RA-25-0200, Subsequent License Renewal Application Supplement 1

Subsequent License Renewal Application Supplement 1

ML25240B656
Person / Time
Site:	Robinson
Issue date:	08/28/2025
From:	Basta L Duke Energy Progress
To:	Office of Nuclear Reactor Regulation, Document Control Desk
Shared Package
ML25240B655	List: RA-25-0200, Subsequent License Renewal Application Supplement 1
References
RA-25-0200
Download: ML25240B656 (1)

Text

t_., DUKE ENERGY Laura A. Basta Site Vice President H.B. Robinson Steam Electric Plant Unit 2 Duke Energy 3581 West Entrance Road Hartsville, SC 29550 o: 864.951.1701 Laura. Basta @duke-energy.com PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED August 28, 2025 Serial: RA-25-0200 ATTN: Document Control Desk U.S Nuclear Regulatory Commission Washington, DC 20555-0001

References:

Duke Energy Progress, LLC (Duke Energy)

H.B. Robinson Steam Electric Plant, Unit Number 2 Docket Number 50-261 / Renewed License Number DPR-23 Subsequent License Renewal Application Supplement 1 10 CFR 50.4 10 CFR Part 54

1. Duke Energy Letter (RA-25-0067), Application for Subsequent Renewed Operating Licenses, dated April 1, 2025 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML25091A291)

2. U.S. NRC Letter, Determination of Acceptability and Sufficiency for Docketing, Proposed Review Schedule, and Opportunity for a Hearing Regarding the Duke Energy Progress, LLC Application for Subsequent License Renewal, dated April 28, 2025 (ADAMS Accession No. ML25106A069)

3. U.S. NRC Letter, Aging Management Audit Plan Regarding the Subsequent License Renewal Application Review, dated April 25, 2025 (ADAMS Accession No. ML25113A162)

4. U.S. NRC Letter, Revision of Schedule for the Safety Review of the H.B. Robinson Steam Electric Plant, Unit 2, Subsequent License Renewal Application, dated August 7, 2025 (ADAMS Accession No. ML25202A136)

5. U.S. NRC, Standardization Recommendations for License Renewal Applications, May 2025 (ADAMS Accession No. ML25132A176)

By letter dated April 1, 2025 (Reference 1 ), Duke Energy Progress, LLC (Duke Energy) submitted an application for the subsequent license renewal of Renewed Facility Operating License Number DPR-23 for the H.B. Robinson Steam Electric Plant (RNP), Unit 2 to the U.S. Nuclear Regulatory Commission (NRC). On April 28, 2025 (Reference 2), the NRC determined that the RNP subsequent license renewal application (SLRA) was acceptable and sufficient for docketing. By letter dated April 25, 2025 (Reference 3), the NRC issued the regulatory audit plan for the aging management portion of the SLRA review. On August 7, 2025 (Reference 4), the NRC provided a change in the review schedule. During the audit, conducted from April 30, 2025 to August 7, 2025, Duke Energy agreed to supplement the SLRA with new or clarifying information. This letter provides the NRC staff with additional information in support of the development of the safety evaluation report. to this letter provides the index of topics to be supplemented. Duke Energy followed the standardization recommendations for license renewal applications (Reference 5), including the PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

U.S. Nuclear Regulatory Commission RA-25-0200 PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED Page 2 formatting guidelines outlined for Section 3 RAI responses and supplements. These changes are described for each attachment, with affected section(s), page number(s), and document mark-ups clearly identified. Changes to commitments are provided in Table A6.0-1 for Attachments 1, 4, 7, 8, and 10. Enclosures 2 and 4 contain the Westinghouse proprietary and non-proprietary versions of a supporting document referenced in the SLRA. An affidavit from Westinghouse attesting to the proprietary nature of the information is provided in Enclosure 3. Duke Energy requests that Enclosure 2 be withheld from public disclosure in accordance with 10 CFR 2.390.

If you have additional questions, please contact Daniel Roberts at (704) 382 3444 or by email at daniel.roberts2@duke-energy.com.

I declare under penalty of perjury that the foregoing is true and correct. Executed on August 28, 2025.

Sincerely, Laura A. Basta Site Vice President H.B Robinson Steam Electric Plant : Index of Attachment Topics Involving SLRA Supplement : Supplement changes to address issues related to Fatigue Monitoring AMP NRC Clarification Request : SLRA updates to address TRP 2 (Water Chemistry) requirements (TRP 2) : Internally Coated Components Managed by Inspection of Internal Surfaces AMP (TRP 15) : Supplement changes to address incorporation of relevant guidance in MRP-227 Revision 2-A requirements in Enhancement 1 and update AMR line ID #7487 (TRP 16) : Changes to Sections 1.5 and 1.7 (TRP 19) : Boraflex Monitoring Not Applicable (TRP 22) : Supplement changes to address issues related to TRP 26 Fire Protection (TRP

26) : TRP 33 - Selective Leaching Supplement Items (TRP 33) : Monitoring of Neutron-Absorbing Materials Other Than Boraflex (TRP 40) 0: RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants (TRP 4 7) 1 : Supplement changes to address issues related to TRP-60 (TRP 60) 2: TRP 74 - Concrete Supplement Updates for Reactor Auxiliary Building and Reservoir and Dam AMR Tables (TRP 74) 3: SS Nickel Alloy Aluminum Alloy Further Evaluations (TRP 84)

PROPRIETARY INFORMATION -WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

U.S. Nuclear Regulatory Commission Page 3 RA-25-0200 PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED 3: SS Nickel Alloy Aluminum Alloy Further Evaluations (TRP 84) 4: Supplement changes to address issues related to TRP-142.4 (TRP 142.4) 5: Supplement changes to address issues related to TRP-143 (TRP 143) 6: Supplement changes to address issues related to TRP-143.1 (TRP 143.1) 7: Supplement changes to address how 80-year projected cycles in SLRA Table 4.3.3-2 were determined per TRP 143.3 (TRP 143.3) 8: TRP 147.2 - TLAA 4.7.2 (Site-Specific) Reactor Coolant Pump Flywheel Analyses (TRP 147.2) 9: Supplement changes to state that no underclad flaws in the reactor vessel have been identified related to TRP 147.5 (TRP 147.5)

WCAP-18944-P, H.B. Robinson Unit 2 Subsequent License Renewal: Reactor Vessel Upper Shelf Energy Equivalent Margins Analysis, Revision 2, dated August 2025 (Proprietary Version) : Westinghouse Affidavit : WCAP-18944-NP, H.B. Robinson Unit 2 Subsequent License Renewal: Reactor Vessel Upper Shelf Energy Equivalent Margins Analysis, Revision 2, dated August 2025 (Non-Proprietary Version)

U.S. Nuclear Regulatory Commission Page 4 RA-25-0200 PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED CC: W/O

Enclosures:

Julio Lara, Acting Regional Administrator U.S. Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, Georgia 30303-1257 Andrew Siwy, Project manager (by electronic mail only)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, Maryland 20852 Karen Loomis, Project Manager (by electronic mail only)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, Maryland 20852 Natreon Jordan, Project Manager (by electronic mail only)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, Maryland 20852 John Zeiler (by electronic mail only)

NRC Senior Resident Inspector H.B. Robinson Steam Electric Plant, Unit 2 A. Wilson, Attorney General (SC)

R.S. Mack, Assistant Bureau Chief, Bureau of Environmental Health Services (SC)

L. Garner, Manager, Radioactive and Infectious Waste Management Section (SC)

U.S. Nuclear Regulatory Commission RA-25-0200 H.B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application H.B. Robinson SLRA Supplement 1 H.B. Robinson SLRA Supplement 1 Index of Attachment Topics Involving SLRA Supplements Attachment Number Topics Title 1

FM AMP NRC Clarification Request Supplement changes to address issues related to Fatigue Monitoring AMP NRC Clarification Request 2

TRP 2 SLRA updates to address TRP 2 (Water Chemistry) requirements.

3 TRP 15 Internally Coated Components Managed by Inspection of Internal Surfaces AMP 4

TRP 16 Supplement changes to address incorporation of relevant guidance in MRP-227 Revision 2-A requirements in Enhancement 1 and update AMR line ID #7487.

5 TRP 19 Steam Generator Surveillance Changes to Sections 1.5 and 1.7 6

TRP 22 Boraflex Monitoring Not Applicable 7

TRP 26 Supplement changes to address issues related to TRP 26 Fire Protection 8

TRP 33 TRP 33 - Selective Leaching Supplement Items 9

TRP 40 Monitoring of Neutron-Absorbing Materials Other Than Boraflex 10 TRP 47 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 11 TRP 60 Supplement changes to address issues related to TRP-060 12 TRP 74 TRP 74 - Concrete Supplement Updates for Reactor Auxiliary Building and Reservoir and Dam AMR Tables 13 TRP 84 SS Nickel Alloy Aluminum Alloy Further Evaluations

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application H.B. Robinson SLRA Supplement 1 14 TRP 142.4 Supplement changes to address issues related to TRP-142.4 15 TRP 143 Supplement changes to address issues related to TRP-143 16 TRP 143.1 Supplement changes to address issues related to TRP-143.1 17 TRP 143.3 Supplement changes to address how 80-year projected cycles in SLRA Table 4.3.3-2 were determined per TRP 143.3 18 TRP 147.2 TRP 147.2 - TLAA 4.7.2 (Site-Specific) Reactor Coolant Pump Flywheel Analyses 19 TRP 147.5 Supplement changes to state that no underclad flaws in the reactor vessel have been identified related to TRP 147.5

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 1 FM AMP NRC Clarification Request

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 1 1, Attachment 1 Supplement changes to address issues related to Fatigue Monitoring AMP NRC Clarification Request (FM AMP NRC Clarification Request)

Affected SLRA Section(s):

A6.0 B3.1 SLRA Page Numbers:

A-101 B-257 Description of Change:

This supplement adds the requirement to monitor and track transient cycles associated with the ASME Code,Section XI, Appendix A analysis between inspections for the Reactor Vessel outlet nozzle in AMP enhancement #1. This changes text in SLRA Section B3.1 and item #45 in the A6.0-1 table.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 1 2

SLRA Revisions:

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 45 Fatigue Monitoring (B3.1)

The Fatigue Monitoring AMP is an existing program that will be enhanced to:

1. The program will be enhanced to require monitoring and tracking of transient cycles associated with the ASME Code,Section XI, Appendix L analysis be performed between the inspections for each ASME Code,Section XI, Appendix L location. Consistent with existing program cycle counting, a surveillance limit will be established between inspections for the locations that credit an ASME Code,Section XI, Appendix L or Appendix A evaluation.

Consistent with the existing program cycle counting, a surveillance limit will be established to initiate corrective action prior to initiate corrective action prior to exceeding transient cycle assumptions in the ASME Code,Section XI, exceeding transient cycle assumptions in the ASME Code,Section XI, Appendix L or Appendix L analysis. A evaluations.

2. The program will be enhanced to require periodic validation of chemistry parameters used to determine Fen factors.

3. The program will be enhanced to expand existing corrective action guidance associated with exceeding a cycle counting surveillance limit to recommend consideration of a range of options, including component repair, component replacement, performance of a more rigorous analysis, performance of an Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 1 3

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule ASME Code,Section XI, Appendix L flaw tolerance analysis, or scope expansion to consider other locations with the highest expected CUFen values.

Changed

- 45 Fatigue Monitoring (B3.1)

The Fatigue Monitoring AMP is an existing program that will be enhanced to:

1. The program will be enhanced to require monitoring and tracking of transient cycles between inspections for the locations that credit an ASME Code,Section XI, Appendix L or Appendix A evaluation. Consistent with the existing program cycle counting, a surveillance limit will be established to initiate corrective action prior to exceeding transient cycle assumptions in the ASME Code,Section XI, Appendix L or Appendix A evaluations.

2. The program will be enhanced to require periodic validation of chemistry parameters used to determine Fen factors.

3. The program will be enhanced to expand existing corrective action guidance associated with exceeding a cycle counting surveillance limit to recommend consideration of a range of options, including component repair, component replacement, performance of a more rigorous analysis, performance of an ASME Code,Section XI, Appendix L flaw tolerance analysis, or scope expansion to consider other locations with the highest expected CUFen values.

Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 1 4

SLRA Section B3.1 is revised as follows:

Section B3.1 Enhancements The following enhancements will be implemented in the following program elements: Scope of Program (Element 1), Parameters Monitored/Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5), Acceptance Criteria (Element 6), and Corrective Actions (Element 7)

1. The program will be enhanced to require monitoring and tracking of transient cycles associated with the ASME Code,Section XI, Appendix L analysis be performed between the inspections for each ASME Code,Section XI, Appendix L locations. Consistent with existing program cycle counting, a surveillance limit will be established to initiate corrective action prior to exceeding transient cycle assumptions in the ASME Code,Section XI, between inspections for the locations that credit an ASME Code,Section XI, Appendix L or Appendix A evaluation. Consistent with existing program cycle counting, a surveillance limit will be established to initiate corrective action prior to exceeding transient cycle assumptions in the ASME Code,Section XI, Appendix L or Appendix L analysis. A evaluations. (Elements 1, 3, 4, 5, 6 and 7)

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 2 TRP 2

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 2 1, Attachment 2 SLRA updates to address TRP 2 (Water Chemistry) requirements.

(TRP 2)

Affected SLRA Section(s)/Table(s):

3.3.1 3.5.2-13 SLRA Page Numbers:

x 3-372 x

3-373 x

3-1012 Description of Change:

The following changes are made to the Robinson SLRA in response to TRP 2 requirements:

x SLRA Table 3.3.1, Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report, was revised to clarify that items 3.3.1-169 and 3.3.1-170 are applicable but not used. The discussion column was modified (as shown below) to clarify that these items are aligned to alternate items in the steam and power conversion system exposed to a treated water environment.

o Item 3.3.1-169 in SLRA Table 3.3.1 is revised to change "Not applicable" to "Not used." The GALL-SLR aging items associated with AMR lines for 'steel and copper alloy piping and piping components exposed to steam' are aligned to alternate item numbers 3.4.1-014, 3.4.1-015, and 3.4.1-016 for treated water in the Steam and Power Conversion Systems.

o Item 3.3.1-170 in SLRA Table 3.3.1 is revised to change "Not applicable" to "Not used." The GALL-SLR aging items associated with AMR lines for 'stainless steel piping and piping components exposed to steam' are aligned to alternate item numbers 3.4.1-083 and 3.4.1-085 for treated water in the Steam and Power Conversion Systems.

x SLRA Table 3.5.2-13, Containments, Structures, and Component Supports - Fuel Handling Building - Aging Management Evaluation, was revised to delete AMR ID 5367 for the Structures Monitoring program.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 2 2

SLRA Revisions:

SLRA Table 3.3.1 is revised as follows:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Item Number Component Aging Effect/Mechanism Aging Management Program Further Evaluation Recommended Discussion Difference -

3.3.1-169 Steel, copper alloy piping, piping components exposed to steam Loss of material due to general (steel only), pitting, crevice corrosion AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" No Not applicable. Aging effects for steel and copper alloy piping and piping components exposed to steam in Robinson Auxiliary Systems are aligned to items in the Steam and Power Conversion Systems with a treated water environment. The associated NUREG-2191 aging items are not used. Not used. The AMR lines for steel and copper alloy piping and piping components exposed to steam are evaluated using alternative GALL Chapter VIII (Steam and Power Conversion Systems) items for loss of material in a treated water environment. This SRP item [3.3.1-169] is addressed by SRP items

[3.4.1-014], [3.4.1-015], and [3.4.1-016].

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 2 3

Changed -

3.3.1-169 Steel, copper alloy piping, piping components exposed to steam Loss of material due to general (steel only), pitting, crevice corrosion AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" No Not used. The AMR lines for steel and copper alloy piping and piping components exposed to steam are evaluated using alternative GALL Chapter VIII (Steam and Power Conversion Systems) items for loss of material in a treated water environment. This SRP item [3.3.1-169] is addressed by SRP items

[3.4.1-014], [3.4.1-015], and [3.4.1-016].

Difference -

3.3.1-170 Stainless steel piping, piping components exposed to steam Loss of material due to pitting, crevice corrosion AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" No Not applicable. Stainless steel piping and piping components exposed to steam in Robinson Auxiliary Systems are aligned to items in the Steam used. The AMR lines for stainless steel piping and piping components exposed to steam are evaluated using alternative GALL Chapter VIII (Steam and Power Conversion Systems with a treated water environment. The associated NUREG-2191 aging items are not used. Systems) line items for loss of material in a treated water environment. This SRP item [3.3.1-170] is addressed by SRP items

[3.4.1-083] and [3.4.1-085].

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 2 4

Changed -

3.3.1-170 Stainless steel piping, piping components exposed to steam Loss of material due to pitting, crevice corrosion AMP XI.M2, "Water Chemistry," and AMP XI.M32, "One-Time Inspection" No Not used. The AMR lines for stainless steel piping and piping components exposed to steam are evaluated using alternative GALL Chapter VIII (Steam and Power Conversion Systems) line items for loss of material in a treated water environment. This SRP item [3.3.1-170] is addressed by SRP items

[3.4.1-083] and [3.4.1-085].

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 2 5

SLRA Table 3.5.2-13 is revised as follows:

Table 3.5.2-13 Containments, Structures, and Component Supports - Fuel Handling Building - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 5367 Spent Fuel Pool Liner Pressure

Boundary, Structural Support Stainless Steel Treated Borated Water (External)

Cracking, Loss of Material Structures Monitoring (B2.1.34)

III.A5.T-14 3.5.1-078 A,4 Deleted -

5367

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 3 TRP 15

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 1, Attachment 3 Internally Coated Components Managed by Inspection of Internal Surfaces AMP (TRP 15)

Affected SLRA Section(s)/Table(s):

3.3.2-4 3.3.2-27 3.3.2-30 3.3.2-31 3.4.2-14 B2.1.25 SLRA Page Numbers:

3-450 3-601 3-602 3-603 3-611 3-612 3-619 3-621 3-622 3-624 B-153 Description of Change:

Add discussion of criteria for substitution of Inspection of Internal Surfaces AMP vs. Inspection of Internal Coatings AMP.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 2

SLRA Revisions:

SLRA Table 3.3.2-4 is revised as follows:

Table 3.3.2-4 Auxiliary Systems - Component Cooling Water System - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 6673 Valve Body Structural Integrity Steel with Internal Coating/Lining Waste Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.E5.A-416 3.3.1-138 A,7 E,7 Changed -

6673 Valve Body Structural Integrity Steel with Internal Coating/Lining Waste Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.E5.A-416 3.3.1-138 E,7 Difference

- 6671 Valve Body Structural Integrity Steel with Internal Coating/Lining Waste Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.E5.A-414 3.3.1-139 A,7 E,7 Changed -

6671 Valve Body Structural Integrity Steel with Internal Coating/Lining Waste Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.E5.A-414 3.3.1-139 E,7

7. Component meets the six conditions outlined in NUREG-2191 Section XI.M42 Element 4 (Detection of Aging Effects) for managing loss of coating or lining integrity under an alternate program. Therefore, the AMR line is considered a match with the referenced NUREG-2191 item where the alternate program is credited for managing the internal coating/lining.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 3

SLRA Table 3.3.2-27 is revised as follows:

Table 3.3.2-27 Auxiliary Systems - Penetration Pressurization Local Leak Rate Test - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 676 Tank (penetration pressurization air receiver A, B, C, D)

Structural Integrity Steel with Internal Coating/Lining Condensation (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.D.A-416 3.3.1-138 A,1 E,1 Changed -

676 Tank (penetration pressurization air receiver A, B, C, D)

Structural Integrity Steel with Internal Coating/Lining Condensation (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.D.A-416 3.3.1-138 E,1 Difference

- 667 Tank (penetration pressurization air receiver A, B, C, D)

Structural Integrity Steel with Internal Coating/Lining Condensation (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.D.A-414 3.3.1-139 A,1 E,1 Changed -

667 Tank (penetration pressurization air receiver A, B, C, D)

Structural Integrity Steel with Internal Coating/Lining Condensation (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.D.A-414 3.3.1-139 E,1

1. Component meets the six conditions outlined in NUREG-2191 Section XI.M42 Element 4 (Detection of Aging Effects) for managing loss of coating or lining integrity under an alternate program. Therefore, the AMR line is considered a match with the referenced NUREG-2191 item where the alternate program is credited for managing the internal coating/lining.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 4

SLRA Table 3.3.2-30 is revised as follows:

Table 3.3.2-30 Auxiliary Systems - Potable Water System - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 894 Water Heater (potable)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Potable) (Internal) Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.G.A-416 3.3.1-138 A,1,3 E,1,3 Changed -

894 Water Heater (potable)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Potable) (Internal) Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.G.A-416 3.3.1-138 E,1,3 Difference

- 7308 Water Heater (potable)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Potable) (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.G.A-414 3.3.1-139 A,1,3 E,1,3 Changed -

7308 Water Heater (potable)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Potable) (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.G.A-414 3.3.1-139 E,1,3

3. Component meets the six conditions outlined in NUREG-2191 Section XI.M42 Element 4 (Detection of Aging Effects) for managing loss of coating or lining integrity under an alternate program. Therefore, the AMR line is considered a match with the referenced NUREG-2191 item where the alternate program is credited for managing the internal coating/lining.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 5

SLRA Table 3.3.2-31 is revised as follows:

Table 3.3.2-31 Auxiliary Systems - Primary and Demineralized Water Makeup System - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 4226 Tank (degasifier)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 A,7 E,7 Changed -

4226 Tank (degasifier)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 E,7 Difference

- 4043 Tank (degasifier)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 A,7 E,7 Changed -

4043 Tank (degasifier)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 E,7 Difference

- 4224 Tank (mixed bed demineralizer)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 A,7 E,7 Changed -

4224 Tank (mixed bed demineralizer)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 E,7 Difference

- 4047 Tank (mixed bed demineralizer)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 A,7 E,7 Changed -

4047 Tank (mixed bed demineralizer)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 E,7 Difference

- 4225 Tank (mixed bed polisher)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 A,7 E,7 Changed -

4225 Tank (mixed bed polisher)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 E,7 Difference

- 4045 Tank (mixed bed polisher)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 A,7 E,7 Changed -

4045 Tank (mixed bed polisher)

Structural Integrity Steel with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 E,7

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 6

Difference

- 4130 Valve Body Structural Integrity Ductile Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 A,7 E,7 Changed -

4130 Valve Body Structural Integrity Ductile Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 E,7 Difference

- 4131 Valve Body Structural Integrity Ductile Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 A,7 E,7 Changed -

4131 Valve Body Structural Integrity Ductile Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 E,7 Difference

- 4095 Valve Body Structural Integrity Ductile Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-415 3.3.1-140 A,7 E,7 Changed -

4095 Valve Body Structural Integrity Ductile Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-415 3.3.1-140 E,7 Difference

- 4180 Valve Body Structural Integrity Gray Cast Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 A,7 E,7 Changed -

4180 Valve Body Structural Integrity Gray Cast Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-416 3.3.1-138 E,7 Difference

- 4181 Valve Body Structural Integrity Gray Cast Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 A,7 E,7 Changed -

4181 Valve Body Structural Integrity Gray Cast Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-414 3.3.1-139 E,7 Difference

- 4099 Valve Body Structural Integrity Gray Cast Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-415 3.3.1-140 A,7 E,7 Changed -

4099 Valve Body Structural Integrity Gray Cast Iron with Internal Coating/Lining Raw Water (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.C1.A-415 3.3.1-140 E,7

7. Component meets the six conditions outlined in NUREG-2191 Section XI.M42 Element 4 (Detection of Aging Effects) for managing loss of coating or lining integrity under an alternate program. Therefore, the AMR line is considered a match with the referenced NUREG-2191 item where the alternate program is credited for managing the internal coating/lining.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 7

SLRA Table 3.4.2-14 is revised as follows:

Table 3.4.2-14 Steam and Power Conversion Systems - Turbine-Generator Lube Oil System - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 3254 Tank (lubricating oil reservoir)

Structural Integrity Steel with Internal Coating/Lining Lubricating Oil (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VIII.E.S-401 3.4.1-066 A,3 E,3 Changed -

3254 Tank (lubricating oil reservoir)

Structural Integrity Steel with Internal Coating/Lining Lubricating Oil (Internal)

Loss of Coating or Lining Integrity Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VIII.E.S-401 3.4.1-066 E,3 Difference

- 3257 Tank (lubricating oil reservoir)

Structural Integrity Steel with Internal Coating/Lining Lubricating Oil (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VIII.E.S-414 3.4.1-067 A,3 E,3 Changed -

3257 Tank (lubricating oil reservoir)

Structural Integrity Steel with Internal Coating/Lining Lubricating Oil (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VIII.E.S-414 3.4.1-067 E,3

3. Component meets the six conditions outlined in NUREG-2191 Section XI.M42 Element 4 (Detection of Aging Effects) for managing loss of coating or lining integrity under an alternate program. Therefore, the AMR line is considered a match with the referenced NUREG-2191 item where the alternate program is credited for managing the internal coating/lining.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 8

SLRA Section B2.1.25 is revised as follows:

Section B2.1.25 Program Description The following components are within the scope of subsequent license renewal due to potential for spatial interaction with safety-related SSCs and do not have any CLB safety function nor any function related to any 10 CFR 54.4(a)(3) regulated event. These components are internally coated or lined but are managed by the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components Program rather than the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks aging management program based on the following considerations:

x Component Cooling Water System steel with internal coating/lining valve bodies in waste water environment - Steel lined valve bodies subject to a waste water environment are located in the portions of the Component Cooling Water System that provide component cooling water to the abandoned in place boric acid evaporators. A plant modification isolated the steam supply approximately 20 years ago, rendering both boric acid evaporator skids non-functional. While the Component Cooling Water System supply and return connections were not removed, these lines were isolated at that time, with no procedural guidance in place that would align and restore the Boric Acid Evaporators to service. Valves CC-779A and CC-779B are within the isolation boundaries (i.e., are not boundary valves) established for the Component Cooling Water System with respect to the "A" and "B" Boric Acid Evaporators. Based on these considerations, these valves are presumed to have remained isolated from the active portion of the Component Cooling Water System since the evaporators were taken out of service. The Component Cooling Water System piping within this isolation boundary is not subject to infrequent operation and / or flushing that might cause detached coatings to migrate downstream. Detached linings from these components cannot cause downstream effects since the abandoned equipment is isolated from the in-service portion of the system by normally closed valves. The intended function of these valves is structural integrity. The environment in the abandoned equipment does not promote accelerated corrosion or microbiological induced corrosion of the base metal since the source of the waste water is component cooling water, which is treated with chromate.

Chromate is a corrosion inhibitor and is toxic to microbiological organisms. While the Chromate level within the isolation boundary is not actively managed, the fluid within the boundary at the time of isolation was chromated water, which would not represent a potential source of MIC bacteria. Likewise, any leakage by the isolation boundaries would have been from the Component Cooling Water System, which is chromated.

Without a source for the bacteria that causes MIC to be introduced, there is no potential for MIC to occur. A galvanic couple is not present since the adjacent piping is steel. A corrosion allowance has not been identified for the components.

x Potable Water System hot water heater tank - The Potable Water System is within the scope subsequent license renewal for the 10 CFR 54.4(a)(2) spatial criteria only.

Therefore, detach linings from the steel lined potable water heater cannot cause downstream effects that will prevent the accomplishment of an 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) intended function. The intended function of the water heater is structural integrity. The environment in the water heater does not promote accelerated corrosion or microbiologically induced corrosion of the base metal since well water is the water source for the Potable Water System. The well water supplying the Potable Water

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 9

System has a pH of approximately 7 and is not corrosive. It is used by the station for domestic (sanitary) use, including water for drinking fountains, lab sinks, washing of machinery, and makeup for the primary and secondary systems after it has been demineralized and chemically treated. This hot water heater supplies a bathroom in the Turbine Building, including lavatories and showers. Failure of the lining on the hot water heater tank would not impact any of the functions identified in 10 CFR 54.4(a)(1),(2) or (3). With regard to a galvanic couple at the connection of the copper supply line to the hot water tank, this installation is typical of hot water heaters of this nature and has proven to be acceptable in its ongoing and prevalent use in residential, commercial, and industrial applications. A corrosion allowance has not been identified for the hot water heater.

x Primary and Demineralized Water System degassifer tank, mixed bed demineralizer tank, mixed bed polisher tank, and associated water treatment skid valve bodies - The associated components are steel, ductile iron, and gray cast line components shown on boundary drawings RSLD-G-190202 sheets 3, 4, and 5. The most corrosive water chemistry for these components would be well water, which has been passed through a mobile demineralizer trailer for pre-treatment prior to being introduced into the Primary and Makeup Water System. At this point, the water is demineralized and has low conductivity, and would not promote corrosion or constitute a source of MIC. Detached coatings from these components cannot cause downstream affects that will prevent the accomplishment of an 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) intended function. Water passing through these demineralizer skid components is filtered and sampled before it enters the condensate storage tank. The intended function of these components is structural integrity. A galvanic couple is not present since maintenance procedures require installing of dielectric insulators to mitigate galvanic corrosion. A corrosion allowance has not been identified for these components.

x Penetration Pressurization Local Leak Rate Test air receivers - The A, B, C, and D penetration pressurization air receiver tanks provide a supply of compressed air or gas for 10 CFR 50 Appendix J local leak rate testing. During normal operations the system is isolated from containment penetrations by closed valves such that downstream effects resulting in a reduction in flow, drop in pressure, or reduction of heat transfer will not occur. The intended function of the air receivers is structural integrity for 10 CFR 54.4(a)(2) connected piping. Penetration Pressurization System utilizes a regulated supply of clean and dry compressed air from the instrument air system to test containment penetrations (local leak rate tests). It is only used during power operations to test the personnel hatch and during outages to perform local leak rate tests. The Penetration Pressurization Local Leak Rate Test air receiver tanks are connected to containment penetrations through a series of headers constructed of 3/8" (OD) tubing.

Pressure regulators are incorporated to reduce air pressure from 100 psig in the receiver tanks) to 46 psig at the penetrations. During Appendix J testing, potential leakage from penetrations would be determined by measurement of air flow in the header associated with the test. Subsequent to testing, pressurization of each penetration can be verified locally by closing off its air supply line, and opening a test connection at the penetration to observe the escape of the pressurizing medium. The Penetration Pressurization System receiver tanks, pressure regulators, instrumentation and tubing up to the point of connection to penetration test valves perform no safety function. The potential for internal coatings in the receiver tanks to migrate to the point where it might lodge under the seat of an isolation valve at a penetration test point is minimal given the design of the system. However, should that occur the result would be potential containment inleakage

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 10 from the higher pressure portions of the Penetration Pressurization System. As described in UFSAR Section 6.9.2.2, the potential for inleakage from the Penetration Pressurization system is not considered to be an operating or safety problem. The internal environment of the receiver tanks would neither promote accelerated corrosion or microbiological induced corrosion of the base metal. A galvanic couple is not present since the air environment in the attached piping does not provide an electrolyte necessary for galvanic corrosion to occur. A corrosion allowance has not been identified for these components.

x Turbine-Generator Lube Oil reservoir tank - The Turbine-Generator Lube Oil System is within the scope subsequent license renewal for 10 CFR 54.4(a)(2) spatial criteria only.

The intended function of the lube oil reservoir tank is structural integrity. The Turbine-Generator Lube Oil system does not perform 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) functions. The tank is required to maintain structural integrity to mitigate leakage that could interact with safety components in the general area. Failure of the tank due to detached linings might precipitate a unit shutdown but would not prevent the satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1), (2) or (3). The Turbine-Generator Lube Oil System is provided with a purification skid to remove water and contaminants and maintain the quality of Turbine-Generator lube oil at an acceptable level for unit operation. The lubricating oil in the Turbine-Generator Lube Oil System is monitored by the Lube Oil Analysis Aging Management Program and would not promote corrosion or microbiological activity. A galvanic couple is not present since lubricating oil is not an electrolyte which is necessary for galvanic corrosion to occur. A corrosion allowance has not been identified for these components.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 4 TRP 16

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 1, Attachment 4 Supplement changes to address incorporation of relevant guidance in MRP-227 Revision 2-A requirements in Enhancement 1 and update AMR line ID #7487.

(TRP 16)

Affected SLRA Section(s)/Table(s):

B2.1.7 3.1.2-3 2.3.1-3 A6.0 SLRA Page Numbers:

A-49 B-52 B-53 B-57 2-57 3-151 Description of Change:

This supplement item makes the changes identified below to the SLRA in response to TRP 16:

x Add a statement that all requirements within the final approved version of MRP-227 Revision 2-A that are relevant to Robinson will be incorporated into the Robinson PWR Vessel Internals AMP prior to entering the SPEO to Section B2.1.7, Enhancement 1 and Table A6.0-1, Commitment #7.

x For clarity, remove Element 6 Only text in Section B2.1.7, Enhancement 1 and Table A6.0-1, Commitment #7.

x In Table 2.3.1-3, change the component type for AMR line ID #7487 from Sample Bomb to Control Rod Guide Tube C-Tubes and Sheaths to be in alignment with document SLR-RNP-IPAR-M100 titled Subsequent License Renewal Integrated Plant Assessment of the Reactor Vessel, Internals, and Reactor Coolant Systems.

x In Table 3.1.2-1, change the component type for AMR line ID #7487 from Sample Bomb to Control Rod Guide Tube C-Tubes and Sheaths to be in alignment with document SLR-RNP-IPAR-M100 titled Subsequent License Renewal Integrated Plant Assessment of the Reactor Vessel, Internals, and Reactor Coolant Systems.

x In Section B2.1.7, revise Operating Experience #15 to state that MRP-227 A Rev 2-A in combination with ASME Section XI will be used to manage aging of the entire upper girth weld.

x Revise Section B2.1.7, Page B-52 to state that all Robinson reactor vessel internals items reported in the SLRA, Table 3.1.1, Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL-SLR Report, are confirmed to be within the scope of MRP-227 Revision 2-A, Tables 4-3, 4-6, 4-9, and 5-3.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 2

x Revise Section B2.1.7, Page B-52 to report that all vessel internals items within the scope of MRP-227-A were inspected during the baseline examinations (~40 years).

SLRA Revisions:

SLRA Section B2.1.7 is revised as follows:

Section B2.1.7 Program Description All vessel internals items within the scope of MRP-227, Revision 1-A were examined during the second MRP-227 inspection interval (~50 years) with the exception of the control rod guide tube (CRGT) guide cards. The CRGT guide card wear measurements are performed on a separate schedule in accordance with WCAP-17451-P, as required by MRP-227, Revision 1-A.

All vessel internals items within the scope of the ASME Code,Section XI, Table IWB-2500-1 were examined during the fifth inservice inspection interval, which ended on February 18, 2023.

The sixth interval inservice inspections have been planned and scheduled in accordance with the Robinson ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD aging management program.

All the in-scope RPV internal items will be examined during the sixth 10-year inservice inspection interval, with the exception of the CRGT guide card wear exams. The sixth inservice inspection interval began on February 19, 2023, and will end on February 18, 2033. The sixth inservice inspection interval examinations are scheduled to occur during the Fall 2032 refueling outage, which is two years after the beginning of the subsequent period of extended operation.

All Robinson reactor vessel internals items reported in the SLRA, Table 2.3.1-3 Reactor Vessel Internals," are confirmed to be within the scope of MRP-227 Revision 2-A.

Enhancements

1. The PWR Vessel Internals aging management program will be updated as necessary to provide guidance for implementing the changes to primary and expansion items in MRP-227, Rev 1-A, Tables 4-3, 4-6, 4-9 (and 4-9, and Table 5-3 for Element 6 only) as supplemented by as supplemented by MRP 2023-005, Revision 01, MRP 2023-005, Revision 01, MRP 2024-008, and the 2024-008, and the Robinson gap analysis.

Robinson gap analysis. Robinson will incorporate the revisions to MRP-227 Revision 1-A, Tables 4-3, 4-6, 4-9, and 5-3 reported in the final NRC approved version of MRP-227 Revision 2, into the Robinson PWR Vessel Internals program prior to entering the subsequent period of extended operation. The Robinson GAP analysis concluded that the primary and expansion items reported in MRP-227, Rev 2 Tables 4-3, 4-6, 4-9 (and Table 5-3 for Element 6 only) as supplemented by MRP 2023-005, Revision 01 and MRP 2024-008 are sufficient for the subsequent period of extended operation and that no additional measures are required for Robinson. will incorporate the revisions to MRP-227 Revision 1-A, Tables 4-3, 4-6, 4-9, and 5-3 reported in the final NRC approved version of MRP-227 Revision 2, into the Robinson PWR Vessel Internals program prior to entering the subsequent period of extended operation. The Robinson GAP analysis concluded that the primary and expansion items reported in MRP-227, Rev 2 Tables 4-3, 4-6, 4-9, and Table 5-3 as supplemented by MRP 2023-005, Revision 01 and MRP 2024-008 are sufficient for the subsequent period of extended operation and that no additional measures are required for Robinson. All requirements within the final approved version of MRP-227 Revision 2-A (ADAMS Accession No. ML25142A177) that

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 3

are relevant to Robinson will be incorporated into the Robinson PWR Vessel Internals aging management program prior to entering the period of extended operation.

Operating Experience

15. As reported in Robinson, Refuel 33 (R2R33), Fall 2022, Inservice Inspection Program Ninety Day Owners Activity Report and Analytical Evaluations (ADAMS ML23089A212) five linear indications were discovered in the vicinity of the core barrel upper girth weld.

Evaluation in accordance with IWB-3142.4 was performed for all five indications resulting in acceptance of four (Flaws 2, 3, 4, and 5) out of five for one additional 24-month cycle. The fifth indication (Flaw 1) exceeded the allowable flaw size for one additional 24-month cycle, and therefore, was remediated via crack arrest holes.

Remediated Flaw 1 was reinspected using visual examination (EVT-1) in November 2024 (R2R34) with no observable change in flaw length. The flaws that were not remediated (Flaws 2, 3, 4, and 5) were reinspected using ultrasonic examinations (UT) in November 2024 (R2R34) with no change in flaw length or depth. Robinson remediated Flaws 3 and 4 in R2R34 by placing two additional crack arrest holes and associated plugs in the core barrel. Flaws 2 and 5 remain unmitigated and are well within the acceptance criteria developed in accordance with the guidance reported in WCAP-17096-NP-A, Revision 3 [ADAMS ML23248A257]. The schedule for subsequent inspections of Flaws 1-5 shall be determined by the Robinson Inservice Inspection Program in accordance with ASME Section XI. Aging management of the upper girth weld for SLR shall be in accordance with ASME Section XI and MRP-227 Revision 2-A.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 4

SLRA Table 3.1.2-3 is revised as follows:

Table 3.1.2-3 Reactor Vessel, Internals, and Reactor Coolant System - Reactor Vessel Internals - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 7487 Sample Bomb Control Rod Guide Tube C-Tubes and Sheaths Structural Support Stainless Steel Reactor Coolant and Neutron Flux (External)

Loss of Material PWR Vessel Internals (B2.1.7) IV.B2.RP-345 3.1.1-059c C

Changed -

7487 Control Rod Guide Tube C-Tubes and Sheaths Structural Support Stainless Steel Reactor Coolant and Neutron Flux (External)

Loss of Material PWR Vessel Internals (B2.1.7) IV.B2.RP-345 3.1.1-059c C

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 5

SLRA Section 2.3.1.3 is revised as follows:

Section 2.3.1.3 Components Subject to Aging Management Review Table 2.3.1-3 Reactor Vessel Internals Component/Commodity Group Intended Functions Sample Bomb Control Rod Guide Tube C-Tubes and Sheaths Structural Support

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 6

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 7 PWR Vessel Internals (B2.1.7)

The PWR Vessel Internals AMP is an existing program that will be enhanced as follows:

1. The PWR Vessel Internals aging management program will be updated as necessary to provide guidance for implementing the changes to primary and expansion items in MRP-227, Rev 1-A, Tables 4-3, 4-6, 4-9 (and 4-9, and Table 5-3 for Element 6 only) as supplemented by as supplemented by MRP 2023-005, Revision 01, MRP 2023-005, Revision 01, MRP 2024-008, and the Robinson gap analysis. Robinson will incorporate the revisions to MRP-227 Revision 1-A, Tables 4-3, 4-6, 4-9, and 5-3 reported in the final NRC approved version of MRP-227 Revision 2, into the Robinson PWR Vessel Internals program prior to entering the subsequent period of extended operation. The Robinson GAP analysis concluded that the primary and expansion items reported in MRP-227, Rev 2 Tables 4-3, 4-6, 4-9 (and Table 5-3 for Element 6 only) as supplemented by MRP 2023-005, Revision 01 and MRP 2024-008 are sufficient for the subsequent period of extended operation and that no additional measures are required for Robinson. 2024-008, and the Robinson gap analysis. Robinson will incorporate the revisions to MRP-227 Revision 1-A, Tables 4-3, 4-6, 4-9, and 5-3 reported in the final NRC approved version of MRP-227 Revision 2, into the Robinson PWR Vessel Internals program prior to entering the subsequent period of extended operation. The Robinson GAP analysis concluded that the primary and expansion items Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 7

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule reported in MRP-227, Rev 2 Tables 4-3, 4-6, 4-9, and Table 5-3 as supplemented by MRP 2023-005, Revision 01 and MRP 2024-008 are sufficient for the subsequent period of extended operation and that no additional measures are required for Robinson. All requirements within the final approved version of MRP-227 Revision 2-A (ADAMS Accession No. ML25142A177) that are relevant to Robinson will be incorporated into the Robinson PWR Vessel Internals aging management program prior to entering the period of extended operation.

Changed

- 7 PWR Vessel Internals (B2.1.7)

The PWR Vessel Internals AMP is an existing program that will be enhanced as follows:

1. The PWR Vessel Internals aging management program will be updated as necessary to provide guidance for implementing the changes to primary and expansion items in MRP-227, Rev 1-A, Tables 4-3, 4-6, 4-9, and Table 5-3 as supplemented by MRP 2023-005, Revision 01, MRP 2024-008, and the Robinson gap analysis. Robinson will incorporate the revisions to MRP-227 Revision 1-A, Tables 4-3, 4-6, 4-9, and 5-3 reported in the final NRC approved version of MRP-227 Revision 2, into the Robinson PWR Vessel Internals program prior to entering the subsequent period of extended operation. The Robinson GAP analysis concluded that the primary and expansion items reported in MRP-227, Rev 2 Tables 4-3, 4-6, 4-9, and Table 5-3 as supplemented by MRP 2023-005, Revision 01 and MRP 2024-008 are sufficient for the subsequent period of extended Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 8

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule operation and that no additional measures are required for Robinson. All requirements within the final approved version of MRP-227 Revision 2-A (ADAMS Accession No. ML25142A177) that are relevant to Robinson will be incorporated into the Robinson PWR Vessel Internals aging management program prior to entering the period of extended operation.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 5 TRP 19 Steam Generator Surveillance

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 5 1, Attachment 5 Changes to Sections 1.5 and 1.7 (TRP 19 Steam Generator Surveillance )

Affected SLRA Section(s):

1.5 1.7 SLRA Page Numbers:

1-8 1-22 Description of Change:

Incorporate discussion on use of later revisions of industry documents endorsed by GALL-SLR R1.

SLRA Revisions:

SLRA Section 1.5 is revised as follows:

Section 1.5 This SLRA is structured in accordance with Regulatory Guide (RG) 1.188, Standard Format and Content for Applications to Renew Nuclear Plant Operating Licenses, and NEI 17-01, Industry Guideline for Implementing the Requirements of 10 CFR Part 54 for Subsequent License Renewal. In addition, Section 3.0, Aging Management Review Results and Appendix B, Aging Management Programs are structured to address the guidance provided in NUREG-2192, Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants. NUREG-2192 references NUREG-2191, Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report. NUREG-2191 was used to determine the adequacy of existing programs for purposes of managing aging and which existing programs should be augmented for SLR. NUREG-2191 (GALL-SLR), Revision 1 (ML25113A021 and ML25113A022) has endorsed updated editions/revisions of industry-generated technical references. These references, included in the Robinson SLRA, are considered acceptable based on the GALL-SLR, Revision 1 allowance for use of later/revisions of various industry-generated documents. The results of the aging management review (AMR),

using NUREG-2191, have been documented and are illustrated in table format in Section 3.0, Aging Management Review Results of this application.

SLRA Section 1.7 is revised as follows:

Section 1.7 1.7.24 NUREG-2191, Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report, July 2025

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 6 TRP 22

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 6 1, Attachment 6 Boraflex Monitoring Not Applicable (TRP 22)

Affected SLRA Section(s):

B1.5 SLRA Page Numbers:

B-8 Description of Change:

Table B1-1 Boraflex Monitoring Program (XI.M22) is updated from "Not Applicable for PWRs" to Not Applicable.

SLRA Revisions:

SLRA Table B1-1 is revised as follows:

Table B1-1 Correlation: NUREG-2191 Program with H. B. Robinson Steam Electric Plant Program NUREG-2191 Number NUREG-2191 Program H. B. Robinson Steam Electric Plant Program Appendix B

Reference XI.M22 Boraflex Monitoring Not Applicable to a PWR N/A

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 7 TRP 26

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 1, Attachment 7 Supplement changes to address issues related to TRP 26 Fire Protection (TRP 26)

Affected SLRA Section(s)/Table(s):

2.4-18 3.5.2.1.18 3.5.2-18 3.5.2.1.2 3.5.2-2 A6.0 B2.1.15 SLRA Page Numbers:

x Table 2.4-18, Page 2-197 x

Section 3.5.2.1.18, Page 3-889 x

Table 3.5.2-18, Pages 3-1026, 3-1027, and 3-1028 x

Section 3.5.2.1.2, Page 3-874 x

Table 3.5.2-2, Page 3-973 x

Table A6.0-1, Page A-57 x

Section B2.1.15, Page B-102 Description of Change:

The supplement item makes the changes identified below to the SLRA in response to TRP-26:

x SLRA Table 2.4-18, SLRA Section 3.5.2.1.18 and SLRA Table 3.5.2-18 for Miscellaneous Structural Commodities are updated based on the following changes.

Grout material for Fire Barriers component type is added utilizing NUREG-2191 item VII.G.A-806 and crediting the Structures Monitoring and Fire Protection AMPs. A fire barrier intended function is added for the drain/ curb component type and the Fire Protection program is credited. An Air - Outdoor environment is added for the steel and elastomer material type for fire barriers to address the moisture from rain along with a plant specific note to clarify the applicability of the AMR line item. Additionally, the Plant Specific Note 1 is revised to clearly state that the stainless-steel material type includes fasteners for fire wraps. Plant Specific Note 4 is added to state that structural berms are included in commodity type drains/curbs.

x SLRA Section 3.5.2.1.2 and SLRA Table 3.5.2-2 for the Reactor Auxiliary Building are updated to include NUREG-2191 item VII.G.A-90 for concrete elements and credits both the Structures Monitoring and Fire Protection AMPs.

x The Fire Protection AMP enhancements are revised to specify the applicable acceptance criteria for the components being managed. Both Table A6.0-1 Subsequent License Renewal Commitments and Section B2.1.15 are updated for the revised enhancements.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 2

SLRA Revisions:

SLRA Section 2.4.18 is revised as follows:

Section 2.4.18 Components Subject to Aging Management Review Table 2.4-18 Miscellaneous Structural Commodities Component/Commodity Group Intended Functions Drains/ Curbs Direct Flow Direct Flow; Fire Barrier SLRA Section 3.5.2.1.18 is revised as follows:

Section 3.5.2.1.18 Materials Components in Miscellaneous Structural Commodities the are constructed of the following materials:

x Grout Aging Effects Requiring Management Components in Miscellaneous Structural Commodities require aging management to address the following aging effects:

x Cracking, Loss of Material

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 3

SLRA Table 3.5.2-18 is revised as follows:

Table 3.5.2-18 Containments, Structures, and Component Supports - Miscellaneous Structural Commodities - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9263 Drains/ Curbs Direct Flow; Fire Barrier Concrete Air (External)

Cracking, Loss of Material Fire Protection (B2.1.15)

VII.G.A-90 3.3.1-060 A,4 New -

9310 Drains/ Curbs Direct Flow; Fire Barrier Concrete Air (External)

Cracking, Loss of Material Structures Monitoring (B2.1.34)

VII.G.A-90 3.3.1-060 A,4 New -

9266 Fire Barriers Fire Barrier Elastomer, Rubber and Other Similar Materials Air - Outdoor (External)

Hardening, Loss of Strength, or Shrinkage Fire Protection (B2.1.15)

VII.G.A-19 3.3.1-057 A

New -

9261 Fire Barriers Fire Barrier Grout Air (External)

Loss of Material, Cracking/Delamination, Change in Material Properties, Separation Fire Protection (B2.1.15)

VII.G.A-806 3.3.1-268 A

New -

9265 Fire Barriers Fire Barrier Steel Air - Outdoor (External)

Loss of Material Fire Protection (B2.1.15)

VII.G.AP-150 3.3.1-058 C,3 Difference

- 5480 Fire Barriers Fire Barrier Steel Air (External)

Loss of Material Fire Protection (B2.1.15)

VII.G.AP-150 3.3.1-058 C,1 C,3 Changed -

5480 Fire Barriers Fire Barrier Steel Air (External)

Loss of Material Fire Protection (B2.1.15)

VII.G.AP-150 3.3.1-058 C,3 Plant Specific Notes:

1. Steel and stainless steel Stainless steel material includes fasteners used to secure fire barrier wraps in place are evaluated as fire barriers -

penetration seals and are evaluated as Fire Barriers component type.

3. Steel material evaluated as Fire Barriers component type includes fasteners used to secure fire barrier wraps in place and fire wall panels/ skirting.

4. Drains/Curbs include structural berms.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 4

SLRA Section 3.5.2.1.2 is revised as follows:

Section 3.5.2.1.2 Aging Effects Requiring Management Components in Reactor Auxiliary Building require aging management to address the following aging effects:

x Cracking, Loss of Material

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 5

SLRA Table 3.5.2-2 is revised as follows:

Table 3.5.2-2 Containments, Structures, and Component Supports - Reactor Auxiliary Building - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9259 Concrete Elements Fire Barrier; Flood Barrier; Missile Barrier;

Shelter, Protection; Structural Support Concrete Air (External)

Cracking, Loss of Material Fire Protection (B2.1.15)

VII.G.A-90 3.3.1-060 A,1,4 New -

9260 Concrete Elements Fire Barrier; Flood Barrier; Missile Barrier;

Shelter, Protection; Structural Support Concrete Air (External)

Cracking, Loss of Material Structures Monitoring (B2.1.34)

VII.G.A-90 3.3.1-060 A,1,4

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 6

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 15 Fire Protection (B2.1.15)

The Fire Protection aging management program is an existing program that will be enhanced to:

1. Revise procedures governing the visual inspection of fire dampers to include inspection parameters for identification of corrosion that could lead to loss no visual indication of material.

corrosion.

2. Perform periodic visual inspections on a refueling outage interval for identification of corrosion that could lead to no indications of excessive loss of material on the external surfaces of the carbon dioxide, Halon, and clean agent fire suppression systems.

Program enhancements for SLR will be implemented six months prior to the SPEO.

Changed

- 15 Fire Protection (B2.1.15)

The Fire Protection aging management program is an existing program that will be enhanced to:

1. Revise procedures governing the visual inspection of fire dampers to include inspection parameters for no visual indication of corrosion.

2. Perform periodic visual inspections on a refueling outage interval for no indications of excessive loss of material on the external surfaces of the carbon dioxide, Halon, and clean agent fire suppression systems.

Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 7

SLRA Section B2.1.15 is revised as follows:

Section B2.1.15 Enhancements

1. Revise procedures governing the visual inspection of fire dampers to include inspection parameters for identification of corrosion that could lead to loss of material. (Elements 3 no visual indication of corrosion. (Elements 3, 4, and 6)

2. Perform periodic visual inspections on a refueling outage interval for identification of corrosion that could lead to no indications of excessive loss of material on the external surfaces of the carbon dioxide, Halon, and clean agent fire suppression systems.

(Elements 3, 4, and 6)

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 8 TRP 33

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 1, Attachment 8 TRP 33 - Selective Leaching Supplement Items (TRP 33)

Affected SLRA Section(s):

A2.1.21 A6.0 B2.1.21 SLRA Page Numbers:

A - 19 A - 66 B - 133 Description of Change:

Including components in soil as in-scope. Providing description of raw water and waste water environments for combining populations. Describing coal tar coatings used for buried components.

SLRA Revisions:

SLRA Section A2.1.21 is revised as follows:

Section A2.1.21 The Selective Leaching aging management program is a new condition monitoring program that will monitor components constructed of materials which are susceptible to selective leaching.

Susceptible materials are gray cast iron, ductile iron, and copper alloys containing greater than 15 percent zinc. The Selective Leaching program includes a one-time inspection for susceptible components exposed to treated water or closed cycle cooling water environments since plant-specific OE has not revealed evidence of selective leaching in these environments. Periodic and opportunistic inspections will be performed on components susceptible to selective leaching that are exposed to raw water and waste water water, waste water, and soil environments.

Visual inspections supplemented by mechanical examination techniques such as chipping or scraping (for ductile iron and gray cast iron components) will be conducted on a representative sample of susceptible components. In addition, periodic destructive examinations of components for physical properties (i.e., degree of dealloying, depth of dealloying, wall thickness, and chemical composition) will be conducted for components exposed to selective leaching susceptible environments. Inspections and tests will be conducted to determine whether loss of material due to selective leaching will affect the ability of the components to perform their intended function for the SPEO. Inspections will be conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset and surface conditions as appropriate. When the acceptance criteria are not met such that it is determined that the affected component should be replaced prior to the end of the SPEO, additional inspections will be performed.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 2

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 21 Selective Leaching (B2.1.21)

The Selective Leaching AMP is a new condition monitoring program that will monitor components in selective leaching susceptible environments (treated water, closed cycle cooling water, raw water, and waste water) constructed of gray cast iron, ductile iron, and copper alloys containing greater than 15 percent zinc. The Selective Leaching program includes a one-time inspection for susceptible components exposed to treated water or closed cycle cooling water environments since plant-specific OE has not revealed evidence of selective leaching in these environments.

Periodic and opportunistic inspections will be performed on components susceptible to selective leaching that are exposed to raw water and waste water water, waste water, and soil environments. In addition, periodic destructive examinations of components for physical properties will be conducted for components exposed to selective leaching susceptible environments.

Industry and plant-specific OE will be considered in the development of this program.

Program will be implemented, and the initial round of inspections will be completed six months prior to the SPEO, or no later than the last refueling outage prior to the SPEO.

Changed

- 21 Selective Leaching (B2.1.21)

The Selective Leaching AMP is a new condition monitoring program that will monitor components in selective leaching susceptible environments (treated water, closed cycle cooling water, raw water, and waste water) constructed of gray cast iron, ductile iron, and copper alloys containing greater than 15 percent zinc. The Selective Leaching program includes a one-time inspection for susceptible components exposed to treated water or closed cycle cooling water environments since plant-specific OE Program will be implemented, and the initial round of inspections will be completed six months prior to the SPEO, or no later than the last

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 3

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule has not revealed evidence of selective leaching in these environments.

Periodic and opportunistic inspections will be performed on components susceptible to selective leaching that are exposed to raw water, waste water, and soil environments. In addition, periodic destructive examinations of components for physical properties will be conducted for components exposed to selective leaching susceptible environments.

Industry and plant-specific OE will be considered in the development of this program.

refueling outage prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 4

SLRA Section B2.1.21 is revised as follows:

Section B2.1.21 Program Description The Selective Leaching aging management program is a new condition monitoring program that includes a one-time inspection for components of materials susceptible to selective leaching that are exposed to a treated water or closed-cycle cooling water environment since plant-specific operating experience has not revealed evidence of selective leaching in these environments. The program includes periodic and opportunistic inspections for components exposed to raw water and waste water environments. Susceptible components exposed to soil will be excluded from inspection due to all in scope external surfaces being coated and review of operating experience reveals no indication of coating damage. If future opportunistic inspection reveals indication of coating damage in the scope of buried Selective Leaching aging management program components, soil environment populations will be subject to periodic inspections. water, waste water, and soil environments.

Visual inspections supplemented by mechanical examination techniques such as chipping or scraping (for ductile iron and gray cast iron components) will be conducted. Periodic destructive examinations of components for physical properties (i.e., degree of dealloying, depth of dealloying, remaining wall thickness, and chemical composition) will be conducted for components exposed to treated water, closed cycle cooling water, raw water, and waste water environments. Inspections and tests will be conducted to determine whether selective leaching is occurring and whether loss of material will affect the ability of the components to perform their intended function for the subsequent period of extended operation.

Components in the scope of the Selective Leaching aging management program include piping and piping components, valve bodies, pump casings, and other components that are constructed of susceptible materials and exposed to environments conducive to selective leaching. Materials susceptible to selective leaching which are in the scope of this program are gray cast iron, ductile iron, and copper alloys containing greater than 15 percent zinc.

Environments that promote susceptibility to selective leaching include closed cycle cooling water, treated water, raw water, waste water, and soil.

Components in raw water and waste water environments will be combined into the same population for inspection. Raw water and waste water were evaluated to determine which environment is most conducive to selective leaching of susceptible materials. Raw water is pumped from Lake Robinson; this presents a more conducive environment for selective leaching when compared to the waste water environment. At Robinson, waste water environments exist where previously treated water has been isolated from the rest of its respective system. Because the water can no longer recirculate, chemistry can no longer be maintained and the water is deemed waste water. While not being chemically controlled, the waste water still does not present as severe of an environment as raw water due to being isolated from water sources with biological, chemical, and physical impurities. For each periodic selection of components to be inspected in raw water and waste water environments, most inspections will occur in the more severe raw water environment. The auxiliary steam system contains one grey cast iron and one ductile iron component within a waste water environment; both components shall be inspected. The population of copper alloy (>15% Zinc) in a waste water environment consists of two components, of which one will be inspected.

The selective leaching susceptible components in a soil environment are within the Fire Protection system. To mitigate the effects of selective leaching, these components are coated in

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 5

coal tar epoxy. Originally installed buried piping was coated in coal tar epoxy per vendor specifications. New or modified buried piping at Robinson is coated in coal tar epoxy per site procedures and specifications. Periodic, opportunistic, and destructive inspections will be performed to ensure selective leaching of buried components does not affect the ability of components to perform their intended functions through the SPEO.

The selective leaching process involves the preferential removal of one of the alloying components from the material. Dezincification (loss of zinc from brass) and graphitization or graphitic corrosion (removal of iron from gray cast iron and ductile iron) are examples of such a process. High operating temperatures, stagnant-flow conditions, and a corrosive environment (e.g., acidic solutions for brasses with high zinc content and dissolved oxygen) are particularly conducive to selective leaching of susceptible materials. These factors will be considered during the selection of sample components to be inspected. A dealloyed component often retains its shape and may appear to be unaffected; however, the functional cross-section of the material has been reduced. The aging effect attributed to selective leaching is loss of material because the affected volume has a permanent change in density and does not retain mechanical properties that can be credited for structural integrity.

Inspections are conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset and surface conditions as appropriate. Results will be evaluated against acceptance criteria to confirm that the sampling bases (e.g., selection, size, frequency) will maintain the intended functions of components throughout the SPEO based on the projected rate and extent of degradation. The acceptance criteria are: (a) for copper-based alloys, no noticeable change in color from the normal yellow color to the reddish copper color or green copper oxide; (b) for gray cast iron and ductile iron, the absence of a surface layer that can be easily removed by chipping or scraping or as identified in the destructive examinations, (c) the presence of no more than a superficial layer of dealloying, as determined by removal of the dealloyed material by mechanical removal, and (d) the components meet system design requirements such as minimum wall thickness, when extended to the end of the SPEO.

When the acceptance criteria are not met such that it is determined that the affected component should be replaced prior to the end of the SPEO, additional inspections will be performed. If subsequent inspections do not meet acceptance criteria, an extent of condition and extent of cause analysis will be conducted to determine the further extent of inspections.

This program will be implemented and initial inspections will be performed within the 10-year period prior to the SPEO.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 9 TRP 40

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 9 1, Attachment 9 Monitoring of Neutron-Absorbing Materials Other Than Boraflex (TRP 40)

Affected SLRA Section(s):

B1.5 SLRA Page Numbers:

B-9 Description of Change:

Table B1-1 Monitoring of Neutron-Absorbing Materials Other Than Boraflex (XI.M40) is updated from "Not Applicable to PWRs" to "Not Applicable".

SLRA Revisions:

SLRA Table B1-1 is revised as follows:

Table B1-1 Correlation: NUREG-2191 Program with H. B. Robinson Steam Electric Plant Program NUREG-2191 Number NUREG-2191 Program H. B. Robinson Steam Electric Plant Program Appendix B

Reference XI.M40 Monitoring of Neutron-Absorbing Materials other than Boraflex Not Applicable to a PWR N/A

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 10 TRP 47

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 1, Attachment 10 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants (TRP 47)

Affected SLRA Section(s):

A6.0 B2.1.35 SLRA Page Numbers:

A-91 B-215 Description of Change:

Updated Enhancement #6 for RG1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants to specify that inspections of underwater water-controlled structures are also to be inspected every 5 years.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 2

SLRA Revisions:

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 35 Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35)

The Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP is an existing program that will be enhanced to:

1. For structural bolting consisting of ASTM A325, ASTMF1852, ASTM F2280 and/or ASTM A490, provide guidance for storage, lubricant selection, and bolting and coating material selection in Section 2 of RCSC (Research Council for Structural Connections) publication, Specification for Structural Joints Using High-Strength Bolts.

2. Provide guidance so that when replacement bolting is required, bolting and coating material, installation torque or tension, and use of lubricants and sealants will be in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339.

3. Provide guidance for proper specification of new high strength bolting and coating material, and lubricant to prevent or mitigate degradation and failure of structural bolting in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339.

4. Provide inspection and evaluation criteria for structural concrete using quantitative second tier criteria of Chapter 5 in ACI 349.3R.

The program will be enhanced to reference ACI 201.1R and incorporate conditions at junctions with abutments and Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 3

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule embankments, pattern cracking with darkened edges, the changes in material properties of increase in porosity and permeability, and loss of strength.

5. Require that personnel performing inspections and evaluations meet the qualifications specified within ACI 349.3R with respect to knowledge of inservice inspection of concrete and visual acuity requirements.

6. Require that periodic inspections are to be performed at least once every 5 years. years, including underwater inspections of water-controlled structures.

7. Create provisions for special inspections immediately following the occurrence of significant natural phenomena, such as large floods, earthquakes, hurricanes, tornadoes, or intense local rainfalls.

8. Require the evaluation of raw water and groundwater chemistry that is sampled from a location that is representative of the water in contact with structures within the scope of subsequent license renewal by the responsible engineer. This will be done on an interval not to exceed 5 years and account for seasonal variations (e.g., quarterly monitoring every 5th year).

9. Develop a new implementing procedure or revise an existing implementing procedure to enhance the aging management of inaccessible areas exposed to potentially aggressive groundwater/soil environment that will include the following:

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 4

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule x

Monitor raw water and ground water chemistry, for pH, chlorides, and sulfates, on a frequency not to exceed five years that accounts for seasonal variations (e.g., quarterly monitoring every fifth year), from locations that are representative of the groundwater in contact with structures within the scope of subsequent license renewal.

x Enter adverse results, which exceed water chemistry criteria, into the corrective action program. As part of the corrective actions, if aggressive groundwater is identified that might affect structures in scope for license renewal, perform additional water testing at additional locations and perform soil testing in order to confirm the extent, severity, and potential aging mechanisms resulting from the aggressive groundwater/soil.

x Develop engineering evaluations to evaluate the water chemistry results to assess the impact, if any, on below-grade concrete, including the potential for further degradation due to the aggressive groundwater, as well as consideration of current conditions. As part of the engineering evaluations, determine if additional actions are warranted, which might include enhanced inspection techniques and/or increased frequency, destructive testing, and focused inspections of representative accessible (leading indicator) or below grade, inaccessible concrete structural elements exposed to aggressive groundwater/soil.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 5

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule x

Develop the initial engineering evaluations prior to the subsequent period of extended operation. Develop follow-up engineering evaluations on an interval not to exceed five years.

x If aggressive groundwater and soil is identified, at a minimum, perform focused inspections of representative, accessible (leading indicator) structural elements, or if accessible areas will not be leading indicators for the potential aging mechanisms, excavate and inspect buried concrete elements exposed to aggressive groundwater/soil.

x If degraded concrete is identified, as part of the focused inspections of leading indicators (representative, accessible or exposed inaccessible concrete), enter adverse results that exceed ACI 349.3R second-tier criteria into the corrective action program, and expose inaccessible concrete so that the extent of the condition can be determined, baseline conditions documented, and additional actions identified such as repairs, new preventative actions, additional evaluations, and future inspections.

10. Monitor and trend through-wall groundwater leakage, infiltration volumes, and leakage water chemistry for signs of concrete or steel reinforcement degradation. Develop additional engineering evaluations, which consider more frequent inspections, as well as destructive testing of affected concrete to validate existing concrete properties, and leakage water chemistry results. If leakage volumes allow, consider water chemistry analysis of the

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 6

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule leakage pH, along with mineral, chloride, sulfate and iron content in the water.

11. Perform inspections under the enhanced program in order to establish quantitative baseline inspection data to a sufficient detail to allow for trending, prior to the subsequent period of extended operation.

12. Provide evaluation criteria for structural concrete using quantitative second tier criteria of Chapter 5 in ACI 349.3R. Base the acceptance criteria for concrete surfaces on the second-tier evaluation criteria provided in Chapter 5 of ACI 349.3R.

13. Clarify that loose bolts and nuts are not acceptable unless accepted by engineering evaluation.

14. Degradation of sheeting and piles is accepted by engineering evaluation or subject to corrective actions.

15. Revise inspection procedures to base inspection acceptance criteria on quantitative requirements derived from industry codes and standards, including but not limited to SEI/ASCE 11, or the relevant AISC specifications and consider industry and plant OE.

Use justified quantitative acceptance criteria whenever applicable.

Changed

- 35 Inspection of Water-Control Structures Associated with The Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP is an existing program that will be enhanced to:

Program enhancements for SLR will be

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 7

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Nuclear Power Plants (B2.1.35)

1. For structural bolting consisting of ASTM A325, ASTMF1852, ASTM F2280 and/or ASTM A490, provide guidance for storage, lubricant selection, and bolting and coating material selection in Section 2 of RCSC (Research Council for Structural Connections) publication, Specification for Structural Joints Using High-Strength Bolts.

2. Provide guidance so that when replacement bolting is required, bolting and coating material, installation torque or tension, and use of lubricants and sealants will be in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339.

3. Provide guidance for proper specification of new high strength bolting and coating material, and lubricant to prevent or mitigate degradation and failure of structural bolting in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339.

4. Provide inspection and evaluation criteria for structural concrete using quantitative second tier criteria of Chapter 5 in ACI 349.3R.

The program will be enhanced to reference ACI 201.1R and incorporate conditions at junctions with abutments and embankments, pattern cracking with darkened edges, the changes in material properties of increase in porosity and permeability, and loss of strength.

5. Require that personnel performing inspections and evaluations meet the qualifications specified within ACI 349.3R with respect implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 8

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule to knowledge of inservice inspection of concrete and visual acuity requirements.

6. Require that periodic inspections are to be performed at least once every 5 years, including underwater inspections of water-controlled structures.

7. Create provisions for special inspections immediately following the occurrence of significant natural phenomena, such as large floods, earthquakes, hurricanes, tornadoes, or intense local rainfalls.

8. Require the evaluation of raw water and groundwater chemistry that is sampled from a location that is representative of the water in contact with structures within the scope of subsequent license renewal by the responsible engineer. This will be done on an interval not to exceed 5 years and account for seasonal variations (e.g., quarterly monitoring every 5th year).

9. Develop a new implementing procedure or revise an existing implementing procedure to enhance the aging management of inaccessible areas exposed to potentially aggressive groundwater/soil environment that will include the following:

x Monitor raw water and ground water chemistry, for pH, chlorides, and sulfates, on a frequency not to exceed five years that accounts for seasonal variations (e.g., quarterly monitoring every fifth year), from locations that are

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 9

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule representative of the groundwater in contact with structures within the scope of subsequent license renewal.

x Enter adverse results, which exceed water chemistry criteria, into the corrective action program. As part of the corrective actions, if aggressive groundwater is identified that might affect structures in scope for license renewal, perform additional water testing at additional locations and perform soil testing in order to confirm the extent, severity, and potential aging mechanisms resulting from the aggressive groundwater/soil.

x Develop engineering evaluations to evaluate the water chemistry results to assess the impact, if any, on below-grade concrete, including the potential for further degradation due to the aggressive groundwater, as well as consideration of current conditions. As part of the engineering evaluations, determine if additional actions are warranted, which might include enhanced inspection techniques and/or increased frequency, destructive testing, and focused inspections of representative accessible (leading indicator) or below grade, inaccessible concrete structural elements exposed to aggressive groundwater/soil.

x Develop the initial engineering evaluations prior to the subsequent period of extended operation. Develop follow-up engineering evaluations on an interval not to exceed five years.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 10 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule x

If aggressive groundwater and soil is identified, at a minimum, perform focused inspections of representative, accessible (leading indicator) structural elements, or if accessible areas will not be leading indicators for the potential aging mechanisms, excavate and inspect buried concrete elements exposed to aggressive groundwater/soil.

x If degraded concrete is identified, as part of the focused inspections of leading indicators (representative, accessible or exposed inaccessible concrete), enter adverse results that exceed ACI 349.3R second-tier criteria into the corrective action program, and expose inaccessible concrete so that the extent of the condition can be determined, baseline conditions documented, and additional actions identified such as repairs, new preventative actions, additional evaluations, and future inspections.

10. Monitor and trend through-wall groundwater leakage, infiltration volumes, and leakage water chemistry for signs of concrete or steel reinforcement degradation. Develop additional engineering evaluations, which consider more frequent inspections, as well as destructive testing of affected concrete to validate existing concrete properties, and leakage water chemistry results. If leakage volumes allow, consider water chemistry analysis of the leakage pH, along with mineral, chloride, sulfate and iron content in the water.

11. Perform inspections under the enhanced program in order to establish quantitative baseline inspection data to a sufficient

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 11 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule detail to allow for trending, prior to the subsequent period of extended operation.

12. Provide evaluation criteria for structural concrete using quantitative second tier criteria of Chapter 5 in ACI 349.3R. Base the acceptance criteria for concrete surfaces on the second-tier evaluation criteria provided in Chapter 5 of ACI 349.3R.

13. Clarify that loose bolts and nuts are not acceptable unless accepted by engineering evaluation.

14. Degradation of sheeting and piles is accepted by engineering evaluation or subject to corrective actions.

15. Revise inspection procedures to base inspection acceptance criteria on quantitative requirements derived from industry codes and standards, including but not limited to SEI/ASCE 11, or the relevant AISC specifications and consider industry and plant OE.

Use justified quantitative acceptance criteria whenever applicable.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 12 SLRA Section B2.1.35 is revised as follows:

Section B2.1.35 Enhancements

6. Require that periodic inspections are to be performed at least once every 5 years. years, including underwater inspections of water-controlled structures. (Element 4)

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 11 TRP 60

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 1, Attachment 11 Supplement changes to address issues related to TRP-060 (TRP 60)

Affected SLRA Section(s):

B3.1 SLRA Page Numbers:

B-258 Description of Change:

TRP-Q1: This supplement removes mention of managing the pressurizer spray line for SLR with an Appendix L evaluation in SLRA Section B3.1 OE#1. This change will eliminate the inconsistency between SLRA Sections 4.3.4 and B3.1. This supplement also illustrates that the pressurizer spay line CUFen is well below unity at the end of SPEO.

SLRA Revisions:

SLRA Section B3.1 is revised as follows:

Section B3.1 Operating Experience

1. In 2013 Duke Energy performed an internal fleet wide self-assessment of the Fatigue Monitoring aging management program. The purpose of this effort was to assess the status of the program at each nuclear site for full scope and depth to ensure each program adhered to best industry practice standards. Any gaps or shortcoming that were identified within the self-assessment were resolved.

The conclusion of the internal assessment for Robinson recommended performing a better review of plant data for cycle counting, an evaluation of the fatigue effects of stratification for the pressurizer spray line, and an evaluation for the fatigue effects of the pressurizer relief valve inlet piping with cooler temperatures.

In 2014 a vendor performed a Duke Energy fleet wide assessment of the Fatigue Monitoring aging management program. The vendor review was extremely comprehensive in scope and depth. The conclusion of the external assessment for Robinson recommended performing a better review of plant data for cycle counting, an increase industry benchmarking for collaborative learning, to review operations to reduce thermal transients of various components, and to evaluate the fatigue effects of the pressurizer relief valve inlet piping with respect to temperature.

For SLR, thermal stratification of the pressurizer spray line and the effects of fatigue and environmentally-assisted fatigue were evaluated. The upper and lower pressurizer spray line and the auxiliary spray line were analyzed. It was determined that the upper portion of the spray line experiences more severe fatigue driven transients than the other portions of the piping and thus is a limiting location. This location has been included in the Fatigue Monitoring aging management program and has been dispositioned with an ASME Section XI Appendix L Flaw Tolerance Evaluation. Westinghouse determined that the CUFEN value for the pressurizer spray line at the end of SPEO is well below 1.0, thus

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 2

this is not considered a sentinel location.

For SLR the effects of fatigue and environmentally-assisted fatigue were evaluated for the pressurizer relief valve inlet piping. This piping is insulated to ensure performance of valves when they open and to ensure the piping surrounding the valves are subjected to acceptable stress levels during various loading conditions. The inlet piping to the relief valves experience thermal stresses during a valve opening event. The number of valve opening occurrences are significantly lower than typical ASME Section III design cycles of 40 for the power operated relief valves and 100 for the safety relief valves. From a projection of expected relief valve opening transients to 80 years of operation, CUFen is well below 1.0.

Both the internal and external Fatigue Monitoring program self-assessment concluded that the Robinson program meet the industry best practices.

Operating experience example 1 provides objective evidence that the Fatigue Management aging management program is being effectively implemented to monitor components for fatigue usage during the first period of extended operation, and continued implementation of the Fatigue Monitoring aging management program will assure that the monitored components will continue to perform their intended functions during the subsequent period of extended operation.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 12 TRP 74

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 1, Attachment 12 TRP 74 - Concrete Supplement Updates for Reactor Auxiliary Building and Reservoir and Dam AMR Tables (TRP 74)

Affected SLRA Table(s):

3.5.2-2 3.5.2-24 SLRA Page Numbers:

3-974, 3-975 3-1046 Description of Change:

SLRA Table 3.5.2-2, Reactor Auxiliary Building, is updated to add the aging effects of loss of material (spalling, scaling) and cracking due to freeze-thaw (AMR Item 3.5.1-042) and increase in porosity and permeability, loss of strength due to leaching of calcium hydroxide (AMR Item 3.5.1-047).

SLRA Table 3.5.2-24, Reservoir and Dam, is updated to align AMR ID 9229 to SRP Item III.A6.TP-31 instead of SRP Item III.A3.TP-31.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 2

SLRA Revisions:

SLRA Table 3.5.2-2 is revised as follows:

Table 3.5.2-2 Containments, Structures, and Component Supports - Reactor Auxiliary Building - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9301 Concrete Elements Fire Barrier; Flood Barrier; Missile Barrier;

Shelter, Protection; Structural Support Concrete Groundwater/Soil (External)

Loss of Material (Spalling, Scaling),

Cracking Structures Monitoring (B2.1.34) III.A3.TP-108 3.5.1-042 A,1,4 New -

9302 Concrete Elements Fire Barrier; Flood Barrier; Missile Barrier;

Shelter, Protection; Structural Support Concrete Water - Flowing (External)

Increase in Porosity and Permeability, Loss of Strength Structures Monitoring (B2.1.34)

III.A3.TP-67 3.5.1-047 A,1,4

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 3

SLRA Table 3.5.2-24 is revised as follows:

Table 3.5.2-24 Containments, Structures, and Component Supports - Reservoir and Dam - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 9229 Concrete Elements

Shelter, Protection; Structural Support Concrete Water - Flowing (External)

Reduction in Foundation Strength, Cracking Structures Monitoring (B2.1.34) III.A3.TP-31 III.A6.TP-31 3.5.1-046 A,1 Changed -

9229 Concrete Elements

Shelter, Protection; Structural Support Concrete Water - Flowing (External)

Reduction in Foundation Strength, Cracking Structures Monitoring (B2.1.34) III.A6.TP-31 3.5.1-046 A,1

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 13 TRP 84

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 13 1, Attachment 13 SS Nickel Alloy Aluminum Alloy Further Evaluations (TRP 84)

Affected SLRA Section(s)/Table(s):

3.3.2.2.8 3.3.2-18 3.3.2-36 3.3.2-37 SLRA Page Numbers:

x 3-320 x

3-321 x

3-539 x

3-652 x

3-669 Description of Change:

The following changes are made to the Robinson SLRA in response to TRP 84:

x SLRA Section 3.3.2.2.8, the discussion of AMR Item 3.3.1-189 on SLRA Page 3-320 receives the following additional bulleted item:

The damper housings in the HVAC Auxiliary Building System are constructed of 3xxx series Aluminum which is not susceptible to stress corrosion cracking.

x SLRA Section 3.3.2.2.8, the discussion of AMR Item 3.3.1-233 on SLRA Page 3-321 is replaced with the following text:

[3.3.1-233] - The insulated aluminum piping, piping components, or tanks exposed to indoor and outdoor air environments with the potential for condensation in the scope of subsequent license renewal in the Service Water System and the Fire Protection System are constructed of 6xxx series Aluminum in the T-6 temper, and not susceptible to stress corrosion cracking. Plant-specific notes are provided in the aging management review tables to indicate the grade of Aluminum for the insulated components not susceptible to stress corrosion cracking and the basis for the determination.

x The SLRA Table 3.3.2-18, Auxiliary Systems - HVAC Auxiliary Building - Aging Management Evaluation, Plant Specific Note 2 is updated to provide specific detail regarding the management of SCC for aluminum damper housings.

x The SLRA Table 3.3.2-36, Auxiliary Systems - Service Water System - Aging Management Evaluation, Plant Specific Note 9 is updated to provide specific detail regarding the management of SCC for aluminum components.

x SLRA Table 3.3.2-37, Auxiliary Systems - Site Fire Protection System - Aging Management Evaluation, Plant Specific Note 3 is updated to provide specific detail regarding the management of SCC for aluminum components.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 13 2

SLRA Revisions:

SLRA Section 3.3.2.2.8 is revised as follows:

Section 3.3.2.2.8

[3.3.1-189] - This item is aligned to the following SSCs:

x Filter bodies in the Instrument Air System are constructed of an unknown aluminum alloy series, and therefore are evaluated as susceptible to SCC. These components are exposed to a halide free internal environment of dry air and a non-aggressive external environment of outdoor air in the Turbine Building. These filter bodies are not encapsulated in materials containing halides or exposed to secondary sources of moisture or halides.

x The damper housings in the HVAC Auxiliary Building System are constructed of 3xxx series Aluminum which is not susceptible to stress corrosion cracking.

[3.3.1-233] - The insulated aluminum piping, piping components, or tanks exposed to air or condensation in the scope of subsequent license renewal indoor and outdoor air environments with the potential for condensation in Auxiliary Systems are the scope of subsequent license renewal in the Service Water System and the Fire Protection System are constructed of 6xxx series Aluminum in the T-6 temper, and not susceptible to stress corrosion cracking. Plant-specific notes are provided in the aging management review tables to indicate the grade of Aluminum for the insulated components not susceptible to stress corrosion cracking and the basis for the determination.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 13 3

SLRA Table 3.3.2-18 is revised as follows:

Plant Specific Notes:

2. Material of construction is 3xxx series Aluminum Series Aluminum, which is not susceptible to stress corrosion cracking per NUREG 2192 Section 3.3.2.2.8. NUREG-2192 Section 3.3.2.2.8. AMR lines are not provided to address stress corrosion cracking since the alloy is not susceptible.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 13 4

SLRA Table 3.3.2-36 is revised as follows:

Plant Specific Notes:

9. Material of construction is Aluminum alloy 6063-T6 which is not susceptible to stress corrosion cracking per NUREG-2192 Section 3.3.2.2.8. 6063 in the T-6 temper, which is not susceptible to stress corrosion cracking per NUREG-2192 Section 3.3.2.2.8. AMR lines are not provided to address stress corrosion cracking since the alloy is not susceptible.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 13 5

SLRA Table 3.3.2-37 is revised as follows:

Plant Specific Notes:

3. Material of construction is Aluminum alloy 6061-T6 which is not susceptible to stress corrosion cracking per NUREG 2192 Section 3.3.2.2.8. 6061 in the T-6 temper, which is not susceptible to stress corrosion cracking per NUREG-2192 Section 3.3.2.2.8. AMR lines are not provided to address stress corrosion cracking since the alloy is not susceptible.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 14 TRP 142.4

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 14 1, Attachment 14 Supplement changes to address issues related to TRP-142.4 (TRP 142.4)

Affected SLRA Section(s):

A4.2.4 A4.2.5 SLRA Page Numbers:

A-36 A-37 Description of Change:

TRP Q1: This supplement removes the following statement found in SLRA Section A4.2.4, "Based on establishment of unirradiated T0 for weld W5214 and irradiated T0 for upper shell plate W10201-1, Duke has determined that the current 46.3 EFPY P-T limits will be applicable to 70 EFPY and thus demonstrates that Robinson will be able to conduct heatups and cooldowns at 80 years."

TRP Q3: This supplement will change "10 CFR 50.54 (c)(1)(iii) to 10 CFR 54.21 (c)(1)(iii) in SLRA Section A4.2.5.

SLRA Revisions:

SLRA Section A4.2.4 is revised as follows:

Section A4.2.4 10 CFR 50 Appendix G requires that the reactor vessel be maintained within established pressure-temperature limits, including heatup and cooldown operations. These limits specify the maximum allowable pressure as a function of reactor coolant temperature. As the reactor vessel is exposed to increased neutron irradiation, its fracture toughness is reduced. The pressure-temperature limits must account for the anticipated reactor vessel fluence.

Based on establishment of unirradiated To for weld W5214 and irradiated To for upper shell plate W10201-1, Duke has determined that the current 46.3 EFPY P-T limits will be applicable to 70 EFPY and thus demonstrates that Robinson will be able to conduct heatups and cooldowns at 80 years.

The Robinson Reactor Vessel Material Surveillance (A2.19) and Neutron Fluence Monitoring (A3.2) aging management programs and plant Technical Specifications will ensure that updated pressure-temperature limits will be submitted to the NRC for approval prior to exceeding the period of applicability. Since the pressure-temperature limits will be updated through the 10 CFR 50.90 process at a later, more appropriate date, the effects of aging on the intended function(s) of the reactor vessels will be adequately managed for the Subsequent Period of Extended Operation and are dispositioned in accordance with 10 CFR 54.21(c)(1)(iii).

SLRA Section A4.2.5 is revised as follows:

Section A4.2.5 The Robinson Reactor Vessel Material Surveillance (A2.19) and Neutron Fluence Monitoring (A3.2) aging management programs and plant Technical Specifications will ensure that updated low temperature overpressure enable temperature and power operated relief valve setpoint will

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 14 2

be submitted to the NRC for approval prior to exceeding the period of applicability. Since the low temperature overpressure enable temperature, power operated relief valve setpoint will be updated through the 10 CFR 50.90 process at a later, more appropriate date, the effects of aging on the intended function(s) of the Robinson reactor vessel will be adequately managed for the Subsequent Period of Extended Operation and are dispositioned in accordance with 10 CFR 50.54(c)(1)(iii) 10 CFR 54.21(c)(1)(iii)

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 15 TRP 143

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 15 1, Attachment 15 Supplement changes to address issues related to TRP-143 (TRP 143)

Affected SLRA Section(s):

4.1.4 4.3.2.7 A4.3.2 SLRA Page Numbers:

4-44 4-45 Description of Change:

TRP Q1: Duke will supplement SLRA Section 4.3.2.7 to include a TLAA description, evaluation and disposition for the generic B31.1 Class 1 piping implicit fatigue evaluations. Currently this section of the SLRA only evaluates the explicit fatigue analysis associated with the pressurizer surge line. This will be dispositioned with 10 CFR 54.21(c)(1)(i). In addition, this will add TLAA disposition "(i)" in SLRA Table 4.1.4-1 for row "Reactor Coolant System Piping" within the Metal Fatigue field.

SLRA Revisions:

SLRA Section 4.1.4 is revised as follows:

Table 4.1.4-1: Time-Limited Aging Analyses Categories and Dispositions TLAA CATEGORY ANALYSIS DISPOSITION (Note

1)

SECTION Metal Fatigue Control Rod Drive Mechanism Housing (iii) 4.3.2.6 Metal Fatigue Reactor Coolant System Piping (iii) (iii), (i) 4.3.2.7 Metal Fatigue Class 1 Component Fatigue Waiver Evaluations (iii) 4.3.2.8 SLRA Section 4.3.2.7 is revised as follows:

Section 4.3.2.7 TLAA Description As described in Section 4.3.2, all of the Reactor Coolant System Class 1 Piping was originally constructed in accordance with USAS B31.1, 1967 Edition. In accordance with USAS B31.1, Paragraph 100.1.1, piping as used in the Code includes pipe, flanges, bolting, gaskets, valves, relief devices, fittings and the pressure containing parts of other piping components. All of these components are subject to an implicit fatigue evaluation using a stress range reduction factor, f,

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 15 2

for cyclic conditions for the total number N of full temperature cycles over total number of years during which system is expected to be in operation.

As described in Section 4.3.2, the only Class 1 piping at Robinson that received a Class 1 The only Class 1 piping at Robinson that received a Class 1 ASME Section III fatigue evaluation is the pressurizer surge line piping in response to IE Bulletin 88-11, Pressurizer Surge Line Thermal Stratification. Specifically, Robinson updated the pressurizer surge line stress analyses to comply with ASME Section III Code, 1986 Edition. The Duke (CP&L) IEB 88-11 closeout letter to the NRC [Reference 4.3-6] reports the following.

TLAA Evaluation The transient cycles for the pressurizer surge line were projected for 80 years of operation as discussed in Section 4.3.1 and were found to be adequate for the subsequent period of extended operation. As reported in Table 4.3.1-1, the 40-year design cycles (CLB cycles) are postulated to bound 80 years of plant operation. Therefore, the fatigue analyses for the pressurizer surge line are projected to have adequate margin to remain valid for the subsequent period of extended operation. In order to ensure the design cycles remain bounding for the pressurizer surge line, the Robinson Fatigue Monitoring (B3.1) aging management program will track cycles for significant fatigue transients listed in Table 4.3.1-1 and ensure corrective action is taken prior to potentially exceeding fatigue design limits.

For all of the B31.1 Class 1 piping at Robinson other than the pressurizer surge line, the stress range reduction factor of 1.0 associated with 7,000 cycles was utilized and it is demonstrated that the number of operational cycles at 80-years will not exceed 7,000 cycles in accordance with SLRA Table 4.3.3-2.

TLAA Disposition: 10 CFR 54.21(c)(1)(iii) and 10 CFR 54.21(c)(1)(i)

The effects of fatigue on the intended function(s) of the pressurizer surge line will be adequately managed by the Robinson Fatigue Monitoring (B3.1) aging management program for the subsequent period of extended operation. Therefore, this TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(iii).

To manage the effects of fatigue on the intended function(s) of the Robinson Class 1 piping constructed to USAS B31.1, excluding the pressurizer surge line, it is demonstrated that the implicit fatigue evaluations stress range reduction factors for Class 1 piping remain valid for the subsequent period of extended operation. Therefore, this TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(i).

SLRA Section A4.3.2 is revised as follows:

Section A4.3.2 The 40-year design transients bound the number of projected transients at the end of the subsequent period of extended operation. In order to ensure the design cycles remain bounded in the fatigue analyses and fatigue waivers, the Fatigue Monitoring (B3.1) aging management program will track cycles for significant fatigue transients listed in section 4.3.1, and ensure corrective action is taken prior to potentially exceeding the fatigue design limits. The effects of fatigue on the class 1 components listed above will be managed by the Fatigue Monitoring aging management program for the subsequent period of extended operation in accordance with 10 CFR 54.21 (c)(iii). (c)(1)(iii).

Except for the pressurizer surge line, the rest of the Class 1 piping is constructed in accordance with USAS B31.1, 1967 Edition standards. This piping is subject to an implicit fatigue evaluation

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 15 3

using a stress range reduction factor for cyclic conditions for the total number of full temperature cycles over the total number of years which the system is expected to be in operation. For all of the B31.1 Class 1 piping (excluding the pressurizer surge line), the stress range reduction factor of 1.0 associated with 7,000 cycles was utilized and it is demonstrated that the number of operational cycles at 80-years will not exceed 7,000 cycles in accordance with SLRA Table 4.3.3-2. To manage the effects of fatigue on the intended functions of the Class 1 B31.1 piping, excluding the pressurizer surge line, it is demonstrated that the implicit fatigue evaluations stress range reduction factors remain valid for the subsequent period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 16 TRP 143.1

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 1, Attachment 16 Supplement changes to address issues related to TRP-143.1 (TRP 143.1)

Affected SLRA Section(s):

4.3.1 SLRA Page Numbers:

4-37 4-39 Description of Change:

TRP Q1: This supplement removes mention of a maximum rate of accumulation in Section 4.3.1 because this methodology is not needed for a single unit plant. The supplement will remove the following text, Each monitored design transient was evaluated to determine the maximum rate of accumulation of the individual transients. The maximum rate of accumulation over a 10-year interval was used to extrapolate the projected number of future occurrences beginning September 30, 2018 and ending at 80 years of operation in Section 4.3.1.

TRP Q2: This supplement changes the 0 entries for the rows related to the hydrostatic test at 3110 psig and 100°F in Table 4.3.1-1 to show 1.

SLRA Revisions:

SLRA Section 4.3.1 is revised as follows:

Section 4.3.1 A review of the Fatigue Monitoring program data was performed to identify the number of cumulative cycles for each transient type that has occurred up to September 30, 2018. Baseline cycle counts were projected to an 80-year operating life based on the rate of actual accumulation history since 2008 (October 2008 - September 2018). They do not represent a revision of the design basis. These transient cycles and projections are documented in Table 4.3.1-1, 80-year Transient Cycle Projections below. Consistent with industry operating experience, the accumulation rate of transients at Robinson has decreased over time.

Therefore, transient projections based on operating experience over a 10-year interval provide an appropriate basis for future projections. Each monitored design transient was evaluated to determine the maximum rate of accumulation of the individual transients. The maximum rate of accumulation over a 10-year interval was used to extrapolate the projected number of future occurrences beginning September 30, 2018 and ending at 80 years of operation. The end of 80-year life for Robinson is July 31, 2050.

Table 4.3.1-1 80-Year Design Transient Cycle Projections Transient Description Observed Transient Cycles (9/30/18)

Projected Cycles for 80 years Percent of Design Cycles CLB cycles (40 year design cycles)

Reactor trip 208 250 63 400

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 2

Hydrostatic test (3)

-Pressure 3110 psig

- Temperature 100

°F 0 1 0 1 100 1

Pre-operational Hydrostatic test (3)

-Pressure 2485 psig

- Temperature 400

°F 1

1 0.03 40 Post-operational

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 17 TRP 143.3

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 17 1, Attachment 17 Supplement changes to address how 80-year projected cycles in SLRA Table 4.3.3-2 were determined per TRP 143.3 (TRP 143.3)

Affected SLRA Section(s):

4.3.3 A4.3.3 SLRA Page Numbers:

4 - 48 A - 39 Description of Change:

This supplement item makes the changes identified below to the SLRA in response to TRP 143.3:

x A discussion of how the 80-year projected cycles listed in SLRA Table 4.3.3-2 were determined is added to the Section 4.3.3, TLAA Evaluation, and Section A4.3.3 in response to TRP 143.3 x

A description of the 15% margin added to the 80-year projection of thermal cycles is added to the Section 4.3.3, TLAA Evaluation, and Section A4.3.3 in response to TRP 143.3 SLRA Revisions:

SLRA Section 4.3.3 is revised as follows:

Section 4.3.3 TLAA Evaluation Data from the life of the plant was used to project the various types of plant transients that could cause a thermal cycle in any portion of non-class 1 mechanical piping systems to 80 years of operation. Conservatism was built into these projections as transient frequency at Robinson has decreased since early life plant operations. The number of cumulative cycles for heatups, cooldowns, reactor trips, plant loadings, and plant unloadings that occurred at Robinson from 1970 to September 30, 2018, was projected to 80 years of operation based on the average number of transients per year. The operating characteristics of in-scope piping systems were identified from a review of plant operation procedures, flow diagrams, surveillance tests, and operations logs to determine when system heatups, cooldowns, reactor trips, plant loadings, and plant unloadings occur. Data from the life of the plant was used to project the various types of plant transients that could cause a thermal cycle in any portion of non-class 1 mechanical piping systems to 80 years of operation. Conservatism was built into these projections as transient frequency at Robinson has decreased since early life plant operations. For additional conservatism, a 15% margin was added to the projection of the number of thermal cycles over 80 years.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 17 2

SLRA Section A4.3.3 is revised as follows:

Section A4.3.3 For the Robinson non-Class 1 mechanical systems within the scope of subsequent license renewal, only the piping and piping components have been explicitly designed to consider thermal transient cycle count assumptions that must be revalidated for the extended period of operation. The piping and piping components are designed to the requirements of USA Standard Code for Pressure Piping (USAS), later reorganized into the American National Standards Institute (ANSI), Power Piping, B31.1, 1967 Edition, where a stress range reduction factor is used based on the number of expected thermal cycles during the period of plant operation. If the total number of expected thermal cycles for a piping system is less than 7,000, then a stress range reduction factor of 1.0 is applied. If the total number of expected thermal cycles for a piping system is greater than 7,000, a stress range reduction factor less than 1.0 is applied to reduce the alternating stress range in the piping design. From review of the design basis and projected 80-year cycles, no portions of non-Class 1 piping exceed the allowable number of thermal cycles. The stress range reduction factors applied to the non-Class 1 piping systems design will remain valid for the subsequent period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

The number of cumulative cycles for heatups, cooldowns, reactor trips, plant loadings, and plant unloadings that occurred at Robinson from 1970 to September 30, 2018, was projected to 80 years of operation based on the average number of transients per year. The operating characteristics of in-scope piping systems were identified from a review of plant operation procedures, flow diagrams, surveillance tests, and operations logs to determine when system heatups, cooldowns, reactor trips, plant loadings, and plant unloadings occur. Data from the life of the plant was used to project the various types of plant transients that could cause a thermal cycle in any portion of non-class 1 mechanical piping systems to 80 years of operation.

Conservatism was built into these projections as transient frequency at Robinson has decreased since early life plant operations. For additional conservatism, a 15% margin was added to the projection of the number of thermal cycles over 80 years. From review of the design basis and projected 80-year cycles, no portions of non-Class 1 piping exceed the allowable number of thermal cycles. The stress range reduction factors applied to the non-Class 1 piping systems design will remain valid for the subsequent period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 18 TRP 147.2

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 1, Attachment 18 TRP 147.2 - TLAA 4.7.2 (Site-Specific) Reactor Coolant Pump Flywheel Analyses (TRP 147.2)

Affected SLRA Section(s):

4.7.2 SLRA Page Numbers:

4-75 Description of Change:

This supplement item provides an update to the SLRA in response to TRP 147.2. Information about the Robinson RCP flywheel inspection has been included, indicating that no relevant indications have been found on the flywheels.

SLRA Revisions:

SLRA Section 4.7.2 is revised as follows:

Section 4.7.2 TLAA Evaluation In addition, a review of Robinson RCP flywheel inspection data since Refueling Outage 9 in 1984, along with data from the corrective action program, was conducted. No relevant indications have been identified on the RCP flywheels at Robinson.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 1 ATTACHMENT 19 TRP 147.5

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 19 1, Attachment 19 Supplement changes to state that no underclad flaws in the reactor vessel have been identified related to TRP 147.5 (TRP 147.5)

Affected SLRA Section(s):

4.7.5 A4.7.5 SLRA Page Numbers:

4-80 A-44 Description of Change:

This supplement item makes the changes identified below to the SLRA in response to TRP 147.5:

x A statement that no underclad flaws were detected in the Robinson reactor vessel is added to Section 4.7.5 and Section A4.7.5 in response to TRP 147.5 x

Reference 4.7.5-5 was corrected to be Reference 4.7-17 in Section 4.7.5.

SLRA Revisions:

SLRA Section 4.7.5 is revised as follows:

Section 4.7.5 TLAA Evaluation TLAA Action Item 1: The NRC notes that it is unlikely that actual RCS transients and cycles for the SPEO will exceed the number of design cycles conservatively considered in the transient table in Reference 4.7.5-5. [Reference 4.7-17]. However, in their plant-specific TLAAs for RPV underclad cracks, SLR applicants are to confirm that the generic transient types and number of transient cycles used for the 80-year FCG calculation, as listed in the RCS transient table in Reference 4.7.5-5, [Reference 4.7-17], bounds the projected number of transient cycles for the actual applicable transients for the SPEO.

Duke Assessment-Action Item 2: There are no SA 508 Class 2 or Class 3 forgings within the beltline/extended beltline region. No underclad flaws were detected in the Robinson reactor vessel. The reactor vessel lower, intermediate, and upper shells are made from A302B plate material and are not susceptible to underclad (reheat) cracking. The reactor vessel nozzles and reactor vessel flange are made from SA 508 Class 2 and the replacement closure head is made from SA-508 Class 3. These items are not considered within the extended beltline owing to 70 EFPY fluence projections and are not required to have adjusted RTNDT values calculated in accordance with 10 CFR 50.61.

SLRA Section A4.7.5 is revised as follows:

Section A4.7.5 There are no SA 508 Class 2 or Class 3 forgings within the beltline/extended beltline region. No underclad flaws were detected in the Robinson reactor vessel. The reactor vessel lower, intermediate, and upper shells are all from A302B plate material and are not susceptible to

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 19 2

underclad (reheat) cracking. The reactor vessel nozzles and reactor vessel flange are made from SA 508 Class 2 and the replacement closure head is made from SA-508 Class 3. These items are not considered within the extended beltline owing to 70 EFPY fluence projections.

U.S. Nuclear Regulatory Commission RA-25-0200 Westinghouse Affidavit

Westinghouse Non-Proprietary Class 3 AFFIDAVIT CAW-25-043 Page 1 of 3 Commonwealth of Pennsylvania:

County of Butler:

(1)

I, Jerrod Ewing, Manager, Operating Plants Licensing, have been specifically delegated and authorized to apply for withholding and execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse).

(2)

I am requesting the proprietary portions of WCAP-18944-P, Revision 2 be withheld from public disclosure under 10 CFR 2.390.

(3)

I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged, or as confidential commercial or financial information.

(4)

Pursuant to 10 CFR 2.390, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld.

(i)

The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse and is not customarily disclosed to the public.

(ii)

The information sought to be withheld is being transmitted to the Commission in confidence and, to Westinghouses knowledge, is not available in public sources.

(iii)

Westinghouse notes that a showing of substantial harm is no longer an applicable criterion for analyzing whether a document should be withheld from public disclosure. Nevertheless, public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar technical evaluation justifications and licensing defense services for commercial power reactors without commensurate expenses. Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.

Westinghouse Non-Proprietary Class 3 AFFIDAVIT CAW-25-043 Page 2 of 3 (5)

Westinghouse has policies in place to identify proprietary information. Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:

(a)

The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.

(b)

It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage (e.g., by optimization or improved marketability).

(c)

Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.

(d)

It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.

(e)

It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.

(f)

It contains patentable ideas, for which patent protection may be desirable.

(6)

The attached documents are bracketed and marked to indicate the bases for withholding. The justification for withholding is indicated in both versions by means of lower-case letters (a) through (f) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower-case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (5)(a) through (f) of this Affidavit.

Westinghouse Non-Proprietary Class 3 AFFIDAVIT CAW-25-043 Page 3 of 3 I declare that the averments of fact set forth in this Affidavit are true and correct to the best of my knowledge, information, and belief. I declare under penalty of perjury that the foregoing is true and correct.

Executed on: 8/4/2025 Signed electronically by Jerrod Ewing Sii d l t

i ll

U.S. Nuclear Regulatory Commission RA-25-0200 WCAP-18944-NP, H.B. Robinson Unit 2 Subsequent License Renewal: Reactor Vessel Upper Shelf Energy Equivalent Margins Analysis, Revision 2, dated August 2025 (Non-Proprietary Version)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 WCAP-18944-NP August 2025 Revision 2 H.B. Robinson Unit 2 Subsequent License Renewal: Reactor Vessel Upper Shelf Energy Equivalent Margin Analysis

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3

• Electronically approved records are authenticated in the electronic document management system.

Westinghouse Electric Company LLC 1000 Westinghouse Drive Cranberry Township, PA 16066, USA

© 2025 Westinghouse Electric Company LLC All Rights Reserved WCAP-18944-NP Revision 2 H.B. Robinson Unit 2 Subsequent License Renewal: Reactor Vessel Upper Shelf Energy Equivalent Margin Analysis August 2025 Gordon Z. Hall*

Structural Design and Analysis (Revision 2 Changes)

Verifier:

B. Reddy Ganta*

Structural Design and Analysis (Revision 2 Changes)

Reviewers:

Thomas E. Demers*

Structural Design and Analysis Approved:

Stephen P. Rigby, Manager Structural Design and Analysis

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 ii WCAP-18944-NP August 2025 Revision 2 FOREWORD This document contains Westinghouse Electric Company LLC proprietary information and data which has been identified by brackets. Coding (a,c,e) associated with the brackets sets forth the basis on which the information is considered proprietary.

The proprietary information and data contained in this report were obtained at considerable Westinghouse expense and its release could seriously affect our competitive position. Westinghouse has policies in place to identify proprietary information. Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:

(a)

The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.

(c)

Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.

(e)

It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.

The document herein is bracketed and marked to indicate the bases for withholding. The justification for withholding is indicated in both proprietary and non-proprietary versions by means of lower-case letters (a)

(c) and (e) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower-case letters refer to the types of information Westinghouse customarily holds in confidence identified above.

The proprietary information in the brackets is provided in the proprietary version of this report (WCAP-18944-P, Revision 2).

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 iii WCAP-18944-NP August 2025 Revision 2 RECORD OF REVISIONS Revision Date Revision Description 0

August 2024 Original issue.

1 December 2024 Addressing additional customer comments for Appendix A. The main body of report is unchanged. Changes are marked with change bars.

2 See PRIME As part of response to NRC audit questions TRP-142.2 Q2 and Q3, this revision corrects typos in Table 4-9 title and typo in Table 3-8 footnote (1). CAP PIR-2025-1632 captures this deficiency. Changes are marked with change bars.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 iv WCAP-18944-NP August 2025 Revision 2 TABLE OF CONTENTS ACRONYMS................................................................................................................................................ v EXECUTIVE

SUMMARY

.......................................................................................................................... vi 1

INTRODUCTION........................................................................................................... 1-1 2

REGULATORY REQUIREMENTS............................................................................... 2-1 2.1 REGULATORY REQUIREMENTS............................................................................... 2-1 2.2 COMPLIANCE WITH 10 CFR 50 APPENDIX G AND ACCEPTANCE CRITERIA.. 2-1 2.2.1 ASME Section XI Code Reconciliation.......................................................... 2-2 2.3 ACCEPTANCE CRITERIA............................................................................................ 2-2 2.3.1 Levels A and B Service Loadings.................................................................... 2-2 2.3.2 Level D Service Loadings............................................................................... 2-3 3

EQUIVALENT MARGINS ANALYSIS INPUTS.......................................................... 3-1 3.1 FINITE ELEMENT STRESS ANALYSIS...................................................................... 3-1 3.1.1 Mechanical Loads............................................................................................ 3-4 3.1.2 Reactor Coolant System Transients................................................................. 3-5 3.2 J-INTEGRAL RESISTANCE MODELS........................................................................ 3-7 3.2.1 Reactor Vessel Nozzle-to-Shell Weld.............................................................. 3-7 3.2.2 Reactor Vessel Nozzle Forging Base Metal..................................................... 3-9 3.2.3 Reactor Vessel Upper/Intermediate Shell Plates............................................ 3-13 4

FRACTURE MECHANICS ANALYSIS........................................................................ 4-1 4.1 METHODOLOGY DISCUSSION.................................................................................. 4-1 4.1.1 Nozzle-to-Shell Welds and Upper/Intermediate Shell Forging....................... 4-1 4.1.2 Nozzle Corner KI Closed-Form Solution........................................................ 4-3 4.1.3 Calculation of J for Small-Scale Yielding....................................................... 4-3 4.1.4 Postulated Flaws.............................................................................................. 4-4 4.1.5 Weld Residual Stress....................................................................................... 4-4 4.1.6 Stress due to Mechanical Loads...................................................................... 4-4 4.2 APPLIED J-INTEGRAL RESULTS AND COMPARISON WITH J-R CURVE ALLOWABLES............................................................................................................... 4-5 4.2.1 Nozzle-to-Shell Welds Levels A/B.................................................................. 4-5 4.2.2 Nozzle-to-Shell Welds Level D....................................................................... 4-7 4.2.3 RV Nozzle Forgings Levels A/B................................................................... 4-10 4.2.4 RV Nozzle Forgings Level D......................................................................... 4-13 4.2.5 Upper and Intermediate Shell Plates Levels A/B.......................................... 4-17 4.2.6 Upper and Intermediate Shell Plates Level D................................................ 4-19 5

CONCLUSIONS............................................................................................................. 5-1 6

REFERENCES................................................................................................................ 6-1 Appendix A Upper Shelf Fracture Toughness Testing of Robinson Reactor Pressure Vessel Steel Plate

.. A-1

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 v

WCAP-18944-NP August 2025 Revision 2 ACRONYMS ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials CMTR certified material test report CVN Charpy v-notch DW deadweight eLBB extended loss of coolant accident EMA equivalent margin analysis EOLE end-of-license-extension FEA finite element analysis FEM finite element model HAZ heat affected zone J

J-integral due to the applied loads, in-lb/in2 (or lbf/in2)

J1 applied J-integral at a flaw depth of a0 + 0.1 in., in-lb/in2 (or lbf/in2)

J-R J-integral fracture resistance for the material, or J-material, or JR J-R curve J-integral fracture resistance vs. crack-extension curve J0.1

-LQWHJUDOIUDFWXUHUHVLVWDQFHIRUWKHPDWHULDODWDGXFWLOHIODZH[WHQVLRQRILQ LOCA loss of coolant accident NRC Nuclear Regulatory Commission OBE operating basis earthquake RG regulatory guide RNP H.B. Robinson Nuclear Plant RPV or RV reactor pressure vessel SF structural factor (dimensionless)

SIF stress intensity factor, ksiin LSB large steam line break SLR subsequent license renewal SRSS square root sum of squares SSE safe shutdown earthquake USE upper shelf energy WRS weld residual stress, ksi

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 vi WCAP-18944-NP August 2025 Revision 2 EXECUTIVE

SUMMARY

At the start of the 80-year subsequent license renewal (SLR) project of the H.B. Robinson Nuclear Plant (RNP) Unit 2, several locations of the reactor vessel (RV) were identified as being at risk to potentially drop below the upper shelf energy (USE) limit of 50 ft-lb per 10 CFR 50, Appendix G. Materials with end-of-license-extension (EOLE) USE below 50 ft-lb are required to be evaluated per paragraph IV.A.1.a of 10 CFR 50, Appendix G. This report presents the methodology and results of the equivalent margins analysis (EMA) for the following locations for the 80-year SLR:

x Intermediate Shell Plates x

Upper Shell Plates x

RV Inlet and Outlet Nozzle Forgings x

Nozzle-to-Shell Welds

[

]a,c,e Levels A and B Conditions For all evaluated locations, the J for the postulated flaw plus a 0.1-inch flaw extension (J1) with a structural factor (SF) of 1.15 for accumulation pressure, and SF of 1.0 for thermal are below the J-material at 0.1-inch flaw extension (J0.1). Therefore, the acceptance criteria in ASME Section XI, K-2200 (a)(1) [6] is satisfied.

The slope of J (with a SF=1.25 for accumulation pressure, SF=1 for thermal) is less than the J-integral resistance (J-R) curve at the intersection of both curves (i.e., when J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-2200 (a)(2) [6] is satisfied.

Levels C and D Conditions There is no Level C or Level D transient defined in the reactor vessel design specification. The Level D large steam line break transient per the current design basis, generic 60-year EMA, WCAP-13587, Rev. 1, Figure 3-2 [2] is analyzed to bound Levels C/D conditions.

For the evaluated locations, the J1 with a SF of 1.0 are below the J0.1. Therefore, the acceptance criteria in ASME Section XI, K-2400 (a) [6] is satisfied.

The slope of J is less than the J-R curve at the intersection of both curves (i.e., when J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-3400 [6] is satisfied. Using this approach, Level D loadings are shown to satisfy the more limiting Level C acceptance criteria established by K-2300 [6].

Per K-2400 of [6], all flaws evaluated for Level D assumed a flaw depth equal to 1/10 of the base metal thickness, plus the cladding thickness, but not exceeding 1 inch, plus a 0.1-inch flaw extension. All flaws evaluated herein have been shown to exhibit ductile and stable flaw extension when compared to J0.1 for all Level D loading conditions. This satisfies the 75% of wall thickness requirement, per K-2400 (c) [6], as the final flaw size, after extension, is much less than 75% of the wall thickness.

Additionally, the maximum Level D internal pressure is less than the tensile instability pressures calculated per K-5300 (b) [6] for all evaluated locations and flaws.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 1-1 WCAP-18944-NP August 2025 Revision 2 1

INTRODUCTION The purpose of this report is to document the equivalent margins analysis (EMA) for H.B. Robinson Nuclear Plant (RNP) Unit 2 reactor vessel (RV) to support an 80-year subsequent license renewal (SLR), per the Duke Energy contract RNP-2077-04-SLR-001, Task 3(j) [1]. It is noted that the current analysis of record for RNP Unit 2 is the generic Westinghouse EMA in WCAP-13587 [2].

Per paragraph IV.A.1.a of 10 CFR 50, Appendix G, RV beltline materials with end-of-license extension (EOLE) Upper Shelf Energy (USE) below 50 ft-lb limit are required to be evaluated for margins of safety against fracture equivalent to those required by Appendix G of Section XI of the ASME Code. Several locations were identified in [1] at the start of the project as being at risk to potentially drop below the minimum USE of 50 ft-lb. These following locations are addressed for the 80-year SLR by the EMA provided herein:

x Intermediate Shell Plates x

Upper Shell Plates x

RV Inlet and Outlet Nozzle Forgings x

Nozzle-to-Shell Welds The RNP Unit 2 intermediate shell and upper shell plates are considered beltline materials per WCAP-18766-NP [4]. The RV extended beltline is defined as the region of materials that meet or exceed a neutron fluence exposure of 1.0 E+17 n/cm2 (E> 1.0 MeV). As discussed in Section 3 and Tables 5-2 and 5-3 of WCAP-18766-NP [4], the RV inlet/outlet nozzles and nozzle welds were considered as extended beltline material conservatively assuming fluence value of 2.0 E+17 n/cm2 (E> 1.0 MeV). The 10 CFR 50, Appendix G paragraph IV.A.1.a requirements for beltline material is applied to the extended beltline materials herein.

For the EMA, Table 5-3 of WCAP-18766-NP [4] provides USE values for the reactor vessel, including the upper and intermediate shell plates, nozzle-to-shell welds and nozzle forgings. Due to lack of test orientation information in the nozzle forging certified material test reports (CMTR), PWROG-23006-NP

[3] provided conservative USE values for the inlet and outlet nozzle forgings for the purpose of EMA.

[

] a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 2-1 WCAP-18944-NP August 2025 Revision 2 2

REGULATORY REQUIREMENTS 2.1 REGULATORY REQUIREMENTS In accordance with 10 CFR 50, Appendix G, IV.A.1, [5] Reactor Vessel Upper Shelf Energy Requirements are as follows.

(a) Reactor Vessel beltline materials must have Charpy upper-shelf energy in the transverse direction for base material and along the weld for weld material according to the ASME Code, of no less than 75 ft-lb (102 J) initially and must maintain Charpy upper-shelf energy throughout the life of the vessel of no less than 50 ft-lb (68 J), unless it is demonstrated in a manner approved by the Director, Office of Nuclear Reactor Regulation, that lower values of Charpy upper-shelf energy will provide margins of safety against fracture equivalent to those required by Appendix G of Section XI of the ASME Code. This analysis must use the latest edition and addenda of the ASME Code incorporated by reference into 10 CFR 50.55a (b)(2) at the time the analysis is submitted.

(b) Additional evidence of the fracture toughness of the beltline materials after exposure to neutron irradiation may be obtained from results of supplemental fracture toughness tests for use in the analysis specified in section IV.A.1.a.

(c) The analysis for satisfying the requirements of section IV.A.1 of this appendix must be submitted, as specified in § 50.4, for review and approval on an individual case basis at least three years prior to the date when the predicted Charpy upper-shelf energy will no longer satisfy the requirements of section IV.A.1 of this appendix, or on a schedule approved by the Director, Office of Nuclear Reactor Regulation.

In accordance with NRC Regulatory Guide 1.161 [13], the NRC has determined that the analytical methods described in ASME Section XI, Appendix K, provide acceptable guidance for evaluating reactor pressure vessels when the Charpy USE falls below the 50 ft-lb limit of Appendix G of 10 CFR Part 50. However, the staff noted that Appendix K does not provide information on the selection of transients and provides very little detail on the selection of material properties. Consistent with PWROG-19047-NP-A [17], the cooldown transient for RNP with a constant pressure of 2750 psia assumed throughout the transient bounds all Levels A/B conditions. This is consistent with and based on the ASME Section XI, Appendix K 100°F/hour cooldown rate guidance coincident with the use of a high pressure value. The Level C/D transient selection is based on the guidance in Regulatory Guide 1.161 Section 4.0 [13]. Based on [8], there is no Level C or D transient defined in the design specification. The level D large steam line break (LSB) transient per the current design basis, WCAP-13587, Rev. 1, Figure 3-2 [2] is analyzed to bound Levels C/D conditions. For clarity, this report will refer to this loading condition as Level D instead of Level C/D.

Additional transient discussions are contained in Section 4.1.

2.2 COMPLIANCE WITH 10 CFR 50 APPENDIX G AND ACCEPTANCE CRITERIA The analyses reported herein are performed in accordance with the code of record, 2007 Edition with 2008 Addenda of the ASME Code Section XI, Appendix K [6]. Per the design input request response [7], Duke Energy concurs that NRC has authorized use of the 2007 Edition and 2008 Addenda of Section XI through 10CFR50.55a. The material properties used for the finite element stress analysis are based on the original RV construction code. See Section 3.1 for detailed discussion on material properties for the finite element analysis (FEA).

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 2-2 WCAP-18944-NP August 2025 Revision 2 2.2.1 ASME Section XI Code Reconciliation In accordance with 10 CFR 50.60, Appendix G, IV, 1., low values of USE require an analysis (EMA) to demonstrate adequate margins of safety against fracture equivalent to those required by Appendix G of Section XI of the ASME Code. The analysis must use the latest NRC approved edition and addenda of the ASME Code, which is 2019 Edition. The EMA herein is performed in accordance to ASME Section XI Appendix K. There has been no substantive change of ASME Section XI Appendix K between 2007 Edition through 2008 Addenda [6] and 2019 Edition [9]. Therefore, the RNP ASME XI code of record, 2007 Edition through 2008 Addenda [6] is reconciled to the current NRC approved ASME Code 2019 Edition.

2.3 ACCEPTANCE CRITERIA ASME Section XI, Appendix K [6] provides the acceptance criterial for the Level A, B, C and D conditions.

These criteria summarized in the following subsections are consistent with Regulatory Guide 1.161.

The EMA is performed in accordance with ASME Section XI [6], Appendix K. This is consistent with previous SLR EMAs, such as B&W designed plants Surry and Turkey Point [15 and 16], and Westinghouse designed plant, North Anna [17] which had been accepted by NRC. As discussed in Section 4.1, detailed FEA thermal transient, pressure, mechanical and residual stresses were used in the calculation of KI and J.

This is more rigorous than the KI formulas in K-4200 which uses generic stress calculations for cylinders.

Based on previous EMAs such as North Anna [17], the Appendix K approach was also applied to the locations of the nozzle corners in a manner consistent with the other locations evaluated herein. This includes the 1/4 wall thickness flaw assumption for Level A and B conditions, which is reasonable for the reactor vessel shell but results in a postulated flaw of more than 3 inches for the nozzle forging at the nozzle corners (due to the nozzle corner having a larger thickness than the reactor vessel shell). This postulated flaw size is very large, and therefore this approach is considered conservative for the nozzle corner locations. This conservatism is acceptable and appropriate as the nozzle corner is evaluated and shown to be acceptable using the Appendix K criteria.

2.3.1 Levels A and B Service Loadings Per ASME Section XI, K-2200 [6]:

(a) Postulated axial and circumferential flaws are interior semi-elliptical surface flaws with a depth of 1/4 of the wall thickness and a length to depth (l/a) aspect ratio of 6.

(1) J with a SF of 1.15 for accumulation pressure, and an SF of 1.0 for thermal (cooldown) shall be less than the J-integral of the material (J-R curve) at a ductile flaw extension of 0.1 inch.

Accumulation pressure is defined in K-1300 as 1.1 times design pressure which is 2.5x1.1=2.75ksi.

(2) J with a SF of 1.25 for accumulation pressure and a SF of 1.0 for thermal (cooldown) shall be ductile and stable. The flaw stability criteria is per K-3400 [6]:

at J JR.

(b) The J-R curve shall be a conservative representation for the vessel material under evaluation.

As noted above, the flaw stability criteria per K-3400 is:

DW-*-57KLVLVIXUWKHUH[SODLQHG

in K-4310. The J-R curve shall be plotted on the crack driving force diagram and shall intersect the horizontal axis at the initial flaw depth, a0. Flaw stability at a given applied load is verified when the slope of the J curve is less than the slope of the J-R curve at the point on the J-R curve where the two curves intersect.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 2-3 WCAP-18944-NP August 2025 Revision 2 2.3.2 Level D Service Loadings Per ASME Section XI [6], K-2400, the Level D postulated flaws shall be the same as those specified for Level C in K-2300.

(a) Postulated axial and circumferential flaws are interior semi-elliptical surface flaws with depths up to 1/10 of the wall thickness of the base metal plus cladding, with total depth not exceeding 1 inch. For cases where 1/10 wall thickness plus cladding exceeded 1 inch, 1 inch is used for the postulated flaws for Level D. The length to depth (l /a) aspect ratio is 6.

(1) J with a SF of 1.0 for thermal and pressure shall be less than the J-R curve at a ductile flaw extension of 0.1 inch. Note that the K-2300(a)(1) criteria for Level C is conservatively considered herein for Level D conditions.

(2) J with a SF of 1.0 for thermal and pressure shall be ductile and stable.

(b) The J-R curve shall be a conservative representation for the vessel material under evaluation.

(c) The total flaw depth after stable flaw extension shall be less than or equal to 75% of the vessel wall thickness, and the remaining ligament shall not be subject to tensile instability.

The flaw stability criteria is detailed in K-5300.

(a) Stability is verified per K-3400:

DW-*-5

(b) For Level D Service Loadings, demonstrate that total flaw depth after stable flaw extension is less than or equal to 75% of the vessel wall thickness, and the remaining ligament is not subjected to tensile instability. The internal pressure shall be less than the instability pressure (PI), calculated by the equations below:

(1) For axial flaw, = 1.07

/

(2) For circumferential flaw, = 1.07

/

PI is limited to = 1.07

where, o

= Flow stress, average of yield strength and ultimate tensile strength A

= An area parameter = t (l + t)

Ac

= Area of the flaw = a l / 4 Ri

= Inner radius of the vessel Rm

= Mean radius of the vessel t

= Wall thickness of the vessel a

= Flaw depth l

= Flaw length

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-1 WCAP-18944-NP August 2025 Revision 2 3

EQUIVALENT MARGINS ANALYSIS INPUTS 3.1 FINITE ELEMENT STRESS ANALYSIS The general procedures for J-integral calculation are described in ASME Section XI, Appendix K [6]. As discussed in Section 2.1, the cooldown transient was analyzed to bound Levels A/B. The Level D transient is SLB. Figure 3-1 through Figure 3-3 illustrates the finite element model (FEM) of the Robinson reactor vessel. Geometry and dimensions are taken from design drawings. The applied loadings consist of pressure, thermal and attached piping and support reactions at the RV nozzles. Multiple cutlines for each location of interest were placed to extract through-wall stress profiles as a function of time. J integrals are then calculated as described in 4.1 using the FEA through-wall stresses for all time points. The most limiting values are reported in Section 4.2.

Figure 3-1: Robinson Reactor Vessel Finite Element Model Overview

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-2 WCAP-18944-NP August 2025 Revision 2 Figure 3-2: Robinson Reactor Vessel Finite Element Model Outlet Nozzle Details Figure 3-3: Robinson Reactor Vessel Finite Element Model Inlet Nozzle Details

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-3 WCAP-18944-NP August 2025 Revision 2 The RNP RV base metal for the upper shell plate, intermediate (middle), lower shell plates, and lower head are SA-302 Gr. B. The inlet and outlet nozzle forgings are SA-336. Per design specification [21],

internal cladding is austenitic stainless steel with a corrosion resistance equal to or better than Type 304.

Therefore, Type 304 stainless steel properties are used for the cladding in the FEA. This is typical of RVs and same as the North Anna EMA [17].

The material properties used in the FEA are based on the original RV construction code, ASME Boiler and Pressure Vessel Code,Section III, 1965 Edition [18.a]. As the 1965 ASME Section III does not provide thermal properties, they are taken from the next code year, 1974 ASME Section III [18.b].

Poissons ration and density are not specified in earlier ASME Codes, they are taken from Table PRD of 2010 ASME Section II Part D [18.c]. All material properties are listed in Table 3-1 and Table 3-2.

Table 3-1: Base Metal Material Properties (SA-302 Gr. B and SA-336)

Temperature

[°F]

E Modulus

[x106 psi]

Thermal Expansion Coef.

[x10-6 in/(in°F)]

K Thermal Conductivity

[BTU/(hrft°F)]

Cp Specific Heat Capacity

[BTU/(lbm°F)]

Density

[lbm/in3]

Poissons Ratio 70 27.9 6.10 31.5 0.1144 0.28 0.3 100 31.0 0.1163 150 30.5 0.1163 200 27.7 6.38 30 0.1182 250 29.5 0.1201 300 27.4 6.60 29.1 0.1220 350 28.6 0.1239 400 27.0 6.82 28.1 0.1258 450 27.6 0.1277 500 26.4 7.02 27.2 0.1296 550 26.7 0.1315 600 25.7 7.23 26.2 0.1333 650 25.8 0.1362 700 24.8 7.44 25.3 0.1390 Table 3-2: Cladding Material Properties (Type 304 Stainless Steel)

Temperature

[°F]

E Modulus

[x106 psi]

Thermal Expansion Coef.

[x10-6 in/(in°F)]

K Thermal Conductivity

[BTU/(hrft°F)]

Cp Specific Heat Capacity

[BTU/(lbm°F)]

Density

[lbm/in3]

Poissons Ratio 70 27.4 9.20 8.35 0.1112 0.29 0.3 100 8.40 0.1121 150 8.67 0.1135 200 27.1 9.34 8.90 0.1147 250 9.12 0.1160 300 26.8 9.47 9.35 0.1174 350 9.56 0.1192 400 26.4 9.59 9.80 0.1200 450 10.00 0.1218 500 26.0 9.70 10.23 0.1231 550 10.45 0.1238 600 25.4 9.82 10.70 0.1251 650 10.90 0.1264 700 24.9 9.94 11.10 0.1276

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-4 WCAP-18944-NP August 2025 Revision 2 3.1.1 Mechanical Loads The RNP RV nozzle mechanical loads include deadweight (DW), thermal, operation basis earthquake (OBE), safe shutdown earthquake (SSE) loads. Loss of coolant accident (LOCA) loads for the Level C/D is based on extended leak before break (eLBB). The OBE, SSE, and LOCA loads are unsigned and are assumed to act in the positive or negative direction.

Table 3-3 and Table 3-4 also list the nozzle load combinations used in the analysis. The Level A/B summation is based on pressure plus DW plus thermal plus or minus OBE loads, and the Level C/D summation is based on DW plus thermal plus or minus the square root sum of the squares (SRSS) of SSE and LOCA loads. The inlet and outlet local coordinate systems are as follows: +X is along the axis of the nozzle oriented towards RV centerline, +Y is vertical oriented towards the RV head, and +Z is lateral following the right-hand rule.

The support pad loads are listed in Table 3-5. As previously mentioned, LOCA is based on eLBB. The vertical support pad loads are signed and act in the vertical direction only. The lateral support pad loads are unsigned and are assumed to act in positive or negative direction. The Level A/B summation is based on pressure plus DW plus thermal plus or minus OBE loads, and the Level C/D summation is based on DW plus thermal plus or minus the square root sum of the squares (SRSS) of SSE and LOCA loads.

Individual load cases are run to test the effect of mechanical loads on both nozzles simultaneously; the goal of these cases is to develop summations that produced maximum tensile stresses on the nozzle welds.

Table 3-3: Level A/B Inlet/Outlet Nozzle Mechanical Load Cases Load Forces [kips]

Moments [inkips]

Fx Fy Fz Mx My Mz Inlet DW 0.00 0.00 0.00 0.00 0.00 0.00 Thermal

-4.45

-92.00 10.26

-2802.30 1831.00 7439.90 OBE 124.00 51.00 59.00 2491.00 12126.00 2871.00 SSE 243.00 89.00 119.00 4472.00 23655.00 5421.00 LOCA 1,337.00 1,437.00 1,473.00 0.00 61,750.00 0.00 Outlet DW 0.00 0.00 0.00 0.00 0.00 0.00 Thermal

-5.00 230.00

-10.00

-320.00

-1830.00 27084.00 OBE 65.00 90.00 71.00 1572.00 11248.00 7282.00 SSE 113.00 92.00 124.00 1343.00 19569.00 7371.00 LOCA 1485.00 380.00 0.00 0.00 0.00 80300.00 Load Cases Inlet Load Case 1 119.55

-41.00 69.26

-311.30 13,957.00 10,310.90 Load Case 2

-128.45

-143.00

-48.74

-5,293.30

-10,295.00 4,568.90 Outlet Load Case 1 60.00 320.00 61.00 1,252.00 9,418.00 34,366.00 Load Case 2

-70.00 140.00

-81.00

-1,892.00

-13,078.00 19,802.00 Note:

(1) Pressure is not included in this summation and is run as a separate load.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-5 WCAP-18944-NP August 2025 Revision 2 Table 3-4: Level C/D Inlet/Outlet Nozzle Mechanical Load Cases with eLBB Load Forces [kips]

Moments [inkips]

Fx Fy Fz Mx My Mz Inlet DW 0.00 0.00 0.00 0.00 0.00 0.00 Thermal

-4.45

-92.00 10.26

-2802.30 1831.00 7439.90 OBE 124.00 51.00 59.00 2491.00 12126.00 2871.00 SSE 243.00 89.00 119.00 4472.00 23655.00 5421.00 LOCA 178.58 95.28 282.90 127.13 2,987.57 823.56 Outlet DW 0.00 0.00 0.00 0.00 0.00 0.00 Thermal

-5.00 230.00

-10.00

-320.00

-1830.00 27084.00 OBE 65.00 90.00 71.00 1572.00 11248.00 7282.00 SSE 113.00 92.00 124.00 1343.00 19569.00 7371.00 LOCA 245.74 16.54 50.82 123.68 3207.94 1367.19 Load Cases Inlet Load Case 3 297.12 38.38 317.17 1,671.51 25,673.92 12,923.10 Load Case 4

-306.01

-222.38

-296.65

-7,276.11

-22,011.92 1,956.70 Outlet Load Case 3 265.48 323.47 124.01 1,028.68 18,000.20 34,580.72 Load Case 4

-275.48 136.53

-144.01

-1,668.68

-21,660.20 19,587.28 Note:

(1) Pressure is not included in this summation and is run as a separate load.

Table 3-5: Inlet Pad Load Cases Condition Case Forces [kips]

Fy Fz Level A/B Load Case 1

-237.50 245.40 Load Case 2 237.50

-245.40 Level C/D Load Case 3 726.50 447.89 Load Case 4

-726.50

-447.89 3.1.2 Reactor Coolant System Transients The transients evaluated for Level A/B is plant cooldown and large steam line break for Level C/D. As discussed in the design input transmittal [8], the current licensing basis EMA for RPN is the Westinghouse generic EMA in WCAP-13587 [2]. The bounding Large Steamline Break (LSB) thermal transient defined in Figure 3-2 of WCAP-13587 [2] will be used for the Levels C/D of the EMA. The digitized LSB transient per WCAP-13587 is reproduced in Figure 3-4. The plant cooldown is a 100°F/hour ramp from 557°F to 70°F shown in Figure 3-5. This transient assumes zero power conditions initially, therefore, applicable to both the inlet and outlet nozzles.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-6 WCAP-18944-NP August 2025 Revision 2 Figure 3-4: Temperature and Pressure History for Large Steam Line Break Transient [2]

Figure 3-5: Temperature History for Plant Cooldown Transient

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-7 WCAP-18944-NP August 2025 Revision 2 3.2 J-INTEGRAL RESISTANCE MODELS The J-integral resistance (J-R) curves are conservative representations for the RV material property as a function of flaw extension. As actual fracture toughness for RNP RV nozzle forging and welds are not available, guidance in NUREG/CR-5729 [12] and Regulatory Guide (RG) 1.161 [13] are used. The RV shell J-R curve is based on test data reported in Appendix A.

3.2.1 Reactor Vessel Nozzle-to-Shell Weld The J-R curves for the RV nozzle-to-shell welds are calculated based on Charpy models based on equations from NUREG/CR-5729 and provided in RG 1.161. Per RG 1.161, Section 3, the general form for J-R is:

= (){1()exp [3()]}

Per RG 1.161, Section 3.2, the parameters are defined as follows:

C1 = exp[-4.12 + 1.49 ln (CVN) - 0.00249T], where T is temperature in °F C2 = 0.077 + 0.116 lnC1 C3 = -0.0812 - 0.0092 lnC1 C4 = -0.5 MF = 0.629 for Levels A, B, C; MF = 1.0 for Level D.

CVN is the Charpy V-notch Impact Energy in ft-lbs. For the nozzle weld, the conservatively projected 80-year (70 EFPY) SLR upper shelf energy (USE) of [

]a,c,e in [4] is used. The J-R curves for the nozzle welds are shown in Figure 3-6 and Figure 3-7 and listed in Table 3-6.

Table 3-6: Nozzle-to-Shell Weld J-R Curves a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-9 WCAP-18944-NP August 2025 Revision 2 3.2.2 Reactor Vessel Nozzle Forging Base Metal The J-R curves for the RV nozzle forging base metal is calculated based on the Charpy models in Table 11 of NUREG/CR-5729. When the specimen net thickness, Bn = 1 inch, ln(Bn) = 0. The equations in NUREG/CR-5729 simplifies to RG 1.161, Section 3.3. The same the general form for J-R defined in RG 1.161, Section 3 is applicable. The parameters for RV base metal are defined in RG 1.161, Section 3.3.1:

C1 = exp[-2.44 + 1.13 ln (CVN) - 0.00277T], where T is temperature in °F C2 = 0.077 + 0.116 lnC1 C3 = -0.0812 - 0.0092 lnC1 C4 = -0.409 MF = 0.749 for Levels A, B, C; MF = 1.0 for Level D.

PWROG-23006-NP [3] provides the RV nozzle USE for the purpose of the EMA. These values are based on the data study of initial unirradiated USE of RV nozzles. [

] a,c,e As discussed in PWROG-23006-NP, while the orientation is identified as unknown data, this value is consistent with Watts Bar USE data and would bound RNP inlet nozzles. The J-R curves for the RV inlet and outlet nozzles are illustrated in Figure 3-8 through Figure 3-11, and listed in Table 3-7.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-10 WCAP-18944-NP August 2025 Revision 2 Table 3-7: Reactor Vessel Nozzle Forging J-R Curves a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 3-14 WCAP-18944-NP August 2025 Revision 2 Table 3-8: Robinson Reactor Vessel Shell Plate J-R Parameters at 70 EFPY Table 3-9: Reactor Vessel Upper and Intermediate Shell Plate J-R Curves a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-1 WCAP-18944-NP August 2025 Revision 2 4

FRACTURE MECHANICS ANALYSIS The EMA methodology that was used for the RNP RV locations with the projected USE below 50 ft-lbs is consistent with previously NRC approved methodologies for WCAP-13587, Rev. 1 [2] and PWROG-19047-NP-A [17]. The respective NRC Safety Evaluation Reports are in [19 and 20]. The EMA methodology is discussed further in Section 4.1. [

] a,c,e 4.1 METHODOLOGY DISCUSSION The J are calculated per ASME Section XI, Appendix K [6], which is consistent with the NRC approved EMA reports, WCAP-13587 [2] and PWROG-19047-NP-A [17]. The maximum J values at the critical time points for service Leves A/B and Level D, along with plots of J vs. flaw depth, are compared with the J-R curves for the EMA. The Levels A/B service loadings required by ASME XI, Appendix K, are based on accumulation pressure (internal pressure load) and a cooldown rate (thermal load). For Levels A/B, K-1300 and K-4000 of [6] conservatively defined the accumulation pressure as 1.1 times the design pressure, which is a constant pressure of 2,750 psia applied throughout the 100°F/hour cooldown transient.

The actual design thermal transients are used for the FEA stress and input for the KI and J calculations, instead of the generic design pressure and cooling rate in the ASME Section XI, Appendix K. As discussed in Section 2.1 of this report, the plant cooldown transient is used to bound all Levels A/B conditions. This is also consistent with the Appendix K guidance of 100°F/hour cooldown rate. The Level D SLB transient per the current design basis, WCAP-13587, Rev. 1 [2] is analyzed to bound Levels C/D conditions.

ASME Section XI, Appendix K [6] provides various postulated flaw depths, locations, and orientations, as well as the J and stability criteria. Per K-2000 of [6], the postulated flaws shall be oriented along the major axis of the weld of concern. Therefore, only circumferential flaws are applicable to the RV inlet and outlet nozzle welds. Both axial and circumferential flaws will be postulated for the nozzle forging and upper/intermediate shell plates.

4.1.1 Nozzle-to-Shell Welds and Upper/Intermediate Shell Forging For an axial or circumferential flaw of depth a, the stress intensity factor (SIF) due to radial thermal gradients can be calculated per K-4210(c) of [6]. However, since the thermal stresses are based on FEA, the procedure from ASME Section XI, Appendix A [6] is used to calculate SIFs. This method accurately captures the stress states of the actual geometry by representing the through-wall stress distribution as a polynomial equation. The same methodology is used for SIF due to pressure and mechanical loads.

The stress profile representation prescribed in A-3200 of [6] is for location over the flaw depth (x/a) for which the Ai coefficients need to be recalculated for every flaw depth analyzed. The term x is defined as distance through the wall measured from the flawed surface. In order to simplify the calculation, the analysis herein uses through-wall stress profiles (x/t) in a similar fashion. The procedure in A-3320 of [6]

is modified for the use of through-wall stress representation. This x/t approach is consistent with methods prescribed in publications such as API-579-1 [14] and A-3212 and A-3411(c) of the 2019 Edition of ASME Section XI [9]. Note that in Appendix A of the 2019 Edition of ASME Section XI, the same Gi coefficient tables are applicable for both the x/a and x/t method. This is an NRC accepted approach for previous

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-2 WCAP-18944-NP August 2025 Revision 2 EMAs for a number of SLR plants such as the North Anna EMA [17]. Additionally, 2021 Edition of ASME Section XI Appendix A includes the x/t methods consistent with the description herein.

The closed-form solution in K-4210 of [6] for SIF due to pressure loading, KIp is generic for cylinder geometry, which is appropriate for the RV. However, the closed-form solution for cylinder is overly conservative for the nozzle weld locations. Therefore, the method described in A-3200 of [6], including crack face pressure, with an actual FEA pressure stress profile will be used for the SIF calculations.

The through-wall stress profile is represented as follows by a cubic polynomial:

= +

+

+

= (+ ) +

+

+

= 1 + 4.593

= 1 6

+

+

+

Where:

 the stress perpendicular to the plane of the crack x = the distance from the inner surface where the crack initiates a = flaw depth, [in]

t = wall thickness, [in]

l = flaw length, [in]

Ai = coefficients from the cubic polynomial stress profile, i= 0, 1, 2, 3 Ap = 0 for thermal KIt; Ap = internal vessel pressure for pressure KIp Gi = free surface correction factors from Table A-3320-1 of [6] for point 1, the deepest point qy = plastic zone correction factor The plastic zone correction factor, qy, in this application is set to zero because K-4210 of [6] uses the effective flaw depth, ae, which already includes ductile flaw extension and a plastic zone correction.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-3 WCAP-18944-NP August 2025 Revision 2 4.1.2 Nozzle Corner KI Closed-Form Solution The nozzle corner flaws are considered using the quarter-circular crack in a quarter-space crack geometry shown in Figure 4-1 for which solutions are available in [10]. Crack tip KI values are computed using:

= + + +

= 0.723+ 0.551 2

+ 0.462 2 + 0.408 4 3

Where:

 the stress perpendicular to the plane of the crack, and A0, A1, A2, and A3 are the polynomial coefficients for the stress profile x = the distance from the inner surface where the crack initiates a = flaw depth Figure 4-1: KI Solution for Quarter-Circular Crack in Quarter-Space [10, page 5]

4.1.3 Calculation of J for Small-Scale Yielding The calculation of J due to applied loads accounts for a materials elastic-plastic behavior. When elastic fracture mechanics with small-scale yielding applies, J may be calculated using crack tip SIF formulae with a plastic zone correction.

The effective flaw depth for small-scale yielding, ae, shall be calculated per K-4210 of [6]:

= +

, [in]

Where, KIp and KIt are SIFs due to pressure and thermal stresses, respectively.

y = material yield strength, ASME temperature-dependent value is used, [ksi]

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-4 WCAP-18944-NP August 2025 Revision 2 Both axial and circumferential KIp and KIt are calculated the same way as KIp and KIt as described in Sections 4.1.1 and 4.1.2, except that the flaw depth, a, is substituted with the effective flaw depth, ae. Then, the J for small-scale yielding is calculated using the following formula:

= 1000

, [lbf/in]

Where:

E = E/(1-2), [ksi]

E = Youngs modulus, [ksi]

 Poissons ratio = 0.3 4.1.4 Postulated Flaws The procedures for the J calculation for Levels A/B are described in ASME Section XI, K-4000 [6]. The J calculation procedure for Level D is described in ASME Section XI, K-5000, which is the same as those for Levels A/B in K-4000, except that the effect of cladding/base metal differential thermal expansion needs to be considered for Levels C/D per K-5210(a). Therefore, stress data from the FEM with cladding is included for the Level D evaluation. Further details of the postulated flaw requirements per ASME Section XI, K-2200, K-2300 and K-2400 are summarized in Section 2.3.

4.1.5 Weld Residual Stress The weld residual stress (WRS) is to be included for nozzle-to-shell welds and shell plates. The normalized WRS profile is from [11, Section 4.1.3.4, Figure 30]. The WRS is directly added to FEA thermal stresses for the calculation of KIt. This is an NRC accepted approach for previous EMAs for a number of SLR plants such as the North Anna EMA [17].

4.1.6 Stress due to Mechanical Loads Since the structural factor (SF) is only applicable to pressure, the mechanical stress is directly added to the FEA thermal stress in the stress intensity factor calculations. The maximum through-thickness mechanical stress for design conditions is added to the corresponding thermal stresses. KI and J are calculated for all transient time points. The limiting J values for postulated flaws plus a 0.1-inch flaw extension, J1 are reported herein.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-5 WCAP-18944-NP August 2025 Revision 2 4.2 APPLIED J-INTEGRAL RESULTS AND COMPARISON WITH J-R CURVE ALLOWABLES The detailed methodology of the J evaluation is described in Section 4.1. As discussed in Section 2.1, the cooldown transient is evaluated for Levels A/B. FEA through-wall stress profiles were fitted to 3rd order polynomials, and A-3200 of [6] was used for the calculation of KIt and KIp instead of the generic closed-form solution in Appendix K of [6]. As discussed in Section 4.1, this is more accurate and is an NRC approved method. Unit pressure (1 ksi) FEA stress profiles were scaled to pressure transients and KIp was then calculated in the same manner as KIt using the 3rd order polynomial method. As described in Section 4.1.1, the crack face pressure was applied, and the double counting of the plastic zone correction was removed by setting the qy term in A-3200 of [6] to zero. The plastic correction was accounted for in the ae term per K-4210 of [6]. All KI and J are calculated for all transient time points. The limiting J values for the postulated flaws plus a 0.1-inch flaw extension are reported.

4.2.1 Nozzle-to-Shell Welds Levels A/B The J values for the postulated flaw plus a 0.1-inch flaw extension, J1 (from K-1300 nomenclature) with pressure SF = 1.15 and J with SF =1.25 for Level A/B are presented in Table 4-1. The applied J1 for both inlet and outlet nozzle welds are below the J-R at 0.1-inch flaw extension, J0.1 from Table 3-6. The acceptance criteria in ASME Section XI, K-2200 (a)(1) [6] is satisfied.

As shown in Figure 4-2 and Figure 4-3, the slope of J is less than the J-R curve at the intersection of both curves (i.e., when J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-2200 (a)(2)

[6] is satisfied.

The most limiting J is compared to the J-R curve for 600°F. This is conservative since 600°F bounds the maximum temperature during the cooldown transient.

Table 4-1: Inlet and Outlet Nozzle Welds Level A/B, Circumferential Flaw, Limiting J a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-6 WCAP-18944-NP August 2025 Revision 2 Figure 4-2: Outlet Nozzle Weld, Circumferential Flaw, Level A/B J vs. J-R, SF=1.25 Figure 4-3: Inlet Nozzle Weld, Circumferential Flaw, Level A/B J vs. J-R, SF=1.25 a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-7 WCAP-18944-NP August 2025 Revision 2 4.2.2 Nozzle-to-Shell Welds Level D The J and J1 values for nozzle-to-shell weld flaw extensions for Level D are presented in Table 4-2. As discussed in Section 2.3.2, SF = 1 for thermal and pressure. Since the 1/10 base metal wall thickness plus cladding exceeded 1 inch for all evaluated locations, the postulated flaw depth is 1 inch. The applied J1 for both inlet and outlet nozzle welds are below the J-R value, J0.1 from Table 3-6. The acceptance criteria in ASME Section XI, K-2300 (a)(1) [6] is satisfied.

As shown in Figure 4-4 and Figure 4-5, the slope of J is less than the J-R curve at the intersection of both curves (i.e., J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-2300 (a)(2) [6] is satisfied.

The most limiting J is compared to the J-R curve for 400°F. This is conservative since 400°F bounds the Level D transient metal temperature at the time point that results in the most limiting J.

Table 4-2: Inlet and Outlet Nozzle Welds Level D, Circumferential Flaw, Limiting J Additionally, as discussed in Section 2.3.2, K-5300(b) also requires that the remaining ligament is not subjected to tensile instability. As shown in Table 4-3, the Level D, SLB transient internal pressure of 2.5 ksi is significantly less than the tensile instability pressures, PI, calculated per K-5300(b). Therefore, the remaining ligament is not subjected to tensile instability.

a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-8 WCAP-18944-NP August 2025 Revision 2 Table 4-3: K-5300 Tensile Instability Check for Nozzle Welds Circumferential Flaws Figure 4-4: Outlet Nozzle Weld, Circumferential Flaw, Level D J vs. J-R, SF=1 a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-9 WCAP-18944-NP August 2025 Revision 2 Figure 4-5: Inlet Nozzle Weld, Circumferential Flaw, Level D J vs. J-R, SF=1 a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-10 WCAP-18944-NP August 2025 Revision 2 4.2.3 RV Nozzle Forgings Levels A/B The nozzle corner is the limiting location for the nozzle forging due to the wall thickness and the stress concentration effect. The J values for the postulated flaw plus a 0.1-inch flaw extension, J1 with pressure SF = 1.15 and J with SF =1.25 for Level A/B are presented in Table 4-4. All J1 are below the nozzle forging Levels A/B J-R, J0.1 from Table 3-7. The acceptance criteria in ASME Section XI, K-2200 (a)(1) [6] is satisfied.

As shown in Figure 4-6 to Figure 4-9, the slope of J is less than the J-R curve at the intersection of both curves (i.e., when J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-2200 (a)(2)

[6] is satisfied.

The most limiting J is compared to the J-R curve for 600°F. This is conservative since 600°F bounds the maximum temperature during the cooldown transient.

Table 4-4: Nozzle Corner Level A/B, Limiting J a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-11 WCAP-18944-NP August 2025 Revision 2 Figure 4-6: Outlet Nozzle Corner, Circumferential Flaw, Level A/B J vs. J-R, SF=1. 25 Figure 4-7: Inlet Nozzle Corner, Circumferential Flaw, Level A/B J vs. J-R, SF=1.25 a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-12 WCAP-18944-NP August 2025 Revision 2 Figure 4-8: Outlet Nozzle Corner, Axial Flaw, Level A/B J vs. J-R, SF=1.25 Figure 4-9: Inlet Nozzle Corner, Axial Flaw, Level A/B J vs. J-R, SF=1.25 a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-13 WCAP-18944-NP August 2025 Revision 2 4.2.4 RV Nozzle Forgings Level D The J and J1 values for RV forging flaw extensions for Level D are presented in Table 4-5. As discussed in Section 2.3.2, SF = 1 for thermal and pressure. Since the 1/10 base metal wall thickness plus cladding exceeded 1 inch for all evaluated locations, the postulated flaw depth is 1 inch. The applied J-integral for the postulated flaw plus a 0.1-inch flaw extension, J1 for nozzle circumferential and axial flaws are below the J-R value, J0.1 at 600°F for the inlet and outlet nozzle forgings from Table 3-7.

As shown in Figure 4-10 through Figure 4-13, the slopes of J is less than the J-R curve at the intersection of both curves (i.e., when J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-2300 (a)(2) [6] is satisfied.

The most limiting J is compared to the J-R curve for 600°F. This is conservative since 600°F bounds the maximum temperature during the Level D, SLB transient.

Table 4-5: Nozzle Corner Level D, Limiting J Additionally, as discussed in Section 2.3.2, K-5300(b) also requires that the remaining ligament is not subjected to tensile instability. As shown in Table 4-6, the Level D, SLB transient internal pressure of 2.5 ksi is significantly less than the tensile instability pressures, PI, calculated per K-5300(b). Therefore, the remaining ligament is not subjected to tensile instability.

a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-14 WCAP-18944-NP August 2025 Revision 2 Table 4-6: K-5300 Tensile Instability Check for Nozzle Forgings Circumferential and Axial Flaws a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-15 WCAP-18944-NP August 2025 Revision 2 Figure 4-10: Outlet Nozzle Corner, Circumferential Flaw, Level D J vs. J-R, SF=1 Figure 4-11: Inlet Nozzle Corner, Circumferential Flaw, Level D J vs. J-R, SF=1 a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-16 WCAP-18944-NP August 2025 Revision 2 Figure 4-12: Outlet Nozzle Corner, Axial Flaw, Level D J vs. J-R, SF=1 Figure 4-13: Inlet Nozzle Corner, Axial Flaw, Level D J vs. J-R, SF=1 a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-17 WCAP-18944-NP August 2025 Revision 2 4.2.5 Upper and Intermediate Shell Plates Levels A/B The J values for the postulated flaw plus a 0.1-inch flaw extension, J1 with pressure SF = 1.15 and J with SF =1.25 for Level A/B are presented in Table 4-7. The applied J1 for both circumferential and axial flaws are below the shell plate Level A/B J-R, J0.1 from Table 3-9. The acceptance criteria in ASME Section XI, K-2200 (a)(1) [6] is satisfied.

As shown in Figure 4-14 and Figure 4-15, the slope of J is less than the J-R curve at the intersection of both curves (i.e., when J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-2200 (a)(2) [6] is satisfied.

The shell plate FEA stresses were taken at the intersection of upper shell to the intermediate shell.

It captured the stress concentration effect; therefore, the results are applicable to both upper and intermediate shell plates.

Table 4-7: Upper and Intermediate Shell Plates Level A/B, Limiting J a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-18 WCAP-18944-NP August 2025 Revision 2 Figure 4-14: RV Shell, Circumferential Flaw, Level A/B J vs. J-R, SF=1.25 Figure 4-15: RV Shell, Axial Flaw, Level A/B J vs. J-R, SF=1.25 a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-19 WCAP-18944-NP August 2025 Revision 2 4.2.6 Upper and Intermediate Shell Plates Level D The J and J1 values for the upper and intermediate shell plates for Level D are presented in Table 4-8. As discussed in Section 2.3.2, SF = 1 for thermal and pressure. Since the 1/10 base metal wall thickness plus cladding exceeded 1 inch for all evaluated locations, the postulated flaw depth is 1 inch. The applied J-integral for the postulated flaw plus a 0.1-inch flaw extensions, J1 for both circumferential and axial flaws are below the J-R value, J0.1 from Table 3-9. The acceptance criteria in ASME Section XI, K-2300 (a)(1)

[6] is satisfied.

As shown in Figure 4-16 and Figure 4-17, the slope of J is less than the J-R curve at the intersection of both curves (i.e., J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-2300 (a)(2) [6] is satisfied.

Table 4-8: Upper and Intermediate Shell Plates Level D, Limiting J Additionally, as discussed in Section 2.3.2, K-5300(b) also requires that the remaining ligament is not subjected to tensile instability. As shown in Table 4-9, the Level D, SLB transient internal pressure of 2.5 ksi is significantly less than the tensile instability pressures, PI, calculated per K-5300(b). Therefore, the remaining ligament is not subjected to tensile instability.

a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-20 WCAP-18944-NP August 2025 Revision 2 Table 4-9: K-5300 Tensile Instability Check for Upper and Intermediate Shell Plates Circumferential and Axial Flaws Figure 4-16: RV Shell, Circumferential Flaw, Level D J vs. J-R, SF=1.0 a,c,e a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 4-21 WCAP-18944-NP August 2025 Revision 2 Figure 4-17: RV Shell, Axial Flaw, Level D J vs. J-R, SF=1.0 a,c,e

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 5-1 WCAP-18944-NP August 2025 Revision 2 5

CONCLUSIONS The RNP Unit 2 RV nozzle-to-shell welds, nozzle forgings and upper/intermediate shell plates were evaluated for equivalent margins of safety per ASME Code Section XI [6]. The flaw extension and stability criteria of ASME Section XI, Appendix K are satisfied for all locations evaluated herein.

Levels A/B For all evaluated locations, the J for the postulated flaw plus a 0.1-inch flaw extension (J1) with a structural factor (SF) of 1.15 for pressure and SF of 1.0 for thermal are below the J-material at 0.1-inch flaw extension (J0.1). Therefore, the acceptance criteria in ASME Section XI, K-2200 (a)(1) [6] is satisfied.

The slope of J (with a SF=1.25) is less than the J-material (J-R curve) at the intersection of both curves (i.e.,

when J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-2200 (a)(2) [6] is satisfied.

Level D For all the evaluated locations, the J1 with a SF of 1.0 are below the J0.1. Therefore, the acceptance criteria in ASME Section XI, K-2400 (a) [6] is satisfied.

The slope of J is less than the J-R curve at the intersection of both curves (i.e., when J = J-R). Therefore, the stability acceptance criteria in ASME Section XI, K-3400 [6] is satisfied. Using this approach, Level D loadings are shown to satisfy the more limiting Level C acceptance criteria established by K-2300 [6].

Per K-2400 of [6], all flaws evaluated for Level D assumed a flaw depth equal to 1/10 of the base metal thickness, plus the cladding thickness, (not exceeding 1 inch), plus a 0.1-inch flaw extension. All flaws evaluated herein have been shown to exhibit ductile and stable flaw extension when compared to J0.1 for all Level D loading conditions. This satisfies the 75% of wall thickness requirement, per K-2400 (c) [6], as the final flaw size, after extension, is much less than 75% of the wall thickness.

Additionally, the maximum Level D internal pressure is less than the tensile instability pressures calculated per K-5300 (b) [6] for all evaluated locations and flaws.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 6-1 WCAP-18944-NP August 2025 Revision 2 6

REFERENCES

1. RNP-2077-04-SLR-0001, Rev. 0, Reactor Coolant Systems Class 1 Component Analysis Required for RNP Unit 2 Subsequent License Renewal (80 years), June 28, 2022.

2. WCAP-13587, Rev. 1, Reactor Vessel Upper Shelf Energy Bounding Evaluation for Westinghouse Pressurized Water Reactors, September 1993.

3. PWROG-23006-NP, Rev. 0, H.B. Robinson Unit 2 Inlet and Outlet Nozzle Initial Upper-Shelf Energy Determination, July 2023.

4. WCAP-18766-NP, Rev. 0, H.B. Robinson Unit 2 Subsequent License Renewal: Time-Limited Aging Analyses (TLAAs) on Reactor Vessel Integrity (RVI), June 2024.

5. Code of Federal Regulations, 10 CFR Part 50, Appendix G, Fracture Toughness Requirements, U.S. Nuclear Regulatory Commission, Washington D.C., Federal Register, Volume 77, No. 14, January 23, 2012.

6. ASME Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, 2007 Edition, with 2008 Addenda. (Code of Record confirmed per

[7])

7. DUKE-RNP-SLR-22-004, Rev. 0, Design Input Request (DIR) Appendix L Evaluations, August 25, 2022.

8. DUKE-RNP-SLR-22-010, Rev. 0, Design Input Request (DIR) Reactor Vessel (RV) Integrity

- EMA (WS02h), November 21, 2022.

9. ASME Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, 2019 Edition.

10. S. A. Delvin and P. C. Riccardella, Fracture Mechanics Analysis of JAERI Model Pressure Vessel Test, ASME Paper No. 78-PVP-91, Proceedings of the 1978 ASME Pressure Vessels and Piping Conference, June 25-30, 1978, Montreal, Quebec, Canada.

11. Fracture Analysis of Vessels - Oak Ridge FAVOR, v05.1, Computer Code: Theory and Implementation of Algorithms, Methods, and Correlations, ORNL/NRC/LTR-05/18 (ADAMS Accession Number ML063350323).

12. NUREG/CR-5729, Multivariable Modeling of Pressure Vessel and Piping J-R Data, May 1991.

13. U.S. Nuclear Regulatory Commission Regulatory Guide 1.161, Evaluation of Reactor Pressure Vessels with Charpy Upper-Shelf Energy Less Than 50 Ft-Lb, June 1995.

14. API 579-1/ASME FFS-1, Fitness-For-Service, Annex 9B, Compendium of Stress Intensity Factor Solutions, June 2016.

15. BAW-2192NP Supplement 1, Rev. 0, Low Upper-Shelf Toughness Fracture Mechanics Analysis of Reactor Vessels of B&W Owners Reactor Vessel Working Group for Levels A &

B Service Loads, December 2017 (ADAMS Accession Number ML17354A012).

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 6-2 WCAP-18944-NP August 2025 Revision 2

16. BAW-2178NP Supplement 1, Rev. 0, Low Upper-Shelf Toughness Fracture Mechanics Analysis of Reactor Vessels of B&W Owners Reactor Vessel Working Group for Levels C &

D Service Loads, December 2017 (ADAMS Accession Number ML18029A199).

17. PWROG-19047-NP-A, Rev. 0, North Anna Units 1 and 2 Reactor Vessels Low Upper-Shelf Fracture Toughness Equivalent Margin Analysis, September 2021 (ADAMS Accession Number ML21264A535).

18. Material Properties for Finite Element Model in accordance to:

a. ASME Boiler & Pressure Vessel Code,Section III, 1965 Edition

b. ASME Boiler and Pressure Vessel Code,Section III, 1974 Edition

c. ASME Boiler and Pressure Vessel Code, Section II-D, 2010 Edition

19. NRC SE Report, Safety Assessment of Report WCAP-13587, Revision 1, Reactor Vessel Upper Shelf Energy Bounding Evaluation For Westinghouse Pressurized Water Reactors, September 1993, April 21, 1994.

20. NRC SE Report, Final Safety Evaluations for BAW-2192, Supplement 1NP, Revision, Low Upper-Shelf Toughness Fracture Mechanics Analysis of Reactor Vessels of B&W Owners Reactor Vessel Working Group for Level A&B Service Loads and BAW-2178, Supplement 1NP, Revision 0, Low Upper-Shelf Toughness Fracture Mechanics Analysis of Reactor Vessels of B&W Owners Reactor Vessel Working Group for Level C&D Service Loads, April 29, 2019 (ADAMS Accession Number ML19106A196).

21. 676367, Rev. 0, Reactor Vessel - Reactor Coolant System, June 8, 1966, modified by:

a. 676487, Rev. 0, Addendum to Equipment Specification 676376, Rev. 0, Reactor Vessel - Reactor Coolant System, February 21, 1967.

b. DS-MRCDA-12-2, Rev. 0, Addendum to H.B. Robinson Unit 2 Reactor Vessel Equipment Specification 676367, Rev. 0, April 25, 2012.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-1 WCAP-18944-NP August 2025 Revision 2 APPENDIX A Upper Shelf Fracture Toughness Testing of Robinson Reactor Pressure Vessel Steel Plate

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-2 WCAP-18944-NP August 2025 Revision 2 A.1 Background and Purpose Several of the H. B. Robinson Unit 2 Reactor Pressure Vessel (RPV) shell plates have sulfur above the A-302 Grade B plate cutoff of 0.018% set in Regulatory Guide (RG) 1.161[A1] for validity of the NUREG/CR-5729 [A2] Charpy prediction model. Therefore, upper-shelf fracture toughness (Jmaterial) has been measured rather than only depending on the closed form model in RG 1.161 and NUREG/CR-5729.

Westinghouse performed J-R curve tests per ASTM E 1820 [A3] determining Jmaterial using available unirradiated archive plate W10201-4. Several 0.5-inch-thick compact tension fracture toughness (0.5TC(T)) specimens were machined from the archive plate and tested according to ASTM E 1820 to ensure four fully valid tests were obtained with at least 2 valid tests at 390°F and 2 at 550°F.

The specimens were pre-cracked and tested per the requirements of ASTM E 1820. Full Jmaterial curves were developed as far as the capacity of the specimen permits. After testing the specimens were heat-tinted, broken open, the fracture surfaces measured, and photographed. The resulting lower bound Jmaterial toughness curve has been adjusted for reduction in fracture toughness due to neutron irradiation to the applicable 80-year fluence needed for the equivalent margins analysis (EMA). Plate W10201-5 also has high sulfur (S) but is not available in archives. The adjusted W10201-4 results bound the properties and chemistry of plate W10201-5. The bounding adjusted J-R curve for the measured unirradiated plate W10201-4 can be used for Jmaterial for all the beltline plates in the EMA.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-3 WCAP-18944-NP August 2025 Revision 2 A.2 Summary of Results and Conclusions The results of the ASTM E1820-15 ductile fracture toughness testing of unirradiated archive plate W10201-4 are summarized in Table A2-2. Figure A2-1 through Figure A2-7 show the plots of the fracture toughness J-R (J versus a where a is the stable crack extension) curves.

Extra J-R curve tests were conducted as part of this test program to ensure valid results were obtained.

Some tests were also conducted with specimen orientation of L-T (strong) in case the analysis cannot pass with the conservative weak direction (T-L) results. Please note that test L-TB4 is not valid and is an approximate value. The L-T orientation is expected to have higher toughness than T-L, however, test L-TB3 has a lower measured JIc value than the T-L tests at the 288°C test temperature. For the other tests shown in Table A2-2, some had minor E1820 validity criteria violations but can be considered reliable and valid tests.

Conservatively, a mean - 2standard deviations) lower bound and mean J-R curve was determined which is lower than the lowest T-L JIc, C (J@1 mm) and J at 2.54 mm (0.1 inch) values measured and should be used for all temperatures from 199°C to 291°C as shown in Table A2-1a and Table A2-1b, respectively.

Typically, one would expect a lower upper-shelf toughness at higher temperature. This measured unirradiated toughness is adjusted to the fluence of interest applicable to subsequent license renewal (SLR) as shown in Table A2-1a and Table A2-1b, which is bounding for all the upper and intermediate shell plates.

JIc is the onset of stable crack extension, and the J-R curve is described by the following power law equation with C and n values shown in Table A2-1a, Table A2-1b and Table A2-2:

J = C

• an Table A2-1a: Predicted Lower Bound Toughness Values for EMA at 70 EFPY for Upper and Intermediate Shell Plates for 199°C to 291°C Vessel Location Fluence (x 1019 n/cm2, E > 1.0 MeV)

Projected RG1.99R2 USE Decrease

(%)

JIc C

n kJ/m2 in-lb/in2 kJ/m2 in-lb/in2 Unirradiated 0.0 0%

110 627 184 4225 0.43 1/10T 7.077 32%

75 426 125 2873 0.43 1/4T 5.061 30%

77 439 129 2958 0.43 Table A2-1b: Predicted Mean Toughness Values for EMA at 70 EFPY for Upper and Intermediate Shell Plates for 199°C to 291°C Vessel Location Fluence(b)

(x 1019 n/cm2, E > 1.0 MeV)

Projected RG1.99R2 USE Decrease

(%)

JIc C

n kJ/m2 in-lb/in2 kJ/m2 in-lb/in2 Unirradiated 0.0 0%

150 856 216 4969 0.43 1/10T 7.077 32%

102 582 147 3379 0.43 1/4T 5.061 30%

105 599 151 3479 0.43

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-8 WCAP-18944-NP August 2025 Revision 2 A.3 References

[A1]

U.S. Nuclear Regulatory Commission Regulatory Guide 1.161, Evaluation of Reactor Pressure Vessels with Charpy Upper-Shelf Energy Less Than 50 Ft-Lb, June 1995.

[A2]

E. D. Eason, L. E. Wright, and E. E. Nelson, Multivariable Modeling of Pressure Vessel and Piping J-R Data, NUREG/CR-5729, US Nuclear Regulatory Commission, May 1991.

[A3]

ASTM E 1820-15, Standard Test Method for Measurement of Fracture Toughness, ASTM International, 2015.

[A4]

WCAP-7373, Carolina Power and Light Co. H. B. Robinson Unit No. 2 Reactor Vessel Radiation Surveillance Program, S.E. Yanichko, January 1970.

[A5]

SA-302, Specification for Manganese-Molybdenum and Manganese-Molybdenum-Nickel Steel Plates for Pressure Vessels, ASME B&PV Section II, 1966 Winter Addenda.

[A6]

NUREG/CR-5265, Size Effects on J-R Curves for A 302-B Plate, U.S. Nuclear Regulatory Commission, January 1989.

[A7]

WCAP-17651-NP, Revision 0, Palisades Nuclear Power Plant Reactor Vessel Equivalent Margins Analysis, February 2013.

[A8]

PWROG-20043-NP, Revision 0, PBN Unit 1 IS Plate A9811-1 Equivalent Margins Analysis for SLR, October 2020.

[A9]

WCAP-13554, Revision 0, Effects of Section Size and Cleanliness on the Upper Shelf and Transition Range Toughness of Three Nuclear Pressure Vessel Steels, August 1992.

[A10] Radiation Embrittlement of Reactor Vessel Materials, Regulatory Guide 1.99, Revision 2 (Washington, DC: U.S. Nuclear Regulatory Commission, 1988).

[A11] T. Ogawa, J. B. Hall, B. E. Mays, and T. C. Hardin, Upper Shelf Energy Prediction Model for Irradiated Reactor Pressure Vessel Steels, Proceedings of the ASME 2017 Pressure Vessel &

Piping Conference, ASME 2017.

[A12] WCAP-18766-NP, Rev. 0, H.B. Robinson Unit 2 Subsequent License Renewal: Time-Limited Aging Analyses (TLAAs) on Reactor Vessel Integrity (RVI), June 2024.

[A13] T. Ogawa, J. B. Hall, and B. E. Mays, Prediction Model for the Decrease in Upper Shelf Energy of Reactor Vessel Steel Due to Neutron Embrittlement, MRP-414 (Palo Alto, CA: EPRI, 2016).

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-9 WCAP-18944-NP August 2025 Revision 2 A.4 Testing Methods and Acceptance Criteria All the specimens were precracked at room temperature in the irradiated condition in the low-level cell at Churchill in accordance with ASTM E1820-20. The number of cycles ranged from 49,000 to 64,000. All precrack loads are acceptable with maximum precrack load being 6.1kN. A sine wave generator was used for precracking with a frequency around 20 Hz and a minimum/maximum ratio of between 0.1 and 0.2.

An inboard clip gage was used to measure displacement on the load-line. The gauge knife edges were integrally machined into the specimen load-line as shown in Figure A5-1. The specimen temperature was controlled by a split tube furnace. Two thermocouples were placed specimens to record the specimen temperature. One was spot welded to the specimen and the other was magnetically attached as an independent check.

Before performing each test, precycles were conducted to measure crack depth by measuring load vs.

CMOD compliance to ensure the clip gage is properly seated and to enable calculation of crack depth and consistency according to Section 8.6.3.1 of E1820.

The calculation methodology is according to ASTM E1820-15 Annex A9. The various acceptance criteria in E1820 are checked as applicable.

A.5 Input Plate W10201-4 is reported as SA-302-B in the certified material test report (CMTR) versus SA 302 Grade A in WCAP-7373 [A4]. The chemistry reported in [A4] is consistent between the CMTR and is shown in Table A5-1. Both grade specifications from SA-302 from the 1966 ASME Code [A5] for comparison are shown in Table A5-1.

Table A5-1: Plate W10201-4 Chemistry and Tensile Properties Specification or Heat Measurement C

Mn P

S Si Mo Yield (ksi)

Tensile (ksi)

Elong.

(%)

Red.

Area

(%)

SA-302-A Spec.

0.25 max 0.90-1.35 0.035 max 0.040 max 0.13-0.32 0.41-0.64 45 75-95 15 19 SA-302-B Spec.

0.25 max 1.10-1.55 0.035 max 0.040 max 0.13-0.32 0.41-0.64 50 80-100 15 18 Heat A6604-1 Plate W10201-4 0.19 1.35 0.007 0.019 0.23 0.48 55.0 77.51 33.0 62.7 Note:

1 The tensile strength tested for the RV surveillance program in both TL and LT orientations are greater than 80 ksi [A4].

Plate W10201-4 meets the requirements for both Grade A and Grade B and is therefore considered as SA-302 Grade B consistent with the CMTR, hereafter.

Figure A5-1 illustrates the W10201-4 plate material removed from archival storage. The plate was stamped identifying it at Lukens Heat No. A6604-1 and plate W10201-4 consistent with the CMTR and

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-11 WCAP-18944-NP August 2025 Revision 2 Figure A5-2: Photograph of the Archival Block Showing the Location of Extraction of the Test Material Figure A5-3: 0.5TC(T) Isometric

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-12 WCAP-18944-NP August 2025 Revision 2 Table A5-2: Test specimens Specimen ID Thickness Location Orientation L-TB1 to L-TB4 3/4T from top L-T strong T-LU1 to T-LU6 1/4T from top T-L weak T-LB8 (T-LB7 not used) 3/4T from top T-L weak Measurements were taken from the specimen fracture surface for precrack and final crack size and specimen side surface photos and scaled using the scale bar.

Tensile properties were taken from WCAP-7373 [A4] which are surveillance program baseline test results with the relevant results shown in Table A5-3.

Table A5-3: Material Properties for Plate W10201-4 [A4]

Orientation Test Temperature

°F 0.2% Yield Strength (ksi)

Ultimate Strength (ksi)

L-T 400 56.4 79.6 L-T 600 57.1 84.0 T-L 400 55.8 77.4 T-L 600 56.2 82.7

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-13 WCAP-18944-NP August 2025 Revision 2 A.6 J-R Curve Test Results The precracking met the requirements of E1820 [A3], therefore all the precracks were acceptable. T-LB8 failed the A9.9.2.2 a0q R2 requirement of >0.96 by a small amount (0.93). Regardless of the failure of the a0q positioning criteria, the a0q a position was definitively obtained and is positioned as expected through inspection of the blunting line relative to the J-R curve, therefore the determination of JQ can be determined with certainty even though a fully valid E1820 JIc measurement was not obtained. Test T-LU6, 2 of the 9 final crack length measurements were short violating the crack straightness criteria of 8.4.5 of E1820 which may affect slightly the J-R curve affecting the C or n value.

Tests L-TB1, L-TB2, T-LU1 and T-LU2 had a large backup rather than following the blunting line and T-LU2 had a crooked precrack. These are not included in the summary table as the results are not reliable.

A.7 Adjustment of Measured J Data to account for Neutron Irradiation The measured upper-shelf toughness (J) data was adjusted to account for the reduction in toughness due to neutron irradiation. RG1.161 recommends use of NUREG/CR-5265 [A6] or a material-specific justification IRUSODWHVZLWK65*KDVDQXSSHUOLPLWLQVXOIXUEHFDXVH--R data for plates with high sulfur content are scarce and the available data showed low toughness, flat J-R curves, and a size effect.

The most data available for a high-sulfur A-302B plate are for the V-50 plate as reported in NUREG/CR-5265. The V-50 plate was unusual in that it had a test specimen size effect that has not been observed in other RV material J-R curves and is unique to the V-50 plate. A high content of manganese-sulfide (MnS) inclusions and banded regions of microstructure are believed to be the causes of the unusual specimen size effect observed and the relatively low toughness. The inclusions and banded microstructure are not seen in any of the fracture surfaces of the tested 0.5TC(T) specimens tested from plate W10201-4.

In addition, the lowest measured toughness of the W10201-4 plate is higher than the V-50 plate highest values even though the W10201-4 the J-R curve was conducted at 199°C, 117°C higher than the V-50 plate data as shown in Figure A7-1. For these reasons, the V-50 plate is not considered representative and the actual measured toughness of W10201-4 is used with reduction to account for irradiation. This conclusion is consistent with the Palisades and Point Beach equivalent margins analyses [A7] and [A8]. In addition, comparison of test results to another high sulfur plate (S = 0.022%) [A9] tested on 0.5 to 8 inch thick bend bars of a A302B plate shows that the W10201-4 lower bound result, bounds the larger specimens from this 1992 test program.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-14 WCAP-18944-NP August 2025 Revision 2 Figure A7-1: Comparison of W10201-4 Plate to V-50 Plate J-R Curve Two methods are considered to reduce toughness to account for irradiation with the more conservative being chosen:

1.

Since Charpy upper-shelf energy (USE) is correlated with J, the reduction according to RG1.99 R2 [A10] is considered in reducing the measured J values, and 2.

The reduction according to a more modern USE prediction model [A11] is considered for reduction of the measured J values.

A.7.1 RG1.99 R2 Reduction in USE RG1.99R2 predicted reduction in USE is calculated in WCAP-18766-NP [A12] and is shown in Table A7-1. The W10201-4 plate falls within the limitations stated in RG1.99R2 section 1.3 and there is no sulfur limitation for predicting USE reduction. As shown in Table 5-2 of WCAP-18766-NP [A12], the W10201-4 plate predicted USE at 1/4T considering the measured USE drop according to RG1.99R2 Position 2.2 is 18%, which is bounded by the 30% calculated from RG1.99R2 Position 1.2. The measured value being bounded by the general RG Position 1.2 model indicates that the higher sulfur content of this plate does not have a deleterious effect on the USE decrease and the Table A7-1 USE drop values can conservatively be applied to the measured J values.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-15 WCAP-18944-NP August 2025 Revision 2 Table A7-1: Predicted USE for EMA at 70 EFPY for Intermediate Shell Plate W10201-4 [A12]

Vessel Location Fluence (x 1019 n/cm2, E > 1.0 MeV)

Projected USE Decrease (%)

Projected SLR USE (ft-lbs) 1/10T 7.077 32%

42.2 1/4T 5.061 30%

43.4 A.7.2 Modern USE Reduction Prediction Several modern best-estimate USE prediction models were developed by Ogawa et al. for EPRI using 1,177 international RV surveillance program measured changes in USE due to irradiation [A11] and [A13]. The selected models have no significant residual trend with any inputs that include initial USE, fluence, irradiation temperature, copper, nickel, manganese, sulfur, and product form. The C-1 model developed by EPRI-Ogawa has an associated 2x standard deviation that provides a prediction that bounds at least 95%

of the measured USE data that are a function of the predicted USE. The improved model was verified to perform well for the subset of low-USE materials (<100 J), which are of most concern with the EPRI-Ogawa C-1 model bounding 97% of the low-USE measured data. The Ogawa C-1 model included materials in the database with sulfur content up to 0.026% and is therefore applicable to Plate W10201-4 which has 0.019% sulfur. The Ogawa C-1 model is performed with the result shown in Table A7-2.

Table A7-2: Predicted USE Values for EMA at 70 EFPY for Intermediate Shell Plate W10201-4 using Modern Prediction Vessel Location Fluence (x 1019 n/cm2, E > 1.0 MeV)

Projected median USE Decrease (%)

Projected median -

2*SD USE Decrease

(%)

1/10T 7.077 12%

28%

1/4T 5.061 11%

28%

These values in Table A7-2 are bounded by the RG1.99R2 predicted decrease shown in Table A7-1, therefore, conservatively, the percent decrease shown in Table A7-1 is applied to the lower bound J-R curve developed in the next section.

A.7.3 Plate W10201-4 Irradiated J-R Curve The mean and standard deviation (for the 5 T-L tests are calculated for JIc, C (J at 1 mm) and J at 2.54 mm. The mean - 2is calculated for each of these points along the J-R curve and includes J at 0.1 inch since this is used in the EMA. A mean - 2lower bound curve was iteratively selected so that the curve lies at or below mean - 2at JIc, 1 mm and 2.54 mm. The lower bound curve is represented by C=184 kJ/m2, n=0.43 and bounds the lowest measured test and mean - 2and is therefore conservatively used for all temperatures between 199 and 288°C at 70 EFPY as shown in Table A7-3.

Table A7-4 shows the decrease of the lower bound J-R curve using the RG1.99R2 decrease.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-16 WCAP-18944-NP August 2025 Revision 2 Table A7-3: Lower Bound Unirradiated Plate W10201-4 J-R Curve Orientation, Thickness Location Test Temperature

(°C)

Specimen ID JIc (kJ/m2)

C (J@1mm)

(kJ/m2) n J@2.54mm (J@0.1 in)

(kJ/m2)

T-L, 1/4T 288 T-LU3 150 216 0.35 299 288 T-LU4 174 233 0.30 308 199 T-LU5 140 203 0.36 284 199 T-LU6 162 230 0.36 322 T-L, 3/4T 199 T-LB8 123 200 0.44 301 Mean 150 216 303 19.7 15.1 13.7 mean - 2 110 186 275 Lower Bound:

C=184, n=0.43 199 - 288 110 184 0.43 275 Table A7-4: Lower Bound Predicted Toughness Values for EMA at 70 EFPY for Intermediate Shell Plate W10201-4 Vessel Location Fluence(b)

(x 1019 n/cm2, E > 1.0 MeV)

Projected RG1.99R2 USE Decrease

(%)

JIc C

n kJ/m2 in-lb/in2 kJ/m2 in-lb/in2 Unirradiated 0.0 0%

110 627 184 4225 0.43 1/10T 7.077 32%

75 426 125 2873 0.43 1/4T 5.061 30%

77 439 129 2958 0.43 A.7.4 Other Beltline Plates Plate W10201-5 (Heat B-1256-1) also has high sulfur (0.021%) and is predicted to drop below 50 ft-lb USE per WCAP-18766-NP [A12], but is not available in archives for testing. This heat is contained in some of the surveillance capsules that have been tested and Capsule U which is planned for withdrawal and testing in a few years. It is recommended that high S plates W10201-4 and W10201-5 be tested for upper-shelf fracture toughness when Capsule U is withdrawn and tested. There are 2 upper shell plates (W10201-1 and W10201-3) and 2 lower shell plates (W10201-4 and W10201-5) projected to drop below 50 ft-lbs per Table 5-3 of WCAP-18766-NP [A12]. Plate W10201-5 has higher S than the tested plate W10201-4, however the tested W10201-4 plate has the lowest projected USE due to its higher Cu content and lower starting USE, therefore the W10201-4 projected J-R properties are bounding for all the upper and intermediate shell plates. In addition, all 3 of the intermediate shell plates have measured irradiated USE values which when projected using the RG1.99R2 Position 2.2 methodology are bounded by the Position 1.2 projections.

Therefore, the RG1.99R2 Position 1.2 projections are conservative and the measured J-R curve projected to SLR fluence can be conservatively used for all the plates.

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-17 WCAP-18944-NP August 2025 Revision 2 A.7.5 Plate W10201-1 and Weld W5214 Irradiated J-R Testing Upper shell plate W10201-1 weld W5214 were available from the tested Capsule X HAZ specimens irradiated to 4.42 x 1019 n/cm2 which is significantly higher than either material is projected to reach during SLR [A12]. This plate and weld were machined into 0.16TC(T) specimens and tested mostly in the ductile-brittle transition region. However, one of each was tested slightly above this region and a full J-R curve was generated for each according to ASTM E1820-15 [A3]. The plate result was significantly higher than the measurement capacity of the small specimen and is therefore not a valid measure of JIc, in addition to a couple of other violations (see Table A7-5 and Figure A7-2). However, it demonstrated very good toughness at this high fluence which is greater than the projected Intermediate Shell Plate W10201-4 toughness at SLR fluence providing support to the projected toughness values reported in Table A7-4. The weld test had a number of test violations primarily due to the small specimen size, therefore the reported JQ is approximate. However, the JQ and J-R curve measured values are significantly higher than the projected J-R curve properties for Intermediate Shell Plate W10201-4 toughness at SLR fluence also providing support to the projected toughness values reported in Table A7-4 being lower bound for the RPV. It is noted that the test temperature and fluence are different, so a direct quantitative comparison cannot be made.

Table A7-5: Invalid Toughness Properties of Specimens Irradiated in Capsule X to Fluence of 4.42 x 1019 n/cm2 Material Test Temperature

(°C)

JQ (kJ/m2)

JIc Validity Violation C

n J-R Curve Validity Violation Specimen ID Upper shell plate W10201-1

-31

~4021 Multiple1

~506

~0.35 Multiple1 PB Weld W5214 78

~1292 Multiple2

~253

~0.55 Multiple2 WU Notes:

1. Significant E1820-15 violations included: Significantly exceeds Jmax (A8.3.2); Final crack front straightness violation (9.1.4.2); and blunting line crack size measurements exceed noise limit (A9.9.2.2).

2. Significant E1820-15 violations included: Final crack front straightness violation (9.1.4.2);

Compliance measured a does not agree with optical fracture surface measurement (9.1.5.2); Minor violations included: blunting line crack size measurements exceed noise limit slightly (A9.9.2.2) and initial a straightness (9.1.4.1).

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-19 WCAP-18944-NP August 2025 Revision 2 A.8 Detailed Test Results Specimen ID L-TB4 JQ 255.8 kJ/m2 Fluence 0

n/cm2 C1 310.9 Test Temperature 200

°C C2 0.26 Width [W]

25.40 mm KJQ 232.0 Mpa Thickness [B]

12.70 mm Tensile Strength 549 MPa Jmax; A8.3.1 YES Yield Strength 389 MPa amax; A8.3.2 YES Net Thickness 9.95 mm a final crack straightness; 9.1.4.2 YES Initial adjusted crack length 12.36 mm Initial fatigue crack length (measured) 12.08 mm a0 crack straightness; 9.1.4.1 YES Final crack length (calculated) 14.70 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 15.08 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 NO Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 NO Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 6.6 0.10 12.40 0.04 34.3 5.6 2

7.9 0.13 12.37 0.01 40.8 8.7 3

9.0 0.15 12.39 0.03 46.6 12.4 4

9.8 0.18 12.36 0.00 50.7 16.7 5

10.4 0.20 12.38 0.02 54.0 21.0 6

10.9 0.23 12.38 0.02 56.4 25.8 7

11.2 0.25 12.37 0.01 58.0 30.9 8

11.4 0.28 12.40 0.04 59.5 35.8 9

11.6 0.31 12.38 0.02 60.4 41.3 10 11.8 0.33 12.40 0.04 61.5 46.3 11 12.0 0.36 12.39 0.03 62.2 51.7 12 12.1 0.38 12.44 0.08 63.3 56.7 13 12.2 0.41 12.44 0.08 63.9 62.1 14 12.3 0.43 12.45 0.09 64.6 67.6 15 12.5 0.46 12.46 0.10 65.3 72.9 16 12.6 0.48 12.46 0.10 65.9 78.6 17 12.7 0.51 12.47 0.11 66.5 84.1 18 12.8 0.53 12.48 0.12 67.1 89.6 19 12.9 0.56 12.47 0.11 67.4 95.5 20 12.9 0.59 12.49 0.13 68.1 100.9 21 13.0 0.61 12.48 0.12 68.4 106.9 22 13.1 0.64 12.50 0.14 69.0 112.5 23 13.2 0.66 12.51 0.15 69.6 118.2 24 13.3 0.69 12.49 0.13 69.8 124.5 25 13.4 0.71 12.52 0.16 70.5 129.9 26 13.4 0.74 12.51 0.15 70.7 136.1 27 13.5 0.76 12.54 0.18 71.1 141.6 28 13.5 0.79 12.54 0.18 71.4 147.6 29 13.5 0.81 12.54 0.18 71.5 153.7 30 13.5 0.84 12.58 0.22 72.0 159.1 31 13.5 0.86 12.59 0.23 71.9 165.0 32 13.5 0.89 12.64 0.28 72.4 170.0 33 13.6 0.92 12.59 0.23 72.1 177.3 34 13.6 0.94 12.49 0.13 71.5 185.5 35 13.7 0.97 12.51 0.15 71.9 191.0 36 13.7 0.99 12.54 0.18 72.2 196.6 37 13.7 1.02 12.58 0.22 72.9 201.6 38 13.7 1.04 12.58 0.22 73.0 207.8 39 13.8 1.07 12.61 0.25 73.4 213.4 40 13.8 1.09 12.66 0.30 73.9 218.4 41 13.8 1.12 12.65 0.29 74.0 224.8 42 13.8 1.14 12.71 0.35 74.4 229.5 43 13.8 1.17 12.74 0.38 74.7 235.1 44 13.8 1.19 12.76 0.40 74.9 240.6 45 13.8 1.22 12.81 0.45 75.4 245.5 46 13.8 1.24 12.82 0.46 75.5 251.5 47 13.8 1.27 12.88 0.52 75.9 256.2 48 13.8 1.30 12.85 0.49 75.7 263.2 49 13.7 1.32 12.91 0.55 75.9 267.9 50 13.6 1.35 12.96 0.60 75.9 272.6 51 13.6 1.37 12.98 0.62 75.7 278.1 52 13.5 1.40 13.06 0.70 76.3 281.8 53 13.4 1.42 13.07 0.71 75.8 287.7 54 13.3 1.45 13.13 0.77 75.8 292.1 55 13.3 1.47 13.17 0.81 75.9 296.9 56 13.2 1.50 13.22 0.86 75.7 301.4 57 13.1 1.52 13.30 0.94 76.0 304.7 58 13.0 1.55 13.31 0.95 75.8 310.7 59 12.9 1.58 13.40 1.04 76.0 313.4 60 12.8 1.60 13.45 1.09 75.9 317.6 61 12.7 1.63 13.49 1.13 75.9 322.2 62 12.7 1.65 13.55 1.19 76.0 325.9 63 12.5 1.68 13.58 1.22 75.5 331.0 64 12.4 1.70 13.69 1.33 75.8 332.6 65 12.3 1.73 13.74 1.38 75.7 336.5 66 12.2 1.75 13.79 1.43 75.3 340.8 67 12.1 1.78 13.85 1.49 75.3 344.5 68 12.0 1.80 13.89 1.53 75.0 348.6 69 11.7 1.83 13.97 1.61 74.3 351.2 70 11.5 1.86 14.07 1.71 73.8 352.7 71 11.1 1.91 14.21 1.85 72.6 358.0 72 10.7 1.96 14.36 2.00 71.9 361.9 73 10.4 2.01 14.56 2.20 71.4 363.8 74 10.1 2.06 14.70 2.34 71.4 368.0 J-R Curve Valid; A8 JIc Valid; A9

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-20 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-21 WCAP-18944-NP August 2025 Revision 2 Specimen ID L-TB3 JQ 132.0 kJ/m2 Fluence 0

n/cm2 C1 251.2 Test Temperature 291

°C C2 0.59 Width [W]

25.40 mm KJQ 164.2 Mpa Thickness [B]

12.70 mm Tensile Strength 580 MPa Jmax; A8.3.1 YES Yield Strength 394 MPa amax; A8.3.2 YES Net Thickness 9.95 mm a final crack straightness; 9.1.4.2 YES Initial adjusted crack length 12.13 mm Initial fatigue crack length (measured) 12.08 mm a0 crack straightness; 9.1.4.1 YES Final crack length (calculated) 14.38 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 14.69 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 YES Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 YES Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 6.5 0.10 12.19 0.06 33.2 5.4 2

7.8 0.13 12.16 0.02 39.2 8.4 3

8.7 0.15 12.17 0.03 44.2 11.8 4

9.5 0.18 12.15 0.02 47.9 15.7 5

10.1 0.20 12.16 0.03 51.0 19.9 6

10.5 0.23 12.14 0.01 53.1 24.4 7

10.9 0.25 12.15 0.02 55.0 28.9 8

11.2 0.28 12.15 0.02 56.4 33.7 9

11.4 0.31 12.15 0.02 57.6 38.5 10 11.6 0.33 12.19 0.06 59.0 43.4 11 11.8 0.36 12.22 0.09 60.1 50.4 12 12.0 0.38 12.25 0.11 61.2 55.4 13 12.1 0.41 12.28 0.14 62.3 60.6 14 12.3 0.43 12.26 0.13 62.9 66.1 15 12.4 0.46 12.30 0.17 64.0 71.2 16 12.6 0.48 12.30 0.16 64.6 76.7 17 12.7 0.51 12.34 0.21 65.6 81.9 18 12.8 0.53 12.33 0.20 66.2 87.6 19 13.0 0.56 12.36 0.22 67.0 93.0 20 13.0 0.59 12.39 0.26 67.8 98.4 21 13.1 0.61 12.39 0.26 68.3 104.2 22 13.2 0.64 12.44 0.31 69.2 109.3 23 13.3 0.66 12.43 0.30 69.6 115.4 24 13.4 0.69 12.45 0.32 70.3 121.0 25 13.5 0.71 12.46 0.33 70.7 126.9 26 13.6 0.74 12.51 0.38 71.5 132.2 27 13.6 0.76 12.54 0.41 72.1 137.8 28 13.7 0.79 12.54 0.40 72.4 144.1 29 13.8 0.81 12.57 0.43 72.9 149.7 30 13.8 0.84 12.59 0.46 73.4 155.4 31 13.8 0.86 12.62 0.48 73.8 161.2 32 13.9 0.89 12.65 0.52 74.3 166.7 33 13.9 0.92 12.66 0.53 74.5 172.7 34 13.9 0.94 12.70 0.57 75.0 178.2 35 13.9 0.97 12.73 0.60 75.4 183.9 36 14.0 0.99 12.75 0.62 75.7 189.9 37 14.0 1.02 12.79 0.66 76.1 195.2 38 14.0 1.04 12.78 0.64 76.0 202.1 39 13.9 1.07 12.82 0.68 76.2 207.5 40 13.9 1.09 12.84 0.70 76.4 213.4 41 14.0 1.12 12.87 0.74 76.8 218.9 42 14.0 1.14 12.92 0.78 77.3 224.0 43 14.0 1.17 12.91 0.78 77.2 230.6 44 13.9 1.19 12.95 0.82 77.4 236.1 45 13.9 1.22 12.98 0.85 77.4 241.5 46 13.8 1.25 13.00 0.87 77.4 247.5 47 13.7 1.27 13.06 0.93 77.4 252.1 48 13.6 1.30 13.11 0.97 77.1 257.3 49 13.5 1.32 13.21 1.08 77.3 260.4 50 13.4 1.35 13.25 1.12 77.2 265.3 51 13.3 1.37 13.30 1.16 77.1 270.2 52 13.3 1.40 13.34 1.21 77.5 275.0 53 13.2 1.42 13.36 1.22 77.3 280.8 54 13.2 1.45 13.42 1.29 77.8 285.0 55 13.2 1.47 13.44 1.31 77.9 290.5 56 13.2 1.50 13.47 1.34 78.1 295.9 57 13.1 1.53 13.54 1.40 78.6 299.8 58 13.1 1.55 13.54 1.40 78.4 306.1 59 13.1 1.58 13.60 1.46 78.8 310.2 60 13.0 1.60 13.60 1.47 78.8 316.2 61 12.8 1.65 13.71 1.57 78.6 325.2 62 12.7 1.70 13.77 1.64 78.6 335.0 63 12.7 1.76 13.84 1.71 78.8 344.8 64 12.5 1.81 13.92 1.79 78.7 353.4 65 12.3 1.86 14.03 1.90 78.6 361.3 66 12.1 1.91 14.13 2.00 78.2 368.8 67 11.8 1.96 14.23 2.09 77.4 376.5 68 11.5 2.01 14.38 2.25 77.2 381.2 J-R Curve Valid; A8 JIc Valid; A9

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-22 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-23 WCAP-18944-NP August 2025 Revision 2 Specimen ID T-LU3 JQ 150.4 kJ/m2 Fluence 0

n/cm2 C1 216.4 Test Temperature 288

°C C2 0.35 Width [W]

25.40 mm KJQ 175.3 Mpa Thickness [B]

12.70 mm Tensile Strength 571 MPa Jmax; A8.3.1 YES Yield Strength 388 MPa amax; A8.3.2 YES Net Thickness 9.95 mm a final crack straightness; 9.1.4.2 YES Initial adjusted crack length 11.89 mm Initial fatigue crack length (measured) 12.08 mm a0 crack straightness; 9.1.4.1 YES Final crack length (calculated) 14.71 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 15.30 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 YES Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 YES Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 6.5 0.10 11.96 0.07 32.2 5.1 2

7.7 0.13 11.94 0.05 37.8 8.1 3

8.6 0.15 11.93 0.04 42.4 11.7 4

9.3 0.18 11.90 0.01 45.7 15.6 5

9.9 0.20 11.93 0.04 48.5 19.6 6

10.3 0.23 11.89 0.00 50.3 24.1 7

10.6 0.25 11.89 0.00 51.9 28.5 8

10.9 0.28 11.91 0.02 53.3 33.1 9

11.1 0.30 11.87

-0.02 54.2 38.0 10 11.3 0.33 11.94 0.05 55.6 42.5 11 11.5 0.36 11.90 0.01 56.3 47.6 12 11.6 0.38 11.97 0.07 57.6 52.1 13 11.8 0.41 11.98 0.09 58.5 57.1 14 12.0 0.43 11.98 0.09 59.2 62.3 15 12.1 0.46 12.00 0.11 60.0 67.2 16 12.2 0.48 11.99 0.10 60.6 72.6 17 12.3 0.51 12.04 0.15 61.5 77.5 18 12.5 0.53 12.04 0.15 62.1 82.8 19 12.6 0.56 12.06 0.17 62.8 88.1 20 12.7 0.58 12.09 0.20 63.6 93.3 21 12.8 0.61 12.08 0.19 64.0 99.0 22 12.9 0.63 12.12 0.23 64.8 104.0 23 12.9 0.66 12.11 0.22 65.0 109.8 24 13.0 0.69 12.11 0.22 65.4 115.4 25 13.1 0.71 12.14 0.25 65.9 120.8 26 13.1 0.74 12.15 0.26 66.2 126.3 27 13.2 0.76 12.20 0.31 66.9 131.2 28 13.2 0.79 12.19 0.30 66.9 137.2 29 13.2 0.81 12.22 0.33 67.3 142.5 30 13.2 0.84 12.27 0.38 67.8 147.5 31 13.3 0.86 12.26 0.37 67.9 153.5 32 13.3 0.89 12.32 0.43 68.5 158.3 33 13.3 0.91 12.36 0.47 68.9 163.4 34 13.3 0.94 12.38 0.49 69.2 168.9 35 13.4 0.96 12.39 0.50 69.5 174.5 36 13.4 0.99 12.44 0.55 70.0 179.5 37 13.4 1.02 12.53 0.64 70.7 183.8 38 13.3 1.04 12.55 0.66 70.7 189.2 39 13.3 1.07 12.61 0.72 71.1 194.1 40 13.3 1.09 12.64 0.75 71.3 199.3 41 13.3 1.12 12.69 0.80 71.4 204.2 42 13.2 1.14 12.77 0.88 71.9 208.3 43 13.2 1.17 12.80 0.91 72.0 213.5 44 13.1 1.19 12.86 0.97 72.2 218.1 45 13.1 1.22 12.93 1.04 72.5 222.3 46 13.0 1.24 12.97 1.08 72.6 227.2 47 13.0 1.27 13.02 1.13 72.7 232.0 48 12.7 1.30 13.05 1.16 71.6 237.3 49 12.4 1.32 13.20 1.30 71.3 239.0 50 12.2 1.35 13.28 1.38 70.8 242.6 51 12.0 1.37 13.36 1.47 70.2 246.0 52 11.8 1.40 13.54 1.65 70.6 246.1 53 11.5 1.42 13.63 1.74 69.6 249.4 54 11.3 1.45 13.76 1.87 69.4 251.0 55 10.9 1.47 13.87 1.98 68.4 253.1 56 10.8 1.50 13.99 2.10 68.5 254.6 57 10.0 1.55 14.26 2.37 66.3 256.8 58 9.7 1.60 14.48 2.59 66.3 259.6 59 9.5 1.65 14.71 2.82 66.7 261.8 J-R Curve Valid; A8 JIc Valid; A9

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-24 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-25 WCAP-18944-NP August 2025 Revision 2 Specimen ID T-LU4 JQ 173.6 kJ/m2 Fluence 0

n/cm2 C1 232.7 Test Temperature 288

°C C2 0.30 Width [W]

25.4 mm KJQ 188.4 Mpa Thickness [B]

12.70 mm Tensile Strength 571 MPa Jmax; A8.3.1 YES Yield Strength 388 MPa amax; A8.3.2 YES Net Thickness 9.95 mm a final crack straightness; 9.1.4.2 Minor Initial adjusted crack length 11.62 mm Initial fatigue crack length (measured) 12.08 mm a0 crack straightness; 9.1.4.1 YES Final crack length (calculated) 14.17 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 14.98 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 YES Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 YES Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 6.6 0.10 11.71 0.09 31.9 5.0 2

7.9 0.12 11.69 0.06 37.8 8.1 3

8.9 0.15 11.68 0.05 42.7 11.6 4

9.7 0.17 11.69 0.07 46.5 15.6 5

10.3 0.20 11.66 0.03 49.3 19.9 6

10.8 0.22 11.60

-0.02 51.2 24.6 7

11.2 0.25 11.63 0.01 53.1 29.1 8

11.4 0.27 11.61

-0.01 54.3 34.0 9

11.7 0.30 11.63 0.01 55.5 38.7 10 11.9 0.33 11.62

-0.01 56.5 43.8 11 12.1 0.35 11.65 0.03 57.6 48.7 12 12.3 0.38 11.67 0.04 58.6 53.7 13 12.4 0.40 11.68 0.06 59.6 58.9 14 12.6 0.43 11.69 0.07 60.4 64.1 15 12.8 0.45 11.69 0.06 61.1 69.6 16 12.9 0.48 11.73 0.10 62.1 74.7 17 13.0 0.50 11.73 0.11 62.8 80.1 18 13.2 0.53 11.71 0.09 63.2 85.9 19 13.3 0.55 11.75 0.13 64.0 91.1 20 13.4 0.58 11.76 0.14 64.6 96.7 21 13.5 0.61 11.79 0.17 65.4 102.0 22 13.6 0.63 11.81 0.18 66.0 107.6 23 13.7 0.66 11.77 0.15 66.2 114.0 24 13.8 0.68 11.84 0.22 67.2 118.9 25 13.9 0.71 11.82 0.20 67.5 125.0 26 14.0 0.73 11.86 0.23 68.1 130.4 27 14.0 0.76 11.84 0.22 68.3 136.7 28 14.1 0.78 11.87 0.24 68.8 142.3 29 14.1 0.81 11.90 0.28 69.3 147.8 30 14.2 0.83 11.89 0.27 69.4 154.1 31 14.2 0.86 11.94 0.32 70.0 159.2 32 14.2 0.88 11.96 0.34 70.4 164.9 33 14.3 0.91 11.96 0.34 70.5 171.1 34 14.3 0.94 12.04 0.42 71.2 175.7 35 14.3 0.96 12.08 0.45 71.6 181.3 36 14.3 0.99 12.13 0.51 72.1 186.4 37 14.3 1.01 12.16 0.54 72.5 191.9 38 14.3 1.04 12.20 0.57 72.7 197.4 39 14.3 1.06 12.26 0.63 73.2 202.3 40 14.3 1.09 12.27 0.64 73.0 208.6 41 14.2 1.11 12.35 0.73 73.2 212.6 42 14.1 1.14 12.38 0.76 73.1 218.2 43 14.0 1.16 12.46 0.84 73.3 222.5 44 13.9 1.19 12.54 0.92 73.5 226.6 45 13.7 1.22 12.62 1.00 73.3 230.8 46 13.6 1.24 12.67 1.05 73.1 235.7 47 13.5 1.27 12.75 1.12 73.0 239.8 48 13.3 1.29 12.79 1.17 72.7 244.5 49 13.2 1.32 12.87 1.25 72.8 248.4 50 13.1 1.34 12.92 1.30 72.7 252.9 51 13.0 1.37 12.99 1.37 72.7 257.1 52 12.8 1.39 13.08 1.45 72.5 260.5 53 12.7 1.42 13.14 1.52 72.2 264.4 54 12.5 1.44 13.22 1.60 71.8 267.9 55 12.3 1.47 13.31 1.69 71.8 270.9 56 12.2 1.49 13.38 1.75 71.7 274.6 57 12.1 1.52 13.42 1.79 71.6 279.0 58 12.1 1.55 13.50 1.88 72.0 282.0 59 11.9 1.60 13.59 1.96 71.4 290.9 60 11.7 1.65 13.68 2.06 71.4 298.7 61 11.5 1.70 13.83 2.21 71.3 304.7 62 11.1 1.75 13.98 2.36 70.8 310.2 63 10.7 1.80 14.17 2.55 69.7 313.9 JIc Valid; A9 J-R Curve Valid; A8

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-26 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-27 WCAP-18944-NP August 2025 Revision 2 Specimen ID T-LU5 JQ 140.2 kJ/m2 Fluence 0

n/cm2 C1 203.3 Test Temperature 199

°C C2 0.36 Width [W]

25.40 mm KJQ 171.8 Mpa Thickness [B]

12.70 mm Tensile Strength 534 MPa Jmax; A8.3.1 YES Yield Strength 385 MPa amax; A8.3.2 YES Net Thickness 9.95 mm a final crack straightness; 9.1.4.2 Minor Initial adjusted crack length 11.72 mm Initial fatigue crack length (measured) 12.08 mm a0 crack straightness; 9.1.4.1 YES Final crack length (calculated) 14.35 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 14.87 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 YES Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 YES Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 6.7 0.09 11.73 0.02 32.0 4.9 2

8.0 0.12 11.70

-0.01 38.5 8.0 3

9.2 0.14 11.75 0.04 44.3 11.7 4

10.0 0.17 11.73 0.01 48.2 15.8 5

10.6 0.20 11.71 0.00 51.1 20.2 6

11.1 0.22 11.74 0.03 53.5 24.8 7

11.4 0.25 11.71

-0.01 54.8 29.9 8

11.6 0.27 11.76 0.04 56.2 34.8 9

11.8 0.30 11.75 0.03 57.1 39.9 10 12.0 0.33 11.77 0.05 58.0 44.9 11 12.1 0.35 11.79 0.07 58.8 49.8 12 12.3 0.38 11.79 0.08 59.5 55.0 13 12.4 0.40 11.83 0.11 60.2 60.0 14 12.5 0.43 11.81 0.09 60.7 65.6 15 12.6 0.45 11.83 0.12 61.4 70.7 16 12.7 0.48 11.83 0.11 61.8 76.2 17 12.8 0.50 11.80 0.09 62.2 81.8 18 12.9 0.53 11.85 0.13 62.8 86.9 19 13.0 0.55 11.82 0.11 63.2 92.7 20 13.1 0.58 11.86 0.15 63.8 97.9 21 13.1 0.60 11.89 0.17 64.2 103.2 22 13.1 0.63 11.89 0.17 64.4 108.8 23 13.2 0.66 11.94 0.22 65.0 113.8 24 13.2 0.68 11.93 0.22 65.1 119.5 25 13.3 0.71 11.97 0.26 65.7 124.7 26 13.3 0.73 12.00 0.28 66.0 130.2 27 13.3 0.76 12.01 0.29 66.3 135.8 28 13.4 0.78 12.07 0.36 67.0 140.6 29 13.4 0.81 12.10 0.38 67.3 146.0 30 13.4 0.83 12.13 0.42 67.5 151.2 31 13.4 0.86 12.17 0.46 67.8 156.3 32 13.4 0.88 12.20 0.48 67.9 161.7 33 13.3 0.91 12.29 0.58 68.4 165.8 34 13.2 0.93 12.33 0.61 68.3 171.1 35 13.2 0.96 12.39 0.68 68.4 175.5 36 13.1 0.99 12.44 0.73 68.5 180.3 37 13.1 1.01 12.47 0.75 68.5 185.5 38 13.0 1.04 12.55 0.84 68.9 189.7 39 12.9 1.06 12.59 0.88 68.8 194.6 40 12.8 1.09 12.66 0.95 68.9 198.8 41 12.7 1.11 12.70 0.99 68.6 203.7 42 12.6 1.14 12.81 1.10 68.8 206.9 43 12.5 1.16 12.91 1.20 69.1 210.2 44 12.5 1.19 12.93 1.21 69.0 215.5 45 12.4 1.21 13.04 1.32 69.9 218.3 46 12.4 1.24 13.08 1.37 70.1 223.1 47 12.3 1.27 13.17 1.45 70.4 226.7 48 12.3 1.29 13.24 1.52 70.7 230.3 49 12.2 1.32 13.24 1.53 70.6 236.0 50 12.2 1.34 13.30 1.58 70.8 240.3 51 12.1 1.37 13.33 1.62 70.7 245.1 52 12.0 1.39 13.38 1.66 70.7 249.4 53 12.0 1.42 13.45 1.73 70.9 253.2 54 11.9 1.44 13.47 1.76 70.6 258.0 55 11.6 1.47 13.57 1.86 70.0 260.8 56 11.4 1.49 13.60 1.89 68.8 265.4 57 11.2 1.52 13.73 2.02 68.6 266.8 58 11.0 1.54 13.87 2.16 68.8 267.7 59 10.9 1.57 13.95 2.24 68.8 270.5 60 10.5 1.62 14.12 2.41 68.2 275.4 61 10.4 1.67 14.21 2.50 68.0 282.7 62 10.2 1.72 14.35 2.64 67.9 288.2 J-R Curve Valid; A8 JIc Valid; A9

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-28 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-29 WCAP-18944-NP August 2025 Revision 2 Specimen ID T-LU6 JQ 161.8 kJ/m2 Fluence 0

n/cm2 C1 229.8 Test Temperature 199

°C C2 0.36 Width [W]

25.40 mm KJQ 184.5 Mpa Thickness [B]

12.70 mm Tensile Strength 534 MPa Jmax; A8.3.1 YES Yield Strength 385 MPa amax; A8.3.2 YES Net Thickness 9.95 mm a final crack straightness; 9.1.4.2 Minor Initial adjusted crack length 11.67 mm Initial fatigue crack length (measured) 12.08 mm a0 crack straightness; 9.1.4.1 YES Final crack length (calculated) 14.33 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 14.93 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 YES Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 YES Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 6.7 0.09 11.70 0.02 32.1 4.9 2

8.1 0.12 11.73 0.05 38.8 8.0 3

9.2 0.14 11.72 0.05 44.3 11.7 4

10.1 0.17 11.70 0.03 48.3 15.9 5

10.7 0.20 11.70 0.02 51.1 20.3 6

11.1 0.22 11.70 0.03 53.4 24.9 7

11.5 0.25 11.69 0.02 55.0 29.8 8

11.7 0.27 11.68 0.00 56.0 34.9 9

11.9 0.30 11.69 0.02 57.1 40.0 10 12.1 0.32 11.71 0.03 58.0 44.9 11 12.2 0.35 11.71 0.03 58.7 50.0 12 12.4 0.37 11.75 0.08 59.7 55.0 13 12.5 0.40 11.75 0.08 60.2 60.3 14 12.6 0.42 11.76 0.08 60.8 65.6 15 12.7 0.45 11.78 0.11 61.5 70.8 16 12.8 0.48 11.77 0.09 61.9 76.4 17 12.9 0.50 11.80 0.13 62.7 81.5 18 13.0 0.53 11.81 0.13 63.2 87.0 19 13.1 0.55 11.84 0.16 63.8 92.3 20 13.2 0.58 11.85 0.18 64.4 97.7 21 13.3 0.60 11.86 0.19 64.8 103.4 22 13.4 0.63 11.88 0.20 65.4 108.8 23 13.4 0.65 11.86 0.19 65.5 114.8 24 13.5 0.68 11.89 0.21 66.1 120.2 25 13.5 0.70 11.90 0.23 66.4 125.8 26 13.6 0.73 11.92 0.25 66.9 131.3 27 13.7 0.75 11.98 0.30 67.6 136.4 28 13.7 0.78 11.95 0.28 67.6 142.7 29 13.8 0.81 11.99 0.32 68.2 147.9 30 13.8 0.83 12.00 0.33 68.3 153.8 31 13.8 0.86 12.02 0.35 68.7 159.3 32 13.8 0.88 12.06 0.39 69.0 164.5 33 13.8 0.91 12.07 0.39 68.9 170.5 34 13.8 0.93 12.15 0.48 69.6 174.8 35 13.8 0.96 12.18 0.51 69.8 180.3 36 13.8 0.98 12.23 0.56 70.1 185.4 37 13.8 1.01 12.28 0.60 70.5 190.3 38 13.7 1.03 12.31 0.63 70.7 195.8 39 13.7 1.06 12.35 0.68 71.1 200.7 40 13.7 1.09 12.41 0.74 71.5 205.6 41 13.7 1.11 12.44 0.77 71.5 210.8 42 13.7 1.14 12.52 0.85 72.1 214.9 43 13.6 1.16 12.55 0.88 72.1 220.3 44 13.5 1.19 12.63 0.95 72.3 224.6 45 13.4 1.21 12.66 0.99 71.8 229.8 46 13.3 1.24 12.71 1.04 71.8 234.5 47 13.2 1.26 12.78 1.11 71.9 238.6 48 13.1 1.29 12.84 1.17 71.8 243.0 49 13.0 1.31 12.92 1.25 71.7 246.7 50 12.9 1.34 12.96 1.29 71.7 251.5 51 12.8 1.37 13.02 1.35 71.8 255.7 52 12.7 1.39 13.10 1.43 72.1 259.2 53 12.6 1.42 13.14 1.47 71.5 263.9 54 12.5 1.44 13.24 1.57 71.9 266.7 55 12.4 1.47 13.28 1.60 71.8 271.5 56 12.3 1.49 13.33 1.66 71.8 275.4 57 12.2 1.52 13.37 1.70 71.7 280.1 58 12.1 1.54 13.42 1.75 71.5 284.2 59 12.0 1.57 13.51 1.84 71.7 286.8 60 11.9 1.59 13.53 1.86 71.3 291.8 61 11.3 1.65 13.68 2.00 69.0 298.3 62 11.0 1.70 13.82 2.14 68.2 304.0 63 10.6 1.75 13.99 2.32 67.3 308.2 64 10.3 1.80 14.14 2.46 67.0 312.9 65 10.0 1.85 14.33 2.65 66.5 315.9 J-R Curve Valid; A8 JIc Valid; A9

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-30 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-31 WCAP-18944-NP August 2025 Revision 2 Specimen ID T-LB8 JQ 123.0 kJ/m2 Fluence 0

n/cm2 C1 199.7 Test Temperature 199

°C C2 0.44 Width [W]

25.40 mm KJQ 160.9 Mpa Thickness [B]

12.70 mm Tensile Strength 534 MPa Jmax; A8.3.1 YES Yield Strength 385 MPa amax; A8.3.2 YES Net Thickness 9.95 mm a final crack straightness; 9.1.4.2 YES Initial adjusted crack length 11.81 mm Initial fatigue crack length (measured) 12.08 mm a0 crack straightness; 9.1.4.1 YES Final crack length (calculated) 14.63 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 15.23 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 Minor Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 YES Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 6.7 0.10 11.83 0.02 32.4 5.0 2

8.0 0.12 11.85 0.04 39.0 8.1 3

9.1 0.15 11.80 0.00 44.3 11.8 4

10.0 0.18 11.85 0.04 48.8 15.9 5

10.6 0.20 11.82 0.01 51.7 20.4 6

11.1 0.23 11.83 0.02 54.1 25.0 7

11.4 0.25 11.84 0.03 55.7 29.8 8

11.7 0.28 11.84 0.03 56.9 35.0 9

11.9 0.30 11.87 0.06 58.0 40.0 10 12.0 0.33 11.86 0.06 58.8 45.2 11 12.2 0.36 11.89 0.08 59.8 50.2 12 12.3 0.38 11.89 0.09 60.3 55.5 13 12.4 0.41 11.90 0.10 61.0 60.6 14 12.6 0.43 11.94 0.13 61.9 65.8 15 12.6 0.46 11.90 0.10 62.1 71.5 16 12.7 0.48 11.95 0.15 62.9 76.5 17 12.8 0.51 11.96 0.16 63.4 81.9 18 12.9 0.53 11.97 0.16 63.8 87.4 19 13.0 0.56 11.99 0.18 64.4 92.9 20 13.0 0.58 11.96 0.16 64.4 98.7 21 13.1 0.61 12.00 0.20 65.0 104.0 22 13.1 0.63 12.03 0.22 65.3 109.3 23 13.1 0.66 12.05 0.24 65.4 114.8 24 13.1 0.69 12.10 0.29 65.8 119.7 25 13.1 0.71 12.11 0.31 65.7 125.3 26 13.1 0.74 12.20 0.39 66.3 129.7 27 13.1 0.76 12.21 0.41 66.4 135.1 28 13.0 0.79 12.26 0.45 66.6 140.1 29 13.0 0.81 12.31 0.51 66.9 144.9 30 13.0 0.84 12.36 0.55 67.1 150.1 31 13.0 0.86 12.41 0.61 67.6 154.8 32 13.0 0.89 12.46 0.65 68.0 159.7 33 13.0 0.91 12.49 0.68 68.2 164.9 34 13.0 0.94 12.55 0.74 68.6 169.5 35 13.0 0.96 12.56 0.76 68.7 175.0 36 12.9 0.99 12.62 0.82 69.1 179.8 37 12.9 1.02 12.63 0.83 69.1 185.2 38 12.9 1.04 12.69 0.88 69.5 190.0 39 12.9 1.07 12.72 0.91 69.7 195.1 40 12.8 1.09 12.75 0.95 69.5 200.2 41 12.8 1.12 12.82 1.01 69.9 204.4 42 12.7 1.14 12.86 1.05 69.8 209.4 43 12.6 1.17 12.91 1.11 69.8 213.9 44 12.5 1.19 12.96 1.15 69.7 218.5 45 12.4 1.22 13.04 1.23 69.6 222.2 46 12.3 1.24 13.10 1.30 69.8 226.3 47 12.3 1.27 13.13 1.33 69.7 231.2 48 12.1 1.30 13.21 1.41 69.7 234.8 49 12.0 1.32 13.28 1.47 69.5 238.5 50 11.9 1.35 13.36 1.56 69.4 241.9 51 11.7 1.37 13.45 1.64 69.3 245.1 52 11.5 1.40 13.50 1.69 68.6 249.2 53 11.4 1.42 13.60 1.79 68.9 251.7 54 11.3 1.45 13.65 1.85 68.9 255.6 55 11.2 1.47 13.73 1.92 68.8 258.7 56 11.1 1.50 13.86 2.05 69.2 260.1 57 11.0 1.52 13.93 2.13 69.2 263.2 58 10.9 1.55 14.02 2.21 69.4 265.8 59 10.8 1.57 14.04 2.23 69.2 270.4 60 10.7 1.60 14.11 2.31 69.1 273.5 61 10.6 1.63 14.19 2.39 69.0 276.1 62 10.4 1.65 14.26 2.45 68.8 279.2 63 10.0 1.70 14.50 2.69 68.0 281.1 64 9.7 1.75 14.63 2.83 67.8 286.5 J-R Curve Valid; A8 JIc Valid; A9

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-32 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-33 WCAP-18944-NP August 2025 Revision 2 Specimen ID PB JQ 402.3 kJ/m2 Fluence 4.42 n/cm2 C1 505.7 Test Temperature

-31

°C C2 0.35 Width [W]

8.48 mm KJQ 301.7 Mpa Thickness [B]

3.96 mm Tensile Strength 685 MPa Jmax; A8.3.1 NO Yield Strength 554 MPa amax; A8.3.2 YES Net Thickness 3.96 mm a final crack straightness; 9.1.4.2 NO Initial adjusted crack length 4.25 mm Initial fatigue crack length (measured) 4.12 mm a0 crack straightness; 9.1.4.1 YES Final crack length (calculated) 5.69 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 5.63 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 NO Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 YES Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 1.0 0.05 4.20

-0.04 26.6 3.1 2

1.4 0.07 4.20

-0.04 37.8 7.4 3

1.8 0.10 4.24 0.00 46.6 12.6 4

2.0 0.12 4.25 0.01 51.9 19.1 5

2.0 0.15 4.29 0.04 54.8 26.0 6

2.1 0.17 4.32 0.07 56.4 32.3 7

2.1 0.20 4.23

-0.01 55.6 40.4 8

2.1 0.22 4.30 0.05 57.3 46.7 9

2.1 0.25 4.26 0.01 57.2 54.2 10 2.2 0.27 4.31 0.07 58.8 60.9 11 2.2 0.30 4.30 0.05 59.1 68.0 12 2.2 0.33 4.34 0.09 60.6 76.6 13 2.2 0.35 4.34 0.10 61.1 82.5 14 2.2 0.38 4.24

-0.01 59.1 95.0 15 2.3 0.40 4.38 0.14 62.9 96.1 16 2.3 0.43 4.32 0.08 61.9 107.2 17 2.3 0.45 4.29 0.04 61.6 114.8 18 2.3 0.47 4.30 0.06 62.1 122.6 19 2.3 0.51 4.36 0.12 63.9 130.1 20 2.3 0.52 4.35 0.10 64.1 136.9 21 2.3 0.56 4.35 0.11 64.2 146.8 22 2.3 0.57 4.36 0.11 64.6 152.1 23 2.4 0.60 4.35 0.10 64.7 160.2 24 2.4 0.62 4.30 0.06 64.0 171.9 25 2.4 0.65 4.30 0.06 64.2 179.3 26 2.4 0.67 4.26 0.01 63.2 191.0 27 2.4 0.70 4.31 0.07 64.8 195.1 28 2.4 0.73 4.37 0.13 66.1 199.5 29 2.4 0.75 4.44 0.19 67.7 204.0 30 2.4 0.78 4.42 0.17 67.3 213.1 31 2.4 0.80 4.39 0.14 66.6 223.0 32 2.4 0.83 4.47 0.23 69.0 225.2 33 2.4 0.85 4.53 0.29 70.7 229.6 34 2.4 0.87 4.49 0.24 69.3 239.6 35 2.4 0.90 4.44 0.20 68.2 252.1 36 2.4 0.93 4.52 0.28 70.2 256.6 37 2.4 0.95 4.53 0.29 70.6 261.3 38 2.4 0.98 4.53 0.28 70.3 271.1 39 2.4 1.01 4.48 0.24 68.6 286.2 40 2.4 1.02 4.62 0.38 72.2 278.2 41 2.3 1.06 4.58 0.34 70.8 293.7 42 2.3 1.07 4.60 0.35 71.2 297.0 43 2.3 1.11 4.61 0.37 71.5 307.7 44 2.3 1.12 4.56 0.32 70.1 317.9 45 2.3 1.15 4.81 0.56 77.3 300.8 46 2.3 1.18 4.49 0.24 67.8 347.5 47 2.3 1.21 4.60 0.36 70.8 342.6 48 2.3 1.23 4.75 0.50 75.0 332.9 49 2.3 1.25 4.64 0.39 71.7 353.5 50 2.3 1.28 4.62 0.38 70.8 367.5 51 2.3 1.31 4.81 0.57 75.9 349.8 52 2.3 1.34 4.71 0.47 72.4 373.7 53 2.3 1.35 4.75 0.51 73.7 371.9 54 2.2 1.38 4.76 0.51 71.2 383.0 55 2.3 1.40 4.69 0.45 71.6 398.1 56 2.3 1.44 4.74 0.50 72.3 403.3 57 2.2 1.45 4.81 0.56 73.0 398.9 58 2.2 1.47 4.72 0.47 71.5 419.9 59 2.2 1.49 4.73 0.49 72.0 424.5 60 2.2 1.55 4.76 0.52 70.4 438.1 61 2.1 1.60 4.88 0.63 70.8 436.1 62 2.1 1.66 4.89 0.65 70.3 451.1 63 2.0 1.71 4.82 0.58 65.8 479.0 64 2.0 1.76 4.95 0.70 70.8 472.9 65 2.0 1.80 5.01 0.77 72.1 473.6 66 1.9 1.85 5.12 0.87 70.8 469.5 67 1.9 1.92 5.27 1.03 76.5 460.7 68 1.8 1.97 5.19 0.95 71.9 492.3 69 1.8 2.02 5.18 0.94 70.3 510.2 70 1.8 2.06 5.30 1.06 72.8 499.4 71 1.7 2.11 5.40 1.15 72.9 494.8 72 1.7 2.17 5.36 1.12 70.8 519.9 73 1.6 2.22 5.37 1.13 70.4 529.0 74 1.5 2.25 5.34 1.09 64.8 549.0 75 1.6 2.31 5.45 1.20 70.7 538.5 76 1.6 2.36 5.47 1.22 70.3 549.4 77 1.5 2.43 5.51 1.26 70.1 557.8 78 1.5 2.47 5.57 1.32 71.6 554.0 79 1.4 2.52 5.56 1.32 66.7 568.0 80 1.4 2.56 5.54 1.30 67.8 585.2 81 1.4 2.63 5.69 1.45 71.8 564.5 J-R Curve Valid; A8 JIc Valid; A9

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-34 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-35 WCAP-18944-NP August 2025 Revision 2 Specimen ID WU JQ 129.2 kJ/m2 Fluence 4.42 n/cm2 C1 252.7 Test Temperature 78

°C C2 0.55 Width [W]

8.3 mm KJQ 168.1 Mpa Thickness [B]

3.96 mm Tensile Strength 746 MPa Jmax; A8.3.1 YES Yield Strength 650 MPa amax; A8.3.2 YES Net Thickness 3.96 mm a final crack straightness; 9.1.4.2 NO Initial adjusted crack length 4.25 mm Initial fatigue crack length (measured) 4.44 mm a0 crack straightness; 9.1.4.1 Minor Final crack length (calculated) 5.61 mm Points between exclusion lines; A9.6.6.6 or A9.7 YES Final crack length (measured) 6.02 mm Initial crack length agreement; A9.9.2.1 YES Initial crack length Adjustment; A9.9.2.2 Minor Precycle crack length consistency; 8.6.3.1 YES a predicted vs optical; 9.1.5.2 NO Sequence Peak Load (kN)

Peak CMOD (mm) a (mm) a (mm)

<DW J (kJ/m2) 1 1.0 0.04 2

1.4 0.07 4.24 0.00 38.0 6.4 3

1.7 0.09 4.23

-0.02 47.3 12.1 4

2.0 0.12 4.28 0.04 55.5 18.4 5

2.1 0.14 4.30 0.05 60.4 25.6 6

2.2 0.17 4.33 0.08 63.6 33.2 7

2.3 0.19 4.35 0.10 65.2 41.1 8

2.3 0.22 4.31 0.07 64.7 50.1 9

2.3 0.25 4.37 0.12 66.2 57.8 10 2.3 0.27 4.41 0.17 67.1 64.9 11 2.3 0.30 4.45 0.20 67.8 72.2 12 2.3 0.32 4.39 0.15 66.3 82.8 13 2.3 0.35 4.47 0.23 68.0 88.8 14 2.2 0.37 4.43 0.19 66.2 98.2 15 2.2 0.40 4.51 0.26 67.5 103.4 16 2.2 0.43 4.53 0.29 67.3 111.9 17 2.2 0.45 4.54 0.30 66.8 118.0 18 2.1 0.47 4.52 0.27 65.6 127.2 19 2.1 0.50 4.59 0.35 66.8 132.6 20 2.1 0.53 4.60 0.36 66.1 140.9 21 2.1 0.55 4.64 0.40 66.3 145.6 22 2.0 0.58 4.63 0.38 65.2 154.8 23 2.0 0.61 4.66 0.42 65.6 160.3 24 2.0 0.63 4.69 0.45 65.6 166.8 25 2.0 0.65 4.69 0.45 65.1 173.3 26 2.0 0.68 4.75 0.50 65.9 177.7 27 1.9 0.71 4.78 0.53 65.4 183.3 28 1.9 0.74 4.78 0.54 64.4 192.0 29 1.9 0.76 4.81 0.56 64.2 197.2 30 1.8 0.78 4.84 0.60 64.4 200.1 31 1.8 0.81 4.88 0.63 64.1 205.2 32 1.8 0.83 4.88 0.63 63.0 212.9 33 1.7 0.86 4.94 0.70 63.8 214.8 34 1.7 0.89 4.98 0.74 63.7 218.7 35 1.7 0.91 5.01 0.76 63.6 222.1 36 1.6 0.94 5.10 0.85 65.4 223.1 37 1.6 0.96 5.13 0.88 65.4 225.7 38 1.6 0.98 5.17 0.93 65.6 228.7 39 1.6 1.01 5.18 0.93 64.4 236.4 40 1.5 1.03 5.20 0.96 64.2 238.9 41 1.5 1.06 5.26 1.02 65.0 240.2 42 1.5 1.09 5.29 1.05 64.8 245.6 43 1.4 1.12 5.35 1.11 65.4 246.0 44 1.4 1.14 5.42 1.18 66.8 245.4 45 1.4 1.16 5.41 1.16 65.3 252.0 46 1.4 1.20 5.47 1.22 65.7 255.8 47 1.3 1.21 5.49 1.24 65.6 255.4 48 1.3 1.24 5.41 1.17 61.8 271.1 49 1.3 1.27 5.48 1.24 63.0 271.9 50 1.3 1.31 5.58 1.34 65.6 267.3 51 1.3 1.32 5.61 1.36 65.7 267.2 52 1.2 1.35 5.60 1.35 62.3 275.4 JIc Valid; A9 J-R Curve Valid; A8

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 A-36 WCAP-18944-NP August 2025 Revision 2

• • • This record was final approved on 08/04/2025 15:21:01. (This statement was added by the PRIME system upon its validation)

WCAP-18944-NP Revision 2 Non-Proprietary Class 3

• • This page was added to the quality record by the PRIME system upon its validation and shall not be considered in the page numbering of this document.**

Approval Information Author Approval Hall Gordon Z Aug-04-2025 12:24:55 Verifier Approval Ganta B Reddy Aug-04-2025 14:08:05 Reviewer Approval Demers Thomas E Aug-04-2025 14:37:24 Manager Approval Rigby Stephen Aug-04-2025 15:21:01 Files approved on Aug-04-2025