ML17271A307

Issuance of Amendments to Revise Actions of TS 5.5.12, Primary Containment Leakage Rate Testing Program

ML17271A307
Person / Time
Site:	Hatch
Issue date:	11/30/2017
From:	Hall J Plant Licensing Branch II
To:	Hutto J Southern Nuclear Operating Co
Hall J
References
CAC MF8110, CAC MF8111
Download: ML17271A307 (47)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 November 30, 2017 Mr. J. J. Hutto Regulatory Affairs Director Southern Nuclear Operating Company, Inc.

P. 0. Box 1295, Bin 8038 Birmingham, AL 35201-1295

SUBJECT:

EDWIN I. HATCH NUCLEAR PLANT, UNITS 1 AND 2 - ISSUANCE OF AMENDMENTS TO REVISE TS 5.5.12, "PRIMARY CONTAINMENT LEAKAGE RATE TESTING PROGRAM" (CAC NOS. MF8110 AND MF8111)

Dear Mr. Hutto:

The U.S. Nuclear Regulatory Commission (NRC, the Commission) has issued the enclosed Amendment No. 288 to Renewed Facility Operating License No. DPR-57 and Amendment No. 233 to Renewed Facility Operating License No. NPF-5 for the Edwin I. Hatch Nuclear Plant, Units 1 and 2 (HNP), respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated July 1, 2016, as supplemented by letters dated August 24, 2016, February 10, 2017, June 1, 2017, and July 12, 2017.

The amendments revise the requirements of TS 5.5.12, "Primary Containment Leakage Rate Testing Program," regarding the performance of Type A and Type C leak rate tests, which are required by Title 1O of the Code of Federal Regulations Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." Specifically, the amendments increase the existing testing intervals for the Type A integrated leakage rate test (ILRT) program, and for the Type C containment isolation valve leakage testing of selected components. The amendments also revise the applicable standards and referenced reports governing the primary containment leakage rate testing program for HNP.

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

Sincerely, k/./JJJ

.Ues R. Hall, Senior Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366

Enclosures:

1. Amendment No. 288 to DPR-57

2. Amendment No. 233 to NPF-5

3. Safety Evaluation cc w/enclosures: Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SOUTHERN NUCLEAR OPERATING COMPANY, INC.

GEORGIA POWER COMPANY OGLETHORPE POWER CORPORATION MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CITY OF DALTON, GEORGIA DOCKET NO. 50-321 EDWIN I. HATCH NUCLEAR PLANT, UNIT NO. 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 288 Renewed License No. DPR-57

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

A. The application for amendment to the Edwin I. Hatch Nuclear Plant, Unit No. 1 (the facility) Renewed Facility Operating License No. DPR-57 filed by Southern Nuclear Operating Company, Inc. (the licensee), acting for itself, Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and City of Dalton, Georgia (the owners), dated July 1, 2016, as supplemented by letters dated August 24, 2016, February 10, 2017; June 1, 2017; and July 12, 2017, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

Enclosure 1

2. Accordingly, the license is hereby amended by page changes as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. DPR-57 is hereby amended to read as follows:

(2) Technical Specifications The Technical Specifications (Appendix A) and the Environmental Protection Plan (Appendix B), as revised through Amendment No. 288, are hereby incorporated in the renewed license.

Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. This license amendment is effective as of its date of issuance and shall be implemented within 6 months from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION p-J--Zh~

Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Renewed Facility Operating License No. DPR-57 and Technical Specifications Dateoflssuance: November 30, 2017

ATTACHMENT TO LICENSE AMENDMENT NO. 288 EDWIN I. HATCH NUCLEAR PLANT, UNIT NO. 1 RENEWED FACILITY OPERATING LICENSE NO. DPR-57 DOCKET NO. 50-321 Replace the following pages of the license and the Appendix A Technical Specifications (TSs) with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Pages Insert Pages License License 4 4 TSs TSs 5.0-16 5.0-16

for sample analysis or instrumentation calibration, or associated with radioactive apparatus or components; (6) Southern Nuclear, pursuant to the Act and 10 CFR Parts 30 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Section 50.54 of Part 50, and Section 70.32 of Part 70; all applicable provisions of the Act and the rules, regulations, and orders of the Commission now or hereafter in effect; and the additional conditions specified or incorporated below:

(1) Maximum Power Level Southern Nuclear is authorized to operate the facility at steady state reactor core power levels not in excess of 2804 megawatts thermal.

(2) Technical Specifications The Technical Specifications (Appendix A) and the Environmental Protection Plan (Appendix B), as revised through Amendment No. 288, are hereby incorporated in the renewed license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

The Surveillance Requirement (SR) contained in the Technical Specifications and listed below, is not required to be performed immediately upon implementation of Amendment No. 195. The SR listed below shall be successfully demonstrated before the time and condition specified:

SR 3.8.1.18 shall be successfully demonstrated at its next regularly scheduled performance.

(3) Fire Protection Southern Nuclear shall implement and maintain in effect all provisions of the fire protection program, which is referenced in the Updated Final Safety Analysis Report for the facility, as contained in the updated Fire Hazards Analysis and Fire Protection Program for the Edwin I. Hatch Nuclear Plant, Units 1 and 2, which was originally submitted by letter dated July 22, 1986. Southern Nuclear may make changes to the fire protection program without prior Commission approval only if the changes Renewed License No. DPR-57 Amendment No. 288

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J,"

Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 50.8 psig.

The maximum allowable primary containment leakage rate, La, at Pa is 1.2% of primary containment air weight per day.

Leakage rate acceptance criteria are:

a. Primary containment overall leakage rate acceptance criterion is s 1. O La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are s 0.60 La for the combined Type Band Type C tests, ands 0.75 La for Type A tests;

b. Air lock testing acceptance criteria are:

1) Overall air lock leakage rate is s 0.05 La when tested at~ Pa,

2) For each door, leakage rate is s 0.01 La when the gap between the door seals is pressurized to ~ 1O psig for at least 15 minutes.

The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program.

(continued)

HATCH UNIT 1 5.0-16 Amendment No. 288

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SOUTHERN NUCLEAR OPERATING COMPANY, INC.

GEORGIA POWER COMPANY OGLETHORPE POWER CORPORATION MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CITY OF DALTON, GEORGIA DOCKET NO. 50-366 EDWIN I. HATCH NUCLEAR PLANT, UNIT NO. 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 233 Renewed License No. NPF-5

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

A. The application for amendment to the Edwin I. Hatch Nuclear Plant, Unit No. 2 (the facility) Renewed Facility Operating License No. NPF-5 filed by Southern Nuclear Operating Company, Inc. {the licensee), acting for itself, Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and City of Dalton, Georgia (the owners), dated July 1, 2016, as supplemented by letters dated August 24, 2016, February 10, 2017; June 1, 2017; and July 12, 2017, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended {the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

Enclosure 2

2. Accordingly, the license is hereby amended by page changes as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-5 is hereby amended to read as follows:

(2) Technical Specifications The Technical Specifications (Appendix A) and the Environmental Protection Plan (Appendix B), as revised through Amendment No. 233 are hereby incorporated in the renewed license.

Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. This license amendment is effective as of its date of issuance and shall be implemented within 6 months from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Renewed Facility Operating License No. NPF-5 and Technical Specifications Date of Issuance: November 3 O , 2 O1 7

ATTACHMENT TO LICENSE AMENDMENT NO. 233 EDWIN I. HATCH NUCLEAR PLANT, UNIT NO. 2 RENEWED FACILITY OPERATING LICENSE NO. NPF-5 DOCKET NO. 50-366 Replace the following pages of the license and the Appendix A Technical Specifications (TSs) with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Pages Insert Pages License License 4 4 TSs TSs 5.0-16 5.0-16

(6) Southern Nuclear, pursuant to the Act and 10 CFR Parts 30 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This renewed license shall be deemed to contain, and is subject to, the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Section 50.54 of Part 50, and Section 70.32 of Part 70; all applicable provisions of the Act and the rules, regulations, and orders of the Commission now or hereafter in effect; and the additional conditions 2 specified or incorporated below:

(1) Maximum Power Level Southern Nuclear is authorized to operate the facility at steady state reactor core power levels not in excess of 2,804 megawatts thermal, in accordance with the conditions specified herein.

(2) Technical Specifications The Technical Specifications (Appendix A) and the Environmental Protection Plan (Appendix B), as revised through Amendment No. 233, are hereby incorporated in the renewed license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) Additional Conditions The matters specified in the following conditions shall be completed to the satisfaction of the Commission within the stated time periods following the issuance of the renewed license or within the operational restrictions indicated. The removal of these conditions shall be made by an amendment to the license supported by a favorable evaluation by the Commission.

(a) Fire Protection Southern Nuclear shall implement and maintain in effect all provisions of the fire protection program, which is referenced in the Updated Final Safety Analysis Report for the facility, as contained 2 The original licensee authorized to possess, use, and operate the facility with Georgia Power Company (GPC). Consequently, certain historical references to GPC remain in certain license conditions.

Renewed License No. NPF-5 Amendment No. 233

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J,"

Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 47.3 psig.

The maximum allowable primary containment leakage rate, La, at Pa is 1.2% of primary containment air weight per day.

Leakage rate acceptance criteria are:

a. Primary containment overall leakage rate acceptance criterion is s 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are s 0.60 La for the combined Type Band Type C tests, ands 0.75 La for Type A tests;

b. Air lock testing acceptance criteria are:

1) Overall air lock leakage rate is s 0.05 La when tested at s Pa,

2) For each door, leakage rate is s 0.01 La when the gap between the door seals is pressurized to 2: 1O psig for at least 15 minutes.

The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program.

(continued)

HATCH UNIT2 5.0-16 Amendment No. 233

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 288 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-57 AND AMENDMENT NO. 233 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-5 SOUTHERN NUCLEAR OPERATING COMPANY, INC.

EDWIN I. HATCH NUCLEAR PLANT, UNITS 1 AND 2 DOCKET NOS. 50-321 AND 50-366

1.0 INTRODUCTION

By application dated July 1, 2016 (Reference 1), as supplemented by letters dated August 24, 2016 (Reference 2), February 10, 2017 (Reference 3); June 1, 2017 (Reference 4); and July 12, 2017 (Reference 5), Southern Nuclear Operating Company, Inc. (SNC, the licensee), requested changes to the Technical Specifications (TSs) for the Edwin I. Hatch Nuclear Plant, Units 1 and 2 (HNP). The supplements dated August 24, 2016; February 10, 2017; June 1, 2017; and July 12, 2017, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC, the Commission) staff's original proposed no significant hazards consideration determination as published in the Federal Register on September 13, 2016 (81 FR 62930).

The proposed changes in this license amendment request (LAR) would revise the requirements of TS 5.5.12, "Primary Containment Leakage Rate Testing Program," regarding the performance of Type A and Type C leak rate tests, which are required by Title 1O of the Code of Federal Regulations Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." Specifically, the amendments increase the existing testing intervals for the Type A integrated leakage rate test (ILRT) program, and for the Type C containment isolation valve leakage testing of selected components. The amendments also revise the applicable standards and referenced reports governing the primary containment leakage rate testing program for HNP.

2.0 REGULATORY EVALUATION

The following NRC requirements and guidance documents are applicable to the NRC staff's review of the LAR:

Enclosure 3

• The regulations in 10 CFR 50.36(c)(5), "Administrative controls," govern the programmatic requirements typically contained in Section 5.0 of technical specifications. Administrative controls are the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure operation of the facility in a safe manner.

• The regulations in 10 CFR 50.54(0) require that primary reactor containments for water cooled power reactors shall be subject to the requirements set forth in 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." Appendix J to 10 CFR Part 50 includes two options: "Option A - Prescriptive Requirements," and "Option B -

Performance-Based Requirements," either of which may be chosen by a licensee for meeting the requirements of Appendix J. The testing requirements ensure that:

(a) leakage through containments or systems and components penetrating these containments does not exceed allowable leakage rates specified in the TS; and (b) integrity of the containment structure is maintained during its service life.

• Option B of Appendix J specifies performance-based requirements and criteria for preoperational and subsequent leakage rate testing of the primary containment. The requirements set forth in Appendix J are satisfied by performing a Type A test to measure the overall integrated leakage rate of the primary containment; Type B pneumatic tests to detect and measure local leakage rates across pressure-retaining and leakage-limiting boundaries; and Type C pneumatic tests to measure containment isolation valve leakage rates.

Following preoperational testing and initial plant startup, periodic tests are required to be conducted at intervals based on the historical performance of the overall containment system (for Type A tests), and based on the safety significance and historical performance of each penetration boundary and isolation valve (for Type Band C tests) to ensure integrity of the overall containment system as a barrier to fission product release.

• The leakage rate test results must not exceed the allowable leakage rate (La) as specified in the TS. Option B also requires that a general visual inspection of the accessible interior and exterior surfaces of the containment system, for structural deterioration which may affect the containment leak-tight integrity, must be conducted prior to each Type A test and at a periodic interval between tests based on the performance of the containment system.

• Currently, HNP Unit 1 and Unit 2 TS 5.5.12, "Primary Containment Leakage Rate Testing Program" requires that leakage rate testing be performed as required by 10 CFR Part 50, Appendix J, Option B, as modified by approved exemptions.

The program is in accordance with the guidelines contained in NRC Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program" (Reference 6), September 1995, as modified by one approved exception to Nuclear Energy Institute (NEI) Topical Report 94-01, Revision 0, "Industry

Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J" (Reference 7).

• 10 CFR 50.55a, "Codes and Standards," contains the Containment In-Service Inspection (CISI) requirements that, in conjunction with the requirements of Appendix J, ensure the continued leak-tight and structural integrity of the containment during its service life.

• 10 CFR 50.65(a)(1 ), "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," states, in part, that the licensee, " ... shall monitor the performance or condition of structures, systems, or components

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

• NEI 94-01, Revision 2-A (Reference 8) and Revision 3-A (Reference 9) have been reviewed by the NRC and approved for use. The final Safety Evaluation (SE) for NEI 94-01, Revision 2, issued by letter dated June 25, 2008 (Reference 10), documents the NRC's evaluation and acceptance of this document subject to six specific limitations and conditions listed in Section 4.1 of the SE. The final SE of NEI 94-01, Revision 3, issued by letter dated June 8, 2012 (Reference 11 ),

includes two specific limitations and conditions listed in Section 4.0 of the SE.

NEI 94-01 Revisions 2-A and 3-A incorporate the corresponding NRC SEs.

• Section V.8.3 of 10 CFR 50, Appendix J, Option B, requires that the regulatory guide or other implementation document used by a licensee to develop a performance-based leakage testing program must be included, by general reference, in the plant TSs. The submittal for TS revisions must contain justification, including supporting analyses, if the licensee chooses to deviate from methods approved by the NRC and endorsed in a regulatory guide.

3.0 TECHNICAL EVALUATION

A Type A test is an overall lLRT of the primary containment structure. NEI 94-01, Revision O (Reference 7), specifies an initial test interval of 48 months, but allows an extended interval of 10 years based upon two consecutive successful tests. There is also a provision for extending the test interval an additional 15 months, but states in part, "should be used only in cases where refueling schedules have been changed to accommodate other factors."

Amendment Number 226 to Renewed Facility Operating License Number DPR-57 for HNP Unit 1 (Reference 17) allowed a one-time extension of the ILRT interval to 15 years. Similarly, Amendment Number 187 to Renewed Facility Operating License Number NPF-5 for HNP Unit 2 (Reference 18) allowed a one-time extension of the ILRT interval to 15 years. However, subsequent to these one-time extensions, the required ILRT test intervals for HNP Units 1 and 2 under TS 5.5.12 remained at 10 years.

In its submittal dated July 1, 2016, the licensee stated that the results of the two most recent HNP Unit 1 Type A tests performed in April 1993 and March 2008 are reflected in LAR

Table 3.2.4-1, "Unit 1 Type A ILRT History." Both Type A tests were successful in that the "As Found" test results were less than 1.0 La, as specified by the limiting value of HNP Unit 1 TS 5.5.12. Both peak calculated primary containment internal pressure (Pa) and La are defined in TS 5.5.12. For Unit 1, the peak calculated primary containment internal pressure for the design basis loss of coolant accident (DBLOCA), Pa, equals 50.8 psig and the maximum allowable primary containment leakage rate, La at Pa, equals 1.2 percent of primary containment air weight per day.

Similarly, the results of the two most recent HNP Unit 2 Type A tests performed in November 1995 and March 2009 are reflected in LAR Table 3.2.4-2, "Unit 2 Type A ILRT History." Both Type A tests were successful in that the "As Found" test results were less than 1.0 La, as specified by the limiting value of HNP Unit 2 TS 5.5.12. Both Pa and La are defined in HNP Unit 2 TS 5.5.12. For Unit 2, the peak calculated primary containment internal pressure for the DBLOCA, Pa equals 47.3 psig and the maximum allowable primary containment leakage rate, La at Pa, equals 1.2 percent of primary containment air weight per day.

3.1 Licensee's Proposed Changes SNC proposes to extend the HNP Unit 1 interval for the primary containment ILRT to 15 years from the last ILRT. The last HNP Unit 1 ILRT was completed during Refueling Outage RF23 in March 2008. The ILRT for HNP Unit 1 is currently required to be performed at a frequency of once every ten years. Therefore, the next HNP Unit 1 ILRT is due during March 2018. Using the proposed interval of 15 years, the next HNP Unit 1 ILRT would need to be completed before the end of March 2023.

Similarly, SNC proposes to extend the HNP Unit 2 interval for the primary containment ILRT to 15 years from the last ILRT. The last HNP Unit 2 ILRT was completed during Refueling Outage RF20 in March 2009. The ILRT for HNP Unit 2 is currently required to be performed at a frequency of once every ten years. Therefore, the next HNP Unit 2 ILRT is due during March 2019. Using the proposed interval of 15 years, the next HNP Unit 2 ILRT would need to be completed before the end of March 2024.

The HNP Unit 1 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," currently states, in part:

A program shall be established to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J":

Section 9.2.3: The first Type A test after the April 1993 Type A test shall be performed no later than April 2008.

The proposed amendment would delete the requirement associated with the Type A test performance that was to be completed no later than April 2008, and will revise HNP Unit 1 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," to state, in part:

A program shall be established to implement the leakage testing of the primary containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J,"

Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

The HNP Unit 2 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," currently states, in part:

A program shall be established to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J":

Section 9.2.3: The first Type A test after the November 2, 1995, Type A test shall be performed no later than November 2010.

The proposed amendment would delete the requirement associated with the Type A test performance that was to be completed no later than November 2010, and will revise HNP Unit 2 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," to state, in part:

A program shall be established to implement the leakage testing of the primary containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

3.2 NRC Staff Evaluation As indicated by LAR Table 3.2.4-1, "Unit 1 Type A ILRT History," the first Type A test conducted after the April 1993 ILRT was completed during HNP Unit 1 Refueling Outage RF23 in March 2008. Similarly, in Table 3.2.4-2, "Unit 2 Type A ILRT History," the first Type A test conducted after the November 1995 ILRT was completed during HNP Unit 2 Refueling Outage RF20 in March 2009. The NRC acknowledges that the aforementioned Type A ILRTs have been successfully completed, and, therefore, finds it acceptable to remove these specific references to the most recent tests in TS 5.5.12, "Primary Containment Leakage Rate Testing Program,"

for both HNP Unit 1 and Unit 2.

The proposed changes will also revise HNP Unit 1 and Unit 2 TS 5.5.12 by removing the reference to RG 1.163 (Reference 6) and NEI 94-01, Revision O (Reference 7). Subsequently, TS 5.5.12 will instead reference NEI 94-01, Revision 3-A (Reference 9), and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8), as the implementing documents used for the performance-based leakage testing program in accordance with Option B of 10 CFR Part 50, Appendix J. The NRC acknowledges that by referencing these two versions of

the NEI 94-01 technical reports, the licensee will be: 1) adopting the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, "Containment System Leakage Testing Requirements" (Reference 19); and 2) adopting a more conservative grace interval of 9 months for Type A, Type Band Type C leakage tests in accordance with NEI 94-01, Revision 3-A (Reference 9).

Consistent with the guidance contained in both NEI 94-01, Revision 2-A (Reference 8) and NEI 94-01, Revision 3-A (Reference 9), the licensee has provided a justification for the proposed changes by demonstrating successful performance of the HNP Unit 1 and Unit 2 containment leakage rate testing program. This justification is based on: (a) the historical plant-specific containment leakage testing program results; (b) the GISI program results; and (ca plant-specific risk assessment for HNP. The NRC staff's detailed evaluation of the licensee's justification is provided in the following subsections of this safety evaluation.

3.2.1 HNP Primary Containment Description The LAR provided a detailed description of the primary containment system for HNP, Unit 1 and Unit 2 (they are of similar design). The primary containment system houses the reactor pressure vessel, the reactor coolant recirculation system, and other branch connections of the reactor coolant system (RCS). The primary containment consists of the drywell, the suppression chamber that stores a large volume of water, a connecting vent system between the drywell and suppression chamber, isolation valves, a vacuum relief system, containment cooling systems, and other service equipment.

The drywell is a steel pressure vessel in the shape of an inverted light bulb, and the suppression chamber is a torus-shaped steel pressure vessel located below and encircling the drywell.

The primary containment system is designed to withstand the pressures resulting from a breach of the nuclear system process piping up to and including an instantaneous circumferential break of the reactor recirculation piping. The primary containment system provides a holdup for the decay of any released radioactive material, and stores sufficient water to condense the steam released as a result of a breach in the nuclear system process barrier and to serve as a water supply for the emergency core cooling system (ECCS).

The primary containment system free volume is filled with a nitrogen atmosphere during normal operation. The containment atmospheric control system is capable of reducing and maintaining the oxygen content of the atmosphere below 4 percent during normal operation.

3.2.2 Historical Type A Test {ILRT) Results Unit 1 Type A Test Results Per TS 5.5.12, the HNP Unit 1 containment was designed for a maximum allowable containment leakage rate La of 1.2 percent by weight of primary containment air per day at the calculated peak pressure, Pa. The calculated peak primary containment internal pressure for the design basis loss of coolant accident (DBLOCA), Pa, is 50.8 psig.

Since 1978, a total of six ILRTs of the HNP Unit 1 primary containment have been performed with satisfactory "As Found" results. The results of the ILRTs were provided in LAR Table 3.2.4-1, "Unit 1 Type A ILRT History." The NRC staff requested additional information

associated with these tests in a letter dated February 10, 2017 (Reference 3) and has summarized its findings in the following table:

TABLE 3.2.2-1 Edwin I. Hatch Nuclear Plant Unit 1 Type A ILRT History Date Test Pa Upper Correction Total Acceptance Pressure On the Confidence for Type B & Leakage Criteria(6l, La during Date of Limit C Tests (%weight (%weight/

"As ILRT Measured (%weight/ /day) day)

Found" (psig) Leakage(1) day)

ILRT (%weight (psig) /day)

June 1978 (4) (4) (4) (4) 0.456(7 ) 1.2 Feb. 1983 (4) (4) (4) (4) 0.442(7 ) 1.2 April 1986 (4) (4) (4) (4) 0.428(7 ) 1.2 Nov. 1988 (4) (4) (4) (4) 0.4968(7 ) 1.2 April 1993 59.0732(5) 60.0(5) 0.3608( 1) 0.3857( 2) 0.7465(3) 1.2 March 2008 52.243( 5) 50.8( 5) 0.3401( 1) 0.4157(2) 0.7558(3 ) 1.2 Table 3.2.2-1 Notes:

1

( ) BN-TOP-1 Upper Confidence Limit (UCL) - Reference 3.

2

( ) Sum of: MNPLR + penetration minimum pathway improvements made during the local leak rate test {LLRT) program prior to the Type A test + H20 Level Correction -

Reference 3.

3

( ) Performance Leakage Rate (PLR) as defined by NEI 94-01 Revision 3-A, Sections 5.0 and 9.2.3 - Reference 3.

4

( ) Not Available as not provided in the LAR.

(5) Reference 3.

5

( ) Per Technical Specification 5.5.12.

7

( ) Leakage rate value from LAR Table 3.2.4-1.

Guidance in NEI 94-01, Section 9.2.3 "Extended Test Intervals" states, in part:

In the event where previous Type A tests were performed at reduced pressure (as described in 10 CFR 50, Appendix J, Option A), at least one of the two consecutive periodic Type A tests shall be performed at peak accident pressure (Pa).

As noted in Table 3.2.2-1, the last two HNP Unit 1 Type A tests were performed in April 1993 and March 2008 at test pressures of 59.07 psig and 52.24 psig, respectively. The NRC staff acknowledges that at least one of the previous two ILRT test pressures satisfied the Pa value of 50.8 psig as required by Section 9.2.3 of NEI 94-01, Revision 2-A (Reference 8).

By letter dated February 1O, 2017 (Reference 3), the licensee responded to the NRC staff's request for a detailed breakdown of the last two ILRT results performed in April 1993 and March 2008, to enable the staff to determine whether these results complied with the definition of

"performance leakage rate (PLR)" as defined in Section 5.0 of NEI 94-01, Revision 3-A (Reference 9). The definition of PLR is provided as follows:

The performance leakage rate is calculated as the sum of the Type A upper confidence limit (UCL) and as-left minimum pathway leakage rate (MNPLR) leakage rate for all Type B and Type C pathways that were in service, isolated, or not lined up in their test position (i.e., drained and vented to containment atmosphere) prior to performing the Type A test. In addition, leakage pathways that were isolated during performance of the test because of excessive leakage must be factored into the performance determination. The performance criterion for Type A tests is a performance leak rate of less than 1.0 La.

In its response to this request, the licensee provided a comprehensive breakdown of both the 1993 and 2008 Type A test results that demonstrated compliance with the NEI 94-01, Revision 3-A, definition of PLR. The details are reflected in the data contained in Table 3.2.2-1 and its footnotes.

The HNP Unit 1 TS 5.5.12.a. establishes a leakage rate acceptance criterion of:::: 0. 75 La for the first startup following Type A testing in accordance with this program. This value equals 0.9 percent of primary containment air weight per day.

The primary containment was designed for a leakage rate La not to exceed 1.2 percent by weight of primary containment air per day at the calculated peak pressure, Pa. As displayed in Table 3.2.2-1, there has been adequate margin to the "As found" performance limit of 1.2 percent weight/day for all historical HNP Unit 1 ILRTs.

Past ILRT results have confirmed that the containment leakage rates are acceptable with respect to the design criterion of 1.2 percent leakage of primary containment air weight (La) per day at the DBLOCA pressure (Pa). Since the last two Type A tests for HNP Unit 1 had "as found" test results of less than 1.0 La. a test frequency of 15 years in accordance with NEI 94-01 Revision 3-A and the conditions and limitations of NEI 94-01, Revision 2-A, is acceptable for HNP Unit 1.

Unit 2 Type A Test Results Per TS 5.5.12, the HNP Unit 2 containment was designed for a maximum allowable containment leakage rate La of 1.2 percent by weight of primary containment air per day at the calculated peak pressure, Pa. The calculated peak primary containment internal pressure for the DBLOCA, Pa, is 47.3 psig.

Since 1982, a total of six ILRTs of the primary containment have been performed with satisfactory "As Found" results at HNP Unit 2. The results of the ILRTs were provided in LAR Table 3.2.4-2, "Unit 2 Type A ILRT History." The licensee responded to the NRC staff's request for additional information associated with these tests in a letter dated February 10, 2017 (Reference 3). The NRC staff summarized its findings for HNP Unit 2 in the following table:

TABLE 3.2.2-2 Edwin I. Hatch Nuclear Plant Unit 2 Type A ILRT History Date Test Pa Upper Correction Total Acceptance Pressure On the Confidence for Type B & Leakage Criteria(6l, La during Date of Limit C Tests (%weight (%weight/

"As ILRT Measured {%weight/ /day) day)

Found" (psig) Leakage(1) day)

ILRT (%weight (psig) /day)

May 1982 (4) (4) (4) (4) 0.7890(7) 1.2 Jan. 1986 (4) (4) (4) (4) 0.5870( 7 ) 1.2 Nov. 1989 (4) (4) (4) (4) 0.8000(7 ) 1.2 Nov. 1992 (4) (4) (4) (4) 0.8839(7 ) 1.2 Nov. 1995 46.3168( 5) 45_5( 5) 0.3145( 1) 0.3562(2) 0.6707(3) 1.2 March 2009 47_957( 5) 47_3( 5) 0.2183( 1) 0.3239( 2) 0.5422(3) 1.2 Table 3.2.2-2 Notes:

1

( l BN-TOP-1 Upper Confidence Limit (UCL) - Reference 3 2

( ) Sum of: MNPLR + penetration minimum pathway improvements made during the LLRT program prior to the Type A test + H20 Level Correction - Reference 3 3

( ) Performance Leakage Rate {PLR) as defined by NEI 94-01 Revision 3-A, Sections 5.0 and 9.2.3 - Reference 3 4

( ) Not Available as not provided in the LAR (5 ) Reference 3 5

( ) Per Technical Specification 5.5.12 7

( ) Leakage rate value from LAR Table 3.2.4-1 Guidance in NEI 94-01, Section 9.2.3 "Extended Test Intervals" states, in part, In the event where previous Type A tests were performed at reduced pressure (as described in 10 CFR 50, Appendix J, Option A), at least one of the two consecutive periodic Type A tests shall be performed at peak accident pressure (Pa).

As noted in Table 3.2.2-2, the last two HNP Unit 2 Type A tests were performed in November 1995 and March 2009 at test pressures of 46.32 psig and 47.96 psig, respectively.

The staff acknowledges that at least one of the previous two ILRT test pressures satisfied the Pa value of 47.3 psig, as required by Section 9.2.3 of NEI 94-01, Revision 2-A (Reference 8).

Per letter dated February 10, 2017 (Reference 3), the NRC staff requested a detailed breakdown of the results of the last two ILRTs performed in November 1995 and March 2009 to determine whether these results complied with the definition of "performance leakage rate (PLR)" as defined in Section 5.0 of NEI 94-01, Revision 3-A (Reference 9). The definition of PLR is provided as follows:

The performance leakage rate is calculated as the sum of the Type A upper confidence limit (UCL) and as-left minimum pathway leakage rate (MNPLR)

leakage rate for all Type B and Type C pathways that were in service, isolated, or not lined up in their test position (i.e., drained and vented to containment atmosphere) prior to performing the Type A test. In addition, leakage pathways that were isolated during performance of the test because of excessive leakage must be factored into the performance determination. The performance criterion for Type A tests is a performance leak rate of less than 1.0 La.

In response to this request, the licensee provided a comprehensive breakdown of both the 1995 and 2009 Type A test results that demonstrated compliance with the NEI 94-01, Revision 3-A, definition of PLR. The details are reflected in the data contained in Table 3.2.2-2 and its footnotes.

The HNP Unit 2 TS 5.5.12.a. establishes a leakage rate acceptance criterion of::; 0.75 La for the first startup following Type A testing in accordance with this program. This value equals 0.9 percent of primary containment air weight per day.

The primary containment was designed for a leakage rate La not to exceed 1.2 percent by weight of primary containment air per day at the calculated peak pressure, Pa. As displayed in Table 3.2.2-2, there has been adequate margin to the "As found" performance limit as described in TS 5.5.12 of La equal to 1.2 percent weighVday for all historical ILRTs.

Past ILRT results have confirmed that the containment leakage rates are acceptable with respect to the design criterion of 1.2 percent leakage of primary containment air weight {La) per day at the DBLOCA pressure (Pa). Since the last two Type A tests for HNP Unit 2 had "as found" test results of less than 1.0 La. a test frequency of 15 years in accordance with NEI 94-01 Revision 3-A and the conditions and limitations of NEI 94-01, Revision 2-A, is acceptable for HNP Unit 2.

3.2.3 Historical Type Band Type C Test (Local Leak Rate Test (LLRT)) Results Unit 1 Type Band Type C Test Results HNP Unit 1 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," states, in part:

Leakage Rate acceptance criteria are:

a. Primary containment overall leakage rate acceptance criterion is ::; 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are::; 0.60 La for the combined Type Band Type C tests, and

0. 75 La for Type A tests; In LAA Section 3.4.4, "Primary Containment Leakage Rate Testing Program - Type Band Type C Testing Program," along with LAA Table 3.4.4-1, "Unit 1 Type Band C LLRT Combined As-Found/As-Left Trend Summary," the licensee describes the margin between the "As-Found" and "As-Left" outage summations. Furthermore, the licensee states that the value of La equals approximately 272,320 standard cubic centimeters per minute (seem) for Unit 1.

The NRC staff confirmed the accuracy of the "Fraction of La" values contained in this Table, and verified that:

• The HNP Unit 1 "As-Found" minimum pathway leakage rates (MNPLRs) for the last five refueling outages since 2008 have an average of 18.1 percent of La with a high of

43. 74 percent La.

• The HNP Unit 1 "As-Left" maximum pathway leakage rates for the last five refueling outages since 2008 have an average of 12.2 percent of La with a high of 14.13 percent La.

The NRC staff inquired about the percentages of Type B and Type C components that are currently on the maximum permissible test interval of 120 months and 60 months, respectively, as allowed by RG 1.163 (Reference 6) and NEI 94-01, Revision O (Reference 7). In its response dated February 10, 2017 (Reference 3), the licensee indicated that:

• Unit 1 has a total population of 143 Type B tested penetrations. Of these 143 penetrations, 71 percent are on a 120-month extended performance-based test inte.rval.

• Unit 1 has a total population of 124 Type C tested containment isolation valves (CIVs).

Of these 124 CIVs, 53 percent are on a 60-month extended performance-based test interval.

The LAR Table 3.4.5-1, "Unit 1 Type Band C LLRT Program Implementation Review," identified components on extended intervals that had not demonstrated acceptable performance during the previous two Unit 1 refueling outages. Per Reference 3, the NRC staff requested further information to (1) clarify the causes of the Unit 1 LLRT failures associated with Penetrations 221A and 26; and (2) identify historical examples of Unit 1 repetitive failures of "Administrative Limits" for LLRTs associated with Type B or Type C penetrations over the last ten years. Upon review of that information, the NRC staff confirmed that the licensee has effective preventative maintenance and corrective action programs to address components with unacceptable performance.

The NRC staff concludes that the aggregate results of the "As-Left Max Path" for all Unit 1 Type B and C tests from 2008 through 2016 demonstrate a history of adequate refueling outage maintenance and confirm that an extended test interval of up to 75 months for Unit 1 Type C containment isolation valves is justified.

Unit 2 Type Band Type C Test Results The HNP Unit 2 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," states, in part:

Leakage Rate acceptance criteria are:

b. Primary containment overall leakage rate acceptance criterion is s 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are s 0.60 La for the combined Type B and Type C tests, and :S

0. 75 La for Type A tests; In LAR Section 3.4.4, "Primary Containment Leakage Rate Testing Program - Type Band Type C Testing Program," along with Table 3.4.4-2 "Unit 2 Type B and C LLRT Combined

.As-Found/As-Left Trend Summary", the licensee describes the margin between the "As-Found"

and "As-Left" outage summations. Furthermore, the licensee states that the value of La equals approximately 254,937 seem for Unit 2.

The NRC staff confirmed the accuracy of the "Fraction of La" values contained in this Table, and verified that:

• The HNP Unit 2 "As-Found" MNPLRs for four of the last five refueling outages since 2007 (i.e. exclusive of the "AF Min Path" failure of 2RF21) have an average of 40.4 percent of La with a high of 54.03 percent La.

• The HNP Unit 2 "As-Left" maximum pathway leakage rates for the last five refueling outages since 2007 have an average of 25.3 percent of La with a high of 50.43 percent La.

The NRC staff inquired about the percentages of Type B and Type C components that are currently on the maximum permissible test interval of 120 months and 60 months, respectively, as allowed by RG 1.163 (Reference 6) and NEI 94-01, Revision O (Reference 7). In its response dated February 10, 2017 (Reference 3), the licensee indicated that:

• Unit 2 has a total population of 149 Type B tested penetrations. Of these 149 penetrations, 79 percent are on a 120-month extended performance-based test interval.

• Unit 2 has a total population of 133 Type C tested CIVs. Of these 133 CIVs, 57 percent are on a 60-month extended performance-based test interval.

The LAR Table 3.4.5-2, "Unit 2 Type Band C LLRT Program Implementation Review," identified components on extended intervals that had not demonstrated acceptable performance during the previous two Unit 2 refueling outages. Per Reference 3, the NRC staff requested further information to (1) clarify the causes of the Unit 2 LLRT failures associated with Penetrations 41, 26 and 225K; and (2) identify historical examples of Unit 2 repetitive failures of "Administrative Limits" for LLRTs associated with Type B or Type C penetrations over the last ten years. Upon review of that information, the staff confirmed that the licensee has effective preventative maintenance and corrective action programs to address components with unacceptable performance.

The NRC staff concludes that the aggregate results of the "As-Left Max Path" for all Unit 2 Type B and C tests from 2007 through 2015 demonstrate a history of adequate refueling outage maintenance and confirm that an extended test interval of up to 75 months for Unit 2 Type C containment isolation valves is justified.

3.2.4 Containment In-Service Inspection Program (CISI)

The HNP Unit 1 and Unit 2 primary containment systems house the reactor pressure vessel, and other important systems, and consist of the drywell (a steel pressure vessel), the suppression chamber (a torus-shaped steel pressure vessel), a connecting vent system, isolation valves, and other service equipment. The drywell is enclosed in a reinforced concrete structure for shielding purposes and is designed, fabricated, inspected and tested to the requirements of American Society of Mechanical Engineers (ASME) Section Ill, Subsection NB.

Containment inspection activities are also performed in accordance with TS SR 3.6.1.1.1 and the Protective Coatings program.

In LAR Section 3.4.2, the licensee provided the description of the HNP GISI Program for Units 1 and 2. The inspection plan provides a summary of the examinations and tests applicable to components treated as Class MC for inservice inspection (ISi) and include the drywell, the suppression pool (torus), the vent headers, penetrations, airlocks and manways. The Containment Inspection Program is comprised of existing plant programs and procedures which provide a complete and comprehensive program for examination of the pressure retaining surfaces of containment structures that are a part of reinforcement and any associated permanent attachments.

Examination results for both HNP Units 1 and 2 suppression pool shells indicated some coating degradation, and shell pit measurements were taken to determine the maximum degradation rate. The LAR stated that to date, there has been no significant degradation of the submerged area of the suppression pool shell and the current degradation rate is very slow. During the 1990 and 1991 refueling outages, a visual inspection was performed by divers in the submerged areas with local repairs performed whenever general corrosion exceeded established acceptance criteria. The LAR also stated that in no case was any degradation observed which infringed upon the minimum wall thickness requirements of the torus. The licensee concluded that based on evaluation of the results from all previous examinations, there is currently no indication of any degradation concerns which impact the wall thickness or structural integrity of the torus of HNP Unit 1 or Unit 2.

The licensee stated that the current 10-year inspection interval began on January 1, 2016 and ends on December 31, 2025. The selection, planning, and scheduling of ISi examinations and tests will comply with Section XI of the 2007 Edition, 2008 Addenda of the ASME Code, or applicable NRG approved alternatives that are specified in the HNP ISi and GISI program plans.

The design, operation, testing methods and acceptance criteria for Type A containment leakage tests specified in applicable codes and standards would continue to be met with the acceptance of the proposed change, since these are not affected by changes to the Type A test intervals.

The licensee also employs several Aging Management Programs at HNP developed as part of the process of obtaining renewed operating licenses for both Units 1 and 2, which were issued by the NRG on January 15, 2002. HNP has multiple inspection and testing programs that ensure the containment structure remains capable of meeting its design functions and that are designed to identify any degrading conditions that might affect that capability. One such program is the Protective Coatings Program (PCP), which provides a means of preventing or minimizing loss of material that would otherwise result from contact of the base material with a corrosive environment, and includes inspection of protective coatings on selected components and structures. The PCP is a mitigation and condition monitoring program designed to provide base metal aging management through surface application, maintenance, and inspection of protective coatings on selected components and structures.

Coating Service Level I is a designation for those coating systems applied inside the primary containment where coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown of the plant. The Primary Containment Leakage Rate Testing program is designed to ensure that primary containment leakage does not exceed TS limits in addition to maintaining the integrity of the containment structure. Lastly, the HNP ISi program is a condition monitoring program that provides for the implementation of ASME Section XI in accordance with the provisions of 10 CFR 50.55a. The 10-year examination plan provides a systematic guide for performing required examinations.

Section 12.2.1, "Reactor Building," of the HNP Unit 1 FSAR states that the foundation of the reactor building consists of a reinforced concrete mat which supports the primary containment and its internals. The reactor building, a reinforced concrete structure, provides secondary containment for the reactor, and primary containment for auxiliary systems. Furthermore, Section 18.3.5, "Structural Monitoring Program," (SMP) of the HNP Unit 2 FSAR states that the SMP complies with the Maintenance Rule (10 CFR 50.65) and the License Renewal Rule (10 CFR Part 54) and utilizes visual inspections in managing aging effects for concrete and grout in accessible areas. Concrete structures are inspected for cracks, leaching, spalling and corrosion staining, as evidence of loss of material and cracking. Steel components are inspected for general and localized corrosion as evidence of loss of material. Panel joints and seals are inspected for evidence of loss of adhesion and changes in material properties, and piping is inspected for leakage. Secondary containment leakage characteristics are verified in accordance with SR 3.6.4.1.4 of the HNP TS.

The inspection process assesses the overall conditions of the buildings and structures, identifies any ongoing degradation, and manages loss of material, cracking and changes in material properties including loss of adhesion. The SMP requires inspection of plant structural features in the scope of the Maintenance Rule on a 4-year frequency. The enhanced scope of the SMP monitors those portions of the reactor building and other structures, components and commodities that are within the scope of license renewal and patterned after the Westinghouse Owners Group Life Cycle Management/License Renewal Program. This encompasses reinforced concrete throughout the plant, including the reactor building bottom floor slab and reactor pedestal.

Based on the results of the HNP recent ASME Code IWE inspections and concrete component inspections discussed above, the NRC staff finds that there has not been evidence to date of significant degradation of the HNP Units 1 and 2 primary containments. Therefore, the NRC staff concludes that there is reasonable assurance that the licensee is adequately implementing the CISI program for HNP Units 1 and 2 to monitor and manage age-related degradation of the primary containments.

3.2.5 Evaluation of the Conditions and Limitations of NEI 94 01, Revisions 2-A and 3-A As required by 10 CFR 50.54(0), both HNP Unit 1 and Unit 2 primary containments are subject to the requirements set forth in 10 CFR Part 50, Appendix J. Option 8, "Performance-Based Requirements," of Appendix J requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach. Currently, both HNP units invoke RG 1.163 (Reference 6) with reference to NEI 94-01, Revision O (Reference 7), as the plan implementing documents. The LAR proposes to revise both programs by replacing the current implementing documents with the guidance contained in NEI 94-01 Revision 3-A (Reference 9) and the conditions and limitations of NEI 94-01, Revision 2-A (Reference 8).

In accordance with the guidance in NEI 94-01, Revision 2-A, the licensee proposes to extend the containment Type A test interval from the current approved 10 years to 15 years, based on acceptable performance. In accordance with the guidance in NEI 94-01, Revision 3-A, the licensee proposes to extend the containment Type C test interval from the current approved 60 months to 75 months, with a permissible extension period of 9 months (total of 84 months) for non-routine emergent conditions, based on acceptable performance. The NRC staff's evaluation of the proposed LAR with respect to the limitations and conditions in NEI 94-01, Revision 2-A and Revision 3-A, is discussed below.

3.2.5.1 NRC Conditions in NEI 94-01, Revision 2-A In Section 4.1 of the NRC staff's safety evaluation incorporated in topical report NEI 94-01, Revision 2-A (Reference 8), the staff concludes that the guidance in the topical report is acceptable for reference by licensees proposing to amend their TSs to permanently extend the ILRT surveillance interval to 15 years, provided that six conditions are satisfied. The NRC staff evaluated whether the licensee addressed and satisfied these conditions as discussed below.

a. NRC Condition 1 NRC Condition 1 states: "For calculating the Type A leakage rate, the licensee should use the definition [for performance leakage rate] in the NEI [Topical Report] TR 94-01, Revision 2, in lieu of that in ANSI/ANS-56.8-2002 [Reference 19]. (Refer to SE Section 3.1.1.1.)"

In Table 3.7.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," of its letter dated July 1, 2016 (Reference 1), the licensee states:

HNP will utilize the definition in NEI 94-01, Revision 3-A, Section 5.0. This definition has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

The NRC staff reviewed the definitions for performance leakage rate contained in NEI 94-01, Revision 2-A and Revision 3-A, and concluded that the definitions contained in both revisions are identical. Therefore, the NRC staff finds that the licensee has addressed and satisfied NRC Condition 1.

b. NRC Condition 2 NRC Condition 2 states: "The licensee submits a schedule of containment inspections to be performed prior to and between Type A tests. (Refer to SE Section 3.1.1.3.)"

In Table 3. 7.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," of its letter dated July 1, 2016 (Reference 1), the licensee states:

Reference Tables 3.4.2-2 and 3.4.2-3 of this submittal.

The following is the applicable guidance for satisfying NRC Condition 2.

Section 3.1.1.3 of the NRC staff's SE of NEI TR 94-01, Revision 2A, states, in part:

To provide continuing supplemental means of identifying potential containment degradation, a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity must be conducted prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years.

NEI TR 94-01, Revision 2, recommends that these inspections be performed in conjunction or coordinated with the examinations required by ASME Code,Section XI, Subsections IWE and IWL. The NRC staff finds that these visual examination provisions, which are consistent with the provisions of Regulatory Position C.3 of RG 1.163, are acceptable, considering the longer 15 year interval.

Regulatory Position C.3 of RG 1.163 recommends that such examination be performed at least two more times in the period of 10 years. The NRC staff agrees that as the Type A test interval is changed to 15 years, the schedule of visual inspections should also be revised. Section 9.2.3.2 in NEI TR 94-01, Revision 2, addresses the supplemental inspection requirements, which have been found acceptable by the NRC staff.

NEI 94-01, Revision 3-A, Section 9.2.1, "Pretest Inspection and Test Methodology,"

reads in part:

Prior to initiating a Type A test, a visual examination shall be conducted of accessible interior and exterior surfaces of the containment system for structural problems that may affect either the containment structure leakage integrity or the performance of the Type A test. This inspection should be a general visual inspection of accessible interior and exterior surfaces of the primary containment and components. It is recommended that these inspections be performed in conjunction or coordinated with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE/IWL required examinations.

NEI 94-01, Revision 3-A, Section 9.2.3.2, "Supplemental Inspection Requirements,"

states:

To provide continuing supplemental means of identifying potential containment degradation, a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity must be conducted prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years. It is recommended that these inspections be performed in conjunction or coordinated with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE/IWL required examinations.

In the LAR (Reference 1), Section 3.4.2, "lnservice Inspection Program (ISi)," the licensee provides its position with respect to meeting the requirements of Section XI, Table IWE-2500-1, "Examination Categories," Item E1 .11, "Accessible Surface Areas."

Specifically, the section titled, "Item E1 .11 Examination Position," states:

A General Visual Examination of the accessible containment surfaces is required once each inspection period and prior to each Type A test. The General Visual Examination includes the following areas.

• Accessible surfaces of the interior of the drywell shell above the 114-foot floor elevation.

• Interior and exterior surfaces of the drywell head.

• Accessible interior and exterior surfaces of drywell penetrations.

• Accessible interior and exterior surfaces of the drywell to torus vent lines.

• Accessible interior and exterior surfaces of the torus vent header and downcomers.

• Accessible exterior surfaces of the torus shell and torus supports.

• Accessible interior surfaces of the torus shell above the water level.

The exterior drywell shell surface is exempt from examination per IWE-1220(b) and IWE-1232(a).

The requirements of IWE-1231(a)(3) are satisfied (i.e., at least 80% of the accessible surface area can be examined either directly or remotely) by performing examination from existing catwalks, walkways, ladders, floor elevations and adjacent structures of the drywell shell, drywell head, drywell to torus vent lines, vent header and downcomers, containment penetrations, the interior torus shell above the water level, and the torus exterior shell surfaces."

LAR Table 3.4.2-2, "HNP Unit 1 IWE Examination Schedule," and Table 3.4.2-3, "HNP Unit 2 IWE Examination Schedule," indicate that HNP Unit 1 and Unit 2 are currently in the 1st Period of their respective 5th Intervals as defined by the ASME Code.

For Unit 1, the 1st Period of the 5th Interval runs for three years, from January 1, 2016 through December 31, 2018. The NRC staff notes that the last HNP Unit 1 Type A test was performed in March 2008. The prior 10-year Interval ended on December 31, 2015 and would have had at least one Item E1 .11 Evaluation (General Visual Examination) completed in two different Periods since March 2008. Therefore, it is projected that the refueling outage schedule for HNP Unit 1 will accommodate the increased General Visual Examination requirements for the containment as specified in Sections 9.2.1 and 9.2.3 of NEI 94-01, Revision 3-A.

For Unit 2, the 1st Period of the 5th Interval runs for four years, from January 1, 2016 through December 31, 2019. The NRC staff notes that the last Unit 2 Type A test was performed in March 2009. The prior 10-year Interval ended on December 31, 2015 and would have had at least one Item E1 .11 Evaluation (General Visual Examination) completed in two different Periods since March 2009. Therefore, it is projected that the refueling outage schedule for HNP Unit 2 will accommodate the increased General Visual Examination requirements for the containment as specified in Sections 9.2.1 and 9.2.3 of NEI 94-01, Revision 3-A.

Based these two projections for HNP Unit 1 and Unit 2, the NRC staff concludes that the licensee intends to comply with the guidance contained in NEI 94-01, Revision 3-A, Sections 9.2.1 and 9.2.3.2, and that HNP satisfies the provisions contained in Section 3.1.1.3 of the NRC staff's SE of NEI TR 94-01, Revision 2A.

Therefore, the NRC staff finds that the licensee has addressed and satisfied NRC Condition 2.

c. NRC Condition 3 NRC Condition 3 states: "The licensee addresses the areas of the containment structure potentially subjected to degradation. (Refer to SE Section 3.1.3.)

[Reference 8]"

In Table 3.7.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," of its letter dated July 1, 2016 (Reference 1), the licensee states:

Reference Sections 3.4.2 and 3.5 of this submittal.

The following is the applicable guidance for satisfying NRC Condition 3.

NRC Staff's SE of NEI 94-01, Revision 2-A, Section 3.1.3 states, in part:

In approving for Type A tests the one-time extension from 10 years to 15 years, the NRC staff has identified areas that need to be specifically addressed during the IWE and IWL inspections including a number of containment pressure-retaining boundary components (e.g., seals and gaskets of mechanical and electrical penetrations, bolting, penetration bellows) and a number of the accessible and inaccessible areas of the containment structures (e.g., moisture barriers, steel shells, and liners backed by concrete, inaccessible areas of ice condenser containments that are potentially subject to corrosion).

General visual examinations of the accessible surfaces of primary containment are performed to assess the general condition of the primary containment surfaces and are performed as part of the HNP Unit 1 and Unit 2 Containment lnservice Inspection Program. This program is based on Subsection IWE of Section XI of the ASME Code and is applicable to the containment vessel.

LAR Section 3.4.2, "lnservice Inspection Program (ISi)" (Reference 1) provides details on examination types performed in different areas and components that specifically address IWE inspections to satisfy the requirements of Section 3.1.3 of the NRC staff's SE for NEI 94-01, Revision 2-A. The NRC staff also reviewed LAR Section 3.5, "Operating Experience."

The NRC staff concludes that, based on the information contained in LAR Sections 3.4.2 and 3.5, the licensee has established its intent to satisfy the issues described in Section 3.1.3 of the NRC staff's SE for NEI 94-01, Revision 2-A, and finds that the licensee has addressed and satisfied N RC Condition 3.

d. NRC Condition 4 NRC Condition 4 states: "The licensee addresses any tests and inspections performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4.) [Reference 8]"

In Table 3.7.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," of its letter dated July 1, 2016 (Reference 1), the licensee states:

There are no major modifications planned.

The following is the applicable guidance for satisfying NRC Condition 4.

NRC Staff SE of NEI 94-01, Revision 2-A, Section 3.1.4 states, in part:

Section 9.2.4 of NEI TR 94-01, Revision 2, states that: "Repairs and modifications that affect the containment leakage integrity require LLRT or short duration structural tests as appropriate to provide assurance of containment integrity following the modification or repair. This testing shall be performed prior to returning the containment to operation." Article IWE-5000 of the ASME Code,Section XI, Subsection IWE (up to the 2001 Edition and the 2003 Addenda), would require a Type A test after major repair or modifications to the containment. In general, the NRC staff considers the cutting of a large hole in the containment for replacement of steam generators or reactor vessel heads, replacement of large penetrations, as major repair or modifications to the containment structure.

The NRC staff notes that HNP Unit 1 and Unit 2 containments have both been in service for greater than 35 years. By letter dated February 10, 2017 (Reference 3), NRC staff requested that the licensee provide a history of any modifications made to the Unit 1 and Unit 2 containment structures since the most recent ILRTs, and a synopsis of the subsequent post-modification testing performed.

The licensee responded that HNP has not made any modifications to the primary containments since the last ILRT performance on either unit.

Accordingly, the NRC staff reviewed the licensee's response and concluded that no HNP major containment modifications have taken place since the ILRTs of March 2008 for Unit 1 and March 2009 for Unit 2. Furthermore, there are no plans for major modifications to the containment structures of either unit. The NRC staff concludes that the licensee has adequately addressed the issues described in SE Section 3.1.4, and therefore, finds that the licensee has addressed and satisfied NRC Condition 4.

e. NRC Condition 5 NRC Condition 5 states: "The normal Type A test interval should be less than 15 years. If a licensee has to utilize the provision of Section 9.1 of NEI TR 94-01, Revision 2, related to extending the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition.

(Refer to SE Section 3.1.1.2.) [Reference 8]"

In Table 3.7.1-1, "NEI 94-01, Revision 2-A, Limitations and Conditions," of its letter dated July 1, 2016 (Reference 1), the licensee states:

HNP will follow the requirements of NEI 94-01 Revision 3-A, Section 9.1.

This requirement has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01. In accordance with the requirements of NEI 94-01 Revision 2-A, [safety evaluation report] SER Section 3.1.1.2, HNP will also demonstrate to the NRC staff that an unforeseen emergent

condition exists in the event an extension beyond the 15-year interval is required.

The following is the applicable guidance for satisfying NRC Condition 5.

The NRC staff SE of NEI 94-01, Revision 2-A, Section 3.1.1.2, states:

As noted above, Section 9.2.3, NEI TR 94-01, Revision 2, states, Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history." However, Section 9.1 states that the "required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes." The NRC staff believes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons. Therefore, if a licensee wants to use the provisions of Section 9.1 in TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists.

In LAA Section 3.2.1, "Chronology of Testing Requirements of 10 CFR 50, Appendix J,"

the licensee adopted the staff position by invoking the above words from NRC SER Section 3.1.1.2 of NEI 94-01, Revision 2-A. The NRC staff also notes that SNC states in Reference 1, in part:

HNP will also demonstrate to the NRC staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.

Therefore, the NRC staff confirms that the licensee has stated its understanding that any extension of the Type A test interval beyond the upper-bound performance-based limit of 15 years should be infrequent, and that in the event the licensee needs such an extension, it will demonstrate to the NRC staff that an unforeseen emergent condition exists.

Based on the above review, the NRC staff finds that the licensee has addressed and satisfied NRC Condition 5.

f. NRC Condition 6 NRC Condition 6 states: "For plants licensed under 10 CFR Part 52, applications requesting a permanent extension of the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI TR 94-01, Revision 2, and EPRI [Electric Power Research Institute] Report No. 1009325, Revision 2, including the use of past containment ILRT data."

This condition is not applicable to HNP Units 1 and 2, since they were not licensed under 10 CFR Part 52.

Based on the above evaluation of each condition, the NRC staff determined that the licensee has adequately addressed the six conditions identified in Section 4.1 of the NRC SE of NEI 94-01, Revision 2-A. Therefore, the NRC staff finds it acceptable for the licensee to adopt the "Conditions and Limitations" of NEI 94-01, Revision 2-A, as part of the implementation documents in TS 5.5.12, "Primary Containment Leakage Rate Testing Program," for both HNP Unit 1 and Unit 2.

3.2.5.2 NRC Conditions in NEI 94-01, Revision 3-A In Section 4.0 of the NRC staff's safety evaluation incorporated in topical report NEI 94-01, Revision 3-A (Reference 9), the staff concludes that the guidance in the topical report is acceptable for reference by licensees in the implementation for the optional performance-based requirements of Option B to 10 CFR Part 50, Appendix J, provided that two conditions are satisfied. The NRC staff evaluated whether the licensee addressed and satisfied these two conditions as discussed below.

a. NRC Condition 1 NRC Condition 1 states, in part: "The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g. BWR MSIVs [boiling-water reactor main steam isolation valves]), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval.

Only non-routine emergent conditions allow an extension to 84 months."

In LAR Section 3.7.2, "Limitations and Conditions Applicable to NEI 94-01, Revision 3-A," the licensee provides the following response to the requirements of Condition 1:

• The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La.

• When the potential leakage understatement adjusted Type B and C MNPLR total is greater than the HNP leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the HNP leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues so as to maintain an acceptable level of margin.

• HNP will apply the 9-month grace period only to eligible Type C components and only for non-routine emergent conditions. Such occurrences will be documented in the record of tests.

The NRC staff has reviewed the requirements of NEI TR 94-01, Revision 3, against the SNC responses for Condition 1. Based on this review, the NRC staff concludes that SNC acknowledges all the requirements of Condition 1 and has established its intent for HNP to comply with these requirements.

b. NRC Condition 2 NRC Condition 2 states, in part: "When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Type B & C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations."

In LAR Section 3. 7 .2, "Limitations and Conditions Applicable to NEI 94-01, Revision 3-A," the licensee provides the following in response to the requirements of Condition 2:

• The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3A, represents an increase of 25 percent in the LLRT periodicity. As such, HNP will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the actual As-Left leak rate, which will increase the As-Left leakage total for each Type C component currently on greater than a 60-month test interval up to the 75-month extended test interval. This will result in a combined conservative Type C total for all 75-month LLRT's being "carried forward" and will be included whenever the total leakage summation is required to be updated (either while on line or following an outage).

• When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-month test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, if the MNPLR is greater than the leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the HNP leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.

• If the potential leakage understatement adjusted leak rate MNPLR is less than the HNP leakage summation limit of 0.50 La, then the acceptability of the greater than a 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.

• In addition to Condition 1, ISSUES 1 and 2, which deal with the MNPLR Type B and C summation margin, NEI 94-01, Revision 3-A, also has a margin related requirement as contained in Section 12.1, Report Requirements.

• A post-outage report shall be prepared presenting results of the previous cycle's Type Band Type C tests, and Type A, Type Band Type C tests, if performed during that outage. The technical contents of the report are generally described in ANSI/ANS-56.8-2002 (Reference 19) and shall be available on-site for NRC review. The report shall show that the applicable performance criteria are met, and serve as a record that continuing performance is acceptable. The report shall also include the combined Type B and Type C leakage summation, and the margin between the Type B and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type B and Type C leakage rate summation shall be identified in the report and a corrective action plan developed to restore the margin to an acceptable level.

• At HNP, in the event an adverse trend in the aforementioned potential leakage understatement adjusted Type Band C summation is identified, then an analysis and determination of a corrective action plan shall be prepared to restore the trend and associated margin to an acceptable level. The corrective action plan shall focus on those components which have contributed the most to the adverse trend in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.

• At HNP an adverse trend is defined as three (3) consecutive increases in the final pre-RCS Mode Change Type B and C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La.

The NRC staff has reviewed the requirements of NEI TR 94-01, Revision 3, against the SNC responses for Condition 2. Based on this review, the NRC staff concludes that SNC acknowledges all the requirements of Condition 2 and has established its intent for HNP to comply with these requirements.

3.2.6 Probabilistic Risk Assessment 3.2.6.1 Background Section 9.2.3.1, "General Requirements for ILRT Interval Extensions beyond Ten Years," of NEI 94-01, Revision 2-A (Reference 8), states that plant-specific confirmatory analyses are required when extending the Type A integrated leak rate test interval beyond ten years.

Section 9.2.3.4, "Plant-Specific Confirmatory Analyses," of NEI 94-01 states that the assessment should be performed using the approach and methodology described in EPRI TR-1009325, Revision 2-A1, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Final Report" (Reference 12). The analysis is to be performed by the licensee and retained in the plant documentation and records as part of the basis for extending the ILRT interval.

In the NRC staff's SER, dated June 25, 2008 (Reference 10), the staff found the methodology in EPRI TR-1009325, Revision 2 (Reference 12), acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT interval to 15 years, provided certain conditions are satisfied. These conditions, set forth in Section 4.2 of the SER for EPRI TR-1009325, Revision 2, stipulate that:

1. The licensee submits documentation indicating that the technical adequacy of their Probabilistic Risk Assessment (PRA) is consistent with the requirements of Regulatory Guide (RG) 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (Reference 14),

relevant to the ILRT extension application.

2. The licensee submits documentation indicating that the estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years is small and consistent with the clarification provided in Section 3.2.4.62 of the SER for EPRI TR-1009325, Revision 2.

3. The methodology in EPRI TR-1009325, Revision 2, is acceptable provided the average leak rate for the pre-existing containment large leak accident case (i.e., accident case 3b) used by licensees is assigned a value of 100 times the maximum allowable leakage rate (La) instead of 35 La.

4. A license amendment request (LAR) is required in instances where containment over-pressure is relied upon for emergency core cooling system (ECCS) performance.

3.2.6.2 Plant-Specific Risk Evaluation The licensee performed a risk impact assessment for extending the Type A containment ILRT interval from 1O years to 15 years. The risk analyses for HNP Unit 1 and Unit 2 were provided 1 It should be noted that EPRI TR-1009325, Revision 2-A, is also identified as EPRI TR-1018243. This report is publicly available and can be found at www.epri.com by typing "1018243" in the search field box.

2 The SER for EPRI TR-1009325, Revision 2, indicates that the clarification regarding small increases in risk is provided in Section 3.2.4.5; however, the clarification is actually provided in Section 3.2.4.6.

in Attachment 3 of the LAR (Reference 1). Additional information was provided by the licensee in its letters dated August 24, 2016, and February 10, June 1, and July 12, 2017, in response to NRC requests for additional information (RAls).

In Section 3.3.1 of Enclosure 1 to the LAR (Reference 1), the licensee stated that the plant-specific risk assessment follows the guidance in:

• NEI 94-01, Revision 3-A (Reference 9),

• The methodology described in EPRI TR-1018243, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-A of 1009325," dated October 2008 (Reference 12),

• The NRC regulatory guidance on the use of risk insights in support of a request for a plant's licensing basis as outlined in RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," (Reference 15), and

• The methodology used for Calvert Cliffs Nuclear Plant (CCNP) to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval.

The licensee addressed each of the four conditions for the use of EPRI TR-1009325, Revision 2, which are listed in Section 4.2 of the NRC SER (Revision 10). A summary of how each condition has been met is provided in the sections below.

3.2.6.2.1 Technical Adequacy of the PRA \

The first condition of Reference 10 stipulates that the licensee submits documentation indicating that the technical adequacy of their PRA is consistent with the requirements of RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (References 13 and 14), relevant to the ILRT extension application.

In Regulatory Issue Summary 2007-06, "Regulatory Guide 1.200 Implementation" (Reference 16), the NRC clarified that for all risk-informed applications received after December 2007, the NRC staff will use Revision 1 of RG 1.200 (Reference 13), to assess technical adequacy of the PRA used to support risk-informed applications. Revision 2 of RG 1.200 (Reference 14), will be used for all risk-informed applications received after March 2010. In Section 3.2.4.1 of the SER for EPRI TR-1009325, Revision 2 (Reference 10), the staff stated, in part:

Licensee requests for a permanent extension of the ILRT surveillance interval to 15 years pursuant to NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, will be treated by NRC staff as risk-informed license amendment requests. Consistent with information provided to industry in Regulatory Issue Summary 2007-06, "Regulatory Guide 1.200 Implementation," the NRC staff will expect the licensee's supporting Level 1/LERF PRA to address the technical

adequacy requirements of RG 1.200, Revision 1... Any identified deficiencies in addressing this standard shall be assessed further in order to determine any impacts on any proposed decreases to surveillance frequencies. If further revisions to RG 1.200 are issued which endorse additional standards, the NRC staff will evaluate any application referencing NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, to examine if it meets the PRA quality guidance per the RG 1.200 implementation schedule identified by the NRC staff.

In the same section of that SER, the NRC staff states that Capability Category I of the ASME PRA standard shall be applied as the standard for assessing PRA quality for ILRT extension applications, as approximate values of core damage frequency (CDF) and large early release frequency (LERF) and their distribution among release categories are sufficient to support the evaluation of changes to ILRT frequencies.

As discussed in Section 3.3.2.2 and in Appendix B to Attachment 3 of the LAR, the HNP risk assessment performed to support the ILRT application uses the current Unit 1 Level 1 and Level 2 internal events and internal flooding PRA models of record, Revision 4.1. In response to the NRC staff's request for additional information, the licensee provided an overview of the differences between Unit 1 and Unit 2, and concluded that the Unit 1 models bound those for Unit 2, and therefore the results from Unit 1 provided in the LAR are considered representative of both Unit 1 and Unit 2. In Section B.2 of Attachment 3 to the LAR, the licensee describes the process used for controlling the PRA model and for ensuring that it reflects the as-built, as-operated plant. The licensee has a process for continued PRA maintenance and update, including procedures for regularly scheduled and interim PRA model updates and for tracking issues identified as potentially affecting the PRA model. As explained in the LAR, and in response to the staff's RAI, the licensee performed a review of the plant modifications and changes and concluded that there are no plant changes that have not yet been incorporated in those PRA models that would affect this application.

The PRA technical adequacy for HNP is discussed in Section 3.3.2 and Attachment 3 of the LAR. The licensee stated that a full-scope peer review of the HNP internal events PRA model was conducted in November 2009 against RG 1.200, Revision 2, the PRA Standard ASME/ANS RA-Sa-2009 (Reference 20), and NEI 05-04 (Reference 21). The licensee stated that there were ten supporting requirements (SRs) that were considered "not met" by the peer review team and five SRs that were met at Capability Category I. The Facts and Observations (F&Os) related to these SRs were submitted in Section B.2.5.2 of Attachment 3 of the LAR, together with a brief summary of their resolution. The NRC staff reviewed these F&Os and their associated dispositions and determined that they have no impact on the ILRT application results.

In Section 3.2.4.2 of the SER for NEI 94-01, Revision 2 and EPRI TR-1009325, Revision 2, the NRC staff states that:

Although the emphasis of the quantitative evaluation is on the risk impact from internal events, the guidance in EPRI Report No. 1009325, Revision 2, Section 4.2.7, "External Events," states that: "Where possible, the analysis should include a quantitative assessment of the contribution of external events (e.g., fire and seismic) in the risk impact assessment for extended ILRT intervals." This section also states that: "If the external event analysis is not of sufficient quality or detail to directly apply the methodology provided in this

document [(i.e., EPRI Report No. 1009325, Revision 2)], the quality or detail will be increased or a suitable estimate of the risk impact from the external events should be performed. This assessment can be taken from existing, previously submitted and approved analyses or other alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval.

The licensee performed an analysis of the impact of external events in Section 5.8 of of the LAR, which was further updated in response to the staff's RAI in the licensee's supplement dated July 12, 2017 (Reference 5). For the evaluation of the acceptance criteria discussed in Section 3.2.6.2.2 of this SE, the licensee's analysis reflected the contribution from internal fire, seismic events and high winds quantitatively by scaling the internal events CDF by a multiplication factor based on the CDF of each initiator group. For other external events, the licensee determined their contribution to be negligible for this application.

The risk estimates for internal fire and external hazards, except for seismic risk, are based on the results from the Individual Plant Examination for External Events (IPEEE). The NRC staff requested that the licensee assess these external events for the current state of HNP and discuss the effect on the LAR and justify the licensee's approach for using the "external events multiplier" or an updated analysis to correctly capture the impact from external events. The licensee stated that the consequences associated with the other external events (e.g., high winds and tornadoes, external flooding, industrial and military facility accidents, etc.) were evaluated in 2013 and the licensee concluded that these hazards do not pose a credible threat and, therefore, can be screened out consistent with the conclusions made in the IPEEE. The licensee's fire CDF was estimated from the IPEEE to be 7.5E-6/year. The licensee does not have a peer-reviewed fire PRA and, therefore, one was not used for this application. The licensee's seismic CDF was derived from the 2008 United States Geological Survey's seismic hazard curves developed in conjunction with NRC Generic Issue (GI) 199, "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants." The licensee stated that, based on results from Peach Bottom, which is also a Mark I containment design, the probability of early containment failure for seismically initiated events is high (70 percent or greater), therefore the licensee reduced the Gl-199 seismic CDF of 6.6E-7/year by 70 percent to 2.2E-6/year to eliminate those sequences that are already included in the LERF, consistent with the EPRI methodology. Additionally, the licensee stated that the recently developed seismic PRA model estimated a seismic CDF of 3.08E-7 per year, which is a factor of 7 lower than the value assumed in this application. Therefore, the NRC staff finds the licensee's estimate of seismic CDF acceptable for this application.

In summary, the licensee has evaluated its internal events PRA model against the currently implemented version of RG 1.200, Revision 2 (Reference 14) and the currently endorsed ASME PRA standard (Reference 20), evaluated the findings developed during the peer review of its internal events PRA for their applicability to the ILRT extension, addressed the findings or evaluated their impact, and included a quantitative assessment of the contribution of external events. The staff reviewed the internal events peer review findings and agrees that the dispositioned findings have been adequately addressed for this application and, therefore, the NRC staff concludes that the PRA model used by the licensee is of sufficient technical adequacy to support the evaluation of changes to ILRT frequency. Furthermore, the NRC staff concludes that the external hazards contribution is appropriately considered by an order of magnitude estimate. Accordingly, the first condition is met.

3.2.6.2.2 Estimated Risk Increase The second condition of Reference 10 stipulates that the licensee submit documentation indicating that the estimated risk increase associated with permanently extending the ILRT interval to 15 years is small, and consistent with the guidance in RG 1.174 (Reference 15) and the clarification provided in Section 3.3.2 of the NRC SER for NEI 94-01, Revision 2 (Reference 10). Specifically, a small increase in population dose should be defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or one percent of the total population dose, whichever is less restrictive. In addition, a small increase in conditional containment failure probability (CCFP) should be defined as a value marginally greater than that accepted in previous one-time 15-year ILRT extension requests. This would require that the increase in CCFP be less than or equal to 1.5 percentage points. Additionally, for plants that rely on containment overpressure for net positive suction head (NPSH) for ECCS injection, both CDF and LERF will be considered in the ILRT evaluation and compared with the risk acceptance guidelines in RG 1.174 (Reference 15). As discussed further in Section 3.2.6.2.4 of this Safety Evaluation, HNP credits containment overpressure. Thus, the associated risk metrics include: CDF, LERF, population dose, and CCFP.

The licensee reported the results of the plant-specific risk assessment in Section 3.3.3 of the LAR, and updated those results by letter dated July 12, 2017 (Reference 5). Details of the risk assessment are provided in Attachment 3 of the LAR and updated by the RAI responses. The reported risk impacts are based on a change in test frequency from three tests in 1O years (the test frequency under 10 CFR 50 Appendix J, Option A), to one test in 15 years. The following conclusions can be drawn based on the licensee's analysis associated with extending the Type A ILRT frequency:

1. The reported increase in CDF due to containment overpressure and the change in test frequency from three in 10 years to one in 15 years is 2.74E-7 per year for both Unit 1 and Unit 2 (Reference 5). As discussed further in Section 3.2.6.2.4 of this SE, this estimate credits Reactor Core Isolation Cooling (RCIC) for long term cooling without providing adequate justification for this credit. Removing this credit would result in an increase in CDF of 5.47E-7 per year, as reported by the licensee in the RAI response.

Both of these estimates are considered to be "very small" (i.e. less than 1E-6 per year) and are below the acceptance guidelines in RG 1.174. The applicability of containment overpressure crediting for ECCS performance is discussed in further detail in Section 3.2.6.2.4 of this SE.

2. The reported increase in LERF for a change in test frequency from three tests in 1O years to one test in 15 years is 6.24E-7 per year for both Unit 1 and Unit 2 (Reference 5). This estimate includes both internal and external events (internal fires, seismic events and high winds) and the contribution from loss of containment overpressure impact on the NPSH for the ECCS pumps. This change in internal and external events risk is considered to be "small" (i.e., between 1E-06/year and 1E-07 /year) per the acceptance guidelines in RG 1.174. An assessment of total baseline LERF is required to show that the total LERF is less than 1E-05/year. The licensee estimated the total LERF for internal and external events as 3.1 E-06/year. The total LERF, given the increase in ILRT interval, is below the acceptance guideline of 1E-05/year in RG 1.174 for a "small" change. As discussed further in Section 3.2.6.2.4 of this SE, this estimate credits RCIC for long term cooling when ECCS NPSH is lost due to loss of containment overpressure, but adequate justification for this credit was not

provided by the licensee. The sensitivity analysis discussed in Section 3.2.6.2.4 of this SE demonstrates that the acceptance criteria are still met if the credit for RCIC for long term cooling is removed.

3. Given a change in Type A ILRT frequency from three tests in 10 years to one in 15 years, and assuming the loss of containment overpressure at 100 La, the reported increase in the total population dose is 8.2 x 10-2 person-rem per year for both Unit 1 and Unit 2. The licensee states that the site-specific dose estimates are based on analyses performed for the Severe Accident Management Alternatives (SAMA), adjusted to reflect the projected Hatch population estimates for year 2030. However, because this plant specific dose estimate did not include results for intact containment as required for the EPRI ILRT methodology, the licensee used the conditional population dose results from Peach Bottom (as evaluated in NUREG/CR-4551, Reference 22) and scaled it to adjust for regional population, reactor power level, and allowable containment leakage rate (La), consistent with the guidance in EPRI TR-1018243. The reported increase in total population dose is below the value provided in EPRI TR-1009325, Revision 2 A, and defined in Section 3.2.4.6 of the NRC SER for NEI 94-01, Revision 2. Thus, this increase in the total integrated plant risk for the proposed change is considered small and is acceptable for the proposed change.

4. The increase in CCFP due to the change in test frequency from three in 10 years to one in 15 years is 0.84 percent for both Unit 1 and Unit 2. This value is small and is below the acceptance guidelines in Section 3.2.4.6 of the NRC SER for NEI 94-01, Revision 2.

Based on its review of the HNP risk assessment results, the NRC staff concludes that the increases in CDF and LERF are small and consistent with the risk acceptance guidelines of RG 1.174 (Reference 15). In addition, the increase in the total population dose and the CCFP for the requested change is small and acceptable for this LAR. The defense-in-depth philosophy is maintained because the independence of barriers will not be degraded as a result of the requested change, and the use of quantitative risk metrics collectively ensures that the balance between prevention of core damage/containment failure and consequence mitigation is preserved. Accordingly, the second condition is met.

3.2.6.2.3 Leak Rate for the Large Pre-Existing Containment Leak Rate Case The third condition of Reference 10 stipulates that in order to make the methodology in EPRI TR-1009325, Revision 2 (Revision 12), acceptable, the average leak rate for the pre-existing containment large leak rate accident case (i.e., accident case 3b) used by licensees shall be 100 La instead of 35 La.

As noted by the licensee in Table 3.3.1-1 of the LAR, the methodology in EPRI TR-1009325, Revision 2, incorporates the use of 100 La as the average leak rate for the pre-existing containment large leak rate accident case, and this value has been used in the HNP plant specific risk assessment. Accordingly, the third condition is met.

3.2.6.2.4 Applicability if Containment Over-Pressure is Credited for ECCS Performance The fourth condition of Reference 10 stipulates that in instances where containment overpressure is relied upon for ECCS performance, a LAR is required to be submitted. In Section 3.1.6 of the LAR, the licensee stated that the ECCS analysis for the mitigation of design basis events relies on containment overpressure in the calculation of available NPSH for the

Residual Heat Removal (RHR) and Core Spray (CS) pumps at Unit 1. For Unit 2, the licensee stated that the short-term and long-term containment response analyses demonstrate that the RHR and CS pumps have sufficient NPSH margin without taking credit for containment overpressure.

According to the clarification provided in Section 3.2.4.6 of the NRC SER for NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2 (Reference 10), plants that rely on containment overpressure NPSH for ECCS injection must also consider the change in CDF in the ILRT evaluation. In the LAR, the licensee stated that the change in CDF would be negligible; however, the LAR only addressed large-break LOCA initiators. As stated in Section 5.2.4 of EPRI TR-1018243, all LOCA-type scenarios should be considered, including consequential LOCAs (i.e., when the LOCA is not the initiating event), therefore, the NRC staff requested a justification on how all the accident scenarios that could impact NPSH for the ECCS pumps were considered. The licensee further updated its assessment of risk impact of containment overpressure in its response dated June 1, 2017 (Reference 4 ), as further supplemented in its July 12, 2017 (Reference 5) letter. The licensee explained that to estimate the change in CDF, the containment isolation failure logic was increased by the Class 3b frequency at 15 years, and that a basic model for the failure of ECCS if the containment is depressurized was applied to a wide range of accident sequences. The licensee provided a summary of the impact of loss of NPSH to each group of initiating events, and showed that a wide range of accident sequences were analyzed. The licensee stated that the increase in CDF results from loss of low pressure injection when containment heat removal fails, coupled with loss of injection from outside containment. The licensee explained in the LAR that, based on MAAP calculations, loss of ECCS NPSH is not a concern when RHR containment heat removal is available, because adequate suppression pool water temperature is maintained. The licensee estimated a delta CDF of 5.47E-7 per year. The licensee further credited RCIC for long-term cooling, and estimated a 50 percent reduction in delta CDF to 2. 74E-7 per year. The NRC staff finds that the licensee did not provide adequate justification for this credit for CDF reduction; however, discounting the licensee's crediting of RCIC for long-term cooling does not impact the conclusion that the change in CDF is acceptable. Accordingly, the fourth condition is met.

To estimate the change in LERF, the licensee assumed that the core damage sequences resulting from loss of containment overpressure directly result in LERF. This is a conservative assumption. While the staff does not find that the licensee's credit for RCIC for long-term cooling was appropriately justified, it also acknowledges the fact that not all of the core damage sequences resulting from loss of containment overpressure to the ECCS would directly result in LERF. For example, as stated in response to second round RAls (Reference 4), for some of the accident scenarios, such as Medium LOCA and any transients with Stuck Open Relief Valves (SORVs), NPSH would be lost late in the scenario (at 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />), and therefore would not classify as LERF. The staff also performed an independent estimate of total change in LERF assuming a change in LERF due to the loss of containment overpressure of 4E-7/year. Using the licensee's external events multiplier factor of 1.21, the resulting total change in LERF was estimated at 1.02E-6 per year and the total LERF as 3.5E-6 per year, which is still acceptable per the acceptance criteria in RG 1.174 (Reference 15). Therefore, the staff finds that the conclusion of this safety evaluation is unchanged, even if the licensee's credit for RCIC for long-term cooling is not considered. The total change in LERF is further discussed in Section 3.2.6.2.2 of this Safety Evaluation.

3.2.6.3 PRA Conclusion Based on the above, the NRC staff concludes that the LAR for a permanent extension of the

Type A containment ILRT frequency from once in 10 years to once in 15 years for HNP Unit 1 and Unit 2 is acceptable. In accordance with the revised TS 5.5.12, the containment leakage rate testing program for HNP shall be in accordance with the guidelines contained in NEI 94-01, Revision 3-A.

3.3 Summary and Conclusion Based on the above evaluation, the NRC staff finds that the licensee has adequately implemented its Primary Containment Leakage Rate Testing Program (i.e. Type A, B, and C leakage tests), for the HNP Unit 1 and Unit 2 containments. The results of past ILRTs and recent LLRTs demonstrate acceptable performance of the HNP Unit 1 and Unit 2 containments and demonstrate that the structural and leak-tight integrity of the containment structures are being adequately maintained. The staff also finds that the licensee has satisfactorily addressed the limitations and conditions of the NRC safety evaluations approving the use of TR NEI 94-01, Revision 2-A (Reference 8) and TR NEI 94-01, Revision 3-A (Reference 9),

Therefore, the staff finds that the proposed changes to HNP TS 5.5.12 regarding the primary containment leakage rate testing program are acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Georgia State official was notified of the proposed issuance of the amendments on October 13, 2017. The NRC staff verified that the State official had no comments on October 16, 2017.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change requirements with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20 and change surveillance requirements. The NRC staff has determined that the amendments involve no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding published in the Federal Register on September 13, 2016 (81 FR 62930). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

6.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

7.0 REFERENCES

1. Pierce, C. R., Southern Nuclear Operating Company, Inc., letter to U.S. Nuclear Regulatory Commission, "Edwin I. Hatch Nuclear Plant - Units 1 and 2; License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies" dated July 1, 2016 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML16188A268).

2. Wheat, Justin T., Southern Nuclear Operating Company, Inc., letter to U.S. Nuclear Regulatory Commission, "Edwin I. Hatch Nuclear Plant - Units 1 and 2; License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies, Correction to Attachment 3" dated August 24, 2016 (ADAMS Accession No. ML16238A477).

3. Pierce, C. R., Southern Nuclear Operating Company, Inc., letter to U.S. Nuclear Regulatory Commission, "Edwin I. Hatch Nuclear Plant - Units 1 and 2; License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies, Responses to NRC Requests for Additional Information" dated February 10, 2017 (ADAMS Accession No. ML17041A294).

4. Wheat, Justin T., Southern Nuclear Operating Company, Inc., letter to U.S. Nuclear Regulatory Commission, "Edwin I. Hatch Nuclear Plant - Units 1 and 2, License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies, Responses to NRC Second Set of Requests for Additional Information" dated June 1, 2017 (ADAMS Accession No. ML17152A413).

5. Hutto, J. J., Southern Nuclear Operating Company, Inc., letter to U.S. Nuclear Regulatory Commission, "Edwin I. Hatch Nuclear Plant - Units 1 and 2, License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies, Supplemental Responses to NRC Second Set of Requests for Additional Information" dated July 12, 2017 (ADAMS Accession No. ML17194B078).

6. U.S. Nuclear Regulatory Commission, RG 1.163, "Performance-Based Containment Leak-Test Program," September 1995 (ADAMS Accession No. ML003740058).

7. NEI Topical Report 94-01, Revision 0, dated July 21, 1995 "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J" (ADAMS Accession No. ML11327A025)

8. NEI Topical Report 94-01, Revision 2-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," October 2008 (ADAMS Accession No. ML100620847).

9. NEI Topical Report 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," July 2012 (ADAMS Accession No. ML12221A202).

10. U.S. Nuclear Regulatory Commission, Final Safety Evaluation, "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, 'Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J,'

and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, 'Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals," June 25, 2008 (ADAMS Accession No. ML081140105).

11. U.S. Nuclear Regulatory Commission, "Final Safety Evaluation of Nuclear Energy Institute (NEI) Report, 94-01, Revision 3, 'Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J,' (TAC No. ME2164),"

June 8, 2012 (ADAMS Accession No. ML121030286).

12. Electric Power Research Institute, TR-1009325, Revision 2, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Final Report," August 2007 (ADAMS Accession No. ML072970208).

13. U.S. Nuclear Regulatory Commission, RG 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," January 2007 (ADAMS Accession No. ML070240001).

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

15. U.S. Nuclear Regulatory Commission, RG 1.174, Revision 2, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," May 2011 (ADAMS Accession No. ML100910006).

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

17. Olshan, Leonard N., U.S. Nuclear Regulatory Commission, letter to H.L. Summer, Jr.,

Southern Nuclear Operating Company, Inc., "Edwin I. Hatch Nuclear Plant, Unit 1 RE:

Issuance of Amendment (TAC No. MB2842)," Amendment No. 226, dated February 20, 2002 (ADAMS Accession No. ML020560321 ).

18. Gratton, Christopher, U.S. Nuclear Regulatory Commission, letter to H.L. Sumner, Jr.,

Southern Nuclear Operating Company, Inc., "Edwin I. Hatch Nuclear Plant, Unit 2 RE:

Issuance of Amendment Revising the Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC No. MC2761)," Amendment No. 187 dated February 01, 2005 (ADAMS Accession No. ML050320004).

19. American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, "Containment System Leakage Testing Requirements," November 27, 2002.

20. ASME/ANS RA-Sa-2009, "Standard for Probabilistic Risk Assessment for Nuclear Power Plants," Addendum A to Revision of ASME RA-Sa-2002, ASME, New York, NY, February 2009.

21. Nuclear Energy Institute, NEI 05-04, "Process for Performing Follow-On PRA Peer Reviews Using the ASME PRA Standard," Revision 2, Washington, DC, November 2008.

22. NUREG/CR-4551, Revision 1, Vol. 4, Part 1, "Evaluation of Severe Accident Risks:

Peach Bottom, Unit 2, Main Report," December 1990 (ADAMS Accession No. ML063490176).

Principal Contributor: D. Nold, NRR R. Pettis, NRR J. Evans, NRR M. Biro, NRR Date: November 30, 2017

ML17271A307 *via memo **via e-mail OFFICE NRR/DORL/LPL2-1 /PM N RR/DORL/LPL2-1 /PM** NRR/DORL/LPL2-1/LA NRR/DSS/SBPB/BC*

NAME JHall !Anchondo KGoldstein RDennig DATE 11/16/17 11/16/17 10/11/17 3/21/17 OFFICE NRR/DE/EMCB/BC* NRR/DRA/APLA/BC* NRR/DSS/STSB/BC OGC-NLO NAME JQuichocho SRosenberg VCusumano DRoth DATE 1/19/17 8/25/17 11/28/17 11/27/17 OFFICE NRR/DORL/LPL2-1 /BC NRR/DORL/LPL2-1/PM NAME MMarkley JHall DATE 11/30/17 11/30/17