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On October 16, 2017, with Unit 2 shutdown for a refueling outage, investigation into a boric acid indication identified a through wall leak at the socket weld that joins a 3/4 inch line to Loop A Reactor Coolant System (RCS)(AB) shutdown communication line valve 2RC-8-37 )(VTV). The leak was isolated by closed valves that would have limited primary coolant leakage to within the capacity of the charging system when the reactor coolant system was pressurized. The quantity of dry boric acid at the location was small (estimated at 1/2 teaspoon in volume). This failure constituted a welding or material defect in the primary coolant system that was not found acceptable under ASME Section Xl and an event or condition prohibited by Technical Specifications.

The cause of the leakage was determined to be stress corrosion cracking. Valve 2RC-8-37 was replaced. In addition, Prairie Island Nuclear Generating Plant intends to perform phased array ultrasonic inspections of socket welds on similar Class 1 piping containing stagnant water during future refueling outages.

On 12/17/2015 at 1234 Central Standard Time (CST) with Unit 2 (U2) in Mode 1 at 100 percent power, the U2 electric generator tripped due to a ground overvoltage protection relay (59/2G) actuation, which resulted in an automatic reactor trip and expected Auxiliary Feedwater System actuation. At 1307 CST a fire alarm was received in the U2 containment.

Personnel were unable to verify the status within 15 minutes and the site declared an Unusual Event, HU2.1, at 1318 CST.

The licensee notified the NRC Resident Inspector, state and local authorities and made an Event Notification to the NRC for the Unusual Event and the U2 reactor trip as required under 10 CFR 50.72(a)(1)(i) and 10 CFR 50.72(b)(2)(iv)(B).

Subsequently, the Unusual Event was terminated on 12/17/2015 at 1450 CST after a containment entry determined there was no smoke or fire. The original Event Notification was updated to cancel the Unusual Event and to add reporting under 10 CFR 50.72(b)(3)(iv)(A) for the expected Auxiliary Feedwater system actuation. Decay heat removal was via forced circulation with Auxiliary Feed and Steam Dumps providing secondary cooling. Offsite power remained available. The health and safety of the public was not at risk.

A troubleshooting plan was initiated which determined an actual ground fault existed internal to the new U2 electric generator, installed during the Fall 2015 U2 refueling outage, causing a U2 reactor trip and the expected Auxiliary Feedwater actuation. The cause of the ground fault of the U2 electric generator was determined to be foreign material, specifically a hex socket and hex key introduced at the vendor's manufacturing facility during installation of a temporary dust cover on collector end of the generator rotor.

At 11:55 CST on March 7, 2015, Unit 2 was at Mode 4-when a small cooling water leak was identified on the 21 Containment Fan Coil Unit (FCU) east face U-bend on the northeast corner bottom bundle. Unit 2 Containment was declared inoperable per Technical Specifications (TS) 3.6.1, Condition A, Containment inoperable, applicable in MODES 1, 2, 3, and 4. Immediate actions were taken to isolate the FCU within 1 hour from the initial identification of the leak and Containment was declared operable at 1220 CST on March 7., 2015.

This condition is reportable under 10 CFR 50.72(b)(3)(v)(C): Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems.that are needed to control the release of radioactive material. ENS 50870 was submitted at 14:05 CST. The plant remains in a safe condition and there was no effect to the health and safety of the public. The NRC Resident Inspector was notified.

The cause has been determined to be under-deposit pitting corrosion resulting in through-wall leaks. The identified leaking faces were replaced on 03/13/2015. The remaining FCU faces subjected to under-deposit pitting corrosion are scheduled to be replaced during the next Unit 2 refueling outage Fall 2015 (2R29). Increased inspections of the FCUs will remain in effect until corrective actions have been implemented.

On December 31, 2013, while Unit 2 was in Mode 3 (Hot Standby), the Hot Gap clearance checks and adjustments were being performed following the Steam Generator (SG) Replacement Project. During the performance of the Hot Gap checks, it was discovered that multiple Upper Lateral Support (ULS) shims were removed from both 21 and 22 SG. This resulted in both Reactor Coolant System (RCS) loops being declared inoperable and entering Technical Specification (Tech Specs) 3.4.5 Condition D for the RCS loops while in Mode 3. This placed both RCS loops in an unanalyzed condition for seismic and pipe rupture analysis and required an 8 hours report to the NRC via Event Notification (49685) under 10 CFR 50.72(b)(3)(ii)(B). Additionally, based on further analysis, it was determined that with both RCS loops inoperable, the condition required the notification to be updated to include 10 CFR 50.72(b)(3)(v)(B), a loss of safety function.

Actions were taken to reinstall all of the ULS shims, which restored the proper configuration to meet operability requirements for seismic and pipe rupture acceptance criteria. The installation was completed on December 31, 2013, at 1728 CST, at which time Tech Specs 3.4.5 Condition D was exited.

The Root Cause to this event was the Steam Generator Replacement Project (SGRP) failure to document on the design drawings their assumption that the Unit 2 ULS shim packs would be measured and adjusted one shim pack at a time while making adjustments in Mode 3.

On June 27, 2011, the off-site AC power sources to Unit 2 Prairie Island Nuclear Generating Plant (PINGP) were declared inoperable as a result of Transformer 2RY lockout and less than the required minimum voltage on the transmission system. The paths to the transmission system was declared inoperable. Although inoperable, transmission system sources remained connected to Unit 2; emergency diesel generators were available but not required to run.

The overcurrent ground detection relay actuated due to a bus phase to ground fault resulting from failed gasket material resulting in the Transformer lockout. It was determined that a less than adequate review of the Preventive Maintenance (PM) Deferral Process delayed the bus duct inspections that would have likely identified and corrected the deficient gasket material.

While Unit 2 was operating at 100% power, improper control of Unit 2 Shield Building access doors (Doors 172 and 173) during planned maintenance resulted in an unplanned Limiting Condition for Operation (LCO) entry and a Loss of Safety Function (LOSF) for the Shield Building system. During the maintenance work, the doors were simultaneously opened several times, for approximately ten seconds each time, resulting in a LOSF. This was reportable per 10 CFR 50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of the safety function that was needed to control the release of radioactive material.

The causal evaluation determined that Planning did not identify within the Work Order (WO) the latent impact of the LOSF when two Shield Building access doors were to be simultaneously opened.

On February 16, 2009 at 0129 CST, while train A emergency diesel generator (EDG) was out of service for planned maintenance, the train B EDG for Prairie Island Nuclear Generating Plant (PINGP) Unit 2 was rendered inoperable. This had the effect of making both EDGs for PINGP Unit 2 inoperable concurrently.

This event was due to an improperly planned electrical isolation that inadvertently disabled both of the train A fuel oil transfer pumps. One of these two pumps is necessary to meet the fuel oil requirements specified in the technical specifications (TS). This condition was discovered the following day at approximately 1100 CST. Operations personnel took actions immediately to restore the isolated fuel oil transfer pump and by 1145 CST, the pump and subsequently the train B EDG were returned to operable status. Thus, this condition existed for a period of approximately 34 hours which is reportable as a condition prohibited by TS.

TS require that if both EDGs are inoperable, then that Unit must be in MODE 3 within 8 hours.

PINGP licensing basis requires that three of the four fuel oil storage tanks (FOST) for Unit 2 be available in order to provide up to 14 days of fuel in the event of a design basis flood and loss of offsite power (LOOP) scenario. The 14 days is deemed sufficient to allow the PINGP fuel oil supply to be replenished from offsite sources. To meet this requirement, at least one of the fuel oil transfer pumps and FOSTs in the opposite train are relied upon in order to consider the EDG operable.

On July 31, 2008, Prairie Island Nuclear Generating Plant (PINGP) Unit 2 was operating at 100 percent power. At 1345 CDT Prairie Island staff declared both trains of the Unit 2 component cooling water (CC) system inoperable due to the discovery that a postulated Unit 2 high energy line break (HELB) in the Turbine Building could fail a CC line that would affect both trains of the Unit 2 CC system. With both trains of CC declared inoperable, PINGP staff entered Technical Specification (TS) Limiting Condition for Operability (LCO) 3.0.3. PINGP staff isolated the CC line in the Turbine Building at 1612 on July 31, 2008, which returned Unit 2 CC to operable status.

The as-found condition was an original design issue uncovered during walkdowns in support of turbine building CC system seismic qualification. The planned corrective action is to modify the cooling source to the cold lab and turbine building sample coolers to reroute or eliminate CC lines from the Turbine Building.

On August 21, 2016, at 1740 CDT, the Prairie Island Nuclear Generating Plant (PINGP) 2RY Transformer locked out.

During the event, 121 Motor Driven Cooling Water Pump (MDCLP) stopped due to the loss of power and then automatically restarted when sequenced by the load sequencer. The pump auto started on low pressure in the cooling water pump discharge header. This event is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in automatic actuation of an emergency service water system.

The cause of the 121 MDCLP auto-start was a low-pressure condition in the cooling water pump discharge header resulting from 2RY Transformer lockout. There was no safety injection signal from PINGP Unit 1 nor Unit 2 when 121 MDCLP started. The health and safety of the public was not at risk. The most likely cause of 2RY Transformer lockout is that the breathers on 2RY Transformer dog house were not adequately maintained. Breathers were not adequately maintained due to design limitations that did not allow proper internal inspection.

Immediate actions taken, 2RY Transformer dog house dried out and internal components were tested to validate the functionality of the equipment. Results were satisfactory. Corrective actions, 2RY Transformer Dog house breathers and outdoor bus breather were replaced per work order prior to returning the transformer to service. Also, the Preventative Maintenance (PM) procedure was updated to perform the full internal inspection during the future PM's (bus duct or transformer).

On 1/7/2016, Prairie Island Nuclear Generating Plant (PINGP) reviewed corrective actions associated with the transition to National Fire Protection Association "Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants" (NFPA 805). PINGP discovered no cold shutdown repair procedure existed to restore power to train B reactor coolant system (RCS) vent valves to reduce RCS pressure in event of fire in Fire Area (FA) 59 (Auxiliary Building Mezzanine Floor Unit 1) and FA 74 (Auxiliary Building Mezzanine Floor Unit 2). The PINGP Appendix R safe shutdown analysis (SSA) credits such actions for train B RCS vent valves for a fire in these areas. PINGP established compensatory measures for affected equipment and, with automatic detection and suppression capability, these measures ensured protection of potentially affected equipment. The health and safety of the public was not at risk. PINGP submitted Event Notification (EN) 51642 on 1/7/2016 as this event is reportable pursuant to 10 CFR 50.72(b)(3)(ii)(B) as an unanalyzed condition that significantly degrades plant safety. On 04/14/2005, a revision of the SSA was approved that credited a cold shutdown repair 'as a compliance strategy for FA 59 and 74, but no repair procedure existed in the event of afire in FA 59 nor FA 74.

On 1/11/2016, F5 Appendix D "Impact of Fire Outside Control/Relay Room" was issued and includes cold shutdown repair procedures for Train B RCS vent valves. Lack of technical rigor to ensure procedure F5 Appendix D included actions required by the SSA is the identified cause.

On 12/21/2015 with Unit 1 (U1) in Mode 1 at 100% power and Unit 2 (U2) in Mode 3, a technical review of a new weak link calculation as part of the transition to National Fire Protection Association's Performance Based Standard for Fire Protection for Light Water Reactor Electronic Generating Plants (NFPA 805) identified a non-emergency unanalyzed condition reportable under 10 CFR 50.72(b)(3)(ii)(B). Specifically, several motor operated valves (MOVs) credited to be manually operated from outside the control room in the event of a fire in the control room or relay room could be damaged in a postulated fire if hot shorts were to bypass the torque and limit switches. Also, MOVs associated with the Gland Steam system of both U1 and U2 had been added to F5 Appendix B but never analyzed in the event of a hot short. These conditions could impact the ability of plant operators to implement procedure F5 Appendix B, Control Room Evacuation (Fire). The identified MOVs are located in Fire Area (FA) 13 (Control Room) and FA 18 (Relay and Cable Spreading Room). New hourly fire watch impairments were created in these areas as compensatory measures. The fire detection systems in the control room and relay room remain in service. The site submitted Event Notification (EN) 51616.

Reviews of the list of MOVs susceptible to hot shorts bypassing the torque and limit switches continued and additional valves were noted to be affected by this failure mechanism. As a compensatory measure, new hourly fire watch impairments were created for FA 31 ("A" Train Hot Shutdown Panel & Air Compressor/Auxiliary 695 Feedwater Room), FA 32 ("B" Train Hot Shutdown Panel & Air Compressor/Auxiliary 695 Feedwater Room), FA 58 (Auxiliary Building Ground Floor U1) and FA 73 (Auxiliary Building Ground Floor U2). EN 51616 was updated on 01/14/2016. The public health and safety was not impacted.

Event Description

During technical review for a new calculation as part of the transition to NFPA-805, the station reviewed MOVs identified in the Appendix R program to ensure they had been analyzed correctly. In this review it was determined several MOVs had been added to the program but had not been analyzed for a weak link. Further, several MOVs would not survive a hot short condition, although they were credited in the Appendix R program to meet programmatic requirements for survivability from a hot short condition. Also, MOVs associated with the Gland Steam system of both U1 and U2 had been added to F5 Appendix B but never analyzed in the event of a hot short. These MOVs could be affected by a fire in FA 13 (Control Room) and FA 18 (Relay and Cable Spreading Room). This unanalyzed condition could impact the ability of plant operators to implement procedure F5 Appendix B. Therefore, the station reported this unanalyzed condition under 10 CFR 50.72(b)(3)(ii)(B) on 12/21/2015 as EN 51616. New hourly fire watch impairments were created in these fire areas as compensatory measures.

After submittal of EN 51616, the review was further expanded for all credited MOVs which resulted in identifying additional MOVs that would not survive a hot short condition if a fire were to occur in the following fire areas: FA 31 ("A" Train Hot Shutdown Panel & Air Compressor/Auxiliary Feedwater Room, 695), FA 32 ("B" Train Hot Shutdown Panel & Air Compressor/ Auxiliary Feedwater Room, 695), FA 58 (Auxiliary Building Ground Floor U1), and FA 73 (Auxiliary Building Ground Floor U2). EN 51616 was updated on 01/14/2016 listing the additional fire areas and the compensatory actions of new hourly fire watch impairments.

Event Analysis

On February 28, 1992 the NRC released Information Notice 92-18 (IN 92-18), Potential for Loss of Remote Shutdown Capability During a Control Room Fire, addressing the potential for a control room fire causing electrical short circuits ("hot shorts") between normally energized conductors and conductors associated with the control circuitry of motor-operated valves (MOVs) required for achieving and maintaining post-fire safe shutdown conditions. This could result in a loss of capability to achieve or maintain safe shutdown conditions 2

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prompted the 12/15/2015 event notification, and the updated notification on 01/14/2016, for an unanalyzed condition due to non-compliant fire protection manual operator actions reportable under 10 CFR 50.72(b)(3)(ii)(B). Compensatory measures were initiated in affected fire areas.

EN 51616 was submitted to the NRC.

During the causal evaluation for the LER, PINGP reviewed its response to a 1997 Unresolved Issue (URI) regarding the review of MOVs in accordance with IN 92-18 (Accession Number 9710200112). The response stated PINGP would use IN 92-18 as guidance to perform additional reviews of the hot short problem following the completion of the Appendix R safe shutdown analysis and create an accurate list of MOVs susceptible to hot shorts (ADAMS Accession Number 9711200012). On August 7, 1998, calculation ENG-ME-353, Mechanical MOV Analysis to support IN 92-18 determined the valve and operator thrust and torque values that may occur during a hot short that bypasses the limit switches and torque switches. The calculation addressed 46 Appendix R related valves and found 32 could potentially be damaged during a fire induced hot short requiring modifications and revision to the Appendix R safe shutdown analysis.

During a fire, a hot short could cause the MOV to operate without its torque/limit switch protection, damaging the valve and preventing manual operation of the valve. All credited MOVs for safe shut-down were reviewed for this condition and seventeen MOVs were found susceptible.

Susceptible MOVs Eleven (11) MOVs require modification to re-wire the torque and limit switches to prevent damage to the actuator:

3 infocollects.Resource@nrc.goy, and to the Desk Officer, Office of Information and Regulatory Affairs, Prairie Island 05000282 1) MV-32006, 1 TURB GLND STM SL SPLY UPSTRM SO MV 2) MV-32010, 1 TURB GLND STM SL SPLY B-P MV 3) MV-32016, 11 SG MS SPLY TO 11 TD AFW PMP MV 4) MV-32017, 12 SG MS SPLY TO 12 TD AFW PMP MV 5) MV-32019, 21 SG MS SPLY TO22 TD AFW PMP MV 6) MV-32020, 22 SG MS SPLY TO 22 TD AFW PMP MV 7) MV-32021, 2 TURB GLND STM SL SPLY UPSTRM SO MV 8) MV-32022, 2 TURB GLND STM SL SPLY B-P MV 9) MV-32238, 11 AFW TO 11 SG MV 10) MV-32246, 22 AFW TO 21 SG MV 11) MV-32333, 11 TD AFW PMP SUCT FROM CST MV Six (6) MOVs require PINGP to revise the Appendix R safe shutdown analysis to credit actions to isolate other valves or to credit check valves.

1) MV-32115, 122 SFP HX INLT HDR MV B 2) MV-32117, 121 SFP HX INLT HDR MV A 3) MV-32166, 1 REAC EXCS LTDN LINE ISOL MV A 4) MV-32194, 2 REAC EXCS LTDN LINE ISOL MV A 5) MV-32335, 12 MD AFW PMP SUCT FROM CST MV 6) MV-32336, 21 MD AFW PMP SUCT FROM CST MV The causal evaluation for this event determined the cause was the failure to include ENG-ME- 353 as an input to the Appendix R safe shutdown analysis. Because of this exclusion, the site did not update ENG-ME-353 to include new weak link data to support the Appendix R safe shutdown analysis.

Additionally, the causal evaluation identified inadequate supervisory oversight during the transition to NFPA 805 that contributed to the event. When one engineer was assigned to both the Appendix R program and the transition to NFPA 805 resulting in untimely responses, in a 4

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Infocollects,Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, 05000282 Prairie Island

NO

manner commensurate with their safety significance, to previously identified deficiencies for compliance with IN 92-18.

Safety Significance

The NFPA 805 License Amendment identified the need to revise ENG-ME-353 to incorporate updated vendor information (ADAMS Accession Number ML12278405). During the revision of ENG-ME-353, this issue was identified, There were no structures, components or systems that were inoperable at the start of the event that contributed to the event.

There was no nuclear, environmental, radiological or industrial safety consequences related to this event. PINGP has procedures and controls in places to minimize the likelihood and severity of fires occurring, and a significant fire impacting the ability to safely shutdown did not occur.

This postulated fire scenario requires that a significant fire of sufficient size and intensity to damage MOV control cables and bypass torque and limit switches to cause spurious operation and damage to MOVs. The frequency of fires large enough to damage control cables is much lower than the generic fire ignition frequency that includes fires of all intensities. To damage the MOV, the fire must cause damage to cable insulation to the point that an energized conductor shorts around the torque and limit switches to the MOV control circuit for sufficient time for the MOV to stroke to the opposite position without open circuit or short to ground.

Causes PINGP failed to include ENG-ME-353 as an input to the Appendix R safe shutdown analysis which led to failure to update ENG-ME-353 to include new weak link data.

During the original analysis for IN 92-18, only a specified list of MOVs was reviewed to be credited; however, additional MOVs were added without the required analysis to support survivability.

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Corrective Actions

• The Appendix R safe shutdown analysis for the fire protection program will be updated to include ENG-ME-353 in the methodology section.

• Document actions necessary to address the 17 MOVs.

o Eleven (11) MOVs require modification to re-wire the torque and limit switches to prevent damage to the actuator:

® MV-32006, 1 TURB GLND STM SL SPLY UPSTRM SO MV ® MV-32010, 1 TURB GLND STM SL SPLY B-P MV ® MV-32016, 11 SG MS SPLY TO 11 TD AFW PMP MV ® MV-32017, 12 SG MS SPLY TO 12 TD AFW PMP MV

• MV-32019, 21 SG MS SPLY TO 22 TD AFW PMP MV

• MV-32020, 22 SG MS SPLY TO 22 TD AFW PMP MV ® MV-32021, 2 TURB GLND STM SL SPLY UPSTRM SO MV ® MV-32022, 2 TURB GLND STM SL SPLY B-P MV ® MV-32238, 11 AFW TO 11 SG MV ® MV-32246, 22 AFW TO 21 SG MV ® MV-32333, 11 TD AFW PMP SUCT FROM CST MV ® Six (6) MOVs require PINGP to revise the Appendix R safe shutdown analysis to credit actions to isolate other valves or to credit check valves.

0 ® MV-32115, 122 SFP HX INLT HDR MV B ® MV-32117, 121 SFP HX INLT HDR MV A ® MV-32166, 1 REAC EXCS LTDN LINE ISOL MV A ® MV-32194, 2 REAC EXCS LTDN LINE ISOL MV A ® MV-32335, 12 MD AFW PMP SUCT FROM CST MV ® MV-32336, 21 MD AFW PMP SUCT FROM CST MV 6

Previous Similar Events

Damage by Fire Induced Hot Shorts" was submitted on September 7, 1998 (ADAMS Accession Number 9809150244).

Corrective Actions

• Compensatory fire watches in each affected area until the affected MOVs had been evaluated or modified as described below:

a. Re-evaluate MOVs to identify alternate shutdown systems, components, or flow paths that are not susceptible to damage and revise the Safe Shutdown Analysis accordingly, or b. Modify MOV's mechanically to prevent mechanical damage (e.g.

smaller motor), or c. Modify MOV's electrically to prevent hot short susceptibility (e.g. hold the MOV circuit breaker open or rewire the MOV control circuit).

• Submit a schedule of corrective actions after the engineering review is completed.

submitted on October 26, 1998 (ADAMS Accession Number 9810300149).

Corrective Actions

• Include MOV's MV-32075, MV-32076, MV-32077, MV-32078, MV-32178, MV- 32179, MV-32180, and MV-32181 in the Appendix R safe shutdown equipment list. Complete the circuit analysis packages for the valves with recommendations to provide assurance of maintaining the flow diversion path closed.

• Evaluate the valves for IN 92-18 damage concerns. If the valves could be mechanically damaged during spurious operation, circuit modifications will be performed as required under the IN 92-18 program. Results of this evaluation will be provided in a Supplement to LER 1-98-10.

7 NRC with a schedule of the corrective actions as committed to in the original submittal (ADAMS Accession Number 9904150006).

8

On February 15, 2012, a reportability review was completed regarding an error identified in the pre operation test records for the Unit 1 diesel generators (D1 and D2). The error, along with the subsequent discovery of an additional error regarding fuel oil energy content assumptions, affected the fuel oil storage calculation, which increased the volume of stored diesel fuel required to operate D1 or D2 and a diesel-driven cooling water pump for 14 days in the event of a postulated maximum probable flood. A review using the corrected values determined that for a single period of up to 738 continuous hours and 2202 total hours in 2010 the revised requirements were not met, rendering D1 and D2 inoperable.

Compensatory measures were updated to ensure a minimum 14-day supply of diesel fuel oil until a previously submitted Technical Specification amendment to revise LCOs 3.7.8 and 3.8.3 is approved.

On July 1, 2011, Prairie Island Nuclear Generating Plant (PINGP) Unit 1 was manually tripped from approximately 100% steady-state power. The manual reactor trip was in response to the right main turbine stop valve failing closed as the result of an Electro-Hydraulic (EH) oil leak located at the stop valve. As designed, 11 and 12 Auxiliary Feed Water (AFW) pumps auto started on steam generator low water level.

The causal evaluation determined that right main turbine stop valve failed closed due to excessive oil leakage from a failed 0-ring. An age related compression set and slight extrusion near the outside contact surface resulted in the failed 0-ring.

Safety related battery chargers have the potential to stop providing an output, or "lock up", if their AC input voltage drops below their nameplate minimum voltage of 90% of 480V at the battery charger Motor Control Center. Exact voltage, duration of voltage dip, and charger loading conditions which cause lock up of chargers are unknown.0If a reduction in input voltage results in a battery charger locking up, the battery charger will not be able to recharge the battery from a partially discharged state unless operator actions are taken to restore the battery charger.

On October, 22, 2010, an operability determination concluded that specific Design Basis Accident scenarios may include this undervoltage condition which could cause the battery chargers to lock up. The design basis requirements of the safeguards battery are such that it can carry expected shutdown loads for the DC system for one hour. Compensatory measures in the form of new operator actions have been put in place to support restoration of the battery chargers within this timeframe.