IR 05000323/2025011

License Renewal Report 05000323/2025011

ML25070A022
Person / Time
Site:	Diablo Canyon
Issue date:	03/20/2025
From:	Greg Warnick NRC/RGN-IV/DORS/EB2
To:	Gerfen P Pacific Gas & Electric Co
Pick G
References
IR 2025011
Download: ML25070A022 (1)

Text

March 20, 2025

SUBJECT:

DIABLO CANYON POWER PLANT - LICENSE RENEWAL REPORT 05000323/2025011

Dear Paula A. Gerfen:

On February 27, 2025, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Diablo Canyon Power Plant and discussed the results of this inspection with Maureen Zawalick, Vice President, Business and Technical Services and other members of your staff. The results of this inspection are documented in the enclosed report.

No findings or violations of more than minor significance were identified during this inspection.

This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, Gregory G. Warnick, Chief Engineering Branch 2 Division of Operating Reactor Safety Docket No. 05000323 License No. DPR-82

Enclosure:

As stated

Inspection Report

Docket Number:

05000323

License Number:

DPR-82

Report Number:

05000323/2025011

Enterprise Identifier:

I-2025-011-0007

Licensee:

Pacific Gas and Electric Company

Facility:

Diablo Canyon Power Plant

Location:

Avila Beach, CA

Inspection Dates:

February 24 to 27, 2025

Inspectors:

G. Pick, Senior Reactor Inspector

P. Cooper, Senior Reactor Inspector

A. Siwy, Senior Project Manager

C. Smith, Senior Reactor Inspector

Approved By:

Gregory G. Warnick, Chief

Engineering Branch 2

Division of Operating Reactor Safety

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting a license renewal inspection at Diablo Canyon Power Plant, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.

List of Findings and Violations

No findings or violations of more than minor significance were identified.

Additional Tracking Items

None.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures in effect at the beginning of the inspection unless otherwise noted. Currently approved inspection procedures with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html.

Samples were declared complete when the inspection procedure requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2516, Policy and Guidance for The License Renewal Inspection Program. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

OTHER ACTIVITIES

- TEMPORARY INSTRUCTIONS, INFREQUENT AND ABNORMAL

===71002 - License Renewal Inspection On November 17, 2010, the NRC issued an inspection report for the withdrawn license renewal application (ML103220205). This previous inspection was performed using Inspection Procedure 71002, and evaluated the licensees aging management programs, the structures, systems, and components in the scope of license renewal, and the application itself.

This inspection report is the fourth in a series of inspections related to the review of aging management programs and their implementation activities for the current license renewal application (ML23311A154).

The inspectors performed this inspection to evaluate whether aging management programs will be capable of managing identified aging effects in an appropriate manner. This inspection allowed the inspectors to review their assigned aging management programs, to assess the progress of the licensee implementation activities, and to perform walkdowns in the plant, as needed.

The inspectors reviewed the aging management program basis documents and compared them to NUREG-1801, Generic Aging Lessons Learned (GALL) Report, revision 2 and appendices A and B of the submitted license renewal application. The inspectors also reviewed implementing documents and completed work activities, walked down plant structures, systems and components, and interviewed program owners. The inspectors verified that aging management programs reflected the planned updated final safety analysis report supplement, verified the programs considered applicable industry and site-specific operating experience, and assessed site-specific information when designing the aging management programs described in the basis documents.

License Renewal Inspection===

(1) Vertical Slice The inspectors selected the component cooling water system for review to identify whether the licensee had screened in components and properly assigned them to aging management programs based on the component materials and the environments that the components interacted. Based on a sample of selected components, the inspectors determined that the licensee had properly accounted for the possible environmental aging effects for the component cooling water system in the license renewal application.

(2) Annual Update The inspectors determined that the licensee initiated the following letters since the inspection completed in September 2024:

• Letter DCL-24-091, Response to Request for Additional Information by the Office of Nuclear Reactor Regulation Diablo Canyon Safety Review Pacific Gas and Electric Company Diablo Canyon Units 1 & 2 (Set 1), dated October 3, 2024.

• Letter DCL-24-092, Supplement and Annual Update: Diablo Canyon Power Plant License Renewal Application, Amendment 1, dated October 14, 2024,

• Letter DCL-25-001, Response to Request for Additional Information by the Office of Nuclear Reactor Regulation Diablo Canyon Safety Review Pacific Gas and Electric Company Diablo Canyon Units 1 & 2 (Set 2), dated January 2, 2025.

During review of each of the aging management programs, the inspectors included the applicable content from the letters in their program evaluations. The letters typically revised the commitments in response to staff review of the submitted application and review of the aging management programs or provided clarifying information in response to staff information requests.

===71013 - Site Inspection for Plants with a Timely Renewal Application The inspectors performed Phase 2 of Inspection Procedure 71013, Site Inspection for Plants with a Timely Renewal Application, of the Diablo Canyon Power Plant the week of February 24, 2025. The inspectors completed the inspection within 6 months of Unit 2 entering the period of extended operation as recommended. The period of extended operation is the additional 20 years beyond the original 40-year licensed term. The period of extended operation for Diablo Canyon Power Plant, Unit 1, began after midnight on November 2, 2024. The period of extended operation for Diablo Canyon Power Plant, Unit 2, will begin after midnight on August 26, 2025.

The inspectors evaluated the adequacy and effectiveness of the implementation of the aging management programs and completion of activities described in the regulatory commitments proposed in the license renewal application, updated final safety analysis report supplement program descriptions, and proposed license conditions as agreed to by the licensee while the application for renewal is under review.

For each aging management program reviewed, as part of their sampling review, the inspectors reviewed program documents, license renewal documents, the safety analysis report, the annual update to the license renewal application, and the safety evaluation report. Supporting documents reviewed included implementing procedures, work orders, inspection reports, engineering evaluations, calculations, database entries, and condition reports. The inspectors interviewed program owners and license renewal program personnel.

The inspectors paraphrased most of the proposed commitments as listed in the updated final safety analysis report supplement and the license renewal application. For the actual wording refer to the safety evaluation report once issued. The inspectors listed specific documents reviewed in the attachment.

Site Inspection for Plants with a Timely Renewal Application===

(1) A.2.1.1 Fatigue Monitoring (X.M1) and Commitment 1 This existing condition monitoring program manages fatigue usage caused by anticipated cyclic strains. The program criteria ensure fatigue usage remains within allowable limits for components of the reactor coolant system.

Commitment 1 specified:

Continue the fatigue monitoring aging management program with enhancements to:

• Include additional analyses and critical thermal and pressure transients for components with a fatigue time-limited aging analysis, which are not covered by the current program. Additional locations will include environmentally assisted fatigue analyses for the set of sample components.

• Include acceptance criteria for transient definitions, cycle count action limits, and cumulative usage factor action limits.

• Modify procedures to require review at least once per fuel cycle of the cycle count and cumulative usage factor data. Assess whether to update the fatigue analyses if

(1) an allowable cycle limit is approached,

(2) a transient definition has been changed,

(3) unanticipated new thermal events are discovered, or

(4) the geometry of components has been modified.

• Revise procedures to require corrective actions if a component reaches a cycle count or a fatigue usage action limit. Revise the fatigue analysis or repair/replacement the component. Corrective actions for approaching fatigue crack growth analysis action limits include re-analyzing the fatigue crack growth analysis consistent with or reconciled to the original analysis. The reanalysis will receive the same level of regulatory review as the original analysis.

The inspectors reviewed the program basis documents, administrative procedures and implementing procedures to verify that the licensee developed the program as described in the license renewal application. The inspectors confirmed the licensee completed the required commitments and implemented the procedures or administrative controls associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(2) A.2.1.2 Environmental Qualification (EQ) of Electric Components (X.E1)and Commitment 2 This existing program manages the effects of aging of EQ equipment, such that the components maintain their intended function(s) for the period of extended operation.

EQ components not qualified for the current license term must be replaced or requalified before reaching their aging limits. Reanalysis is an acceptable method to extend the qualified life of an EQ component and involves analytical methods, data collection, assumptions, acceptance criteria, and corrective actions.

Commitment 2 specified:

• Continue the environmentally qualified equipment aging management program.

The inspectors reviewed the aging management program basis document, implementing procedures, completed work activities, EQ files, and corrective action documents. This program includes determining the qualified life of components and maintaining a schedule for replacement or requalification. The licensee maintained a list of qualified components in a database and documented the details of the service requirements in dedicated EQ files. The inspectors determined the licensee procedurally controlled changes to EQ components.

The licensee prevents failures of EQ components by establishing component aging limits, service conditions, and tolerances. The program credits methods such as reanalysis, Arrhenius methodology for thermal aging, and total integrated dose for radiation aging. Surveillance, maintenance, and temperature monitoring programs ensure components remain within their qualification basis. The inspectors found that the licensee implemented temperature logging to support reanalysis of components and to extend qualified life up to 60 years. The inspectors determined the licensee used conservative values and performed the reanalysis in accordance with NRC-approved calculational methods. The inspectors also sampled EQ components with a qualified life shorter than 60 years and confirmed the licensee replaced, or scheduled them to be replaced, prior their qualified life.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(3) A.2.2.1 ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD (XI.M1) and Commitment 3 This existing condition monitoring and inspection program manages the aging effects of cracking, loss of material, and reduction of fracture toughness by performing inspections on class 1, 2, and 3 piping and components. The licensee performs periodic visual, surface, and volumetric examinations, as well as leakage tests of class 1, 2, and 3 pressure-retaining components, including welds, pump casings, valve bodies, vessels, integral attachments, and pressure-retaining bolting.

Commitment 3 specified:

• Continue the existing ASME Section XI, Subsections IWB, IWC and IWD aging management program with an enhancement to reexamine the Unit 1 Pressurizer Spray Line Pipe Weld WIB-378 for three inservice inspection periods since identification of the weld flaw in 2015 in accordance with the ASME Code, paragraph IWB-2420.

• Inspect the outside diameter of 10 percent of the susceptible ASME Code Class 1 socket weld population greater than or equal to 1 inch and less than 4 inches with a maximum of 25 welds per unit using visual and penetrant examinations in each inservice inspection interval in the period of extended operation.

The inspectors reviewed the program basis documents, administrative and implementing procedures, and corrective action documents to verify that the licensee developed the program as described in the license renewal application.

The inspectors assessed the second commitment because the licensee added it to the license renewal application since the prior Phase 2 inspection in September 2024.

Because the licensee had identified a cracked class 1 socket weld while implementing their one-time program, the licensee elected to perform periodic inspections of these welds as part of their inservice inspection program. The inspectors confirmed the licensee completed the required commitments and implemented the procedures or administrative controls associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(4) A.2.2.8 Flow-Accelerated Corrosion (XI.M17) and Commitment 10 This existing monitoring program manages wall thinning caused by flow accelerated corrosion and various erosion mechanisms. This program includes performing

(a) an analysis to determine critical locations,

(b) limited baseline inspections to determine the extent of thinning at these locations, and

(c) follow-up inspections to confirm the predictions or repairing or replacing components as necessary.

Commitment 10 specified:

Continue the flow-accelerated corrosion program with enhancements to:

• Include piping, components, and piping elements susceptible to erosion wall-thinning mechanisms such as cavitation, flashing, droplet impingement, or solid particle impingement and include erosion as an aging mechanism for susceptible components.

• Identify locations susceptible to erosion based on the extent of condition reviews in response to plant-specific and industry operating experience.

Include guidance from industry documents for potential damage locations, including cavitation erosion.

• Trend wall thickness measurements at susceptible locations to adjust the monitoring frequency and to predict the remaining service life for scheduling repairs. Evaluate to ensure assumptions in the extent-of-condition review remain valid. If degradation results from operational alignments, then trending considers the number or duration of these occurrences. Periodically measure wall thickness of replaced components to confirm the effectiveness of corrective actions.

• Control and independently update the plant predictive models by a second qualified flow-accelerated corrosion engineer.

• Ensure long-term corrective actions to eliminate the cause of erosion mechanisms will consider adjusting operating parameters or changing component designs. Continue periodic monitoring for any replaced components.

Exception:

The licensee implemented the recommendations provided in NSAC-202L, Recommendations for an Effective Flow-Accelerated Corrosion Program, revision 4, which was endorsed by the subsequent license renewal GALL rather than the revisions endorsed by LR-ISG-2012-01, Wall Thinning due to Erosion Mechanisms.

The inspectors identified no concerns with the licensee utilizing the most current versions of industry monitoring software since NRC endorsed it in the subsequent license renewal GALL.

The inspectors reviewed the program basis documents, administrative and implementing procedures, and corrective action documents to verify that the licensee developed the program as described in the license renewal application. The inspectors verified that implementing procedures accomplished the actions described in the commitments or that the licensee established administrative controls to accomplish the described activities. In addition, the inspectors reviewed the Unit 1 FAC Program Outage Inspection Report to verify that the licensee completed their examination and evaluation of results as described by the implementing procedures.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(5) A.2.2.9 Bolting Integrity (XI.M18) and Commitment 11 This existing inspection program manages cracking, loss of material, and loss of preload for pressure retaining closure bolting. The program includes preload control, selection of bolting material, use of lubricants or sealants, and performance of periodic inspections for indication of aging effects consistent with industry and NRC guidance.

Commitment 11 specified:

Implement the bolting integrity aging management program, including enhancements to:

• Procedures and/or specifications to minimize any future use of high strength bolts (yield strength greater than or equal to 150 ksi). If high strength bolts are used, bolting will be monitored for cracking, with volumetric examinations performed in accordance with ASME Section XI.

• Explicitly ban the use of molybdenum disulfide on bolts.

• Ensure the program is consistent with the listed industry guidelines and the additional recommendations of NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants, to prevent or mitigate degradation and failure of closure bolting.

• Inspect pressure retaining closure bolting in piping systems that contain air or gas. Demonstrate integrity of the bolted joint by one of the following methods:

(a) perform inspections consistent with that of submerged closure bolting;

(b) visually inspect for discoloration when leakage would discolor the surfaces;

(c) monitor and trend pressure decay for connections located within an isolation boundary;

(d) perform soap bubble testing;

(e) use thermography when the fluid temperature is higher than ambient; or

(f) other inspection methods capable of detecting leakage. At a minimum, in each 10-year interval, inspect a representative sample of at least 20 percent of the population (with the same material and environmental combination) at each unit, up to a maximum of 19.

• Visually inspect a representative sample of submerged closure bolting for loss of material when bolt heads are made accessible and bolt threads when joints are disassembled. If opportunistic activities do not result in 20 percent of the population up to a maximum of 19 bolt heads and threads over a 10-year period, then specify how integrity of the bolted joint will be demonstrated.

• Establish specific acceptance criteria when alternative inspections or testing is conducted for submerged closure bolting or for piping containing air/gas and leakage is difficult to detect.

• For sampling-based inspections, if the cause of the aging effect for each applicable material and environment is not corrected by repair or replacement, conduct additional inspections if the acceptance criteria are not met. Use the corrective action program to determine the number of inspections; however, conduct no fewer than five additional inspections or 20 percent of each combination, whichever is less. If these subsequent inspections do not meet acceptance criteria, conduct an extent of condition and extent of cause analysis to determine additional inspections required. Inspect for any recurring degradation at both units to ensure corrective actions address the associated causes. The additional inspections will be completed within the interval (e.g.,

refueling outage interval, 10-year inspection interval) in which the original inspection was conducted.

The inspectors reviewed the aging management program basis document, implementing procedures, completed work activities, harsh files, environmental qualification files, and corrective action documents. The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(6) A.2.2.15 Fire Water Program (XI.M27) and Commitment 17 This existing condition monitoring program manages loss of material and flow blockage caused by corrosion, including microbiologically induced corrosion, recurring internal corrosion, or fouling; flow blockage because of fouling; and loss of integrity for internal coatings for water-based fire protection systems. Components in the program include fire hose stations, standpipes, piping (above ground, buried and underground), piping components, hydrants, fire pump casings, valve bodies, fittings, spray nozzles, fire hoses, sprinklers, sprinkler heads, and the fire water storage tanks, including coatings. The program includes the internal surfaces of water-based fire protection system piping that is normally drained, such as dry-pipe or preaction sprinkler system piping and valves.

Commitment 17 specified:

Continue the fire water system aging management program, including enhancements to:

• Clean and inspect every 24-months the makeup water system strainers that support the fire water system.

• Test/replace sprinkler heads in accordance with NFPA 25, Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems, section 5.3.1. Sprinklers in service for greater than 50 years will be replaced or tested prior to the program being implemented.

• Develop new procedures to conduct flow tests at hydraulically most remote locations. Measure flow, static pressure, and residual pressure at the hydraulically most remote fire water hose station by testing:

(1) eight hose stations in the turbine building;

(2) two hose stations in the auxiliary building;

(3) two hose stations in the containment buildings; and

(4) one hose station in the common intake structure.

• Perform and trend main drain testing every 18-months, include the 10 percent acceptance criteria from NFPA 25, section 13.2.5.

• Maintain hydrant flow for not less than 1 minute.

• Perform at least one flow test of the buried portions of the fire water system in accordance with NPFA 25, section 7.3 in each 1-year period.

• Ensure interior and exterior surface inspections of the fire water storage tank include the following criteria:

(1) Inspect surfaces every five years. Enter degradation not meeting acceptance criteria into the corrective action program and evaluate to determine whether additional actions required. Record via camera, take nodule measurements, and record the corrosion depth. Revise procedures to allow use of a variety of nondestructive examination methods;

(2) Use appropriate tools to conduct the inspection;

(3) Personnel will be qualified in accordance with ASTM D7108-05, Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist. Acceptance criteria and corrective actions will meet LR-ISG-2013-01, appendix C, New Program: Gall Report AMP XI.M42, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks, and

(4) Perform a one-time ultrasonic test inspection of the tank bottom prior to November 2, 2024.

• Test the turbine building deluge valves consistent with NFPA 25. Every three years (every second visual inspection) test the downstream dry piping with air, smoke, or other medium.

• Clean deluge system nozzles and retest the respective systems if obstructions are identified during flow testing.

• Update existing procedures to

(1) inspect wet sprinkler systems internally using a method to detect flow blockage caused by fouling in addition to loss of material;

(2) investigate obstructions; and

(3) not allow external wall thickness measurements in lieu of prescribed internal visual examinations (or flow test)for managing flow blockage.

• Create a new procedure to implement the following:

(1) If any normally dry fire water deluge piping becomes periodically wetted, but unable to be drained, perform each 5-year period either:

(a) a flow test or flush sufficient to detect flow blockage, or

(b) a 100 percent internal surface inspection on portions unable to be drained;

(2) Each 5-year period, volumetrically inspect 20 percent of the identified portion so that after 25 years, 100 percent has been tested; and

(3) If the turbine building deluge system spray piping becomes wetted, determine if any portions of the spray piping cannot be drained or water collects, then apply the flow testing and inspection criteria for normally dry wet sprinkler systems.

• Include the following for recurring internal corrosion:

(1) monitor for loss of material using ultrasonic testing;

(2) compare current measurements to previous thickness measurements to determine the estimated time to reach minimum wall thickness;

(3) if results do not meet acceptance criteria or reduced wall thickness greater than 50 percent, enter the issue into the corrective action program;

(4) evaluate the effectiveness of previous corrective actions taken;

(5) enter any newly identified recurring internal corrosion deficiency into the corrective action program; and

(6) perform internal visual inspections during opportunistic inspections.

• Require trending of test data.

• Ensure visual inspection techniques for loss of material can detect surface irregularities that could indicate wall loss below nominal thickness. When detected perform volumetric testing.

• Remove and inspect water system mainline strainers every five years.

• Flush mainline strainers after each operation or flow test.

• Do not allow using performance-based inspection, testing, and maintenance frequencies.

• Update procedure acceptance criteria to include: maintain fire protection system pressure and flow rates, maintain minimum design wall thickness, and fouling in the sprinkler system does not block the sprinklers.

Exceptions:

Exception 1: Manage more material types than described in the GALL report. The fire water piping includes asbestos concrete piping. The inspectors determined that the licensee trended the fire water performance testing of the asbestos concrete piping.

The licensee included visual inspections of the buried asbestos concrete piping as part of their buried and underground piping aging management program.

Exception 2: Establish sprinkler inspections every 18 months in lieu of annual. The inspectors verified that procedure STP M-65, Sprinkler/Deluge System Visual Verification, revision 26, specified implementing this requirement.

Exception 3: Instead of testing each zone of an automatic standpipe system and each riser of the fire water system annually as specified in NFPA, the licensee established actions to perform a flow test to the hydraulically most remote fire water hose stations every five years. The inspectors verified that procedure PEP 18-02, Firewater Hose Station Flow Test, revision 3, implemented the flow testing.

Exception 4: Establish main drain tests every 18 months in lieu of annual tests. The inspectors verified that the licensee included these test requirements in procedures STP M-63C, Fire Water System Function Test of the Fuel Handling and Radwaste Building, and procedure STP M-63D, Fire Water Main System Functional Test of the Turbine Buildings.

Exception 5: Inspection and cleaning of long-term cooling strainers STR-97 and STR-98 biannually instead of annually. The inspectors determined that maintenance plans MP-11601, MP-11602, MP-11603, and MP-11604 implemented this exception.

Exception 6: Use the corrective action program to identify pitting, corrosion or coating failures of fire water storage tank surfaces instead of automatic testing. Use a variety of nondestructive examination techniques rather than vacuum box testing on the fire water storage tank bottom. The inspectors determined that the licensee had operating experience that demonstrated effective monitoring and managing the surface of the fire water storage tank. Procedure AWP E-058, Fire Water Storage Tank 01 Inspections, revision 1, implemented the condition monitoring and inspections described by this exception.

Exception 7: Test deluge systems using manual pull boxes instead of automatic actuation. The inspectors verified procedure AWP E-063, Sprinkler Head Testing/Replacement, revision 0, implements this exception.

Exception 8: Test the turbine deluge valves every 18 months at minimal flow through a system drain. Test the dry piping downstream of the deluge valves every 36 months with air, smoke, or other medium during every other visual inspection. The licensee developed procedure PEP 18-05, Flow Testing of Turbine Building Deluge System Downstream Dry Piping, revision 0, to implement these inspection requirements.

The inspectors reviewed the aging management program basis document, implementing procedures, completed work activities, and corrective action documents. The inspectors identified no issues with the actions taken by the licensee for the exceptions. The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(7) A.2.2.17 Fuel Oil Chemistry (XI.M30) and Commitment 19 This existing mitigation and condition monitoring program manages loss of material in tanks, components, and piping exposed to diesel fuel oil. The program includes periodic removal of accumulated water found in tanks, periodic draining, cleaning, and inspection of fuel oil storage tanks.

The licensee performs volumetric examinations to assess identified degradation or where internal visual inspection is not possible. The licensee maintains fuel oil quality by monitoring and controlling fuel oil contamination. Technical specifications provide limits for both new and stored fuel oil for use in the emergency diesel generators. The licensee follows manufacturer fuel oil quality recommendations for the portable diesel driven fire water pump tanks, portable diesel electric generator fuel oil tanks, and the portable caddy fuel oil tanks.

The fuel tanks in the scope of this program include emergency diesel fuel oil storage tanks (DFOST), emergency diesel fuel oil day tanks (DFODT), portable diesel electric generator fuel oil tanks (OPGEN). portable diesel-driven fire water pump fuel oil storage tanks (PDDFWP FOST), emergency diesel fuel oil pump head (priming)tanks, and portable caddy fuel oil tanks.

Commitment 19 specified:

Continue the fuel oil chemistry aging management program, including enhancements to:

• Include the emergency diesel generator diesel fuel oil day tanks, portable diesel electric generator fuel oil tanks, portable diesel driven fire water pump tanks, emergency diesel fuel oil pump head (priming) tanks, and portable caddy fuel oil tanks.

• Drain, clean, and visually inspect the internal surfaces of the in-scope tanks every ten years. Volumetrically inspect the tanks if degradation is observed or if visual inspection is not possible.

• Add biocide to the portable diesel electric generator and caddy fuel oil tanks.

• Periodically sample the fuel oil stored in the fuel oil tanks for the portable tanks. Perform multilevel samples or, if tank design does not allow, take a sample from the lowest point in the tank. If accumulated water is found, remove using the corrective action program.

• Sample new fuel oil prior to adding to the in-scope tanks. Annually monitor and trend water and sediment content, total particulates, and the levels of microbiological organisms for the portable in-scope equipment fuel oil tanks.

Establish acceptance criteria in accordance with industry standards and equipment manufacturer or fuel oil supplier recommendations.

• Credit the fuel oil storage tank inspections as a one-time sample if the material and environment are the same.

• Control trending of water and particulate levels in accordance with technical specifications and procedures for the emergency diesel generator diesel fuel oil storage and day tanks.

• Enhance procedures to check and drain water from the in-scope tanks filtration devices prior to use to minimize any water entry.

Exceptions:

Exception 1: Water is not removed from the portable caddy fuel oil tanks or the emergency diesel fuel oil pump head (priming) tanks.

The inspectors determined the portable caddy fuel oil tanks do not have provisions to remove water from the tank bottoms. The licensee performs quarterly surveillances for the diesel driven fire water pumps and the portable diesel generators for 30 minutes each surveillance that consumes fuel oil contained in the caddy fuel oil tanks. The licensee refills the fuel oil after each surveillance and tests new fuel for the presence of water in accordance with the aging management program prior to introduction into the portable caddy fuel oil tanks.

The priming tanks do not have provisions to remove water from the tank bottoms. The priming tanks get oil from the fuel oil day tanks and reroute excess fuel to the fuel oil day tanks. The licensee checks the fuel oil day tanks for accumulated water every 31 days removing any water present. The frequent addition of fuel oil and the absence of water from the fuel oil supply ensure that the licensee does not introduce nor allow water to accumulate in priming tanks. The inspectors identified no issues with this exception.

Exception 2: The emergency diesel fuel oil pump head (priming) tanks will not be periodically sampled.

The inspectors determined that the licensee does not take samples from the priming tanks rather the licensee samples the diesel fuel oil day tanks since the day tanks provide fuel oil to the priming tanks. The licensee analyzes the oil in the diesel fuel oil day tanks quarterly for total particulate concentration and microbiological organisms in accordance with ASTM standards. The inspectors identified no issues with this exception.

Exception 3: The licensee does not test new fuel for microbiological organisms prior to introduction into the emergency diesel fuel oil storage tanks, portable diesel generators, portable fire water pumps and portable caddies.

The inspectors verified that the licensee tested the oil from these tanks annually using an offsite laboratory to analyze for microbiological organisms. The inspectors verified the licensee added biocide to new emergency diesel fuel oil. Onsite operating experience demonstrated that the use of biocide and other preventative measures has prevented contamination of the diesel fuel oil. The inspectors identified no issues with this exception.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed program activities, and held discussions with site personnel and fleet program owners. Specifically, the inspectors verified the fuel quality chemistry analyses for new diesel fuel receipt, diesel tank inspection results, trends, performed walkdowns of the accessible portions of the diesel generator and their associated tanks and discussed the program with the system engineers, chemistry technicians, and the aging management program owner.

The inspectors noted that the second commitment bullet could not be met as written.

Specifically, because the portable diesel electric generator fuel oil tanks are an integral part of a larger generator set, the licensee had to disassemble the equipment to access the tank bottom and perform the volumetric examination. Out of the six portable diesel electric generator fuel oil tanks that were visually inspected, three showed minor indications of corrosion (OPGEN 2, OPGEN 3, and OPGEN 6). To gain access to the portable diesel electric generator fuel oil tank (OPGEN2) for the volumetric inspection, the licensee removed the fuel tank from the generator. The volumetric exam identified no measurable material loss of material in the OPGEN2 fuel tank. A licensee evaluation concluded the OPGEN 3 and OPGEN 6 had similar times in service, identical construction, similar visual indications and therefore the volumetric data from OPGEN 2 would be representative of all six components.

As a result, because the licensee could not meet the volumetric exam requirements for these components, the licensee generated corrective action program notifications (SAPNs) 51273390 and 51273391 for OPGEN 3 and OPGEN 6 to revise the commitment because the licensee considered them complicated assemblies. The inspectors did not have any concerns with this approach. The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(8) A.2.2.18 Reactor Vessel Surveillance (XI.M31) and Commitment 20 This existing surveillance program manages loss of fracture toughness for the reactor vessel caused by exposure to neutron fluence. The licensee had removed and tested surveillance capsules containing specimens of the limiting beltline material and associated weld metal and weld heat affected zone metal. The program provides sufficient data for monitoring irradiation embrittlement at the end of the period of extended operation and determines the need for any operating restrictions on the inlet temperature, neutron spectrum, and neutron flux.

Commitment 20 specified:

• Continue the reactor vessel surveillance aging management program.

Exception:

The licensee identified that they could not store all coupons for future use.

Specifically, several specimens from Unit 2 capsule V had been donated to an EPRI research program; consequently, these donated specimens will no longer be available for retrieval and future use. The inspectors determined that the licensee had other coupons that could be inserted and exposed to fluence if required. The inspectors identified no issues with this exception.

The inspectors reviewed the aging management program basis document, engineering evaluations, design documents, drawings, implementing procedures, work plans, and corrective action documents.

The inspectors determined that the licensee had extensive ex-vessel neutron dosimetry for both units, which had been installed prior to initial operation. For Unit 1 the licensee had withdrawn and measured seven sets of ex-vessel neutron dosimeters following cycles 1, 2, 4, 6, 10, 16, and 22. The licensee withdrew seven in-vessel capsules (three tested): capsule S at the end of cycle 1, capsules Y, T, and Z at the end of cycle 5, capsule V at the end of cycle 11, and capsules C and D at the end of cycle 12. For Unit 2 the licensee had withdrawn and measured seven sets of ex-vessel neutron dosimeters following cycles 1, 2, 4, 6, 10, 16, and 21. The licensee withdrew all six in-vessel capsules with four tested at the end of cycles 1, 3, 6, and 9.

The inspectors determined that the licensee evaluations demonstrated good agreement between the in-vessel coupon fluence exposure and the ex-vessel neutron dosimetry measurements that agreed with the guidance in Regulatory Guide 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence, revision 0. The licensee initiated work order 50859061 and work order 50859062 to replace and measure their reactor vessel ex-vessel neutron dosimetry for Unit 1 in refueling outage 1R26 (October 2026) and for Unit 2 in refueling outage 2R26 (April 2027).

The inspectors determined that work order 60150763 provided the mechanism to track removing Unit 1 reactor vessel capsule B in the upcoming 1R25 refueling outage (April 2025). The inspector verified the licensee had this activity in the upcoming outage schedule. After unsuccessfully, removing capsule in 1R24, the licensee took measurements to alter the tool so they could remove the capsule and established a backup plan. The licensee will analyze the materials in capsule B to ensure that the neutron fluence at the end of the period of extended operation receives a fluence between one to two times the peak reactor vessel wall neutron fluence and revise the pressure temperature limits report curves if necessary. For Unit 2, the inspectors determined that the vessel materials had a predicted end-of-life exposure of 52.51 effective full power years of operation. Although less than 54 effective full power years, the inspectors confirmed that this exposure remained within the 20 percent specified in Regulatory Guide 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence.

The inspectors determined that the current pressure temperature limits report supported operation of Unit 1 until refueling outage 1R25 in April 2025. The licensee received a license amendment in October 2024 that allowed use of a newer, more advanced neutron fluence calculational methodology to support determining the reactor coolant system pressure and temperature limits. The inspectors reviewed design document package 1000025725, Revise Pressure Temperature Limits Report/Low Temperature Overpressure Setpoint, that revised the pressure temperature curves and low temperature overpressure limits for operation out to 45 effective full power years for both Units 1 and 2. The inspectors verified that the licensee used approved methods to develop the pressure temperature limit report heatup and cooldown curves and to establish new low temperature overpressure limits. The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(9) A.2.2.19 One-Time Inspection (XI.M32) and Commitment 21 This one-time aging management program that conducts visual examinations of components in the water chemistry, fuel oil chemistry, and lubricating oil analysis programs to verify the effectiveness of the aging management activities performed by those programs. The licensee selected a representative sample size of 20 percent of the population (defined as components having the same material, environment, and aging effect combination) or a maximum of 25 components. This sample will be based on criteria such as the longest service period, most severe operating conditions, lowest design margins, lowest or stagnant flow conditions, high flow conditions, and highest temperature.

Commitment 21 specified:

• Implement the one-time inspection aging management program.

The inspectors reviewed the aging management program basis document, implementing procedures, examination sheets, destructive examination reports, engineering evaluations, and corrective action documents. The inspectors reviewed the sampling plan and technical basis document that established the sample populations and evaluation samples for each material and environment combination.

The inspectors determined that the licensee had selected the components, in part, subject to low flow conditions, severity of service conditions, time in service and other factors. In addition, the inspectors verified that the licensee appropriately separated the components into similar material environment groups.

One-Time Inspection Program Samples Unit 1 Unit 2 Total 136 141 In-progress

Planned - Outage

Planned - at Power

Completed 114 The licensee completed 75 percent of the inspections of their sample populations.

The sample inspections included at least one sample from every material environment group and the inspection results confirmed minor corrosion on 16 samples and no corrosion on the other components. The inspectors reviewed the inspection results, images for each component, and engineering assessments documented in each notification for the samples that had minor corrosion. The licensee determined that the components with minor corrosion had been in low flow areas and installed between 30 and 39 years. The inspectors identified no concerns with the licensee evaluations. Because the inspections identified little to no corrosion and the licensee has scheduled the remainder of the inspections to be completed by March 31, 2026, the inspectors determined that this program provided confirmation that the water chemistry, lubricating oil, and fuel oil chemistry programs provided reasonable assurance of preventing the effects of aging. The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(10) A.2.2.20 Selective Leaching (XI.M33) and Commitment 22 This new one-time condition monitoring program evaluates whether loss of material has been caused by selective leaching for gray cast iron, ductile iron, and copper alloys (except for inhibited brass) containing greater than 15 percent zinc or greater than 8 percent aluminum components that are exposed to raw water, treated water, closed cooling water, or ground water.

The program includes visual inspection and hardness measurement or other industry-accepted mechanical inspection techniques such as destructive testing, scraping, or chipping of selected components to determine whether selective leaching affects the component intended functions. If the licensee identifies selective leaching, the licensee will expand the sample to include locations for follow-up examinations or evaluations.

Commitment 22 specified:

• Implement the selective leaching aging management program.

The inspectors reviewed the aging management program basis document, implementing procedures, examination sheets, destructive examination reports, engineering evaluations, and corrective action documents. The inspectors reviewed the sampling plan and technical basis document that established the sample populations and evaluation samples for each material and environment combination.

The inspectors determined that the licensee had divided the components into appropriate material/environment groups, established procedure guidance and acceptance criteria that would allow them to identify the presence of selective leaching. The licensee used qualified personnel to perform the inspections. The licensee had identified the components within each group to inspect and had initiated work orders to track the inspections. The licensee had reviewed at least one component from each group. The inspectors had determined the following status for the selective leaching one-time inspections:

Selective Leaching One-Time Inspections Unit 1 Unit 2 Total

In-progress

Planned - Outage

Planned - at Power

Completed

The licensee indicated that they would complete their initial inspections by March 31, 2026, and would complete any expansion inspections, if necessary, by December 1, 2028, as described in Letter DCL-23-020, Responses to NRC Questions Regarding Diablo Canyon Power Plant License Renewal Efforts, dated March 17, 2023. The inspectors determined that none of the Unit 2 components had any indications of selective leaching. The licensee continued to evaluate a valve (cast-iron in a raw water environment) removed from the fire protection system with evidence of selective leaching. The licensee evaluation will determine whether this material and environment should be included in their periodic selective leaching program. The inspectors determined that SAPN 51263882 tracks the remaining inspection activities for this aging management program.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation. Because the licensee had additional required inspections that could result in expanding the scope of their periodic inspection aging management program, this aging management program will be evaluated during a future Phase 3 inspection.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(11) A.2.2.21 One-time Inspection of ASME Code Class 1 Small Bore-Piping (XI.M35)and Commitment 23 This new one-time inspection program provides assurance that aging of ASME Code Class 1 small-bore piping is not occurring, or that the aging effects are not significant, such that a plant-specific aging management program is not warranted.

Commitment 23 specified:

• Implement the one-time inspection of ASME Code Class 1 small bore piping aging management program.

The inspectors reviewed the program basis documents, administrative and implementing procedures, and corrective action documents to verify that the licensee developed the program as described in the license renewal application. The inspectors verified work orders evaluated and examined small bore butt and socket welds in accordance with implementing procedures. The inspectors confirmed the licensee completed the required commitments and implemented the procedures or administrative controls associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(12) A.2.2.26 Buried and Underground Piping and Tanks (XI.M41) and Commitment 28 This existing condition and performance monitoring program manages cracking, loss of material, and change in surface conditions of buried and underground components in the auxiliary saltwater, diesel generator fuel transfer, fire protection, and the makeup water systems. The program includes preventive measures (i.e., coatings, backfill quality, and cathodic protection), inspections, and, as appropriate, performance monitoring activities. Visual inspections monitor the condition of protective coatings and wrappings and directly assess the surface condition of components with no protective coatings or wraps. Evidence of wall loss beyond minor scale observed during visual inspections of buried piping will require a supplemental surface examination and/or volumetric non-destructive testing. The program includes opportunistic inspection of buried piping and tanks as they are excavated or on a planned basis if opportunistic inspections have not occurred.

Commitment 28 specified:

Continue the buried and underground piping and tanks program, including enhancements to:

• Close valve MU-0-881, Water Supply to Firing Range 2nd Off (Alt. Supply), for any pressure boundary failure further along the flow path or when the raw water storage reservoirs provide long-term cooling.

• Install impressed current cathodic protection for remaining portions of the buried auxiliary saltwater system discharge and supply piping.

• Revise the backfill procedure to include the requirements related to material quality.

• Include qualification requirements for individuals evaluating coatings.

• Align the inspection scope with LR-ISG-2015-01, Changes to Buried and Underground Piping and Tank Recommendations, Table XI.M41-2, Preventive Actions for Buried Piping and Tanks, and section 4.c.

• Require an annual firewater system flow test.

• For steel components, where the acceptance criteria for cathodic protection are other than -850 mV instant off, loss of material rates will be measured per the recommendations in LR-ISG-2015-01, appendix B, Revised AMP XI.M41, Buried and Underground Piping and Tanks, section 6.m.

• Revise program and backfill procedures to include the following: Cracks in controlled low strength material backfill that could admit groundwater are not acceptable. Where significant coating damage caused by non-conforming backfill is identified, evaluate the condition to ensure the as-left condition will not cause further degradation.

• Include the corrective actions recommended by LR-ISG-2015-01, appendix B, section 7.

• Specify the limiting critical potential should not be more negative than -

1200 mV.

• Include the following acceptance criteria:

(1) evaluate blistering, gouges, or wear of nonmetallic piping;

(2) projected measured wall thickness to the end of the period of extended operation meets minimum wall thickness;

(3) manage indications of cracking in metallic pipe with the corrective action program, and

(4) cementitious piping may exhibit minor cracking and spalling provided there is no evidence of leakage, exposed or rust staining from rebar or reinforcing hoop bands.

Exceptions:

Exception 1: The diesel fuel oil storage tanks, makeup water cast iron valves, and some of the buried steel discharge and supply piping in the auxiliary saltwater system do not have cathodic protection as recommended by LR-ISG-2015-01, appendix B, Table XI.M41-1, Preventive Actions for Buried and Underground Piping and Tanks.

The inspectors verified that the licensee tested the annular space between the double-walled tanks with procedure STP M-122, Diesel Fuel Oil Underground Storage Tanks (DFOUST) 0-1 and 0-2 Interstitial Test and Enhanced Leak Detection Test, revision 8, and drains, cleans, and visually inspects the inside of both storage tanks at least every ten years with procedure PEP 21A, Diesel Fuel Oil Storage Tanks Inspection and Cleaning, revision 6. After installing cathodic protection by December 1, 2028, only 24-feet of inaccessible auxiliary saltwater piping per line will not be cathodically protected. The inspectors determined that the licensee established plans to inspect the uncoated cast iron makeup water valve exterior surfaces.

Exception 2: Asbestos cement pipe in the fire protection and makeup water systems and cast iron valves in the makeup water system are not coated as recommended by LR-ISG-2015-01, appendix B, Table XI.M41-1.

The inspectors determined that the asbestos cement piping would not corrode from the soil surrounding the pipe. The licensee identified in their inspection plan evaluation of asbestos cement piping and inspection of the buried cast iron makeup water valves. The program procedures require entering adverse conditions into the corrective action program. Based on these factors, the inspectors identified no concerns associated with this exception.

Exception 3: Current backfill procedure does not specify that backfill located within 6 inches of the component will meet ASTM D 448-08 size number 67 (size number 10 for polymeric materials). An enhancement has been included to ensure future compliance with LR-ISG-2015-01.

The inspectors determined that the licensee no longer included this exception since they added the requirement to plant procedures. Specifically, procedure MIP C-15.0, Excavation and Backfill, revision 5, requires the use of Backfill that is located within 6 inches of steel components meets ASTM D 448-08 size number 67 (size number 10 for polymeric components).

Exception 4: The GALL report requires that inspections of buried and underground piping and tanks will commence ten years prior to the period of extended operation.

Because of the expedited timeframe to implement the buried piping and tanks aging management program, initial inspections will be completed by December 1, 2028, after both units have entered the period of extended operation.

The inspectors verified that the licensee had established three inspection intervals to accommodate timely renewal. The first interval for Unit 1 and Unit 2 occurs from 2014 or 2015, respectively, through 2028. The second interval will be 2024 - 2034 for Unit 1 and 2025 - 2035 for Unit 2. In addition, the licensee will not credit any inspections for the first intervals through 2028 towards the inspection requirements in the second intervals. The licensee planned to complete their first interval inspections during outages that will occur in the spring and fall of 2025, 2026 and 2027.

The inspectors reviewed the aging management program basis document, implementing procedures, drawings, licensing correspondence, corrective action documents, and completed and planned work activities. The inspectors determined that the licensee had included their commitments among appropriate procedures for the activity being implemented (e.g., fire water flow testing, cathodic protection system testing, or excavation and backfill). Procedure TS5-ID3, Buried Piping and Tanks Program, revision 9, included the requirements for performing license renewal inspections.

The inspectors determined that the licensee established a buried piping technical basis document that prescribed requirements for implementing the license renewal buried piping and tanks program. The basis document described how they implemented the requirements of LR-ISG-2015-001 and accounted for the as-found condition of the in-scope piping (i.e., condition of their cathodic protection system, coatings, and backfill). The inspectors determined that the licensee identified the piping segments for excavation for the first interval. Also, the licensee established calculation 9000041674, Buried Piping and Tanks Program Asset Management Plan, revision 4, that continued to implement other buried piping inspections.

Because the licensee had initiated plans to complete but had not completed several inspections and had not completed their cathodic protection modification, the inspectors could not complete review of this program. The licensee initiated SAPN 51261789 because they identified from review of the prior ten years of cathodic protection system performance that the system had not met the requirement to exceed the -850 mV acceptance criteria more than 80 percent of the time.

SAPN 51261789 had tasks that tracked the corrective actions needed to bring the cathodic protection system into compliance. The inspectors will review this program during a future Phase 3 inspection.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(13) A.2.2.28 ASME Subsection IWE (XI.S1) and Commitment 30 This existing condition monitoring program manages loss of material, loss of sealing, and leakage through containment and provides aging management of the steel liner of the concrete containment building (including the containment liner plate and its integral attachments), containment hatches and airlocks, and pressure-retaining bolting.

Commitment 30 specified:

Continue the ASME Subsection IWE aging management program with enhancements to:

• Identify the listed documents to form a basis for the bolting program.

• Prohibit the use of molybdenum disulfide as a lubricant for structural bolts.

• Inspect non-coated surface examinations for arc strikes.

• Require a one-time volumetric examination of metal liner surfaces that are inaccessible from one side, only if triggered by plant-specific operating experience. The trigger includes any plant-specific occurrence of measurable metal liner corrosion (material loss exceeding 10 percent of nominal) initiated on the inaccessible side or areas.

• Perform a one-time inspection using methods capable of detecting cracking caused by stress corrosion cracking of a representative sample to confirm the absence of stress corrosion cracking, which would be 2 stainless steel penetrations or dissimilar metal welds associated with high-temperature (above 140 F) stainless steel piping systems per unit in frequent use. If cracking is detected, additional inspections will be conducted in accordance with the corrective action process. Periodic inspection of subject penetrations with dissimilar metal welds for cracking may be added to this program, depending on the inspection results.

The inspectors reviewed the program basis documents, administrative and implementing procedures, and corrective action documents to verify that the licensee developed the program as described in the license renewal application. The inspectors identified that the scope of the corrective actions associated with the fourth bullet was unclear. Following discussions with NRC subject matter experts and licensee personnel, the inspectors concluded, if plant experience revealed material loss exceeding 10 percent of nominal, the scope of the expansion should match the guidance in the subsequent license renewal GALL or an approved equivalent methodology. The licensee initiated SAPN 51263882 to ensure that they tracked their actions to clarify the commitment.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures or administrative controls associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(14) A.2.2.29 ASME Subsection IWL (XI.S2) and Commitment 31 This existing condition monitoring program manages aging of the reinforced concrete containment building in accordance with ASME Section XI, Subsection IWL.

Commitment 31 specified:

Continue the ASME Subsection IWL aging management program with enhancements to:

• Evaluate results that do not meet the acceptance standards and document the results in an engineering report to identify the cause and the extent, nature, and frequency of additional examinations. Include whether the concrete containment is acceptable without repair and, if repair is required, the extent, method, and completion date of the repair.

• Update the acceptance criteria guidance to be consistent with ACI 349.3R-02, Evaluation of Existing Nuclear Safety-Related Concrete Structures.

• Inspect accessible concrete for visual indications of potential alkali silica reactions, such as map or patterned cracking, alkali silica gel exudations, surface staining, expansion causing structural deformation, relative movement or displacement, or misalignment/distortion of attached components.

The inspectors reviewed the program basis documents, administrative and implementing procedures, and corrective action documents to verify that the licensee developed the program as described in the license renewal application. The inspectors reviewed Subsection IWL inspection reports to verify that the licensee examined and evaluated results in accordance with program implementing procedures. The inspectors confirmed the licensee completed the required commitments and implemented the procedures or administrative controls associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(15) A.2.2.30 ASME Subsection IWF (XI.S3) and Commitment 32 This existing condition monitoring program manages loss of material, cracking, and loss of mechanical function that could result in loss of intended function for supports for class 1, 2, and 3 piping and components.

Commitment 32 specified:

Continue the ASME Subsection IWF aging management program with enhancements to:

• Prohibit the use of molybdenum disulfide as a lubricant for structural bolts.

• Enhance bolting practice procedures to explicitly identify the listed documents as a portion of the basis for the bolting program. Consider the addition controls required for ASTM A325, F1852, and/or A490 bolts.

• Ensure replacement and maintenance activities for high-strength structural bolting specify that the replaced bolting material has an actual measured yield strength less than 150 ksi.

• Monitor high-strength structural bolting (measured yield strength greater than or equal to 150 ksi) and greater than one-inch, using volumetric examination comparable to applicable code categories in addition to the VT-3 examination.

• Enter and evaluate any adverse results of high-strength structural bolting examinations into the corrective action program.

• Include the following conditions as unacceptable unless the technical basis for their acceptance is documented:

(1) loss of material caused by corrosion or wear;

(2) debris, dirt, or excessive wear that could prevent or restrict sliding of the sliding surfaces;

(3) cracked or sheared bolts, including high-strength bolts, and anchors; and

(4) arc strikes, weld splatter, paint scoring, roughness, or general corrosion on close tolerance machined or sliding surfaces.

Exception:

Prohibit the use of molybdenum disulfide and limit the amount of sulfur used in other lubricants consistent with levels discussed in the EPRI Materials Handbook for Nuclear Plant Pressure Boundary Application. The inspectors determined that the licensee plans to implement the bolting practices consistent with NUREG-1339 and EPRI guidance for high strength bolting that recommends nickel-based anti-seize or graphite-alcohol lubricants. The inspectors identified no concerns with the licensee planned actions.

The inspectors reviewed the program basis documents, administrative and implementing procedures, and corrective action documents to verify that the licensee developed the program as described in the license renewal application. The inspectors reviewed Subsection IWL inspection reports to verify that the licensee examined and evaluated results in accordance with program implementing procedures. The inspectors confirmed the licensee completed the required commitments and implemented the procedures or administrative controls associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(16) A.2.2.32 Masonry Walls (XI.S5) and Commitment 34 This existing condition monitoring program includes inspections to detect age-related degradation including shrinkage, separation, gaps, loss of material, and cracking for in-scope masonry walls. Visual inspections monitor for significant cracking, coating damage, loss of material, missing or broken blocks, deterioration of penetrations, discoloration efflorescence, separation, and shrinking.

The program includes masonry walls in the auxiliary and turbine buildings that support safety-related piping or equipment, or whose failure could prevent a safety-related system from performing its safety function. The fire protection aging management program evaluates that fire protection function of masonry walls considered fire barriers.

Commitment 34 specified:

Continue the masonry walls program, including enhancements to:

• Monitor for evidence of shrinkage and/or separation of masonry walls and gaps between the supports and masonry walls that could impact the intended function.

• Require inspections to be performed at least every five years for masonry walls.

The inspectors reviewed the aging management program basis document, implementing procedures, maintenance plans, design information, drawings, prior inspections, and corrective action documents. The inspectors verified that the licensee had included these commitments in procedure AWP E-016, Inspection Guide - Maintenance Rule Structural Monitoring Programs - Civil. The inspectors reviewed selected corrective action documents, selected inspection results, and interviewed the program owner. The inspectors determined the methods used by the licensee would allow them to manage the effects of aging. The inspectors verified that the licensee had included the commitments for this program in the appropriate procedures. The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(17) A.2.2.33 Structures Monitoring (XI.S6) and Commitment 35 This existing condition monitoring program manages the condition of in-scope structures and structural supports that are not covered by other structural aging management programs. The program implements the requirements of 10 CFR 50.65, including the implementing industry and regulatory documents as described in updated final safety analysis report, section 13.5.2.19.

Commitment 35 specified:

Continue the structures monitoring program, including enhancements to:

• Notify appropriate personnel to allow them to perform an opportunistic inspection whenever opening a pull box that may include previous inspection results or new industry operating experience for pull boxes.

• Add embedments, jet impingement shields, racks, and sliding surfaces to the scope.

• Include appropriate preload and proper tightening (torque or tension) for structural bolting replacement and maintenance activities as recommended in listed industry standards and to explicitly prohibit the use of molybdenum disulfide as a lubricant for structural bolts.

• Monitor groundwater samples at least every five years for pH, sulfates, and chlorides, including seasonal variations, and assess the impact of changes on below grade concrete.

• Monitor accessible sliding surfaces for indication of significant loss of material caused by wear or corrosion, debris, or dirt and specify the acceptance criteria that could restrict or prevent sliding of the surfaces as required by design.

• Monitor all structures on a frequency not to exceed five years upon entering the period of extended operation. such that all structures will be inspected within the five years after November 2, 2024, for Unit 1 and August 26, 2025, for Unit 2.

• Conduct a baseline inspection of all safety and non-safety related concrete elements in accordance with ACI 349.3R-02 acceptance criteria.

• Align the inspector qualifications with the guidance in ACI 349.3R-02.

• Specify that structural sealants (including weatherproofing boots) remain acceptable if the observed loss of material, cracking, and hardening will not result in loss of function.

• Monitor structural sealants on an interval not to exceed five years, except for aboveground tanks that are monitored each refueling outage.

• Inspect fiberglass roofing for no evidence of blistering, cracking, or loss of material that could cause a loss of function.

• Inspect accessible concrete for visual indications of potential alkali silica reaction such as map or patterned cracking, gel exudations, surface staining, expansion or displacement, or misalignment/distortion of attached components.

• Inspect spent fuel pools and transfer canals leak chase tell-tale drains to identify potential blockages prior to the period of extended operation. Perform subsequent periodic internal inspections once every five years. The long-term frequency may be adjusted by evaluating internal and external operating experience.

• Walkdowns of accessible interior walls and ceilings adjacent to the reactor cavity, refueling canal, spent fuel pool and transfer canal on a 5-year interval to identify in-leakage into the structure. Place newly identified leaks or changes in existing leak sites into the corrective action program.

• Enhance the reactor cavity, refueling canal, spent fuel pool and transfer canal leak chase sampling parameters and acceptance criteria as described in the commitment table.

• Develop procedures to manage the reactor cavity, refueling canal, spent fuel pool and transfer canal surveillance and maintenance activities consistent with the guidance in EPRI 3002007348, Aging Management for Leaking Spent Fuel Pools.

• During refueling outage 1R25, the licensee will evaluate the feasibility of internal boroscope examinations of the refueling cavity and refueling canal leak chases. If determined feasible, during refueling outages 2R25 and 1R26, the licensee will inspection the Unit 2 and Unit 1 reactor cavity and refueling canal leak chases. Perform subsequent periodic inspections at an initial frequency of once per every three refueling outages.

• Perform a structural evaluation of any identified degradation of concrete and structural steel caused by leakage of borated water, including a conservative projection of the potential degradation of those surfaces six months after refueling outage 2R25.

The inspectors reviewed the aging management program basis document, implementing procedures, design information, drawings, completed inspections, and corrective action documents.

The inspectors reviewed the baseline concrete inspection reports for the different structures. Each report discussed indications as greater or within Tier 2 criteria, identified indications on room maps, identified the notification that documented the indications that exceeded Tier 2 criteria. The inspectors determined that upgrading ACI 349.3R-02 from ACI 349.3R-96 added concrete inspection criteria and extending the operating licensee expanded the areas required to be inspected. The inspectors determined the methods used by the licensee would allow them to manage the effects of aging. The licensee had identified areas not reviewed during the concrete baseline inspections. This included areas in the Unit 1 and 2 auxiliary buildings and the Unit 1 submerged structures as identified in the reports. Subsequently, the licensee initiated several notifications to track the required area inspections - SAPN 51273567, 51273568, 51273569, 51273651, 51273653, and 51273660.

The inspectors verified that SAPN 51271506 tracked the requirement for walking down the reactor cavity, refueling canal, spent fuel pool, and transfer canal looking for newly identified leaks prior to completing the first outage for each unit after entering the period of extended operation. The licensee issued

(1) SAPN 51246931 to document the Unit 1 reactor cavity leak chase feasibility evaluation,

(2) SAPN 51260295 to document the internal inspection of Unit 2 reactor cavity and refueling canal leak chases during refueling outage 2R25, and

(3) SAPN 51269294 to document the internal inspection of Unit 1 leak chases during refueling outage 1R26.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation. For those commitments not implemented related to the refueling cavity, refueling canal, transfer canal, and the spent fuel pool, the licensee created notifications to track completion.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(18) A.2.2.34 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants (XI.S7) and Commitment 36 This existing condition monitoring program manages cracking, movement (e.g.,

settlement, heaving, deflection), loss of material, loss of form, loss of bond, loss of strength, and increase in porosity and permeability caused by extreme environmental conditions, and the effects of natural phenomena on water-control structures.

Although not committed to Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants, the program includes all structural components within the scope of license renewal addressed by the regulatory guides, as well as their attributes. The scope includes monitoring of structural steel and structural bolting associated with water-control structures, and miscellaneous steel (e.g., bar racks).

The water-control structures included in this aging management program include the:

intake structure, discharge structure, circulating water conduits, earth slopes over the auxiliary saltwater pipes, wave protection measures over the auxiliary saltwater pipes and electrical conduits, east and west breakwaters, and raw water reservoirs.

Commitment 36 specified:

Continue the water control structures program, including enhancements to revise implementing procedures to:

• Include miscellaneous steel (e.g., bar racks) for water control structures.

• Specify

(1) structural bolting replacement and maintenance will include appropriate preload and proper tightening (torque or tension) as recommended in the listed industry standards; and

(2) molybdenum disulfide will not be used.

• Monitor structural concrete for movements (e.g., heaving, deflection),conditions at junctions with abutments and embankments, loss of material, and increase in porosity and permeability.

• Develop the requirements for future discharge conduit inspections to address the following:

(1) inspection interval not to exceed five years,

(2) extent and frequency of marine growth removal; and

(3) include 100 percent of the accessible area.

• Align the inspector qualifications with the guidance in ACI 349.3R-02.

• Perform baseline inspections of all concrete water-control structures in accordance with ACI 349.3R-02 acceptance criteria.

• Inspect accessible concrete for visual indications of potential alkali silica reactions.

The inspectors reviewed the aging management program basis document, implementing procedures, design information, drawings, completed inspections, and corrective action documents. The inspectors determined that the licensee had performed detailed inspections of their water control structures every five years and had established preventive maintenance tasks that controlled the type and frequency of inspections. The inspections demonstrated their structures remained in good condition and determined little degradation had occurred from one inspection to another.

The inspectors reviewed the license renewal baseline concrete inspection reports performed for the water control structures. The inspectors determined that, when the licensee identified indications that exceeded the Tier 2 criteria in ACI 349.3R-02, the licensee initiated a corrective action notification and marked the issues on a location map for future tracking and review. The inspectors determined that upgrading ACI 349.3R-02 from ACI 349.3R-96 added concrete inspection criteria and extending the operating licensee expanded the areas required to be inspected. The inspectors determined the methods used by the licensee would allow them to manage the effects of aging.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(19) A.2.2.36 Insulation Material for Electric Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (XI.E1) and Commitment 38 This new program provides reasonable assurance that the intended functions of electrical cables and connections not subject to environmental qualification requirements and exposed to adverse localized environments (temperature, radiation, or moisture) are maintained consistent with the current licensing basis. Adverse localized environments exists in a limited plant area that is significantly more severe than the plant design basis environment for the cable or connections insulation material.

Commitment 38 specified:

Implement the insulation material for electrical cables and connections not subject to environmental qualification requirements aging management program.

• Implement a solution by December 31, 2025, to prevent or divert oil from the cables affected by oil residue.

The inspectors reviewed the aging management program basis document, implementing procedures, completed inspection activities, corrective action program evaluation of related issues, and commitment closure documents. The inspectors reviewed the inspection results with licensee staff and discussed previous station operating experience.

The licensee identified one area as an adverse localized environment for cables in cable trays related to the 480VAC, 120VAC, and 125VDC vital switchgear rooms ventilation supply systems. The inspectors reviewed design change 60171149, Installation of Cable Tray Covers to Deflect Oil Unit 1 and 2. This design change will add a cover plate over cable trays to prevent oil from dripping from the ventilation louvers onto the cables below. The licensee designed the cable tray covers to preclude oil dripping onto the cables at any low points. In addition, periodic oil cleanup will be maintained on the installed covers to preclude any housekeeping issues or prolonged oil buildup. The licensee had not implemented this design modification at the time of this inspection but scheduled completion by December 31, 2025, as described in the commitment. The licensee tracked this issue with SAPN 51205737.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(20) A.2.2.37 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits (XI.E2) and Commitment 39 This existing program manages the aging effects of the cables and connections used in instrumentation circuits with sensitive, high-voltage, low-level current signals within the nuclear instrumentation and radiation monitoring systems.

Commitment 39 specified:

Continue the insulation material for electrical cables and connections not subject to environmental qualification requirements used in instrumentation circuits aging management program, including enhancements to:

• Develop procedures for the cables and connections used in nuclear instrumentation channels (source, intermediate, and power ranges).

• Specify the parameters that require monitoring for indications of age-related degradation for nuclear instrumentation channels.

• Develop procedures for calibration/surveillance tests of radiation monitors to require evaluating the test results and to determine whether the associated circuits remain functional. Complete baseline calibration/surveillance test results for each unit prior to the 40-year license expiration and at least every ten years thereafter. Review calibration/surveillance results that do not meet acceptance criteria for aging effects.

• Implement cable system testing for the nuclear instrumentation monitors using a proven method for detecting deterioration of the insulation system. Complete baseline cable insulation system testing for nuclear instrumentation monitors for each unit prior to the license expiration and at least every ten years thereafter. Specify parameters that require monitoring.

• Develop acceptance criteria for the procedures that implement testing of nuclear instrumentation cables.

The inspectors reviewed the aging management program basis document, implementing procedures, completed inspection activities, and commitment closure documents. The inspectors reviewed the inspection results with licensee staff and discussed previous station operating experience.

The inspectors determined that the licensee performed testing of the source, intermediate, and power range nuclear instrument channels to identify any adverse aging effects of the cables. The licensee also performed a review of calibration records for their radiation monitors to determine if the associated circuits continued to perform their function. The inspectors determined that procedure AWP E-038, Aging Management for XI.E2 Electrical Cables & Connections Used in I&C Circuits, revision 0, implemented this aging management program. The procedure requires an engineering evaluation when the acceptance criteria are not met to ensure that the intended functions of the electrical cables can be met. When an unacceptable condition or situation is identified, a determination also is made under the corrective action program as to whether the review of calibration and surveillance results or the cable system testing frequency needs to be increased.

The inspectors confirmed the licensee included their commitments in associated implementing procedures or design activities and had implemented the procedures for this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(21) A.2.2.38 Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (XI.E3) and Commitment 40 This existing program manages the aging effects of inaccessible power cables (greater than or equal to 400 volts) located in conduit, cable trenches, cable troughs, duct banks, and pull boxes or directly buried in soil and potentially exposed to adverse localized environments caused by significant moisture. Significant moisture is defined as periodic exposures to moisture that last more than a few days (e.g., cable wetting or submergence in water).

Commitment 40 specified:

Continue the inaccessible power cables not subject to environmental qualification requirements aging management program, including the following enhancements to:

• Ensure procedures implement actions to manage aging of inaccessible and underground in-scope power cables (greater than or equal to 400 volts).

• Enhance maintenance plans to require

(1) annual inspection for water accumulation, and

(2) for cables found submerged (i.e., cable exposed to significant moisture), corrective actions to keep the cable dry, assess cable degradation, and determine the cause of water accumulation.

• Perform baseline inspection of pull boxes, looking for excessive drooping or sagging of cables and for visible indications of damage or degradation of cables and their supports.

• Enhance maintenance plans to require

(1) inspecting the intake structure pull boxes every refueling outage, inspect accessible conduit ends for water collection and cables and cable support structures for visible signs of degradation and

(2) an engineering evaluation to assess cable degradation and to determine the cause of water accumulation for cables found submerged.

• Enhance maintenance plans to test sump alarm features annually prior to the rainy season.

• Implement testing of power cables to assess the condition of cable insulation, using a proven test for detecting deterioration caused by wetting or submergence. Perform tests once every six years with the first tests completed prior to November 2, 2024, and August 26, 2025, for Units 1 and 2, respectively. Trend test results to determine the rate of degradation. More frequent testing may occur based on test results and operating experience.

• Establish acceptance criteria for pull box inspections and cable testing based on the type of test performed and the cable tested.

Exceptions:

Exception 1: Annual direct inspections will not include direct inspection of accessible cable conduit ends or direct inspection of cables and cable support structures.

Instead, a baseline inspection of pull boxes was be performed prior to November 2, 2024, and August 26, 2025, for Units 1 and 2, respectively.

The inspectors verified that the licensee inspects the pull boxes as part of the structures monitoring program through the period of extended operation.

The inspectors determined that the pull boxes have conduits that drain to pull boxes at the intake and turbine building. The end pull boxes drain to a building sump or to an in-ground drain sump, which is separate from the pull boxes. The sump has an automatic sump pump and high-level alarm, which provides indication of pump failure before water in the sump backs up into pull boxes. The pull box sump pump and alarm features are tested annually prior to the rainy season. The pull box layout and sump pumps minimize the potential for submergence of cables, splices, and cable supports. California weather patterns consist of a concentrated rainy season lasting 6-7 months. Rain outside of the rainy season is very rare, and when encountered, produces negligible amounts of rain. Therefore, testing once annually prior to the rainy season provides reasonable assurance that the pumps will operate properly throughout the season.

Furthermore, engineering evaluation will be conducted if cables are found to be submerged in pull boxes to assess the impact of submergence on cable degradation and determine the cause of water accumulation, including any potential drain conduit blockage with appropriate corrective actions taken.

Exception 2: No annual inspections for water collection in the listed intake structure pull boxes.

Because the inspections cannot be accessed at power, the licensee inspects these pull boxes during refueling outages. The inspectors verified that these pull boxes drain to the intake building sump and there is no plant operational experience of water accumulating in these pull boxes.

Exception 3: No event driven inspections for water accumulation in pull boxes.

The inspectors determined that the layout ensures that water would be drained away from the pull boxes, sump pumps remove the water at the end pull boxes and a high-level alarm will actuate to indicate the sump pump cannot remove the accumulated water. The licensee assures reliability of sump pumps through annual inspections.

Exception 4: No inspections of dewatering devices (sump pumps) prior to any known or predicted heavy rain or flooding events.

The inspectors determined that the licensee tests the sump pumps and alarm features at least annually, typically, prior to the rainy season.

The inspectors reviewed the aging management program basis document, implementing procedures, completed inspection activities, and commitment closure documents. The inspectors reviewed the inspection results with licensee staff and discussed previous station operating experience. The inspectors confirmed the licensee included their commitments in associated implementing procedures and had implemented the procedures for this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(22) A.2.2.39 Metal Enclosed Bus (XI.E4) and Commitment 41 This existing program manages aging of in-scope nonsegregated phase and isolated phase buses. Specifically, this program manages the degradation for electrical bus bar bolted connections, bus bar insulation, bus bar insulating supports, bus enclosure assemblies (internal and external), and elastomers. The licensee evaluates the effects of loose connections, embrittlement, cracking, melting, swelling, or discoloration of insulation, loss of material of bus enclosure assemblies, hardening of boots and gaskets, and cracking of internal bus supports to ensure the intended function remains.

Commitment 41 specified:

Continue the metal enclosed bus aging management program, including an enhancement to formalize the existing inspection and testing of the metal enclosed buses.

• Create procedures to formalize the existing inspection and testing of the metal enclosed buses and include specific inspection scope, methods, frequencies, and actions to be taken when acceptance criteria are not met.

Exception:

The isolated phase bus inspections do not require inspection or testing of bolted connections between bus segments or the inspection of insulating materials on the bus.

The inspectors determined that the isophase bus bars are welded and do not require resistance checks or infrared inspections. The licensee manages the three bolted connections under the maintenance programs of the motor-operated disconnect, the main unit transformers, and the auxiliary transformers. The inspectors did not identify any concerns with this exception.

The inspectors reviewed the aging management program basis document, implementing procedures, completed inspection activities, and commitment closure documents. The inspectors walked down accessible metal-enclosed buses to inspect material conditions. The inspectors interviewed licensee personnel regarding operating experience and lessons learned from previous bus inspections. The inspectors verified procedure AWP E-039, Metal Enclosed Bus Aging Management, identified the parameters and acceptance requirements for the program.

The inspectors determined that the licensee visually inspected the internal portion of each bus section prior to the period of extended operation for aging degradation including cracks, corrosion, foreign debris, excessive dust buildup, structural integrity, and evidence of water intrusion. The bus insulation is inspected for signs of embrittlement, cracking, melting, swelling, hardening or discoloration, which may indicate over heating or aging degradation. The bus enclosure assemblies are inspected for loss of material caused by corrosion and hardening of boots and gaskets. The licensee will conduct these recurring inspections every ten years.

The licensee inspected a sample (20 percent of the population with a maximum sample of 25) of the accessible bolted connections of non-segregated phase internal bus work for loose connections by performing digital low resistance ohmmeter electrical testing, or thermography. This program requires recurring inspections every ten years. The inspectors reviewed the maintenance plans scheduled and confirmed licensee will complete 100 percent of the in-scope population within the 10-year or 5-year interval, as appropriate.

The inspectors confirmed the licensee included their commitments in associated implementing procedures and had implemented the procedures for this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(23) A.2.2.41 Periodic Inspections for Selective Leaching (Plant Specific) and Commitment 43 This new plant-specific condition monitoring program manages the loss of material caused by selective leaching identified in gray cast iron components subject to a soil environment and identified in aluminum-bronze components in a raw water environment. The licensee performs visual inspections coupled with mechanical examinations (scraping), and destructive examinations to determine if loss of material caused by selective leaching has occurred. The licensee will complete the initial inspections for each unit prior to their entry into the period of extended operation.

Commitment 43 specified:

• Implement the periodic inspections for selective leaching aging management program.

The inspectors reviewed the aging management program basis document, implementing procedures, examination reports, and corrective action documents. The inspectors reviewed some inspection results but determined that the licensee had not completed the baseline examinations for this program. The licensee established a schedule to complete the initial baseline Unit 1 and Unit 2 for both material environment groups by March 31, 2026. The licensee identified they needed the extra time in Letter DCL-24-092. The inspectors determined SAPN 51263882 implemented the periodic inspections planned for both units for the gray cast iron in soil and aluminum bronze with raw water inside. The inspectors verified that the licensee had the components identified and scheduled for review prior to March 31, 2026.

Additionally, the licensee had identified the number of inspections for each material/environment during subsequent 10-year periods. The inspectors verified that the licensee refurbished the interior of the auxiliary saltwater vacuum breaker check valves on a 3-yrear frequency to reduce the sensitization to the effects of selective leaching.

The inspectors determined that the licensee had several 5 to 10-foot sections of fire water piping that they considered as a single component. The inspectors reviewed the licensee justification and identified no concerns with this approach since the relatively short pipe lengths consisted of the same material and did not transition from different internal or external environments over the pipe lengths. The impact of considering these pipe lengths as single components resulted in there being less than 35 components and the licensee was required to conduct a single destructive examination each 10-year period for this material and environment instead of two destructive examinations.

Because the licensee had established a program with implementing procedures and had inspections scheduled, the inspectors had reasonable assurance that the licensee would manage the effects of aging caused by selective leaching of aluminum bronze and gray cast iron in soil. The inspectors confirmed the licensee included their commitments in associated implementing procedures and had implemented the procedures for this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

(24) A.2.2.42 Transmission Conductor and Connections, Switchyard Bus and Connections, and High-Voltage Insulators (Plant Specific) and Commitment 44 This existing program manages the aging effects of the 230 kV and 500 kV components required for station blackout recovery that include transmission conductors and connections, insulators, and switchyard bus and connections to ensure that these components remain capable of performing their intended functions.

Infrared thermography inspection of transmission and bus connections for indications of loose or degraded connections, inspection of transmission conductors for corrosion and fatigue, and inspection of insulator supports for corrosion and wear will be conducted at a frequency based on plant-specific operating experience. The licensee will complete their baseline inspections and determine the extent of future degradation prior to entering the period of extended operation.

Commitment 44 specified:

Continue the transmission conductor and connections, switchyard bus and connections, and high-voltage insulators plant specific aging management program including enhancements to:

• Identify components required to support station blackout recovery in the 230 kV and 500 kV switchyards between the listed transformers and disconnects/breakers.

• Review completed inspection results to identify adverse trends.

• Evaluate any degraded condition that considers the extent of condition, reportability, potential causes, probably of recurrence, and the corrective actions required.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed inspection activities, corrective action program evaluation of related issues, and commitment closure documents. The inspectors reviewed the inspection results with licensee staff to inspect material conditions and discussed previous station operating experience.

The licensee identified this plant-specific program because of a long-term aging issue associated with continued corona activity on their polymer insulators. In some instances, the transmission polymer insulators retained surface contamination (mostly salt from the nearby ocean spray) and led to flashovers. To address the flashovers, the licensee switched to Sediver glass insulators (a toughened glass material) with an RTV-material insulator starting in 2010 for many of its high voltage insulators, which are hydrophilic and less likely to retain surface contamination.

This aging management program requires that all 230 kV and 500 kV transmission lines be inspected by performing aerial, ground, and climbing inspections at specified frequencies. The inspections look for, but not limited to, insulator, conductor, connector, and support degradation including corrosion, mechanical wear, and contamination. The licensee also monitors for indications of conductor degradation including strand breakage, excessive corrosion and swelling of conductors, connectors, splices, and insulators in the switchyard. If the inspections identify degradation, this may result in follow-up inspections such as infrared thermography.

This program manages loss of material in metallic parts caused by mechanical wear or corrosion, reduced insulation resistance caused by salt deposits or surface contamination, and loss of transmission line strength caused by wear.

The inspectors confirmed the licensee included their commitments in associated implementing procedures and had implemented the procedures for this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program for the samples reviewed.

INSPECTION RESULTS

No findings were identified.

EXIT MEETINGS AND DEBRIEFS

The inspectors verified no proprietary information was retained or documented in this report.

• On February 27, 2025, the inspectors presented the license renewal inspection results to Maureen Zawalick, Vice President, Business and Technical Services and other members of the licensee staff.

DOCUMENTS REVIEWED

The following commitments were closed in License Renewal Inspection Report 05000275/2024013 and 05000323/2024013: 3, 4, 5,

6, 7, 8, 9, 12, 13, 14, 15, 16, 18, 24, 25, 26, 27, 29, 33, 37, and 42

The following commitments were closed during this inspection after review of the aging management program implementation and

associated commitments: 1, 2, 3, 10, 11, 17, 19, 20, 21, 23, 30, 31, 32, 34, 35, 36, 38, 39, 40, 41, 43, and 44.

The following commitments remain open and will be reviewed during future inspection(s): 22 and 28.

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Letter DCL-24-091

Response to Request for Additional

Information by the Office of Nuclear Reactor

Regulation Diablo Canyon Safety Review

Pacific Gas and Electric Company Diablo

Canyon Units 1 & 2 (Set 1)

10/3/2024

Letter DCL-24-092

Supplement and Annual Update: Diablo

Canyon Power Plant License Renewal

Application, Amendment 1

10/14/2024

71002

Miscellaneous

Letter DCL-25-001

Response to Request for Additional

Information by the Office of Nuclear Reactor

Regulation Diablo Canyon Safety Review

Pacific Gas and Electric Company Diablo

Canyon Units 1 & 2 (Set 2)

1/2/2025

Calculations

9000041674

Buried Piping and Tanks Program Asset

Management Plan

71013

Corrective

Action

Documents

SAPN

51179006, 51187979, 51198227,

51198770, 51209720, 51211955,

213369, 51213641, 51215632,

219571, 51219572, 51219573,

219574, 51220689, 51224468,

226101, 51230162, 51230402,

230891, 51231286, 51232426,

236487, 51236488, 51237115,

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

240412, 51241254, 51241316,

247080, 51247081, 51251722,

253827, 51254842, 51255925,

256507, 51261789, 51268756,

270623, 51270626, 51270771,

270943, 51273390, 51273391

Corrective

Action

Documents

Resulting from

Inspection

SAPN

273390, 51273391, 51273495,

273567, 51273568, 51273569,

273651, 51273653, 51273660

Design Document Package

1000025725A

Revise PTLR-1/LTOP Enable Setpoint

Change

Engineering

Changes

Design Mechanical Document

60171149

Installation of Cable Tray Covers to Deflect

Oil Unit 1 and 2

One-Time Inspection AMP Inspection

Results

Selective Leaching AMP Inspection Results

DCPP Buried and Underground Piping and

Tanks Program (B.2.3.26) License Renewal

Technical Basis Document

Aging Management Program Results

Binder

Fire Water

2/27/2025

Aging Management Program Results

Binder

Bolting Integrity

2/27/2025

CMR 4.6

Maintenance Rule -Civil Implementation

Masonry Walls

DBC2311010R0-F

Testing of Source, Intermediate and Power

Range Nuclear Instrumentation System

Channels at Diablo Canyon Unit 1

DBC240501R0-F

Testing of Source, Intermediate and Power

Range Nuclear Instrumentation System

Channels at Diablo Canyon Unit 2

Miscellaneous

DCM T-43 License Renewal

Diablo Canyon Aging Management

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Appendix B, Section B.2.3.15

Program Evaluation Report B.2.3.15 - Fire

Water System

DCM T-43 License Renewal

Appendix B, Section B.2.3.17

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.17 - Fuel

Oil Chemistry

DCM T-43 License Renewal

Appendix B, Section B.2.3.18

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.18 -

Reactor Vessel Surveillance

DCM T-43 License Renewal

Appendix B, Section B.2.3.19

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.19 - One-

Time Inspection

DCM T-43 License Renewal

Appendix B, Section B.2.3.20

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.20 -

Selective Leaching

DCM T-43 License Renewal

Appendix B, Section B.2.3.26

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.26 -

Buried and Underground Piping and Tanks

DCM T-43 License Renewal

Appendix B, Section B.2.3.30

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.30 -

ASME Section XI, Subsection IWF

DCM T-43 License Renewal

Appendix B, Section B.2.3.32

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.32 -

Masonry Walls

DCM T-43 License Renewal

Appendix B, Section B.2.3.33

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.33 -

Structures Monitoring

DCM T-43 License Renewal

Appendix B, Section B.2.3.34

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.34 -

Regulatory Guide 1.127, Inspection of

Water-Control Structures Associated with

Nuclear Power Plants

DCM T-43 License Renewal

Appendix B, Section B.2.3.36

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.36 -

Insulation Material for Electrical Cables and

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Connections Not Subject to 10 CFR 50.49

EQ Requirements

DCM T-43 License Renewal

Appendix B, Section B.2.3.37

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.37 -

Insulation Material for Electrical Cables and

Connections Not Subject to 10 CFR 50.49

EQ Requirements Used in Instrumentation

Circuits

DCM T-43 License Renewal

Appendix B, Section B.2.3.38

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.38 -

Inaccessible Power Cables Not Subject to

CFR 50.49 EQ Requirements

DCM T-43 License Renewal

Appendix B, Section B.2.3.39

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.39 - Metal

Enclosed Bus

DCM T-43 License Renewal

Appendix B, Section B.2.3.41

Diablo Canyon Aging Management

Program Evaluation Report B.2.3.41 -

Periodic Inspections for Selective Leaching

EPRI 3002007348

Aging Management for Leaking Spent Fuel

Pools

2/2016

PGEDCROLI-00005-REPT-003

Diablo Canyon Units 1 and 2 Selective

Leaching Aging Management Program

Sampling Plan

PGEDCROLI-00005-REPT-004

E1 Walkdown Methodology

PGEDCROLI-00005-REPT-005

Pre-PEO GALL l XI.E1 Walkdown Results

Report - Unit 1 And Common Areas During

Normal Operating Conditions

PGEDCROLI-00005-REPT-006

Pre-PEO Cable Calibration Surveillance

Test Reviews and Cable Tests [XI.E2]

PGEDCROLI-00005-REPT-014

Selective Leaching Aging Management

Program Technical Basis Document

PGEDCROLI-00005-REPT-016

DCPP One-Time Inspection Program

Sampling Technical Basis Document

PGEDCROLI-00005-REPT-025

Pre-PEO GALL l XI.E1 Walkdown Results

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Report - Unit 2 Areas During Normal

Operating Conditions

PGEDCROLI-00005-REPT-026

Pre-PEO GALL l XI.E1 Walkdown Results

Report - Unit 1 Containment Areas During

Outage Conditions

VL Project No. 23034

Diablo Canyon Power Plant 2023 Survey of

Intake Basin Breakwater Structures

8/8/2023

VL_ 23006_LR_Radwaste

Structure_093024

U0 Radwaste Structure Baseline Concrete

Inspection Report

VL_ 23006_LR_U1_Intake_100124

U1 Intake Structure Baseline Concrete

Inspection Report

VL_

23006_LR_U1_Transformers_093024

U1 Transformer Baseline Concrete

Inspection Report

VL_22005_041322

Diablo Canyon Power Plant Test and

Analysis of Structural Concrete During

1R23 - Inspection of the Circulating Water

Conduits, Traveling Screens, Circulating

Water Pump and Auxiliary Saltwater

Forebays, Discharge Conduits, Intake

Structure and Associated Structures

VL_22022_082522

Diablo Canyon Power Plant Test and

Analysis of Non-Submerged Structural

Concrete of the Intake Structure

VL_23006_LR_ U1_

Containment_100124

U1 Containment (Interior) Baseline

Concrete Inspection Report

VL_23006_LR_ U1_Auxiliary_100124

U1 Auxiliary Building Baseline Concrete

Inspection Report

VL_23006_LR_ U1_Buttress_100224

U1 Buttress Buildings Baseline Concrete

Inspection Report

VL_23006_LR_ U1_TURB_10032024

U1 Turbine Building Baseline Concrete

Inspection Report

VL_23006_LR_Discharge

Structure_093024

U1 & U2 Discharge Structure (Non-

submerged) Baseline Concrete Inspection

VL_23006_LR_OWST_091924

U1 & U2 Outside Water Storage Tanks

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Baseline Concrete Inspection Report

VL_23006_LR_SWITCHYARDS AND

TOWERS_091924

Switchyards and Transmission Towers

Baseline Concrete Inspection Report

VL_23006_LR_U0_ADMIN

BRIDGEWAY BBRE_09172024

U0 Administration Building, Bridgeway, and

BBRE No. 6 Baseline Concrete Inspection

Report

VL_23006_LR_U1_DFO_093024

U1 Diesel Fuel Oil System Structures

Baseline Concrete Inspection Report

VL_23006_LR_U1_Pull

Boxes_100124

U1 Pull Box Baseline Concrete Inspection

Report

VL_23006_LR_U1_Submerged

Saltwater Systems

Diablo Canyon Power Plant License

Renewal Concrete Inspection - Unit 1

Submerged Saltwater Systems

VL_DCPP 2R23_22057_020223

Diablo Canyon Power Plant Test and

Analysis of Structural Concrete During

2R23 - Inspection of the Circulating Water

Conduits, Traveling Screens, Circulating

Water Pump and Auxiliary Saltwater

Forebays, Discharge Conduits, Intake

Structure and Associated Structures

WCAP-18124-NP-A

Fluence Determination with RAPTOR-M3G

and FERRET

WCAP-18566-NP

Ex-Vessel Neutron Dosimetry Program for

Diablo Canyon Unit 2 Cycle 21

WCAP-18655-NP

Ex-Vessel Neutron Dosimetry Program for

Diablo Canyon Unit 1 Cycle 22

WCAP-18984-NP

Diablo Canyon Units 1 and 2 Heatup and

Cooldown Limit Curves for Normal

Operation for 45 EFPY

AD4.ID2

Plant Leakage Evaluation

AD5.ID2

Inservice Inspection Program

AD7.DC8

Work Planning

AD7.ID11

Fluid Leak Management Program

Procedures

AWP E-016

Underground/Buried Commodity Inspection

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Checklist

AWP E-037

Insulation Material for Electric Cables and

Connections AMP

AWP E-038

Aging Management for XI.E2 Electrical

Cables & Connections Used in I&C Circuits

AWP E-039

Metal Enclosed Bus Aging Management

AWP E-052

Transmission Conductors, Switchyard Bus

and Connections and HV Insulators AMP

AWP E-058

Fire Water Storage Tank 01 Inspections

AWP E-059

Fire Water System Obstruction Investigation

AWP E-060

Inaccessible Power Cables

AWP E-061

Miscellaneous Diesel Fuel Oil Tank

Inspection and Cleaning

AWP E-063

Sprinkler Head Testing/Replacement

AWP E-064

Volumetric Testing of Non-Draining Fire

Water Systems

AWP E-065

FWS Piping Recurring Internal Corrosion

Inspections

AWP E-066

Pressure Retaining Closure Bolting

Program

AWP E-067

Fire Water System Internal Visual

Inspections

CAP E-17

Sampling and Analyses of Pool Leak

Detection Lines

CAP E-25

Miscellaneous Fuel Oil Tank Chemistry

Sampling Procedure

CAP O-7

Chemical Additions to Security Generator

DFO Storage Tanks and Other DFO Tanks

CF3.DC1

Maintenance and Surveillance of Electrical

Environmentally Qualified (EQ) Equipment

CF3.DC3

Maintenance of EQ Equipment: I&C

CF3.ID3

Environmental Qualification (EQ) Program

CF3.ID9

Design Change Development

CF5.ID12

Consumable Material Control

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Design Criteria Memorandum T-20

Environmental Qualification

MA1.ID17

Maintenance Rule Monitoring Program

MA1.ID20

Testing/Inspections for Aux Saltwater

System NRC Generic Letter 89-13

Compliance

MA1.NE1

Maintenance Rule Monitoring Program -

Civil Implementation

MIP C-15.0

Excavation and Backfill

MIP C-6.0

Fabrication and Erection of Structural Steel

(DCP-201)

MP E-57.14D

Insulation Resistance (Megger) Testing

MP E-57.14E

Medium Voltage Shielded Cable Testing

and Diagnostics

MP E-57.8A

Temperature Monitoring

MP E-61.9A

Isolated Phase Bus and Motor Operated

Disconnect Maintenance

MP I-17-L 156

Intake Structure Sump 1 1 Level Control

Channel Calibration

MP I-2.1-4

NIS Triaxial Connector Installation, Cable

Testing, and Raychem Installation

MP M-51.14

Generic Check Valve Inspection

MP M-54.1

Bolt Fabrication and Tensioning

MP M-56.1

System Pressure Test

NDE PDI-UT-5

Ultrasonic Examination of Bolts and Studs

NDE VT 1-1

Visual Examination of Component Surfaces

PEP 18-02

Firewater Hose Station Flow Test

PEP 72.1

Annual Survey of ASW Pipe Cathodic

Protection

PEP C-17.14

Concrete Surveillance Program for the

Saltwater Systems

PEP M-21A

Diesel Fuel Oil Storage Tanks Inspection

and Cleaning

PGECROLI-00005-REPT-042

Transmission Conductor and Connections,

Switchyard Bus and Connections, and High-

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Voltage Insulators Technical Basis

Document

STP I-118B

Calibration of Control Room Pressurization

Rad Monitors

STP I-119B

Calibration of Fuel Handling Building Area

Radiation Monitors

STP I-39-R44A.B

Containment Ventilation Exhaust RM-44A

Radiation Monitor Calibration

STP M-10A

Diesel Fuel Oil Storage Tank Inventory

STP M-10B

Diesel Fuel Oil Testing Program

STP M-10B3

New Fuel Oil Shipment Analysis

STP M-122

Diesel Fuel Oil Underground Storage Tanks

(DFOUST) 0-1 and 0-2 Interstitial Test and

Enhanced Leak Detection Test

STP M-21-ENG.1

Diesel Engine Generator Inspection (Every

Refueling Outage)

STP M-63E

Fire Water System Yard Loop Flush

STP M-63F

Yard Loop Fire Water System Hydrant

Flush

STP M-65

Sprinkler/Deluge System Visual Verification

STP M-66A U1

Deluge System Nozzle Proof Test Startup

Transformers

STP M-66A U2

Deluge System Nozzle Proof Test Startup

Transformers

STP M-66B U1

Deluge System Nozzle Proof Test Main and

Auxiliary Transformers

STP M-66B U2

Deluge System Nozzle Proof Test Main and

Auxiliary Transformers

STP M-71

Firewater System Flow Test

STP M-72 U1

Exercising Deluge Valves FCV-200, 201

and 203 through 207 in Unit 1 Turb Bldg

STP M-72 U2

Exercising Deluge Valves FCV-200, 201

and 203 through 207 in Unit 2 Turb Bldg

STP M-90B

Surveillance of Diablo Canyon Breakwaters

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

STP V-18M

Check Valve Inspections - High

Maintenance Valves

TD-1001P-14

Infrared (IR) Inspection Procedures

TS1.DC2

Selective Leaching Aging Management

Program

TS1.DC3

One-Time Inspection Program

TS1.ID4

Saltwater Systems Aging Management

Program

TS1.ID6

Reactor Pressure Vessel Embrittlement

Management Program

TS5-ID3

Buried Piping and Tanks Program

Work Orders

60034364, 60059552, 60133434,

60150708, 60150789, 60151476,

60151842, 60151843, 60151845,

60151890, 60151892, 60152105,

60152156, 60152292, 60152297,

60152327, 60153120, 60153305,

60153341, 60154101, 60154103,

60154106, 60154109, 60154116,

60154229, 60154320, 60154604,

60155281, 60156866, 60157437,

60157439, 60157460, 60157461,

60157466, 60157467, 60157471,

60157472, 60157535, 60159609,

60159651, 60171507, 64181744,

64181772, 64216932, 64236203,

247317, 64252353, 64252354,

254743, 64254744, 64300693