Water Level" (MODE 6); and LCO 3.9.5, "Decay Heat Removal (DHR) and Coolant Circulation - Low Water Level" (MODE 6).

ACTIONS A.1 If the requirements of LCO 3.4.4.b.2 are not met, the Required Action is to reset the Nuclear Overpower - High Setpoint to satisfy the requirements of LCO 3.4.4.b.2. This minimizes the possibility of violating DNB limits.

The Completion Time of 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months is reasonable, based on operating experience, to reset the RPS setpoints in an orderly manner and without challenging safety systems.

B.1 If the Required Action and associated Completion Time of Condition A is not met or the requirements of the LCO are not met, the Required Action is to reduce power and bring the unit to MODE 3. This lowers power level and thus reduces the core heat removal needs and minimizes the possibility of violating DNB limits.

The Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging safety systems.

OCONEE UNITS 1, 2, & 3 B 3.4.4-3 Rev. 002

RCS Loops-MODES 1 and 2 B 3.4.4 BASES (continued)

SURVEILLANCE SR 3.4.4.1 REQUIREMENTS This SR requires verification of the required number of loops in operation.

Verification includes flow rate, temperature, or pump status monitoring, which help ensure that forced flow is providing heat removal while maintaining the margin to DNB. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. UFSAR, Chapter 15.

2. 10 CFR 50.36.

OCONEE UNITS 1, 2, & 3 B 3.4.4-4 Rev. 002

AC Sources - Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources - Operating BASES BACKGROUND The AC Power System consists of the offsite power sources (preferred power) and the onsite standby power sources, Keowee Hydro Units (KHU). This system is designed to supply the required Engineered Safeguards (ES) loads of one unit and safe shutdown loads of the other two units and is so arranged that no single failure can disable enough loads to jeopardize plant safety. The design of the AC Power System provides independence and redundancy to ensure an available source of power to the ES systems (Ref. 1). The KHU turbine generators are powered through a common penstock by water taken from Lake Keowee.

The use of a common penstock is justified on the basis of past hydro plant experience of the licensee (since 1919) which indicates that the cumulative need to dewater the penstock can be expected to be limited to about one day a year, principally for inspection, plus perhaps four days every tenth year.

The preferred power source is provided from offsite power to the red or yellow bus in the 230 kV switchyard to the units startup transformer and the E breakers. The 230 kV switchyard is electrically connected to the 525 kV switchyard via the autobank transformer. Emergency power is provided using two emergency power paths, an overhead path and an underground path. The underground emergency power path is from one KHU through the underground feeder circuit, transformer CT-4, the CT-4 incoming breakers (SK breakers), standby bus and the standby breakers (S breakers). The standby buses may also receive offsite power from the 100 kV transmission system through transformer CT-5 and the CT-5 incoming breakers (SL breakers). The overhead emergency power path is from the other KHU through the startup transformer and the startup incoming breakers (E breakers). In addition to supplying emergency power for Oconee, the KHUs provide peaking power to the generation system. During periods of commercial power generation, the KHUs are operated within the acceptable region of the KHU operating restrictions.

This ensures that the KHUs are able to perform their emergency power functions from an initial condition of commercial power generation. The KHU operating restrictions for commercial power generation are contained in UFSAR Chapter 16, (Ref. 2). The standby buses can also OCONEE UNITS 1, 2, & 3 B 3.8.1-1 Rev. 005

AC Sources - Operating B 3.8.1 BASES BACKGROUND receive power from a combustion turbine generator at the Lee Steam (continued) Station through a dedicated 100 kV transmission line, transformer CT-5, and both SL breakers. The 100 kV transmission line can be supplied from a Lee combustion turbine (LCT) and electrically separated from the system grid and offsite loads. The minimum capacity available from any of the multiple sources of AC power is 22.4MVA (limited by CT-4 and CT-5 transformer capacities).

APPLICABLE The initial conditions of design basis transient and accident analyses SAFETY ANALYSIS in the UFSAR Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5) assume ES systems are OPERABLE. The AC power system is designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ES systems so that the fuel, reactor coolant system, and containment design limits are not exceeded.

Consistent with the accident analysis assumptions of a loss of offsite power (LOOP) and a single failure of one onsite emergency power path, two onsite emergency power sources are required to be OPERABLE.

AC Sources - Operating are part of the primary success path and function to mitigate an accident or transient that presents a challenge to the integrity of a fission product barrier. As such, AC Sources -

Operating satisfies the requirements of Criterion 3 of 10 CFR 50.36 (Ref. 3).

LCO Two sources on separate towers connected to the 230 kV switchyard to a unit startup transformer and one main feeder bus are required to be OPERABLE. Two KHUs with one capable of automatically providing power through the underground emergency power path to both main feeder buses and the other capable of automatically providing power through the overhead emergency power path to both main feeder buses are required to be OPERABLE. The Keowee Reservoir level is required to be 775 feet above sea level to support OPERABILITY of the KHUs.

The zone overlap protection circuitry is required to be OPERABLE when the overhead electrical disconnects for the KHU associated with the underground power path are closed to provide single failure protection for the KHUs. The zone overlap protection circuitry includes the step-up transformer lockout, the underground KHU lockout, the Keowee emergency start signal, the underground breaker for the overhead KHU and the following additional features for the overhead KHU to ensure the zone overlap protection circuitry logic is OPERABLE:

Keowee auxiliary transformer CX and its alternate load center feeder breaker (ACB 7 or ACB 8);

One Oconee Unit 1 S breaker capable of feeding switchgear 1TC; OCONEE UNITS 1, 2, & 3 B 3.8.1-2 Rev. 005

AC Sources - Operating B 3.8.1 BASES LCO (continued)

Switchgear 1TC capable of feeding Keowee auxiliary transformer CX; and

Keowee Load Center (1X or 2X) Transfer Switch in Automatic.

The additional features are required to ensure an alternate auxiliary power source for the KHU assigned to the overhead power path for a postulated single failure mitigated by the Zone Overlap Protection Circuitry.

Operable offsite sources are required to be "physically independent" (separate towers) prior to entering the 230 kV switchyard. Once the 230 kV lines enter the switchyard, an electrical pathway must exist through OPERABLE power circuit breakers (PCBs) and disconnects such that both sources are available to energize the Unit's startup transformer either automatically or with operator action. Once within the boundary of the switchyard, the electrical pathway may be the same for both independent offsite sources. In addition, at least one E breaker must be available to automatically supply power to a main feeder bus from the energized startup transformer. The voltage provided to the startup transformer by the two independent offsite sources must be sufficient to ensure ES equipment will operate. Two of the following offsite sources are required:

1) Jocassee (from Jocassee) Black or White,

2) Dacus (from North Greenville) Black or White,

3) Oconee (from Central) Black or White,

4) Calhoun (from Central) Black or White,

5) Autobank transformer fed from either the Asbury (from Newport), Norcross (from Georgia Power), or Katoma (from Jocassee) 525 kV line.

An OPERABLE KHU and its required emergency power path are required to be able to provide sufficient power within specified limits of voltage and frequency within 23 seconds after an emergency start initiate signal and includes its required emergency power path, required instrumentation, controls, auxiliary and DC power, cooling and seal water, lubrication and other auxiliary equipment necessary to perform its safety function. Two emergency power paths are available. One emergency power path consists of an underground circuit while the other emergency power pathway uses an overhead circuit through the 230 kV switchyard.

OCONEE UNITS 1, 2, & 3 B 3.8.1-3 Rev. 005

AC Sources - Operating B 3.8.1 BASES LCO An OPERABLE KHU and its required overhead emergency power path (continued) must be capable of automatically supplying power from the KHU through the KHU main step-up transformer, the 230 kV yellow bus, the Unit startup transformer and both E breakers to both main feeder buses. At least one channel of switchyard isolation (by actuation from degraded grid voltage protection) is required to be OPERABLE to isolate the 230 kV switchyard yellow bus. If closed, each N breaker must be capable of opening using either of its associated breaker trip circuits. KPF-9 (for KHU1) and KPF-10 (for KHU2) must remain open since there is no engineering analysis that ensures that the associated KHU can power both PSW and Engineered Safeguards (ES) system loads should an event occur (with the breaker closed). Either of the following combinations provides an acceptable KHU and required overhead emergency power path:

Keowee Hydro Unit Keowee Hydro Unit 1A) Keowee Unit 1 generator, 1B) Keowee Unit 2 generator, 2A) Keowee ACB 1 (enabled by 2B) Keowee ACB 2 (enabled by one channel of Switchyard one channel of Switchyard Isolate Complete), Isolate Complete),

3A) Keowee auxiliary transformer 3B) Keowee auxiliary transformer 1X, Keowee ACB 5, Keowee 2X, Keowee ACB 6, Keowee Load Center 1X, Load Center 2X, 4A) Keowee MCC 1XA, 4B) Keowee MCC 2XA, 5A) Keowee Battery #1, Charger 5B) Keowee Battery #2, Charger #2

1 or Standby Charger, and or Standby Charger, and Distribution Center 1DA, Distribution Center 2DA, 6A) ACB-1 to ACB-3 interlock, 6B) ACB-2 to ACB-4 interlock, 7A) Keowee Unit 1 Voltage and 7B) Keowee Unit 2 Voltage and Frequency out of tolerance Frequency out of tolerance (OOT) logic (OOT) logic

8) Keowee reservoir level 775 feet above sea level, 8A) KPF-9 is OPEN with closing 8B) KPF-10 is OPEN with closing spring discharged, spring discharged, Overhead Emergency Power Path

9) Keowee main step-up transformer,

10) PCB 9 (enabled by one channel of Switchyard Isolate Complete),

11) The 230kV switchyard yellow bus capable of being isolated by one channel of Switchyard Isolate,

12) A unit startup transformer and associated yellow bus PCB (CT-1 / PCB 18, CT-2 / PCB 27, CT-3 /

PCB 30),

13) Both E breakers.

OCONEE UNITS 1, 2, & 3 B 3.8.1-4 Rev. 005

AC Sources - Operating B 3.8.1 BASES LCO An OPERABLE KHU and its required underground emergency (continued) power path must be capable of automatically supplying power from the KHU through the underground feeder, transformer CT-4, both standby buses, and both Unit S breakers to both main feeder buses. If closed, each N breaker and each SL breaker must be capable of opening using either of its associated breaker trip circuits. KPF-9 (for KHU1) and KPF-10 (for KHU2) must remain open since there is no engineering analysis that ensures that the associated KHU can power both PSW and Engineered Safeguards (ES) system loads should an event occur (with the breaker closed). Either of the following combinations provides an acceptable KHU and required underground emergency power path:

Keowee Hydro Unit Keowee Hydro Unit 1A) Keowee Unit 1 generator, 1B) Keowee Unit 2 generator, 2A) Keowee ACB 3, 2B) Keowee ACB 4, 3A.1) Keowee auxiliary 3B.1) Keowee auxiliary transformer CX, Keowee transformer CX, Keowee ACB 7, Keowee Load ACB 8, Keowee Load Center 1X, Center 2X, 3A.2) One Oconee Unit 1 S 3B.2) One Oconee Unit 1 S breaker capable of breaker capable of feeding switchgear 1TC, feeding switchgear 1TC, 3A.3) Switchgear 1TC capable 3B.3) Switchgear 1TC capable of feeding Keowee of feeding Keowee auxiliary transformer CX, auxiliary transformer CX, 4A) Keowee MCC 1XA, 4B) Keowee MCC 2XA, 5A) Keowee Battery #1, 5B) Keowee Battery #2, Charger #1 or Standby Charger #2 or Standby Charger, and Distribution Charger, and Distribution Center 1DA, Center 2DA, 6A) ACB-1 to ACB-3 interlock, 6B) ACB-2 to ACB-4 interlock, 7A) Keowee Unit 1 Voltage 7B) Keowee Unit 2 Voltage and Frequency OOT logic and Frequency OOT logic

8) Keowee reservoir level 775 feet above sea level, 8A) KPF-9 is OPEN with closing 8B) KPF-10 is OPEN with closing spring discharged, spring discharged, Underground Emergency Power Path

9) The underground feeder,

10) Transformer CT-4,

11) Both SK breakers,

12) Both standby buses,

13) Both S breakers, and

14) ACB-3 to ACB-4 interlock.

OCONEE UNITS 1, 2, & 3 B 3.8.1-5 Rev. 005

AC Sources - Operating B 3.8.1 BASES LCO This LCO is modified by three Notes. Note 1 indicates that a unit startup (continued) transformer may be shared with a unit in MODES 5 and 6. Note 2 indicates that the requirements of Specification 5.5.18, "KHU Commercial Power Generation Testing Program," shall be met for commercial KHU power generation. Note 3 indicates that the requirements of Specification 5.5.19, "Lee Combustion Turbine Testing Program," shall be met when a Lee Combustion Turbine (LCT) is used to comply with Required Actions.

APPLICABILITY The AC power sources are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of accidents and transients, and

b. Adequate core cooling is provided, and containment OPERABILITY and other vital functions are maintained in the event of a postulated accident.

AC source requirements during MODE 5 and 6 are covered in LCO 3.8.2, AC Sources-Shutdown.

ACTIONS The ACTIONS are modified by a Note. The Note excludes the MODE change restriction of LCO 3.0.4 when both standby buses are energized from an LCT via an isolated power path to comply with Required Actions.

This exception allow entry into an applicable MODE while relying on the ACTIONS even though the ACTIONS may eventually require a unit shutdown. This exception is acceptable due to the additional capabilities afforded when both standby buses are energized from an LCT via an isolated power path.

A.1, A.2, A.3.1, and A.3.2 In the event a startup transformer becomes inoperable, it effectively causes the emergency overhead power path and both of the offsite sources to be inoperable. A KHU and its required underground power path remain available to ensure safe shutdown of the unit in the event of a transient or accident without a single failure.

OCONEE UNITS 1, 2, & 3 B 3.8.1-6 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS A.1, A.2, A.3.1, and A.3.2 (continued)

Operation may continue provided the KHU and its required underground emergency power path are tested using SR 3.8.1.3 within one hour if not performed in the previous 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . This Required Action provides assurance that no undetected failures have occurred in the KHU and its required underground emergency power path. Since Required Action A.1 only specifies "perform," a failure of SR 3.8.1.3 acceptance criteria does not result in a Required Action not met. However, if the KHU and its required underground emergency path fails SR 3.8.1.3, both emergency power paths and both required offsite circuits are inoperable, and Condition I for both KHUs and their required emergency power paths inoperable for reasons other than Condition G and H is entered concurrent with Condition A.

If available, another Unit's startup transformer should be aligned to supply power to the affected Unit's auxiliaries so that offsite power sources and the KHU and its required overhead emergency power path will also be available if needed. Although this alignment restores the availability of the offsite sources and the KHU and its required overhead emergency power path, the shared startup transformer's capacity and voltage adequacy could be challenged under certain DBA conditions. The shared alignment is acceptable because the preferred mode of Unit shutdown is with reactor coolant pumps providing forced circulation and due to the low likelihood of an event challenging the capacity of the shared transformer during a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months period to bring a Unit to MODE 5. Required Action A.3.1 requires that the unit startup transformer be restored to OPERABLE status and normal startup bus alignment in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months or Required Action 3.2 requires designating one unit sharing the startup transformer, to be shutdown. For example, if Unit 1 and 2 are operating and CT-2 becomes inoperable, Unit 2 may align CT-1 to be available to the Unit 2 main feeder buses and continue operating for up to 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . At that time, if CT-2 has not been restored to OPERABLE status, one Unit must be "designated" to be shutdown. The designated Unit must be shut down per ACTION B. Note that with one Unit in MODES 1, 2, 3 or 4 and another Unit in a condition other than MODES 1, 2, 3, or 4, the units may share a startup transformer indefinitely provided that the loads on the unit not in MODES 1, 2, 3 or 4 are maintained within acceptable limits. For example, if Unit 1 is in MODE 5 and CT-2 becomes inoperable, Unit 2 may align CT-1 to the Unit 2 main feeder buses and continue operation indefinitely.

OCONEE UNITS 1, 2, & 3 B 3.8.1-7 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS B.1 and B.2 (continued)

When a unit is designated to be shutdown due to sharing a unit startup transformer per Required Action A.3.2, the unit must be brought to a MODE in which the LCO does not apply, since the shared unit startup transformer's capacity could be challenged under certain DBA conditions.

To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

C.1, C.2.1, C.2.2.1, C.2.2.2, C.2.2.3, C.2.2.4, and C.2.2.5 With the KHU or its required overhead emergency power path inoperable due to reasons other than an inoperable startup transformer (Condition A), sufficient AC power sources remain available to ensure safe shutdown of the unit in the event of a transient or accident. Operation may continue if the OPERABILITY of the remaining KHU and its required underground emergency power path is determined by performing SR 3.8.1.3 within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months if not performed in the previous 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and once every 7 days thereafter. This demonstration assures the remaining emergency power path is not inoperable due to a common cause or other failure. Testing on a 7 day Frequency is acceptable since both standby buses must be energized from an LCT via an isolated power path when in Condition C for > 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . When the standby buses are energized by an LCT via an isolated power path, the likelihood that the OPERABLE KHU and its required underground emergency power path will be required is decreased. Since Required Action C.1 only specifies "perform," a failure of SR 3.8.1.3 acceptance criteria does not result in a Required Action not met. SR 3.8.1.3 is only required to be performed when the KHU associated with the underground emergency power path is OPERABLE.

If the KHU and its required underground emergency path fails SR 3.8.1.3, both KHUs and their required emergency power paths are inoperable, and Condition I (Both KHUs or their required emergency power paths inoperable for reasons other than Condition G or H) is entered concurrent with Condition C.

OCONEE UNITS 1, 2, & 3 B 3.8.1-8 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS C.1, C.2.1, C.2.2.1, C.2.2.2, C.2.2.3, C.2.2.4, and C.2.2.5 (continued)

If the inoperable KHU or its required overhead emergency power path are not restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months as required by Required Action C.2.1, a controlled shutdown must be initiated as required by the Required Actions for Condition M unless the extended Completion Times of Required Action C.2.2.5 are applicable. The second Completion Time for Required Action C.2.1 establishes a limit on the maximum time allowed for a KHU to be inoperable during any single contiguous occurrence of having a KHU inoperable. If Condition C is entered as a result of switching an inoperable KHU from the underground to the overhead emergency power path, it may have been inoperable for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months since the initial failure of the KHU. The second Completion Time allows for an exception to the normal "time zero" for beginning the allowed time "clock." This will result in establishing the "time zero" at the time the KHU become inoperable, instead of at the time Condition C was entered.

The extended Completion Times of Required Action C.2.2.5 apply when the KHU or its required overhead emergency power path is inoperable due to an inoperable Keowee main step-up transformer, an inoperable KHU (if not used for that KHU in the previous 3 years), or a KHU made inoperable to perform generator stator replacement work. In order to use the extended Completion Times, within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of entering Condition C both standby buses must be energized from an LCT (Required Action C.2.2.1), KHU generation to the grid except for testing must be suspended (Required Action C.2.2.2), the remaining KHU and its required underground emergency power path and both required offsite sources must be verified OPERABLE, the LCOs indicated in Required Action C.2.2.3 must be verified to be met, and alternate power source capability must be verified by performing SR 3.8.1.16.

Required Action C.2.2.5 permits maintenance and repair of a Keowee main step-up transformer which requires longer than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Transformer replacement is rare but is time extensive. A 28 day Completion Time is permitted by Required Action C.2.2.5 to restore the KHU and its overhead power path to OPERABLE status when inoperable due to an inoperable Keowee main step-up transformer. This allows a reasonable period of time for transformer replacement.

Required Action C.2.2.5 also permits maintenance and repair of a KHU which requires longer than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The primary long term maintenance items are expected to be hydro turbine runner and discharge ring welding OCONEE UNITS 1, 2, & 3 B 3.8.1-9 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS C.1, C.2.1, C.2.2.1, C.2.2.2, C.2.2.3, C.2.2.4, and C.2.2.5 (continued) repairs which are estimated to be necessary every six to eight years.

Also, generator thrust and guide bearing replacements are necessary.

Other items which manifest as failures are expected to be rare and may be performed during the permitted maintenance periods. The 45-day Completion Time of Required Action C.2.2.5 is allowed to be applied cumulatively over a rolling three year period for each KHU. This Completion Time is 45 days from discovery of initial inoperability of the KHU. This effectively limits the time the KHU can be inoperable to 45 days from discovery of initial inoperability rather than 45 days from entry into Condition C and precludes any additional time that may be gained as a result of switching an inoperable KHU from the underground to the overhead emergency power path. The Completion Time is modified by three notes. Note 1 indicates that the Completion Time is cumulative per a rolling 3-year time period for each KHU. For example, if KHU-1 is inoperable for 15 days, the 45-day Completion Time for KHU-1 is reduced to 30 days for the rolling 3-year time period containing the 15 day inoperability. This requires a review of entries for the previous 3 years to determine the remaining time allowed in the 45-day Completion Time. If the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time of C.2.1 is not exceeded, the 45-day Completion is not applicable and is not reduced. Notes 2 and 3 indicate the Completion Time is not applicable during generator stator replacement work or until one year after the KHU is declared OPERABLE following generator stator replacement work. Note 2 is added to avoid using up the 45-day Completion Time concurrent with the 55-day Completion Time and preserves some time to perform emergent maintenance work should the need arise. Note 3 is added to require a one year waiting period prior to use for planned work.

The temporary 55-day Completion Time of Required Action C.2.2.5 is allowed for each KHU to perform generator stator replacement work. The 55-day Completion Time is modified by three notes that provide conditions for using the extended outage. Note 1 indicates that no discretionary maintenance or testing is allowed on the Standby Shutdown Facility (SSF), Protected Service Water (PSW), Emergency Feedwater (EFW), and essential alternating current (AC) Power Systems. Note 2 indicates that the 55-day Completion Time is only applicable one time for each KHU due to generator stator replacement work and expires on September 30, 2021. Note 3 indicates that it is only applicable if the SSF, PSW and EFW are administratively verified OPERABLE prior to entering the extended Completion Time. This increases the probability, even in the unlikely event of an additional failure, that the risk significant systems will function as required to support their safety function.

Required Actions C.2.2.1, C.2.2.2, C.2.2.3, and C.2.2.4 must be met in order to allow the longer restoration times of Required Action C.2.2.5.

OCONEE UNITS 1, 2, & 3 B 3.8.1-10 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS C.1, C.2.1, C.2.2.1, C.2.2.2, C.2.2.3, C.2.2.4, and C.2.2.5 (continued)

Required Action C.2.2.1 requires that both standby buses be energized using an LCT through the 100 kV transmission circuit. With this arrangement (100 kV transmission circuit electrically separated from the system grid and all offsite loads), a high degree of reliability for the emergency power system is provided. In this configuration, the LCT is serving as a second emergency power source, however, since the 100 kV transmission circuit is vulnerable to severe weather a time limit is imposed. The second Completion Time of Required Action C.2.2.1 permits the standby buses to be re-energized by an LCT within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in the event this source is subsequently lost. Required Action C.2.2.2 requires suspension of KHU generation to the grid except for testing. The restriction reduces the number of possible failures which could cause loss of the underground emergency power path. Required Action C.2.2.3 requires verifying by administrative means that the remaining KHU and its required underground emergency power path and both required offsite sources are OPERABLE. This provides additional assurance that offsite power will be available. In addition, this assures that the KHU and its required underground emergency power path are available.

Required Action C.2.2.3 also requires verifying by administrative means that the requirements of the following LCOs are met:

LCO 3.8.3, "DC Sources - Operating;"

LCO 3.8.6, "Vital Inverters - Operating;"

LCO 3.8.8, "Distribution Systems - Operating;"

LCO 3.3.17, "EPSL Automatic Transfer Function;"

LCO 3.3.18, "EPSL Voltage Sensing Circuits;"

LCO 3.3.19, "EPSL 230 kV Switchyard DGVP;" and LCO 3.3.21, "EPSL Keowee Emergency Start Function."

This increases the probability, even in the unlikely event of an additional failure, that the DC power system and the 120 VAC Vital Instrumentation power panelboards will function as required to support EPSL, power will not be lost to ES equipment, and EPSL will function as required.

OCONEE UNITS 1, 2, & 3 B 3.8.1-11 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS C.1, C.2.1, C.2.2.1, C.2.2.2, C.2.2.3, C.2.2.4, and C.2.2.5 (continued)

Verifying by administrative means allows a check of logs or other information to determine the OPERABILITY status of required equipment in place of requiring unique performance of Surveillance Requirements. If the AC Source is subsequently determined inoperable, or an LCO stated in Required Action C.2.2.3 is subsequently determined not met, continued operation up to a maximum of four hours is allowed by ACTION L.

Required Action C.2.2.3 is modified by a note indicating that it is not applicable to the remaining KHU and its required underground emergency power path or LCO 3.3.21 when in Condition H to perform generator stator replacement work. This note is needed to allow entry into the 60 hour6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months dual unit outage to reassemble the refurbished KHU and return it to functional condition, as well as perform balance runs and shots, post modification testing, and a commissioning run prior to declaring the refurbished KHU operable. Without this note, entry into Condition L would be required allowing only 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months to restore the KHU and its required underground path and only 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to restore compliance with LCO 3.3.21.

Required Action C.2.2.4 requires verifying alternate power source capability by performing SR 3.8.1.16. This confirms that entry into Condition C is due only to an inoperable main step-up transformer or an inoperable KHU, as applicable. If SR 3.8.1.16 is subsequently determined not met, continued operation up to a maximum of four hours is allowed by ACTION L.

D.1, D.2 and D.3 With the KHU or its required underground emergency power path inoperable, sufficient AC power sources remain available to ensure safe shutdown of the unit in the event of a transient or accident. Operation may continue for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if the remaining KHU and its required overhead emergency power path are tested using SR 3.8.1.4 within one hour if not performed in the previous 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . SR 3.8.1.4 is only required to be performed when the KHU associated with the overhead emergency power path is OPERABLE. This Required Action provides assurance that no undetected failures have occurred in the overhead emergency power path. Since Required Action D.1 only specifies "perform," a failure of SR 3.8.1.4 acceptance criteria does not result in a Required Action not met. However, if the KHU and its required overhead emergency path fails SR 3.8.1.4, both KHUs and their required emergency power paths are inoperable, and Condition I for both KHUs and their emergency power paths inoperable for reasons other than Condition G or H is entered concurrent with Condition D. This OCONEE UNITS 1, 2, & 3 B 3.8.1-12 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS D.1, D.2 and D.3 (continued) demonstration is to assure that the remaining emergency power path is not inoperable due to a common cause or due to an undetected failure.

For outages of the KHU and its required underground emergency power path in excess of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , an LCT (using the 100 kV transmission circuit electrically separated from the grid and offsite loads) must energize a standby bus prior to the outage exceeding 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This ensures the availability of a power source on the standby buses when the KHU and its required underground emergency power path are out of service in excess of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The second Completion Time of Required Action D.2 permits the standby buses to be re-energized by an LCT within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in the event this source is subsequently lost.

The second Completion Time for Required Action D.3 establishes a limit on the maximum time allowed for a KHU to be inoperable during any single contiguous occurrence of having a KHU inoperable. If Condition D is entered as a result of switching an inoperable KHU from the overhead to the underground emergency power path, it may have been inoperable for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months since the initial failure of the KHU. The second Completion Time allows for an exception to the normal "time zero" for beginning the allowed time "clock." This will result in establishing the "time zero" at the time the KHU become inoperable, instead of at the time Condition D was entered.

E.1 and E.2 If the Required Action and associated Completion Time for Required Action D.2 are not met, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for one Oconee unit and 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for other Oconee unit(s) and to MODE 5 within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems.

F.1 and F.2 With the zone overlap protection circuitry inoperable when the overhead electrical disconnects for the KHU associated with the underground power path are closed, the zone overlap protection circuitry must be restored to OPERABLE status or the overhead electrical disconnects must be opened within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In this Condition, both KHUs and their required emergency power paths are OPERABLE, however a single failure could result in the loss of both KHUs.

OCONEE UNITS 1, 2, & 3 B 3.8.1-13 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS G.1 (continued)

With both emergency power paths inoperable due to an E breaker and S breaker inoperable on the same main feeder bus, one breaker must be restored to OPERABLE status. In this Condition, both emergency power paths can still provide power to the remaining main feeder bus.

H.1 and H.2 With both KHUs or their required emergency power paths inoperable for planned maintenance or test with both standby buses energized from an LCT via an isolated power path, the KHU must be restored to OPERABLE status within 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months . Operation with both KHUs and their required power paths inoperable is permitted for 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months provided that both standby buses are energized using an LCT through the 100 kV transmission circuit and the requirements of the Note to the Condition are met. The Note to the Condition indicates that it may only be entered when both offsite sources are verified by administrative means to be OPERABLE and the requirements of the following LCOs are verified by administrative means to be met:

LCO 3.8.3, "DC Sources - Operating;"

LCO 3.8.6, "Vital Inverters - Operating;"

LCO 3.8.8, "Distribution Systems - Operating;"

LCO 3.3.17, "EPSL Automatic Transfer Function;"

LCO 3.3.18, "EPSL Voltage Sensing Circuits;" and LCO 3.3.19, "EPSL 230 kV Switchyard DGVP."

This increases the probability, even in the unlikely event of an additional failure, that the DC power system and the 120 VAC Vital Instrumentation power panelboards will function as required to support EPSL, power will not be lost to ES equipment, and EPSL will function as required.

OCONEE UNITS 1, 2, & 3 B 3.8.1-14 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS H.1 and H.2 (continued)

Verifying by administrative means allows a check of logs or other information to determine the OPERABILITY status of required equipment in place of requiring unique performance of Surveillance Requirements. If the AC Source is subsequently determined inoperable, or an LCO stated in the Note to Condition H is subsequently determined not met, continued operation up to a maximum of four hours is allowed by ACTION L.

With both standby buses energized from an LCT via an isolated power path (100 kV transmission circuit electrically separated from the system grid and all offsite loads), a high degree of reliability for the emergency power system is provided. In this configuration, the LCT is serving as the Oconee emergency power source, however, since the Oconee Units are vulnerable to a single failure of the 100 kV transmission circuit a time limit of 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months is imposed. Required Action H.1 permits the standby buses to be re-energized by an LCT within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in the event this source is subsequently lost. The second Completion Time of Required Action H.2 limits the amount of time two KHUs can be inoperable during the 45-day Completion Time of Required Action C.2.2.5 to a cumulative 240 hours0.00278 days 0.0667 hours 3.968254e-4 weeks 9.132e-5 months over a rolling 3-year period. This requires a review of entries for the previous 3 years to determine the remaining time allowed in the 240-hour Completion Time. This limits the dual KHU outage time when using the 45-day Completion Time of Required Action C.2.2.5 on a cumulative basis over a 3-year time period.

If both emergency power paths are restored, unrestricted operation may continue. If only one power path is restored, operation may continue per ACTIONS C or D.

I.1, I.2, and I.3 With both KHUs or their required emergency power paths inoperable for reasons other than Conditions G and H, insufficient standby AC power sources are available to supply the minimum required ES functions. In this Condition, the offsite power system is the only source of AC power available for this level of degradation. The risk associated with continued operation for one hour without an emergency power source is considered acceptable due to the low likelihood of a LOOP during this time period, and because of the potential for grid instability caused by the simultaneous shutdown of all three units. This instability would increase the probability of a total loss of AC power. Operation with both KHUs or their required power paths inoperable is permitted for 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months provided that Required Actions I.1 and I.2 are met. Required Action I.1 requires that both standby buses be energized using an LCT via an isolated power OCONEE UNITS 1, 2, & 3 B 3.8.1-15 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS I.1, I.2, and I.3 (continued) path. With this arrangement (100 kV transmission circuit electrically separated from the system grid and all offsite loads), a high degree of reliability for the emergency power system is provided. In this configuration, the LCT is serving as the Oconee emergency power source, however, since the Oconee Units are vulnerable to a single failure of the 100 kV transmission circuit a time limit of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is imposed. The second Completion Time of Required Action I.1 permits the standby buses to be re-energized by an LCT within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in the event this source is subsequently lost. Required Action I.2 requires that the OPERABILITY status of both offsite sources be determined by administrative means and that the OPERABILITY status of equipment required by the following LCOs be determined by administrative means:

LCO 3.8.3, "DC Sources - Operating;"

LCO 3.8.6, "Vital Inverters - Operating;"

LCO 3.8.8, "Distribution Systems - Operating;"

LCO 3.3.17, "EPSL Automatic Transfer Function;"

LCO 3.3.18, "EPSL Voltage Sensing Circuits;" and LCO 3.3.19, "EPSL 230 kV Switchyard DGVP."

This increases the probability, even in the unlikely event of an additional failure, that the DC power system and the 120 VAC Vital Instrumentation power panelboards will function as required to support EPSL, power will not be lost to ES equipment, and EPSL will function as required.

Determining by administrative means allows a check of logs or other information to determine the OPERABILITY status of required equipment in place of requiring unique performance of Surveillance Requirements. If the AC Source is initially or subsequently determined inoperable, or an LCO stated in Required Action I.2 is initially or subsequently determined not met, continued operation up to a maximum of four hours is allowed by ACTION L.

If both emergency power paths are restored, unrestricted operation may continue. If only one power path is restored, operation may continue per ACTIONS C or D.

OCONEE UNITS 1, 2, & 3 B 3.8.1-16 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS J.1, J.2, and J.3 (continued)

With one or both required offsite sources inoperable for reasons other than Condition A, sufficient AC power sources are available to supply necessary loads in the event of a DBA. However, since the AC power system is degraded below the Technical Specification requirements, a time limit on continued operation is imposed. With only one of the required offsite sources OPERABLE, the likelihood of a LOOP is increased such that the Required Actions for all required offsite circuits inoperable are conservatively followed. The risk associated with continued operation for one hour without a required offsite AC source is considered acceptable due to the low likelihood of a LOOP during this time period, and because of the potential for grid instability caused by the simultaneous shutdown of all three units.

Operation with one or both required offsite sources inoperable is permitted for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months provided that Required Actions J.1 and J.2 are met. Required Action J.1 requires that both standby buses be energized using an LCT via an isolated power path. With this arrangement (100 kV transmission circuit electrically separated from the system grid and all offsite loads), a high degree of reliability for the emergency power system is provided. In this configuration, the LCT is serving as an emergency power source, however, since the Oconee units are vulnerable to a single failure of the 100 kV transmission circuit a time limit is imposed. The second Completion Time of Required Action J.1 permits the standby buses to be re-energized by an LCT within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in the event this source is subsequently lost. Required Action J.2 requires that the OPERABILITY status of both KHUs and their required emergency power paths be determined by administrative means and that the OPERABILITY status of equipment required by the following LCOs be determined by administrative means:

LCO 3.8.3, "DC Sources - Operating;"

LCO 3.8.6, "Vital Inverters - Operating;"

LCO 3.8.8, "Distribution Systems - Operating;"

LCO 3.3.17, "EPSL Automatic Transfer Function;"

LCO 3.3.18, "EPSL Voltage Sensing Circuits;"

LCO 3.3.19, "EPSL 230 kV Switchyard DGVP," and LCO 3.3.21, "EPSL Keowee Emergency Start Function."

OCONEE UNITS 1, 2, & 3 B 3.8.1-17 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS J.1, J.2, and J.3 (continued)

This increases the probability, even in the unlikely event of an additional failure, that the DC power system and the 120 VAC Vital Instrumentation power panelboards will function as required to support EPSL, power will not be lost to ES equipment, and EPSL will function as required.

Determining by administrative means allows a check of logs or other information to determine the OPERABILITY status of required equipment in place of requiring unique performance of Surveillance Requirements. If the AC Source is initially or subsequently determined inoperable, or an LCO stated in Required Action J.2 is initially or subsequently determined not met, continued operation up to a maximum of four hours is allowed by ACTION L.

K.1 The two trip circuits for each closed N and SL breakers are required to ensure both breakers will open. An N breaker trip circuit encompasses those portions of the breaker control circuits necessary to trip the associated N breaker from the output of the 2 out of 3 logic matrix formed by the auxiliary transformer's undervoltage sensing circuits up to and including an individual trip coil for the associated N breaker. The undervoltage sensing channels for the auxiliary transformer are addressed in LCO 3.3.18, "Emergency Power Switching Logic (EPSL)

Voltage Sensing Circuits." An SL breaker trip circuit encompasses those portions of the breaker control circuits necessary to trip the SL breaker from the output of both 2 out of 3 logic matrices formed by each standby bus's undervoltage sensing circuits up to and including an individual trip coil for the associated SL breaker. The undervoltage sensing channels for the CT- 5 transformer are addressed in LCO 3.3.18, "Emergency Power Switching Logic (EPSL) Voltage Sensing Circuits." With one trip circuit inoperable a single failure could cause an N or SL breaker to not open. This could prevent the transfer to other available sources.

Therefore, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed to repair the trip circuit or open the breaker (opening the breaker results in exiting the Condition). The Completion Time is based on engineering judgement taking into consideration the time required to complete the required action and the availability of the remaining trip circuit.

A Note modifies the Condition, indicating that separate Condition Entry is permitted for each breaker. Thus, Completion Times are tracked separately for the N1, N2, SL1, and SL2 breaker.

OCONEE UNITS 1, 2, & 3 B 3.8.1-18 Rev. 005

AC Sources - Operating B 3.8.1 BASES ACTIONS L.1, L.2, and L.3 (continued)

With an AC Source inoperable or LCO not met, as stated in Note for Condition H entry; or with an AC Source inoperable or LCO not met, as stated in Required Action C.2.2.3 when in Condition C for > 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ; or with an AC Source inoperable or LCO not met, as stated in Required Action I.2 or J.2 when in Conditions I or J for > 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ; or with SR 3.8.1.16 not met, Required Action L.1, L.2 and L.3 requires restoration within four hours. Condition L is modified by a Note indicating that separate Condition entry is permitted for each inoperable AC Source, and LCO or SR not met. The Required Action is modified by a Note that allows the remaining OPERABLE KHU and its required emergency power path to be made inoperable if required to restore both KHUs and their required emergency power paths to OPERABLE status. This note is necessary since certain actions such as dewatering the penstock may be necessary to restore the inoperable KHU although these actions would also cause both KHUs to be inoperable.

The purpose of this Required Action is to restrict the allowed outage time for an inoperable AC Source or equipment required by an LCO when in Conditions C, H, I or J. For Conditions I and J when the LCOs stated are initially not met, the maximum Completion Time is four hours or the remaining Completion Time allowed by the stated LCO, whichever is shorter.

M.1 and M.2 If a Required Action and associated Completion Time for Condition C, F, G, H, I, J, K or L are not met; or if a Required Action and associated Completion Time are not met for Required Action D.1 or D.3, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 5 within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.8.1.1 REQUIREMENTS This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are OCONEE UNITS 1, 2, & 3 B 3.8.1-19 Rev. 005

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.1 (continued)

REQUIREMENTS connected to their power source, and that appropriate separation of offsite sources is maintained. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.2 This SR verifies adequate battery voltage when the KHU batteries are on float charge. This SR is performed to verify KHU battery OPERABILITY.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.3 This SR verifies the availability of the KHU associated with the underground emergency power path to start automatically and energize the underground power path. Utilization of either the auto-start or emergency start sequence assures the control function OPERABILITY by verifying proper speed control and voltage. Power path verification is included to demonstrate breaker OPERABILITY from the KHU onto the standby buses. This is accomplished by closing the Keowee Feeder Breakers (SK) to energize each deenergized standby bus. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.4 This surveillance verifies the availability of the KHU associated with the overhead emergency power path. Utilization of either the auto-start or emergency start sequence assures the control function OPERABILITY by verifying proper speed control and voltage. The ability to supply the overhead emergency power path is satisfied by demonstrating the ability to synchronize (automatically or manually) the KHU with the grid system.

If an automatic start of the KHU is performed and a manual synchronization is desired, the KHU will need to be shutdown and re-started in manual to allow a manual synchronization of the KHU. The SR also requires that the underground power path be energized after removing the KHU from the overhead emergency power path. This surveillance can be satisfied by first demonstrating the ability of the KHU OCONEE UNITS 1, 2, & 3 B 3.8.1-20 Rev. 005

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.4 (continued)

REQUIREMENTS associated with the underground emergency path to energize the underground path then synchronizing the KHU to the overhead emergency power path. The SR is modified by a Note indicating that the requirement to energize the underground emergency power path is not applicable when the overhead disconnects are open for the KHU associated with the underground emergency power path or 2) when complying with Required Action D.1. The latter exception is necessary since Required Action D.1 continues to be applicable when both KHUs are inoperable.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.5 This surveillance verifies OPERABILITY of the trip functions of each closed SL and each closed N breaker. Neither of these breakers have any automatic close functions; therefore, only the trip coils require verification. Cycling of each breaker demonstrates functional OPERABILITY and the coil monitor circuits verify the integrity of each trip coil. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR modified by a Note that states it is not required to be performed for an SL breaker when its standby bus is energized from a LCT via an isolated power path. This is necessary since the standby buses are required to be energized from a LCT by several Required Actions of Specification 3.8.1 and the breakers must remain closed to energize the standby buses from a LCT.

SR 3.8.1.6 Infrequently used source breakers are cycled to ensure OPERABILITY.

The Standby breakers are to be cycled one breaker at a time to prevent inadvertent interconnection of two units through the standby bus breakers. Cycling the startup breakers verifies OPERABILITY of the breakers and associated interlock circuitry between the normal and startup breakers. This circuitry provides an automatic, smooth, and safe transfer of auxiliaries in both directions between sources. The Surveillance Frequency is based on operating experience, equipment OCONEE UNITS 1, 2, & 3 B 3.8.1-21 Rev. 005

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.6 (continued)

REQUIREMENTS reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note which states the SR is not required to be performed for an S breaker when its standby bus is energized from a LCT via an isolated power path. This is necessary since the standby buses are required to be energized from a LCT by several Required Actions of Specification 3.8.1 and cycling the S breakers connects the standby buses with the main feeder buses which are energized from another source.

SR 3.8.1.7 The KHU tie breakers to the underground path, ACB3 and ACB4, are interlocked to prevent cross-connection of the KHU generators. The safety analysis utilizes two independent power paths for accommodating single failures in applicable accidents. Connection of both generators to the underground path compromises the redundancy of the emergency power paths. Installed test logic is used to verify a circuit to the close coil on one underground ACB does not exist with the other underground ACB closed. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.8 Each KHU tie breaker to the underground emergency power path and tie breaker to the overhead emergency path, are interlocked to prevent the unit associated with the underground circuit from automatically connecting to the overhead emergency power path. The safety analysis utilizes two independent power paths for accommodating single failures in applicable accidents. Connection of both generators to the overhead emergency power path compromises the redundancy of the emergency power paths. Temporary test instrumentation is used to verify a circuit to the close coil on the overhead ACB does not exist with the Underground ACB closed. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

OCONEE UNITS 1, 2, & 3 B 3.8.1-22 Rev. 005

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 REQUIREMENTS (continued) This surveillance verifies the KHUs' response time to an Emergency Start signal (normally performed using a pushbutton in the control room) to ensure ES equipment will have adequate power for accident mitigation.

UFSAR Section 6.3.3.3 (Ref. 6) establishes the 23 second time requirement for each KHU to achieve rated frequency and voltage based on the assumption that an engineered safeguards actuation in one unit occurs simultaneously with a loss of offsite power to all three units.

Emergency start without a design basis event or minimal load such as unit shutdown could conceivably cause the KHU to experience overshoot or over-frequency.

This surveillance also verifies the KHUs steady-state frequency is 59.4 Hz and 61.8 Hz. These limits were established to ensure key mechanical systems and equipment have adequate frequency for accident mitigation. The limits are automatically maintained by Keowee control systems. A nominal time of 60 seconds following the Emergency Start signal is sufficient time to begin monitoring steady state operation.

Since the only available loads of adequate magnitude for simulating an accident is the grid, subsequent loading on the grid is required to verify the KHU's ability to assume rapid loading under accident conditions.

Sequential block loads are not available to fully test this feature. This is the reason for the requirement to load the KHUs at the maximum practical rate. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.10 A battery service test is a special test of the battery capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length should correspond to the design duty cycle requirements as specified in Reference 4.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

OCONEE UNITS 1, 2, & 3 B 3.8.1-23 Rev. 005

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 REQUIREMENTS (continued) Visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.12 Verification of cell to cell connection cleanliness, tightness, and proper coating with anti-corrosion grease provides an indication of any abnormal condition, and assures continued OPERABILITY of the battery. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.13 The KHU underground ACBs have a control feature which will automatically close the KHU, that is pre-selected to the overhead path, into the underground path upon an electrical fault in the zone overlap region of the protective relaying. This circuitry prevents an electrical fault in the zone overlap region of the protective relaying from locking out both emergency power paths during dual KHU grid generation. In order to ensure this circuitry is OPERABLE, an electrical fault is simulated in the zone overlap region and the associated underground ACBs are verified to operate correctly. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note indicating the SR is only applicable when the overhead disconnects to the underground KHU are closed. When the overhead disconnects to the underground KHU are open, the circuitry preventing the zone overlap protective lockout of both KHUs is not needed.

SR 3.8.1.14 This surveillance verifies OPERABILITY of the trip functions of the SL and N breakers. This SR verifies each trip circuit of each breaker OCONEE UNITS 1, 2, & 3 B 3.8.1-24 Rev. 005

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)

REQUIREMENTS (continued) independently opens each breaker. Neither of these breakers have any automatic close functions; therefore, only the trip circuits require verification. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note indicating that the SR is not required for an SL breaker when its standby bus is energized by a LCT via an isolated power path. This is necessary since the standby buses are required to be energized from a LCT by several Required Actions of Specification 3.8.1 and the breakers must remain closed to energize the standby buses from a LCT.

SR 3.8.1.15 This surveillance verifies proper operation of the 230 kV switchyard circuit breakers upon an actual or simulated actuation of the Switchyard Isolation circuitry. This test causes an actual switchyard isolation (byactuation of degraded grid voltage protection) and alignment of KHUs to the overhead and underground emergency power paths. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. The effect of this SR is not significant because the generator red bus tie breakers and feeders from the Oconee 230 kV switchyard red bus to the system grid remain closed. Either Switchyard Isolation Channel causes full system realignment, which involves a complete switchyard realignment. To avoid excessive switchyard circuit breaker cycling, realignment and KHU emergency start functions, this SR need be performed only once each SR interval.

SR 3.8.1.16 This SR verifies by administrative means that one KHU provides an alternate manual AC power source capability by manual or automatic KHU start with manual synchronize, or breaker closure, to energize its non-required emergency power path. That is, when the KHU to the overhead emergency power path is inoperable, the SR verifies by administrative means that the overhead emergency power path is OPERABLE. When the overhead emergency power path is inoperable, the SR verifies by administrative means that the KHU associated with the overhead emergency power path is OPERABLE.

OCONEE UNITS 1, 2, & 3 B 3.8.1-25 Rev. 005

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 (continued)

REQUIREMENTS This SR is modified by a Note indicating that the SR is only applicable when complying with Required Action C.2.2.4.

SR 3.8.1.17 This SR verifies the Keowee Voltage and Frequency out of tolerance logic trips and blocks closure of the appropriate overhead or underground power path breakers on an out of tolerance trip signal. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

There are three over voltage relays, three under voltage relays, and three over/under frequency relays per KHU with each relay actuating an auxiliary relay used to provide two out of three logic. These relays monitor generator output voltage and if two phases are above/below setpoint, prevent the power path breakers from closing or if closed, provide a trip signal which is applied after a time delay, to open the power path breakers. Testing demonstrates that relays actuate at preset values, that timers time out and that two under voltage relays, two over voltage relays, or two over/under frequency relays will actuate the logic channel.

This ensures that the power path breakers will not close and if closed, will trip after a preset time delay that becomes effective when the KHU first reaches the required frequency and voltage band.

SR 3.8.1.18 This SR verifies the ability of each KHU auxiliary power system to automatically transfer from its normal auxiliary power source to its alternate auxiliary power source. The surveillance frequency is based on operating experience, equipment reliability and plant risk and is controlled under the Surveillance Frequency Control Program.

Testing demonstrates the ability of each KHU 600 Volt Auxiliary Load Center 1X or 2X to close its alternate feeder breaker after the time delay from its normal feeder breaker opening whether as the underground or overhead power path unit.

OCONEE UNITS 1, 2, & 3 B 3.8.1-26 Rev. 005

AC Sources - Operating B 3.8.1 BASES REFERENCES 1. UFSAR, Section 3.1.39

2. UFSAR, Chapter 16

3. 10 CFR 50.36

4. UFSAR, Chapter 6

5. UFSAR, Chapter 15

6. UFSAR, Section 6.3.3.3 OCONEE UNITS 1, 2, & 3 B 3.8.1-27 Rev. 005

SSF 3.10.1 B 3.10 STANDBY SHUTDOWN FACILITY B 3.10.1 Standby Shutdown Facility (SSF)

BASES BACKGROUND The Standby Shutdown Facility (SSF) is designed as a standby system for use under certain emergency conditions. The system provides additional "defense in-depth" protection for the health and safety of the public by serving as a backup to existing safety systems. The SSF is provided as an alternate means to achieve and maintain the unit in MODE 3 with average RCS temperature 525oF (unless the initiating event causes the unit to be driven to a lower temperature) following a fire, turbine building flood, and station blackout (SBO) events. The SSF is designed in accordance with criteria associated with these events. The SSF Auxiliary Service Water (ASW) System is credited as a backup to Emergency Feedwater (EFW) due to the lack of tornado missile protection for the EFW System. In addition, the SSF may be activated as necessary in response to events associated with plant security. In that the SSF is a backup to existing safety systems, the single failure criterion is not required. Failures in the SSF systems will not cause failures or inadvertent operations in other plant systems. The SSF requires manual activation and can be activated if emergency systems are not available.

The SSF is designed to maintain the reactor in a safe shutdown condition for a period of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months following a fire or turbine building flood, and for a period of four hours following an SBO. The capability of the SSF to maintain the reactor in a safe shutdown condition is also credited for certain security-related events. For events initiating from nominal plant operating conditions, this is accomplished by re-establishing and maintaining Reactor Coolant Pump Seal cooling; assuring natural circulation and core cooling by maintaining the primary coolant system filled to a sufficient level in the pressurizer while maintaining sufficient secondary side cooling water; and maintaining the reactor subcritical by isolating all sources of Reactor Coolant System (RCS) addition except for the Reactor Coolant Makeup System which supplies makeup of a sufficient boron concentration. For events initiating from off-nominal operating conditions (i.e., low decay heat or high decay heat with low initial RCS temperature), natural circulation may not be achievable and the pressurizer may go off-scale low or the pressurizer may go water-solid without lifting the pressurizer safety valves.

The main components of the SSF are the SSF Auxiliary Service Water (ASW) System, SSF Portable Pumping System, SSF Reactor Coolant (RC) Makeup System, SSF Power System, and SSF Instrumentation.

The SSF ASW System is a high head, high volume system designed to provide sufficient steam generator (SG) inventory for adequate decay OCONEE UNITS 1, 2, & 3 B 3.10.1-1 Rev. 003

SSF B 3.10.1 BASES BACKGROUND heat removal for three units during a loss of normal AC power in (continued) conjunction with the loss of the normal and emergency feedwater systems. One motor driven SSF ASW pump, located in the SSF, serves all three units. The SSF ASW pump, two HVAC service water pumps, and the Diesel Service Water (DSW) pump share a common suction supply of lake water from the embedded Unit 2 condenser circulating water (CCW) piping. The SSF DSW pump and an HVAC pump must be operable in order to satisfy the operability requirements for the Power System. (Only one HVAC service water pump is required to be operable to satisfy the LCO.)

The SSF ASW System is used to provide adequate cooling to maintain single phase RCS natural circulation flow in MODE 3 with an average RCS temperature 525oF (unless the initiating event causes the unit to be driven to a lower temperature). In order to maintain single phase RCS natural circulation flow, an adequate number of Bank 2, Group B and C pressurizer heaters must be OPERABLE. These heaters are needed to compensate for ambient heat loss from the pressurizer. As long as the temperature in the pressurizer is maintained, RCS pressure will also be maintained. This will preclude hot leg voiding and ensure adequate natural circulation cooling.

The SSF Portable Pumping System, which includes a submersible pump and a flow path capable of taking suction from the intake canal and discharging into the Unit 2 CCW line, is designed to provide a backup supply of water to the SSF in the event of loss of CCW and subsequent loss of CCW siphon flow. The SSF Portable Pumping System is installed manually according to procedures.

The SSF RC Makeup System is designed to supply makeup to the RCS in the event that normal makeup systems are unavailable. An SSF RC Makeup Pump located in the Reactor Building of each unit supplies makeup to the RCS should the normal makeup system flow and seal cooling become unavailable. The system is designed to ensure that sufficient borated water is provided from the spent fuel pools to allow the SSF to maintain all three units in MODE 3 with average RCS temperature 525oF (unless the initiating event causes the unit to be driven to a lower temperature) for approximately 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . An SSF RC Makeup Pump is capable of delivering borated water from the Spent Fuel Pool to the RC pump seal injection lines. A portion of this seal injection flow is used to makeup for reactor coolant pump seal leakage while the remainder flows into the RCS to makeup for other RCS leakage (non LOCA).

The SSF Power System provides electrical isolation of SSF equipment from non-SSF equipment. The SSF Power System includes 4160 VAC, 600 VAC, 208 VAC, 120 VAC and 125 VDC power. It consists of OCONEE UNITS 1, 2, & 3 B 3.10.1-2 Rev. 003

SSF B 3.10.1 BASES BACKGROUND switchgear, a load center, motor control centers, panelboards, remote (continued) starters, batteries, battery chargers, inverters, a diesel generator (DG),

relays, control devices, and interconnecting cable supplying the appropriate loads.

The AC power system consists of 416O V switchgear OTS1; 600 V load center OXSF; 600 V motor control centers XSF, 1XSF, 2XSF, 3XSF, PXSF; 208 V motor control centers 1XSF, 1XSF-1, 2XSF, 2XSF-1, 3XSF, 3XSF-1; 120 V panelboards KSF, KSFC.

The SSF 125 VDC Power System provides a reliable source of power for DC loads needed to black start the diesel. The DC power system consists of two 125 VDC batteries and associated chargers, two 125 VDC distribution centers (DCSF, DCSF-1), and a DC power panelboard (DCSF). Only one battery and associated charger is required to be operable and connected to the 125 VDC distribution center to supply the 125 VDC loads. In this alignment, which is normal, the battery is floated on the distribution center and is available to assure power without interruption upon loss of its associated battery charger or AC power source. The other 125 VDC battery and its associated charger are in a standby mode and are not normally connected to the 125 VDC distribution center. However, they are available via manual connection to the 125 VDC distribution center to supply SSF loads, if required.

The SSF Power System is provided with standby power from a dedicated DG. The SSF DG and support systems consists of the diesel generator, fuel oil transfer system, air start system, diesel engine service water system, as well as associated controls and instrumentation. This SSF DG is rated for continuous operation at 3500 kW, 0.8 pf, and 4160 VAC.

The SSF electrical design load does not exceed the continuous rating of the DG. The auxiliaries required to assure proper operation of the SSF DG are supplied entirely from the SSF Power System. The SSF DG is provided with manual start capability from the SSF only. It uses a compressed air starting system with four air storage tanks. An independent fuel system, complete with a separate underground storage tank, duplex filter arrangement, a fuel oil transfer pump, and a day tank, is supplied for the DG.

OCONEE UNITS 1, 2, & 3 B 3.10.1-3 Rev. 003

SSF B 3.10.1 BASES BACKGROUND The following information will aid in determination of SSF Operability:

(continued)

Associated Inoperable Systems SSF SSF SSF SSF SSF ASW Portable RCMU Power Instruments System Pumping System System System SSF ASW System YES YES YES YES YES SSF System Removed From Service SSF Portable YES YES YES YES YES Pumping SSF RCMU System NO NO YES NO NO SSF Power System YES YES YES YES YES SSF Instr.

System NO NO NO NO YES SSF PZR.

Heaters** YES NO NO NO NO SSF RCS Isolation NO NO YES NO NO Valves MS Branch Isolation YES NO NO NO NO Valves***

Steam Isolations for YES NO NO NO NO Startup SSF HVAC System YES YES YES YES YES

- When SSF pressurizer heaters are inoperable, the resulting inoperability of the SSF ASW System does NOT render other SSF systems inoperable.

- - Only applicable on unit(s) with the SSF letdown line modification complete.

SSF ASW System Provides motive force for SSF ASW suction pipe air ejector. The air ejector is needed to maintain siphon flow to the SSF HVAC service water pump, the SSF DSW pump, and the SSF ASW pump when the water level in the U2 CCW supply pipe becomes too low. If the SSF DSW pump becomes inoperable, the SSF Power System will become inoperable. Since an inoperable SSF Power System causes all other SSF subsystems to be inoperable, an inoperable SSF ASW System will OCONEE UNITS 1, 2, & 3 B 3.10.1-4 Rev. 003

SSF B 3.10.1 BASES BACKGROUND also cause other SSF Subsystems to be inoperable.

(continued)

Provides adequate SG cooling to reduce & maintain RCS pressure below the pressure where the SSF RC makeup pump discharge relief valve, HP-404, begins to leak flow. Therefore, full SSF RC Makeup System seal injection flow will be provided to the RC pump seals in time to prevent seal degradation or failure.

SSF ASW pump should be operated when the diesel is operated to provide a load for the diesel. This is not a requirement for operability since the diesel could be operated to provide long term power to one or more units RC makeup pumps without operating the SSF ASW pump as long as a large load (SSF ASW pump) is not added later (diesel desouping concern).

SSF Portable Pumping Supplies makeup water to the SSF ASW System, the SSF DSW System, and the SSF HVAC Service Water System after siphon flow / gravity flow and forced CCW flow are lost.

SSF Power System Other SSF Systems cannot operate without receiving power from the diesel for SSF scenarios where power from U2 MFB is not available.

SSF Pressurizer Heaters Single phase RCS natural circulation flow cannot be maintained without the pressurizer heaters. The number of SSF heaters utilized is based on testing and calculations performed on a unit by unit basis to determine the minimum number of required heaters needed to overcome actual pressurizer ambient losses. Since the heaters do not have their own Action statement, the SSF ASW System is declared inoperable when the heaters are inoperable.

SSF RCS Isolation Valves (HP-3, HP-4, HP-20, RC-4, RC-5, RC-6)

These valves do not have their own Action statement. When they are inoperable, their corresponding SSF RC makeup system is considered inoperable.

OCONEE UNITS 1, 2, & 3 B 3.10.1-5 Rev. 003

SSF B 3.10.1 BASES BACKGROUND Main Steam (MS) Branch Isolation Valves (MS-17, 24, 26, 33, 35, 36, 76, (continued) 79, 82, 84, FDW-103, 104)***

These valves do not have their own Action statement. When they are inoperable, their corresponding SSF ASW system is considered inoperable.

- - Only applicable on unit(s) with the SSF letdown line modification complete.

Steam Isolations for Startup To ensure SSF operability during conditions of low decay heat, the following SSCs shall have the MS supply isolated prior to reaching Mode 3 and they shall remain isolated for at least four days of continuous operation at > 2542 MW reactor power or for a duration determined by a cycle-specific decay heat analysis:

i. Auxiliary Steam System, ii. Condenser Steam Air Ejectors, iii. Turbine Driven Emergency Feedwater Pump, iv. Emergency Steam Air Ejector.

If these SSCs are not isolated for the stated conditions above, their corresponding SSF ASW system is considered inoperable.

SSF HVAC System Portions of the SSF HVAC System, consisting of the SSF Air Conditioning (AC) and Ventilation Systems support the SSF Power System OPERABILITY. The SSF AC System, which includes the HVAC service water system and AC equipment (fan motors, compressors, condensers, and coils), must be operable to support SSF Power System operability. Since an inoperable SSF Power System results in all other SSF subsystems being inoperable, an SSF HVAC System operability problem that makes the SSF Power System inoperable also results in other SSF Subsystems being inoperable.

The SSF AC System is designed to maintain the SSF Control Room, Computer Room, and Battery Rooms within their design temperature range. Elevated temperatures in the SSF Control Room and Computer Room could cause the SSF Power System to fail during an accident which requires operation of the SSF. The SSF AC System consists of two refrigeration circuits and an air handling unit. The requirements for the refrigeration circuits vary with outdoor air temperature. Depending on OCONEE UNITS 1, 2, & 3 B 3.10.1-6 Rev. 003

SSF B 3.10.1 BASES BACKGROUND outdoor air temperature and Air Conditioning System performance, the (continued) two refrigeration circuits may not be required to support SSF power system OPERABILITY. The air handling unit is required to circulate air regardless of the number of refrigeration circuits required. Since the SSF HVAC service water pumps perform a redundant function, only one of the two are required to be operable for the SSF HVAC service water system to be considered operable. The SSF Ventilation System, which supplies outside air to the Switchgear, Pump, HVAC and Diesel Generator Rooms, is composed of the following four subsystems: Constant Ventilation, Summer Ventilation, On-line Ventilation, and Diesel Generator Engine Ventilation. These ventilation systems work together to provide cooling to the various rooms of the SSF under both standby and on-line modes. The Diesel Generator Engine Ventilation fan is required for operability of the SSF Power System. The six fans associated with the other three ventilation systems may or may not be required for SSF operability dependent upon outside air temperature. If the SSF AC System refrigeration circuits or one of the ventilation fans fail, an engineering evaluation must be performed to determine if any of the SSF Systems or instrumentation are inoperable.

SSF Instrumentation System SSF Instrumentation is provided to monitor RCS pressure, RCS Loop A and B temperature (hot leg and cold leg), pressurizer water level, and SG A and B water level. Indication is displayed on the SSF control panel.

APPLICABLE The SSF serves as a backup for existing safety systems to SAFETY ANALYSES provide an alternate and independent means to achieve and maintain one, two, or three Oconee units in MODE 3 with average RCS temperature 525oF (unless the initiating event causes the unit to be driven to a lower temperature) for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months following a fire or a turbine building flood. The SSF is also credited for station blackout (SBO) coping, which has a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months coping duration (Refs. 1, 4, 5, 6, and 7.)

The OPERABILITY of the SSF is consistent with the assumptions of the Oconee Probabilistic Risk Assessment (Ref. 2). Therefore, the SSF satisfies Criterion 4 of 10 CFR 50.36 (Ref. 3).

OCONEE UNITS 1, 2, & 3 B 3.10.1-7 Rev. 003

SSF B 3.10.1 BASES (continued)

LCO The SSF Instrumentation in Table B 3.10.1-1 and the following SSF Systems shall be OPERABLE:

a. SSF Auxiliary Service Water System;

b. SSF Portable Pumping System;

c. SSF Reactor Coolant Makeup System; and

d. SSF Power System.

An OPERABLE SSF ASW System includes pressurizer heaters capable of being powered from the SSF, and an SSF ASW pump, piping, instruments, and controls to ensure a flow path capable of taking suction from the Unit 2 condenser circulating water (CCW) line and discharging into the secondary side of each SG. The minimum number of pressurizer heaters capable of being powered from the SSF is based on maintaining RCS natural circulation flow which is achieved by maintaining a steam bubble in the pressurizer at a high enough temperature to provide subcooling margin in the RCS. The pressurizer steam bubble is maintained by offsetting pressurizer heat loss due to ambient heat loss from the pressurizer and pressurizer steam space leakage. The following table provides the minimum number of SSF controlled pressurizer heaters versus steam space leakage rates that may be used in combination to meet Operability requirements for the SSF. Engineering Input is needed to determine if other combinations of pressurizer heaters versus steam space leakage rate are acceptable.

Currently, SSF turbine building flood mitigation thermal margin issues require an additional four (4) pressurizer heaters above the number needed to offset ambient heat loss. The additional 4 heaters are included in the required number of Pressurizer Heaters Available for each unit presented in the tables below.

Unit 1 Number of Bank 2, Group B & C Maximum Allowed Pressurizer Pressurizer Heaters Available Steam Space Leakage 15 0.00 GPM Unit 2 Number of Bank 2, Group B & C Maximum Allowed Pressurizer Pressurizer Heaters Available Steam Space Leakage 17 0.00 GPM OCONEE UNITS 1, 2, & 3 B 3.10.1-8 Rev. 003

SSF B 3.10.1 BASES LCO Unit 3 (continued) Number of Bank 2, Group B & C Maximum Allowed Pressurizer Pressurizer Heaters Available Steam Space Leakage 14 0.00 GPM An OPERABLE SSF Portable Pumping System includes an SSF submersible pump and a flow path capable of taking suction from the intake canal and discharging into the Unit 2 CCW line. An OPERABLE Reactor Coolant Makeup System includes an SSF RC Makeup pump, piping, instruments, and controls to ensure a flow path capable of taking suction from the spent fuel pool and discharging into the RCS. The following leakage limits are applicable for the SSF RC Makeup System to be considered OPERABLE:

Maximum Allowed Total Combined RCS Leakage for SSF RC Makeup System Operability The maximum allowed total combined RCS leakage is 15.0 GPM for Units 1, 2, and 3. A Units total combined RCS leakage shall be less than or equal to this value for its corresponding SSF RC Makeup System to be considered OPERABLE.

Total Combined RCS leakage is based on Total RCS Leakage Rate +

Quench Tank Level Increase + Total RC Pump Seal Return Flow. Total RC Pump Seal Return Flow is determined by summing the seal return flow rate for all four RC Pumps. If the seal return flow rate for a RC Pump is not available, the seal return flow may be determined using the method described below. The seal return flow rate limits defined below have been previously determined to meet operability requirements for the SSF.

The following discussion regarding failed RCP seal stages does not permit or prohibit operation with a failed seal stage. It is included only to indicate the basis for SSF RCMU System operability. Engineering input is needed to determine operability requirements when multiple seal return flow instruments have failed.

Unit 1 If the seal return flow rate for a RC Pump is not available and at least two of three seals are intact on one RCP, 3.1 GPM may be used as the seal OCONEE UNITS 1, 2, & 3 B 3.10.1-9 Rev. 003

SSF B 3.10.1 BASES LCO return flow rate for the affected pump. This worst case seal leakage (continued) occurs when one seal stage is failed and RCS pressure is at 2500 psig.

Engineering input is needed to determine operability requirements when two seals of an RCP have failed.

Unit 2 and Unit 3 If the seal return flow rate for a RC Pump not available, 2.9 GPM may be used as the seal return flow rate for the affected pump. This worst case leakage occurs when two seal stages are failed and RCS pressure at 2500 psig.

An OPERABLE SSF Power System includes the SSF DG, diesel support systems, 4160 VAC, 600 VAC, 208 VAC, 120 VAC, and 125 VDC systems. Only one 125 VDC SSF battery and its associated charger are required to be OPERABLE to support OPERABILITY of the 125 VDC system.

APPLICABILITY The SSF System is required in MODES 1, 2, and 3 to provide an alternate means to achieve and maintain the unit in MODE 3 with average RCS temperature 525oF (unless the initiating event causes the unit to be driven to a lower temperature) following a fire, turbine building flood, or SBO. The SSF ASW System is credited as a backup to EFW due to the lack of tornado missile protection for the EFW System. The safety function of the SSF is to achieve and maintain the unit in MODE 3 with average RCS temperature 525oF (unless the initiating event causes the unit to be driven to a lower temperature); therefore, this LCO is not applicable in MODES 4, 5, or 6.

ACTIONS The exception for LCO 3.0.4, provided in the Note of the Actions, permits entry into MODES 1, 2, and 3 with the SSF not OPERABLE. This is acceptable because the SSF is not required to support normal operation of the facility or to mitigate a design basis accident.

A.1, B.1, C.1, D.1, and E.1 With one or more of the SSF Systems inoperable or the required SSF instrumentation of Table B 3.10.1-1 inoperable, the SSF is in a degraded condition and the system(s) or instrumentation must be restored to OPERABLE status within 7 days. The 7 day Completion Time is based on the low probability of an event occurring which would require the SSF to be utilized.

OCONEE UNITS 1, 2, & 3 B 3.10.1-10 Rev. 003

SSF B 3.10.1 BASES ACTIONS F.1 (continued)

If the Required Action and associated Completion Time of Condition A, B, C, D, or E are not met when SSF Systems or Instrumentation are inoperable due to maintenance, the unit may continue to operate provided that the SSF is restored to OPERABLE status within 45 days from discovery of initial inoperability.

This Completion Time is modified by a Note that indicates that the SSF shall not be in Condition F for more than a total of 45 days in a calendar year. This includes the 7 day Completion Time that leads to entry into Condition F. For example, if the SSF ASW System is inoperable for 10 days, the 45 day special inoperability period is reduced to 35 days. If the SSF ASW System is inoperable for 6 days, Condition A applies and there is no reduction in the 45 day allowance. The limit of 45 days per calendar year minimizes the number and duration of extended outages associated with exceeding the 7 day Completion Time of a Condition.

G.1 and G.2 If the Required Action and associated Completion Time of Condition F are not met or if the Required Action and associated Completion Time of Condition A, B, C, D, or E are not met for reasons other than Condition F, the unit must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 4 within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . The allowed Completion Times are appropriate, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems, considering a three unit shutdown may be required.

OCONEE UNITS 1, 2, & 3 B 3.10.1-11 Rev. 003

SSF B 3.10.1 BASES (continued)

SURVEILLANCE SR 3.10.1.1 REQUIREMENTS Performance of the CHANNEL CHECK for each required instrumentation channel ensures that a gross failure of instrumentation has not occurred.

A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel with 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 the two 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; therefore, it is key in verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION. This SR is modified by a Note to indicate that it is not applicable to the SSF RCS temperature instrument channels, which are common to the RPS RCS temperature instrument channels and are normally aligned through a transfer isolation device to each Unit control room. The instrument string to the SSF control room is checked and calibrated periodically per the Surveillance Frequency Control Program.

Agreement criteria are determined 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. If the channels are within the criteria, it is an indication that the channels are OPERABLE. If the channels are normally off scale during times when surveillance is required, the CHANNEL CHECK will only verify that they are off scale in the same direction. Off scale low current loop channels are verified to be reading at the bottom of the range and not failed downscale.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

OCONEE UNITS 1, 2, & 3 B 3.10.1-12 Rev. 003

SSF B 3.10.1 BASES SURVEILLANCE SR 3.10.1.2 REQUIREMENTS (continued) Verifying battery terminal voltage while on float charge for the batteries helps to ensure the effectiveness of the charging system and the ability of the batteries to perform their intended function. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery (or battery cell) and maintain the battery (or a battery cell) in a fully charged state. The voltage requirements are based on the nominal design voltage of the battery and are consistent with the initial voltages assumed in the battery sizing calculations. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.10.1.3 and 3.10.1.4 SR 3.10.1.3 provides verification that the level of fuel oil in the day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons. The day tank is sized based on the amount of fuel oil required to successfully start the DG and to allow for orderly shutdown of the DG upon loss of fuel oil from the main storage tank.

SR 3.10.1.4 provides verification that there is an adequate inventory of fuel oil in the storage tanks to support SSF DG operation for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months at full load. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months period is sufficient time to place the unit in a safe shutdown condition The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program during this period.

OCONEE UNITS 1, 2, & 3 B 3.10.1-13 Rev. 003

SSF B 3.10.1 BASES SURVEILLANCE SR 3.10.1.5 REQUIREMENTS (continued) The SR requires the DG to start (normal or emergency) from standby conditions and achieve required voltage and frequency. Standby conditions for a DG means that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations. This SR is modified by a Note to indicate that all DG starts for this Surveillance may be preceded by an engine prelube period and followed by a warmup period prior to loading. This minimizes wear on moving parts that do not get lubricated when the engine is running.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.10.1.6 This Surveillance ensures that sufficient air start capacity for the SSF DG is available, without the aid of the refill compressor. The SSF DG air start system is equipped with four air storage tanks. Each set of two tanks will provide sufficient air to start the SSF DG a minimum of three successive times without recharging. The pressure specified in this SR is intended to reflect the lowest value at which the three starts can be accomplished.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.10.1.7 This Surveillance demonstrates that the fuel oil transfer pump automatically starts and transfers fuel oil from the underground fuel oil storage tank to the day tank. This is required to support continuous operation of SSF DG. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

OCONEE UNITS 1, 2, & 3 B 3.10.1-14 Rev. 003

SSF B 3.10.1 BASES SURVEILLANCE SR 3.10.1.8 REQUIREMENTS (continued) A sample of fuel oil is required to be obtained from the SSF day tank and underground fuel oil storage tank in accordance with the Diesel Fuel Oil Testing Program in order to ensure that fuel oil viscosity, water, and sediment are within the limits of the Diesel Fuel Oil Testing Program.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.10.1.9 This Surveillance verifies that the SSF DG is capable of synchronizing with the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize electrical loads, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.

The 0.8 value is the design rating of the machine, while the 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by three Notes. Note 1 indicates that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit will not invalidate the test. Note 3 indicates that all DG starts for this Surveillance may be preceded by an engine prelube period and followed by a warmup period prior to loading.

This minimizes wear on moving parts that do not get lubricated.

OCONEE UNITS 1, 2, & 3 B 3.10.1-15 Rev. 003

SSF B 3.10.1 BASES SURVEILLANCE SR 3.10.1.10 REQUIREMENTS (continued) Visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance.

The presence of physical damage or deterioration does not necessarily represent a failure of this SR, provided an evaluation determines that the physical damage or deterioration does not affect the OPERABILITY of the battery (its ability to perform its design function).

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.10.1.11 Visual inspection of battery cell to cell and terminal connections provides an indication of physical damage that could potentially degrade battery performance. The anti-corrosion material is used to help ensure good electrical connections and to reduce terminal deterioration. The visual inspection for corrosion is not intended to require removal of and inspection under each terminal connection.

The limits established for this SR must be no more than 20% above the resistance as measured during installation or not above the ceiling value established by the manufacturer.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

OCONEE UNITS 1, 2, & 3 B 3.10.1-16 Rev. 003

SSF B 3.10.1 BASES SURVEILLANCE SR 3.10.1.12 REQUIREMENTS (continued) A battery service test is a special test of the battery capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length correspond to the design duty cycle requirements. The design basis discharge time for the SSF battery is one hour.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.10.1.13 CHANNEL CALIBRATION is a complete check of the instrument channel, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drift to ensure that the instrument channel remains operational between successive tests. CHANNEL CALIBRATION shall find that measurement errors and bistable setpoint errors are within the assumptions of the setpoint analysis. CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint analysis.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.10.1.14 Inservice Testing of the SSF valves demonstrates that the valves are mechanically OPERABLE and will operate when required. These valves are required to operate to ensure the required flow path.

The specified Frequency is in accordance with the INSERVICE TESTING PROGRAM requirements. Operating experience has shown that these components usually pass the SR when performed at the INSERVICE TESTING PROGRAM Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

OCONEE UNITS 1, 2, & 3 B 3.10.1-17 Rev. 003

SSF B 3.10.1 BASES SURVEILLANCE SR 3.10.1.15 REQUIREMENTS (continued) This SR requires the SSF pumps to be tested in accordance with the INSERVICE TESTING PROGRAM. The INSERVICE TESTING PROGRAM verifies the required flow rate at a discharge pressure to verify OPERABILITY. The SR is modified by a note indicating that it is not applicable to the SSF submersible pump.

The specified Frequency is in accordance with the INSERVICE TESTING PROGRAM requirements. Operating experience has shown that these components usually pass the SR when performed at the INSERVICE TESTING PROGRAM Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.10.1.16 This SR requires the SSF submersible pump to be tested on a 2 year Frequency and verifies the required flow rate at a discharge pressure to verify OPERABILITY.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. UFSAR, Section 9.6.

2. Oconee Probabilistic Risk Assessment.

3. 10 CFR 50.36.

4. NRC Letter from L. A. Wiens to H. B. Tucker, "Safety Evaluation Report on Effect of Tornado Missiles on Oconee Emergency Feedwater System," dated July 28, 1989.

5. NRC Letter from L. A. Wiens to J. W. Hampton, "Safety Evaluation for Station Blackout (10 CFR 50.63) - Oconee Nuclear Station, Units 1, 2, and 3," dated March 10, 1992.

OCONEE UNITS 1, 2, & 3 B 3.10.1-18 Rev. 003

SSF B 3.10.1 BASES REFERENCES 6. NRC Letter from L. A. Wiens to J. W. Hampton, "Supplemental (continued) Safety Evaluation for Station Blackout (10 CFR 50.63) - Oconee Nuclear Station, Units 1, 2, and 3," dated December 3, 1992.

7. UFSAR Section 8.3.2.2.4.

OCONEE UNITS 1, 2, & 3 B 3.10.1-19 Rev. 003

SSF B 3.10.1 Table B 3.10.1-1 (page 1 of 1)

SSF Instrumentation FUNCTION REQUIRED CHANNELS PER UNIT

1. Reactor Coolant System Pressure 1

2. Reactor Coolant System Temperature (Tc) 1/Loop

3. Reactor Coolant System Temperature (Th) 1/Loop

4. Pressurizer Water Level 1

5. Steam Generator A & B Water Level 1/SG OCONEE UNITS 1, 2, & 3 B 3.10.1-20 Rev. 003

U.S. Nuclear Regulatory Commission to RA-20-0136 Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, and 50-287 Renewed License Nos. DPR-38, DPR-47, and DPR-55 Submittal of Updated Final Safety Analysis Report (UFSAR) Revision 28, Technical Specifications Bases Revisions, Selected Licensee Commitments Revisions, 10 CFR 50.59 Evaluation Summary Report, and 10 CFR 54.37 Update Attachment 6 Selected Licensee Commitments (SLC) Manual Revisions

Oconee Nuclear Station Selected Licensee Commitments Revised 12/19/2019 List of Effective Pages Page Revision Number Implementation Date 16.0 005 08/16/17 16.1 000 10/15/07 16.2 000 08/25/14 16.3 001 06/29/15 16.4 --- PENDING 16.5.1 000 11/26/12 16.5.2 000 11/15/12 16.5.3 000 02/21/07 16.5.4 --- Deleted 03/28/18 16.5.5 --- Deleted 05/16/09 16.5.6 --- Deleted 02/10/14 16.5.7 000 12/13/06 16.5.8 000 01/31/07 16.5.8a --- Deleted 05/19/05 16.5.9 --- Deleted 06/06/19 16.5.10 000 10/08/03 16.5.11 000 01/31/00 16.5.12 001 10/17/18 16.5.13 000 03/27/99 16.6.1 001 12/05/19 16.6.2 000 01/31/07 16.6.3 000 11/15/12 16.6.4 000 11/15/12 16.6.5 000 12/14/00 16.6.6 000 11/15/12 16.6.7 000 03/27/99 16.6.8 000 03/27/99 16.6.9 000 11/15/12 16.6.10 000 11/15/12 16.6.11 000 11/15/12 16.6.12 000 11/15/12 16.6.13 000 03/31/08 16.6.14 000 04/21/14 16.6.15 000 11/15/12 16.7.1 000 11/15/12 Oconee Nuclear Station LOEP 1 Revision 034

Oconee Nuclear Station Selected Licensee Commitments Revised 12/19/2019 List of Effective Pages Page Revision Number Implementation Date 16.7.2 000 11/15/12 16.7.3 000 11/15/12 16.7.4 000 07/14/05 16.7.5 000 11/15/12 16.7.6 000 04/08/14 16.7.7 000 11/15/12 16.7.8 000 03/27/99 16.7.9 000 10/23/03 16.7.10 000 11/15/12 16.7.11 000 11/15/12 16.7.12 000 06/30/04 16.7.13 000 12/05/12 16.7.14 000 11/15/12 16.7.15 000 04/08/14 16.7.16 000 10/14/15 16.7.17 000 07/14/16 16.8.1 000 08/09/01 16.8.2 000 02/10/05 16.8.3 001 01/26/16 16.8.4 001 12/19/19 16.8.5 000 05/21/15 16.8.6 000 01/04/07 16.8.7 000 01/31/00 16.8.8 000 01/31/00 16.8.9 000 06/21/05 16.9.1 001 08/16/16 16.9.2 002 08/16/16 16.9.3 --- Deleted 01/08/18 16.9.4 003 07/17/18 16.9.5 002 08/16/16 16.9.6 007 12/19/19 16.9.7 001 08/16/16 16.9.8 --- Deleted 09/26/18 16.9.8a 000 02/07/05 16.9.9 002 08/16/17 Oconee Nuclear Station LOEP 2 Revision 034

Oconee Nuclear Station Selected Licensee Commitments Revised 12/19/2019 List of Effective Pages Page Revision Number Implementation Date 16.9.10 000 01/12/04 16.9.11 001 06/29/15 16.9.11a 001 06/06/17 16.9.12 001 09/21/15 16.9.13 001 12/05/19 16.9.14 000 10/28/04 16.9.15 000 03/27/99 16.9.16 000 10/15/14 16.9.17 000 05/23/01 16.9.18 000 07/15/14 16.9.19 000 03/31/05 16.9.20 003 07/17/18 16.9.21 001 08/06/19 16.9.22 --- Deleted 08/16/17 16.9.23 001 08/16/17 16.9.24 003 11/18/16 16.9.25 001 08/16/17 16.10.1 000 11/15/12 16.10.2 000 12/02/03 16.10.3 000 03/27/99 16.10.4 000 11/15/12 16.10.5 --- Deleted 08/24/04 16.10.6 000 03/27/99 16.10.7 001 09/21/15 16.10.8 000 11/27/06 16.10.9 000 11/25/09 16.11.1 000 03/15/11 16.11.2 000 01/31/00 16.11.3 000 11/20/08 16.11.4 000 06/30/14 16.11.5 000 10/30/02 16.11.6 000 11/08/13 16.11.7 000 01/31/00 16.11.8 000 12/21/09 16.11.9 000 03/22/10 Oconee Nuclear Station LOEP 3 Revision 034

Oconee Nuclear Station Selected Licensee Commitments Revised 12/19/2019 List of Effective Pages Page Revision Number Implementation Date 16.11.10 000 05/14/14 16.11.11 001 12/19/19 16.11.12 000 04/10/03 16.11.13 000 03/27/99 16.11.14 000 03/27/99 16.12.1 000 03/27/99 16.12.2 000 05/03/07 16.12.3 000 05/01/03 16.12.4 000 03/27/99 16.12.5 000 03/27/99 16.12.6 000 11/08/07 16.13.1 002 11/28/18 16.13.2 000 12/15/04 16.13.3 000 12/15/04 16.13.4 000 03/27/99 16.13.5 --- Deleted 11/30/99 16.13.6 000 03/27/99 16.13.7 000 12/15/04 16.13.8 000 03/27/99 16.13.9 000 03/27/99 16.13.10 000 03/27/99 16.13.11 000 03/27/99 16.14.1 000 11/15/12 16.14.2 000 07/23/12 16.14.3 000 03/27/99 16.14.4 --- Deleted 03/15/11 16.14.4.a 000 03/15/11 16.15.1 000 04/12/06 16.15.2 000 11/15/12 16.15.3 000 11/15/12 Note: With the introduction of Fusion in June 2015, all controlled documents require a three-digit revision number. Thus, the revision numbers were set to 000 in the summer of 2015. As such, the revision dates for Revision 000 are based on the implementation dates for revisions in effect prior to this change.

Oconee Nuclear Station LOEP 4 Revision 034

TABLE OF CONTENTS SECTION TITLE PAGE NO 16.0 SELECTED LICENSEE COMMITMENTS 16.1-1

16.1 INTRODUCTION

16.1-1 16.2 APPLICABILITY 16.2-1 16.3 DEFINITIONS 16.3-1 16.4 COMMITMENTS RELATED TO REACTOR COMPONENTS Pending 16.5 REACTOR COOLANT SYSTEM 16.5.1-1 16.5.1 Reactor Coolant System Vents 16.5.1-1 16.5.2 Low Temperature Overpressure Protection (LTOP) System 16.5.2.1 16.5.3 Loss of Decay Heat Removal 16.5.3-1 16.5.4 [DELETED] 16.5.4-1 16.5.5 [DELETED] 16.5.5-1 16.5.6 [DELETED] 16.5.6-1 16.5.7 Chemistry Requirements 16.5.7-1 16.5.8 Pressurizer 16.5.8-1 16.5.8a [DELETED] 16.5.8a-1 16.5.9 [DELETED] 16.5.9-1 16.5.10 Loss of Reactor Coolant 16.5.10-1 16.5.11 Subcriticality 16.5.11-1 16.5.12 RCS Leakage Testing Following Opening of System 16.5.12-1 16.5.13 High Pressure Injection and the Chemical Addition Systems 16.5.13-1 16.6 COMMITMENTS RELATED TO ENGINEERED SAFETY FEATURES 16.6.1-1 (NON-ESF SYSTEMS) 16.6.1 Containment Leakage Tests 16.6.1-1 16.6.2 Reactor Building Post-Tensioning System 16.6.2-1 16.6.3 Containment Heat Removal Verification Frequency 16.6.3-1 16.0-1 Rev. 009

TABLE OF CONTENTS (continued)

SECTION TITLE PAGE NO 16.6.4 Low Pressure Injection System Leakage 16.6.4-1 16.6.5 Core Flood Tank Discharge Valve Breakers 16.6.5-1 16.6.6 Core Flooding System Test 16.6.6-1 16.6.7 BWST Outlet Valve Control 16.6.7-1 16.6.8 LPI System Valve Test Restrictions 16.6.8-1 16.6.9 Containment Purge Valve Testing 16.6.9-1 16.6.10 Trisodium Phosphate (TSP) 16.6.10-1 16.6.11 Containment Debris Sources 16.6.11-1 16.6.12 Additional High Pressure Injection (HPI) Requirements 16.6.12-1 16.6.13 Additional Requirements to Support Low Pressure Injection (LPI) 16.6.13-1 Operability 16.6.14 Control of HPI and LPI/RBS Pump Room Temperatures 16.6.14-1 16.6.15 High Pressure Injection (HPI) and Liquid Waste Disposal (LWD) 16.6.15-1 Leakage 16.7 INSTRUMENTATION 16.7.1-1 16.7.1 Accident Monitoring Instrumentation 16.7.1-1 16.7.2 Anticipated Transient Without Scram 16.7.2-1 16.7.3 Emergency Feedwater System 16.7.3-1 16.7.4 Hydrogen Analyzers 16.7.4-1 16.7.5 Steam Generator Overfill Protection 16.7.5-1 16.7.6 Diverse Actuation Systems 16.7.6-1 16.7.7 Position Indicator Channels 16.7.7-1 16.7.8 Incore Instrumentation 16.7.8-1 16.7.9 RCP Monitor 16.7.9-1 16.7.10 Core Flood Tank Instrumentation 16.7.10-1 16.7.11 Display Instrumentation 16.7.11-1 16.0-2 Rev. 009

TABLE OF CONTENTS (continued)

SECTION TITLE PAGE NO 16.7.12 SSF Diesel Generator (DG) Air Start System Pressure 16.7.12-1 Instrumentation 16.7.13 SSF Instrumentation 16.7.13-1 16.7.14 Rod Withdrawal Alarm Limit 16.7.14-1 16.7.15 Engineered Safeguards Protective System (ESPS) Voter Trouble Alarm 16.7.15-1 16.7.16 Spent Fuel Pool - Wide Range Level Instrumentation 16.7.16-1 16.7.17 Reactor Protective System Instrumentation Setpoints 16.7.17-1 16.8 ELECTRIC POWER SYSTEMS 16.8.1-1 16.8.1 Control of Room Temperatures for Station Blackout 16.8.1-1 16.8.2 Additional Requirements to Support Keowee Hydro Unit (KHU) 16.8.2-1 OPERABILITY 16.8.3 Power Battery Parameters 16.8.3-1 16.8.4 Keowee Operational Restrictions 16.8.4-1 16.8.5 [DELETED] 16.8.5-1 16.8.6 Lee/Central Alternate Power System 16.8.6-1 16.8.7 Auctioneering Diodes 16.8.7-1 16.8.8 External Grid Trouble Protection 16.8.8-1 16.8.9 Keowee Governor Speed Out Of Tolerance (OOT) Alarm 16.8.9-1 16.9 AUXILIARY SYSTEMS 16.9.1-1 16.9.1 Fire Suppression Water System 16.9.1-1 16.9.2 Sprinkler and Spray Systems 16.9.2-1 16.9.3 [DELETED] 16.9.3-1 16.9.4 Fire Hose Stations 16.9.4-1 16.9.5 Fire Barriers 16.9.5-1 16.9.6 Fire Detection Instrumentation 16.9.6-1 16.9.7 Keowee Lake Level 16.9.7-1 16.0-3 Rev. 009

TABLE OF CONTENTS (continued)

SECTION TITLE PAGE NO 16.9.8 [DELETED] 16.9.8-1 16.9.8a HPSW System Requirements to Support Loss of LPSW 16.9.8a-1 16.9.9 Additional Protected Service Water (PSW) System Commitments 16.9.9-1 16.9.10 Component Cooling and HPI Seal Injection to Reactor 16.9.10-1 Coolant Pumps 16.9.11 Turbine Building Flood Protection Measures 16.9.11-1 16.9.11a Auxiliary Building Flood Protection Measures 16.9.11a-1 16.9.12 Additional Low Pressure Service Water (LPSW) And 16.9.12-1 Siphon Seal Water (SSW) System Operability Requirements 16.9.13 Spent Fuel Cooling System 16.9.13-1 16.9.14 SSF Diesel Generator (DG) Inspection Requirements 16.9.14-1 16.9.15 Radioactive Material Sources 16.9.15-1 16.9.16 Reactor Building Polar Crane and Auxiliary Hoist 16.9.16-1 (RCS System Open) 16.9.17 Reactor Building Polar Crane (RCS at elevated 16.9.17-1 temperature and pressure) 16.9.18 Snubbers 16.9.18-1 16.9.19 Gravity Induced Reverse Flow to Standby Shutdown Facility (SSF) 16.9.19-1 Through a Unit 2 Condensate Cooler 16.9.20 Diesel Driven Service Air Compressors 16.9.20-1 16.9.21 Standby Shutdown Facility External Flood Protection 16.9.21-1 16.9.22 [DELETED] 16.9.22-1 16.9.23 Alternate Chilled Water (AWC) and Alternate Reactor Building Cooling 16.9.23-1 (RBC) Systems 16.9.24 FLEX - Equipment and Connections 16.9.24-1 16.9.25 Spent Fuel Pool Area Isolation 16.9.25-1 16.0-4 Rev. 009

TABLE OF CONTENTS (continued)

SECTION TITLE PAGE NO 16.10 COMMITMENTS RELATED TO STEAM & POWER CONVERSION 16.10.1-1 SYSTEMS 16.10.1 Local Start of Turbine Driven Emergency Feedwater (EFW) Pump 16.10.1-1 16.10.2 Steam Generator Secondary Side Pressure and 16.10.2-1 Temperature (P/T) Limits 16.10.3 Emergency Feedwater (EFW) Pump and Valve Testing 16.10.3-1 16.10.4 Low Presssure Service Water System Testing 16.10.4-1 16.10.5 [DELETED] 16.10.5-1 16.10.6 Emergency Feedwater Controls 16.10.6-1 16.10.7 Alternate Source of Emergency Feedwater (EFW) 16.10.7-1 16.10.8 Upper Surge Tank (UST) Riser Branch Line Automatic Isolation Valves 16.10.8-1 16.10.9 Air Operated Valves (AOVs) Required to Support Standby Shutdown 16.10.9-1 Facility (SSF) During Station Blackout (SBO) 16.11 RADIOLOGICAL EFFLUENTS CONTROL 16.11.1-1 16.11.1 Radioactive Liquid effluents 16.11.1-1 16.11.2 Radioactive Gaseous Effluents 16.11.2-1 16.11.3 Radioactive Effluent Monitoring Instrumentation 16.11.3-1 16.11.4 Operational Safety Review 16.11.4-1 16.11.5 Solid Radioactive Waste 16.11.5-1 16.11.6 Radiological Environmental Monitoring 16.11.6-1 16.11.7 Dose calculations 16.11.7-1 16.11.8 Reports 16.11.8-1 16.11.9 Radioactive effluent release report 16.11.9-1 16.11.10 Radiological Environmental Operating Reports 16.11.10-1 16.11.11 Iodine Radiation Monitoring Filters 16.11.11-1 16.0-5 Rev. 009

TABLE OF CONTENTS (continued)

SECTION TITLE PAGE NO 16.11.12 Radioactive Material in Outside Temporary 16.11.12-1 Tanks Exceeding Limit 16.11.13 Radioactive Material in Waste Gas Holdup 16.11.13-1 Tank Exceeding Limit 16.11.14 Explosive Gas Mixture 16.11.14-1 16.12 REFUELING OPERATIONS 16.12.1-1 16.12.1 Decay Time for Movement of Irradiated Fuel 16.12.1-1 16.12.2 Area Radiation Monitoring for Fuel Loading and Refueling 16.12.2-1 16.12.3 Communication Between Control Room and Refueling Personnel 16.12.3-1 16.12.4 Handling of Irradiated Fuel Assemblies 16.12.4-1 16.12.5 Loads Suspended over Spent Fuel in Spent Fuel Pool 16.12.5-1 16.12.6 Fuel Damage During Fuel Handling Operations in Containment 16.12.6-1 16.13 CONDUCT OF OPERATION 16.13.1-1 16.13.1 Minimum Station Staffing Requirements 16.13.1-1 16.13.2 [DELETED] 16.13.2-1 16.13.3 [DELETED] 16.13.3-1 16.13.4 Reactivity Anomaly 16.13.4-1 16.13.5 Deleted 16.13.5-1 16.13.6 Retraining and Replacement of Station Personnel 16.13.6-1 16.13.7 Procedures for Control of Ph in Recirculated 16.13.7-1 Coolant after Loss-of-coolant Accident & Long-term Emergency Core Cooling Systems 16.13.8 Respiratory Protective Program 16.13.8-1 16.13.9 Startup Report 16.13.9-1 16.13.10 Core Operating Limits Reports 16.13.10-1 16.13.11 Procedure for Station Survey Following an Earthquake 16.13.11-1 16.0-6 Rev. 009

TABLE OF CONTENTS (continued)

SECTION TITLE PAGE NO 16.14 CONTROL RODS AND POWER DISTRIBUTION 16.14.1-1 16.14.1 APSR Movement 16.14.1-1 16.14.2 Control Rod Program Verification 16.14.2-1 16.14.3 Power Mapping 16.14.3-1 16.14.4 [DELETED] 16.14.4-1 16.14.4.a Engineering Work Station 16.14.4.a-1 16.15 VENTILATION FILTER TESTING PROGRAM 16.15.1-1 16.15.1 [DELETED] 16.15.1-1 16.15.2 Control Room Pressurization and Filtering System 16.15.2-1 16.15.3 Spent Fuel Pool Ventilation System 16.15.3-1 16.0-7 Rev. 009

Containment Leakage Tests 16.6.1 16.6 ENGINEERED SAFETY FEATURES 16.6.1 Containment Leakage Tests COMMITMENT The local leak rate shall be measured for the containment penetrations listed in Table 16.6-1 in accordance with ITS SR 3.6.1.1.

APPLICABILITY MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. NA A.1 NA NA SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.1.1 NA NA BASES This commitment establishes the list of penetrations that require local leak rate testing in accordance with ITS SR 3.6.1.1. This list was removed from the Technical Specifications in accordance with the guidance in NRC Generic Letter 91-08.

The requirement to leak test the blind isolation flanges on the containment Hydrogen Recombiner System permanent piping after each installation was relocated from CTS 4.4.3.1.b during conversion to the ITS.

The Containment Leak Rate Testing Program (Type A and Type B Tests only) is credited in Oconee License Renewal with managing aging of steel components of the Reactor Building Containment for the period of extended operation.

REFERENCES

1. 10 CFR 50, Appendix J.

2. NRC Generic Letter 91-08.

3. UFSAR section 3.8.1.7.4, 6.2.3, 6.2.4, and Table 18-1.

4. OSS-0274.00-00-0016, Oconee License Renewal Commitments.

16.6.1-1 Rev. 001

Containment Leakage Tests 16.6.1 Table 16.6-1 List of Penetrations With 10 CFR 50 Appendix J Requirements Penetration System Type A Test Local Leak Remarks Number System Test Condition 1 Pressurizer sample line (Unit 1 only) Vented - Type C Note 1, 2 2 OTSG A Sample line Not Vented None Required 3 Component Cooling inlet Vented - Type C line Note 1, 2 4 OTSG B drain line Not Vented None required 5a RB normal sump drain line portion Not Vented None required 5a Hydrogen Recombiner drains portion Not Vented None required 5b Post Accident Liquid Vented - Type C Sample Line Note 1, 2 6 Letdown line Vented - Type C Note 1, 2 7 RC Pump seal return line Not Vented Type C Note 3 8a Pressurizer Aux. Spray Line Not Vented None Required 8b Loop A nozzle warming line Not Vented None Required RCS normal makeup line 9 Not Vented None Required and HP injection A loop 10a RC Pump B1 seal injection Not Vented Type C 10b RC Pump B2 seal injection Not Vented Type C 11a Fuel transfer tube cover portion Not Vented Type B 11b RC Makeup Pump suction portion Vented - Type C Note 1, 2 11c Fuel transfer tube drain portion Vented - Type C Note 1, 2 12a Fuel transfer tube cover portion Not Vented Type B 12b RC Makeup Pump discharge portion Vented - Type C Note 1, 2 12c SSF letdown line portion Vented - Type C Note 1, 2, 4 13 RB Spray inlet line Not Vented None Required 14 RB Spray inlet line Not Vented None Required 15 LPI and DHR inlet line Not Vented None Required 16 LPI and DHR inlet line Not Vented None Required 17 OTSG B Emergency FDW line Not Vented None Required 18 Quench tank vent line Vented - Type C Note 3 Note 1, 2 19 RB purge inlet line Vented - Note 1 Type C Note 3 20 RB purge outlet line Vented - Note 1 Type C Note 3 16.6.1-2 Rev. 001

Containment Leakage Tests 16.6.1 Table 16.6-1 List of Penetrations With 10 CFR 50 Appendix J Requirements Penetration System Type A Test Local Leak Remarks Number System Test Condition 21 LPSW to RC Pump motors and lube Not Vented None Required oil coolers inlet 22 LPSW from RC Pump motors and Not Vented None Required lube oil coolers outlet 23a RC Pump A1 seal injection Not Vented Type C 23b RC Pump A2 seal injection Not Vented Type C 24a RB H2 Analyzer Train A Vented - Note 1 Type C 24b RB H2 Analyzer Train A Vented - Note 1 Type C 25 OTSG B Feedwater line Not Vented None Required 26 OTSG A Main steam line Not Vented None Required 27 OTSG A Feedwater line Not Vented None required 28 OTSG B Main steam line Not Vented None required 29 Quench tank drain line Vented - Type C Note 3 Note 1, 2 30, 31, 32 LPSW for RB Cooling units inlet line Not Vented None required 33, 34, 35 LPSW for RB cooling units outlet line Not Vented None required 36, 37 RB emergency sump recirculation Not Vented None required line 38 Quench tank cooler inlet line Vented - Type C Note 1, 2 39a CFT Vent Line Vented - Type C (Unit 2, 3 Note 1, 2 only) 39b HP Nitrogen supply Vented - Note 1 Type C 40 RB emergency sump drain line Not Vented None required 40 LDST drain line portion Not Vented None required 41 Instrument air supply & ILRT Vented - Note 1 Type C verification line 42a RB H2 Analyzer Train B Vented - Note 1 Type C 42b RB H2 Analyzer Train B Vented - Note 1 Type C 43 OTSG A drain line Not Vented None required 44 Component cooling to control rod Vented - Type C drive inlet line Note 1, 2 45a ILRT instrument line Vented - Type C Note 1, 2 45b ILRT instrument line Vented - Type C Note 1, 2 45c ILRT instrument line Vented - Type C (Units 2 & 3) Note 1, 2 48 Breathing air inlet Vented - Note 1 Type C 16.6.1-3 Rev. 001

Containment Leakage Tests 16.6.1 Table 16.6-1 List of Penetrations With 10 CFR 50 Appendix J Requirements Penetration System Type A Test Local Leak Remarks Number System Test Condition 49 LP Nitrogen supply Vented - Note 1 Type C (Unit 1 only) 50 OTSG A Emergency FDW line Not Vented None required 51 ILRT Pressurization line Vented - Note 1 Type C 52 HP injection to 'B' loop Not Vented None required 53a (All) HP Nitrogen supply to 'A' core flood Vented - Note 1 Type C tank 53b LP Nitrogen supply Vented - Note 1 Type C (Units 2,3) 54 Component cooling outlet line Vented - Type C Note 3 Note 1, 2 55 Demineralized water supply Vented - Type C Note 1, 2 56 Spent fuel canal fill and drain Vented - Type C Note 1, 2 57 DHR return line Not Vented None required (Unit 1 only) 58a Pressurizer sample line Vented - Type C (Unit 2, 3) Note 1, 2 58b (All) OTSG B sample line Not Vented None required 59 CF tank sample line Not Vented None required 60 RB sample line (outlet) Vented - Note 1 Type C Note 3 61 RB sample line (inlet) Vented - Note 1 Type C Note 3 62 (Units 2, 3 DHR return line Not Vented None required Only) 63 LPSW RBAC Supply Vented - Type C Note 1,2 64 LPSW RBAC Return Vented - Type C Note 1,2 90 Personnel hatch Type B 91 Equipment hatch Vented Type B 92 Emergency hatch Vented Type B 101 through Electrical Penetrations Vented Type B 105 NOTE 1 Pathways shall be vented to the containment atmosphere during the test. Vented pathways shall be drained of fluid to the extent necessary to expose the pathway to post accident differential pressure.

NOTE 2 Pathways which are Type B or Type C tested within the previous 24 months need not be vented or drained during the Type A test.

NOTE 3 Reverse direction test of inside containment isolation valve authorized. Leakage results are conservative.

NOTE 4 Applicable for units that have completed SSF letdown line replacement.

GENERAL NOTE: Refer to OSS-0254.00-00-4001 for specific penetration testing and alignment bases.

16.6.1-4 Rev. 001

Keowee Operational Restrictions 16.8.4 16.8 ELECTRIC POWER SYSTEM 16.8.4 Keowee Operational Restrictions COMMITMENT a. Keowee Hydro Units (KHUs) 1 and 2 output shall be 85 MW with an operating head 124 feet of water and 145 feet of water during single unit operation.

b. KHUs 1 and 2 outputs shall each be 79 MW with an operating head 124 feet of water and 145 feet of water during dual unit operation.

c. For each KHU, at least one Forebay Level sensor and one Tailrace Level sensor shall be OPERABLE.

d. For each KHU, no manual inputs of forebay or tailrace level to the digital control system shall be made.

APPLICABILITY: During periods of commercial power generation by one or both KHUs whenever a KHU is credited as an emergency power source per Technical Specification 3.8.1 or 3.8.2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Keowee station output A.1 Enter applicable ITS Immediately not within limit. Condition(s) and Required Actions for inoperable OR KHU(s),

Operating head not AND within limits.

A.2 Initiate action to restore Immediately within limits.

(continued) 16.8.4-1 Rev. 001

Keowee Operational Restrictions 16.8.4 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Forebay or B.1 Suspend commercial Immediately Tailrace level sensor operation of both KHUs.

inoperable.

AND OR B.2 Manually input Immediately Forebay or Tailrace Forebay/Tailrace level (s) level manually entered into the digital governor.

into the digital governor SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.8.4.1 Verify Keowee station output and operating During commercial head are within the limits for SLC 16.8.4.a generation and b.

16.8.4-2 Rev. 001

Keowee Operational Restrictions 16.

8.4 BACKGROUND

Portions of this SLC are relocated from CTS 3.7.1 TS Note 3.

During periods of commercial power generation, the OPERABILITY of the Keowee Hydro Units shall be based on operating head and the power level of the Keowee Hydro Units. The Keowee Hydro operating restrictions for commercial power generation shall be contained in the ONS Selected Licensee Commitment manual.

This SLC is used to determine Keowee Hydro Unit OPERABILITY as an Oconee Emergency Power source when Keowee is generating to the commercial grid. It specifies the range of acceptable Keowee operating head and Keowee power generation levels. The operating restrictions were determined by Reference 1.

SLC 16.8.4.a specifies the maximum operating limits of Keowee Hydro Units 1 and 2 when only one Keowee Hydro Unit is operating.

SLC 16.8.4.b specifies the maximum operating limits of Keowee Hydro Units 1 and 2 when both Keowee Hydro Units are operating.

The digital governors for the KHUs use gross head (Forebay level - Tailrace level) for startup wicket gate openings to ensure consistency of start, both for an acceptable overshoot and startup within an acceptable time limit (Reference 6). The head compensation circuitry provides accurate input of the available head from Forebay and Tailrace elevations. The Forebay and Tailrace elevations may also be manually input into the digital governor controls. Therefore, appropriate SLC commitments are included to ensure KHUs 1 and 2 are capable of an acceptable emergency start.

APPLICABLE SAFETY ANALYSIS The Keowee Hydro Units provide emergency power for Oconee Nuclear Station on the appropriate emergency power path. The OPERABILITY of the Keowee Hydro Units is required to ensure the OPERABILITY and the capability of the Emergency Power System. Nuclear Station Modification (NSM) ON-52966 installed Frequency protection and revised the runaway governor protection logic circuits which ensure the OPERABILITY of the Keowee Hydro units during periods of commercial generation. This SLC will ensure that the Keowee Hydro units are operated within the acceptable limits. For Keowee Hydro Units 1 and 2, a digital governor has replaced the original mechanical governor. Analysis of ONS frequency requirements has been completed and the design criteria was part of the modification. This SLC will ensure that the KHUs are operated within acceptable limits.

APPLICABILITY During periods of commercial power generation, the Keowee Hydro Units are required to be within the acceptable regions whenever they are credited per Technical Specification 3.8.1 or 3.8.2 as an emergency power source for one or more Oconee nuclear units.

16.8.4-3 Rev. 001

Keowee Operational Restrictions 16.8.4 ACTIONS The OPERABILITY of the Keowee Hydro Units during periods of commercial generation is ensured when the Keowee Hydro Units operate within limits and other requirements of SLC 16.8.4 are met.

A.1 If the Keowee Hydro Units are determined to be outside the limits of station output or operating head, action will be taken to restore commercial generation of the Keowee Hydro Units to within the limits. In addition, the applicable TS Condition shall be entered since the Keowee Hydro Unit may not be able to perform its design function. Once the commercial operation of the Keowee Hydro Unit(s) is restored to within limits, the TS Condition shall be exited. It is not necessary to perform an OPERABILITY test of Keowee Hydro Units prior to exiting the Condition as long as no maintenance is performed on the units in order to return them to within limits.

B.1 and B.2 Condition B applies when a required forebay or tailrace level sensor is inoperable on either Keowee Hydro Unit since they are required to ensure a proper emergency start of Keowee Hydro Units 1and 2. Required Action B.1 requires commercial operation of both Keowee Hydro Units to be suspended to ensure the tailrace level remains relatively static and manual input of the levels provides the appropriate parameters for the digital controller. Required Action B.1 requires manual input of the Keowee Forebay/Tailrace level into the digital governor controls to ensure Keowee Hydro Units 1 and 2 remain OPERABLE to provide emergency power if needed. Condition B also applies when a manual entry of Forebay/Tailrace level has been made. Required Action B.2 requires commercial operation of both Keowee Hydro Units to be suspended to ensure the tailrace level remains relatively static SURVEILLANCE REQUIREMENTS SR 16.8.4.1 This surveillance ensures that the operating conditions are within the limits of SLC 16.8.4.a or b during commercial generation by the Keowee Hydro units.

REFERENCES:

1. Calculation KC-UNIT1-2-0106

2. 04/19/95 letter from J. W. Hampton to the NRC, "Response to NRC Questions on the Proposed Emergency Power Modification Action Plan."

3. 03/15/95 letter from J. W. Hampton to the NRC, "Proposed Emergency Power Modification Action Plan."

4. 08/15/95 letter from the NRC to J. W. Hampton, "Issuance of Amendments."

5. 03/20/97 Safety Evaluation Report from the NRC to add OPERABILITY requirements and surveillances to the Technical Specifications.

6. NSM ON-53080, Replace Existing KHUs 1 and 2 Governor with Digital Controls.

16.8.4-4 Rev. 001

Fire Detection Instrumentation 16.9.6 16.9 AUXILIARY SYSTEMS 16.9.6 Fire Detection Instrumentation COMMITMENT The provided Fire Detection Instrumentation for each equipment/location shall be FUNCTIONAL as listed in Table 16.9.6-1.

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

Fire Detection Instrumentation located within containment is not required to be FUNCTIONAL during the performance of Type A Containment Leakage Rate Tests.

APPLICABILITY: At all times.

16.9.6-1 Rev. 007

Fire Detection Instrumentation 16.9.6 ACTIONS

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

FUNCTIONALITY of fire detection instrumentation for adequate equipment/location coverage may also be determined by the Site Fire Protection Engineer or designee, based on performance based assessment risk.

CONDITION REQUIRED ACTION COMPLETION TIME A. All fire detection A.1 --------------NOTE-------------

instruments in all fire An hourly firewatch is not zones nonfunctional required for inaccessible due to fire detection equipment/locations such system failure. as the Reactor Building at power operation. Periodic inspections using a TV camera (if available) are permitted, or, the inaccessible equipment condition may be monitored by remote indications which would ------------NOTE-----------

provide early warning of a The provisions of SLC fire. 16.2.7 do not apply.

Establish hourly fire watch once within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months patrol in all affected fire zones. AND hourly +25% thereafter 16.9.6-2 Rev. 007

Fire Detection Instrumentation 16.9.6 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One or more Fire B.1 --------------NOTE-------------

Detection An hourly firewatch is not Instrument(s) in any required for inaccessible fire zone equipment/locations such nonfunctional. as the Reactor Building at power operation. Periodic inspections using a TV camera (if available) are permitted, or, the inaccessible equipment condition may be monitored by remote indications which would ------------NOTE-----------

provide early warning of a The provisions of SLC fire. 16.2.7 do not apply.

Establish hourly fire watch once within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months patrol for the affected fire detection instruments or AND zones.

hourly +25% thereafter OR B.2 Complete an evaluation as Prior to terminating permitted by RIS 2005-07 Required Action B.1 and implement alternative compensatory measures as required.

16.9.6-3 Rev. 007

Fire Detection Instrumentation 16.9.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.6.1 Perform CHANNEL FUNCTIONAL TEST of 31 days Oconee Fire Detection Instruments using Fire Detection Instrumentation Control Board Panel Test Switch.

SR 16.9.6.2 Visually inspect Oconee Fire Detection 184 days Instruments accessible during power operation.

SR 16.9.6.3 Test each Oconee fire detector for sensitivity. 12 months SR 16.9.6.4 Visually inspect Oconee Fire Detection 24 months Instruments not accessible during power operation.

SR 16.9.6.5 Test each Oconee fire detector not accessible 24 months during power operation for sensitivity.

16.9.6-4 Rev. 007

Fire Detection Instrumentation 16.9.6 TABLE 16.9.6-1 Fire Detection Instrumentation OCONEE NUCLEAR STATION Fire Fire Detectors Area Zone Location Description Details Provided AB Auxiliary Building El. 758 - Col. S-AB 48 T/45-47 Unit 3 LPI & RB Spray Pumps LPI/HPI areas 2 El. 758 - Col. S-AB 49 T/42-44 Unit 3 LPI & RB Spray Pumps LPI/HPI areas 2 El. 758 - Col.

AB 50 R-S/42-44 Unit 3 HPI Pump Area LPI/HPI areas 1 El. 758 - Col. Unit 3 HPI Pump. Spent Resin Xfr Pump Waste AB 50A R-S/45-47 Tank, Waste & CT Dm Pumps LPI/HPI areas 1 El. 758 - Col. S- Unit 2 LPI Pumps & Valve Room (Inside Room AB 52 T/29-31 63) LPI/HPI areas 2 El. 758 - Col. S-AB 53 T/26-29 Units 1 & 2 LPI & RB Spray Pumps LPI/HPI areas 2 El. 758 - Col. S- Unit 1 LPI Pumps & Valve Room (Inside Room AB 54 T/24-26 61) LPI/HPI areas 2 El. 758 - Col. Unit 1 RB Sump & Cmp Dm Pump, HPI Pump, AB 55 R-S/24-26 Spent resin Xfer Pump LPI/HPI areas 1 El. 758 - Col.

AB 55A R-S/26-27 Unit 1 & 2 HPI Pump Area LPI/HPI areas 1 El. 758 - Col. Unit 2 Spent Resin Xfer Pump, HPI Pump, RB AB 56 R-S/28-30 Sump & Comp Brn Pump, Wt LPI/HPI areas 1 Unit 3 BA Mix, Spt Res Storage, RC Bld HUT, AB 58 Rms. 100, 261 CBAST, Misc WHUT 1st floor hallway 7 AB 60 Rm. 159 Unit 3 LPI Room Hatch Area LPI hatch 3 AB 61 Rm. 158 Unit 3 HPI Room Hatch Area all 3 AB 62 Rm. 157 Unit 3 Operators Panel/Chem Sample Hood Waste Control 1 ASW SWGR area/

AB 64 Rm. 128 Unit 2 Emerg Aux Service Water Pump PSW pump area 2 Unit 2 MWHT, Misc Wst Exp, CBAST, RC Bld AB 65 Rms. 100, 124 Xfer Pmp, RC Bld HT 1st floor hallway 9 AB 67 Rm. 119 Unit 2 LPI Room Hatch Area LPI hatch 3 AB 68 Rm. 118 Unit 2 HPI Pump Hatch Area HPI hatch 2 AB 69 Rm. 117 Unit 2 Operators Panel/Chem Sample Hood Waste Control 1 AB 70 Rm. 119 Unit 1 LPI Room Hatch Area LPI hatch 1 AB 72 Rm. 118 Unit 1 HPI Pump Hatch Area HPI hatch 3 Unit 1 RC HU Tnks, CBAST, RC Bld Xfr Pmp, AB 76 Rm. 100 Wst Dmg, Fltr Room SRST 1st floor hallway 6 AB 77 Rms. 200, 264 Unit 3 Storage, Chemistry Storage all 14 AB 79 Rm. 252 Unit 3 RB Component Coolers Component Coolers 1 Rms. 200, 220, Unit 2 I&E Hot shop, Misc Evap Fd Tk, Chem AB 81 224 Storage, Laund, RC EFT 2nd floor hallway 15 AB 83 Rm. 216 Unit 1 & 2 RB Component Coolers Component Coolers 1 AB 85 Rms. 200, 204 Unit 1 Chemistry Storage, High Level Storage 2nd floor hallway 10 16.9.6-5 Rev. 007

Fire Detection Instrumentation 16.9.6 TABLE 16.9.6-1 Fire Detection Instrumentation Fire Fire Detectors Area Zone Location Description Details Provided AB Auxiliary Building (contd)

Unit 3 Hatch Area Chemistry Labs & Change AB 86 Rms. 356, 368 Room 3rd floor hallway 32 Rms. 354, all; including cable AB 89 354A Unit 3 Equipment Room shaft 20 Unit 2 Hallway, Change Room, Laundry Room, Rms, 312, 328, RP Lab, Chemistry Lab, Medical Room, Decon AB 90 333, 334 Room and Offices 3rd floor hallway 36 all; including cable AB 92 Rm. 311 Unit 2 Equipment Room shaft 13 Unit 1 Hallway, Hatch Area, Change Room, Tool AB 94 Rms. 300, 304 Storage, and Drumming Area all 28 all; including cable AB 95 Rm. 310 Unit 1 Equipment Room shaft 12 AB 99 Rm. 452 Unit 3 East Penetration Room all 20 AB 100 Rms. 455, 458 Unit 3 Control Battery Room all 4 Rms. 450, 450B, Cable all; including cable AB 101 Shaft Unit 3 Cable Room shaft 29 AB 103 Rm. 407 Unit 2 East Penetration Room all 25 AB 104 Rm. 408 Unit 2 Control Battery Room all 5 all; including cable AB 105 Rm. 404 Unit 2 Cable Room shaft 21 all; including cable AB 106 Rm. 403 Unit 1 Cable Room shaft 21 AB 108 Rm. 402 Unit 1 East Penetration Room all 22 AB 109 Rm. 400 Unit 1 Control Battery Room all 5 Rms. 504, 505, 506, 507, 508, 509, 510, 511, 512, 513, 515, AB 110 516, 516A Unit 1 & 2 Control Room all 38 Rms. 552, 553, AB 112 554, 556, 557 Unit 3 Control Room all 29 AB 114 Rm. 669 Unit 3 Purge Inlet Equipment Room all 5 AB 115 Rm. 666 Unit 3 Purge Exhaust Equipment Room all 10 Rms. 650, 651, AB 116 653, 657 Unit 3 AHU Room all 6 AB 118 Rm. 618 Unit 2 Purge Exhaust Equipment Room all 10 AB 119 Rm. 603 Unit 1 & 2 AHU Room all 8 AB 121 Rm. 600 Unit 1 Purge Exhaust Equipment Room all 11 16.9.6-6 Rev. 007

Fire Detection Instrumentation 16.9.6 TABLE 16.9.6-1 Fire Detection Instrumentation Fire Fire Detectors Area Zone Location Description Details Provided BH Blockhouse Unit 1 & 2 BH12 45 Block House Unit 1 & 2 Block House all 6 Unit 3 Block BH3 47 House Unit 3 Block House all 3 CT-4 Block spot type smoke CT4 46 House CT-4 Block House detection 2 PSW PSW Building photoelectric smoke PSW PS101 Cable Vault detectors only 2 photoelectric smoke PSW PS102 PSW Main Floor (transformer space) detectors only 6 photoelectric smoke PSW PS103 Battery Room 2 detectors only 2 photoelectric smoke PSW PS104 Battery Room 1 detectors only 2 photoelectric smoke PSW PS105 Mezzanine Area detectors only 4 RB Reactor Building EL. 796+6 and Unit 1 Reactor Building - Basement thru 4th all (both spot type and RB1 122 797+6 Floor heat) 22 EL. 796+6 and Unit 2 Reactor Building - Basement thru 4th all (both spot type and RB2 123 797+6 Floor heat) 22 EL. 796+6 and Unit 3 Reactor Building - Basement thru 4th all (both spot type and RB3 124 797+6 Floor heat) 22 SSF Standby Shutdown Facility all (Honeywell panel SSF SSF SF104 Standby Shutdown Facility detection) 75 TB Turbine Building Ele. 775 - Col.

TB 1 B-E/52-56 Unit 3 Lube Oil Purifier Area all 2 Ele. 775 - Col.

TB 2 E-F/54-55 Unit 3 EHC Area all 3 Ele. 775 - Col. all (both spot type and TB 3 H-N/48-56 Unit 3 Heater Drain Pumps 3D1 & 3D2 beam) 15 Ele. 775 - Col.

TB 4 E-F/54-55 Unit 3 Turbine Driven EFDW Pump Area all 2 Ele. 775 - Col.

TB 6 B-E/42-46 Unit 3 Main Feedwater Pump Area all 4 Ele. 775 - Col.

TB 7 E-F/43-44 Unit 3 Motor Driven EDFW Pump Area all 1 Ele. 775 - Col.

TB 8 F-G/43-44 Unit 3 Hotwell Pump & TB Sump Area all 1 Ele. 775 - Col.

TB 9 J-M/43-44 Unit 3 Powdex/LPSW Pump Area all 2 16.9.6-7 Rev. 007

Fire Detection Instrumentation 16.9.6 TABLE 16.9.6-1 Fire Detection Instrumentation Fire Fire Detectors Area Zone Location Description Details Provided TB Turbine Building (contd)

Ele. 775 - Col. spot type smoke TB 10 B-C/38-39 Unit 2 Lube Oil Purifier Area detectors 2 Ele. 775 - Col.

TB 11 E-F/40-41 Unit 2 EHC Area all 3 Ele. 775 - Col. Unit 2 Heater Drain Pumps 2D1, 2D2, 2E1, & all (both spot type and TB 12 H-N/34-42 2E2 beam) 15 Ele. 775 - Col.

TB 13 B-D/32-38 Unit 2 Turbine Driven EFDW Pump Area all 4 Ele. 775 - Col.

TB 15 B-E/27-32 Unit 2 Main Feedwater Pump Area, MCC 2XC all 6 Ele. 775 - Col.

TB 17 F-J/28-29 Unit 2 HW Pump, LPSW Pump - B Area all 3 Ele. 775 - Col.

TB 18 L-M/30-31 Unit 2 Powex, Backup IA Compressors all 1 Ele. 775 - Unit 1 Main Feedwater Pump Area, MCC 1XC TB 19 Col.E-F/21-27 Switchgear all 5 Ele. 775 - Col.

TB 21 F-J/27-28 Unit 1 HW Pump, LPSW Pump - A Area all 3 Ele. 775 - Col.

TB 22 L-M/22-23 Unit 1 Powdex Area all 1 Ele. 775 - Col. Unit 1 TDEFDW Pump, EHC, Oil Purifier, TB 24 B-F/13-21 Auxiliary Boiler all 4 Ele. 775 - Col all (both spot type and TB 25 F-M/13-20 Heater Drain Pumps 1E1 & 1E2 beam) 15 Ele. 796 - Col.

TB 27 E-G/53-55 Unit 3 MT Oil Tank, MS & Control Valves all 6 Ele. 796 - Col.

TB 28 L-M/52-53 Unit 3 Heater Bay Area, MSRH A1 & A2 all 3 Ele. 796 - Col.

TB 29 J-M/43-46 Unit 3 4160 Volt Switchgear all 37 Ele. 796 - Col.

TB 31 D-G/39-41 Unit 2 MT Oil Tank, MS & Control Valves all 4 Ele. 796 +6 - Unit 2 Heater Bay Area, MSRH A1 & A2, 3XS6, TB 32 Col. G-N/32-42 3X10, MCC 2XGB, SSF Transfer cables all 14 Ele. 796 +6 - Unit 2 6900/4160 Volt Switchgear, SSF Transfer TB 33 Col. B-N/28-32 cables all 31 Ele. 796 +6 -

TB 33A Col.B-N/28-30 Unit 2 Power Battery Room all 1 Ele. 796+6 -

Col. B-N/23-28 (not including Unit 1 6900/4160 Volt Switchgear, SSF Transfer TB 34 FZ 34A) cables all 30 Ele. 796 +6-TB 34A Col. L-M/25-26 Unit 1 Power Batteries all 2 Ele. 796 - Col. Unit 1 Heater Bay Area, MSRH A1 & A2, MCC TB 35 G-N/14-23 1XGB Switchgear all 4 Ele. 796 - Col.

TB 36 F-G/14-15 Unit 1 MT Oil Tank, MS & Control Valves all 3 Ele. 796 +6 -

TB 37 Col.N-R/86-87 Unit 2 SSF Transfer Cables all 4 Ele. 822 - Col.

TB 38 D-G/45-54 Unit 3 Main Turbine, Turbine Flr, Offices all 7 16.9.6-8 Rev. 007

Fire Detection Instrumentation 16.9.6 TABLE 16.9.6-1 Fire Detection Instrumentation Fire Fire Detectors Area Zone Location Description Details Provided TB Turbine Building (contd)

Ele. 822 - Col.

TB 39 J-N/43-56 Unit 3 Auxiliary Shutdown Panel all 1 Ele. 822 - Col.

TB 39A L-M/45-47 Unit 3 Power Battery Room all 2 Ele. 822 - Col.

TB 40 D-G/28-40 Unit 2 Main Turbine, Turbine Flr, Offices all 7 Ele. 822 - Col TB 41 J-N/27-42 Unit 1 Auxiliary Shutdown Panel all 1 Ele. 822 - Col.

TB 42 E-G/15-27 Unit 1 Main Turbine, Turbine Flr, Offices all 7 Ele. 796 - Col.

TB 44 C-F/12-14 Unit 1 MCC 1XA & 1XA-A all 2 WP1 Unit 1 West Penetration Room WP1 97 Rm. 348 Unit 1 Cask Decon Tank Room all 4 WP1 107 Rm. 409 Unit 1 West Penetration Room all 7 WP1 120 Rm. 620 Unit 1 Purge Inlet Equipment Room all 6 WP2 Unit 2 West Penetration Room WP2 91 Rm. 349 Unit 2 Cask Decon Tank Room all 4 WP2 102 Rm. 410 Unit 2 West Penetration Room all 7 WP2 117 Rm. 621 Unit 2 Purge Inlet Equipment Room all 6 WP3 Unit 3 West Penetration Room WP3 87 Rm. 376 Unit 3 Cask Decon Tank Room all 4 WP3 98 Rm. 455 Unit 3 West Penetration Room all 7 YARD Yard YARD-YARD EAST U3 RCP SWGR Yard Area - East U3 RCP SWGR 2 16.9.6-9 Rev. 007

Fire Detection Instrumentation 16.9.6 BASES On June 16, 2004, the NRC revised its regulation Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Section 50.48 to include a new paragraph 50.48(c) that incorporates by reference National Fire Protection Association 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants 2001 Edition, hereafter referred to as NFPA 805. On December 29, 2010, the NRC issued Oconees Safety Evaluation Report (SER) approving adoption of a performance-based (PB) fire protection program (FPP) as an alternative to the existing, deterministic fire protection regulations. Specifically, NFPA 805 allows the use of PB methods, such as fire modeling, and risk-informed (RI) methods, such as fire probabilistic risk assessment (PRA), to demonstrate compliance with the nuclear safety performance criteria. As a result of transitioning to the NFPA 805 Licensing Basis, certain Fire Protection Systems and Features are required to satisfy either the NFPA 805 Chapter 3 fundamental fire protection program safety goals or the NFPA 805 Chapter 4 performance based/risk informed safety goals. These required Fire Protection Systems and Features are placed into SLCs since they comprise the safety basis of the new fire protection program.

Allowed out of service times and action statements along with some surveillance requirements are consistent with the NFPA 805 licensing basis and safety goals. The documentation of these required fire protection systems and features is provided in the SER Attachments A and D.

The equipment contained in this SLC is considered part of the NFPA 805 Power Block. Power Block structures, systems, and components (SSCs) include all safety-related and balance-of-plant systems and components required for operation, including radioactive waste processing and storage, the 230 kV switchyard, and Keowee Dam and associated structures. Power Block SSCs are required for the safe and reliable operation of the plant. Calculation OSC-10650, Oconee NFPA 805 Power Block, defines the Power Block for Oconee. Not all fire detection within the Power Block is required by this SLC. Only the Power Block detection listed in Table 16.9.6-1 herein is within the scope of this SLC.

DPC-1435.00-00-0002, Technical Basis for Roving Continuous Fire Watches, justifies the allowances for continuous and hourly fire watches. This Selected Licensee Commitment is part of the Oconee Fire Protection Program and therefore subject to the provisions of Oconee Facility Operating License Conditions.

ACTIONS FUNCTIONALITY of the NRC committed Fire Detection Instrumentation ensures that adequate warning capability is available for the prompt detection of fires in areas containing safety related and important to safety equipment at Oconee Facilities. Prompt detection of fires will reduce the potential for damage to safety related equipment and is an integral element in the overall facility fire protection program. The regulatory requirement is to have NFPA 805 required Fire Detection Instrumentation FUNCTIONAL at all times.

16.9.6-10 Rev. 007

Fire Detection Instrumentation 16.9.6 A.1 and B.1 In the event that a portion of the Fire Detection Instrumentation is nonfunctional, the establishment of compensatory actions in the affected areas is required to provide detection capability until the nonfunctional instrumentation is restored to FUNCTIONALITY.

B.2 RA B.2 provides an option for times when fire watches may not be the most effective compensatory measure for degraded or inoperable fire protection features. To implement a different compensatory measure or combination of measures, perform a documented evaluation of the impact of the proposed alternate compensatory measure. The evaluation must demonstrate that the alternate compensatory measure would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. Additionally, the evaluation of the alternate compensatory measure should incorporate risk insights regarding the location, quantity, and type of combustible material in the fire area; the presence of ignition sources and their likelihood of occurrence; the automatic fire suppression and fire detection capability in the fire area; the manual fire suppression capability in the fire area; and the human error probability where applicable. Retain all such evaluations in accordance with 10 CFR 50.48(a). Refer to RIS 2005-07 for additional information.

REFERENCES:

1. Oconee UFSAR, Chapter 9.5-1 and UFSAR, Chapter 18, Table 18-1 (Portions of this SLC are credited in the Fire Protection Program for License Renewal).

2. Oconee License Renewal Commitments, OSS-0274.00-00-0016.

3. Oconee Fire Protection Safety Evaluation dated December 29, 2010.

4. Oconee License Amendment Request dated April 14, 2010.

5. Oconee Fire Protection Design Basis Specification for Fire Protection Program, (currently contained in the Fire Protection DBD), as revised.

6. Oconee Plant Design Basis Specification for Fire Detection, as revised.

7. Drawing Series O-0310-K, Fire Protection Plans.

8. Drawing Series O-0310-L, Fire Protection Plans.

9. OSC-10650, Oconee NFPA 805 Power Block.

10. DPC-1435.00-00-0002, Technical Basis for Roving Continuous Fire Watches.

11. O-0756-J, Location Diagram Fire Detection System (FD) Standby Shutdown Facility Detector Locations.

16.9.6-11 Rev. 007

Spent Fuel Cooling System 16.9.13 16.9 AUXILIARY SYSTEMS 16.9.13 Spent Fuel Cooling System COMMITMENT a) Perform specified SR.

b) 1. For units that have not replaced the SSF letdown line (Reference 8, 9, and 10) - Provide SSF Makeup source and letdown storage capacity (for RCS inventory control) with flowpath valves SF-1 and SF-2 Open.

2. For units that have replaced the SSF letdown line (Reference 8, 9, and 10) - Provide SSF Makeup source and letdown storage capacity (for RCS inventory control) with flowpath valves SF-1, SF-221, and SF-222 Open and valve SF-2 Closed.

c) Provide capability for draining accumulated Reactor Building Spray water (post actuation) from the fuel transfer canal with flowpath valves SF-65 and SF-66 Open.

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

1. Commitment a applies when irradiated fuel assemblies are stored in the spent fuel pool.

2. Commitment b applies in MODES 1, 2, and 3.

3. Commitment c applies in MODES 1, 2, 3, and 4.

APPLICABILITY: At all times ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Commitment b not met. A.1 Log unavailability duration in Immediately the Operations Log for Maintenance Rule Performance monitoring.

AND (continued) 16.9.13-1 Rev. 001

Spent Fuel Cooling System 16.9.13 CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 Perform a Risk Assessment Immediately considering equipment out of service.

AND A.3 Declare SSF Reactor Immediately Coolant Makeup System inoperable.

B. Commitment c not met. B.1 Log unavailability duration in Immediately the Operations Log for Maintenance Rule Performance monitoring.

AND B.2 Perform a Risk Assessment Immediately considering equipment out of service .

AND B.3 Declare LPI inoperable. Immediately AND B.4 Declare Reactor Building Immediately Spray System inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.13.1 Functionally Test the Spent Fuel Cooling Prior to each refueling System.

16.9.13-2 Rev. 001

Spent Fuel Cooling System 16.9.13 BASES Actions Spent Fuel Cooling System provision for SSF Makeup source and letdown storage capability The purpose of this SLC action is to track Maintenance Rule unavailability and to ensure an acceptable level of risk associated with the removal from service of a risk significant maintenance rule system function. This function is credited for the Turbine Building Flood event.

For Unit(s) that have not replaced the SSF letdown line (References 8, 9, and 10):

Spent Fuel Cooling System valves SF-1 and SF-2 shall be Open in MODES 1, 2, and 3 to provide an adequate flowpath when the SSF RC Makeup System is required to be operable.

Isolation of SF-1 or SF-2 would block the SSF RC Makeup System recirculation line or the SSF RC letdown line. These lines are needed to regulate the amount of liquid added to the RC during an SSF Event.

When SF-1 is isolated, the SSF RC Makeup System is unable to deliver flow from the spent fuel pool to its corresponding Units RC pump seals during an SSF Event. The piping between SF-2 and HP-428 could be overpressurized if the SSF RC Makeup System were operated with SF-2 isolated.

For Unit(s) that have replaced the SSF letdown line (References 8, 9, and 10):

Spent Fuel Cooling System valves SF-1, SF-221, and SF-222 shall be Open and valve SF-2 shall be Closed in MODES 1, 2, and 3 to provide an adequate flowpath when the SSF RC Makeup System is required to be operable. Isolation of SF-1 would block the SSF RC Makeup recirculation line. Isolation of SF-221 or SF-222 would restrict the SSF RC letdown line flow into the spent fuel pool during an SSF Event. SF-2 is required to be Closed to limit the impact of a potential waterhammer during an SSF Event. These lines are needed to control RCS inventory during an SSF Event.

When SF-1 is isolated, the SSF RC Makeup System is unable to deliver flow from the spent fuel pool to its corresponding Units RC pump seals during an SSF Event. When SF-2, SF-221, and SF-222 are isolated, control of pressurizer level during an SSF Event would be lost. If SF-2, SF-221, and SF-222 are isolated, the spent fuel transfer tube and upstream piping could be overpressurized when:

The SSF RC makeup pump is operated for testing,

The SSF letdown line is operated.

Spent Fuel Cooling System provision for draining the fuel transfer canal drain following a Reactor Building Spray actuation.

The purpose of this SLC action is to track Maintenance Rule unavailability and ensure an acceptable level of risk associated with the removal from service of a risk significant maintenance rule system function.

SF-65 and SF-66 shall be open in MODES 1, 2, 3, and 4 to provide a flowpath to drain Reactor Building Spray water (post actuation) from the fuel transfer canal.

16.9.13-3 Rev. 001

Spent Fuel Cooling System 16.9.13 BASES Actions (Continued)

There are two 4-inch drain lines from the deep end of the Fuel Transfer Canal which are used during refueling operations to drain the canal. There is a branch line from this drain to the Reactor Building sump which contains two manual isolation valves in the Spent Fuel system.

These valves (SF-65 and SF-66) must be kept open during normal plant operation (above MODE 5) so that the canal will gravity drain to the sump in the event of a LOCA to provide an adequate supply of water for post-accident sump recirculation for ECCS systems.

Surveillance Requirements The surveillance requirement(s) of this SLC section were relocated from CTS Table 4.1-2, Item 9 during the conversion to ITS.

Functional testing of the Spent Fuel Cooling System is performed prior to refueling to assure proper system operation.

REFERENCES

1. UFSAR 9.6.1, Standby Shutdown Facility.

2. Design Basis Specification for the Spent Fuel Cooling System (OSS-0254.00-00-1006, Rev. 14).

3. Design Basis Specification for the SSF RC Makeup System (OSS-0254.00-00-1004, Rev 23).

4. Design Basis Specification for the Reactor Building Spray System (OSS-0254.00 1034, Rev. 16).

5. OSC-1948, Post Accident Reactor Building Water Level Following a Large Break LOCA, Revision 7, 2/26/2004.

6. 10 CFR 50.65, Maintenance Rule

7. PIP 02-4679, Assess Adequacy of Administrative Controls for Risk Significant Equipment.

8. EC 112474, Modify the Unit 1 SSF RCS Letdown Line to Support SSF Operability in All Modes of Applicability

9. EC 403752, Modify the Unit 2 SSF RCS Letdown Line to Support SSF Operability in All Modes of Applicability

10. EC 112872, Modify the Unit 3 SSF Letdown Line to Achieve Throttling Capability 16.9.13-4 Rev. 001

SSF External Flood Protection 16.9.21 16.9 AUXILIARY SYSTEMS 16.9.21 Standby Shutdown Facility (SSF) External Flood Protection COMMITMENT SSF External Flood protection integrity shall be maintained.

APPLICABILITY: Whenever the SSF is required to be OPERABLE ACTIONS

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

Conditions are not applicable if SSF External Flood protection integrity is breached due to planned maintenance activities which will require contingency measures prior to breaching the barrier.

CONDITION REQUIRED ACTION COMPLETION TIME A. SSF External Flood A.1 Implement contingency Immediately protection integrity actions in accordance with maintained > 801 feet Site Directive 3.2.16.

and 803.5 feet B. SSF External Flood B.1 Perform a risk Immediately protection integrity assessment using the maintained 801 feet. Electronic Risk Assessment Tool.

AND B.2.1 Implement contingency 7 days actions in accordance with Table 16.9.21-1.

OR B.2.2 Restore the SSF External 7 days Flood Protection integrity of SSF building.

C. SSF External Flood C.1 Enter applicable TS Immediately protection integrity of the Condition.

SSF building maintained 796.5 feet.

16.9.21-1 Rev. 001

SSF External Flood Protection 16.9.21 CONDITION REQUIRED ACTION COMPLETION TIME D. Required Actions and D.1 Initiate a NCR. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Associated Completion Times not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.21.1 NA NA BASES This SLC provides monitoring of Maintenance Rule High Safety Significant Function 8094.3, Provide barrier to external flooding of the SSF. Based on information from the Oconee Probabilistic Risk Assessment (PRA), external flood walls were installed at the south and north entrances to the SSF Building to reduce the consequences of a Jocassee dam failure. These walls were originally built to an elevation of 801; however, the height was later increased to 803.5 to provide additional margin. SSF flood barriers are adequate to protect the SSF from the most probable Jocassee dam failure flood scenarios.

Access through the south wall is provided through a water tight door. Stairways over the walls provide access to both the north and south entrances. Flood protection integrity of the SSF must be maintained except for normal ingress and egress through the south side water tight door. In addition to the flood wall located at the north entrance to the SSF and to the flood wall and water tight door located at the south entrance to the SSF, the following features prevent flood water from entering the SSF:

SSF exterior concrete wall (not located within area protected by north and south flood walls).

SSF exterior concrete wall located below 803.5 provides flood protection. Though the SSF exterior concrete wall was not originally designed for external flooding due to a Jocassee dam failure, the design of the SSF exterior concrete wall is considered to be inherently capable of providing adequate flood protection.

Bolted plate, electrical/temporary access (pipe), and closed valves CO-14 and CO-17, located at CO2 fill lines that penetrate the South wall of the SSF. Use of the CO2 system valves to fill and vent the CO2 system is acceptable because the UFSAR allows the use of seismic boundary valves under procedural controls. These valves are procedurally controlled. Use of the electrical/temporary access pipe is acceptable because the 16.9.21-2 Rev. 001

SSF External Flood Protection 16.9.21 elevation of the access pipe opening in the SSF is above the elevation of the flood wall that protects the SSF from external flooding.

SSF sewer system piping including check valve ST-53 and downstream SSF sewer system piping located inside the SSF.

Check valve ST-53 prevents flood water from entering the SSF via the SSF sewer system.

Piping and electrical exterior wall penetration seals located below 803.5 elevation.

When flood protection integrity of the SSF is degraded, a risk assessment shall be performed immediately by RA B.1. RA B.1 is required to be performed in conjunction with either, RA B.2.1 to implement compensatory measures in accordance with Table 16.9.21-1 or RA B.2.2 to restore SSF External Flood Protection Integrity within 7 days. A 7-day Completion Time is sufficient for either of these RAs.

Table 16.9.21-1 Compensatory Actions Com# Protective Measure Compensatory Actions 1 Flood protection integrity of the 1. Place sandbags at breach.

SSF building shall be maintained 2. Place sealing materials at breach.

3. Take other appropriate measures to provide flood protection to SSF.

This SLC addresses SSF external flood protection preserved margin as defined in OSC-11417 up to elevation 803.5 and SSF external flood protection which is considered in the Oconee PRA for floods up to elevation 801. SSF External flood protection is not a licensed requirement of the SSF. Therefore, entry into Condition A or B of this SLC does not require entry into any TS.

However, there is a potential that the SSFs mitigation of a Turbine Building flood could be affected if a flood protection feature located at an elevation of 796.5 is defeated. Condition C requires immediate entry into applicable TS (TS 3.10.1 Condition A, B, C, D, and E) if a flood protection feature located at an elevation of 796.5 is defeated.

Condition D will also initiate a NCR within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if required actions and associated completion times are not met.

The Actions are modified by a NOTE that states that the Conditions are not applicable if SSF External Flood protection integrity is breached due to planned maintenance activities which require contingency measures prior to breaching the barrier. Contingencies as specified by Table 16.9.21-1 or the Control of Passive Design Features Site Directive will be in place when SSF External Flood protection integrity is intentionally breached. SLC actions will not be required.

16.9.21-3 Rev. 001

SSF External Flood Protection 16.9.21 REFERENCES

1) OSS-0254.00-00-1005, Design Basis Document for SSF ASW System

2) Individual Plant Examination of External Events (IPEEE) Submittal Report dated December 21, 1995

3) Letter from JW Hampton (Duke) to NRC dated 3/14/94, Providing Response to Several Findings from the Service Water Audit.

4) Letter from AF Gibson (NRC) to JW Hampton (Duke) dated 2/21/94, Sending Notice of Violation and Deviation for Service Water Audit.

5) Generic Letter 88-20, dated 11/23/88, "Individual Plant Examination for Severe Accident Vulnerabilities"

6) Letter from JF Stolz (NRC) to HB Tucker (Duke), dated 8/14/85, Providing Review of the Oconee PRA that was Performed in Conjunction with NAC of EPRI.

7) NSD 213, Risk Management Process.

8) NSD 415, Operational Risk Management (Modes 1-3) per 10 CFR 50.65 (a)(4).

9) NSD 403, Shutdown Risk Management (Modes 4, 5, 6, and No-Mode) per 10 CFR 50.65 (a)(4).

10) PIP O-05-3770, SSF Risk Reduction PIP

11) PIP O-05-4978, Access panel on south side of SSF below flood level

12) PIP O-06-740, SSF sewage lift station vent line elevation is too low to prevent backflow into the SSF during a Turbine Building Flood.

13) PIP O-06-5375, MRFF on SSF Flood System

14) PIP O-06-5649, NRC letter dated August 31,2006, issued a preliminary white finding, associated with a failure to maintain control of the standby shutdown facility (SSF) flood protection barrier.

15) O-320-Z-3, External Barrier Walls Concrete

16) OSC-631, Standby Shutdown Facility Design

17) SD 3.2.16, Control of Passive Design Features

18) OSC-11417, Evaluate External Flood Mitigation Strategy for Jocassee Dam Failure Using the SSF.

16.9.21-4 Rev. 001

Iodine Radiation Monitoring filters 16.11.11 16.11 RADIOLOGICAL EFFLUENTS CONTROL 16.11.11 Iodine Radiation Monitoring Filters COMMITMENT Assure that the iodine radiation monitoring filters perform their intended function.

APPLICABILITY: At all times.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. NA A.1 NA NA SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.11.11.1 Remove and replace iodine radiation 30 days of operation monitoring filters in RIA-44.

SR 16.11.11.2 Discard spare iodine radiation monitoring After manufacturer filters. expiration date.

BASES The purpose of this commitment is to assure the reliability of the iodine radiation monitoring charcoal filters. Plant procedures prevent the use of spare filters after the manufacturer expiration date.

REFERENCES:

1. Oconee CTS Amendment No. 3/3 SER date July, 1974.

16.11.11-1 Rev. 001

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16.1 INTRODUCTION

8.4 BACKGROUND

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