05000413/LER-2012-001

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LER-2012-001,
Docket Number
Event date:
Report date:
Reporting criterion: 10 CFR 50.73(a)(2)(vii)(A), Common Cause Inoperability
10 CFR 50.73(a)(2)(iv)(A), System Actuation
10 CFR 50.73(a)(2)(vii), Common Cause Inoperability
10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications
10 CFR 50.73(a)(2)(v), Loss of Safety Function
10 CFR 50.73(a)(2)(v)(A), Loss of Safety Function - Shutdown the Reactor
4132012001R01 - NRC Website
v • d • e

BACKGROUND

This event is being reported under the following criteria:

10 CFR 50.73(a)(2)(i)(B), any operation or condition which was prohibited by the plant's Technical Specifications (TS). (Refer to Page 4 for detailed discussion.) 10 CFR 50.73(a)(2)(iv)(A), any event or condition that resulted in manual or automatic actuation of the Reactor Protection System (RPS) including: reactor scram or reactor trip; PWR auxiliary or emergency feedwater system; and emergency ac electrical power systems, including: emergency diesel generators (EDGs). (Refer to Page 6 for detailed discussion.) 10 CFR 50.73(a)(2)(v), any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) Shut down the reactor and maintain it in a safe shutdown condition; (B) Remove residual heat; (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident. (Refer to Page 10 for detailed discussion.) 10 CFR 50.73(a)(2)(vii), any event where a single cause or condition caused two independent trains or channels to become inoperable in a single system designed to: (A) Shut down the reactor and maintain it in a safe shutdown condition; (B) Remove residual heat; (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident. (Refer to Page 8 for detailed discussion.) Catawba Nuclear Station Units 1 and 2 are Westinghouse four-loop Pressurized Water Reactors (PWRs) [ENS:

RCT].

Systems Description:

The Main Power System [EDS: EL] for each Catawba nuclear unit includes the main generator [EllS: GEN] and a switchyard [EDS: FK] common to both nuclear units. A protective relaying network [EllS: FK] is provided for the Main Power System for each Catawba nuclear unit. It is the function of the protective relaying to detect faults and other abnormal conditions affecting equipment in the switchyard or associated with the main generator and isolate the affected equipment from the remaining equipment while reducing to a minimum the impact of the fault or isolation on the remaining equipment. The protective relaying system is partitioned into three zones: Zones A and B for that portion of the switchyard associated with a nuclear unit and the main generator of that unit, and Zone G for the main generator itself.

Zone G encloses the main generator, generator exciter [EllS: EXC], the generator isolated phase bus [EIIS:

IPBU], neutral grounding cubicle [EllS: None], and the main generator power circuit breakers (PCBs) [EIIS: 52].

Most of the Zone G protective relaying schemes cause the main generator PCBs to open, isolating Zone G from the other two zones. Some of the relaying schemes trip the exciter or the exciter and turbine [EllS: TRB]. Other protective relaying schemes block the closing of the motor operated disconnects (MODS) [EllS: MOD] for the main generator PCBs until the generator approaches operating speed, block the auto synchronizer [EllS: None] if a potential transformer (PT) [EllS: IPT] is lost, and trip the switchyard breakers in case of generator breaker failure or faults in the switchyard that are not cleared by switchyard relaying.

The Catawba 230kV switchyard is designed in a breaker-and-a-half scheme which allows any one of the switchyard PCBs to be isolated from the grid without deenergizing any transmission line or affecting the integrity of the switchyard. Six double-circuit transmission lines from the primary transmission system terminate in the switchyard. Additionally, each Catawba unit is tied to the 230kV switchyard by two separate and independent overhead lines. The entire switchyard, including the PCBs, cabling system, ac and dc auxiliary power systems, protective relaying system, and control system is also divided into two power trains. Additionally, the incoming transmission lines are also assigned to power trains in such a way as to separate the associated cabling, protective relaying, and controls for each circuit of the double-circuit transmission lines into two distinct sources of offsite power. The Catawba 230kV switchyard design assures the independence of the redundant offsite power feeders to each nuclear unit.

The 4160VAC Essential Auxiliary Power System [EIIS: EB] supplies power to those Class 1E loads required to safely shut down the unit following a design basis accident. This system is divided into two completely redundant and independent trains, each consisting of one 4160V switchgear assembly [EIIS: SWGR], three 4160V/600V transformers [EIIS: XFMR], two 600V load centers [EIIS: None], and associated loads. Normally, each Class 1E 4160V switchgear is powered from its associated non-Class 1 E train of the 6900VAC Normal Auxiliary Power System [EIIS: EA]. Additionally, an alternate source of power to each 4160V essential switchgear is provided from the 6900V system via two separate and independent 6900V/4160V transformers. These transformers are shared between units and provide the capability to supply an alternate source of preferred power to each unit's 4160V essential switchgear from either unit's 6900V system. A key interlock scheme is provided to preclude the possibility of connecting the two units together at either the 6900V level or the 4160V level. Each train of the 4160VAC Essential Auxiliary Power System is also provided with a separate and independent emergency diesel generator [EllS: EK] to supply the Class 1 E loads required to safely shut down the unit following a design basis accident.

The 4160VAC Blackout Auxiliary Power System [EIIS: EA] supplies power to those non-Class 1 E loads that may be required following a Loss of Offsite Power (LOOP). This system consists of two separate and independent 4160V switchgear assemblies, 4160V/600V transformers, 600V load centers, and their associated loads. This system is divided into two trains, with each train normally powered from its corresponding train of the 6900VAC Normal Auxiliary Power System via a separate 6900V/4160V transformer and feeder breaker. Each 6900V/4160V transformer also serves as the normal source to its associated 4160V essential switchgear. In the event that the normal source is not available, each blackout switchgear assembly can be supplied from the emergency diesel generator through a connection with its associated 4160V essential switchgear. Upon the loss of the normal source to each 4160V blackout switchgear, all loads are shed and the associated emergency diesel generator is started and automatically connected to its 4160V essential switchgear. All essential loads required during the blackout and all loads on the blackout switchgear that are required are then sequenced onto the emergency diesel generator.

Zone G Modification Description:

In May - June 2011, during the Unit 1 End-of-Cycle 19 Refueling Outage, the protective relaying system for Zone G was replaced. A similar replacement was subsequently performed during the Unit 2 End-of-Cycle 18 Refueling Outage. The purpose of the modification was to maximize the reliability of the protective function while minimizing the likelihood of spurious actuation. The modification consisted, in part, of adding a redundant train of protective relays for each function. Within each train, the protective relays are arranged in either a one-out-of-one (1/1) or a two-out-of-two (2/2) scheme for each function.

Of all of the functions affected by the modification, the following function is the one of importance relative to this event:

  • Generator Underfrequency (81L1/L2/L3/L4/L5). This function trips the switchyard unit tie breakers, separating the turbine generator from the grid. The previous (pre-modification) protection was provided by a series of relays and timers in a stepped protective relaying scheme at various settings at different frequencies. The initial design of the revised (post-modification) protection was to incorporate a blocking scheme when the generator is not connected to the grid. However,, this blocking scheme was not fully incorporated into the Zone G digital relay upgrades. The effect of this error was that during an unanticipated event such as a reactor trip, generator voltage remains above the voltage block setpoint and the underfrequency trip will actuate, isolating the nuclear unit from the switchyard. In contrast, during a planned event such as a normal reactor shutdown, generator voltage decays below the voltage blocking setpoint, preventing the undervoltage trip from actuating.

TS Requirements:

TS 3.8.1 compliance for Unit 1 and Unit 2:

TS 3.8.1 requires two offsite circuits, two EDGs, and the corresponding automatic load sequencers to be operable in Modes 1 through 4. From the Zone G modification implementation until the Unit 1 reactor trip occurred, both offsite circuits were available; however, they were technically inoperable. The improper implementation of the modification provided the mechanism by which the offsite circuits could be rendered unavailable under certain conditions (e.g., a reactor trip). However, they were not actually rendered unavailable until the reactor trip occurred.

Following the Unit 1 reactor trip, both Unit 1 offsite circuits were lost. At this time, Unit 1 entered TS 3.8.1 Conditions A and C. Condition A applies to one inoperable offsite circuit and Condition C applies to two inoperable offsite circuits. The time requirement for restoring the first offsite circuit to operable status (24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per Required Action C.2) was complied with. The time requirement for restoring the second offsite circuit to operable status (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per Required Action A.3) was also complied with. TS 3.8.1 did not apply to Unit 2 at the time that the offsite circuits were lost since Unit 2 was not in a mode of applicability.

SR 3.8.1.8 states: "Verify automatic and manual transfer of AC power sources from the normal offsite circuit to each alternate offsite circuit." This surveillance demonstrates that a transfer can be executed by opening the 6.9 kV normal feeder breaker upon loss of power and closing the 6.9 kV tie breaker. This provides power from the alternate offsite circuit to the 4 kV essential bus. When the Unit 1 reactor trip occurred on April 4, 2012, power was lost to both offsite circuits simultaneously. A transfer of power did not occur on 1TA (for Train A) or 1TD (for Train B) because no power source was available to transfer to. The issue with implementation of the Zone G modification had no impact on the 6.9 kV tie breakers or the capability to execute automatic or manual transfers.

Because Unit 1's offsite circuits were technically inoperable from the time of implementation of the Zone G modification, SR 3.8.1.8 was technically not met. Therefore, since the SR was not met, Limiting Condition for Operation (LCO) 3.8.1 was not met according to SR 3.0.1. Since action was not taken to shut down the unit as required, a TS violation resulted. SR 3.8.1.8 is applicable while the unit is in Modes 1 through 4; therefore, this SR was not met for Unit 1 and was not met for Unit 2 while it was in Modes 1 through 4 and aligned to Unit l's offsite circuits.

SR 3.8.1.12 states: "Verify on an actual or simulated Engineered Safety Feature (ESF) actuation signal each DG auto-starts from standby condition and: a. In 3950 V and 61.2 Hz; c. Operates for > 5 minutes; and d. The emergency bus remains energized from the offsite power system." According to the Bases for this SR, the ESF actuation signal is a LOCA signal. Since a LOCA signal will result in a SI signal, which will result in a reactor trip, item d. of this SR was technically not met for the time period that the Zone G modification was in place on Unit 1. Therefore, since the SR was not met, LCO 3.8.1 was not met according to SR 3.0.1. Since action was not taken to shut down the unit as required, a TS violation resulted. SR 3.8.1.12 is applicable while the unit is in Modes 1 through 4; therefore, this SR was not met for Unit 1 and was not met for Unit 2 while it was in Modes 1 through 4 and aligned to Unit l's offsite circuits.

SR 3.8.1.17 states: "Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ESF actuation signal overrides the test mode by: a. Returning DG to standby operation; and b. Automatically energizing the emergency load from offsite power." Item b. of this SR is subject to the same issue as item d. of SR 3.8.1.12 above. Therefore, since the SR was not met, LCO 3.8.1 was not met according to SR 3.0.1. Since action was not taken to shut down the unit as required, a TS violation resulted. SR 3.8.1.17 is applicable while the unit is in Modes 1 through 4; therefore, this SR was not met for Unit 1 and was not met for Unit 2 while it was in Modes 1 through 4 and aligned to Unit l's offsite circuits.

Conclusion: TS 3.8.1 requirements were not complied with for Unit 1 as a result of implementation of the Zone G modification. They were not complied with for Unit 2 while it was in Modes 1 through 4 and aligned to Unit l's offsite circuits.

TS 3.8.2 compliance for Unit 2:

TS 3.8.2 requires one offsite circuit and one EDG associated with the distribution system train required by TS 3.8.10 to be operable in Modes 5 and 6, and during movement of irradiated fuel assemblies. Since Unit 2's essential busses were aligned to Unit l's offsite circuits when the event occurred, the offsite circuits could not be credited for operability. This constituted a TS 3.8.2 violation for Unit 2.

Conclusion: While Unit 2 was in shutdown modes (Modes 5, 6, and No Mode), TS 3.8.2 requirements were not met.

In addition, due to the facts that: 1) some TS systems are shared between units and have additional operability requirements relative to non-shared systems (i.e., unlike non-shared systems, shared systems require both normal and emergency power for operability), and 2) other systems are in turn supported by these shared TS systems, the following additional TS were determined to have been violated as a result of cascading (although the systems governed by these TS remained available):

Shared systems' TS:

TS 3.7.8, "Nuclear Service Water System (NSWS)" TS 3.7.10, "Control Room Area Ventilation System (CRAVS)" TS 3.7.11, "Control Room Area Chilled Water System (CRACWS)" TS 3.7.12, "Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)" Supported systems' and other TS:

TS 3.4.6, "RCS Loops - MODE 4" TS 3.5.2, "ECCS - Operating" TS 3.6.6, "Containment Spray System" TS 3.6.17, "Containment Valve Injection Water System (CVIWS)" TS 3.7.5, "Auxiliary Feedwater (AFW) System" TS 3.7.7, "Component Cooling Water (CCW) System" TS 3.8.9, "Distribution Systems - Operating" TS 3.8.10, "Distribution Systems - Shutdown" TS LCO 3.0.3 When this event occurred on 04/04/12, Unit 1 was in Mode 1 at 100% power and Unit 2 was in Mode 5 during its End-of-Cycle 18 Refueling Outage. No other structures, systems, or components were out of service that had any effect on the event.

EVENT DESCRIPTION

Date/Time�Event (Some event times are approximate.) 05/11-06/11 Zone G relay modification installed on Unit 1 during the End-of-Cycle 19 Refueling Outage.

06/01/11/0518 Unit 1 entered Mode 4 following the completion of the End-of-Cycle 19 Refueling Outage.

07/23/11/1530 Unit 1 essential bus 1 ETA was aligned to its Unit 1 offsite circuit.

11/03/11/1535 Unit 1 essential bus 1ETB was aligned to its Unit 1 offsite circuit.

02/04/12/1555 Unit 2 essential bus 2ETA was aligned to Unit l's offsite circuit.

02/18/12/1256 Unit 2 essential bus 2ETB was aligned to Unit l's offsite circuit.

03/10/12/1157 Unit 2 entered Mode 5 in preparation for the End-of-Cycle 18 Refueling Outage.

03/12-04/12 Zone G relay modification installed on Unit 2 during the End-of-Cycle 18 Refueling Outage.

04/04/12/1943 Unit 2 entered Mode 5 following the completion of the End-of-Cycle 18 Refueling Outage.

2003�EDG 1B started due to trip of reactor coolant pump 1D and opening of feeder breaker 1ATD. The opening of feeder breaker 1ATD was unexpected and was due to a breaker coordination issue. This issue was evaluated under the Catawba Corrective Action Program.

Unit 1 reactor tripped on low reactor coolant system flow. Unit 1 generator PCBs opened following the reactor trip. Zone G protective relaying system actuated on the underfrequency condition and opened the switchyard breakers, isolating Unit 1 from the grid and resulting in a LOOP on Unit 1. (At the time of the trip, Unit 2's essential busses were aligned to Unit 1 offsite power.) LOOP resulted in loss of residual heat removal and spent fuel cooling on Unit 2.

EDGs 1A, 2A, and 2B started due to LOOP.

EDGs were powering all essential busses on both units.

Turbine-driven and both motor-driven auxiliary feedwater pumps automatically started for Unit 1.

2006�Residual heat removal pump 2A was started to restore Unit 2 core cooling.

2012�Notification of Unusual Event (NOUE) was declared.

2031�Spent fuel cooling pump 2B was started to restore Unit 2 spent fuel cooling.

2045�Started raising Unit 2 reactor coolant system level. Level increased to approximately 43%.

2122�Operational Support Center (OSC) and Technical Support Center (TSC) were activated.

2232�Emergency Operations Facility (EOF) was activated.

04/05/12/0129�Offsite power was restored to Unit 1 essential bus 1 ETA.

0137�Offsite power was restored to Unit 2 essential bus 2ETB.

NOUE was terminated.

0138 � EDG 1A was shut down.

0143�EDG 2B was shut down.

0236 � Offsite power was restored to Unit 2 essential bus 2ETA.

0245�EDG 2A was shut down.

0537�Offsite power was restored to Unit 1 essential bus 1 ETB.

0541�EDG 1B was shut down.

1200�It was determined that the LOOP was caused by a Zone G relay programming error.

04/06/12/0000 � Reactor coolant pump motor 1D was inspected. No damage to motor was indicated.

CAUSAL FACTORS

Separate root cause analyses were performed for the trip of reactor coolant pump 1D (the initiating event) and for the LOOP (the resultant event).

The trip of reactor coolant pump 1D occurred as a result of a phase to ground fault in the Y phase conductor for the pump motor. The fault occurred in the vicinity of the Elastimold connector. In 2000, reactor coolant pump 1D experienced a similar trip as a result of the pump motor Y phase Elastimold bushing fault to ground.

This likely resulted in thermal degradation to the cable which was not replaced at that time. The cause analysis and corrective actions following that event did not sufficiently address the thermal degradation that occurred leading to the failure of the cable on 04/04/12.

The LOOP occurred as a result of inadequate design input specification and insufficient control over vendor outsourcing in conjunction with the Zone G relay modification. As a result, a critical design input was not included in the design change package or confirmed by testing. During preparation of the relay setting calculation, the blocking function for the instantaneous generator underfrequency trip was omitted. The vendor calculation check was performed as a high level review and did not identify the missing blocking function. The calculation was subsequently approved and used for relay setting and factory acceptance testing preparation. In addition to the described vendor issue, Catawba Engineering personnel did not specify all of the critical design inputs required for proper operation of the Zone G relay scheme. As a result, the design error was not detected during site review or post-modification testing.

CORRECTIVE ACTIONS

Immediate:

1.�Operations entered the appropriate plant response procedures for the reactor trip on Unit 1 and the LOOP on both units.

2. Unit 1 was stabilized on natural circulation, with residual heat removal via auxiliary feedwater and secondary side steam relief.

3. Residual heat removal core cooling was restored on Unit 2.

4. A NOUE was declared in response to the LOOP and the Emergency Response Organization was activated.

5. Spent fuel cooling was restored on both units.

Subsequent:

1. Following the restoration of offsite power, the NOUE was terminated.

2. The faulted reactor coolant pump motor cable was replaced.

3. The Zone G relay modification error was corrected on both units.

4.AA modification was implemented to correct the identified breaker coordination issue.

Planned:

1. A formal station process will be developed to direct diagnostic testing of medium voltage cable and connectors on a periodic basis and following identified issues with these components.

2. Power cables and Elastimold connectors associated with reactor coolant pump and other critical pump motors will be incorporated into a more rigorous predictive monitoring program.

3. Processes associated with modification scope description, specification of critical design inputs, specification of vendor services and oversight, and checker responsibilities will be revised as appropriate.

There are no NRC commitments contained in this LER.

SAFETY ANALYSIS

Prior to the Unit 1 reactor trip, all safety systems were in their normal standby readiness alignments. As a result of the shorted Y-phase cable on reactor coolant pump motor 1D, Unit 1 tripped on low reactor coolant system flow (P-8 permissive). The reactor protection system functioned as designed to trip the reactor within the required response time and all control rods inserted normally. The main turbine tripped as designed following the reactor trip. Safety injection was not required and did not actuate. Main feedwater was isolated as designed on the reactor trip signal coincident with reactor coolant system average temperature isolation nor containment isolation was required. Ice condenser actuation was not required. The containment spray system was not required to be actuated. All four EDGs (1A, 1B, 2A, and 2B) started as designed on the blackout logic actuation and energized their respective load groups. (EDG 1B started prior to the other three EDGs due to the trip of reactor coolant pump 1D and the opening of feeder breaker 1ATD.) Offsite power 2A remained available throughout the event. Following the reactor trip, pressurizer power operated relief valve (PORV) 1NC34A cycled four times. The valve was determined to have exhibited acceptable performance. The pressurizer code safety valves were not required to actuate. All four steam generator PORVs (1SV1,1SV7, 1SV13, and 1SV19) lifted in response to the transient. 1SV1 and 1SV13 were initially determined to have exhibited sluggish response. Nevertheless, core cooling was effectively established via natural circulation. One steam generator code safety valve (1SV14) lifted a total of nine times due to the sluggish PORV response.

Subsequent troubleshooting revealed no problems with 1SV1. The valve appeared to have several slow strokes at the onset of the event, but stroked as expected over 200 times beyond the initial strokes. 1SV13's sluggish response was attributed to a solenoid valve porting air incorrectly in two directions. This condition was subsequently corrected. Both main feedwater pumps tripped and the auxiliary feedwater pumps (both motor­ driven pumps and the single turbine-driven pump) automatically started in response to this event. The following items were noted during the nuclear safety assessment of the reactor trip:

  • Pressurizer level remained on scale.

. The transient response was bounded by the Updated Final Safety Analysis Report (UFSAR) analyses.

When this event occurred, Unit 2 was in Mode 5 during its End-of-Cycle 18 Refueling Outage. As a result of this event, residual heat removal and spent fuel cooling were briefly lost. Residual heat removal capability was restored in approximately three minutes following the LOOP. Spent fuel cooling capability was restored in approximately 28 minutes following the LOOP. There was no significant impact to Unit 2 as a result of this event.

During this event, the Standby Shutdown System (SSS) diesel generator experienced a low voltage condition after it was started. The cause of the low voltage condition was traced back to a latent design error which occurred during the original plant design. This error resulted in a condition where the diesel generator's power factor controller was not disabled during isochronous operation (i.e., separated from the grid). The SSS is designed to mitigate the consequences of certain postulated fire, security, and station blackout incidents by providing the capability to maintain Mode 3 conditions and by controlling and monitoring vital systems from locations external to the main control room. The SSS is not required to function in order to mitigate design basis events analyzed in Chapter 15 of the Catawba UFSAR. Therefore, the issue with the SSS diesel generator had no impact upon the ability to mitigate the LOOP event (a UFSAR Chapter 15 analyzed event), since the EDGs started and operated to supply power to the essential busses. The SSS diesel generator low voltage condition does not constitute a reportable event in itself; however, it is discussed in this LER for completeness. A separate root cause analysis was performed for this issue.

On September 11, 2012, Duke Energy Corporation presented its evaluation of this event at a Regulatory Conference at the NRC Region II office in Atlanta, GA. On October 11, 2012, the NRC issued letter EA-12-153, formally documenting the final significance determination for this event (Reference 2).

This event did not affect the health and safety of the public.

ADDITIONAL INFORMATION

Within the previous three years, there have been no other reactor trip events or LOOP events. In addition, there have been no other LER events attributed to similar root causes. Therefore, this event is considered to be non-recurring.

Energy Industry Identification System (EllS) codes are identified in the text as [EllS: XX]. This event is considered reportable to the INPO Consolidated Event System (ICES) (formerly called the Equipment Performance and Information Exchange (EPIX) program).

This event is considered to constitute a Safety System Functional Failure under 10 CFR 50.73(a)(2)(v)(A)-(D).

The LOOP resulted in the inability to meet the requirements of 10 CFR 50, Appendix A, General Design Criterion (GDC) 17, "Electric Power Systems". Page 54 of NUREG-1022, Revision 2, "Event Reporting Guidelines 10 CFR 50.72 and 50.73", states the following:

"Both offsite electrical power (transmission lines) and onsite emergency power (usually diesel generators) are considered to be separate functions by GDC 17. If either offsite power or onsite emergency power is unavailable to the plant, it is reportable regardless of whether the other system is available. GDC 17 defines the safety function of each system as providing sufficient capacity and capability, etc., assuming that the other system is not available. Loss of offsite power should be determined at the essential switchgear busses.

It should be noted that during this event, the EDGs and necessary TS systems were available and functioned to mitigate the effects of the LOOP.

There was no release of radioactive material, radiation overexposure, or personnel injury associated with the event described in this LER.

REFERENCES

1. Catawba Nuclear Station Licensee Event Report (LER) 413/2012-001, Revision 0, "Unit 1 Automatic Reactor Trip Due to Faulted Reactor Coolant Pump Motor Cable Resulted in Zone G Relay Lockout and Subsequent Loss of Offsite Power and Emergency Diesel Generator Automatic Start for Both Units", June 4, 2012.

2. NRC letter EA-12-153, "Catawba Nuclear Station - Final Significance Determination of One White Finding and One Green Finding and Notice of Violation (NRC Inspection Report 05000413/2012010 and 05000414/2012010) and Assessment Follow-Up Letter", October 11, 2012.

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