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On December 15, 2016, the Unit 3 "B" train (3B) diesel generator (DG) experienced a failure during the performance of a monthly surveillance test. At 0356 Mountain Standard Time, a master connecting rod mechanically failed and caused significant damage to the 3B DG. Unit 3 control room staff declared the 3B DG inoperable and entered Technical Specification Limiting Condition for Operation (LCO) 3.8.1, AC Sources - Operating, Condition B. To support repairs, Palo Verde Nuclear Generating Station (PVNGS) received two license amendments to extend the LCO 3.8.1, Condition B required action completion time for the 3B DG from 10 days to 62 days. PVNGS Unit 3 continues to operate at 100 percent power.

The preliminary cause analysis indicates that the 3B DG master connecting rod failed due to high cycle fatigue caused by misalignment of the crankshaft bore introduced by a previous failure that occurred in 1986. The failure mechanisms that caused the 1986 and 2016 3B DG failures are not present in any other PVNGS DG.

PVNGS has completed significant disassembly, repair, and reassembly of the 3B DG, and testing efforts are ongoing. The cause investigation is still in progress, and the results will be reported in a supplement to this Licensee Event Report.

No previous similar events have been reported by PVNGS in the last 3 years.

On August 13, 2015, at approximately 2106, the Unit 3 main steam isolation valve SGE-UV-181 (MSIV-181) B actuator train was declared inoperable and Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2, Condition A, was entered due to a failed fitting on the air supply line. To correct the condition the failed fitting was replaced and an additional pipe support was installed on the air-line. Following retests, the MSIV-181 B actuator train was restored to operable status and LCO 3.7.2, Condition A, was exited on August 15, 2015, at approximately 1830.

A similar air-line fitting failure had occurred on the Unit 3 MSIV-181 B actuator train on May 19, 2015. The investigation of this condition following the second failure determined the MSIV-181 B actuator train air-line configuration was modified in the spring 2015 Unit 3 refueling outage and was inoperable from the time Unit 3 entered Mode 4 on May 1, 2015, at 0258, following the outage because the air-line tubing was not adequately supported following the design change.

The investigation of the two fitting failures is still in progress. The cause of this condition and any additional corrective actions will be reported in a supplement to this Licensee Event Report.

No similar conditions have been reported by PVNGS in the last three years.

On May 30, 2015, emergent maintenance on the Unit 3 train A high pressure safety injection (HPSI) pump motor outboard journal bearing performed under Nuclear Regulatory Commission (NRC) approved notice of enforcement discretion 15-4-01 exceeded the Technical Specification Limiting Condition for Operation (LCO) completion time for LCO 3.5.3, Emergency Core Cooling Systems - Operating, Condition C.1. The HPSI pump had been removed from service on May 27, 2015, at 0628, for planned routine maintenance. During maintenance, it was discovered that the motor outboard journal bearing was damaged. The bearing was replaced and the pump was declared operable on May 30, 2015, at 1710.

The root cause was work instruction weaknesses which resulted in improper reassembly of the HPSI pump motor during planned maintenance in the Unit 3 spring 2015 refueling outage. Immediate corrective actions replaced the damaged outboard motor bearing and properly reassembled the pump and motor. To prevent recurrence, maintenance procedures will be revised to provide enhanced guidance for pump and motor reassembly. An additional action will determine training enhancements needed to address weaknesses with maintenance personnel knowledge.

No previous-similar events have been reported to the NRC by PVNGS in the prior three years.

in preparation for plant startup. On May 2, 2015, when plant conditions needed to test atmospheric dump valves (ADV) with steam were achieved, testing of ADVs was initiated. At 1739 on May 2, 2015, testing determined that ADV SGB-HV-178 (ADV-178) would not stroke more than approximately 13 percent open. Operations personnel declared ADV-178 inoperable and entered Technical Specification Limiting Condition of Operation (LCO) 3.7.4, Atmospheric Dump Valves, Condition A. An investigation determined ADV-178 was inoperable when Unit 3 entered Mode 4.

Inspection of ADV-178 determined internal sealing rings were improperly installed during maintenance performed in the refueling outage. The valve was repaired and tested and declared operable at 0853 on May 7, 2015. The causes of the event were human error by maintenance personnel and inadequacies with the procedure used to perform the valve maintenance. Corrective actions will revise work instructions to provide detailed guidance for valve re-assembly and to require verifications of proper re-assembly.

A similar event was reported in LER 50-529/2012-003-00 which resulted when testing in Mode 3 following refueling activities identified an inoperable steam supply valve for the steam driven auxiliary feedwater pump.

On December 03, 2013, at approximately 0130, Unit 3 was in Mode 1 at 40 percent power recovering from a dropped Control Element Assembly (CEA) when the Required Action Completion Times of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.2.1, Linear Heat Rate (LHR), and TS LCO 3.2.4, Departure from Nucleate Boiling Ratio (DNBR), were exceeded. Condition C of both LCO 3.2.1 and LCO 3.2.4 requires power to be hours if the Completion Time of Condition A is not met. During response to the event, the LHR and DNBR LCOs were inappropriately exited and the Completion Time of Condition C was exceeded by 12 minutes. This condition was identified during a post-event review of plant data by plant personnel on December 15, 2013.

The cause of exceeding the required action completion times was the operating crew inappropriately exited LCO 3.2.1 and LCO 3.2.4 prior to fully understanding and reconciling instrument and alarm discrepancies.

Planned corrective actions will revise procedure 40DP-90P02 "Conduct of Shift Operations" to add guidance and actions for Operations personnel prior to exiting a LCO. The revised guidance will require independent review of decisions to exit LCOs. A case study of this event will be developed and presented to licensed operators and shift technical advisors during Licensed Operator Continuing Training. Also, procedure 40A0-9ZZ11 "CEA Malfunctions" will be revised to incorporate lessons learned from this event.

No similar events have been reported to the NRC by PVNGS in the prior three years.

On January 19, 2011, at approximately 1840 Mountain Standard Time, Unit 3 was at 100 percent power at normal operating temperature and normal operating pressure when the main feedwater pump A minimum flow recirculation valve (mini-flow valve) failed open causing a percentage of feedwater flow to be diverted to the condenser. Subsequently, Unit 3 experienced a reactor power cutback when main feedwater pump B tripped on low suction pressure. The combination of the main feedwater pump B trip and the main feedwater pump A mini-flow valve failure caused both steam generator water levels to lower causing an automatic reactor trip.

Both steam generator levels continued to drop which initiated an auxiliary feedwater actuation signal. The plant was stabilized in Mode 3.

The failed open mini-flow valve was caused by a failed diaphragm in a pneumatic 3-way precision relay within the mini-flow valve control loop. The relay was replaced and Unit 3 was returned to 100 percent power on January 23, 2011, at approximately 0100.

No similar conditions have been reported by Palo Verde in the past three years.

During an extent of condition review for events that could have led to the obstruction of the Containment Spray (CS) system, Arizona Public Service (APS) identified an April 21, 2007, event where nozzles in the Unit 3 CS system may have become obstructed. On December 5, 2007, while performing a Surveillance Test of the Unit 3 CS spray nozzles, APS personnel discovered one obstructed nozzle on each of two separate Containment Spray (CS) train 'A' lines. The evaporation of borated water from a header overfill event caused boric acid residue to accumulate and obstruct the two CS nozzles for a period greater than allowed by Technical Specification 3.6.6 limiting condition for operation. The nozzles were cleaned and restored to service on December 18, 2007.

The cause of the CS overfill event was determined to be leakage by the containment spray train 'A' discharge valve seat. The cause of the Unit 3 CS system nozzles blockage was from inadequate consideration of the consequences of overfilling the CS system with borated water.

There have been no previous similar events in the past three years that had a similar failure mechanism or that should have prevented this event as a result of previously implemented corrective actions.

On January 11, 2015, at 0024, Unit 2 received a plant computer monitoring system (RJ) alarm on point SASB22, indicating the setpoint for the bistable relay that compares pressures between Steam Generators (SGs) was approaching the technical (RK) and went unnoticed until late in the shift. Operators then verified the annunciator for SG differential pressure (DP) was not alarming and SG pressures were normal. The significance of the RJ alarm was not apparent because the value was displayed in units of voltage versus DP.

On January 24, 2015, further questioning determined the setpoint for the bistable that monitors differential pressure between SGs had exceeded its allowable value. Channel B SG Pressure Difference-High was declared inoperable and SG Level 2-Low was placed in bypass per LCO 3.3.5, Condition A.

The direct cause of the event was setpoint drift of the SASB22 bistable relay caused by potentiometers that had not recently been wiped clean. The root cause was the lack of an annunciated alarm for SASB22 and associated alarm response procedure to ensure the alarm condition was promptly acknowledged, understood, and correctly addressed within TS time limitations.

No previous similar events have been reported to the NRC by PVNGS in the prior three years.

On November 6, 2014, at approximately 1116 Mountain Standard Time, Unit 2 was in Mode 1, 100 percent power, when control element assembly (CEA) 15 dropped fully into the core while the 88 other CEAs remained fully withdrawn.

Operations entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.1.5, Condition A, for one CEA misaligned from its group which requires a power reduction and restoration of CEA alignment. An initial power reduction was performed in accordance with TSs and attempts to repair the problem were initiated. The CEA could not be aligned within the 2 hour TS time limit and TS LCO 3.1.5, Condition C was entered at 1316 which required entry into Mode 3 within 6 hours. The power reduction was continued and the reactor was manually shutdown at 1636 to comply with TSs.

The direct cause of the event was a failed upper gripper coil on the control element drive mechanism (CEDM) for CEA 15.

The failed coil was replaced and Unit 2 was restarted and entered Mode 1 at 0332 on November 13, 2014. Operation of the coil at elevated temperatures accelerated thermal degradation of the coil insulation. A preventive maintenance strategy for establishing coil voltages and online CEDM coil monitoring, and adjustment, if necessary, was implemented.

In the previous 3 years, similar events related to malfunctions of control element drive mechanism control system equipment that resulted in a plant shutdown were reported in LERs 50-528/2011-004, 50-528/2011-005 and 50-530/2012-001.

On December 2, 2013, Unit 2 was operating in Mode 1 at 100 percent power. At approximately 1758 Mountain Standard Time a reactor trip was automatically actuated when reactor coolant pump (RCP) 1A speed dropped below 95 percent of rated speed which generated low departure from nucleate boiling ratio and high local power density trips on all four channels of the plant protection system. The reactor trip was determined to be uncomplicated and the reactor trip procedure was implemented to stabilize the plant in Mode 3. Operations personnel subsequently determined the RCP 1A motor circuit breaker tripped on excessive phase differential current.

The probable cause of the RCP 1A motor circuit breaker trip was a high impedance fault within the C phase of the motor stator coil. The faulted RCP 1A motor was replaced with an on-site spare RCP motor and Unit 2 was returned to power operation on December 14, 2013.

The faulted motor has been sent to an off-site facility for disassembly and root cause analysis.

No previous similar events involving an automatic RPS actuation due to a RCP motor failure have been reported to the NRC by PVNGS in the prior three years.

On October 8, 2012, at 13:30, when Unit 2 was in Mode 5 during refueling outage 2R17, Shutdown Cooling System (SDC) Train A was declared inoperable in accordance with Technical Specification 3.4.7 due to a leak on a Low Pressure Safety Injection (LPSI) system Train A drain pipe during SDC operation. The leakage source was a weld defect on the LPSI cold leg 1A injection pipe drain connection upstream of drain valve SIA-V908. The leakage was first discovered on October 7, 2012, at 22:00 when water on the floor adjacent to the LPSI cold leg 1A injection pipe was first found, but not identified as leakage through the drain pipe weld until insulation was removed on October 8, 2012.

A configuration control problem in the early 1990s allowed contact between the drain pipe and a pipe hanger when the SDC system was in operation. This resulted in a weld defect being introduced due to the high cyclic stresses from the pipe/hanger contact. The configuration control problem was corrected in May 1993; but, the weld defect propagated slowly during periods of SDC operations until the leak occurred in the 2R17 outage.

The cause was determined to be inadequate guidance to ensure temporary fittings on safety-related fluid systems were removed prior to placing the system in service. To prevent recurrence, procedures were revised to require that systems with capped pipe ends be returned to their design configuration following maintenance.

On February 3, 2007, Unit 2 was in Mode 1 at approximately 100 percent power performing a surveillance test (ST) to demonstrate the operability of full strength Control Element Assemblies (CEA) by moving each CEA five inches. While performing this test, Shutdown Group B, Subgroup 6 failed to withdraw after it was successfully inserted five inches. This left the CEA Subgroup at 144 inches, which is below the limit as required by Technical Specification (TS) Limiting Condition for Operation (LCO) 3.1.6. Unit 2 entered TS LCO 3.1.6, condition A and TLCO 3.1.204 condition A at approximately 12:32 Mountain Standard Time (MST). At approximately 13:15 (MST), Unit 2 Operators entered LCO 3.0.3 due to more than one CEA inserted beyond the TS limit.

At approximately 16:16 (MST) on February 3, 2007, following corrective maintenance to replace a phase synchronization card, CEA Subgroup 6 was restored above the TS 3.1.6 insertion limit and Unit 2 exited LCO 3.0.3. The cause of the failed phase synchronization card was determined to be the random failure of a ceramic capacitor.

In the past three years, there were no similar events reported for multiple CEAs being inserted beyond TS Limits.

On December 22, 2006, the Palo Verde Nuclear Generating Station (PVNGS) received a Final Significance Determination letter from the Nuclear Regulatory Commission (NRC) for Apparent Violations received during an NRC Heat Exchanger Performance inspection. The NRC concluded in the letter that the Unit 2 Essential Cooling Water, Train B heat exchanger was Inoperable and a Technical Specification (TS) 3.7.7 violation for a period of 78 days occurred, ending on September 27, 2003 when Unit 2 was shutdown for a refueling outage (U2R11). The subject heat exchanger was restored to Operable during the refueling outage. Essential Cooling Water, Train A heat exchanger was functional for the 78 day period that EW 2B was considered inoperable.

As a result of other heat exchanger problems, in May 2006, Arizona Public Service (APS) initiated an investigation of the Essential Cooling Water heat exchangers and the chemistry controls for the Spray Pond System. The APS investigation identified system problems with chemistry control, equipment maintenance and organizational weakness which allowed the problems to develop and remain uncorrected for an extended period. A number of corrective actions were implement or are being implement which include restoring effective chemistry controls of the system, procedure changes, personnel training, and equipment modification.

In the past three years, there were no similar events reported.

On July 16, 2006 at approximately 14:52 Mountain Standard Time (MST) Unit 2 was operating at 100 percent power, Model (power operations), when an Area Operator (AO) notified the control room that door C-A-06 was found open with no compensatory measures established.

Door C-A-06 is a watertight fire door that functions as the train separation barrier between Auxiliary Feedwater (AF) pump rooms 'A' and 'B.' When door C-A-06 is open with the unit operating in Mode 1, compensatory action must be taken in order to maintain both trains of AF operable. The AO who discovered door C-A-06 open and unattended, closed the door immediately. Based on a review of security computer transaction logs, control room personnel determined that door C-A-06 was open with no compensatory actions in place for approximately 4 hours and 20 minutes. As such, AF trains 'A' and 'B' were considered inoperable between 10:32 and 14:52 (MST). Based on further review and personnel interviews, an investigation concluded that a Fire Department Emergency Services Officer (ESO) had failed to close C-A-06 after leaving the AF pump room.

In the past three years, there were two similar events reported (LER 50-529/2005-003-00, and 50-530-2006-001-00).

On December 31, 2004, at approximately 1042 Mountain Standard Time (MST), Units 2 and 3 were operating in MODE 1, at approximately 100 percent power, when Arizona Public Service Company (APS) Transmission and Distribution (T&D) personnel inadvertently tested a relay for the 525 kilovolt (kV) Westwing #2 transmission line that resulted in the Westwing #2 line relaying out and disrupting power to the PVNGS NAN-X01 startup transformer.. - 7 . .

Disruption of power to the NAN-X01 startup transformer resulted in the loss of offsite power to the Unit 2 train "A" engineered safety features (ESF) 4.16 kV class electrical buss and Unit 3 train "B" ESF 4.16 kV class electrical buss. The loss of power to the Unit 2 and 3 ESF 4.16 kV class electrical busses caused auto-starts of the associated diesel generators to supply power to the Unit 2 "A" Train PBA-S03 class bus and the Unit 3 "B" Train PBB-SO4 class bus. All equipment responded satisfactorily. By 1107 MST, power to the Westwing #2 transmission line and startup transformer NAN-X01 had been restored. Previous similar events have been reported in LERs 50 528/2004-006 and 50-530/2003-004.

On April 17. 2017, the staff identified a low refrigerant level in the Unit 1 train B essential chilled water (EC) system chiller during inspection. Operations personnel immediately declared EC chiller train B inoperable. On April 17, 2017, the leak was corrected and EC chiller train B was refilled with refrigerant to within the manufacturer's specifications. Operations personnel declared the system operable on April 18, 2017. The chiller had been inoperable since April 11. 2017, when the automatic purge system was placed into service. The direct cause of the low refrigerant level was leakage due to prior installation of a fitting on the automatic purge system filter without a plug.

During the 7-day period that EC chiller train B was inoperable, the supported low pressure safety injection (LPSI) system train B was inoperable. LPSI train A was also inoperable for approximately 17 minutes on April 13, 2017, during the performance of a routine surveillance test. This 17-minute period represented a condition that could have prevented the fulfillment of a safety function.

The cause of the leak was determined to be ineffective work instructions that did not identify the appropriate part number to be used during filter replacement. Corrective actions include revision of the work instructions. This change will ensure that the existing plug remains in place during filter element replacement. A leak test was also added to the work instructions to verify that no refrigerant leaks are present following maintenance.

On September 7, 2016, at 2131, with Unit 1 in Mode 1 and 100 percent power, the reactor was manually tnpped and reactor coolant pumps were secured due to a control malfunction which prevented closure of a pressurizer spray valve. This event initiated from an unsuccessful attempt to transfer a non-class 120VAC instrument power bus from its normal source to its emergency/alternate source. The transfer was attempted to facilitate an inspection of an electrical load center which was sprayed with water earlier in the day by a leaking sprinkler head following Fire Protection (FP) Department routine testing of a FP water line.

The cause of the spray valve malfunction was a failed pneumatic volume booster in the spray valve actuator system combined with a current to pressure converter (I/P) calibration offset which resulted from a voltage transient during the unsuccessful electrical transfer. These conditions caused the spray valve to stay approximately five percent open when it received a close demand from the spray valve controller. The I/P converter and pneumatic volume booster were replaced and the spray valve was returned to service. Additional corrective actions will adjust preventive maintenance frequency on the pneumatic volume boosters.

In the past three years, PVNGS has not reported a similar event to the NRC.

On April 10, 2014, a post-event review conducted in response to a proposed NRC non-cited violation concluded the actions to close and deactivate main steam isolation valve SGE-UV-170 (MSIV-170) to address an equipment malfunction on November 6, 2013, did not meet the operability requirements of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2. As a result, the requirement of LCO 3.7.2 Condition G to place the unit in Mode 2 within 6 hours was not completed. MSIV-170 was repaired and returned to service on November 9, 2013.

An 'investigation determined the cause of the condition prohibited by TSs was the operability determination (OD) was overly focused on the ability of the MSIV to perform its specified safety function and did not adequately consider the definition of operability and compliance with the TS. To prevent recurrence, PVNGS OD guidance will be revised to explicitly require evaluation of applicable LCOs to ensure the OD technical conclusions support compliance with the LCOs.

No similar events have been reported to the NRC by PVNGS in the prior three years.

This LER reports the failure of components caused by a defect in ARD66OUR control relays reported by Westinghouse, pursuant to 10 CFR 21, on April 8, 2013. The defect resulted in the failure of five normally energized control relays at PVNGS in two different systems in Unit 1 and two different systems in Unit 2.

The relays were used in normally energized applications which are de-energized to position associated components to support the related safety function. The relays failed to change state when de-energized during testing.

The five failed relays were replaced. The cause was a change in the manufacturing process that occurred in May 2008. The defect was exhibited only on relays that failed in the manner described in the Westinghouse Part 21 report. An extensive testing program was completed to identify and replace ARD66OUR relays installed at PVNGS that exhibited the described failure mode. Westinghouse has modified the ARD66OUR relay plastic molding process to preclude this described failure mode. LER 05000529 / 2009-002-00 reported ARD66OUR relay failures that exhibited a similar failure mode.

On December 21, 2012, PVNGS discovered that previous revisions of surveillance test (ST) procedures to conduct safety injection system (SI) injection line check valve testing allowed system alignments that could have resulted in less than the minimum required emergency core cooling system (ECCS) flow described in the safety analysis and licensing bases. The ST procedures directed closure of the manual discharge isolation valve for the train B high pressure safety injection (HPSI) pump and directed opening of a manual drain valve on one of the four SI injection headers which created a potential for diversion of a portion of the ECCS flow provided by the train A HPSI pump.

The latent procedure deficiencies existed since 1983. The root cause was the procedure review process failed to identify the latent procedure deficiencies affecting both ECCS trains. The ST procedures were revised so that system alignments for SI injection line check valve testing ensure availability of at least 100 percent of ECCS flow equivalent to a single operable ECCS train. To prevent recurrence, the procedure process will be revised to identify and resolve common train impacts on design and licensing bases involving safety systems during procedure reviews.

A similar event has not occurred in the prior three years that required reporting.

On May 9, 2012, a review of the procedural guidance for inoperable essential ventilation equipment by an investigation team concluded that a condition prohibited by Technical Specifications (TS) had occurred in unit 2 on January 22, 2012, when the TS requirements for electrical distribution equipment were not met.

On January 22, 2012, during surveillance testing in unit 2, a control relay did not change state as expected and the essential ventilation dampers controlled by this relay did not change position. Operations declared the affected essential air handling units inoperable. The TSs do not contain specific Limiting Conditions for Operation (LCO) requirements for the affected essential ventilation equipment and no TS LCO Conditions were entered. Operations followed existing procedural guidance for inoperable ventilation equipment. The procedural guidance required operations to verify that there was no loss of safety function and that normal room cooling was available.

The cause of the event was an inadequate procedure that was based on an incorrect understanding of the relationship between essential ventilation equipment that provides a support function to electrical distribution equipment and operability of the electrical distribution equipment. As corrective action, the affected procedure was revised.

Similar reportable events have not occurred in the past three years.

On April 13, 2011, control room essential filtration system (CREFS) outside air intake (OSA) dampers were found to be in the normally closed position instead of the normally open position stipulated in the updated final safety analysis report. This incorrect configuration was the result of procedure changes made in 1986.

Each train of the CREFS system contains two OSA dampers in series, with each damper actuated from one of the two separate channels of the control room essential filtration actuation signal (CREFAS). Upon identification, Unit 1 and Unit 3 entered Technical Specification (TS) 3.3.9, condition A when both channels of CREFAS were determined to be inoperable. In response, both units placed an OPERABLE train of CREFS into operation per required action A.1. Unit 2 was defueled and irradiated fuel assemblies were not being moved; therefore, TS 3.3.9 was not applicable to Unit 2 at the time this condition was identified.

In the three years prior to this event, a similar legacy issue was reported in which station procedures directed system configurations not permitted by the plant design (LER 0500528/529/530/2009-001-00, Safety Injection System Recirculation Alignment Results in Unanalyzed Condition).

On February 21, 2011, at approximately 2001 Mountain Standard Time, a valid actuation of the circuitry that starts the emergency diesel generators (EDG) for Palo Verde Nuclear Generating Station Unit 1 train 'B' and Unit 3 train 'A' occurred due to an undervoltage condition on their respective 4.16 kV safety buses. Both EDGs started and loaded as designed.

The loss of power to the Unit 1 and Unit 3 safety buses was the result of a protective relay actuation on the AE-NAN-X02 startup transformer which de-energized the transformer and the Unit 1 13.8 kV intermediate bus 1E-NAN-S06 and the Unit 3 13.8 kV intermediate bus 3E-NAN-S05. The affected intermediate buses provide offsite power to the Unit 1 safety bus 1E-PBB-SO4 and the Unit 3 safety bus 3E-PBA-S03 respectively.

The cause of the undervoltage was a cable splice failure on the cable for the 'Y' winding of the AE-NAN-X02 startup transformer.

Unit 1 and Unit 3 entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.8.1, Condition A, for one required offsite circuit inoperable. Offsite power was restored to Unit 1 safety bus through the intermediate bus from the altemate supply.

Offsite power was restored to Unit 3 safety bus through the intermediate bus from the altemate supply. The LCO condition was exited by Unit 1 and Unit 3.

No similar events involving a cable splice failure have been reported by PVNGS in the last three years.