ML25149A055

Nuclear Power Plant, Units 1 and 2 - 95001 Supplemental Inspection Report 05000318/2025040 and Follow-Up Assessment Letter

ML25149A055
Person / Time
Site:	Calvert Cliffs
Issue date:	05/29/2025
From:	Nicole Warnek Division of Operating Reactors
To:	Rhoades D Constellation Energy Generation, Constellation Nuclear
References
IR 2025040
Download: ML25149A055 (1)

Text

May 29, 2025 David P. Rhoades Senior Vice President Constellation Energy Generation, LLC President and Chief Nuclear Officer (CNO)

Constellation Nuclear 4300 Winfield Road Warrenville, IL 60555

SUBJECT:

CALVERT CLIFFS NUCLEAR POWER PLANT, UNIT 2 - 95001 SUPPLEMENTAL INSPECTION REPORT 05000318/2025040 AND FOLLOW-UP ASSESSMENT LETTER

Dear David Rhoades:

On April 18, 2025, the U.S. Nuclear Regulatory Commission (NRC) completed a supplemental inspection using Inspection Procedure 95001, "Supplemental Inspection Response to Action Matrix Column 2 (Regulatory Response) Inputs. On April 18, 2025, the NRC inspection team discussed the results of this inspection and the implementation of your corrective actions with Christopher Smith, Plant Manager, and other members of your staff.

The NRC performed this inspection to review your stations actions in response to a White Unplanned Scrams per 7000 Critical Hours performance indicator (PI). The Unplanned Scrams per 7000 Critical Hours PI exceeded the White threshold value in the third quarter of 2024, which you reported on October 23, 2024. The NRC communicated the Calvert Cliffs Nuclear Power Plants (Calvert Cliffs), Unit 2, entry into Reactor Oversight Process Action Matrix Column 2, Regulatory Response Column, in an assessment follow-up letter 05000318/2024007, dated November 6, 2024 (Agencywide Document and Management System (ADAMS) Accession Number ML24309A247). Because this PI returned to the Green performance band in the fourth quarter of 2024, the NRC opened a parallel White PI finding, by annual assessment letter, dated March 11, 2025 (ML25069A535), which was to remain open until satisfactory completion of the appropriate supplemental inspection. On March 13, 2025, NRC was informed of the stations readiness for the supplemental inspection (ML25073A014).

The NRC determined that your staffs evaluation identified the cause of the White PI.

Specifically, the NRC inspectors determined your staff's common root cause analysis identified two common root causes and one common contributing cause. The first common root cause was that site leadership failed to effectively drive utilization of Nuclear Risk Management and Equipment Reliability processes to monitor, evaluate, and prioritize elimination and/or mitigation of single point and conditionally critical equipment vulnerabilities. The second common root cause was that site personnel failed to effectively use MA-AA-716-004, Conduct of

D. Rhoades 2

Troubleshooting, and OP-AA-106-101-1006, Operational Decision Making Process, to identify, evaluate, and disposition all potential failure mechanisms for single point vulnerabilities and conditionally critical equipment. The common contributing cause was that the plant design, based on original construction and legacy modifications, has resulted in multiple single point and conditionally critical equipment vulnerabilities. Corrective actions to preclude repetition are discussed in detail in the attached inspection report.

Overall, the NRC determined that your problem identification, causal analyses, and corrective actions sufficiently addressed the performance issues that led to the White PI. All inspection objectives, as described in Inspection Procedure 95001, were met, and this inspection is, therefore, closed. In accordance with Inspection Manual Chapter (IMC) 2515, Appendix B, Supplemental Inspection Program, dated September 28, 2022, the NRC plans to conduct follow-up inspection activities for the planned corrective actions to preclude repetition that were not yet complete at the time of this supplemental inspection. These inspection activities will be scheduled consistent with your corrective action to preclude repetition completion date as part of a future baseline inspection sample to verify that Constellation completed these actions in accordance with the established plan.

The NRC determined that completed or planned corrective actions were sufficient to address the performance issue that led to the White PI previously described. Therefore, the performance issue will be closed and no longer considered as an Action Matrix input as of the date of the exit meeting. Based on the guidance in IMC 0305, Operating Reactor Assessment Program, and the results of this inspection, the White PI (and associated parallel White finding) will no longer count as an Action Matrix input and Calvert Cliffs, Unit 2, will transition from the Regulatory Response Column (Column 2) of the NRCs Action Matrix to the Licensee Response Column (Column 1) as of April 18, 2025.

One finding of very low safety significance (Green) is documented in this report. This finding did not involve a violation of NRC requirements.

If you disagree with a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; and the NRC Resident Inspector at Calvert Cliffs Nuclear Power Plant, Unit 2.

D. Rhoades 3

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, Nicole S. Warnek, Chief Projects Branch 3 Division of Operating Reactor Safety Docket No. 05000318 License No. DPR-69

Enclosure:

As stated cc w/ encl: Distribution via LISTSERV NICOLE WARNEK Digitally signed by NICOLE WARNEK Date: 2025.05.29 11:00:48 -04'00'

ML25149A055 SUNSI Review Non-Sensitive Sensitive Publicly Available Non-Publicly Available OFFICE DORS/RI DORS/RI DORS/RI NAME SHaney RClagg NWarnek DATE 5/28/2025 5/29/2025 5/29/2025

5 U.S. NUCLEAR REGULATORY COMMISSION Inspection Report Docket Number:

05000318 License Number:

DPR-69 Report Number:

05000318/2025040 Enterprise Identifier: I-2025-040-0003 Licensee:

Constellation Energy Generation, LLC Facility:

Calvert Cliffs Nuclear Power Plant, Unit 2 Location:

Lusby, MD Inspection Dates:

April 07, 2025 to April 18, 2025 Inspectors:

S. Haney, Senior Project Engineer L. Sinclair, Operations Engineer Approved By:

Nicole S. Warnek, Chief Projects Branch 3 Division of Operating Reactor Safety

6

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) reviewed Constellations corrective actions (CAs) to address a White performance indicator (PI) by performing a supplemental inspection using Inspection Procedure (IP) 95001, Supplemental Inspection Response to Action Matrix Column 2 Inputs, at Calvert Cliffs Nuclear Power Plant (CCNPP), Unit 2, 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.

The inspectors determined that the licensees problem identification, causal analysis, and CAs sufficiently addressed the performance issue that led to the White PI.

List of Findings and Violations Failure to Properly Classify Operating Experience Event Contributes to Reactor Trip Cornerstone Significance Cross-Cutting Aspect Report Section Initiating Events Green FIN 05000318/2025040-01 Open/Closed None (NPP) 71153 A self-revealed finding (FIN) of very low safety significance (Green) was identified when Constellation failed to properly screen relevant operating experience (OPEX) as required by NS-1-100, "Use of Operating Experience." Specifically, a 2006 Beaver Valley operating experience report applicable to Calvert Cliffs, Unit 2, was improperly screened as Priority 3, when it should have been classified as Priority 1. As a result, barriers were not put in place to prevent the occurrence of a similar event at CCNPP which contributed to a Unit 2 reactor trip on July 18, 2024, due to the same failure mechanism.

Additional Tracking Items Type Issue Number Title Report Section Status LER 05000318/2024-002-00 LER 2024-002-00 for Calvert Cliffs Nuclear Power Plant, Unit No. 2, Automatic Reactor Trip Due to Main Turbine Loss of Load 71153 Closed LER 05000318/2024-002-01 LER 2024-002-01 for Calvert Cliffs Nuclear Power Plant, Unit No. 2, Automatic Reactor Trip Due to Main Turbine Loss of Load 71153 Closed LER 05000318/2024-003-00 LER 2024-003-00 for Calvert Cliffs Nuclear Power Plant, Unit No. 2, Automatic Reactor Trip Due to Main Turbine Loss of Load 71153 Closed LER 05000318/2024-003-01 LER 2024-003-01 for Calvert Cliffs Nuclear Power Plant, Unit 2, Automatic Reactor 71153 Closed

7 Trip Due to Main Turbine Loss of Load FIN 05000318/2024006-01 Parallel White Finding for White Performance Indicator (IEO1) 95001 Closed

8 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 IPs 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 IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. 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 71153 - Follow Up of Events and Notices of Enforcement Discretion Event Report (IP Section 03.02) (2 Samples)

The inspectors evaluated the following licensee event reports (LERs):

(1)

LERs 05000318/2024-002-00, 01, Automatic Reactor Trip Due to Main Turbine Loss of Load, (ADAMS Accession Number ML24260A142 and ML25024A089).

A Green self-revealed finding was identified during the review of the LERs and is documented in this report under Inspection Results Section as FIN 05000318/2025040-01. These LERs are Closed.

(2)

LERs 05000318/2024-003-00, 01, Automatic Reactor Trip Due to Main Turbine Loss of Load, (ML24344A197 and ML25083A223). The inspectors determined that the cause of the condition described in the LERs was not reasonably within the licensee's ability to foresee and correct and, therefore, was not reasonably preventable. No performance deficiency nor violation of NRC requirements was identified. These LERs are Closed.

95001 - Supplemental Inspection Response to Action Matrix Column 2 Inputs The inspectors reviewed and selectively challenged aspects of the licensees problem identification, causal analyses, and CAs in response to a White PI for Unplanned Scrams per 7000 Critical Hours, reported to the NRC on October 23, 2024, which includes unplanned manual or automatic reactor trips. Specifically, Calvert Cliffs, Unit 2, experienced five reactor trips as follows:

1. On November 7, 2023, Unit 2 automatically tripped when the U-4000-22 Unit Service Transformer was lost due to an electrical bus fault. This event was reported under LER 2023-002-00, Automatic Reactor Trip from Reactor Protection System Actuation due to Loss of Unit Service Transformer (ML24008A240). A self-revealed Green finding for the licensees failure to adequately implement work instructions for the performance of maintenance was documented in NRC Inspection Report 05000317/2024001 and 05000318/2024001, as FIN 05000318/2024001-01 (ML24128A001). [Event 1]

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2. On November 16, 2023, Unit 2 automatically tripped when the U-4000-22 Unit Service Transformer was lost due to a ground fault signal. This event was reported under LERs 05000318/2023-004-00, 01, "Automatic Reactor Trip from Reactor Protection System Actuation Due to Loss of Unit Service Transformer," (ML24016A205 and ML24107B099). The LERs were closed in NRC Inspection Report 05000317/2024003 and 05000318/2024003 (ML24296A008). The inspectors determined that the cause of the condition described in the LER was not reasonably within the licensee's ability to foresee and correct and, therefore, was not reasonably preventable. No performance deficiency nor violation of NRC requirements was identified. [Event 2]

3. On February 24, 2024, operators initiated a Unit 2 manual reactor trip in response to a trip of the 22 steam generator feed pump (SGFP). Following the manual reactor trip, the 21 SGFP tripped due to high discharge pressure. This event was reported under LERs 05000318/2024-001-00, 01, Manual Reactor Trip due to 22 Steam Generator Feed Pump Trip, (ML24115A183 and ML24233A038). An NRC-identified Green finding for the licensees failure to correct the feedwater system reactor trip override response was documented in NRC Inspection Report 05000317/2024004 and 05000318/2024004, as FIN 05000318/2024004-03 (ML25035A192). [Event 3]

4. On July 18, 2024, Unit 2 automatically tripped due to a main turbine loss of load trip initiated by the reactor protection system. The loss of load trip was the result of main generator exciter loss of field due to a failed stationary field pole electrical connection.

This event was reported under LERs 05000318/2024-002-00, 01 as noted in IP 71153 above. [Event 4]

A fifth reactor trip, similar to Event 4, occurred on October 10, 2024, and was outside the four-quarter band covered by the White PI. However, based on the similarity of the scrams, the fifth scram was included within the scope of the common root cause analysis (RCA):

5. On October 10, 2024, Unit 2 automatically tripped due to a main turbine loss of load trip initiated by the reactor protection system. The loss of load trip was the result of main generator exciter loss of field due to a repeat failure of the stationary field pole electrical connection that was replaced following the Event 4 trip due to the same jumper being broken. This event was reported under LER 05000318/2024-003-00, 01, as noted in IP 71153 above. [Event 5]

To address each of these reactor trips, Constellation performed individual causal analyses.

Following identification of the White PI for Unplanned Scrams per 7000 Critical Hours and subsequent entry into the Regulatory Response Column (Column 2) of the Reactor Oversight Process Action Matrix, Constellation performed a Common RCA to identify the common themes that led to the five events. In a \

letter dated March 13, 2025 (ML25073A014), the NRC was notified of the licensee's readiness for the supplemental inspection to review the actions taken to address the performance issues. Subsequently the NRC performed the onsite portion of this supplemental inspection during the week of April 7-11, 2022, and a subsequent regional office review during the week of April 14-18, 2025.

The inspectors reviewed the following causal analysis products during this inspection:

Corrective action program evaluation (CAPE) 04716036, U2 Automatic Reactor Trip due to U-4000-22 Deenergized

10 RCA 04718086, 11/16/23 U2 Automatic Reactor Trip due to U-4000-22 De-energized RCA 04752936, U2 Manual Reactor Trip - 22 Steam Generator Feed Pump RCA 04808192/04788487, U2 Reactor Trip initiated by Exciter Pole Electrical Connection Failure/U1 AOP-7K Entry RCA 04808192, U2 RX Trip RCA 04797040/04828886, Exceeded Threshold for Unplanned Scrams NRC PI - Unit 2 [Common RCA]

1. Objective: Ensure that the root and contributing causes of significant individual and collective white performance issues are understood.

Under this objective, the inspectors reviewed the causal analyses the licensee conducted for the five individual inputs into the White PI for Unplanned Scrams per 7000 Critical Hours and the Common RCA for the overall PI having exceeded the Green to White threshold. The review consisted of an evaluation of the following: the licensee's identification of the issues, when and how long the issues existed, prior opportunities for identification, documentation of significant plant-specific consequences and compliance concerns, use of systematic methodology to identify causes with a sufficient level of supporting detail, consideration of prior occurrences, identification of extent of condition (EOCo) and extent of cause (EOCa),

and identification of any potential programmatic weaknesses in performance.

NRC Assessment: The team concluded that this objective was met. The inspectors determined that each of the six causal products appropriately identified and documented the direct, root, and contributing causes for the associated problem statements. The inspectors determined that Constellation appropriately evaluated and documented problem identification, including adequate considerations of identification credit, how long the condition existed, and risk insights. The teams review determined the licensees evaluations included relevant OPEX and appropriately considered the safety culture aspects related to each reactor trip.

The team identified weaknesses associated with the Event 4, Event 5 and Common Root Cause RCA reports. Constellation subsequently revised the RCA reports to ensure the documents fully identified prior opportunities for identification, employed systematic methodology and contained an adequate level of detail. See the following general weaknesses in this inspection area:

General Weakness 1 - Prior Opportunities (Section 1.c):

The inspectors determined the Event 5 root cause analysis did not appropriately identify a missed opportunity. The Event 5 root cause was, The Event 4 troubleshooting team/personnel failed to establish appropriate bridging, mitigating, and monitoring parameters in accordance with MA-AA-716-004, Conduct of Troubleshooting, to adequately manage risk until Unit 2 2025 outage elimination strategy could be implemented. The inspection team determined that the Event 4 startup plant operations review committee (PORC) meeting should have been reviewed during the investigation as another prior opportunity for identification, considering PORCs function and relation to the stations operational decision making and risk management processes.

Step 4.3.1.6 of LS-AA-106, Plant Operations Review Committee, states that PORC shall review startup reviews for plant refueling and forced outages as required by OP-AA-108-

11 108, Unit Restart Review, and post trip reviews and post transient reviews as required by OP-AA-108-114, Post Transient Review. The Event 4 startup PORC meeting conducted on July 19, 2024, approved restart pending determining the cause and resolving the cause of the trip. The team noted the final PORC approval, which addressed the pending item to determine and resolve the cause of the trip, had to be reconstructed in a White paper by Constellation. The team determined the stations presentation to this on-site review committee was an opportunity for management to engage the processes called out in the Event 5 root cause (bridging and/or mitigating strategies, adverse condition monitoring (ACM), operational decision-making (ODM), and risk assessment with risk classification manager (RCM)), which was not explored by the Event 5 root cause investigation.

Additionally, Step 4.12.1 of PI-AA-125-1001, Root Cause Analysis Manual, states that if gaps are identified in the qualification, preparation, and/or behavior of the candidates associated with the event, then perform a Performance Analysis, PI-AA-125-1006, 0, as part of the investigation.Section IV of the Management Solution Analysis in the Event 5 Performance Analysis documented, Inadequate measures in place to review troubleshooting plans post resolution of immediate equipment deficiency, and Potential exists for a hindsight look post event response to ensure all documentation is accurate regarding actions taken, owners associated, and key decisions made. The Performance Analysis subsequently documented a Non-Training Solution in Section V to, Recommend addition of management review of troubleshooting plan entries post event (e.g., 4.0 critiques, startup PORC), further supporting the Event 4 startup PORC as a potential missed opportunity for Event 5.

General Weakness 2 - Methodology (Section 1.e):

The inspectors determined the initial versions of the Event 4 and Event 5 root cause analyses were not conducted using an adequate application of systematic methodology.

Although the inspectors determined Constellation's techniques were selected appropriately, the inspectors concluded that in two cases the methodology was not clearly documented.

Specifically, the Equipment Evaluations documented in the root cause reports did not follow the guidance in Attachment 14 of PI-AA-125-1006, Equipment Evaluation.

Step 4.5.1 of PI-AA-125-1001, "Root Cause Analysis Manual," requires the performance of PI-AA-125-1006, Attachment 14, "Equipment Evaluation," for equipment failures to ensure the investigation thoroughly evaluates all potential causes. The Equipment Evaluations performed for the Event 4 and Event 5 root cause investigations were not performed in accordance with the procedure. Specifically, the applicable Section 3.0, Equipment Failure Analysis Checklist attributes, did not have a clearly correlating action in Section 6.0, Actions to Address Contributors. This issue was captured by Constellation in issue report (IR) 04853210 for Event 4 and IR 04853978 for Event 5. Constellation subsequently revised the Section 6.0 actions to clearly correlate to the Section 3.0 checklist attributes. The inspectors subsequent review of the revised Equipment Evaluations determined that no additional Section 6.0 actions were required, and all applicable Section 3.0 attributes were able to be tied to existing actions.

12 General Weakness 3 - Level of Detail (Section 1.f):

The inspectors identified multiple examples where there was an inadequate level of detail documented in the Event 4 and Event 5 RCA reports such that they could be understood and verified by a knowledgeable reader:

1. The Event 5 EOCo embedded the EOCo review performed for Event 4 without justification. Additionally, no information was provided regarding inspections performed at the time of the October 2024 (Event 5) plant trip prior to returning to service.

2. The Event 4 and Event 5 EOCo reviews considered and evaluated the extent to which cyclic fatigue could affect the other Unit 2 exciter stationary poles or the Unit 1 exciter. However, there was less than adequate detail documented discussing the condition of the electrical connections and no discussion documented regarding the extent to which cyclic fatigue might affect the Unit 1 exciter.

3. All CAs taken to address elevated vibration following Event 4 and Event 5 were not listed in the root cause reports. The direct cause was recharacterized from high cyclic fatigue to low cyclic fatigue following the Event 5 failure analysis, but the only CA to reduce vibration was to rewind the exciter.

4. The Event 5 Equipment Evaluation Ineffective Action attribute/contributor did not document review of the Event 4 corrective maintenance. Subsequent review determined the corrective maintenance would not be considered rework.

5. The Common RCA documented that design changes to monitor and reduce vibration and to improve exciter cooling were necessary based on language in the Event 4 RCA direct cause. However, exciter cooling was refuted as a contributor to the stationary pole failure following failure analysis in Event 5.

In the above documentation quality examples, the inspectors determined that the evaluations level of review was adequate, but conclusions were not well documented. This issue was captured in IR 04855550, and Constellation subsequently revised the Event 4, Event 5, and Common RCA reports.

These general weaknesses were independently evaluated in accordance with the guidance in IMC 0612, Appendix B, Issue Screening, and Appendix E, Examples of Minor Issues.

The inspectors determined the issues were not of more than minor significance and, therefore, were not subject to enforcement action in accordance with the NRCs Enforcement Policy.

a. Identification. The five unplanned scrams for Unit 2 were appropriately categorized by the licensee as self-revealing events.

b. Exposure Time. For the five events, the licensee appropriately addressed the exposure time for each issue.

Event 1: During installation of an open phase condition detection modification in 2017, work instructions provided in the modification document failed to install voltage

13 regulator current transformer (CT) wiring with proper clearance from the 13 kilovolt (kV) bus bar that resulted in the U-4000-22 transformer fault on November 7, 2023.

Event 2: During installation of a modification in the U-4000-22 transformer in 2001, installation deficiencies resulted in the 250G ground sensor CT cable missing required shielding and insulation. Without the required shielding, it is believed that the cables armor jacket was damaged by an arc to ground generated from the Event 1 ground potential rise. The damaged cable introduced circuit vulnerability to electromagnetic interference (EMI) and resulted in the spurious ground fault actuation on November 16, 2023.

Event 3: Latent pipe strain in the 22 SGFP discharge piping was present prior to 1985 and resulted in misalignment between the pump and turbine and subsequent coupling failure on February 24, 2024.

Event 4: The long-term equipment vibration associated with the main generator and exciter that caused the Unit 2 exciter stationary pole connection failure on July 18, 2024, had existed since 1986.

Event 5: The elevated vibration that caused a repeat stationary pole connection failure in Event 5 existed prior to Event 4. Forensic analysis following Event 5 identified that both stationary pole connection failures were due to low cyclic fatigue as opposed to the high cyclic fatigue failure mechanism due to long-term degradation as determined in the Event 4 RCA.

c. Identification Opportunities. In general, the licensee appropriately considered prior occurrences and identification opportunities; however, the team identified that the Event 5 RCA did not document all prior opportunities for identification. See General Weakness 1 above.

Event 1: There were several opportunities to identify the installation deficiency prior to the unplanned scram on November 7, 2023. The preventive maintenance (PM) performed between the modification installation and Event 1 did not identify the inadequately installed wiring. PM procedures did not contain specific acceptance criteria for clearance between CT wiring and the 13kV bus bar to prevent faults.

Event 2: Opportunities to identify the incorrect wire configuration prior to the unplanned scram on November 16, 2023, existed during preparation for the modification installation. Vendor drawings explicitly stated control wire in high voltage sections must be placed in metal wireways or be shielded; however, that was not aligned with the equipment provided. Additionally, while acceptance testing and receipt inspections were conducted satisfactorily, separate load tap changer testing completed resulted in ground fault relays tripping.

Event 3: There were several opportunities to identify latent pipe strain prior to the unplanned scram on February 24, 2024. Event 3 is the fourth known instance of the 22 SGFP coupling failing. Previous root cause analyses in 2013 and 2015 concluded factors other than pipe strain were the main failure modes and did not discuss the contributing effect that pipe strain had on proper pump to turbine alignment.

14 Event 4: There were several opportunities to identify the issues associated with Unit 2 turbine generator vibration prior to the unplanned scram on July 18, 2024. The station had attempted to reduce vibration on the exciter outboard bearing several times with no lasting success. Siemens Westinghouse issued a Service Bulletin recommending reinforcement of the support structure for low pressure turbine bearings that would lower vibration throughout the machine that was not performed at Calvert Cliffs, Unit 2. Additionally, OPEX was available from an identical event at Beaver Valley that occurred in 2006. A self-revealed Green finding for this missed OPEX is documented in the Results section of this report.

Event 5: In addition to the Siemens Westinghouse Service Bulletin and Beaver Valley OPEX, the failed exciter poles from Event 4 were not quarantined and sent for failure analysis. Additionally, troubleshooting following Event 4 failed to establish appropriate bridging, mitigating, and monitoring parameters to adequately manage risk resulting in a repeat occurrence. During the review, the team noted a missed prior opportunity for identification associated with the stations conduct of startup PORC following Event 4 as documented in General Weakness 1.

d. Risk and Compliance. The causal analysis reports documented the qualitative consequences of each event and the performance issue with respect to nuclear, radiological, safety culture, and industrial consequences. The inspectors concluded the causal analysis reports demonstrated an understanding of significant plant consequences and compliance concerns associated with each event and the performance issue.

All five of the reactor trips were evaluated by a Region I senior reactor analyst (SRA) and were determined to be of very low risk significance. The NRC issued Green findings for the circumstances associated with Event 1 and Event 3, as discussed previously in this inspection report, and with the circumstances of Event 4 as documented in the Inspection Results Section below.

Event 1: There were no adverse safety consequences because of the Event 1 automatic trip caused by an electrical bus fault and subsequent loss of the U-4000-22 transformer. This resulted in a loss of both control element drive mechanism motor generator sets and a reactor trip bus undervoltage condition. The scram was not complicated. Mitigating equipment operated as designed and operators responded appropriately. While the safety-related 24 4kV bus was de-energized as a result, the 2B emergency generator started and powered the bus with no issues.

Event 2: There were no adverse safety consequences because of the Event 2 automatic trip caused by a spurious ground fault signal and subsequent loss of the U-4000-22 transformer. This resulted in a loss of both control element drive mechanism motor generator sets and a reactor trip bus undervoltage condition. The scram was not complicated. Mitigating equipment operated as designed and operators responded appropriately. While the safety-related 24 4kV bus was de-energized as a result, the 2B emergency generator started and powered the bus with no issues.

Event 3: There were no adverse safety consequences because of the Event 3 manual reactor trip. The scram was not complicated. Mitigating equipment operated

15 as designed and operators responded appropriately by manually tripping the Unit 2 reactor upon loss of the 22 SGFP as required with the 23 standby feed pump out of service.

Event 4: There were no adverse safety consequences because of the Event 4 automatic reactor trip due to a main turbine load reject trip. The scram was not complicated. Mitigating equipment operated as designed and operators responded appropriately.

Event 5: There were no adverse safety consequences because of the Event 5 automatic reactor trip due to a main turbine load reject trip. The scram was not complicated. Mitigating equipment operated as designed and operators responded appropriately.

Common RCA: As a result of the five events, Constellation conducted an analysis to perform a Bayesian update of the initiating event frequencies to include the Unit 2 trip events. After the Bayesian update, the full power internal events model-of-record Unit 2 cutsets were updated with the new initiating event values, and the delta-core damage frequency increase over baseline risk was assessed to be 3.5E-7/yr. Plant trip events after 2022 will be reviewed and included in the next model-of-record update. A Region I SRA reviewed Constellations evaluation. The SRA used Calvert Cliffs initiating events alpha and beta prior values and independently calculated a posterior mean value for the initiating events which was consistent with the licensees calculation.

e. Methodology. The licensee employed systematic, evidenced-based methodologies including, Barrier Analysis, Organizational Effectiveness Evaluation, Safety Culture Assessment, Event and Causal Factors Charting, Equipment Evaluation, Gap, Driver, Action and Result Industry Good Practice, Performance Analysis, Analysis of Common Issues and Interviewing to gather data, identify the problem, and determine the root cause and contributing causes of the White performance issue. The team identified that the Event 4 and Event 5 RCA reports did not perform the Equipment Evaluation investigation technique in accordance with the procedure. See General Weakness 2 above.

Event 1 - The CAPE identified the following:

o Cause 1 (1C1): The cause of the U-4000-22 transformer fault was the A phase of the 13kV voltage regulator being shorted to ground through the CT secondary wiring due to inadequate clearance. Inadequate work practices due to a lack of detail in the E-406, Engineering & Construction Standard, guidance led to insufficient clearance between the installed CT wire and the live 13kV bus bar.

The CT wire was routed such that inducted heat allowed the wire to sag and contact the 13kV bus bar.

o Cause 2 (1C2): The work order (WO) to install the open phase detection modification in 2017 (C93393660) was not screened as operational critical component work (OPCCW), per MA-AA-716-010-1015, Operational Critical Component Work (OPCCW) Process, Revision 2, and ER-AA-2004, System Vulnerability Identification and Mitigation, Revision 8, resulting in inadequate Constellation oversight of the work performed.

16 o Cause 3 (1C3): The PM strategy did not prevent the fault from occurring, because PMs performed between the initial installation and the fault did not identify the inadequately installed CT wire. The PM task was for cleaning, inspecting, and testing the voltage regulator, but did not contain specific acceptance criteria associated with the clearance between the CT wiring and the 13kV bus bar to prevent faults from occurring.

Event 2 - The RCA identified the following:

o Cause 1 (2C1): The root cause was a spurious ground fault signal caused by EMI, which actuated the U-4000-22 transformer high side feeder breaker ground fault relay (250G).

o Cause 2 (2C2): The contributing cause was ground fault relay circuit vulnerability to EMI attributed to component selection of the ground sensor circuit and cable installation deficiencies.

Event 3 - The RCA identified the following:

o Cause 1 (3C1): The direct cause was that piping strain caused misalignment from pump to turbine casing leading to catastrophic failure of the coupling.

o Cause 2 (3C2): The root cause was that long-term management of the 22 SGFP equipment was inadequate through repeat failures where latent pipe strain was not addressed in response to 2013 and 2015 events as data evidenced a different failure mechanism prevailed as a cause.

o Cause 3 (3C3): A contributing cause was that the station response to 22 SGFP coupling failures did not ensure physical field condition information was gathered to fully refute pipe strain as a failure mechanism.

o Cause 4 (3C4): A second contributing cause was that the outage control center did not prioritize restoration of 500kV black bus prior to entering reduced inventory window for 12B reactor coolant pump seal replacement.

Event 4 - The revised RCA identified the following:

o Cause 1 (4C1): The direct cause was the loss of a Unit 2 exciter field electrical connection from cyclic fatigue due to vibration until the electrical connector failed.

o Cause 2 (4C2): The root cause was that engineering personnel and their leadership failed to adequately exhibit technical conscience principles and technical human performance behaviors, resulting in cyclic fatigue of a single point vulnerability (SPV) component to plant trip.

o Cause 3 (4C3): The contributing cause was insufficient use of directly related OPEX.

Event 5 - The revised RCA identified the following:

o Cause 1 (5C1): The direct cause was the loss of a Unit 2 exciter field electrical connection from cyclic fatigue due to vibration until the electrical connector failed.

o Cause 2 (5C2): The root cause was that troubleshooting team/personnel (war room, outage control center, Operations, Maintenance, Engineering) for the July 2024 trip failed to establish appropriate bridging, mitigating, and monitoring parameters in accordance with MA-AA-716-004, Conduct of Troubleshooting, to adequately manage risk until the Unit 2 2025 refueling outage elimination strategy could be implemented.

o Cause 3 (5C3): The contributing cause was inadequate use of technical human performance fundamentals by station personnel to sufficiently challenge vendor

17 inputs, ensure data-based decision making and intolerance to long-standing degraded conditions.

Common RCA - The RCA identified the following:

o Cause 1 (CC1): A common root cause was that CCNPP leadership failed to effectively drive utilization of Nuclear Risk Management and Equipment Reliability processes to monitor, evaluate, and prioritize elimination and/or mitigation of single point and conditionally critical equipment vulnerabilities.

o Cause 2 (CC2): A second common root cause was that CCNPP personnel failed to effectively use MA-AA-716-004, Conduct of Troubleshooting, and OP-AA-106-101-1006, Operational Decision Making Process, to identify, evaluate, and disposition all potential failure mechanisms for single point vulnerabilities and conditionally critical equipment.

o Cause 3 (CC3): A common contributing cause was that the plant design, based on original construction and legacy modifications, has resulted in multiple single point and conditionally critical equipment vulnerabilities.

f. Level of Detail. The inspectors determined the causal analyses, in the aggregate, were performed commensurate with the safety significance and complexity of the performance issue and were of sufficient detail to identify the root and contributing causes, EOCo, and EOCa. The causal analysis teams utilized a formal cause analysis process to identify the problems and determine CAs. The causal analyses were performed by individuals in the licensees organization with varying levels of experience and backgrounds. The team identified multiple examples where the causal evaluations were not documented at a level of detail that was adequate to be understood and verified to preclude repetition by a knowledgeable reader. See General Weakness 3 above.

g. Operating Experience. The inspectors determined that the licensee appropriately considered prior occurrences and OPEX.

Event 1: The CAPE determined there was no significant OPEX applicable to this event.

Event 2: The RCA performed an OPEX search to identify other potentially related events using keywords such as ground fault sensor, ground fault relay, spurious signal, spurious trip, ground grid, ground potential, ground potential rise, and protective relay shield. None of the identified OPEX would have prevented the November 16, 2023, automatic reactor trip.

Event 3: The RCA performed an OPEX search to identify other potentially related events using keywords such as pipe strain, pipe strain and alignment, strain on pump and nozzle, coupling strain, pump strain, pipe stress and pump alignment. Five of the OPEX reviewed were found to be applicable. None of the reviewed OPEX would have prevented the February 2024, Unit 2, manual reactor trip.

Event 4: The RCA performed an OPEX search to determine if other industry events could have been leveraged to prevent this event. Of the OPEX reviewed, one could have potentially prevented the trip that occurred at Calvert Cliffs. The stations failure to review the directly related 2006 OPEX from Beaver Valley was determined to be a

18 contributing cause of the July 2024, Unit 2, reactor trip. A self-revealed Green finding for this missed OPEX is documented in the Results section of this report.

Event 5: The RCA performed an OPEX search and included an evaluation of why the repeat failure mode from Event 4 occurred. In addition to the July 2024, Unit 2, reactor trip and the OPEX identified in the Event 4 RCA, two similar failures and reactor trips occurred at Sequoyah, Unit 1, in August 2024 and September 2024.

Conversations between CCNPP and Sequoyah ensured recommendations and learnings were leveraged for affected components.

Common RCA: The RCA documented OPEX relevant to the five events and their causes and determined the five trips collectively were not OPEX preventable.

Lessons learned and CAs from relevant OPEX were used to develop CAs. The OPEX review revealed that the issues and causes driving these events are known issues at the station. The actions credited in the RCA were focused not just on improving performance, but included proactive actions that will sustain improved performance and avoid cyclical results.

h. Extent of Condition and Cause. The causal analyses performed EOCo and EOCa reviews as required by PI-AA-125-1003, Corrective Action Program Evaluation Manual, and PI-AA-125-1001, Root Cause Manual, in accordance with PI-AA-1006, Attachment 19, Extent of Condition/Extent of Cause. See Section 2 for discussion of EOCo and EOCa reviews.

The inspectors reviewed the safety culture components referenced in NUREG-2165, Safety Culture Common Language, to determine whether these were appropriately considered during the licensees evaluations of the root causes, EOCo, and EOCa. The Common RCA included a review in accordance with PI-AA-125-1006, Attachment 17, Safety Culture Assessment, and identified the following safety culture components that applied to the common root causes to ensure CAs resolve the identified gaps:

H.6 - Design Margins H.7 - Documentation H.8 - Procedure Adherence H.10 - Bases for Decisions H.11 - Challenge the Unknown H.12 - Avoid Complacency H.13 - Consistent Process H.14 - Conservative Bias P.1 - Identification P.2 - Evaluation P.3 - Resolution P.5 - Operating Experience X.10 - Expectations X.11 - Challenge Assumptions

i.

Common Cause. To identify commonalities that led to or contributed to the five scrams, the Common RCA performed a review of the five individual event causal products collectively in accordance with PI-AA-125-1006, Attachment 15, Analysis of Common

19 Issues, to identify issues or causes common to more than one of the events. The Common RCA subsequently identified two common root causes and one common contributing cause. The inspectors determined this was reasonable and consistent with the licensees corrective action program guidance.

2. Objective: Ensure that the extent-of-condition and extent-of-cause of individual and collective white performance issues are identified.

Under this objective, the inspectors independently assessed the causal analyses conducted by the licensee for the five individual inputs into the White PI for Unplanned Scrams per 7000 Critical Hours and the common analysis for the overall PI having exceeded the Green to White threshold, to assess the licensee's EOCo and EOCa.

NRC Assessment: The team concluded that this objective was met. The teams independent assessment was conducted through review of causal product documentation, verification of corrective action program assignments, interviews with knowledgeable plant personnel, review of WO records, equipment design and drawing review, data retrieval and review, and walkdowns of equipment in the field. The inspectors review determined the licensees evaluations of EOCo and EOCa sufficiently addressed the key attributes of the cornerstone associated with the significant performance issue and appropriately considered whether other systems, equipment, programs, or conditions could be affected.

Extent of Condition and Cause. The inspectors determined that the licensee appropriately identified the EOCo and EOCa.

Event 1:

o The CAPE determined the EOCo for potentially similar wiring installation deficiencies included voltage regulator CT wiring that was installed during the open phase detection modifications in 2016 and 2017 under Engineering Change Package (ECP)-14-000629 and ECP-15-000572. EOCo inspection and repair of the associated CT wiring for the U-4000-11/12/21 voltage regulators has been completed.

o EOCa is not required for a CAPE per PI-AA-125-1003, Corrective Program Evaluation Manual.

Event 2:

o The RCA determined the EOCo of similar installation deficiencies resulting in missing required shielding and insulation is limited to the components of the ground fault protective relay circuit of each of the six U-4000 unit service transformers installed at Calvert Cliffs. Vulnerability to EMI is only applicable to the GKC relay type which is only used in the U-4000 unit service transformers.

Insulated sensor cable installation is in progress, with five of the six unit service transformers completed.

o The EOCa scope was focused on identification, mitigation, and elimination of design and construction vulnerabilities of the ground fault circuits associated with the 13.8kV/4.16kV transformers utilizing the ABB GKC relay systems as well as resolution of potential sources of local EMI.

20 Event 3:

o The RCA EOCo reviewed the piping supports on suction, discharge, and minimum flow lines to evaluate whether piping strain has caused misalignment of any SGFP across both units with no deficiencies identified.

o The RCA EOCa review did not identify other repeat failures or catastrophic SGFP coupling failures. No other significant limiting conditions for operation were entered for Unit 2 due to outage activities on Unit 1. Challenges to Unit 1 outage work windows being extended have been captured in their own causal products.

Actions have been created to address less than adequate behaviors through training.

Event 4:

o The revised RCA EOCo reviewed the extent to which cyclic fatigue can affect other electrical connections on the Unit 2 Westinghouse exciter. The other Unit 2 exciter electrical connections were inspected satisfactory at the time of the July 2024 plant trip prior to returning to service. The connections also have existing support blocks installed as part of the design. The Unit 1 exciter is a different design. The EOCo review also evaluated the extent to which reduced margin material conditions may cause component failures in other key systems.

o The RCA EOCa initiated action to perform technical conscience training to ensure station personnel exhibited technical conscience and technical human performance behaviors and practices to potential issues that lead to any SPV component equipment challenge, and to ensure related OPEX is used sufficiently.

Event 5:

o The revised RCA EOCo reviewed the extent to which cyclic fatigue can affect other electrical connections on the Unit 2 Westinghouse exciter. The other Unit 2 exciter electrical connections were inspected and electrically tested satisfactory at the time of the July 2024 and October 2024 plant trips prior to returning to service. The EOCo review also evaluated the extent to which reduced margin material conditions may cause component failures in other key systems, and initiated action to ensure risk management and decision-making conclusions are documented as required. Actions also included direction to ensure the health reports of key systems reflect actual current state of equipment.

o The RCA EOCa performed a review of equipment and operator log entries of previous outage control center staff responses to determine if decisions and vendor information was appropriately challenged and evaluated in accordance with management model process governance.

Common RCA:

o The Common RCA EOCo reviewed NRC PI, inspection findings and CCNPP system health PIs for Units 1 and 2. The EOCo review also included a review of plant operation prior to the five events by reviewing Unit 1 and Unit 2 LERs since 2019 to identify any similar plant trips to Event 1 through Event 5.

o The Common RCA EOCa review identified CCNPP failed to eliminate generation risks for some known SPVs and conditionally critical equipment that have existed since the plant construction. As a result, these SPVs have caused several unplanned Unit 2 trips. Planned actions for CC1 are associated with changing behavior of station leadership, whose oversight extends to Unit 1. Additionally,

21 the EOCa review was extended from SPVs to Generation Risk Reduction (GRR) vulnerabilities (i.e., SPVs, OPCCW, and Equipment Related Consequential Events), as defined by ER-AA-2004-1001, Living Process for GRR Vulnerability Identification, Classification, Elimination and Mitigation. The cause was also extended to include Tier 1 and Tier 2 systems, as defined by ER-AA-2030, Conduct of Equipment Reliability Manual, which includes safety-related and mitigating system performance index systems.

o For CC2, the Common RCA EOCa review identified gaps in troubleshooting and operational decision-making behaviors that have resulted in failures to identify the lowest level of failure mechanisms and implement effective bridging and mitigation strategies for SPVs and conditionally critical equipment. Station personnel have not effectively executed these processes as written. This has led to repeat events and reactor trips. Actions to address CC2 EOCa included audits of all RCM, Life Cycle Management (LCM) and Health Reports for Tier 1 & 2 systems within the last five years for closure quality, a sample review of IRs in the last five years to ensure all failure mechanisms were identified and resolved for troubleshooting on Tier 1 and 2 systems and repeat OPCC issues, and a sample review of open and closed ODMs for closure quality in accordance with management model requirements.

o For CC3, the Common RCA EOCa review identified that several of the events occurred due to SPVs specific to CCNPPs original design or legacy modifications. This cause is validated by the lack of redundancy in the alternating current electrical distribution and feedwater systems. Some SPVs associated with these systems have not been prioritized for elimination. Although modifications have been made to improve system reliability and redundancy, these modifications have not thoroughly eliminated vulnerabilities. In some cases, modifications have introduced new or different types of vulnerabilities. The CC3 cause could exist where other plant modifications have introduced vulnerabilities and were not appropriately assessed for Tier 1 and 2 systems. An action was initiated to identify modifications, including temporary modifications, to Tier 1 and 2 systems performed over the past five years to determine the impact of the design change on system vulnerability.

3. Objective: Ensure that completed corrective actions to address and preclude repetition of white performance issues are timely and effective.

Under this objective, the inspectors assessed the appropriateness and timeliness of the licensee's CAs.

NRC Assessment: The team concluded that this objective was met. The inspectors determined that Constellation implemented appropriate and timely CAs to preclude repetition for performance issues that led to the White PI. Constellation also identified appropriate effectiveness reviews (EFRs) for these CAs. The inspection team identified the following weakness associated with the CA completed to address the Event 4 contributing cause:

General Weakness 4 - Other Completed Corrective Actions (Section 3.b):

During the teams review to determine whether the licensee implemented appropriate CAs for each contributing cause, the inspectors determined the closeout of a CA to address the

22 Event 4 contributing cause (4C3) was not performed in accordance with corrective action program requirements. The Event 4 contributing cause was insufficient use of directly related OPEX. Specifically, Beaver Valley had a similar event in 2006 which also led to a reactor trip. As part of the Event 4 RCA, assignment 4788102-44 was created to perform an OPEX evaluation for the 2006 Beaver Valley OPEX, as a CA to address the contributing cause. Step 4.5.2 of PI-AA-125, Corrective Action Program (CAP) Procedure, specifies use of the ATI Model Template for any CA necessary to restore a condition adverse to quality. The ATI Model Template requires additional review prior to the closure of CA assignments. The inspectors identified that the required OPEX review was completed in November 2024, but it did not receive the CA ATI Model Template closeout review.

This issue was captured in IR 04849980. Constellation reopened the assignment and completed the missed ATI Model Template, which resulted in the creation of a new assignment, CA assignment 4788102-93, to ensure additional CAs recommended in the Beaver Valley OPEX, not implemented following the OPEX review in November 2024, are put in place at Calvert Cliffs.

This general weakness was independently evaluated in accordance with the guidance in IMC 0612, Appendix B, Issue Screening, and Appendix E, Examples of Minor Issues.

The inspectors determined the issue was not of more than minor significance and therefore is not subject to enforcement action in accordance with the NRCs Enforcement Policy.

a. Completed Corrective Actions to Prevent Recurrence Event 1: No corrective action to preclude repetition (CAPR) was required for a Class B investigation (CAPE) per licensee procedure. The Common RCA added CAPR 04797040-88 and EFR 04828886-07 to ensure the sustainability and effectiveness of CAPE CA 04716036-34 (1C1). CAPR 04797040-88 and CA 04716036-34 have been completed. EFR 04828886-07 is planned to verify that 25 percent of applicable installed plant modifications meet the revised E-406, Engineering & Construction Standard, guidance.

Event 2 CAPR ESR-24-000018 / ECP ES199501242 (2C1): Determined appropriate replacement for modification to replace currently installed GKC relays and associated components with microprocessor-based relays for all U-4000 transformer protective relay schemes.

Event 3 CAPR 04752936-44/45 (3C2/3C3/3C4): Developed and implemented a case study for first line supervisors and above for this event in relation to troubleshooting, use of corrective action program, managing critical path, risk, stakeholder engagement in the modification process, and performance monitoring. Included review of existing governance for coping with risk when refueling outage activities affect the operating units and outage control center roles and responsibilities. Shared applicable learnings and governance from a nuclear professional standpoint with station personnel. Included decisions around discovery milestones and critical path decision making. EFR 4752936-57 to perform a review of documentation to identify clear documentation of risk and decision making post 2025 refueling outage for conditionally critical windows and reduced inventory is planned.

Event 4: No completed CAPRs.

23 Event 5: No completed CAPRs.

Common RCA: No completed CAPRs.

b. Other Completed Corrective Actions Event 1 Completed CAs:

o WO C93948248 (1C1): Repairs were made to the affected voltage regulator and inspections performed for the other Unit 2 voltage regulators.

o CA 04716036-34 (1C1): Updated E-406, Engineering & Construction Standard, to clarify the definition of insulated/non-conductive and add language to ensure minimum clearance distances are outlined.

o CA 04716036-37 (1C2): Reviewed all existing 4kV transformer voltage regulator PMs and ensured that they are screened for operational critical component (OPCC) work in accordance with MA-AA-716-101-1015, Operational Critical Component Work (OPCCW) Process. For any discrepancies identified, take or create additional actions to re-classify the work as OPCC.

o CA 04716036-38 (1C3): Updated the voltage regulator cleaning, inspection, and testing PMs to include acceptance criteria for distance between CT wiring and 13kV bus bar.

Event 2 Completed CAs:

o Immediate actions (2C1): Replaced all components within the ground fault protection circuit, performed electrical testing, performed additional monitoring.

Installed new style cable in U-4000-23 and sleeved U-4000-22 and U-4000-11 cables.

o Interim CA (2C1): Performed cable pulls supporting a permanent modification to fast bus transfer scheme to 4kV buses such that their power supplies automatically transfer from the primary power source to the alternate power source upon the loss of the in-service power source (WO C93963780, C93963781, C93963782, ECP-23-000416).

o ECP-23-000416 (2C2): Raised Unit 1 ground fault relay setpoint to improve margin.

Event 3 Immediate actions (3C1): Repair of piping support on discharge line of 22 SGFP (C93966544), realignment of pump to turbine (C93966545), replacement of broken coupling (C93966545), and reinforcement of broken weld areas on support H10 for 22 SGFP discharge piping and pinned pipe stanchions/stops (C93966620).

Event 4 Completed CAs:

o Immediate actions (4C1): Repaired and returned Unit 2 exciter to service, including a low pressure turbine bearing balance shot (C93985169).

o CA 04788102-39 (4C2): Implemented a PM strategy for both Unit 2 and Unit 1 exciter and main generator that fully aligns to the Engage Health PM Template including a formal and documented assessment for completeness against Westinghouse (Unit 2) and GE (Unit 1) Best Practices and Electric Power Research Institute documents.

o CA 04788102-44 (4C3). Performed an OPEX Evaluation for OE 22478 - 2006 Beaver Valley Exciter failure to plant trip.

24 The team identified a required review was not performed for this completed CA.

See General Weakness 4, above.

Event 5 Completed CAs:

o Immediate actions (5C1): Repaired and returned Unit 2 exciter to service, including the installation of a pole jumper with reinforced tabs to mitigate the potential for cyclic fatigue failure, and installation of a blocking modification to exciter support pole tabs as recommended in Beaver Valley OPEX. Performed exciter outboard bearing balance shot and torquing of base plate and seat plate bolts. (C93995234, C93995635, C93995353, ECP-24-000242, and ECP 000343) o WO C93995636 (5C1): Performed exciter seat plate shimming during the 2025 refueling outage.

o CAL-2-2024-0280 (5C2): Performed ODM/RCM to capture bridging, mitigating, monitoring and elimination strategies associated with Unit 2 generator exciter.

Implemented ACM that established a monitoring plan which will provide leading indicators of potential failure which will allow monitoring and if necessary, remove the machine from service prior to failure resulting in trip.

Common RCA: No completed CAs.

4. Objective: Ensure that planned corrective actions to preclude repetition direct timely and effective actions to address and preclude repetition of significant individual and collective performance issues.

Under this objective, the inspectors assessed the appropriateness and timeliness of the licensee's planned CAs.

NRC Assessment: The team concluded that this objective was met. The inspectors concluded the dates for implementation and completion of the planned CAs were reasonable, effective, and prioritized with consideration for risk significance and regulatory compliance. The inspectors also concluded that the licensee established reasonable measures of success to evaluate the effectiveness of the CAs. When complete, the NRC plans to inspect and assess the planned CAPRs identified in Section a of this objective.

a. Planned Corrective Actions to Prevent Recurrence Event 1: No planned CAPRs.

Event 2 CAPR 04718086-29 (2C1): Implement a modification (ECP-24-000291) to replace currently installed GKC relays and associated ground sensor circuit components with microprocessor-based relays and necessary circuit components (e.g., ground sensor, interfacing cabling appropriate for circuit) providing harmonic filtering capabilities, robust resistance to EMI capacity, and provides data monitoring and retrieval for electrical quantities for all U-4000 transformers protective relay schemes. Unit 2 WOs are complete. Unit 1 WOs are planned and scheduled (C94019525, C94019526, C94019527, C94019528). EFR 04718086-40 is planned to ensure a review of event logs of microprocessor-based relays post installation identifies no invalid ground fault signals.

25 Event 3 CAPR 04752936-47 (3C2): To address latent pipe strain, a hard reset strategy has been developed for 22 SGFP to assuage existing pipe strain and establish a baseline for the equipment.

o Restore piping support configuration to original design, check as-found pump to turbine alignment.

o Cut pump casing nozzles from suction and discharge piping and reconnect to eliminate pipe strain.

o Check and adjust pump casing pedestal for squareness.

o Dowel casing inboard side feet to pedestal (WO C93976198).

EFR 4752936-55 is planned to check alignment in 2027 refueling outage to ensure as-found alignment is within normal tolerances. EFR 4752936-56 is planned to validate no drift from as-left to as-found alignment data for the 2029 overhaul of 22 SGFP.

Event 4 CAPRs:

o CAPR 04788102-35 (4C2): Implement recurring Basis Captured training that, when combined with management model oversight, reinforces excellence in technical conscience principles and technical human performance behaviors for station personnel - Engineering (Strategic, Design, Component Monitoring etc.)

including first line supervisors and above. EFR 04788102-76 is planned with the following success criteria:

Minimum of 100% training attendance rate of each of the three populations.

Zero Externally Identified IRs related to System Ownership, Maintenance Strategy, Margin Management and Technical Conscience Principles.

Review of training per TQ-AA-225-F010, Performance Evaluation After Training, and TQ-AA-225-F020, Training Effectiveness Evaluation Worksheet, for any gaps.

o CAPR 04788102-36 (4C2): Engineering Leaders perform a minimum quantity of two documented technical conscience observations per week for a period of six months across the Engineering first line supervisor and above population.

Observations are to include both positive performance and specific areas for improvement for technical conscience and technical human performance. EFR 04788102-77 is planned to verify the quantity and quality of observations.

Event 5 CAPR 04797040-49 (5C2/5C3/CC2): Improve station utilization of Troubleshooting and Operational Decision-Making processes, consistent with MA-AA-716-004 and OP-AA-106-101-1006, such that all potential failure mechanisms are identified, evaluated, and dispositioned. This behavior change will be accomplished by completing the following actions:

o CCNPP leadership to reset and enforce troubleshooting expectations consistent with MA-AA-716-004, Conduct of Troubleshooting, and OP-AA-106-101-1006, Operational Decision Making Process. (CAs 04797040-50, 04797040-51, 04797040-52) o Implement enhancements to troubleshooting and corrective action program procedures to ensure all failure mechanisms are identified and dispositioned by clearly defining roles and responsibilities, consistently defining terms, and clearly stating troubleshooting closure and documentation requirements. (04797040-46, 04797040-53, 04797040-54, 04797040-84, 04828886-08) o Develop and present a series of focused training activities for leadership and individual contributors on the Troubleshooting and Operational Decision-Making

26 processes. Reinforce training on a recurring basis. (04797040-55, 04797040-56, 04797040-57, CA 04797040-58, 04797040-59, CA 04797040-60, 04797040-61, CA 04797040-62, 04828886-03) o Monitor behaviors through performance improvement tools (observations, metrics, performance improvement action plans) to detect adverse behaviors and reinforce positive behaviors associated with the Troubleshooting and Operational Decision Making processes. (04828886-09, 04797040-63, 04797040-64, 04828886-05, 04797040-65 through 77, 04828886-14, 04797040-86) o EFRs 04828886-14, 04797040-86 are planned to perform quality reviews of plant performance and focused and complex troubleshooting investigations using CC-AA-202-1001, Quality Review Team (QRT), and effectiveness evaluation of behavior metrics and training.

Common RCA CAPR 04797040-18 (CC1): Improve station utilization of Nuclear Risk Management and Equipment Reliability processes, consistent with AD-AA-3000 and ER-AA-2004, to monitor, evaluate, and prioritize elimination and/or mitigation of SPV and conditionally critical components. This includes ensuring vulnerabilities are addressed with an elimination over mitigation bias. This behavior change will be accomplished by completing the following actions:

o CCNPP leadership to reset and enforce SPV and conditionally critical equipment risk evaluation, elimination, and mitigation expectations consistent with AD-AA-3000, Nuclear Risk Management Process, ER-AA-2030, Conduct of Equipment Reliability Manual, ER-AA-2001, Plant Health Committee, ER-AA-2004, System & Component Vulnerability Identification and Mitigation, and ER-AA-2004-1001, Living Process for GRR Vulnerability Identification, Elimination, and Mitigation (CAs 04797040-19, 04797040-20, 04797040-21, 04797040-45).

o Develop and present a series of focused training activities for leadership and individual contributors on the Nuclear Risk Management, Equipment Reliability, and Plant Health Committee processes. Reinforce training on a recurring basis (04797040-22, 04797040-23, 04797040-24, CA 04797040-25, 04797040-26, CA 04797040-27, 04797040-28, CA 04797040-29, 04828886-02).

o Benchmark other stations to identify high-quality behaviors with respect to effectiveness in the utilization of the Nuclear Risk Management and Equipment Reliability processes. Update focused training activities using best practices identified by the benchmarks (04797040-96, 04797040-97, CA 04797040-98).

o Monitor behaviors through performance improvement tools (observations, metrics, performance improvement action plans) to detect adverse behaviors and reinforce positive behaviors associated with the Nuclear Risk Management, Equipment Reliability, and Plant Health Committee processes (04828886-10, 04797040-30, 04797040-31, 04828886-04, 04797040-32 through 44, 04828886-13, 04797040-85).

o EFRs 04828886-13 and 04797040-85 are planned to review plant performance and perform quality reviews of RCM issues using CC-AA-202-1001, Quality Review Team (QRT), and effectiveness evaluation of behavior metrics and training.

b. Other Planned Corrective Actions Event 1: No planned CAs.

27 Event 2 Planned CAs:

o CA 4718086-54 (2C2): Perform inspection of cabling exiting breaker 1BKR252-1106 for similar issues experienced with 2BKR252-2106 regarding corona damage and cable shield not passing through ground sensor CT aperture (WO C93961358).

o CA 4718086-55 (2C2): Correct the cable installation at 1BKR252-1106 and 2BKR252-2106 to reduce the likelihood of corona from occurring (WO C93949454).

Event 3 Planned SPC 4752936-43 (3C3): A special plant condition assignment is planned to confirm source(s) of force being applied to 22 SGFP:

o Perform operating deflection shape data collection to approximate natural frequencies present on 22 SGFP and primarily identify any mechanical issues present such as soft foot, misalignment, imbalance, foundation degradation (C93967458).

o Document results of operating deflection shape model. Provide gathered data to vendors to run additional models and determine actions required based on current system operation (609093-265).

Event 4 Planned CAs:

o CA 04788102-38 (4C2): Rewind or replace the Unit 2 exciter.

o CA 04788102-45 (4C3): Perform a documented review of Siemens and Westinghouse Service Bulletins (2014-SB-14-0001-ST-EN-01). Initiate IR(s) for all gaps and open recommendations that have not been completed for formal dispositioning.

o CA 04788102-93 (4C3): Incorporate Beaver Valley OPEX CAs (PMC 156373):

The existing main exciter PM task is being revised to ensure that the proper details exist on disassembly and reassembly of the exciter field pole connectors.

A generator/exciter PM template is being developed to include a mechanical inspection of the exciter which includes the exciter stator series lead connections and a verification of the presence of all the stator field lead support blocks.

Event 5 CA 04808192-47 (5C3): Modify MA-AA-716-004, Conduct of Troubleshooting, to include clear guidance post scram for monitoring and mitigation.

Common RCA Planned CA 04797040-82 (CC3): Implement planned actions for vulnerability elimination and mitigation created per approved scope and schedule documented in 04797040-81. 04787040-81 will perform a documented review of site vulnerabilities including a review of primary, secondary, and electrical system design vulnerabilities and actions to address these events. The focus of the review will be on developing a scope for eliminating long-standing vulnerabilities, with a focus on SPV elimination and improving margins at CCNPP.

While this CA is still in progress, and plans for its full scope are in development, the team noted a number of modifications have been completed at the station to address site vulnerabilities including:

28 o ECP-23-000416: Unit 1, 4kV Balance of Plant (BOP) Bus Fast Transfer Modification. This modification installed a sequential fast bus transfer that was enabled on 4kV buses 13, 15 and 16. [Event 1/2]

o ECP-24-000294: Unit 2, Supervised 4kV BOP Fast Transfer. This modification improved upon the Unit 1 project (ECP-23-000416) by providing digital supervised fast transfer. With this technology, BOP 4kV bus sections (22, 23, 25, and 26) were enabled. [Event 1/2]

o ECP-25-000011 and ECP-24-000057: These document change packages evaluated capability for operating the 13 and 23 standby feedwater pumps with a safety 4kV bus on the same unit transformer winding and concluded that a short duration in this condition can be permitted. They allow the pump to remain in standby and eliminate conditionally critical risk windows, such as during a refueling outage on the other unit. [Event 3]

o LCM CAL-24-0005 - Relieved discharge and mini-flow pipe stress for 22 SGFP to eliminate excess nozzle loading thus preventing the driving force to casing misalignment or torsion. [Event 3]

o Implemented control room plant process computer alarm change to alert operators of a temperature differential change to the SGFP thrust bearings to ensure personnel are aware of degrading condition that can lead to a SGFP trip and act in response. Response actions were first implemented via adverse condition monitoring plan. [Event 3]

5. Conclusion (1 Sample)

During a supplemental inspection, inspectors will generally verify licensee performance of issue identification, evaluation, and corrective plans and activities, sufficiently challenging aspects and assessing the adequacy of licensee performance in each of these areas to ensure that the greater-than-green performance issue and its causes have been properly identified, and that corrective plans and actions are in place to promptly and effectively address and preclude repetition. Based on a review of the initial root cause analyses, the inspectors performed an independent evaluation for Events 4 and 5 to evaluate the inspection requirements for: (1) when and how long the performance issue existed and prior opportunities for identification, (2) use of a systematic methodology to identify the root and contributing causes, (3) conducting an evaluation to a level of detail commensurate with the significance and complexity of the White PI, and (4) determining whether the licensee has identified or implemented appropriate CAs for each contributing cause. As a result, Constellation revised the Event 4 and Event 5 root cause analyses to, in part, correct the Equipment Evaluation investigation techniques and include additional supporting information regarding the EOCo and EOCa reviews.

The inspectors determined that the licensees problem identification, causal analyses, and CAs sufficiently addressed the performance issues that led to the White PI. The inspectors also determined that the final root cause analyses produced CA plans which appear to effectively address and preclude repetition of significant performance issues. Constellation was able to resolve the challenges raised by the inspectors prior to the conclusion of the inspection, and the inspectors determined that the final root cause analysis revisions contained sufficient information such that Constellation met the objectives of the IP.

Scheduled CAPRs will be inspected as part of the ongoing NRC baseline inspection program. Therefore, this inspection, and associated parallel White finding, are closed.

29 INSPECTION RESULTS Failure to Properly Classify Operating Experience Event Contributes to Reactor Trip Cornerstone Significance Cross-Cutting Aspect Report Section Initiating Events Green FIN 05000318/2025040-01 Open/Closed None (NPP) 71153 A self-revealed finding (FIN) of very low safety significance, Green, was identified when Constellation failed to properly screen incoming operating experience (OPEX) as required by NS-1-100, "Use of Operating Experience." Specifically, a 2006 Beaver Valley OPEX report applicable to Calvert Cliffs, Unit 2, was improperly designated as Priority 3, when it should have been classified as Priority 1. As a result, barriers were not put in place to prevent the occurrence of a similar event at CCNPP which contributed to a Unit 2 reactor trip on July 18, 2024.

==

Description:==

On July 18, 2024, Calvert Cliffs, Unit 2, automatically tripped due to a main turbine loss of load trip initiated by the reactor protection system. The main turbine loss of load trip was the result of main generator exciter loss of field due to a failed stationary field pole electrical connection. The stationary field pole electrical connection failed from cyclic fatigue due to vibration.

Constellation performed an RCA (IR 4788102) and determined that a contributing cause of the event was insufficient use of directly related OPEX. Specifically, Beaver Valley, Unit 2, experienced a similar event in 2006. The OPEX document described a failure of the connection on the stationary pole terminal of the exciter as a result of increased flexing during normal operation and maintenance activities with the absence of adequate support blocking.

This OPEX is relevant as Calvert Cliffs, Unit 2, has the same exciter design installed.

Calvert Cliffs reviewed and evaluated the Beaver Valley OPEX using procedure NS-1-100, Use of Operating Experience, Revision 8. NS-1-100 required an initial screening of incoming OPEX to determine the priority of the item and to establish whether a barrier analysis should be performed. Priority 1 items required the applicable line organization to perform a barrier analysis, while Priority 3 items were distributed as informational items. A barrier analysis reviewed an incoming OPEX item and evaluated CCNPP procedures, policies, practices, etc., to ensure that adequate defenses exist to avoid occurrence of the event. The barrier analysis process would identify physical, administrative, procedure controls, and other barriers that should prevent an event from occurring.

Initial screening of the incoming Beaver Valley OPEX, based on the definitions in NS-1-100 should have classified it as Priority 1, Event that could directly affect nuclear safety, personnel safety, or plant reliability or availability. Specifically, the OPEX documented the event as noteworthy since a reactor trip from 100 percent power resulted. However, the event was improperly classified as Priority 3, Events that do not appear to pose an adverse effect on nuclear or personnel safety or on plant reliability or availability but shall be reviewed as informational. As a result, no barrier analysis was performed.

The failure to properly classify the OPEX report and perform a barrier analysis for the Beaver Valley event precluded the stations ability to ensure that adequate barriers existed to prevent occurrence of the event at CCNPP and contributed to the Unit 2 trip in July 2024. The OPEX recommended a number of CAs, including installation of a support block, ensuring PM

30 revisions to ensure the proper details exist on disassembly and reassembly of the exciter field pole connectors, and development of a PM task to perform a mechanical inspection of the excited which included the exciter stator series lead connection and verification of the presence of all the stator field lead support blocks.

Corrective Actions: Corrective actions included the repair of the exciter, completion of the required OPEX review, and subsequent performance of a modification to install a support block in accordance with WO C93995234 and ECP-24-000343.

Corrective Action References: IR 04788102 Performance Assessment:

Performance Deficiency: Constellation failed to properly screen incoming OPEX as required by NS-1-100, "Use of Operating Experience." Specifically, a 2006 Beaver Valley OPEX report applicable to Calvert Cliffs, Unit 2, was improperly designated as Priority 3, when it should have been classified as Priority 1.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, failure to properly screen the Beaver Valley OPEX resulted in adequate barriers not being implemented to prevent the occurrence of the event at CCNPP, which contributed to a Unit 2 reactor trip on July 18, 2024.

Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. In accordance with IMC 0609, Appendix A, Exhibit 1, Section B, "Transient Initiators," the finding screened to Green because it did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition.

Cross-Cutting Aspect: Not Present Performance. No cross-cutting aspect was assigned to this finding because the inspectors determined the performance deficiency was not reflective of present performance. The performance issue occurred more than three years ago and was corrected/eliminated when the licensee replaced procedure NS-1-100, with PI-AA-115-1003, Processing of Level 3 OPEX Evaluations.

Enforcement: The inspectors did not identify a violation of regulatory requirements associated with this finding.

The disposition of this finding closes LERs 05000318/2024-002-00, 01, Automatic Reactor Trip Due to Main Turbine Loss of Load, (ML24260A142 and ML25024A089).

31 EXIT MEETINGS AND DEBRIEFS The inspectors verified no proprietary information was retained or documented in this report.

On April 18, 2025, the inspectors presented the 95001 supplemental inspection results to Christopher Smith, Plant Manager, and other members of the licensee staff. Immediately following the exit meeting, Nicole Warnek, Chief, Projects Branch 3, conducted the regulatory performance meeting with Christopher Smith, Plant Manager, and other members of the licensee staff.

32 DOCUMENTS REVIEWED Inspection Procedure Type Designation Description or Title Revision or Date 71153 Engineering Changes ECP-23-000416 Balance of Plant (BOP) 4kV Fast Bus Transfer Modification Revision 1 ECP-24-000291 13kV Service Bus 21 Protection Digital Upgrade Revision 0 ECP-24-000343 Install blocking due to jumper damage in U2 Main Generator Exciter Revision 0 Procedures NS-1-100 Use of Operating Experience Revision 8 PI-AA-115-1003 Processing of Level 3 OPEX Evaluations Revision 7 95001 Corrective Action Documents 04716036 U2 Automatic Reactor Trip Due to U-4000-22 De-energized 12/15/2023 04718086 U2 Automatic Reactor Trip Due to U-4000-22 De-Energized 11/16/2023 04752936 U2 Manual Reactor Trip - 22 Steam Generator Feed Pump 04/24/2024 04788102/04788487 U2 Reactor Trip/U1 AOP-7K Entry 10/15/2024 04788102/04788487 U2 Reactor Trip/U1 AOP-7K Entry 04/09/2025 04797040 Exceeded Threshold for Unplanned Scrams NRC PI - Unit 2

08/27/2024 04808192 U2 RX Trip 10/10/2024 Corrective Action Documents Resulting from Inspection 04853013 OP-AA-108-108 documents from July 2024 04853210 Equipment Evaluation for IR 04788102 requires revision 04853978 Equipment Evaluation for IR 04808192 requires revision 04855550 NRC 95001: Editorial Changes for Root Causes Procedures ER-AA-2004-1001 Living Process for GRR Vulnerability Identification, Classification, Elimination and Mitigation Revision 2 LS-AA-1003 NRC Inspection Preparation and Response Revision 27 LS-AA-106 Plant Operations Review Committee Revision 16 OP-AA-108-108 Unit Restart Review Revision 23 OP-AA-108-114 Post Transient Review Revision 15 PI-AA-120 Issue Identification and Screening Process Revision 13 PI-AA-125 Corrective Action Program Revision 9 PI-AA-125-1001 Root Cause Analysis Manual Revision 8 PI-AA-125-1003 Corrective Action Program Evaluation Manual Revision 8 PI-AA-125-1004 Effectiveness Review Manual Revision 3

33 Inspection Procedure Type Designation Description or Title Revision or Date PI-AA-125-1006 Investigation Techniques Manual Revision 8 PI-AA-126-1001 Self Assessments Revision 7 Self-Assessments 04797040 Readiness Assessment - Supplemental Inspection for NRC White Finding - CCNPP Unit 2 NRC IE01 Performance Indicator (PI), Unplanned Scrams per 7000 Critical Hours, entered the NRC Increased Regulatory Response Band as defined in LS-AA-2010 for 3Q24 following the Unit 2 July 18, 2024 Scram 01/08/2025