IR 05000263/2014005

IR 05000263/2014005; on 10/01/2014 - 12/31/2014; Monticello Nuclear Generating Plant; Equipment Alignment

ML15029A459
Person / Time
Site:	Monticello
Issue date:	01/29/2015
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Fili K Northern States Power Co
References
IR 2014005
Download: ML15029A459 (34)

Text

UNITED STATES ary 29, 2015

SUBJECT:

MONTICELLO NUCLEAR GENERATING PLANT NRC INTEGRATED AND POWER UPRATE INSPECTION REPORT 05000263/2014005

Dear Ms. Fili:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Monticello Nuclear Generating Plant. The enclosed report documents the inspection findings, which were discussed on January 7, 2015, with you and other members of your staff.

Based on the results of this inspection, one NRC-identified finding of very low safety significance was identified. The finding involved a violation of NRC requirements. However, because of the very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating the issue as a non-cited violation (NCV) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, - Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Monticello Nuclear Generating Plant. In addition, if you disagree with a cross-cutting aspect assigned to any finding 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 Regional Administrator, Region III, and the NRC Resident Inspector at the Monticello Nuclear Generating Plant. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS)

component of the NRC's Agencywide Documents Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Kenneth Riemer, Branch Chief Branch 2 Division of Reactor Projects Docket No. 50-263 License No. DPR-22

Enclosure:

Inspection Report 05000263/2014005; w/Attachment: Supplemental Information

REGION III==

Docket No: 50-263 License No: DPR-22 Report No: 05000263/2014005 Licensee: Northern States Power Company, Minnesota Facility: Monticello Nuclear Generating Plant Location: Monticello, MN Dates: October 1 through December 31, 2014 Inspectors: P. Zurawski, Senior Resident Inspector P. Voss, Resident Inspector M. Phalen, Senior Health Physicist J. Beavers, Emergency Preparedness Inspector S. Bell, Health Physicist D. McNeil, Senior Operations Engineer Approved by: K. Riemer, Branch Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000263/2014005; 10/01/2014-12/31/2014; Monticello Nuclear

Generating Plant; Equipment Alignment.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Green finding was identified by the inspectors.

This finding was considered a non-cited violation (NCV) of Nuclear Regulatory Commission (NRC) regulations. The significance of inspection finding is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas effective date January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 5, dated February 2014.

Cornerstone: Barrier Integrity

Green.

The inspectors identified a finding of very low safety significance and NCV of 10 CFR 50.55a(f)(4) for the licensees failure to test main steam line drain containment isolation valves MO-2373 and MO-2374 in accordance with the American Society of Mechanical Engineers (ASME) Operation and Maintenance (OM) code requirements or maintain the valves in the alternative configuration specified in an NRC-approved Relief Request (VRR-05). Specifically, on October 17, 2014, the NRC identified that the licensee had failed to maintain the approved alternative configuration which had been accepted by the NRC in lieu of the required quarterly stroke testing of MO-2373 and MO-2374. Corrective actions for this event included immediate restoration of the NRC-approved configuration specified in the relief request, cancellation of the noncompliant procedure temporary revisions, and cancellation of the associated 10 CFR50.59 screening. The licensee also initiated an apparent cause evaluation, which was in progress at the end of this inspection period.

The inspectors determined that the failure to test MO-2373 and MO-2374 in accordance with the ASME OM code or maintain the relief request approved plant configuration was a performance deficiency. The inspectors evaluated the issue and determined that the finding was more than minor in accordance with IMC 0612, Appendix B, because it adversely impacted the Barrier Integrity Cornerstone attributes of Design Control and Configuration Control, and affected the cornerstone objective to provide reasonable assurance that physical design barriers, including containment, protect the public from radionuclide releases caused by accidents or events. The inspectors assessed the significance of this finding in accordance with IMC 0609, and determined that this finding was of very low safety significance because it did not represent an actual open pathway in the physical integrity of reactor containment, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The inspectors concluded that this finding was cross-cutting in the Human Performance Decision making aspect because of the failure to use a consistent, systematic approach to make decisions and a failure to ensure that risk insights are incorporated as appropriate. [H.13]

(Section 1R04)

REPORT DETAILS

Summary of Plant Status

Monticello began the inspection period operating at approximately 64 percent (1285 Megawatts Thermal (MWt)) reactor power. Power was reduced on October 1, 2014, due to the unexpected trip of the 11 circulating water pump motor. On November 8, 2014, power was raised to approximately 88.5 percent (1775 MWt). On November 18, 2014, the licensee re-commenced Extended Power Uprate (EPU) testing. Testing continued during the remainder of the inspection period and consisted of raising power to a predetermined level, acquiring data, and subsequently lowering power back to the previous power level with acceptable results until the newly acquired data was analyzed. This evolution occurred four times including: November 18, 2014 (1775 MWt to 1797 MWt to 1775 MWt); December 5, 2014 (1775 MWt to 1819 MWt to 1797 MWt); December 15, 2014 (1797 MWt to 1864 MWt to 1819 MWt); December 26, 2014 (1819 MWt to 1903 MWt to 1864 MWt); and December 30, 2014 (1864 MWt to 1903 MWt) .

Reactor power was approximately 95 percent (1903 MWt) at the end of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Safety Analysis Report (USAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

This inspection constituted one winter seasonal readiness preparations sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• Standby Gas Treatment Train B;

• Division 2 125 Volt Battery with Division 1 125 Volt Battery Out-Of-Service;

• Offsite Power Sources with 1AR Out-Of-Service Following 2R LTC Lockout; and

• Primary Containment Isolation Valves.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, USAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.

These activities constituted four partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

Introduction The inspectors identified a finding of very low safety significance (Green) and NCV of 10 CFR 50.55a(f)(4) for the licensees failure to test main steam line drain containment isolation valves MO-2373 and MO-2374 in accordance with the ASME OM code requirements or maintain the valves in the alternative configuration specified in an NRC-approved Relief Request (VRR-05). Specifically, on October 17, 2014, the NRC identified that the licensee had failed to maintain the approved alternative configuration which had been accepted by the NRC in lieu of the required quarterly stroke testing of MO-2373 and MO-2374.

Description In May 2014, the licensee observed an upward trend in unidentified drywell leakage in conjunction with stroke time testing of the inboard main steam line drain valve, MO-2373. The licensee suspected a packing leak on this valve and concluded that backseating the valve could reduce the leakage into the drywell. The licensee subsequently developed a back seating methodology which included initial testing to maintain the operability of both the inboard (MO-2373) and outboard (MO-2374)valves. On July 10, 2014, MO-2373 was back seated and MO-2374 was closed and de-energized to prevent opening due to 10 CFR 50, Appendix R concerns. Since the next quarterly exercise, testing of MO-2373 on its backseat was due October 10, 2014, rather than risk cycling the valves, the licensee requested permission from the NRC to defer this quarterly testing until the next Monticello Nuclear Generating Plant (MNGP)refueling outage.

Pursuant to 10 CFR 50.55a(a)(3), the licensee may request relief from code requirements along with information to support the determination. The Commission is authorized to evaluate such a request and may grant relief or impose alternative requirements considering the burden that the licensee might incur if the Code requirements were enforced for a given facility. Monticello Relief request VRR-05 proposed to maintain MO-2374 in the closed position with the valve motor electrically de-energized and with MO-2373 in the full open and backseated position with electrical power provided to maintain isolation capability on receipt of an automatic close signal.

This configuration was proposed to be in place until the next refueling outage, at which time the required testing would take place. By letter and safety evaluation, dated August 27, 2014, the NRC authorized the proposed alternative.

On October 16, 2014, as part of an effort to reduce operator workarounds, the licensee performed a 10 CFR 50.59 screening, which concluded that although the relief request was in place, the licensee could change the accepted configuration. Specifically, the screening documented acceptability of reenergizing the MO-2374 valve motor and putting a fire watch in place for all affected fire areas to meet the fire protection requirements. This screening specifically evaluated the concern that relief request VRR-05 had approved the configuration as part of the proposed alternative to quarterly testing. The 10 CFR 50.59 screening concluded that the configuration change would not adversely impact the overall conclusions of the NRC-approved relief request. As a result, on October 17, 2014, the licensee took action to reenergize the MO-2374 valve motor and install a fire watch.

On October 17, 2014, the inspectors identified that the licensee had altered the configuration of these valves, which deviated from the NRC-approved relief request.

The inspectors reviewed the 10 CFR 50.59 screening document and concluded that the licensee had inappropriately used the 10 CFR 50.59 process to justify a configuration change that was required to be performed under a separate process. This process, the 10 CFR 50.55a relief request process, would have required NRC approval to make the change. The inspectors concluded that the licensee had failed to test these valves in accordance with the ASME code requirements or the approved relief request, and immediately discussed these concerns with the licensee. The licensee restored the approved alternative configuration within three hours of the noncompliant configuration change.

The inspectors reviewed licensee procedures and determined that there were several ways that the site could have identified and prevented this issue. Specifically, Section 5.7.5 of procedure CD 5.5, In-service Testing Standard states in part, Relief requests from requirements determined to be clearly impractical that implement a proposed alternative test may be implemented while under NRC review. All other relief requests should receive NRC approval prior to implementation. Revisions to relief requests that are solely editorial in nature do not require NRC approval prior to implementation. The inspectors determined that this relief request was not for clearly impractical reasons, and the change was not editorial in nature. As a result, the procedure directed NRC approval for the change made.

In addition, FG-E-SE-03, 50.59 Resource Manual discusses that changes to In-service testing and In-service inspection plans or descriptions are controlled by separate processes under 10 CFR 50.55a and are not subject to 10 CFR 50.59. The inspectors also noted that industry guidance included in NUREG-1482, Guidelines for In-service Testing at Nuclear Power Plants states, this 10 CFR 50.59 process does not allow the licensee to change an NRC granted or authorized relief request or alternative. The NRC must authorize any change to an NRC-authorized 10 CFR 50.55a(a)(3) alternative unless the requirements of the ASME code can be met.

The inspectors noted that the licensee, when performing this configuration change, had failed to utilize the tool which had been created to prevent against errors similar to the one made in this case. Specifically, QF0591, Engineering Product Risk Assessment and Mitigation Checklist, was created to provide guidance on risk of engineering products in development and specify tools and barrier to ensure a quality product would be generated. QF0591 specified that if the work involved relief requests or commitment changes, or could result in a mistake in those products, the performer should discuss the activity with the Site Licensing Manager. The inspectors noted that an independent validation from licensing could have identified the error in the proposed plan, given the amount of guidance that existed which prohibited these types of changes.

The inspectors also noted that during the course of development of the engineering product, the 10 CFR 50.59 screening for the configuration change was presented to the Plant Operations Review Committee (PORC). Subsequent investigation revealed that the PORC body had asked whether the configuration change impacted the In-service Testing (IST) relief request and the associated safety evaluation. In response, engineering staff informed PORC that from their review, the configuration change did not impact the hardship described in the relief request. The inspectors noted that the PORC did not request to see a copy of either the IST relief request or the safety evaluation, nor did they request a systematic validation of the IST impacts.

The inspectors concluded that the decision making surrounding the engineering product, the sites failure to incorporate risks associated with the configuration change, and the failure to use the established engineering product risk tool to prompt validation of applicable requirements led to the violation.

Analysis The inspectors determined that the failure to test MO-2373 and MO-2374, in accordance with the ASME OM code or maintain the NRC-approved alternative configuration, was a performance deficiency because it represented a failure to meet 10 CFR 50.55a(f)(4); the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented. The inspectors evaluated the issue and determined that the finding was more than minor in accordance with IMC 0612, Appendix B, because it adversely impacted the Barrier Integrity Cornerstone attributes of Design Control and Configuration Control, and affected the cornerstone objective to provide reasonable assurance that physical design barriers, including containment, protect the public from radionuclide releases caused by accidents or events.

Specifically, the finding resulted in the failure to perform required testing or maintain an NRC-approved alternative configuration for two containment isolation valves on a main steam line drain.

The inspectors assessed the significance of this finding in accordance with IMC 0609, Appendix A, Exhibit 3, for Barrier Integrity. The inspectors determined that this finding was of very low safety significance because it did not represent an actual open pathway in the physical integrity of reactor containment. The inspectors concluded that this finding was cross-cutting in the Human Performance Decision making aspect because of the failure to use a consistent, systematic approach to make decisions and a failure to ensure that risk insights are incorporated as appropriate. Specifically, the site failed to incorporate compliance risks associated with the configuration change, failed to systematically and cross-functionally review the facts and pertinent regulatory documents impacted by the change, and failed to use the established engineering risk tool to prompt validation of the applicable requirements and ensure informed decision-making. [H.13]

Enforcement Title 10 CFR 50.55a(f)(4) requires, in part, that pumps and valves classified as ASME Code Class 1, 2, or 3 must meet the IST requirements set forth in the ASME OM Code and addenda, to the extent practical within the limitations of design, geometry, and materials of construction of the components. Contrary to these requirements, the licensee failed to test main steam line drain containment isolation valves MO-2373 and MO-2374 in accordance with the ASME OM code requirements or maintain the valves in the alternative configuration specified in the NRC-approved Relief Request (VRR-05),for a period of approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Specifically, on October 17, 2014, the NRC identified that the licensee had failed to maintain the approved alternative configuration which had been accepted by the NRC in accordance with 10 CFR 50.55a(a)(3) in lieu of the required quarterly stroke testing of MO-2373 and MO-2374 in accordance with 10 CFR 50.55a(f)(4). The IST test would have been due 7 days earlier, on October 10, 2014. After the inappropriate configuration change, the plant remained in a noncompliant configuration for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.

Because this violation was of very low safety significance and it was entered into the corrective action program as CAP 1451598, this issue is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000263/2014005-01: Failure to comply with ASME Code and maintain configuration approved by IST relief request) Corrective actions for this event included immediate restoration of the NRC-approved configuration specified in the relief request, cancellation of the noncompliant procedure temporary revisions, and cancellation of the associated 10 CFR 50.59 screening. The licensee also initiated an apparent cause evaluation, which was in progress at the end of this inspection period.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Zone 09, Control Room;

• Zone 31-B/32-B/33, EFT 1st Floor (Div 1), 2nd Floor (Div 2) and 3rd Floor;

• Zone 19-B, Essential MCC 42 & 43, 931'; and

• Zone 13-A, Lube Oil Storage Tank Room.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment, which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.

These activities constituted four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On December 1, 2014, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On October 1, 2014, the inspectors observed operator actions in the control room to reduce power from approximately 66 percent to 30 percent following a condenser vacuum transient. This was an activity that required heightened awareness due to a degrading condenser vacuum and was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions.

The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.3 Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Annual Operating Exam administered by the licensee from September 8, 2014 through October 24, 2014, required by 10 CFR 55.59. The results for the exam were compared to the thresholds established in IMC 0609, Appendix I, Licensed Operator Requalification Significance Determination Process, to assess the overall adequacy of the licensees Licensed Operator Requalification Training Program to meet the requirements of 10 CFR 55.59.

(02.02).

This inspection constituted one annual licensed operator requalification examination results sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• Circulating Water System.

The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly maintenance effectiveness sample as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• A Control Room Ventilation/Control Room Emergency Filtration; and

• 11 EDG.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and USAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

This operability inspection constituted two samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• Control Room Outside Air Intake Rad Monitor B Power Supply;

• 11 Circulating Water Pump/Motor; and

• Division 1 125 Volt DC Battery Charger.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted three post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• Reactor Coolant I-131 Dose Equivalent Activity (Routine); and

• Dynamic EPU Testing (Routine).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the USAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, ASME code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two routine surveillance testing samples as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)

a. Inspection Scope

The regional inspectors performed an in-office review of the latest revisions to the Emergency Plan, Emergency Plan Annex, and Emergency Plan Implementing Procedures as listed in the Attachment to this report.

The licensee transmitted the Emergency Plan and Emergency Action Level (EAL)revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, Implementing Procedures. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment to this report.

This Emergency Action Level and Emergency Plan Change inspection constituted one sample as defined in IP 71114.04-06.

b. Findings

No findings were identified.

Introduction.

An Unresolved Item (URI) was identified because additional information is needed to determine whether a performance deficiency exists and if a violation of 10 CFR 50.54(q)(2) occurred. The inspectors identified an issue of concern associated with the licensees changing of the High River Level EAL threshold from 921 to 920 for the alert classification EAL HA1.6.

Description.

During the first quarter of 2014, the licensee made a change to EAL HA1.6, for High River Level. Specifically, the licensee changed the threshold for the Alert classification from 921 to 920. On November 4, 2014, the NRC questioned the reason for the EAL threshold change, noting that the change may be in conflict with the EAL basis for HA1.6. These questions prompted licensee discovery that the EAL threshold basis was associated with flooding impacts on plant equipment, rather than river level historical data, as the licensee originally believed. The inspectors observed that the basis for EAL HA1.6 was linked to the river level where flood waters would reach the top of the retention basin. The inspectors also noted that although the licensee had changed the EAL threshold, the actual level of the basin was not altered.

The licensee then questioned if the known level of the retention basin was a legacy error and what the correct level was for this EAL threshold. To address these questions, the licensee requested input from engineering and documented these issues in Action Request (AR) 01454593 on that same date. As an interim action, AR 01454593 documented that the current river level was 906, and if flooding were to occur, the licensee would rely on Procedure A.6, Acts of Nature, and an event response team would be formed in accordance with the procedure to monitor river level during the duration of a flood event. The licensee noted that at a river level of 918, a Notification of Unusual Event would be declared. In addition, the licensee concluded that the shift manager, event response team, and plant management would monitor for indication of degraded performance of equipment or structures necessary for safe shutdown for event classification escalation to the Alert level. The inspectors evaluated these interim compensatory measures and found them adequate as no additional reasonable risk existed as a result of this issue.

On December 3, 2014, NRC questions regarding the progress of the previous AR led to the licensees statement that the 920 level also may not be correct. Because the licensee had not yet determined the appropriate High River Level EAL threshold for the alert classification EAL HA1.6, the inspectors could not readily determine whether the error was a legacy issue with the old threshold value, a current performance issue with the new threshold value and EAL change process, or both. The interim compensatory measures identified in the previous AR remained in effect at the conclusion of this inspection and the December 3, 2014 discussions and URI determination resulted in the generation of AR 01458209 by the licensee on that same date.

Therefore, a URI was identified because additional information on the correct High River Level EAL threshold is needed for the inspectors to determine whether a performance deficiency existed and if a violation of 10 CFR 50.54(q)(2) occurred.

(URI 05000263/2014005-01; Incorrect Emergency Action Level Threshold

RADIATION SAFETY

Cornerstones: Occupational and Public Radiation Safety

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation (71124.08) This inspection constituted one complete sample as defined in IP 71124.08-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the solid radioactive waste system description in the USAR, the process control program, and the recent radiological effluent release report for information on the types, amounts, and processing of radioactive waste disposed.

The inspectors reviewed the scope of quality assurance audits in this area since the last inspection to gain insights into the licensees performance and inform the smart sampling inspection planning.

b. Findings

No findings were identified.

.2 Radioactive Material Storage (02.02)

a. Inspection Scope

The inspectors selected areas where containers of radioactive waste are stored, and evaluated whether the containers were labeled in accordance with 10 CFR 20.1904, Labeling Containers, or controlled in accordance with 10 CFR 20.1905, Exemptions to Labeling Requirements.

The inspectors assessed whether the radioactive material storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20, Standards for Protection against Radiation. For materials stored or used in the controlled or unrestricted areas, the inspectors evaluated whether they were secured against unauthorized removal and controlled in accordance with 10 CFR 20.1801, Security of Stored Material, and 10 CFR 20.1802, Control of Material Not in Storage.

The inspectors evaluated whether the licensee established a process for monitoring the impact of long term storage (e.g., buildup of any gases produced by waste decomposition, chemical reactions, container deformation, loss of container integrity, or re-release of free-flowing water) that was sufficient to identify potential unmonitored, unplanned releases or nonconformance with waste disposal requirements.

The inspectors selected containers of stored radioactive material, and assessed for signs of swelling, leakage, and deformation.

b. Findings

No findings were identified.

.3 Radioactive Waste System Walkdown (02.03)

a. Inspection Scope

The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation agreed with the descriptions in the USAR, Offsite Dose Calculation Manual, and Process Control Program.

The inspectors reviewed administrative and/or physical controls (i.e., drainage and isolation of the system from other systems) to assess whether the equipment which is not in service or abandoned in place would not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure.

The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, Changes, Tests, and Experiments.

The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what is described in the USAR were reviewed and documented in accordance with 10 CFR 50.59, as appropriate and to assess the impact on radiation doses to members of the public.

The inspectors selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers and assessed whether the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the process control program, and provided representative samples of the waste product for the purposes of waste classification as described in 10 CFR 61.55, Waste Classification.

For those systems that provide tank recirculation, the inspectors evaluated whether the tank recirculation procedures provided sufficient mixing.

The inspectors assessed whether the licensees process control program correctly described the current methods and procedures for dewatering and waste stabilization (e.g., removal of freestanding liquid).

b. Findings

No findings were identified.

.4 Waste Characterization and Classification (02.04)

a. Inspection Scope

The inspectors selected the following radioactive waste streams for review:

• 10 CFR 61 Analysis; Secondary Resins; and

• 10 CFR 61 Analysis; Primary Resins.

For the waste streams listed above, the inspectors assessed whether the licensees radiochemical sample analysis results (i.e., 10 CFR Part 61 analysis) were sufficient to support radioactive waste characterization as required by 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste. The inspectors evaluated whether the licensees use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current 10 CFR Part 61 analysis for the selected radioactive waste streams.

The inspectors evaluated whether changes to plant operational parameters were taken into account to:

(1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and

(2) assure that waste shipments continued to meet the requirements of 10 CFR Part 61 for the waste streams selected above.

The inspectors evaluated whether the licensee had established and maintained an adequate quality assurance program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55 and 10 CFR 61.56, Waste Characteristics.

b. Findings

No findings were identified.

.5 Shipment Preparation (02.05)

a. Inspection Scope

The inspectors observed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors assessed whether the requirements of applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensees procedures for cask loading and closure procedures were consistent with the vendors current approved procedures.

The inspectors observed radiation workers during the conduct of radioactive waste processing and radioactive material shipment preparation and receipt activities. The inspectors assessed whether the shippers were knowledgeable of the shipping regulations and whether shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport with respect to:

• As appropriate, the licensees response to NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, dated August 10, 1979; and

• Title 49 CFR Part 172, Hazardous Materials Table, Special Provisions, Hazardous Materials Communication, Emergency Response Information, Training Requirements, and Security Plans, Subpart H, Training.

Due to limited opportunities for direct observation, the inspectors reviewed the technical instructions presented to workers during routine training. The inspectors assessed whether the licensees training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.

b. Findings

No findings were identified.

.6 Shipping Records (02.06)

a. Inspection Scope

The inspectors evaluated whether the shipping documents indicated the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and UN number for the following radioactive shipments:

• 13-35; Radioactive Waste Shipment; Contaminated Equipment; dated

• March 19, 2013;

• 14-7; Radioactive Material Shipment; Samples; dated January 26, 2014;

• 14-43; Radioactive Material Shipment; Samples; dated May 21, 2014;

• 14-50; Radioactive Waste Shipment; Condensate Resin; dated June 13, 2014; and

• 14-73; Radioactive Waste Shipment; Reactor Water Cleanup Resin; dated November 3, 2014.

Additionally, the inspectors assessed whether the shipment placarding was consistent with the information in the shipping documentation.

b. Findings

No findings were identified.

.7 Identification and Resolution of Problems (02.07)

a. Inspection Scope

The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation, were being identified by the licensee at an appropriate threshold, were properly characterized, and were properly addressed for resolution in the licensee CAP. Additionally, the inspectors evaluated whether the corrective actions were appropriate for a selected sample of problems documented by the licensee that involve radioactive waste processing, handling, storage, and transportation.

The inspectors reviewed results of selected audits performed since the last inspection of this program and evaluated the adequacy of the licensees corrective actions for issues identified during those audits.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, and Occupational and Public Radiation Safety, and Security

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance IndexResidual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index-Residual Heat Removal System performance indicator for the period of the fourth quarter 2013 through the third quarter 2014. To determine the accuracy of the Performance Indicator (PI) data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated IRs for the period of October 2013 through September 2014 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI residual heat removal system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance IndexCooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index-Cooling Water Systems performance indicator for the period of the fourth quarter 2013 through the third quarter 2014. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 2013 through September 2014 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

This inspection constituted one MSPI cooling water system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue. Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Selected Issue Follow-Up Inspection: Minimum Critical Power Ratio Event Corrective

Actions

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting a root cause evaluation (RCE) for a recent reactivity event that occurred at the site. Specifically, as a result of human error, the plant inadvertently exceeded the operational limit for the minimum critical power ratio (MCPR)during actions to retrieve a tripped reactor recirculation pump. This issue was the subject of a violation discussed in Monticello inspection Report 2014-004. The inspectors reviewed the RCE and corrective actions for the event. The RCE concluded that there were several breakdowns that caused the event.

The RCE discussed that the root cause was attributed to the lack of effective communication and coordination of critical parameters and integrated power maneuvering sequencing. This was seen in the form of a reactivity plan that was inadequate, in that it did not appropriately address core flow limits, and did not appropriately set up the power maneuvers so that they were coordinated with the applicable reactor recirculation pump retrieval procedure. It was also seen in the lack of communication of critical parameter limits amongst the crew and nuclear engineering staff. In addition, the RCE found that inadequate reactivity plan preparation and a lack of visibility and description of the ARTS (Average Power Range Monitor, Rod Block Monitor, and Technical Specification Improvement Program (APRM RBM)) Region in operating procedures contributed to the event. Corrective actions were focused on improving processes and procedures that reactivity plans include adequate preparation, improving utilization and effectiveness of reactivity plan challenge boards, revising the procedure for retrieving a tripped recirculation pump to include additional barriers to predict and prevent entering the ARTS region, as well as additional actions focused on improved visibility of the ARTS region and remediation of individuals involved.

The inspectors also reviewed CAPs generated out of inspector questions relating to this event. Specifically, inspectors raised questions about whether decision making to continue power maneuvers was initially rushed after the MCPR event. Inspectors also questioned whether the sites response conformed to the requirements of the Reactivity Control Fleet Procedure FP-OP-COO-21 for reactivity events. The inspectors also questioned why the MCPR event had not risen to the level of a site clock reset, given the unplanned power change impacts to the plant. Subsequently, site management determined this event had met the site clock reset threshold. Inspectors also assessed licensee response to NRC concerns with subsequent Infrequent Tests or Evolution briefs where the crews failed to ensure that critical parameters and limits for monitored parameters were discussed. The inspectors also reviewed ongoing licensee efforts to address NRC concerns with the lack of formality associated with precisely controlling significant reactivity changes due to Xenon. The inspectors discussed the progress of the licensee in addressing all of these concerns and noted that many longer term actions were still in progress at the time of this inspection. The inspectors determined that violations associated with these additional concerns did not rise above minor significance.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

No findings were identified.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

.1 Loss of Condenser Vacuum While Operating with One Circulating Water Pump

a. Inspection Scope

The inspectors reviewed the plants response to an event where the plant experienced a degradation of condenser vacuum. Specifically, on October 1, 2014, the inspectors responded to the control room after reports of operators responding to a degraded condenser vacuum. At the time of the event, the plant had been operating with only one of the two circulating water pumps that would normally be in service. The plant had also experienced another vacuum transient event in previous weeks while in this configuration. At the time of the event, reactor power was at approximately 66 percent.

Upon responding to the control room, the inspectors were informed that operators had observed a step change in condenser vacuum. In addition, the operators had observed that the condenser tube differential pressures had also experienced a step change, suggesting a decrease in condenser heat removal effectiveness. Operators suspected condenser blockage, fouling, in condenser outlet valve malfunction as the culprit.

The inspectors noted that the condenser vacuum and differential pressures had appeared to stabilize, with an almost undetectable degrading trend. Due to the stabilization of the condenser parameters shortly after the transient, operators had not taken action to respond to the transient. The inspectors noted that the crew established appropriate parameters for monitoring, and briefed contingency actions in case of a change in condenser parameters. The inspectors also noted that the operations crew identified the need to update an existing contingency reactivity plan to ensure they were able to use it if the condenser were to degrade further. Subsequently, plant management made the decision to lower reactor power to approximately 30 percent to help stabilize the condenser parameters, and to provide plant staff the opportunity to clean and inspect the condenser, investigate the condenser outlet valves, and perform additional engineering evaluation with the plant in a safe condition. Inspectors concluded that operators responded appropriately to the degraded vacuum transient.

Documents reviewed are listed in the Attachment to this report.

This event follow-up review constituted 1 sample as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Power Uprate Related Inspection Activities

a. Inspection Scope

During this inspection period, the inspectors observed activities related to the power uprate amendment. Specific activities are documented below, and as referenced:

• Section 1R22-This section documents specific inspector reviews of EPU procedures associated with power ascension testing, along with the conduct of control room observation of EPU power dynamic testing.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 7, 2015, the inspectors presented the inspection results to Karen Fili, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• On November 14, 2014, the inspectors presented the inspection results to Mr. G. Allex, Monticello General Supervisor Operations Training. The licensee acknowledged the issues presented.

• The Annual Review of Emergency Action Level and Emergency Plan Changes with the Licensees Emergency Preparedness Manager, Mr. L. Anderson, on December 3, 2014.

• The inspection results for the area of radioactive solid waste processing and radioactive material handling, storage, and transportation with Mr. H. Hanson, Plant Manager, on December 19, 2014.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Fili, Site Vice President

H. Hanson, Jr., Plant Manager

P. Albares, Operations Manager

M. Lingenfelter, Director of Engineering

K. Jepson, Recovery Manager

S. Mattson, Maintenance Manager

S. Quiggle, Chemistry Manager

C. England, Radiation Protection Manager

A. Ward, Regulatory Affairs Manager

T. Hedges, RP General Supervisor

G. Allex, General Supervisor Operations Training

L. Anderson, Emergency Preparedness Manager

D. Bosnic, Business Support Director

B. Carberry, Emergency Preparedness

D. Collins, Regulatory Affairs Manager

S. OConnor, Regulatory Affairs

Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

LIST OF ITEMS

Opened

05000263/2014005-01 NCV Failure to Comply with ASME Code and Maintain Configuration Approved by IST Relief Request (Section 1R04)

05000263/2014005-02 URI Incorrect Emergency Action Level Threshold (Section 1EP4)

Closed

05000263/2014005-01 NCV Failure to Comply with ASME Code and Maintain Configuration Approved by IST Relief Request (Section 1R04)

Discussed

None.