IR 05000373/2025004
| ML26044A121 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 02/13/2026 |
| From: | Robert Ruiz NRC/RGN-III/DORS/RPB1 |
| To: | Murdick C Constellation Energy Generation, Constellation Nuclear |
| References | |
| IR 2025004 | |
| Download: ML26044A121 (0) | |
Text
SUBJECT:
LASALLE COUNTY STATION - INTEGRATED INSPECTION REPORT 05000373/2025004 AND 05000374/2025004
Dear Christopher H. Mudrick:
On December 31, 2025, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at LaSalle County Station. On January 14, 2026, the NRC inspectors discussed the results of this inspection with John VanFleet, Site Vice President, and other members of your staff. The results of this inspection are documented in the enclosed report.
One finding of very low safety significance (Green) is documented in this report. This finding involved a violation of NRC requirements. We are treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.
If you contest the violation or the significance or severity of the violation documented in this inspection report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement; and the NRC Resident Inspector at LaSalle County Station.
February 13, 2026 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, Robert Ruiz, Chief Reactor Projects Branch 1 Division of Operating Reactor Safety Docket Nos. 05000373 and 05000374 License Nos. NPF-11 and NPF-18 Enclosure:
As stated cc: Distribution via GovDelivery Signed by Ruiz, Robert on 02/13/26
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated inspection at LaSalle County Station, 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
Failure to Classify Unit Common Emergency Diesel Generator Breaker Control Power Relays as Critical Equipment Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green NCV 05000373,05000374/2025004-01 Open/Closed None (NPP)71152A The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation (NCV) of Technical Specifications (TS) 5.4.1.a for the licensees failure to follow procedures when classifying the Unit Common emergency diesel generator (EDG)
Unit 1 and Unit 2 output breaker control power relays (1-DG052CX1 and 2-DG052CX1), respectively, as critical equipment. This issue was identified by the inspectors following the September 1, 2025, Unit Common EDG failure to load onto the Unit 1 safety bus during a routine surveillance. Specifically, these relays should have been classified as critical components rather than non-critical components.
Additional Tracking Items
None.
PLANT STATUS
Unit 1 began the inspection period at rated thermal power. On October 18, 2025, Unit 1 down powered to approximately 73 percent to perform control rod drive hydraulic accumulator valve maintenance. The unit returned to full power on October 19, 2025. On November 2, 2025, the unit was automatically tripped following the fast closure of the main turbine control valves after the main generator automatically locked out. The unit was started up on November 3, 2025, and reached full power on November 7, 2025, following repairs. On December 3, 2025, the B train reactor recirculation pump tripped which resulted in a down power to approximately 35 percent.
The unit was restored to full achievable power in coastdown at approximately 98 percent power on December 6, 2025, following repairs. On December 28, 2025, operators inserted a Unit 1 manual scram due to rising drywell pressure and reactor coolant system leakage. The unit was started up on December 30, 2025, following repairs. The unit reached full power in coastdown on January 1, 2026, at approximately 91 percent power.
Unit 2 began the inspection period at rated thermal power. On November 16, 2025, the licensee reduced power to approximately 16 percent power and took the main turbine off line due to the degrading main power transformer. The unit was shut down on November 18, 2025. The unit started up on November 29, 2025, and reached full power on December 1, 2025, following repairs. The unit operated at or near rated thermal power for the remainder of the inspection period.
INSPECTION SCOPES
Inspections were conducted using the appropriate portions of the inspection procedures (IPs) 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 performed activities described in IMC 2515, Appendix D, Plant Status, observed risk significant activities, and completed on-site portions of IPs. 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.
REACTOR SAFETY
71111.04 - Equipment Alignment
Partial Walkdown Sample (IP Section 03.01) (1 Sample)
The inspectors evaluated system configurations during partial walkdowns of the following systems/trains:
- (1) Unit 1 reactor building closed cooling water system from November 24-25, 2025
71111.07A - Heat Exchanger/Sink Performance
Annual Review (IP Section 03.01) (1 Sample)
The inspectors evaluated readiness and performance of:
- (1) Unit 1A diesel generator heat exchanger
71111.11A - Licensed Operator Requalification Program and Licensed Operator Performance
Requalification Examination Results (IP Section 03.03) (1 Sample)
- (1) An inspector reviewed and evaluated the licensed operator examination failure rates for the requalification annual operating exam administered from October 16 to December 4, 2025.
Fifty-three operators were examined. This is short of the 63 in RPS Operator Licensing (OL) Report 9. One operator is on extended leave, and the licensee has a plan to complete the examination prior to resuming licensed operator duties. Two operators did not take the exam and are currently in license class for upgrade. This is permissible per NUREG-1021. The remaining are recently licensed as part of the exam administered September 2025. No concerns with the number of personnel examined. Additional action is not warranted per Inspection Procedure (IP) 71111.11A.
Two operators failed the written examination. The licensee developed a remediation plan and administered a re-examination, which both individuals passed. No concerns related to exam failures and remediation. Additional action is not warranted per IP 71111.11A.
TABLE 03.03-1 EXAMINATION RESULTS
1. Total number of licensed operators: 63
2. Number of licensed operators administered a requalification examination
required by 10 CFR 55.59(a): 53
3. Number of individual licensed operators who failed any portion of a
requalification examination (written, JPM or individual simulator scenario failures): 2
4. Divide line 3 by line 2 to obtain the individual requalification examination
failure rate. Line 3/Line 2: 3.8%
5. Number of crews administered simulator scenarios as part of a requalification
examination required by 10 CFR 55.59(a): 11
6. Number of crews who performed unsatisfactorily on the simulator scenarios: 0
7. Divide line 6 by line 5 to obtain the crew simulator scenario failure rate.
Line 6/Line 5: 0%
The failure rates are below thresholds which require additional actions per IP 71111.11A.
The licensee and NRC staff discussed future dates for licensed operator requalification examinations.
71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance
Licensed Operator Performance in the Actual Plant/Main Control Room (IP Section 03.01) (2 Samples)
- (1) The inspectors observed and evaluated licensed operator performance in the control room during a Unit 1 planned power maneuvering to approximately 73 percent to support corrective maintenance on October 18, 2025.
- (2) The inspectors observed and evaluated licensed operator performance in the control room during Unit 2 main generator sync and power ascension on November 30, 2025.
Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)
- (1) The inspectors observed and evaluated an annual dynamic exam on October 15, 2025.
71111.12 - Maintenance Effectiveness
Maintenance Effectiveness (IP Section 03.01) (1 Sample)
The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components (SSCs) remain capable of performing their intended function:
(1)control rod hydraulic control unit air valve diaphragms; Action Requests (ARs)49000961, 4901137, 4901752, and 4903269; Work Orders (WOs) 5726717,
5728577, and 1599100 Quality Control (IP Section 03.02) (1 Sample)
The inspectors evaluated the effectiveness of maintenance and quality control activities to ensure the following SSC remains capable of performing its intended function:
- (1) Unit Common B train diesel driven fire pump replacement structural supports Aging Management (IP Section 03.03)
The inspectors evaluated the effectiveness of the aging management program for the Unit Common EDG cooling water strainer 0DG01F inspection performed under WO 5265940 associated with License Renewal Commitment 1603204-46-19.
71111.15 - Operability Determinations and Functionality Assessments
Operability Determination or Functionality Assessment (IP Section 03.01) (4 Samples)
The inspectors evaluated the licensees justifications and actions associated with the following operability determinations and functionality assessments:
- (1) AR 4902259, Common Emergency Diesel Starting Air Check Valve Leakage
- (2) AR 4898521, Unit 1 B Diesel Generator Inboard Bearing Degradation
- (3) AR 4905498, Part 21 - Positive Battery Post Separation
- (4) AR 4909379, Unit 1 A Emergency Diesel Generator High Water Temperature Shutdown As-Found Temperature Setpoint Out of Specification
71111.18 - Plant Modifications
Temporary Modifications and/or Permanent Modifications (IP Section 03.01 and/or 03.02) (1 Sample)
The inspectors evaluated the following temporary or permanent modifications:
- (1) Engineering Change (EC) 646462, Defeat Reactor Recirculation Pump Trip Interlock, Revision 000
71111.20 - Refueling and Other Outage Activities
Refueling/Other Outage Sample (IP Section 03.01) (2 Samples)
- (1) The inspectors evaluated Unit 2 forced outage, L2F47, activities from November 18-29, 2025.
- (2) The inspectors evaluated Unit 1 forced outage, L1F48, activities from December 28-30, 2025.
71111.24 - Testing and Maintenance of Equipment Important to Risk
The inspectors evaluated the following testing and maintenance activities to verify system operability and/or functionality:
Post-Maintenance Testing (PMT) (IP Section 03.01) (2 Samples)
- (1) Unit 2 low pressure core spray PMT after work window, WO 5420151
- (2) Unit 1A diesel generator PMT after work window, WO 5728330
Reactor Coolant System Leakage Detection Testing (IP Section 03.01) (1 Sample)
- (1) Unit 1 drywell unidentified leakage, November 24, 2025, through December 28, 2025
71114.04 - Emergency Action Level and Emergency Plan Changes
Inspection Review (IP Section 02.01-02.03) (1 Sample)
- (1) The inspectors evaluated the following submitted Emergency Action Level and Emergency Plan changes.
- EP-AA-1000, Standardized Radiological Emergency Plan, Revision 34 This evaluation does not constitute NRC approval.
RADIATION SAFETY
71124.08 - Radioactive Solid Waste Processing & Radioactive Material Handling,
Storage, & Transportation
Radioactive Material Storage (IP Section 03.01) (1 Sample)
The inspectors evaluated the licensees performance in controlling, labeling and securing the following radioactive materials:
(1)liquid radioactive material storage within Building 20
Radioactive Waste System Walkdown (IP Section 03.02) (1 Sample)
The inspectors walked down the following accessible portions of the solid radioactive waste systems and evaluated system configuration and functionality:
(1)advanced liquid processing system (ALPS)
Waste Characterization and Classification (IP Section 03.03) (2 Samples)
The inspectors evaluated the following characterization and classification of radioactive waste: (1)waste sludge
- (2) ALPS mixed bed
Shipping Records (IP Section 03.05) (3 Samples)
The inspectors evaluated the following non-excepted radioactive material shipments through a record review:
- (1) Shipment LM23-132; GE equipment; UN3321 Radioactive Material, low specific activity (LSA-II)
- (2) Shipment LM24-033; control rod drive boxes; UN3321 Radioactive Material, low specific activity (LSA-II)
- (3) Shipment LM25-001; reactor coolant system low level waste equipment; UN3321 Radioactive Material, low specific activity (LSA-II)
OTHER ACTIVITIES - BASELINE
71151 - Performance Indicator Verification The inspectors verified licensee performance indicators submittals listed below:
MS05: Safety System Functional Failures (SSFFs) Sample (IP Section 02.04) (2 Samples)
- (1) Unit 1 (October 1, 2024, through September 30, 2025)
- (2) Unit 2 (October 1, 2024, through September 30, 2025)
MS08: Heat Removal Systems (IP Section 02.07) (2 Samples)
- (1) Unit 1 (October 1, 2024, through September 30, 2025)
- (2) Unit 2 (October 1, 2024, through September 30, 2025)
MS10: Cooling Water Support Systems (IP Section 02.09) (2 Samples)
- (1) Unit 1 (October 1, 2024, through September 30, 2025)
- (2) Unit 2 (October 1, 2024, through September 30, 2025)
BI01: Reactor Coolant System (RCS) Specific Activity Sample (IP Section 02.10) (2 Samples)
- (1) Unit 1 (September 1, 2024, through August 31, 2025)
- (2) Unit 2 (September 1, 2024, through August 31, 2025)
OR01: Occupational Exposure Control Effectiveness Sample (IP Section 02.15) (1 Sample)
- (1) September 1, 2024, through August 31, 2025 PR01: Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual Radiological Effluent Occurrences (RETS/ODCM) Radiological Effluent Occurrences Sample (IP Section 02.16) (1 Sample)
- (1) September 1, 2024, through August 31, 2025 71152A - Annual Follow-up Problem Identification and Resolution
Annual Follow-up of Selected Issues (Section 03.03) (1 Sample)
- (1) Unit Common emergency diesel generator Unit 1 output breaker failure on September 1, 2025, root cause analysis and corrective actions
71152S - Semiannual Trend Problem Identification and Resolution Semiannual Trend Review (Section 03.02) (1 Sample)
- (1) The inspectors reviewed the licensees corrective action program to identify potential trends in operator performance that might be indicative of a more significant safety issue.
71153 - Follow-Up of Events and Notices of Enforcement Discretion
Personnel Performance (IP Section 03.03) (4 Samples)
- (1) The inspectors evaluated plant equipment and operator response to an automatic Unit 1 reactor scram during ground isolation troubleshooting activities on November 2, 2025.
- (2) The inspectors evaluated plant equipment and operator response to an unexpected Unit 1B train reactor recirculation pump trip on December 3, 2025.
- (3) The inspectors evaluated plant equipment and operator response due to increasing reactor coolant leakage inside of the containment resulting in a Unit 1 reactor manual scram on December 28, 2025.
- (4) The inspectors evaluated plant equipment and operator performance during a plant shutdown in response to a degraded Unit 2 2E main power transformer on November 16, 2025.
INSPECTION RESULTS
Failure to Classify Unit Common Emergency Diesel Generator Breaker Control Power Relays as Critical Equipment Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green NCV 05000373,05000374/2025004-01 Open/Closed None (NPP)71152A The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation (NCV) of Technical Specifications (TS) 5.4.1.a for the licensees failure to follow procedures when classifying the Unit Common emergency diesel generator (EDG)
Unit 1 and Unit 2 output breaker control power relays (1-DG052CX1 and 2-DG052CX1),respectively, as critical equipment. This issue was identified by the inspectors following the September 1, 2025, Unit Common EDG failure to load onto the Unit 1 safety bus during a routine surveillance. Specifically, these relays should have been classified as critical components rather than non-critical components.
Description:
On September 1, 2025, the Unit Common EDG Unit 1 output breaker failed to close during a routine surveillance test. However, the licensee was successful in closing the Unit Common EDG Unit 2 output breaker during the test. The licensee entered TS Limiting Condition for Operation (LCO) 3.8.1 required Action B.4 which was to restore the Unit Common EDG to Unit 1 within 14 days.
The licensees troubleshooting efforts identified that the most likely cause for the Unit 1 output breaker failure to close was the failure of safety-related Unit 1 breaker control power relay (1-DG052CX1) to close contacts #1 and #7 upon demand. The relay was replaced, tested, and Unit Common EDG restored to operable status. The licensee sent the relay offsite to perform a causal analysis which confirmed the relay was degraded. The failure analysis identified mechanical binding between the relays armature assembly and plastic housing. It was observed that the movable contacts did not line up well with the stationary contacts due to the armature assembly being tilted all the way to the left. As-found contact NC 4-8 resistance was measured at 114 mohms which was outside of the Constellation PowerLab typical acceptance criteria of less than 100 mohms. The relay plastic housing surface showed directional surface scratches that were likely caused by a movable contact rubbing against the plastic housing.
This failure mechanism was intermittent, and the failure analysis testing demonstrated one failure out of five sampled closure attempts. Based upon these results, the licensee determined that the September 1, 2025, failure resulted in both a preventable maintenance rule functional failure and a mitigating systems performance index (MSPI) monitored component failure.
The inspectors reviewed the maintenance history associated with the 1-DG52CX1 and 2-DG52CX1 relays. This review identified that these relays were likely original plant equipment based upon plant records. Additionally, the licensee did not have any records of performing preventative maintenance activities that could have prevented this in-service failure. The inspectors questioned the licensees run-to-maintenance strategy and identified that the licensee had failed to appropriately classify these safety-related relays in accordance with station Procedure ER-AA-200-1001, Equipment Classification. Specifically, since the relay failure would result in an MSPI-monitored component failure, the procedures required these relays to be classified as critical from which a preventative maintenance strategy would be developed. The inspectors reviewed the historic equipment classification for these relays. The 1-DG52CX1 and 2-DG52CX1 relays had been historically classified as critical components until they were reclassified as non-critical on May 11, 2017. The licensee did not document a reason for why these components no longer met the critical component classification. The licensees standard maintenance strategy for these components with a non-critical equipment classification required the licensee to perform a 2-year periodic functional check which was met by routine TS surveillances.
The licensee entered the issue into the corrective action program and performed a root cause analysis. The licensee identified that the September 1, 2025, Unit Common EDG failure to load onto Unit 1 was maintenance preventable based upon the control relay misclassification and not performing the required 4-year interval as-found testing and calibration. The licensee identified this as a missed opportunity to check through inspection of material conditions such as high resistance contacts, binding in the mechanism, mid-adjustment, and coil thermal performance as well as test coil resistance, contact continuity, and pickup voltage. The licensee determined that the failure to adhere to the relays critical PCM template delayed the identification of various types of relay contact degradation. The licensee developed a new maintenance strategy based upon the correct critical component classifications. Using the PCM template, the licensees new maintenance strategy consisted of performing additional as-found relay testing and calibration at a 4-year frequency. The licensee performed an extent-of-condition review for the other EDG output breakers. The other station EDGs unit output breaker relays were determined by the licensee to not be misclassified.
Corrective Actions:
The licensee replaced the failed 1-52CX1 relay associated with the Unit Common EDG Unit 1 breaker. Further, the licensee changed the equipment classification of Unit 1-52CX1 and Unit 2-52CX1 relays from non-critical to critical equipment, and a new preventative maintenance strategy was created.
Corrective Action References: AR 4894683
Performance Assessment:
Performance Deficiency:
The licensees failure to properly classify the safety-related Unit Common EDG control power relays for the Unit 1 output breaker (1-DG52CX1) and Unit 2 output breaker (2-DG52CX1) in accordance with station Procedure ER-AA-200-1001, Equipment Classification, Revision 3, was a performance deficiency. Specifically, these relays were required to be classified as a critical component (vice non-critical). Additionally, the licensee was required to develop a maintenance strategy for these critical components in accordance with ER-AA-200, Preventative Maintenance, Revision 3 based upon the licensees PCM template or provide a technical basis for any deviations from the template. Using the correct PCM template could have identified this degradation prior to the Unit Common EDGs failure to load onto the Unit 1 vital bus on September 1, 2025, during testing. Implementing these procedures is required by TS 5.4.1.a.
Screening:
The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in the loss of Unit Common EDG availability/capability to Unit 1.
Significance:
The inspectors assessed the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined a detailed risk evaluation was required using Exhibit 2, Mitigating Systems Screening Questions, Section A, Mitigating SSCs and PRA Functionality (except Reactivity Control Systems). The inspectors answered Yes to question 3 of that section because the degraded condition represented a loss of the PRA function of one train of a multi-train TS system for greater than its TS allowed outage time. Specifically, the failed Unit 1 control relay represented a loss of the PRA function to power the 141-Y bus from the Unit Common EDG through the 1413 breaker, for greater than the TS 3.8.1 allowed outage time of 14 days.
A regional Senior Reactor Analyst (SRA) performed a risk assessment in accordance with NRC Inspection Manual Chapter 0609 Appendix A, The Significance Determination Process for Findings At-Power. The SRA used SAPHIRE 8 version 8.2.12 and the LSAL-EQK-HWD-FLEX, LaSalle 1 & 2 Standardized Plant Analysis Risk (SPAR) Model, version 8.83. The SRA estimated the increase in internal and external risk to be 6.21E-7/yr, a finding of very low safety significance (Green).
Assumptions:
- The exposure time of the degraded condition was 64 days, which included the time from the last successful operation of the 1-DG052CX1 relay on July 1, 2025, until it was repaired and returned to service on September 3, 2025.
- The condition was modeled by setting the following basic events to TRUE:
o EPS-DGN-LR-DG0, Diesel Generator 0 Fails to Load Run o
EPS-DGN-AP-DG0-U2, DG0 Aligned to U1 Initially
- Recovery credit was provided by allowing the unit specific Division I safety bus to be repowered from the Unit Common EDG (EDG 0) via the opposite units Division I safety bus, as directed by procedures and accounting for time constraints (i.e., crosstie).
- Revised EDG common cause component groupings (CCCGs) to better align with Risk Assessment of Operational Events (RASP) Handbook - Volume 1, Internal Events, Revision 3.
- SPAR model data was used for equipment failure rates, as it is assumed to be the best estimate gathered from Idaho National Laboratories (INL) data.
- FLEX credit was applied by changing basic event FLX-XHE-XE-ELAP, Operators Fail to Declare ELAP When Beneficial, from a TRUE setting to a failure probability of 1E-2.
- Hardened Containment Venting credit was applied by changing basic event CVS-XHE-XM-VENTLT, Operator Fails to Vent Containment, from a TRUE setting to a failure probability of 1E-2.
- The LaSalle SPAR model did not contain internal flooding or fire events; therefore, the Constellation LaSalle internal flooding and fire probabilistic risk assessment (PRA)results were used as best available information.
Exposure Time:
The 1-DG052CX1 control power relay was last successfully operated on July 1, 2025. Since the failure mechanism was determined to be mechanical binding between the relays armature assembly and plastic housing, it was reasonable to conclude the failure occurred (relay became bound) when the component was last functionally operated. The component was discovered failed on September 1, 2025. The relay was replaced, and the Unit Common EDG was returned to an available status on September 3, 2025. Therefore, per Section 2.3 of the RASP Handbook - Volume 1, the exposure time included the time from the last successful operation to the unsuccessful operation
- (t) plus the repair time, a total of 64 days.
Failure Modeling and Recovery Credit:
The 1-DG052CX1 control power relay failure directly affected the Unit Common EDGs capability to power Unit 1 Division I Bus 141-Y via output breaker 1413. However, since the LaSalle SPAR model was a Unit 2 model, the degraded condition was reflected on the model as affecting the Unit Common EDGs capability to power Unit 2 Division I Bus 241-Y via output breaker 2413, as a surrogate. Therefore, the remaining discussions in this detailed risk evaluation will be from the perspective of the degraded conditions impact on the Unit 2 LaSalle model.
The SPAR model did not explicitly model EDG output breakers since those failures were accounted for in the EDG failure to load/run (FTLR) event probabilities. Specifically, the EDG output breakers were included within the EDG component boundary, as described in NUREG/CR-6928, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants, Section A.2.17, Emergency Diesel Generator (EDG)
Data Sheet. Therefore, the degraded condition was modeled by setting basic event EPS-DGN-LR-DG0, Diesel Generator 0 Fails to Load Run.
During a dual unit loss of offsite power (LOOP) the SPAR model assumed the Unit Common EDG would align to the opposite unit 50% of the time because a relay race determined which unit the EDG aligned to. However, the degraded condition precluded the Unit Common EDG from aligning to Unit 2 (surrogate). Since the degraded condition would always cause the Unit Common EDG to align to the opposite unit during a dual unit LOOP, basic event EPS-DGN-AP-DG0-U2, DG0 Aligned to U1 Initially, was also set to TRUE.
The degraded condition only affected the capability of the Unit Common EDG to directly supply Unit 2 Division I Bus 241-Y (surrogate). Therefore, model changes were made to ensure the Unit Common EDG was still capable of supplying power to Bus 241-Y via a crosstie through Unit 1 Division 1 Bus 141-Y (surrogate), given the degraded condition. A common cause failure (CCF) of the Unit Common EDG would still fail the crosstie action. This recovery credit was deemed appropriate after:
- (1) a review of site procedures;
- (2) interviews of licensed operators;
- (3) a review of dominant cut sets; and
- (4) consideration of the time constraints involved with performing the crosstie actions.
Common Cause Component Grouping (CCCG):
The SPAR model was revised to more closely align with the RASP Handbook - Volume 1 Section 5.3, CCCG Modeling, and Section 5.4, Intersystem and Cross-Unit CCF Modeling.
Specifically, the EDG CCCG for all EDG failure modes were changed to the following:
1. Unit Common EDG (EDG 0) and Unit 2 Division II EDG (EDG 2A) (surrogates)
2. Unit Common EDG (EDG 0), Unit 2 Division II EDG (EDG 2A), and Unit 1 Division II
The CCCGs assigned above did not include the Unit 2 Division III high pressure core spray (HPCS) system EDG (EDG 2B) because although it was similar to the EDGs in the groupings, it only supported the HPCS system/function and could not be cross tied to support the emergency power supply system/function.
Internal Events Risk:
The SRA ran the SPAR model with the changes described above for an exposure time of 64 days. The result was a core damage frequency (CDF) increase from the baseline of 9.91E-8/yr. This result aligned closely to the licensees internal events result using similar assumptions. The dominant core damage sequences were LOOP events that lead to a Station Blackout (SBO) condition with failures of the emergency power system, HPCS system, and reactor core isolation cooling (RCIC) system. Since the SPAR model did not include the capability to evaluate internal flooding, the licensees internal flooding results were used as best available information. The CDF increase due to internal flooding was 1.24E08/yr.
External Events Risk:
The SPAR model did not include the capability to evaluate the fire risk. However, the licensee was able to provide the fire risk increase due to the degraded condition for the exposure time.
The SRA reviewed initial risk results from the licensee and noted their PRA model of record did not factor in CCFs for the degraded condition. Specifically, the degraded condition was mapped onto the licensees PRA as a failure of the Unit Common EDG output breaker to the affected unit, but the model did not contain CCFs for EDG output breaker basic events. Unlike the SPAR model, the licensees PRA model did not include EDG FTLR events. To account for the CCF risk increase due to the degraded condition, the licensee added CCCGs to their significance determination process (SDP) evaluation that included different combinations of the following EDG output breakers:
- Breaker 1413 (Unit Common EDG output breaker to Unit 1 Division I)
- Breaker 2413 (Unit Common EDG output breaker to Unit 2 Division I)
- Breaker 1423 (EDG 1A output breaker to Unit 1 Division II)
- Breaker 2423 (EDG 2A output breaker to Unit 2 Division II)
The licensee also performed additional fire modeling refinements for their SDP evaluation. The CDF increase due to fire events was 5.03E-7/yr. The dominant core damage sequence was a fire in the Unit 1 auxiliary electric equipment room (AEER) which caused a dual unit LOOP, failure of the RCIC system, a failure of the unit specific Division II EDG and Division II residual heat removal (RHR) loops B and C, and other balance of plant equipment. The sequence also included a failure of alternating current (AC) power to Division I equipment, and a failure of the HPCS system, leaving the unit in an SBO condition.
The SPAR model included the capability to evaluate seismic risk. Although not dominant, the CDF increase due to seismic was 6.20E-9. Although the SPAR model also had the capability to evaluate the risk due to tornado and high wind events, the SRA determined the risk from those external events was insignificant with respect to the degraded condition and exposure time.
Sensitivity Evaluation:
The SRA conducted sensitivity analysis by changing the EDG combinations within the CCCGs as well as changing the alpha factors of cross-unit CCCGs in accordance with the RASP Handbook - Volume 1, Section 5.4.1 Interim Approach for Cross-Unit CCF. The SPAR internal events results varied between 6.6E-8 to 4.6E-7. The SPAR CCCGs described above, without the alpha factor modification, led to a result in the middle of the range which was considered the best estimate for this evaluation. The licensee performed similar sensitivity analysis for their internal flooding and fire risk results. The licensees results with the PRA CCCGs described above were used as the best estimates for this evaluation.
Results:
The following table contains the risk increase for the 64-day exposure time.
Event Internal Events (SPAR)
Internal Flooding (Licensee)
Fire (Licensee)
Seismic (SPAR)
Total CDF/yr 9.91E-8 1.24E-8 5.03E-7 6.20E-9 6.21E-7 The SRA estimated the increase in internal and external risk to be 6.21E-7/yr, a finding of very low safety significance (Green).
The SRA determined that any impact on Large Early Release Frequency (LERF) was bounded by the results of the CDF evaluation.
Cross-Cutting Aspect:
Not Present Performance. No cross-cutting aspect was assigned to this finding because the inspectors determined the finding did not reflect present licensee performance.
Enforcement:
Violation:
Technical Specification Section 5.4.1.a, requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
NRC Regulatory Guide 1.33, Revision 2, Appendix A, Section 9, addresses Procedures for Performing Maintenance, and Section 9b requires that preventative maintenance schedules are developed to specify lubrication schedules, inspections of equipment, replacement of such items such as filters and strainers, and inspection or replacement of parts that have a specific lifetime such as wear rings.
The licensee established Procedure ER-AA-200, Preventative Maintenance Program, Revision 3, in part, to describe key elements associated with establishing component classification and development of maintenance strategy. Procedure ER-AA-200, Step 4.4.5, requires, in part, that the Licensee review the PCM template against the stations structure, systems, and components and develop the maintenance strategy for the component, and to use the PCM template as a guide.
Contrary to the above, from May 11, 2017, until September 1, 2025, the licensee failed to implement Step 4.4.5 of Procedure ER-AA-200, Revision 3, for the safety-related Unit Common EDG Unit 1 and Unit 2 control power relays (1-DG052CX1 and 2-DG052CX1).
Specifically, the licensee failed to use the PCM template, which established as-found testing and calibration of the relays every 4 years, as a guide to develop the Maintenance Strategy.
The relays were critical components as defined by the criteria in ER-AA-200-10001, Revision 3, Attachment 1, Step, 1.4.1.B.
Enforcement Action:
This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified that no proprietary information was retained or documented in this report.
- On December 9, 2025, the inspectors presented the emergency preparedness inspection results to Ronald Vanderhyden, Emergency Preparedness Manager, and other members of the licensee staff.
- On December 11, 2025, the inspectors presented the radiation protection inspection results to Rachael Conley, Acting Radiation Protection Manager, and other members of the licensee staff.
- On January 14, 2026, the inspectors presented the integrated inspection results to John VanFleet, Site Vice President, and other members of the licensee staff.
DOCUMENTS REVIEWED
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
M-136, Sheet 1
P&ID Reactor Building Closed Cooling Water
Drawings
M-136, Sheet 3
P&ID Reactor Building Closed Cooling Water
W
LOP-WR-01E
Unit 1 Reactor Building Closed Cooling Water System
Electrical Checklist
Procedures
LOP-WR-01M
Unit 1 Reactor Building Closed Cooling Water System
Mechanical Checklist
Degraded Coatings on Inlet/Outlet Head
10/27/2025
10/29/2025
Corrective Action
Documents
1DG01A Consecutive Restricted Tubes Indication
10/28/2025
Work Orders
Disassemble and Inspect 1DG01A DG Cooling Water HX
11/04/2025
Miscellaneous
Procedure Form
TQ-AA-150-F25
LaSalle Requal Data - Procedure Form TQ-AA-150-F25
2/15/2025
Scenario #ESG 96 Licensed Operator Evaluated Scenario Guide
Scenario #ESG 97 Licensed Operator Evaluated Scenario Guide
Unit 1 REMA for
October 16, 2025
Control Rod Pattern Adjustment
10/16/2025
Miscellaneous
Unit 2 REMA for
November 30,
25 - December
2, 2025
L2F47 Startup
11/30/2025
Procedures
LOP-TG-02
Turbine Generator Startup
Corrective Action
Documents
QV/QC Hold Point Unable to be Inspected
01/06/2025
1B DG Generator Lock Tab Missing
09/16/2025
Corrective Action
Documents
1B DG Inboard Generator Bearing
09/16/2025
Procedures
Operability Determinations (CM-1)
Work Orders
Perform 2 Year Inspection on 1B EDG
09/15/2025
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
1B DG Lock Tab Missing
09/17/2025
Engineering
Changes
Defeat RR Interlock
Engineering
Evaluations
550.59 Screening
Number L25-059
Remove Reactor Recirculation Pump Trip
Corrective Action
Documents
WHR Violation Report Showing False Violation - MMD
11/17/2025
Miscellaneous
L2F47 Key Safety Function Review
11/17/2025
LGP-2-1
Normal Unit Shutdown
135
Procedures
LGP-3-2
Reactor SCRAM
1A DG Falk Coupling is Showing Wear Indication
10/28/2025
Corrective Action
Documents
Indications of a Leak in the U1 Drywell
11/24/2025
Engineering
Changes
ITE Breakers TSC Switch Removal
Miscellaneous
Unit 1 Drywell Unidentified Leakage ACMP
Conduct of Maintenance Manual
Procedures
Post Maintenance Testing
Verify Proper Operation of 0DG01F
09/30/2025
Clean/Flush Cooler and PMT
09/30/2025
Perform TSC Switch IT-7000 Modification
09/30/2025
Work Orders
1A DG Fast Start Surveillance
11/03/2025
Calculations
Evaluation No.: 24-
§50.54(q) Program Evaluation Assessment Review for
Standardized Radiological Emergency Plan Revision 34
2/28/2025
Miscellaneous
EPID L-2018-LLA-
0045
Issuance of Amendments to Revise the Emergency Response
Organization Staffing Requirements
03/21/2019
Exelon Nuclear Standardized Radiological Emergency Plan
Procedures
Standardized Radiological Emergency Plan
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
EPA-400/R-17/001 PAG Manual: Protective Action Guides and Planning
Guidance for Radiological Incidents
January 2017
ALARA: Post-DSP Draindown LL
2/01/2023
Long Term Storage Laydown Area - Radiation Protection
07/03/2024
Temporary Storage Area
08/13/2024
RP Plan Needed to Support 2025 RW Shipping Campaign
01/23/2025
Long Term Storage Laydown Area - Radiation Protection
07/28/2025
Improvement Opportunity for Radiological Waste Barrel
Labels
08/13/2025
Corrective Action
Documents
Damaged Source LSL-1029
09/08/2025
RP-AA-605 Att 2 Waste Stream Results Review Waste
Stream DAW June 2023
09/06/2026
Waste Stream Review and Scaling Factor Determination
Report - ALPS PV7 Mixed Bed
2/07/2023
Training and
Qualification
Records
Shipment Training and Qualification Records
Various
Miscellaneous
Leak Test List and Long Term Storage Inventory
09/09/2025
CFR 61 Program
Procedures
Process Control Program for Radioactive Wastes
LM23-132
GE Equipment
11/28/2023
LM24-033
Control Rod Drive Boxes
2/29/2024
Shipping Records
LM25-001
Reactor Coolant System Low Level Waste Equipment
01/02/2025
Occupational Exposure Control Effectiveness Condition
Report Search
Various
MS-05 PI Summary Report
10/14/2025
MS-08 PI Summary Report
10/14/2025
71151
Miscellaneous
MS-10 PI Summary Report
10/14/2025
Inspection
Procedure
Type
Designation
Description or Title
Revision or
Date
Sentinel Dose Rate Alarm Search
Various
Monthly Data Elements for NRC ROP Indicator - Reactor
Coolant System (RCS) Specific Activity
Various
Monthly Data Elements for NRC ROP
Indicator - RETS/ODCM Radiological Effluent Occurrences
Various
MSPI Monitoring and Margin Evaluation
MSPI Basis Document
Procedures
Mitigating System Performance Index Data Acquisition and
Reporting
Corrective Action
Documents
DG Output Breaker Failed to Close on Unit 1
09/02/2025
Miscellaneous
LAS-44873
Failure Analysis Report for Relay, Auxiliary, GE Type HMA,
Century Series Coil
09/26/2025
Preventative Maintenance Program
Preventative Maintenance Program
Equipment Classification
Procedures
Equipment Classification
Unit 1 SCRAM During Ground Isolation
11/02/2025
1B Reactor Recirc Pump Trip
2/03/2025
Corrective Action
Documents
Reactor SCRAM on Unit 1
2/28/2025
LGA-001
RPV Control (1-3)
LOA-RR-101
Unit 1, Reactor Recirculation System Abnormal
Procedures
LOP-RR-13
Interim Single Loop Operation (SLO) Baseline Data
Verification Gathering and Operability Verification
14