Text

Request for License Amendments - Diesel Generator (DG) Completion Time Extension for Technical Specification (TS) 3.8.1, AC Sources Operating.
	ML11350A244
Person / Time
Site:	Brunswick
Issue date:	12/05/2011
From:	Annacone M; Progress Energy Carolinas
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	BSEP 11-0097, TSC-2011-02
	Download: ML11350A244 (234)
	v • d • e

Progress Energy MichaelJ.I.Annacone Bresick Brunswick Nuclear Plant December 5, 2011 Serial: BSEP 11-0097 10 CFR 50.90 TSC-2011-02 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-000131

Subject:

Brunswick Steam Electric Plant, Unit Nos. 1 and 2 Renewed Facility Operating License Nos. DPR-71 and DPR-62 Docket Nos. 50-325 and 50-324 Request for License Amendments - Diesel Generator (DG) Completion Time (CT) Extension for Technical Specification (TS) 3.8.1, "AC Sources -

Operating" Ladies and Gentlemen:

Pursuant to the provisions of 10 CFR 50.90, Carolina Power & Light Company (CP&L),

now doing business as Progress Energy Carolinas (PEC), Inc., hereby requests a revision to the Technical Specifications (TS) for the Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2. The TS change proposes to extend the Completion Time (CT) of TS 3.8.1 Required Action D.4 for an inoperable diesel generator (DG). A commensurate change is also proposed to extend the maximum Completion Time of TS 3.8.1 Required Actions C.3 and D.4. BSEP will add a supplemental AC power source (i.e., a supplemental diesel generator) with the capability to power any E-bus within one hour from the Station Blackout (SBO) event, and with the capacity to bring the affected unit to cold shutdown, to support this request.

This request is subdivided as follows:

Enclosure 1, Description and Evaluation of Proposed Change

Enclosure 2, Proposed BSEP TS and TS Bases (Markup)

Enclosure 3, Proposed BSEP TS (Retyped Pages)

Enclosure 4, PRA Evaluation of Risk Impact Including Treatment of Uncertainties

Enclosure 5, PRA Quality Report

Enclosure 6, PRA Quantification Data Tables

Enclosure 7, Commitment List The PRA Fire Peer Review is scheduled for December 2011. CP&L expects to receive the Fire Peer Review Final Report in January 2012, and will provide the Fire Peer Review supplemental information within 30 days of receipt of the Final Report. This commitment is included in Enclosure 7. A Self Assessment has been performed to evaluate the Progress Energy Carolinas, Inc.

PO. Box 10429 O (

Southport, NC 28461 T > 910.457.3698

Document Control Desk BSEP 11-0097 / Page 2 of 3 performance of the Fire portion of the PRA. The Self Assessment description and findings are provided in Enclosure 5.

CP&L requests approval of the proposed amendment by February 14, 2013 with implementation prior to startup from the 2013 Brunswick Unit 2 refueling outage.

CP&L has evaluated the proposed change in accordance with 10 CFR 50.91(a)(1), using the criteria in 10 CFR 50.92(c), and determined that there are no significant hazards considerations associated with the proposed TS changes. Additionally, PEC has determined that the proposed TS changes qualify for a categorical exclusion from environmental review pursuant to the provisions of 10 CFR 51.22(c)(9).

In accordance with 10 CFR 50.91 (b)(1), CP&L is notifying the State of North Carolina of this application for amendment by providing a copy of this letter and enclosures to the designated State Official.

Please refer any questions regarding this submittal to Ms. Annette Pope, Supervisor -

Licensing/Regulatory Programs, at (910) 457-2184.

I declare under penalty of perjury, that the foregoing is true and correct; executed on December 5, 2011.

Sincerely, Michael J. Annacone

Enclosures:

1. Description and Evaluation of Proposed Change

2. Proposed BSEP TS and TS Bases (Markup)

3. Proposed BSEP TS (Retyped Pages)

4. PRA Evaluation of Risk Impact Including Treatment of Uncertainties

5. PRA Quality Report

6. PRA Quantification Tables

7. Commitment List

Document Control Desk BSEP 11-0097 / Page 3 of 3 cc (with enclosures):

U. S. Nuclear Regulatory Commission, Region II ATTN: Mr. Victor M. McCree, Regional Administrator 245 Peachtree Center Avenue, NE, Suite 1200 Atlanta, GA 30303-1257 U. S. Nuclear Regulatory Commission ATTN: Mr. Philip B. O'Bryan, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 U. S. Nuclear Regulatory Commission (Electronic Copy Only)

ATTN: Mrs. Farideh E. Saba (Mail Stop OWFN 8G9A) 11555 Rockville Pike Rockville, MD 20852-2738 Chair - North Carolina Utilities Commission P.O. Box 29510 Raleigh, NC 27626-0510 Mr. W. Lee Cox, Ill, Section Chief Radiation Protection Section North Carolina Department of Environment and Natural Resources 1645 Mail Service Center Raleigh, NC 27699-1645

BSEP 11-0097 Enclosure 1 DIESEL GENERATOR COMPLETION TIME EXTENSION DESCRIPTION AND EVALUATION OF PROPOSED CHANGE TABLE OF CONTENTS

1. DESCRIPTIO N .................................................................................................................... 1

2. PRO PO SED CHANG E ..................................................................................................... 1 2.1. Need for Proposed Change ..................................................................................... 1 2.2. Proposed Change to Technical Specifications ........................................................ 2 2.3. Bases for Proposed Change ................................................................................... 2

3. BACKG RO UND ................................................................................................................... 4 3.1. BSEP AC Power System ......................................................................................... 4 3.2. G rid Reliability ..................................................................................................... 8 3.3. Station Blackout Capability ....................................................................................... 9 3.4. Supplemental Diesel Generator (SUPP-DG) ............................. 10 3.5. Fire Hazards ............................................................................................................... 15 3.6. 10 CFR 50, Appendix R .......................................................................................... 15 3.7. Training ....................................................................................................................... 16 3.8. Diesel Generator Reliability Program ...................................................................... 16 3.9. Maintenance Rule Program (10 CFR 50.65) ........................................................... 16 3.10. Configuration Risk Managem ent Program ........................................................... 17 3.11. W ork Control and Scheduling ............................................................................. 17 3.12. HPCI, RCIC, and RHR Pum ps ............................................................................ 18 3.13. Current TS Requirem ents and Lim itations ........................................................... 18 3.14. Traditional Engineering Considerations ............................................................... 19

4. TECHNICAL ANALYSIS ................................................................................................. 22 4.1. Current Licensing Basis for DG Com pletion Tim e .................................................. 22 4.2. Proposed TS 3.8.1 Changes and Benefits ............................................................. 23 4.3. Deterministic Assessment of Proposed DG Completion Time Extension ................ 23 4.4. Risk Assessm ent .................................................................................................. 24 4.5. Conclusion .................................................................................................................. 27

5. REG ULATO RY SAFETY ANALYSIS ............................................................................ 28 5.1. No Significant Hazards Consideration .................................................................... 28 5.2. Applicable Regulatory Requirem ents/Criteria ......................................................... 30 5.3. Precedent ................................................................................................................... 31 5.4. Conclusions ................................................................................................................ 31 Page 1 of 2

BSEP 11-0097 Enclosure 1 DIESEL GENERATOR COMPLETION TIME EXTENSION DESCRIPTION AND EVALUATION OF PROPOSED CHANGE

6. ENVIRONMENTAL CONSIDERATION .......................................................................... 31

7. R E F E R E NC E S .................................................................................................................. 32 7.1. Brunsw ick Steam Electric Plant .............................................................................. 32 7.2. Applicable Regulatory Requirements/Other Criteria ................................................ 32 Page 2 of 2

BSEP 11-0097 Enclosure 1

1. DESCRIPTION Pursuant to 10 CFR 50.90, the Brunswick Steam Electric Plant (BSEP) is submitting a request for Technical Specification (TS) changes to license DPR-71 for BSEP Unit 1, and license DPR-62 for BSEP Unit 2. The proposed TS 3.8.1 changes:

a) Extend the Completion Time (CT) for Required Action D.4 (i.e., return of an inoperable diesel generator (DG) to operable status) from 7 days to 14 days; based upon availability of a supplemental AC power source (i.e., a supplemental diesel generator);

b) Make commensurate changes to the maximum Completion Times for Required Action C.3 and D.4 by extending these times from 10 days to 17 days.

These changes will provide operational and maintenance flexibility. They will allow sufficient time to perform DG planned reliability improvement modifications and maintenance activities that cannot be performed within a 7-day Completion Time.

This License Amendment Request (LAR) includes both deterministic justification and risk-based information. The proposed new CT is based on the 14-day CT permitted in Branch Technical Position (BTP) 8-8 (Reference 7.2.5) and application of the BSEP Probabilistic Risk Assessment (PRA) in support of a risk-informed extension, and on additional considerations and compensatory actions. The risk evaluation and deterministic engineering analysis supporting the proposed change have been developed in accordance with the guidelines established in Regulatory Guide 1.177, "An Approach for Plant-Specific Risk-Informed Decision-making:

Technical Specifications" (Reference 7.2.1), and NRC Regulatory Guide 1.174, "An Approach for using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" (Reference 7.2.2).

2. PROPOSED CHANGE 2.1. Need for Proposed Change This TS change is being requested to allow sufficient time to perform planned reliability improvement modifications and adequate preventive maintenance to ensure diesel generator reliability and availability. The proposed change also provides flexibility to resolve DG deficiencies and avoid potential unplanned plant shutdown, along with the potential challenges to safety systems during an unplanned shutdown, should a condition occur requiring DG corrective maintenance.

The purpose of the proposed change is to extend the TS CT for an inoperable DG from 7 days to 14 days. The 14-day CT is needed to (1) provide the necessary time to support planned DG voltage regulator, governor, and starting air replacements/upgrades as described below, and (2) reduce the likelihood and unnecessary burden of a dual unit shutdown should an unplanned DG outage occur with the units at power by providing additional time to repair and reestablish operability of the inoperable DG. To justify the 7-day CT extension, a supplemental AC power source capable of powering any of the four 4.16 kV emergency buses during a Station Blackout (SBO) is required. BSEP will add a supplemental AC power source (i.e., a supplemental diesel generator) with the capability to power any E-bus within one hour from the SBO event, and with the capacity to bring the affected unit to cold shutdown, to support this request.

Planned component replacement/upgrade activities for each DG for the period 2013-2017 include activities requiring an extended 14-day DG CT. Voltage regulator, governor, and diesel starting air component replacements/upgrades require a 14-day CT. It is anticipated that the voltage regulator work (i.e., estimated at 11.5 days total DG outage time) and governor work Page 1 of 32

BSEP 11-0097 Enclosure 1 (i.e., estimated at 7.5 days total DG outage time) will be performed with the associated unit in a refueling outage (i.e., cold shutdown) to support the required operability testing. It is anticipated that the diesel starting air system work (i.e., estimated at 8 days total DG outage time) will be performed with the associated unit online. The 14-day CT applicable to both the Unit 1 TS and the Unit 2 TS is needed to perform this work. The TS changes will provide operational and maintenance flexibility. They will also allow more time for unanticipated DG repairs. If these replacement activities are combined with other DG maintenance activities and performed over an extended DG CT, the number of entries into the TS Actions and the number of associated DG starts performed for post-maintenance testing prior to exiting the TS will be reduced.

2.2. Proposed Change to Technical Specifications A description of the proposed TS change is provided below. The specific changes to the BSEP TS and TS Bases for Units 1 and 2 are indicated in the markups provided in Enclosure 2. The retyped (clean) pages of the BSEP TS for Units 1 and 2 are provided in Enclosure 3.

2.2.1. TS 3.8.1 - Required Action and Completion Time - New Required Action A new Required Action (shown as D.2 in the markup) to "Evaluate availability of SUPP-DG" with a CT of "2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter" is proposed.

2.2.2. TS 3.8.1 - Completion Time - Required Action D.4 The CT for Required Action D.4 (shown as D.5 in the markup) is proposed to be extended from 7 days to 14 days. The existing 7-day CT is proposed to be conditional concurrent with the SUPP-DG unavailable. Additionally, a CT is proposed to limit the time the SUPP-DG is unavailable during the extended CT to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The proposed CTs would extend the CT from 7 days to 14 days provided the SUPP-DG is available 1 . The initial and subsequent verification of SUPP-DG availability is described in Section 2.2.1.

2.2.3. TS 3.8.1 - Maximum Completion Time - Required Actions C.3 and D.4 The maximum CT for Required Actions C.3 and D.4 (shown as D.5 in the markup) are proposed to be extended from 10 days to 17 days. The maximum Completion Time limits the total time that Limiting Condition for Operation (LCO) 3.8.1 is not met while concurrently or simultaneously in Conditions C and D. This CT is the sum of the CT for Required Action C.3 (i.e., 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ) and D.4 (7 days). BSEP is proposing to increase the CT for Required Action D.4 to 14 days; thus, the maximum CT for Required Action C.3 and D.4 will be increased from 10 days to 17 days.

2.3. Bases for Proposed Change Consistent with the objectives of the NRC's policy entitled "Use of Probabilistic Risk Assessment Methods in Nuclear Activities: Final Policy Statement" (60 FR 42622) (Reference 7.2.3), the amendment proposed herein provides (1) safety decision-making enhanced by the use of Probabilistic Risk Assessment (PRA) insights, (2) more efficient use of resources, and (3) a reduction in unnecessary burden.

1 SUPP-DG availability to extend the DG CT is addressed in the TS and TS Bases. Enclosure 2 provides marked-up pages for the proposed BSEP TS and TS Bases pages. Enclosure 3 provides the retyped (clean) pages for the proposed BSEP TS.

Page 2 of 32

BSEP 11-0097 Enclosure 1 The Completion Time of Required Action D.4 of TS 3.8.1 currently allows only 7 days to perform maintenance and post-maintenance testing or troubleshoot and repair an inoperable DG, and return it to an operable status when BSEP is in Modes 1, 2, or 3.

The purpose of the proposed change is to extend the TS Completion time for an inoperable DG from 7 days to 14 days. The 14-day CT is needed to (1) provide the necessary time to support planned DG voltage regulator, governor, and starting air replacements/upgrades as described in the next paragraph, and (2) reduce the likelihood and unnecessary burden of a dual unit shutdown should an unplanned DG outage occur with the units at power by providing additional time to repair and reestablish operability of the inoperable DG. To justify the 7-day CT extension, a supplemental AC source power source (i.e., a supplemental DG) capable of powering any of the four 4.16 kV emergency buses during a Station Blackout (SBO) is required. BSEP will add a supplemental AC power source (i.e., a supplemental diesel generator) to support this request.

Planned component replacement/upgrade activities for each DG for the period 2013-2017 include activities requiring an extended 14-day DG CT. Voltage regulator, governor, and diesel starting air component replacements/upgrades require a 14-day CT. It is anticipated that the voltage regulator work (i.e., estimated at 11.5 days total DG outage time) and governor work (i.e., estimated at 7.5 days total DG outage time) will be performed with the associated unit in a refueling outage (i.e., cold shutdown) to support the required operability testing. It is anticipated that the diesel starting air system work (i.e., estimated at 8 days total DG outage time) will be performed with the associated unit online. The 14-day CT applicable to both Unit 1 TS and Unit 2 TS is needed to perform this work.

As a condition for implementing an extended 14-day CT for a single inoperable DG, an independent supplemental DG (SUPP-DG) will be provided to supply power to any of the four 4.16 kV E-buses via the 4.16 kV BOP bus circuit path. By procedure and TS Bases, the SUPP-DG will power only one E-bus at a time during a station blackout (SBO) event. The capacity of the SUPP-DG exceeds that of a station DG. The SUPP-DG description is provided in Section 3.4.

BSEP is subject to a dual unit shutdown should an unplanned DG outage occur, with the DG not restored to operable status within 7 days. The extension of the 7-day CT to 14 days gives extra time for repairing and reestablishing operability of the inoperable DG; thus, reducing the risk of dual-unit shutdown as a result of exceeding the 7-day CT. A 14-day CT is justifiable as a contingency provision for unexpected DG failures and minimizes the need for expedited licensing actions seeking approval of more completion time. Given the conclusions reached by the deterministic and risk-based evaluations that follow, extending the CT associated with an inoperable DG would also provide the following:

1. Enhanced Decision-Makinq As noted in its approval of the policy statement on the use of PRA methods, the Commission stated an expectation that the use of PRA technology should be increased to the extent supported by the state of the art in PRA methods and in a manner that complements the NRC's deterministic approach and supports the NRC's traditional defense-in-depth philosophy. The NRC's Policy Statement regarding the Use of Probabilistic Risk Assessment Methods in Nuclear Regulatory Activities states:

PRA and associatedanalyses (e.g., sensitivity studies, uncertaintyanalyses, and importance measures) should be used in regulatory matters, where practicalwithin the bounds of the state-of-the-art, to reduce unnecessaryconservatism associatedwith current regulatory requirements,regulatoryguides, license commitments, and staff practices.

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BSEP 11-0097 Enclosure 1 The extended Completion Time, to permit a DG to be removed from service for 14 days to perform maintenance or to trouble shoot and repair an inoperable DG, are acceptable from a risk-based approach due to a small increase in Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) consistent with the criteria in Regulatory Guides 1.177 and 1.174 (Reference 7.2.1 and 7.2.2). The results of the risk assessment are provided in Section 4.4.

2. Efficient Use of Resources The extended Completion Time associated with an inoperable DG will improve the effectiveness of the allowed maintenance period. Plant resources can be more focused on the DG rather than preparation and return to service activities. Under the current CT, a significant portion of maintenance activities is associated with preparation and return to service activities; the duration of which is relatively constant. Longer Completion Time durations allows more maintenance to be accomplished during a given maintenance period and therefore would improve maintenance efficiency.

3. Reduction in Unnecessary Burden The proposed change provides a reduction in unnecessary burden, because it:

Allows additional time to perform routine maintenance activities on the DG enhancing the ability to focus quality resources on the activity, and improve maintenance efficiency.

Increases the time to troubleshoot, repair, and reestablish operability of an inoperable DG during MODE 1, 2, and 3.

Averts unplanned dual unit shutdown and minimizes the potential need for requests for enforcement discretion.

These proposed changes meet the objectives of the NRC's PRA Policy Statement (60 FR 42622) (Reference 7.2.3).

3. BACKGROUND 3.1. BSEP AC Power System 3.1.1. Offsite AC Power System 3.1.1.1. Introduction The electrical output of BSEP Unit 1 and Unit 2 is fed to the Carolina Power and Light Company (CP&L) power system network by 230 kilovolt (kV) transmission lines. The plant electrical system was designed to meet the requirements of Regulatory Guides 1.6, 1.9, and 1.22. The plant electrical system has been evaluated and meets the requirements of 10 CFR 50.63, "Station Blackout Rule," dated June 21, 1988, and Regulatory Guide 1.155, "Station Blackout,"

dated August 1988. The DG and associated distribution systems are capable of supplying loads required for the safe shutdown of one unit and a design basis accident in the other unit, concurrent with the loss of offsite power.

3.1.1.2. Switchyard The objective of the 230 kV switchyard is to deliver the output of the plant to the various points on the system network and to provide adequate offsite power to start the units, provide power for common plant auxiliary loads, and when necessary supply power for the engineered safety features for a unit in a design basis accident condition while supplying the auxiliary power Page 4 of 32

BSEP 11-0097 Enclosure 1 requirements for shutdown of the other unit. The 230 kV switchyard is designed to minimize the effect of failures of individual items of equipment so that any single credible event would not interrupt power from the 230 kV system network to both startup auxiliary transformers.

Each BSEP unit has a separate section of the switchyard. Each section is connected to one generator (i.e., through the main power transformer), four transmission lines, the startup auxiliary transformer and one transformer which serves the Caswell Beach (i.e., discharge canal) pumping station. Each switchyard section has a double bus arrangement with double breakers for the generator, each transmission line, and the startup auxiliary transformer.

3.1.1.3. Transmission Lines The offsite power system includes eight individual 230 kV transmission lines which are connected to CP&L's network. Four of the eight individual lines serve each of the two units.

Each 230 kV transmission line is connected to its associated switchyard buses through a double breaker feeder arrangement. This arrangement not only enhances the stability of the two units, it assures the availability of off-site power to BSEP.

The system was designed such that neither the loss of one line nor the coincident loss of the nuclear unit will adversely affect the operation, or cause the trip out of the remaining lines.

Power requirements of BSEP for normal unit operation, as well as for the nuclear unit safety buses essential for the safe shutdown of the unit during an accident, are provided by the remaining 230 kV transmission lines.

System design provides for an automatic transfer of power from the onsite power source to the offsite power source in the event of the loss of power generation by the nuclear power unit.

Tripping of a generator unit will not cause a trip-out of the 230 kV lines associated with that unit.

Power requirements resulting from the loss of the unit will be picked up by the 230 kV transmission lines.

Sufficient redundancy has been provided in the offsite power system for BSEP to permit functioning of systems important to safety. The offsite power system provides sufficient capacity and capability to assure that the safety functions of the plant are maintained.

3.1.1.4. Offsite Power System Analysis The offsite power system has been designed to maximize the reliability of the incoming power to the plant. It was designed with adequate thermal capacity to carry the expected continuous load and to withstand short circuit forces and all expected environmental conditions such as ice and wind loadings. Each line breaker has an interrupting rating of 20,000 MVa which is adequate to safely interrupt faults. Protective relaying provides for fast detection of faults, and trips the breakers to clear the fault.

The transmission lines meet the requirements of General Design Criterion (GDC) Number 17.

Transmission for the plant consists of eight 230 kV lines, four lines for each unit.

3.1.2. Onsite AC Power System 3.1.2.1. Introduction The BSEP onsite power systems consist of those facilities necessary to interconnect the station generators and offsite power supplies with the onsite power supplies and various site loads.

These systems provide the capabilities to interconnect various non-safety and safety-related loads to available power supplies. Additionally, these systems provide necessary power to loads required for accident mitigation and for the safe shutdown of the plant.

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BSEP 11-0097 Enclosure 1 Power is distributed within the plant at 4160 V and supplied to major loads at that voltage. The electrical output from the DGs is supplied at 4160 V to four buses which supply loads that are required for safe shutdown and accident mitigation. Unit substations consisting of transformers and switchgear are provided within the plant to step the voltage down to 480 V and supply loads at that voltage.

3.1.2.2. Normal Power System Normal plant power for each unit's auxiliaries is supplied by the 24-4.16 kV unit auxiliary transformer which is connected to its associated generator output leads. Normal startup power for each unit's auxiliaries is supplied by the 230-4.16 kV startup transformer which is fed from the CP&L 230 kV system. The startup transformers would furnish power required in the event of a design basis accident condition. Standby power is provided by four diesel-driven generators.

These units are started automatically on loss of voltage on the 4.16 kV buses or on a loss of coolant accident (LOCA) signal.

Buses 1B, 1C, 1D, 2B, 2C, and 2D are provided with a manually initiated, automatically executed fast bus transfer. The scheme is capable of transferring each bus and its related loads between the normal source (i.e., unit auxiliary transformer) and the preferred source (i.e.,

startup auxiliary transformer) without de-energizing the bus. The transfer is initiated manually from a control station in the control room which closes the circuit breaker on the source to which the transfer is desired.

Buses 1C, 1 D, 2C, and 2D are provided with an automatically initiated, automatically executed, quick dead bus transfer. The scheme is capable of quickly transferring each bus section and its loads from the normal source (i.e., unit auxiliary transformer) to the preferred source (i.e.,

startup auxiliary transformer) in the event of loss of the normal source or unit trip. The transfer event sequence is designed such that the transferred bus and its loads are disconnected from both voltage sources (i.e., normal and preferred) for a period that does not exceed five cycles and is not less than one cycle nominal value based on 60 Hz. The transfer signal immediately trips the normal source breaker and simultaneously initiates the automatic control sequence for closing the preferred source breaker.

3.1.2.3. Standby AC Power System The objective of the standby AC power system is to provide a self-contained, highly reliable source of power, as required, for the engineered safety features so that no single credible event can disable the core standby cooling function. The standby AC supply and distribution system for the two units consists of four DGs and four 4.16 kV Class 1E buses.

The design bases of the standby AC power system include:

a. The system is designed so that the failure of any single piece of equipment including a DG, circuit breaker, distribution center, or interconnecting wiring or cabling will not jeopardize the effectiveness of core standby cooling systems.

b. Repair, replacement, or adjustment of any failed or malfunctioning component can be accomplished without negating the effectiveness of the core standby cooling systems.

c. Diesel capacity is such that any three of the four diesels provided can supply all required loads for the safe shutdown of one unit and a design basis accident on the other unit without offsite power.

d. During a SBO event (i.e., loss of offsite power to both units during non-accident conditions, one diesel is operational in the non-blacked out unit and neither diesel is operational in the Page 6 of 32

BSEP 11-0097 Enclosure 1 blacked out unit), diesel capacity is such that the one operational diesel can supply the required loads for safe shutdown of the non-blackout unit and the required SBO coping loads in the blackout unit.

e. The standby AC power system and its associated equipment are automatically initiated.

The DG units were manufactured by Nordberg Manufacturing Company. Each DG unit has a continuous rating of 3500 kW at 0.8 power factor, 4.16 kV, 3 phase, 60 Hz, and a 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months rating of 3850 kW.

The DG unit start, load and run minimum reliability is 0.975. The 0.975 minimum reliability is demonstrated and maintained by a test and corrective action/maintenance program.

3.1.2.4. 4160 Volt Emergency Power Distribution System Description There are four emergency buses: El, E2, E3, and E4.

Feeders from each 4.16 kV emergency bus serve shutdown loads of Units 1 and 2. As an example, one of four residual heat removal (RHR) pump motors for each unit is served from each emergency bus. Other plant loads are the RHR service water pump motor and the conventional service pump motors.

Emergency bus ties and incoming lines from the normal (i.e., preferred) source are provided with two series connected power circuit breakers. The emergency bus tie breakers E3-to-E4 and E4-to-E3 are racked out and have their control power fuses removed. The emergency bus tie breakers El-to-E2, E2-to-E1, El-to-E3, E2-to-E4, E3-to-E1 and E4-to-E2 are racked in and have their control power fuses installed. During normal plant operation the El-to-E2, E2-to-E1, El-to-E3, E2-to-E4, E3-to-E1 and E4-to-E2 tie breakers are prevented from operating by local selector switches which separate the DC control power from the breaker control logic. The selector switches allow local operation of the breakers during a station blackout or fire event.

The selector switches also allow operation of the breakers from the control room if required during events other than a station blackout or fire. These selector switches are key locked and controlled. The E3-to-E4 and E4-to E3 tie breakers are not racked in and the control logic for the El-to-E2, E2-to-El, El-to E3, E2-to-E4, E3-to-El and E4-to-E2 tie breakers are not energized without procedural direction.

The intent of the above controls is to prevent two redundant 4.16 kV electrical buses from being tied together except during a Station Blackout or Appendix R fire event.

3.1.2.5. DG Automatic Starting and Loadinq Conditions Independent, automatic logic is provided for each emergency bus, El through E4, which generates a DG auto-start signal under any of the following conditions:

- Loss of offsite power to either Unit 1 or Unit 2

- Unit trip of either unit

- Engineered safety features, actuation signal, on either unit

- Loss of voltage on the associated emergency bus Four DGs provide standby power for the engineered safety features on the loss of the normal power sources.

Each DG is connected to its individual 4160 V Class 1E bus. AC loads necessary to the safe shutdown of the plant under accident or non-accident conditions are fed from this distribution system. Once the DG is automatically connected to the emergency buses, the logic recognizes Page 7 of 32

BSEP 11-0097 Enclosure 1 which plant if either is in an accident condition and automatically starts the appropriate engineered safety features, according to a prescribed timed sequence.

The steady state loading of each diesel generator has been studied for the following conditions:

a. Design basis accident on one unit and orderly shutdown of the other unit under loss of offsite power conditions with three DGs operating (i.e., LOCA/LOOP loading).

b. Simultaneous safe shutdown of both units under loss of offsite power conditions with three DGs operating (i.e., LOOP loading).

c. Station blackout loading with one DG available (i.e., safe shutdown of the non-blackout unit while supplying the SBO coping loads of the blackout unit) (i.e., SBO loading).

To meet analysis requirements for LOCA/LOOP loading, LOOP loading, and SBO loading, no case requires that the 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months rating (3850 kW) of the DG be exceeded. Operation at DG loading between the continuous rating (3500 kW) and the 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months rating (3850 kW) is only expected for short durations and is appropriate when needed as described above.

3.1.2.6. Onsite Power System Analysis The BSEP onsite power system has been designed to supply systems and components important to safety. Sufficient capacity, capability, and redundancy are provided assuring that plant integrity and all vital functions are maintained in the event of postulated accidents.

In the event of a total loss of the preferred power source, power for the engineered safety features is supplied from the diesel generators.

3.2. Grid Reliability 3.2.1. Generic Letter 2006-02, Grid Reliability and the Impact on Risk and the Operability of Offsite Power BSEP response to Generic Letter (GL) 2006-02, Grid Reliability and the Impact on Risk and the Operability of Offsite Power" (Reference 7.2.7) was provided on March 31, 2006 (i.e., Serial:

BSEP 06-0026, ADAMS Accession No. ML061020057), and supplemented on January 25, 2007 (i.e., Serial: BSEP 07-0009, ADAMS Accession No. ML070310316) in response to an NRC issued RAI.

The NRC completed their review of GL 2006-02 as documented in their letter dated June 15, 2007 (i.e., ADAMS Accession No. ML071580124). The proposed amendment does not adversely impact BSEP's compliance with NRC regulatory requirements governing electric power sources and associated personnel training.

3.2.2. Recent Offsite AC Power System Reliability Improvements Recent Offsite AC Power System reliability improvements include the following:

1. Replacements of the motor operated disconnect switches supplying the Startup transformer with gang operated breakers. Allows both 230 KV buses to be connected to the Startup supply at all times, where previously only one bus could be utilized at a time.

2. Replacements of all switchyard line breakers with independent pole (IPO) breakers; expected to be completed by April 2012. IPO breakers reduce the probability that a Page 8 of 32

BSEP 11-0097 Enclosure 1 phase to phase fault can persist when a breaker malfunction occurs (i.e. at least two poles are likely to open reducing the event to a line to ground fault).

3. Replaced generator output breakers.

4. Main Transformers have been replaced and updated with condition monitoring equipment.

5. Capacitance coupled voltage transformers (CCVTs) have had high industry failure rates therefore all BSEP CCVTs and associated remote end CCVTs have been replaced.

6. Capacitor banks have been installed at each 230 KV bus for improved control of switchyard reactive loading.

7. All switchyard insulators were coated with room temperature vulcanizing (RTV) elastomeric coating following a 1993 LOOP event in which a severe storm caused unusually high salt contamination and flashover of electrical insulators in the switchyard.

Recoating of these insulators is currently in progress.

3.3. Station Blackout Capability 3.3.1. Introduction SBO refers to a complete loss of all offsite and onsite AC power. The SBO rule (10 CR 50.63) requires utilities to assess the impact of a loss of preferred power (i.e., offsite power) concurrent with a loss of the unit's diesel generators. BSEP SBO analysis has been performed in accordance with the guidelines provided in Regulatory Guide 1.155, Station Blackout (Reference 7.2.6), and NUMARC 87-00, Guidelines and Technical Bases for NUMARC Initiatives addressing Station Blackout at Light Water Reactors (Reference 7.2.4), for assessment of BSEP compliance with the requirement of 10 CFR 50.63.

BSEP utilizes the alternate AC source operation approach. BSEP is subject to a minimum station blackout coping capability of four hours with a DG Reliability Target of 0.975.

For BSEP, with its normally dedicated emergency AC power sources, a SBO is assumed to occur on only one unit. The non-blackout unit is capable of sharing a single DG with the blackout unit, after assuming a single failure on the non-blackout unit (i.e., one of the two DGs on the non-blackout unit fails to start). With only one DG available, it will be necessary to load strip and cross-tie the 4.16 kV and 480V substations to provide power to both units. Control power fuses on the blackout unit's cross-tied 4160V emergency bus are removed to prevent tripping of the single operating DG from Residual Heat Removal (RHR), Core Spray (CS), and Nuclear Service Water (NSW) pump starts on possible LOCA signals from the cool down.

It is intended that the SUPP-DG would be connected to the 4.16 kV E-Bus associated with the DG removed from service; however, the SUPP-DG would be available to be connected to any of the four 4.16 kV E-Buses following the licensing basis SBO event. That is, if the DG that was inoperable prior to the SBO is on the non-blackout unit, it would be appropriate to align the SUPP-DG to the 4.16 kV E-Bus in the division on the blackout unit that is not involved in the cross-tie actions per the plant SBO Abnormal Operating Procedure (AOP). The SUPP-DG alignment can be performed concurrent with and independent from the plant SBO AOP cross-tie actions.

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BSEP 11-0097 Enclosure 1 The SUPP-DG is a defense-in-depth measure for SBO. The SUPP-DG is not credited in the SBO analysis.

3.3.2. Coping Duration BSEP is an Alternate AC (AAC) plant subject to a minimum station blackout coping capability of four hours. The required SBO coping duration for BSEP is calculated in accordance with the guidance provided in NUMARC 87-00, Section 3.0. During the first hour of coping, the crosstie with the non-blackout unit is not established and AC power is not available in the blackout unit.

After the first hour, the crosstie is established and the AAC power source can support the coping requirements (i.e., supply battery chargers) in the blackout unit. Two 200 kW, 480 VAC 60 Hz diesel generators, referenced as severe accident management alternative (SAMA) diesel generators, are available to supply the blackout unit battery chargers ifAC power cannot be restored to the blackout unit E-bus (i.e., the crosstie is not possible). If both units are blackout, one SAMA diesel generator is available to supply the Unit 1 battery chargers, and one SAMA diesel generator is available to supply the Unit 2 battery chargers. The SAMA diesel generators are a defense-in-depth measure.

BSEP is an Independence Group 11/2 category site. BSEP is categorized as Extremely Severe Weather Group 5 and Severe Weather Group 2. BSEP is categorized as Offsite AC Power Design Group P3* and Emergency Alternating Current (EAC) Group C.

DG reliability is 0.975 for BSEP. BSEP monitors the DG reliability under the Maintenance Rule Program (i.e., see Section 3.9). Increasing the DG CT will not impact the DG reliability target used in the SBO coping time calculation at BSEP.

Off-site power is delivered to the site via eight individual 230 kV transmission lines. Four of the eight individual lines serve each of the two units. These lines feed a 230 kV switchyard as described in Section 3.1 and in detail in Chapter 8.2 of the updated Final Safety Analysis Report (FSAR) (Reference 7.1.1). The large number of 230 kV transmission lines and the physical separation of the lines and transformer bays minimize the likelihood of power loss due to loss of transmission lines. Additionally, during use of the extended CT, the protection of the switchyard and cooperation with Progress Energy Transmission helps to minimize risk of the SBO event.

While BSEP was not licensed in accordance with the Standard Review Plan (SRP), a review of NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," was conducted. NUREG 0800, Section 8.4, 111.3.O.iv (Reference 7.2.8) states:

'When an SBO occurs at one unit of a multiunit site, the EAC power source(s) and the redundant EAC power source(s) are unavailable. An SBO on one unit does not assume a concurrent single failure; however, the remaining unit(s) should still meet the normal operating single failure criteria. This suggests that BSEP would incur a loss of off-site power coupled with the failure of 3 out of 4 DGs (2 on SBO Unit and 1 on non-SBO Unit). This is consistent with the current SBO licensing basis.

3.4. Supplemental Diesel Generator (SUPP-DG) 3.4.1. SUPP-DG System Description Details of the SUPP-DG are not finalized, but the current descriptions are noted below.

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BSEP 11-0097 Enclosure 1 3.4.2. SUPP-DG Sizing, Separation, Connection, Design, Operation and Testing The supplemental AC power source (SUPP-DG) consists of a 20-cylinder EMD 20-71 OG4C-T3 diesel engine generator unit manufactured by Electro-Motive Diesel (EMD). It can be aligned and started to power any one of the four (4) emergency buses (E-bus). Each Class 1 E DG is rated at 3500 kWe continuous and 3850 kWe (i.e., 2000-hour rating). The SUPP-DG is rated at 4000 kWe (6850 hour0.0793 days 1.903 hours 0.0113 weeks 0.00261 months s/year) and 4300 kWe (i.e., < 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months out of any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period).

Accounting for the SUPP-DG house and auxiliary loads (i.e., approximately 125 kWe during the worst case operating scenario), the output at the SUPP-DG output breaker is > 3850 kWe. The capacity of the SUPP-DG exceeds that of a station DG; thus it can substitute for any one of the four DGs under SBO load requirements. The SUPP-DG is sized to accommodate the DG load under SBO conditions. The SUPP-DG has the capacity to bring the affected unit to cold shutdown, if needed (i.e., if the offsite power is not recovered in a timely manner). The cold shutdown loads are:

LOAD IDENTIFICATION KW Residual Heat Removal (RHR) Pump 880 Conventional Service Water (CSW) Pump 243 Nuclear Service Water (NSW) Pump 243 Control Rod Drive (CRD) Pump 154 Residual Heat Removal Service Water (RHRSW) Pump 553 Reactor Building Closed Cooling Water (RBCCW) Pumps 96 Fuel Pool Cooling Pump 50 Reactor Building Ventilation Fans 239 Drywell Cooling Fans 119 Other 480V Load 722 Transformer/Cable Losses 83 TOTAL LOAD 3382 The SUPP-DG will be a commercial-grade, non-safety related permanently-installed unit.

The SUPP-DG system will be installed inside the plant protected area, in enclosures east of the Switchyard and north of the Transformer yard. The SUPP-DG components will be physically separated from safety-related Class 1 E 4.16 kV AC ESF components, physically separated from the DGs, and physically separated from the preferred offsite AC power sources for the BSEP units. Figure 1 (i.e., Enclosure 1A) shows the approximate SUPP-DG location within the plant.

The Diesel Enclosure, Electrical Enclosure, Mechanical Enclosure, and 10,000 gallon fuel storage tank will be located in this general area. The SUPP-DG will be separated from each Class 1 E power system by two normally open, non-Class 1 E circuit breakers in series, which tie the SUPP-DG into any one of four balance-of-plant (BOP) buses located on Unit 1 (i.e., 1C, 1D) and Unit 2 (i.e., 2C, 2D). One breaker is the SUPP-DG output breaker located in the SUPP-DG Electrical Enclosure; the other breaker is the feeder breaker located at each BOP bus. The SUPP-DG output breaker and the BOP Bus feeder breakers are operated from the SUPP-DG electrical enclosure. The existing master-slave circuit breakers from the BOP buses to the associated E-buses will be used to complete the SUPP-DG alignment to power any one of the four E-buses. The master-slave circuit breaker configuration includes a non-Class 1 E master circuit breaker supplied from the BOP bus and a Class 1 E slave circuit breaker located at the Class 1 E E-bus. The master-slave circuit breakers are controlled from the control room. Figure 2 (i.e., Enclosure 1A) shows the SUPP-DG tie-in to the plant electrical system. The normally open circuit breakers between the SUPP-DG and the selected BOP bus will be closed for SUPP-DG load testing, and after a SBO event, in accordance with approved procedures.

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BSEP 11-0097 Enclosure 1 The SUPP-DG will be equipped with an engine control system to maintain the steady state voltage and frequency output within prescribed limits. Redundant automatic voltage regulators control the voltage level of the generator. A switch is provided to select which regulator is active.

If the active regulator fails the generator will trip offline. Changing the switch position to select the back-up regulator will allow the unit to be restarted and resume automatic operation. The SUPP-DG supplier will be required to demonstrate the capability to maintain voltage and frequency within prescribed limits during factory testing of the assembled Gen-Set. Refer to the factory testing discussion below.

The SUPP-DG and associated outdoor weather enclosures (i.e., Diesel Enclosure, Mechanical Enclosure, and Electrical Enclosure) will be mounted to a seismically-rugged foundation. The foundation will be elevated approximately 10 feet above plant grade to protect the SUPP-DG system from flood and storm surge. The 4.16 kV cable routing, from the SUPP-DG to the Turbine Building, is flood resistant. The cable run originates at the elevated SUPP-DG Electrical Enclosure and drops down into a new cable trench to the Unit 1 Turbine Building. At the Unit 1 Turbine Building, the cable is routed along the western Turbine Building wall and into the Turbine Building at an elevated point approximately 12 feet above plant grade. The cable route is terminated at the new BOP Bus switchgear.

After an SBO, an operator will manually start and stop the SUPP-DG locally. No SUPP-DG control will be available in the Control Room. Operator action will be required to align and tie the SUPP-DG output to the 4.16 kV E-Bus via the associated 4.16 kV BOP Bus circuit path. First, auxiliary operator action is taken to prevent load starts on the 4.16 kV BOP Bus and to control load starts on the 4.16 kV E-bus. Next, the auxiliary operator will start the SUPP-DG and tie it to the 4.16 kV BOP Bus. Next, a control room operator will close from the control room the master-slave circuit breakers from the 4.16 kV BOP Bus to the 4.16 kV E-Bus, energizing the E-Bus. As described in Section 3.3.1, the SUPP-DG alignment can be performed concurrent with and independent from the plant SBO Abnormal Operating Procedure (AOP) cross-tie actions. The SUPP-DG will be aligned and operated according to approved procedures.

Once the de-energized 4.16 kV E-Bus is reenergized by the SUPP-DG, the unit Engineered Safety Feature (ESF) loads can be manually started from the respective unit control room. The time required to enable the SUPP-DG to supply power to any E-bus is less than one hour from the SBO event.

There will be no direct interface between the SUPP-DG and the DGs. The SUPP-DG will be connected to a selected BOP bus during the SUPP-DG load testing. The SUPP-DG electrical system will be provided with metering and protective relaying at the SUPP-DG output breaker and the new BOP Bus switchgears. For its defense-in-depth function, it is intended that the SUPP-DG would be connected to the 4.16 kV E-Bus associated with the DG that is removed from service; however, the SUPP-DG could be connected to any of the four 4.16 kV E-Buses following the licensing basis SBO event. That is, if the DG that was inoperable prior to the SBO is on the non-blackout unit, it would be appropriate to align the SUPP-DG to the 4.16 kV E-Bus on the blackout unit that is not involved in the cross-tie actions per the facility SBO AOP. The SUPP-DG will be connected only to one 4.16 kV E-Bus at a time in accordance with approved procedures.

Protection from common cause failures between the DGs and SUPP-DG is provided by physical separation, difference in DG manufacturer, difference in DG design, difference in environmental conditions, the use of separate fuel oil tanks and fuel oil testing, SUPP-DG use of radiator cooling, and difference in operating and maintenance procedures.

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BSEP 11-0097 Enclosure 1 Factory testing will be performed by the manufacturer on the assembled Gen-Set. Factory testing will include load capability, 24-hour, largest single load start, short-time rating and largest single load reject, start and load acceptance, margin, and load sequence tests. A vibration survey will also be performed.

Site acceptance testing will include testing prior to connection to the plant electrical system and load testing to the 4.16 kV BOP Buses. Upon implementation of the modification, the SUPP-DG will be subject to load testing to a 4.16 kV BOP Bus, and ensuring all its auxiliary support systems are available or operational. The test will be performed only during periods when the SUPP-DG is not credited as available during the extended CT.

3.4.3. SUPP-DG Housing, Batteries, Start System, Fuel, Exhaust Emissions, Lubrication Oil, Consumable Spares The SUPP-DG and associated mechanical and electrical equipment will be primarily housed in three outdoor weather enclosures (i.e., Diesel Enclosure, Mechanical Enclosure, and Electrical Enclosure) and mounted on an elevated foundation to protect the SUPP-DG system from flood and storm surge. The outdoor weather enclosures will withstand wind speed (i.e., 3-second gust) of 155 mph. The SUPP-DG has a closed loop radiator cooling system mounted on the SUPP-DG foundation. The radiator assembly will withstand wind speed (i.e., 3-second gust) of 155 mph. The Diesel Enclosure houses the diesel engine and generator, and its support systems and accessories including Lube Oil, Air Intake, Cooling Water, Fuel Oil, Redundant Dual Turbine Motor Air Start Systems; and Engine Panel with Engine Instrumentation. The Mechanical Enclosure houses required air start accessories, including air receivers, air compressor and dryer. The Electrical Enclosure houses the SUPP-DG output breaker switchgear, engine/generator control panel, 125 vdc battery system with battery charger, 480v motor control center, 480v automatic transfer switch, and 4160:480v auxiliary power transformer. The SUPP-DG output breaker and the feeder breakers to the 4.16 kV BOP Buses are operated from the Electrical Enclosure.

The SUPP-DG system will normally be in a standby configuration and disconnected from the plant 4.16 kV electrical systems. When the plant is not subject to LOOP/SBO, the SUPP-DG house loads (e.g., battery charger, air compressor, heaters) are powered from a plant 480V supply through a transfer switch located at the SUPP-DG. Upon LOOP, the SUPP-DG is capable of starting on its 125 VDC battery system for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and will power its house loads once running.

The engine starting system uses compressed air for starting the engine. The starting system consists of two (2) air receivers and redundant air start systems. Each system includes two (2) air start motors.

The SUPP-DG has a 10,000 gallon fuel storage tank mounted on the SUPP-DG foundation. The fuel storage tank provides a usable supply sufficient for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of running time at 100% rated continuous load. The full load fuel consumption is approximately 6,264 gallons/day (i.e.,

approximately 261 gallons/hour). The fuel storage tank sizing includes approximately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months additional capacity without fuel replenishment. The required action prior to entering the extended CT will include verifying SUPP-DG availability, which includes fuel tank level > 24-hour supply. The fuel storage tank can be replenished via a refill station for the tank. The SUPP-DG will use No. 2 Ultra-Low Sulfur Diesel Fuel (i.e., ASTM Standard D975). The diesel engine is emissions certified to meet Environmental Protection Agency (EPA) Tier 3 regulations in accordance with 40CFR60.

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BSEP 11-0097 Enclosure 1 The SUPP-DG full load lube oil consumption is approximately 0.45 gallons/hour. The oil level with the engine stopped should be above the full mark. The usable oil from the full mark to the low mark is 257 gallons. The extra oil capacity permits extended operation (i.e., approximately 570 hours0.0066 days 0.158 hours 9.424603e-4 weeks 2.16885e-4 months or 23.75 days) without replenishment. Additionally, oil can be added during engine operation. Consumables such as lubrication oil and engine coolant will be available, sufficient for an extended SUPP-DG run.

3.4.4. SUPP-DG Fire Protection The SUPP-DG will be equipped with fire detection and suppression. The Diesel, Mechanical, and Electrical Enclosures will each be equipped with a fire suppression system for the hazards present. The fire detection will be connected to the plant fire detection system.

The SUPP-DG fuel storage tank will be UL 142 certified, double-wall carbon steel construction, equipped with level indication, vent and outer shell leak alarm. The fuel storage tank design and construction will meet the requirements of NFPA 30. The fuel storage tank will withstand wind speed (i.e., 3-second gust) of 155 mph.

The SUPP-DG will be monitored for fire hazards during Operator Rounds 4 .

3.4.5. SUPP-DG Availability The SUPP-DG will be operated and maintained according to approved procedures.

The SUPP-DG will be subject to load testing to a 4.16 kV BOP Bus, and ensuring all its auxiliary support systems are available or operational. This test will be performed only during periods when the SUPP-DG is not credited as available during the extended CT.

In determining the appropriate frequency for SUPP-DG testing, BSEP will utilize the manufacturer's recommendation for load testing. Verification of SUPP-DG availability includes verification that the load test is performed within 30 days of entry into the extended CT. The proposed TS will require evaluation of SUPP-DG availability within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of entry into TS 3.8.1, Condition D, for an inoperable DG. This verification includes an administrative verification of this prior testing. Following initial verification of the SUPP-DG availability, the proposed TS will require ongoing verification of availability on a once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months frequency.

The SUPP-DG will be routinely monitored during Operator Rounds, with monitoring criteria (e.g.,

fuel tank level, battery state of charge, starting air system pressure) identified in the Operator Rounds. In addition, the SUPP-DG will be protected, as defense-in-depth, during the extended DG CT5 .

The marked-up TS Bases include information for SUPP-DG availability as follows:

1. The load test has been performed within 30 days of entry into the extended Completion Time. The Required Action verification is met with an administrative verification of this prior testing;

2. SUPP-DG fuel tank level is verified locally to be > 24-hour supply; and

3. SUPP-DG supporting system parameters for starting and operating are verified to be within required limits for functional availability (e.g., battery state of charge, starting air system pressure).

4 Refer to Enclosure 7, Commitment List.

5 Refer to Enclosure 7, Commitment List.

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BSEP 11-0097 Enclosure 1 3.4.6. SUPP-DG Support The SUPP-DG is a black-start unit independent of external supports for start, run, and load conditions. The availability of fuel and lubrication oil is discussed in Section 3.4.3. The SUPP-DG will be maintained as directed by plant procedures. When the plant is not subject to LOOP/SBO, the SUPP-DG shut down loads (e.g., battery charger, air compressor, heaters) are powered from a plant 480V supply through a transfer switch located at the SUPP-DG. Upon LOOP, the transfer switch automatically aligns to the SUPP-DG supply once the SUPP-DG is running.

Operator rounds will ensure the availability of fuel oil and the functionality of the SUPP-DG starting batteries (charging status) and starting air system, and provide an additional level of SUPP-DG overall monitoring.

3.4.7. SUPP-DG Staffing The SUPP-DG alignment can be performed concurrent with and independent from the plant SBO cross-tie actions. The SBO cross-tie actions would be performed by one Auxiliary Operator. The SUPP-DG alignment actions would be performed by a second Auxiliary Operator, with the final actions (i.e., energizing the E-bus) performed by a Reactor Operator from the Control Room.

Licensed Operators and Auxiliary Operators, for the operating crews on-shift when the extended DG CT is in use, will be briefed on the DG work plan, the revised TS 3.8.1, and procedural actions regarding LOOP, SBO, and SUPP-DG alignment and use prior to entering the extended DG CT 6 .

3.5. Fire Hazards The SUPP-DG and its associated support equipment (i.e., Diesel Enclosure, Electrical Enclosure, Mechanical Enclosure, and fuel storage tank) are located in an outside area adjacent to the plant switchyard and not in a fire zone within an existing building. A fire in the SUPP-DG zone would not impact systems, structure, or components (SSCs) other than the SUPP-DG itself. Since the SUPP-DG is normally separated from the remainder of the plant with open breakers, a SUPP-DG fire would not cause failures or spurious operations of other SCC's. A fire that fails the E-bus that the SUPP-DG is backing up while the associated DG is in an extended CT would have also failed the applicable DG if it were in-service. However, the SUPP-DG can be aligned to any E-bus.

3.6. 10 CFR 50, Appendix R The SUPP-DG is a defense-in-depth measure for SBO. The SUPP-DG is not credited in the 10 CFR 50, Appendix R analysis.

6 Refer to Enclosure 7, Commitment List.

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BSEP 11-0097 Enclosure 1 3.7. Training Licensed Operators and Auxiliary Operators will be appropriately trained on the purpose and use of the SUPP-DG and the revised AOP actions 7. Personnel performing maintenance on the SUPP-DG will be appropriately trained8 .

3.8. Diesel Generator Reliability Program BSEP maintains a DG Reliability Program per plant procedures. The program monitors and evaluates DG performance and reliability. The program requires remedial actions when one or more established reliability "trigger values" are exceeded, then a root cause evaluation is performed and corrective actions taken. The DG reliability target for Brunswick is 0.975. This value represents the underlying unit DG reliability values for purposes of establishing a coping duration of four hours for a Station Blackout Event. The DG reliability program will not be negatively impacted by the proposed amendment because DG testing frequencies are unaffected.

Overall, the CT extension is expected to improve DG availability. A significant portion of DG maintenance windows are associated with the removal and restoration activities including tagging, system restoration & lineup, and post maintenance testing. The durations for these maintenance support activities are fairly consistent. A longer CT duration will allow more maintenance to be accomplished for a given maintenance window, thereby reducing the number of DG outages for the EDGs. Therefore, the total EDG unavailability is expected to decrease over time with this proposed amendment.

It should be noted that using the full duration of the requested 14-day CT would be infrequent.

Other BSEP programs, including the Maintenance Rule Program (i.e., Section 3.9) and Work Control and Scheduling (i.e., Section 3.11) ensure the extended Completion Time would not be abused. Frequent use of the full Completion Time duration would adversely impact DG unavailability, which could result in exceeding Maintenance Rule goals, require corrective actions, and increased management attention to restore the DGs to Maintenance Rule (a)(2) status.

3.9. Maintenance Rule Program (10 CFR 50.65)

The SUPP-DG will be included in the scope of the plant Maintenance Rule Program, and will be classified and implemented in accordance with fleet and plant procedures.

The Maintenance Rule requires that an evaluation be performed when equipment covered by the Maintenance Rule does not meet its performance criteria. The reliability and availability of the DGs are monitored under the Maintenance Rule program. If the pre-established reliability or availability performance criteria are not achieved for the DGs, they are considered for 10 CFR 50.65 (a)(1) actions. These actions would require increased management attention and goal setting to restore their performance to an acceptable level. The actual out of service time for the DGs is minimized to ensure that the reliability and availability performance criteria are met.

Refer to Enclosure 7, Commitment List.

8 Refer to Enclosure 7, Commitment List.

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BSEP 11-0097 Enclosure 1 3.10. Configuration Risk Management Program Brunswick uses a blended approach to configuration risk management, using both a quantitative and qualitative analysis of work activities prior to work authorization. The configuration risk management program is implemented using plant procedures for integrated scheduling of online processes and outage risk management during shutdown conditions. These procedures, used in conjunction with fleet procedures for the maintenance rule program, work management processes, and online equipment-out-of-service (EOOS) models for risk assessment, control the processes in which risk assessments are performed and integrated into the daily work schedule.

Plant configurations and changes in plant configurations are assessed for risk at BSEP. In accordance with station procedures, when risk significant SSCs, such as DGs, are made unavailable, actions are taken to protect redundant/diverse structures, systems and components. PRA based risk assessments are performed for all planned plant configurations as part of the work planning process. These configurations are pre-planned so as to minimize the risk. If unplanned equipment unavailability occurs during DG maintenance activities, station procedures direct that the risk be re-evaluated, and if found to be unacceptable, compensatory actions are taken until such a time that the risk is reduced to an acceptable level. Specific risk thresholds are procedurally specified for the assessment of the need for compensatory actions.

If compensatory actions are insufficient, then procedural direction is to transition to a mode or other specified condition that reduces overall plant risk to an acceptable level.

Configuration Risk Management is also discussed in the Section 4.4, Risk Assessment.

3.11. Work Control and Scheduling BSEP uses a blended approach to risk assessment for work control and scheduling. The blended approach concept uses the best information available to assess and manage risk, including:

1. Quantitative insights from the PSA and the EOOS computer model on-line risk.

2. Expert knowledge of plant operations by licensed Senior Reactor Operators.

3. Qualitative methods of assessing the adequacy of defense-in-depth, potential loss of function, and external factors (e.g., severe weather, offsite power instability due to demand).

Four risk thresholds (i.e., green, yellow, orange, red) are established and include quantitative and qualitative classifications. Risk management actions address configurations that result in elevated risk profiles. These actions are aimed at providing increased risk awareness of appropriate personnel, providing more rigorous planning and control of the activity, and taking measures to control the duration and the magnitude of the increased risk.

Plant procedure OAP-025, BNP Integrated Scheduling, addresses online risk management. The BNP Integrated Scheduling procedure:

1. Provides the process for assessing and managing on-line risk,

2. Provides guidance for the protected equipment process, methodology, and posting,

3. Ensures maintenance is performed in a manner that enhances the reliability and availability of SSCs that is commensurate with safety pursuant to 10CFR50.65.

4. Protects the offsite AC sources and the other DGs, for a DG outage.

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BSEP 11-0097 Enclosure 1 Fleet procedure OMA-NGGC-0203, Shutdown Risk Management, and plant procedure OAP-022, BNP Outage Risk Management, address shutdown risk management. The BNP Outage Risk Management procedure:

1. Contains the site-specific configurations required for various shutdown conditions.

2. Contains the site-specific configurations required to implement the shutdown risk management program, including key safety functions (e.g., decay heat removal capability, electric power availability, inventory control, reactivity control, secondary containment, fuel pool cooling).

3. Provides the process for assessing shutdown risk.

Protocols are in place for daily communications between the Power System (Grid) Operator and the BSEP Control Room to discuss the status of the plant and the transmission system and review upcoming plans and work activities, and for weekly communications between BSEP Outage and Scheduling and the Power System Operator to coordinate activities and generation planning. All field work activities and switching evolutions are assessed for the risks involved.

The BSEP Control Room is responsible for the decision to proceed with activities which involve risks to the plant systems. When it is intended to use the extended DG CT, the Brunswick Control Room will ensure:

1. Component testing or maintenance of safety systems and important nonsafety equipment in the offsite power systems which can increase the likelihood of a plant transient (i.e., unit trip) or LOOP, will be avoided during the extended DG CT. In addition, no discretionary switchyard maintenance will be allowed during the extended DG CT 9.

2. Weather conditions will be evaluated prior to intentionally entering the extended DG CT and will not be entered if official weather forecasts are predicting severe weather conditions (i.e., thunderstorm, tornado, or hurricane warnings). Operators will monitor weather forecasts each shift during the extended DG CT. If severe weather or grid instability is expected after a DG outage begins, station managers will assess the conditions and determine the best course for returning the DG to an operable statuslo.

3.12. HPCI, RCIC, and RHR Pumps The High Pressure Coolant Injection (HPCI) pump, the Reactor Core Isolation Cooling (RCIC) pump, and the Residual Heat Removal (RHR) pump associated with the operable DG will not be removed from service for elective maintenance activities during the extended DG CT1".

3.13. Current TS Requirements and Limitations TS LCO 3.8.1 requires, as a minimum, two physically independent AC circuits between the offsite transmission network and the onsite Class 1 E distribution system, and four separate and independent DGs. With one DG inoperable, TS 3.8.1, Condition D requires the inoperable DG be restored to operable status within 7 days to avoid entering TS 3.8.1 Condition H, which requires plant shutdown. For BSEP, the Unit 1 TS 3.8.1 LCO statement and the Unit 2 TS 3.8.1 LCO statement each require all four DGs operable. Thus, if an inoperable DG were not restored within the 7 day CT, a dual unit shutdown would be required.

9 Refer to Enclosure 7, Commitment List.

10 Refer to Enclosure 7, Commitment List.

11 Refer to Enclosure 7, Commitment List.

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BSEP 11-0097 Enclosure 1 BSEP intends to perform the voltage regulator and governor work with the associated unit in a refueling outage. For BSEP, with one unit in a refueling outage, the opposite unit must also enter the TS 3.8.1 Required Actions and Associated Completion Times for an inoperable DG, since each unit's TS LCO 3.8.1 requires four operable DGs. Without the extended DG CT, the operating unit would also be required to be shutdown to support the voltage regulator and governor work.

BSEP intends to perform the diesel starting air work with the associated unit online. For BSEP, with both units online, the opposite unit must also enter the TS 3.8.1 Required Actions and Associated Completion Times for an inoperable DG, since each unit's TS LCO 3.8.1 requires four operable DGs. Without the extended DG CT, both units would be required to be shutdown to support the diesel starting air work.

3.14. Traditional Engineering Considerations For an SBO, the redundant DGs would be available to mitigate the accident, and the units would remain within the bounds of the accident analyses. In addition, there would be no adverse impact to the unit, because the Safety Function Determination Program will be utilized to ensure that cross-train checks are performed to determine if a loss of safety function exists if there are concurrent equipment inoperabilities, and ensure the appropriate actions are taken if a loss of safety function is identified. Since the probability of these events occurring concurrently during a planned maintenance window is low, there is minimal safety impact due to the requested extended CTs.

The combination of defense-in-depth and safety margin inherent in the onsite emergency power system ensures an emergency supply of power will be available to perform the required safety function. This supports extension of the CTs to allow a DG to be out-of-service for a longer period of time, as discussed further below.

3.14.1. Defense-in-Depth The proposed changes to the CTs maintain system redundancy, independence, and diversity commensurate with the expected challenges to system operation. The other DGs, offsite sources of power, and the associated engineered safety equipment will remain operable to mitigate the consequences of any previously analyzed accident. Otherwise, the Safety Function Determination Program will require that a loss of safety function be declared, and the appropriate TS Conditions and Required Actions taken. In addition to the TS Safety Function Determination Program, the Work Management Process, Integrated Scheduling Program, and Maintenance Rule Program provide for controls and assessments to preclude the possibility of simultaneous outages of redundant trains and ensure system reliability. The proposed increase in the CT associated with an inoperable DG while the unit is in Mode 1, 2, or 3, will not alter the assumptions relative to the causes or mitigation of an accident.

With a DG inoperable, a loss of function has not occurred. The remaining offsite power sources and DGs are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure.

As defined by Regulatory Guide 1.174, consistency with the defense-in-depth principle is maintained if the following occurs:

1. A reasonablebalance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation.

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BSEP 11-0097 Enclosure 1 The proposed extensions to the CTs, associated with an inoperable DG while the unit is in Mode 1, 2, or 3, have only a small calculated impact on CDF and LERE. The proposed changes are not accomplished by degrading core damage prevention and compensating with improved containment integrity nor does this change degrade containment integrity and compensate with improved core damage prevention. The balance between prevention of core damage and prevention of containment failure is maintained. Consequence mitigation remains unaffected by the proposed changes. Furthermore, no new accident or transients are introduced with the requested change and the likelihood of most accidents or transients is not impacted.

The balance between mitigation of core damage and containment failure are preserved by the implementation of this 14 day allowed outage time of the DGs in that the overall DG reliability is expected to be improved in the near term and over the long term the DG unavailability is expected to be improved with fewer emergent issues. Additionally the SUPP-DG which provides an additional AC power source will add to the overall ability to prevent core damage and also prevent containment challenge or failure. Thus DGs ability to support the mitigation of both core damage and containment failure is preserved and in the long term enhanced.

2. Over-relianceon programmaticactivities as compensatory measures associatedwith the change is avoided.

As prescribed in BTP 8-8, a supplemental power source (i.e., the SUPP-DG) is being installed and will be available as a backup to the inoperable DG to maintain the defense-in-depth design philosophy for the electrical system to meet its intended safety function. The installation of the SUPP-DG (i.e., plant equipment) reduces the reliance on programmatic activities as compensatory measures associated with the change.

Plant safety systems are designed with redundancy so when one train is inoperable, a redundant train can provide the necessary design function. During the timeframe when a DG is inoperable, a redundant source of power will be maintained operable. In the event other equipment becomes inoperable concurrent with the DG inoperability, the Safety Function Determination Program requires cross-division checks to ensure a loss of safety function does not go undetected. If a loss of safety function is identified, TS LCO 3.0.6 will require entry into the applicable Conditions and Required Actions for the system that possesses the loss of safety function. TS 3.8.1, Required Action D.2 (i.e., Required Action D.3 in the markup provided in ) requires declaring supported feature(s), supported by the inoperable DG, inoperable when the redundant required feature(s) are inoperable. Required Action D.2 (i.e.,

Required Action D.3 in the markup provided in Enclosure 2) is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed to be powered from redundant safety related 4.16 kV emergency buses. Redundant required feature failures consist of inoperable features associate with an emergency bus redundant to the emergency bus that has an inoperable DG. In addition, the PRA analysis indicates that there is a small calculated impact on CDF and LERF with the proposed TS changes.

3. System redundancy,independence, and diversity are preserved commensurate with the expected frequency, consequences of challenges to the system, and uncertainties.

The redundancy, independence, and diversity of the onsite emergency power system will be maintained during the extended CTs. There were no identified uncertainties in redundancy, independence or diversity with the introduction of the SUPP-DG or the extended CT. The SUPP-DG is not susceptible to the same common cause failures as the currently installed DGs; thus the proposed configuration improves the independence and diversity of the on-site AC power sources.

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BSEP 11-0097 Enclosure 1

4. Defenses againstpotential common-cause failures are preserved, and the potential for the introduction of new common-cause failure mechanisms is assessed.

Defenses against common cause failures are preserved. New common cause failure mechanisms are not expected to be created by the proposed changes. The operating environment and operating parameters for the DGs remain constant; therefore, new common cause failure modes are not expected. Redundant and backup systems are not impacted by this change and no new common cause links between the primary and backup systems are introduced; therefore, no new potential common cause failure mechanisms have been introduced by the proposed change.

5. Independence of barriersis not de-graded.

The barriers protecting the public and the independence of these barriers are maintained.

Multiple DGs, systems or electrical distribution systems will not be intentionally taken out of service simultaneously. This could lead to degradation of these barriers and an increase in risk to the public. In the event other equipment becomes inoperable concurrent with the DG inoperability, the Safety Function Determination Program requires cross-division checks to ensure a loss of safety function does not go undetected. If a loss of safety function is identified, TS LCO 3.0.6 will require entry into the applicable Conditions and Required Actions for the system that possesses the loss of safety function. TS 3.8.1, Required Action D.2 (i.e., Required Action D.3 in the markup provided in Enclosure 2) requires declaring supported feature(s),

supported by the inoperable DG, inoperable when the redundant required feature(s) are inoperable. Required Action D.2 (i.e., Required Action D.3 in the markup provided in Enclosure

2) is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed to be powered from redundant safety related 4.16 kV emergency buses.

Redundant required feature failures consist of inoperable features associate with an emergency bus redundant to the emergency bus that has an inoperable DG. In addition, the extended CTs do not provide a mechanism that degrades the independence of the barriers; fuel cladding, reactor coolant system, and containment.

6. Defenses againsthuman errorsare preserved.

The proposed extensions to the CT do not introduce any new operator actions for the existing plant equipment. However, operators will be required to align and operate the new SUPP-DG.

These actions to align and operate the new SUPP-DG include actions that are the same as or similar to current plant actions, and new actions to operate the SUPP-DG. Licensed Operators and Auxiliary Operators will be appropriately trained on the purpose and use of the SUPP-DG and the revised AOP actions. Licensed Operators and Auxiliary Operators, for the on-shift operating crews, will be briefed on the DG work plan, the revised TS 3.8.1, and procedural actions regarding LOOP, SBO, and SUPP-DG alignment and use prior to entering the extended DG CT. A Human Reliability Analysis (HRA) has been performed of the required actions to start and align the SUPP-DG and it is concluded that these actions are feasible with adequate indications and time to perform. The HRA is discussed in Enclosure 4.

7. The intent of the plant's desiqn criteriais maintained.

The design and operation of the DGs are not altered by the proposed extensions to the CTs.

The safety analysis acceptance criteria stated in the UFSAR is not impacted by the change.

Redundancy and diversity of the DGs is not altered, because the system design and operation are not altered by the proposed extensions to the CTs. The proposed change will not allow plant operation in a configuration outside the design basis. The requirements credited in the accident analysis regarding the DGs will remain the same.

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BSEP 11-0097 Enclosure 1 3.14.2. Safety Margin For the extended CTs associated with an inoperable DG while the unit is in Mode 1, 2, or 3, the plant remains in a condition for which the plant has already been analyzed; therefore, from a deterministic aspect, these changes are acceptable. The 14-day and 17-day CTs are risk-informed CTs based on a plant specific analysis using the methodology defined in this license amendment request. The Maintenance Rule (i.e., 10 CFR 50.65) requires each licensee to monitor the performance or condition of the DGs to ensure that the DGs are capable of fulfilling its intended functions. If the performance or condition of the DGs do not meet performance criteria, appropriate corrective action is required along with goals to monitor effectiveness of the corrective action. Additionally, BSEP will add a supplemental AC power source (i.e., a supplemental diesel generator) with the capability to power any E-bus within one hour from the SBO event, and with the capacity to bring the affected unit to cold shutdown, to support this request.

As defined in Regulatory Guide 1.174, the overall margin of safety is not decreased due to the extended CTs for the DGs, because:

1. Codes and standardsor their alternativesapproved for use by the NRC are met.

The design and operation of the DGs are not altered by the proposed CT extension, or the SUPP-DG. Redundancy and diversity of the electrical distribution system will be maintained, because the system design and operation are not altered by the proposed CT extension, or the SUPP-DG. The SUPP-DG provides an additional AC power source as a defense-on-depth measure for SBO.

2. Safety analysis acceptance criteriain the Licensing Basis (e.g., FSAR, supportinganalyses) are met or proposedrevisions provide sufficient margin to account for analysis and data uncertainty.

The safety analysis acceptance criteria stated in the UFSAR are not impacted by the change.

The proposed change will not allow plant operation in a configuration outside the design basis.

The requirements regarding the DGs credited in the accident analysis will remain the same.

Given the above, CP&L concludes that safety margins were not impacted by the proposed changes.

4. TECHNICAL ANALYSIS This section provides the technical analysis of the proposed changes with regard to the principles that adequate defense-in-depth is maintained, sufficient safety margins are maintained, and the calculated increases in CDF and LERF are small and consistent with the guidance of RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Bases," dated May 2011 and RG 1.177, "An Approach for Plant- Specific, Risk-Informed Decision making: Technical Specifications,"

dated May 2011 (References 7.2.2 and 7.2.1).

4.1. Current Licensing Basis for DG Completion Time Under the current TS, if a DG is inoperable, the 4.16 kV emergency bus design is sufficient to allow operation to continue in the condition for a period that should not exceed 7 days. In this Condition, the three remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E distribution system. The 7-day CT takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

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BSEP 11-0097 Enclosure 1 4.2. Proposed TS 3.8.1 Changes and Benefits This Technical Specification change is being requested to allow sufficient time to perform planned reliability improvement modifications and adequate preventive maintenance to ensure diesel generator reliability and availability. The proposed change also provides flexibility to resolve DG deficiencies and avoid potential unplanned plant shutdown, along with the potential challenges to safety systems during an unplanned shutdown, should a condition occur requiring DG corrective maintenance.

The proposed changes to Technical Specifications are described in Section 2.2. The purpose of the proposed change is to extend the TS CT for an inoperable DG from 7 days to 14 days. The 14-day CT is needed to (1) provide the necessary time to support planned DG maintenance activities including governor, voltage regulator, and diesel starting air replacements and upgrades, and (2) reduce the likelihood and unnecessary burden of a dual unit shutdown should an unplanned DG outage occur with both units at power by providing additional time to repair and reestablish operability of the inoperable DG. To justify the 7-day CT extension, a supplemental AC source power source (i.e., a supplemental DG) capable of powering any of the four 4.16 kV emergency buses during a SBO is required. BSEP will add a supplemental AC power source (i.e., a supplemental diesel generator) to support this request.

The TS change will provide operational and maintenance flexibility. It will also allow more time for unanticipated DG repairs.

4.3. Deterministic Assessment of Proposed DG Completion Time Extension The effect of this license amendment request (LAR) would be to allow continued power operation up to an additional 7 days while DG maintenance or testing is performed. The DG is a standby electrical power supply whose safety function is required when both the normal and alternate off-site power supplies are unavailable and there is an event that requires operation of the plant emergency safeguards features.

Independent standby power systems are provided with adequate capacity and testability to supply the required engineered safety features and protection systems. The standby power source is designed with adequate independency, redundancy, capacity, and testability to ensure power is available for the engineered safety features and protection systems required to avoid undue risk to the health and safety of the public. This power source will successfully provide this capacity when a failure of a single active component is assumed.

Each of the four DGs can supply one of the four separate Class 1 E emergency buses. Each is started automatically on a LOOP or LOCA. The DG arrangement provides adequate capacity to supply the engineered safety features for the DBA, assuming the failure of a single active component in the system.

Since the standby power systems can accommodate a single failure, extending the CT for an out of service DG has no impact on the system design basis. Safety analyses acceptance criteria as provided in the UFSAR are not impacted by this change. AC power sources credited in the accident analyses will remain the same.

To ensure that the single failure design criterion is met, LCOs are specified in the plant TS requiring all redundant components of the onsite power system to be operable. In the event that a DG is inoperable in Modes 1, 2, and 3, existing TS 3.8.1 Condition D requires that to ensure a highly reliable power source remains with one DG inoperable, it is necessary to verify the operability of the offsite circuits on a more frequent basis. When the required redundancy is not maintained, action is required within the specified CT to initiate a plant shutdown. The CT Page 23 of 32

BSEP 11-0097 Enclosure 1 provides a limited time to restore equipment to operable status and represents a balance between the risk associated with continued plant operation with less than the required system or component redundancy and the risk associated with initiating a plant transient while transitioning the unit to a shutdown condition. Thus, the acceptability of the maximum length of the extended CT interval relative to the potential occurrences of design basis events is considered. Since extending the CT for a single inoperable DG does not change the design basis for the standby emergency power system (i.e., DGs), extending the CT by 7 days is acceptable and consistent with BTP 8-8 (Reference 7.2.5).

BSEP's coping time during SBO is not affected by the proposed change. The coping time is calculated based on guidance provided in NUMARC 87-00, Rev. 1 (Reference 7.2.4). The assumptions and the results of the SBO analyses are not changed by an extension of the CT, and compliance with 10 CFR 50.63 will be maintained as it does not impact the reliability of the DGs. In addition, DG reliability is maintained at or above the SBO target level of 0.975, and the effectiveness of maintenance on the DGs and support systems is monitored pursuant to the Maintenance Rule.

Based on the above discussion, extending the CT for a single inoperable DG from 7 days to 14 days is acceptable because the proposed change will not impact the plant design basis. The 7-day extension of the CT is consistent with BTP 8-8 (Reference 7.2.5). The impact of extended plant operation is evaluated in a probabilistic framework in the discussions that follow (i.e., see Section 4.4).

To ensure that the risk associated with extending the CT for a DG is minimized, and consistent with the philosophy of maintaining defense-in-depth, compensatory measures will be applied.

The availability of the SUPP-DG for extending the DG CT is incorporated into the proposed TS.

Other measures are provided in Enclosure 7, Commitment List. These measures will ensure the risks associated with removing a DG from service are managed to minimize the increase in risk during the extended DG CT.

If this LAR is not granted, voltage regulator, governor, and diesel starting air work would require a dual-unit outage (both units shutdown) so that a DG could be removed from service without TS implication. Additionally, if an unplanned DG outage occurs with both units at power, and the DG were not restored to operable status within 7 days, this would require a dual-unit plant shutdown upon expiration of the 7-day CT provided in TS 3.8.1, Condition D. Shutdown of the plant involves many plant operator activities and plant evolutions. These activities and evolutions provide challenges to plant equipment, opportunities for operator errors and increase the possibility of a plant trip. It should also be noted that shutdown of a unit does not remove the desirability of having the DG available to support its associated 1 E bus, but rather places additional dependence on the operable Class 1 E bus by requiring operation of the residual heat removal system. By granting this LAR and allowing continued steady state operation, additional operator activities and plant operations evolutions associated with plant shutdown could be avoided. The increased possibility for plant trip may also be avoided. This LAR proposes an additional 7 days as a reasonable time for which a regulatory basis exists for CT extension. This additional time period is considered small. Due to the short time period, the probability of a design basis accident occurring during this interval is low.

4.4. Risk Assessment 4.4.1. Assumptions The PRA application assumptions are:

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BSEP 11-0097 Enclosure 1

The SUPP-DG is not susceptible to common cause failure of the installed DGs.

The use of the SUPP-DG is only credited during entry into the extended CT.

Operator actions to implement the SUPP-DG occur after failure of installed DG to start and load or the ability to cross tie the 4160 VAC buses (i.e., El/E3 or E2/E4) fails or is not capable.

The failure modes and failure rates of the SUPP-DG are the same as the installed DG.

The SUPP-DG will not be planned to be out of service when the extended CT is exercised.

Each DG will experience 14 days of extended outage time per year, planned or unplanned. This is in addition to the regular planned outage time.

The proposed changes are evaluated to determine that current regulations and applicable requirements continue to be met, that adequate defense-in-depth and sufficient safety margins are maintained, and that any increase in CDF and LERF is small and consistent with the NRC Safety Goal Policy Statement, USNRC, "Use of Probabilistic Risk Assessment Methods in Nuclear Activities: Final Policy Statement," Federal Register, Volume 60, p.42622, August 16, 1995.

4.4.2. Justification for DG Extended CT The justification for the use of a DG extended CT is based upon risk informed and deterministic evaluations consisting of three main elements:

4.4.2.1. Tier 1: Assessment of the impact of the proposed TS change using a valid and appropriate PRA model and compare with appropriate acceptance guidelines The modeling approach is consistent with the NRC guidelines for the calculation on the required risk measures using the Brunswick PRA for interval events, internal floods, high winds, fire hazards as well as a seismic and external flood evaluation. Regulatory Guide 1.177 is followed to calculate the change in risk measures for Incremental Conditional Core Damage Probability (ICCDP) and Incremental Conditional Large Early Release Probability (ICLERP). These conditional probabilities are performed to calculate the risk change while in the DG CT for each DG case. As part of the Tier 1 analysis for the DG CT risk assessment, an integrated assessment of the impact of the CT extension is calculated assigning the worst case diesel generator unavailability to all four diesel generators. This calculation is then used for comparison with the criteria set in Regulatory Guide 1.174. A detailed Tier 1 discussion can be found in Enclosure 4 of this submittal.

4.4.2.2. Tier 2: Evaluate equipment relative to the contribution to risk while the DG is in the extended CT Examination of out of service combinations can be evaluated for their risk significance to determine if additional measures may be required. The SUPP-DG will be required to be available prior to implementing the extended CT, and in review of the results no additional measures were identified as required to meet the risk metrics.

4.4.2.3. Tier 3: Implementation of the Configuration Risk Management Program while a DG is in an extended AOT Brunswick uses a blended approach to configuration risk management, using both a quantitative and qualitative analysis of work activities prior to work authorization. The configuration risk Page 25 of 32

BSEP 11-0097 Enclosure 1 management program is implemented using plant procedures for integrated scheduling of online processes and outage risk management during shutdown conditions. These procedures, used in conjunction with fleet procedures for the maintenance rule program, work management processes, and online equipment-out-of-service (EOOS) models for risk assessment, control the processes in which risk assessments are performed and integrated into the daily work schedule.

Configuration Risk Management is used for scheduling of station maintenance activities and helps ensure that there is no significant increase in plant risk due to severe accidents while any DG maintenance is performed. These elements provide adequate justification for approval of the requested Technical Specification change by providing a high degree of assurance that power can be provided to the ESF buses during the DG extended CT for all Design Basis Accidents (DBAs) (i.e. Loss of Off-site Power, Loss of Coolant Accidents (LOCAs)), Station Blackouts (SBO), or fire during the DG extended CT.

4.4.3. Configuration Risk Management Program Plant configuration changes for required maintenance of the DGs as well as the maintenance of equipment having risk significance are managed by the CRMP. The CRMP helps ensure that these maintenance activities are carried out with no significant increase in the risk of a severe accident.

Proposed plant configurations before performing maintenance activities and changes in plant configuration during performance of maintenance activities are assessed for risk at BSEP. In accordance with station procedures, when risk significant SSCs, such as DGs are made unavailable, actions are taken to protect redundant/diverse SSCs. The PRA-based risk assessment is performed for planned plant configurations as part of the work planning process.

As BSEP is a dual unit plant and some SSCs either are shared such as DGs, or can be shared such as Station Air, the removals of these SSCs have risk assessment performed for both units.

These planned plant configurations are pre-planned so as to minimize the risk to both units. If unplanned equipment unavailability occurs during DG maintenance activities, station procedures direct the risk assessment be re-evaluated and if found unacceptable, compensatory actions are taken until such time that the risk is reduced to acceptable level.

Specific risk thresholds are procedurally specified for the assessment of the need for compensatory actions. The BSEP configuration risk management program uses a blended approach with a quantitative risk input, based upon PRA model SSCs and a qualitative input based upon those SSCs not modeled in the PRA that have been determined to be high safety significant SSCs.

4.4.4. Compensatory Measures The SUPP-DG will be verified to be available prior to implementing the extended CT and treated as protected equipment.

4.4.5. Other Considerations Attendant Shutdown Risk reductions associated with removing DG PMs and overhauls have not been quantified as part of the Enclosure 4 evaluation. The removal of the DG PMs and overhauls from the refueling outages is expected to further reduce the risk associated with the CT extension. One of the drivers for this CT extension request is an overall improvement in DGs reliability with upgrades and modifications to the DG system. This will also result in an overall un-quantified risk reduction to both Brunswick Units.

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BSEP 11-0097 Enclosure 1 In addition, the CRMP discussed in Section 4.4.3 will ensure that the plant state is monitored to minimize the risk impact of the change.

4.4.6. Uncertainties In addition to the assessment of the mean risk metrics which are specified in RG 1.177 and 1.174 for comparison with the acceptance guidelines, it is also prudent to examine whether modeling uncertainties may distort these comparisons.

Therefore, an extensive review of potential modeling uncertainties that may impact the risk metrics is performed. This reviewed used NUREG-1855 and the referenced EPRI guidelines on the treatment of uncertainties were used as well as the review of modeling uncertainties specific identified by Progress Energy PRA practitioners. Enclosure 4 includes an examination of these uncertainties and results of any sensitivity studies.

Uncertainties are minimized by the use of the required compensatory measures listed above.

4.4.7. Conclusion (PSA)

As documented in Enclosure 4, the risk change calculated with the Brunswick PRA for the proposed EDG CT extension for all four DGs is small. The quantitative results of the evaluation are shown in the table below:

Risk Metric Risk Significant Risk Metric ResultsGudlnGieie Meets Acceptance Guideline Guideline ACDF ave(/yr) 3.1E-07 <1.OE-06 Yes ALERF ave(/yr) <5.7E-09 <1.OE-07 Yes ICCDP 4.6E-07 <1.OE-06 Yes ICLERP 8E-09 <1.OE-07 Yes The ICCDP and ICLERP are the cumulative results for assuming each DG will experience 14 days of extended outage time per year, planned or unplanned. This is in addition to the regular planned outage time.

Thus the ICCDP and ICLERP for any individual DG also meet the acceptance guidelines.

4.5. Conclusion The results of the deterministic evaluation and risk-informed assessment described above provide assurance that the equipment required to safely shut down the plant and mitigate the effects of a design basis accident will remain capable of performing their safety functions when a DG is out-of-service in accordance with the proposed CTs.

The proposed CTs are consistent with NRC policy and will continue to provide protection of the public health and safety. As detailed in Section 2.3, the proposed change advances the objectives of the NRC's PRA Policy Statement, including safety decision-making enhanced by the use of PRA insights, more efficient use of resources, and reduction of unnecessary burden.

In addition, the proposed change meets the following principles:

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BSEP 11-0097 Enclosure 1

1. It meets the current regulations.

2. It is consistent with the defense-in-depth philosophy.

3. It maintains sufficient safety margins.

4. It results in risk metrics provided above for CDF and LERF consistent with the criteria in Regulatory Guides 1.177 and 1.174 (Reference 7.2.1 and 7.2.2) and is consistent with the NRC's Safety Goal Policy Statement, as implemented via the NRC Standard Review Plan (SRP) (NUREG-0800), RG 1.174, and RG 1.177.

The extended Completion Times, to permit a DG to be removed from service for 14 days to perform maintenance or to trouble shoot and repair an inoperable DG, are acceptable from a risk-based approach due to risk metrics for CDF and LERF consistent with the criteria in Regulatory Guides 1.177 and 1.174 (Reference 7.2.1 and 7.2.2). The results of the risk assessment are provided in Section 4.4.

5. Its impact will be monitored using performance measurement strategies.

Therefore, based on the above evaluations and conclusions, CP&L believes that the proposed change is acceptable and operation in the proposed manner will not present undue risk to public health and safety or be inimical to the common defense and security.

5. REGULATORY SAFETY ANALYSIS This license amendment request proposes changes to the BSEP TS; specifically, TS 3.8.1, "AC Sources - Operating", Condition D, concerning one inoperable diesel generator (DG). The proposed change would extend the Completion Time (CT) for an inoperable DG from 7 days to 14 days. The proposed CT is based on application of the BSEP Probabilistic Risk Assessment (PRA) in support of a risk-informed extension, and on additional considerations and compensatory actions. The proposed CT of an additional 7 days is a reasonable time for which a regulatory basis exists for CT extension. The risk evaluation and deterministic engineering analysis supporting the proposed change have been developed in accordance with the guidelines established in Regulatory Guide 1.177, "An Approach for Plant-Specific Risk-Informed Decision-making: Technical Specifications" (Reference 7.2.1), and NRC Regulatory Guide 1.174, "An Approach for using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" (Reference 7.2.2).

5.1. No Significant Hazards Consideration CP&L has evaluated whether or not a significant hazards consideration is involved with the proposed amendment(s) by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1. Does the proposed amendment involve a significantincreasein the Probabilityor consequences of an accidentpreviously evaluated?

Response: No.

The DGs are safety related components which provide backup electrical power supply to the onsite emergency power distribution system. The proposed changes do not affect the design of the DGs, the operational characteristics or function of the DGs, the interfaces between the DGs and other plant systems, or the reliability of the DGs. The DGs are not accident initiators; the DGs are designed to mitigate the consequences of previously evaluated accidents including a loss of offsite power. Extending the CT for a single DG would not affect the previously evaluated accidents since the remaining DGs supporting the redundant Engineered Safety Features (ESF)

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BSEP 11-0097 Enclosure 1 systems would continue to be available to perform the accident mitigation functions. Thus allowing a DG to be inoperable for an additional 7 days for performance of maintenance or testing does not increase the probability of a previously evaluated accident.

Deterministic and probabilistic risk assessments evaluated the effect of the proposed TS changes on the availability of an electrical power supply to the plant emergency safeguards features systems. These assessments concluded that the proposed TS changes do not involve a significant increase in the risk of power supply unavailability.

There is small incremental risk associated with continued operation for an additional 7 days with one DG inoperable; however, the calculated impact on risk provides risk metrics consistent with the acceptance guidelines contained in Regulatory Guides 1.177 and 1.174 (Reference 7.2.1 and 7.2.2). This risk is judged to be reasonably consistent with the risk associated with operations for 7 days with one DG inoperable as allowed by the current TS.

Specifically, the remaining operable DGs and paths are adequate to supply electrical power to the onsite emergency power distribution system. A DG is required to operate only if both offsite power sources fail and there is an event which requires operation of the plant engineered safety features such as a design basis accident. The probability of a design basis accident occurring during this period is low.

The consequences of previously evaluated accidents will remain the same during the proposed 14-day CT as during the current 7-day CT. The ability of the remaining TS required DG to mitigate the consequences of an accident will not be affected since no additional failures are postulated while equipment is inoperable within the TS CT. The standby AC power supply for each of the four safety-related load groups consists of one DG complete with its auxiliaries, which include the cooling water, starting air, lubrication, intake and exhaust, and fuel oil systems. The sizing of the DGs and the loads assigned among them is such that any combination of three out of four of these DGs is capable of shutting down the plant safely, maintaining the plant in a safe shutdown condition, and mitigating the consequences of accident conditions.

Thus this change does not involve a significant increase in the probability or consequences of a previously analyzed accident.

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No The proposed changes do not involve a change in the plant design, plant configuration, system operation, or procedures involved with the DGs. The proposed changes allow a DG to be inoperable for additional time. Equipment will be operated in the same configuration and manner that is currently allowed and designed for. The functional demands on credited equipment is unchanged. There are no new failure modes or mechanisms created due to plant operation for an extended period to perform DG maintenance or testing. Extended operation with an inoperable DG does not involve any modification in the operational limits or physical design of plant systems. There are no new accident precursors generated due to the extended CT.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.

3. Does the proposed change involve a significantreduction in a margin of safety?

Response: No Page 29 of 32

BSEP 11-0097 Enclosure 1 Currently, if an inoperable DG is not restored to operable status within 7 days, TS 3.8.1, Condition H, requires the unit to be in MODE 3 (i.e., HOT SHUTDOWN) within a CT of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and to be in MODE 4 (i.e., COLD SHUTDOWN) within a CT of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This TS Condition is entered on both units resulting in a dual-unit shutdown. The proposed Technical Specification changes will allow steady state plant operation at 100% power for an additional 7 days for performance of DG planned reliability improvements and preventive and corrective maintenance.

Deterministic and probabilistic risk assessments evaluated the effect of the proposed TS changes on the availability of an electrical power supply to the plant ESF systems. These assessments concluded that the proposed TS changes do not involve a significant increase in the risk of power supply unavailability.

The DGs continue to meet their design requirements; there is no reduction in capability or change in design configuration. The DG response to LOOP, LOCA, SBO, or fire is not changed by this proposed amendment; there is no change to the DG operating parameters. In the extended CT, as in the existing CT, the remaining operable DGs and paths are adequate to supply electrical power to the onsite emergency power distribution system. The proposed change does not alter a design basis or safety limit; therefore it does not significantly reduce the margin of safety. The DGs will continue to operate per the existing design and regulatory requirements.

The proposed TS changes do not alter the plant design nor does it change the assumptions contained in the safety analyses. The standby AC power system is designed with sufficient redundancy such that a DG may be removed from service for maintenance or testing. The remaining DGs are capable of carrying sufficient electrical loads to satisfy the UFSAR requirements for accident mitigation or unit safe shutdown. The proposed changes do not impact the redundancy or availability requirements of offsite power circuits or change the ability of the plant to cope with a SBO. Therefore, based on the considerations given above, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above, CP&L concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

5.2. Applicable Regulatory Requirements/Criteria Section 50.63 of 10 CFR, "Loss of all alternating current power," requires that light-watercooled nuclear power plants licensed to operate be able to withstand for a specified duration and recover from a station blackout. The proposed change does not affect BSEP's compliance with the intent of 10 CFR 50.36.

Section 50.65 of 10 CFR, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," requires that preventive maintenance activities must not reduce the overall availability of the systems, structures and components. It also requires that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The proposed change does not affect BSEP's compliance with the intent of 10 CFR 50.65.

General Design Criterion (GDC) 17, "Electric power systems," of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50 states, in part, that nuclear power plants have onsite and offsite electric power systems to permit the functioning of structures, systems, and components (SSC) that are important to safety. The onsite system is required to have sufficient independence, redundancy, and testability to perform its safety function, assuming a Page 30 of 32

BSEP 11-0097 Enclosure 1 single failure. The offsite power system is required to be supplied by two physically independent circuits that are designed and located so as to minimize, to the extent practical, the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. The proposed change does not affect BSEP's compliance with the intent of GDC 17.

GDC-18, "Inspection and testing of electric power systems," states that electric power systems that are important to safety must be designed to permit appropriate periodic inspection and testing of important areas and features, such as insulation and connections to assess the continuity of the systems and the condition of their components. The proposed change does not affect BSEP's compliance with the intent of GDC 18.

The BSEP design was reviewed for construction under the "General Design Criteria for Nuclear Power Plant Construction" issued for comment by the AEC in July 1967 and is committed to meet the intent of General Design Criteria (GDC), published in the Federal Register on May 21, 1971, as Appendix A to 10 CFR Part 50.

RG 1.155, "Station Blackout," describes a method acceptable to the NRC staff for complying with the Commission regulation that requires nuclear power plants to be capable of coping with a station blackout (SBO) event for a specified duration. The proposed change does not affect BSEP's compliance with the intent of RG 1.155.

RG 1.174, "An Approach for Using Probabilistic Risk Assessment [PRA] in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed licensing basis changes by considering engineering issues and applying risk insights. This RG also provides risk acceptance guidelines for evaluating the results of such assessments. RG 1.174 was used for the evaluation of risk provided with this license amendment request.

RG 1.177 identifies an acceptable risk-informed approach including additional guidance specifically geared toward the assessment of proposed TS CT changes. Specifically, RG 1.177 identifies a three-tiered approach for the evaluation of the risk associated with a proposed CT TS change. RG 1.177 was used for the evaluation of risk provided with this license amendment request.

5.3. Precedent The NRC has recently approved requests to extend the CT for Diesel Generators including:

Browns Ferry (October 2011, ADAMS Accession No. ML11227A258)

Hope Creek (March 2011, ADAMS Accession No. ML110610501) 5.4. Conclusions In conclusion, based on the considerations discussed above, there is reasonable assurance (1) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, (2) that such activities will be conducted in compliance with Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

6. ENVIRONMENTAL CONSIDERATION BSEP has evaluated the proposed amendment for environmental considerations. The review has determined that the proposed amendment would change requirements with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, and would change an inspection or surveillance requirement.

Page 31 of 32

BSEP 11-0097 Enclosure 1 However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b),

no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

7. REFERENCES 7.1. Brunswick Steam Electric Plant 7.1.1. Brunswick Steam Electric Plant (BSEP), Updated Final Safety Analysis Report (UFSAR),

Chapter 8, Electrical Power Systems, Revision 22.

7.2. Applicable Regulatory Requirements/Other Criteria 7.2.1. RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," Revision 1, May 2011.

7.2.2. RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Bases," Revision 2, May 2011.

7.2.3. NRC Safety Goal Policy Statement, USNRC, "Use of Probabilistic Risk Assessment Methods in Nuclear Activities: Final Policy Statement," Federal Register, Volume 60, p.42622, August 16, 1995.

7.2.4. Nuclear Utility Management and Resource Council (NUMARC) 87-00, "Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors," Revision 1, August 1991.

7.2.5. Branch Technical Position (BTP) 8-8, "Onsite (Diesel Generators) and Offsite Power Sources Allowed Outage Extensions," Initial Issue May 2011.

7.2.6. Regulatory Guide 1.155, Station Blackout, 8/1988.

7.2.7. Generic Letter 2006-02, "Grid Reliability and the Impact on Plant risk and the Operability of Offsite Power."

7.2.8. NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Section 8.4, 111.3.O.iv.

7.2.9. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities," Revision 2, March 2009.

Page 32 of 32

BSEP 11-0097 Enclosure 1A DIESEL GENERATOR COMPLETION TIME EXTENSION FIGURES FIGURES Figure 1, SUPP-DG Location within Plant Figure 2, SUPP-DG Tie-In to Plant Electrical System

SWITCH YARD LI-B313 RELAY HOUSE 11 LU9JSEWGE RATMENT P1LANT Ho UNIT 2 Fi--JI Ed UNIT 1 XFMR XFMR c~f.

nolonl FIRE--"'

HYDRANIT S4HROVP TURBINE BUILDING TURBINE BUILDING UNIT 2 UNIT 1 B306 B306 IM~I COUNTY WATER STORAGE

)

SUPP-DG Location Site Plot Plan Reference F-01021

UAT #2 SAT #2 *SAT #1 UAT #1 Common Common New Equipment

, E6 SUPP-DG ONE UNE DIAGRAM Reretnce F-03043, F-03044

BSEP 11-0097 Enclosure 2 DIESEL GENERATOR COMPLETION TIME EXTENSION PROPOSED BSEP TS AND TS BASES (MARK-UP)

PROPOSED BSEP TS AND TS BASES (MARK-UP)

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One offsite circuit inoperable C.1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for reasons other than OPERABLE offsite Condition A or B. circuit(s). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND C.2 Declare required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from with no offsite power discovery of no available inoperable when offsite power to one the redundant required 4.16 kV emergency feature(s) are inoperable. bus concurrent with inoperability of redundant required feature(s)

AND C.3 Restore offsite circuit to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

AND 1740 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 1 3.8-3 Amendment No. 205

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One DG inoperable for D. 1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months reasons other than OPERABLE offsite Condition B. circuit(s). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND n 17 L

I%va"hiL, annilnhilif,, rf 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months supplemental diesel generator (SUPP-DG). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND D.32 Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from feature(s), supported by discovery of the inoperable DG, Condition D inoperable when the concurrent with redundant required inoperability of feature(s) are inoperable. redundant required feature(s)

AND D.43.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(s) are not inoperable due to common cause failure.

OR D.43.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE DG(s).

AND (continued)

Brunswick Unit 1 3.8-4 Amendment No. 205

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.54 Restore DG to OPERABLE 7 days from status. discovery of unavailability of SUPP-DG AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition D entry

> 6 days concurrent with unavailability of SUPP-DG AND 14 days AND 17-40 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 1 3.8-5 Amendment No. 205

AC Sources-Operating B 3.8.1 BASES BACKGROUND Certain required plant loads are returned to service in a predetermined (continued) sequence in order to prevent overloading of the DGs in the process. The starting sequence of all automatically connected loads needed to recover the unit or maintain it in a safe condition is provided in UFSAR, Table 8-7 (Ref. 4).

Ratings for the DGs satisfy the requirements of Safety Guide 9 (Ref. 5).

Each DG has the following ratings:

a. 3500 kW-continuous; and

b. 3850 kW-2000 hours.

The capability is provided to connect a supplemental diesel generator (SUPP-DG) to supply power to any of the four 4.16 kV emergency buses via a BOP circuit path. This BOP circuit path consists of the BOP bus and the associated circuit path (master/slave breakers and interconnecting cables) to a 4.16 kV emergency bus. The SUPP-DG is commercial-grade and not designed to meet Class 1 E requirements. The SUPP-DG is made available to support extended Completion Times in the event of an inoperable DG. The SUPP-DG is made available as a defense-in-depth alternate source of AC power to one emergency bus to mitigate a station blackout event. The SUPP-DG would remain disconnected from the Class 1 E distribution system unless required durinq a station blackout.

APPLICABLE The initial conditions of DBA and transient analyses in the UFSAR, SAFETY ANALYSES Chapter 6 (Ref. 6) and Chapter 15 (Ref. 7), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded.

These limits are discussed in more detail in the Bases for Section 3.2, "Power Distribution Limits"; Section 3.5, "Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC)

System"; and Section 3.6, "Containment Systems."

The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining the onsite or offsite AC sources OPERABLE during accident conditions in the event of:

a. An assumed loss of all offsite power; and

b. A worst case single failure.

AC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 8).

LCO Two Unit 1 and two Unit 2 qualified circuits between the offsite transmission network and the onsite Class 1 E Distribution System and Brunswick Unit 1 B 3.8.1-3 Revision No. 36

AC Sources-Operating B 3.8.1 four separate and independent DGs (1, 2, 3, and 4) ensure availability of the required power to shut down the reactor and maintain it in a safe (continued)

Brunswick Unit 1 B 3.8.1-4 Revision No. 36

AC Sources-Operating B 3.8.1 BASES ACTIONS C.2 (continued)

The remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection may have been lost for the required feature's function; however, function is not lost. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

C.3 According to Regulatory Guide 1.93 (Ref. 9), operation may continue in Condition C for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this condition, however, the remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action C.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1 .a or b. If Condition C is entered while, for instance, a DG is inoperable, and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 147-days.

This situation could lead to a total of 174-0 days, since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 14.7 days (for a total of 3147-days) allowed prior to complete restoration of the LCO. The 1740 day Completion Time provides a limit on the time allowed (continued)

Brunswick Unit 1 B 3.8.1-12 Revision No. 31

AC Sources-Operating B 3.8.1 BASES ACTIONS C.3 (continued) in a specified condition after discovery of failure to meet LCO 3.8.1 .a or b.

This limit is considered reasonable for situations in which Conditions C and D are entered concurrently. The "AND" connector between the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 17..._ day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action C.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time LCO 3.8.1 .a or b was initially not met, instead of at the time that Condition C was entered.

D.1 To ensure a highly reliable power source remains with one DG inoperable, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure to meet SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered.

D.2 In order to extend the Required Action D.5 Completion Time for an inoperable DG from 7 days to 14 days inoperable, it is necessary to verify the availability of the SUPP-DG within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months on entry into TS 3.8.1 LCO and every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. Since Required Action D.2 only specifies "evaluate," discovering the SUPP-DG unavailable does not result in the Required Action beinq not met (i.e., the evaluation is performed).

However, on discovery of an unavailable SUPP-DG. the Completion Time for Required Action D.5 starts the 7 day and/or 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months clock.

SUPP-DG availability requires that:

1) The load test has been performed within 30 days of entry into the extended Completion Time. The Required Action evaluation is met with an administrative verification of this prior testing:

2) SUPP-DG fuel tank level is verified locally to be > 24-hour supply; and

3) SUPP-DG supporting system parameters for starting and operating are verified to be within required limits for functional availability (e.g., battery state of char-ge, starting air system pressure).

The SUPP-DG is not used to extend the Completion Time for more than one inoperable DG at any one time.

D.32 Required Action D.32 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are Brunswick Unit 1 B 3.8.1-13 Revision No. 31

AC Sources-Operating B 3.8.1 designed to be powered from redundant safety related 4.16 kV emergency buses (i.e., single division systems are not included).

Redundant required feature failures consist of inoperable features associated with an emergency bus redundant to the emergency bus that has an inoperable DG.

(continued)

Brunswick Unit 1 B 3.8.1-14 Revision No. 31

AC Sources-Operating B 3.8.1 BASES ACTIONS D.32 (continued)

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. A redundant required feature on another emergency bus is inoperable.

If, at any time during the existence of this Condition (one DG inoperable),

a required redundant feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering one DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DGs results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature.

Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

(continued)

Brunswick Unit 1 B 3.8.1-15 Revision No. 31

AC Sources-Operating B 3.8.1 BASES ACTIONS D.43.1 and D.43.2 (continued)

Required Action D.43.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DGs, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s), they are declared inoperable upon discovery, and Condition G or I of LCO 3.8.1 is entered, as applicable. Once the failure is repaired, and the common cause failure no longer exists, Required Action D.43.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s), performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of those DGs.

In the event the inoperable DG is restored to OPERABLE status prior to completing either D.43.1 or D.43.2 (i.e., the inoperable DG has been restored to OPERABLE status but it has not yet been determined if the cause of the inoperability is common to the other OPERABLE DGs), the CP&L Corrective Action Program (CAP) will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer required under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition D.

According to Generic Letter 84-15 (Ref. 10), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is a reasonable time to confirm that the OPERABLE DGs are not affected by the same problem as the inoperable DG.

D.54 The 4.16 kV emergency bus design is sufficient to allow operation to continue in Condition D for a period that should not exceed 14.7 days if the SUPP-DG is available.

If the SUPP-DG is or becomes unavailable with an inoperable DG, then action is required to restore the SUPP-DG to available status or to restore the DG to OPERABLE status within 7 days from discovery of an unavailable SUPP-DG. However, if the SUPP-DG unavailability occurs sometime after 6 days of continuous DG inoperability, then the remaininq time to restore the SUPP-DG to available status or to restore the DG to OPERABLE status is limited to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

The 7 day and 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Times allow for an exception to the normal "time zero" for beginning the allowed outage time "clock." The 7 day Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. The SUPP-DG is unavailable.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time only begins on discovery that:

a. An inoperable DG exists for ? 6 davs: and

b. The SUPP-DG is unavailable.

Brunswick Unit 1 B 3.8.1-16 Revision No. 31

AC Sources-Operating B 3.8.1 Therefore, when one required DG is inoperable due to either preplanned maintenance (preventive or corrective) or unplanned corrective maintenance work, the Completion Time can be extended from 7 days to 14 days if the SUPP-DG is verified available for backup operation.

In Condition D, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. The 147- day Completion Time takes into account the capacity and capability of the remaining AC sources (including SUPP-DG), a reasonable time for repairs, and the low probability of a DBA occurring during this period.

(continued)

Brunswick Unit 1 B 3.8.1-17 Revision No. 31

AC Sources-Operating B 3.8.1 BASES ACTIONS D.54 (continued)

The fourthseeeFAA Completion Time for Required Action D.54 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1.a or b. If Condition D is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This situation could lead to a total of 17 days, since initial failure of the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 20.44 days) allowed prior to complete restoration of the LCO. The 171-0 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet LCO 3.8.1.a or b. This limit is considered reasonable for situations in which Conditions C and D are entered concurrently. The "AND" connector between the 14.7 day and 171-0 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.

As in Required Action C.394, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that LCO 3.8.1 .a or b was initially not met, instead of the time that Condition D was entered.

E.1 and E.2 Required Action E.1 addresses actions to be taken in the event of inoperability of redundant required features concurrent with inoperability of two or more offsite circuits. Required Action E.1 reduces the vulnerability to a loss of function. The Completion Time for taking these actions is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed with one 4.16 kV emergency bus without offsite power (Required Action C.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref. 9) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two offsite circuits inoperable, based upon the assumption that two complete safety divisions are OPERABLE.

While this Action allows more than two circuits (continued)

Brunswick Unit 1 B 3-8.1-18 Revision No. 31

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION ICOMPLETION TIME C. One offsite circuit inoperable C. 1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for reasons other than OPERABLE offsite Condition A or B. circuit(s). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND C.2 Declare required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from with no offsite power discovery of no available inoperable when offsite power to one the redundant required 4.16 kV emergency feature(s) are inoperable. bus concurrent with inoperability of redundant required feature(s)

AND C.3 Restore offsite circuit to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

AND 17:.-9 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 2 3.8-3 Amendment No. 235

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One DG inoperable for D. 1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months reasons other than OPERABLE offsite Condition B. circuit(s). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND D.2 Evaluate availability of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months supplemental diesel generator (SUPP-DG). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND D.3-2 Declare required feature(s), 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from supported by the inoperable discovery of DG, inoperable when the Condition D redundant required concurrent with feature(s) are inoperable. inoperability of redundant required feature(s)

AND D.43.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(s) are not inoperable due to common cause failure.

OR D.43.2 Perform SR 3.8.1.2 for OPERABLE DG(s).

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months I

AND (continued)

Brunswick Unit 2 3.8-4 Amendment No. 235

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.54 Restore DG to OPERABLE 7 days from status. discovery of unavailability of SUPP-DG AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition D entry

> 6 days concurrent with unavailability of SUPP-DG AND 14 days AND 1740 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 2 3.8-5 Amendment No. 235

AC Sources-Operating B 3.8.1 BASES BACKGROUND Certain required plant loads are returned to service in a predetermined (continued) sequence in order to prevent overloading of the DGs in the process. The starting sequence of all automatically connected loads needed to recover the unit or maintain it in a safe condition is provided in UFSAR, Table 8-7 (Ref. 4).

Ratings for the DGs satisfy the requirements of Safety Guide 9 (Ref. 5).

Each DG has the following ratings:

a. 3500 kW-continuous; and

b. 3850 kW-2000 hours.

The capability is provided to connect a supplemental diesel generator (SUPP-DG) to supply power to any of the four 4.16 kV emergency buses via a BOP circuit path. This BOP circuit path consists of the BOP bus and the associated circuit path (master/slave breakers and interconnecting cables) to a 4.16 kV emergency bus. The SUPP-DG is commercial-grade and not designed to meet Class 1E requirements. The SUPP-DG is made available to support extended Completion Times in the event of an inoperable DG. The SUPP-DG is made available as a defense-in-depth alternate source of AC power to one emer-gency bus to mitigate a station blackout event. The SUPP-DG would remain disconnected from the Class IE distribution system unless required during a station blackout.

APPLICABLE The initial conditions of DBA and transient analyses in the UFSAR, SAFETY ANALYSES Chapter 6 (Ref. 6) and Chapter 15 (Ref. 7), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded.

These limits are discussed in more detail in the Bases for Section 3.2, "Power Distribution Limits"; Section 3.5, "Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC)

System"; and Section 3.6, "Containment Systems."

The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining the onsite or offsite AC sources OPERABLE during accident conditions in the event of:

a. An assumed loss of all offsite power; and

b. A worst case single failure.

AC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 8).

LCO Two Unit 1 and two Unit 2 qualified circuits between the offsite transmission network and the onsite Class 1 E Distribution System and Brunswick Unit 2 B 3.8.1-3 Revision No. 33

AC Sources-Operating B 3.8.1 four separate and independent DGs (1, 2, 3, and 4) ensure availability of the required power to shut down the reactor and maintain it in a safe (continued)

Brunswick Unit 2 B 3.8.1-4 Revision No. 33

Distribution Systems-Shutdown B 3.8.8 BASES ACTIONS C.2 (continued)

The remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection may have been lost for the required feature's function; however, function is not lost. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

C.3 According to Regulatory Guide 1.93 (Ref. 9), operation may continue in Condition C for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this condition, however, the remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action C.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1.a or b. If Condition C is entered while, for instance, a DG is inoperable, and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 147 days.

This situation could lead to a total of 174-0 days, since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 14_7 days (for a total of 3147 days) allowed prior to complete restoration of the LCO. The 174-0 day Completion Time provides a limit on the time allowed (continued)

Brunswick Unit 2 B 3.8.8-5 Revision No. 30 I

Distribution Systems-Shutdown B 3.8.8 BASES ACTIONS C.3 (continued) in a specified condition after discovery of failure to meet LCO 3.8.1 .a or b.

This limit is considered reasonable for situations in which Conditions C and D are entered concurrently. The "AND" connector between the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 1740 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action C.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time LCO 3.8.1 .a or b was initially not met, instead of at the time that Condition C was entered.

b.1 To ensure a highly reliable power source remains with one DG inoperable, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure to meet SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered.

D.2 In order to extend the Required Action D.5 Completion Time for an inoperable DG from 7 days to 14 days inoperable, it is necessary to verify the availability of the SUPP-DG within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months on entry into TS 3.8.1 LCO and every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. Since Required Action D.2 only specifies "evaluate," discovering the SUPP-DG unavailable does not result in the Required Action being not met (i.e., the evaluation is performed).

However, on discovery of an unavailable SUPP-DG, the Completion Time for Required Action D.5 starts the 7 day and/or 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months clock.

SUPP-DG availability requires that:

1) The load test has been performed within 30 days of entry into the extended Completion Time. The Required Action evaluation is met with an administrative verification of this prior testing:

2) SUPP-DG fuel tank level is verified locally to be > 24-hour supply: and

3) SUPP-DG supporting system parameters for starting and operating are verified to be within required limits for functional availability (e.q., batter state of char-qe, starting air system pressure).

The SUPP-DG is not used to extend the Completion Time for more than one inoperable DG at any one time.

D.32 Required Action D.32 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are Brunswick Unit 2 B 3.8.8-6 Revision No. 30 1

Distribution Systems-Shutdown B 3.8.8 designed to be powered from redundant safety related 4.16 kV emergency buses (i.e., single division systems are not included).

Redundant required feature failures consist of inoperable features associated with an emergency bus redundant to the emergency bus that has an inoperable DG.

(continued)

Brunswick Unit 2 B 3.8.8-7 Revision No. 30 I

Distribution Systems-Shutdown B 3.8.8 BASES ACTIONS D.32 (continued)

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. A redundant required feature on another emergency bus is inoperable.

If, at any time during the existence of this Condition (one DG inoperable),

a required redundant feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering one DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DGs results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature.

Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

(continued)

Brunswick Unit 2 B 3.8.8-8 Revision No. 30

Distribution Systems-Shutdown B 3.8.8 BASES ACTIONS D.43.1 and D.43.2 (continued)

Required Action D.43.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s),

they are declared inoperable upon discovery, and Condition G or I of LCO 3.8.1 is entered, as applicable. Once the failure is repaired, and the common cause failure no longer exists, Required Action D.43.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s), performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of those DGs.

In the event the inoperable DG is restored to OPERABLE status prior to completing either D.43.1 or D.43.2 (i. e., the inoperable DG has been restored to OPERABLE status but it has not yet been determined if the cause of the inoperability is common to the other OPERABLE DGs), the CP&L Corrective Action Program (CAP) will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer required under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition D.

According to Generic Letter 84-15 (Ref. 10), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is a reasonable time to confirm that the OPERABLE DGs are not affected by the same problem as the inoperable DG.

D.54 The 4.16 kV emergency bus design is sufficient to allow operation to continue in Condition D for a period that should not exceed 147- days if the SUPP-DG is available.

If the SUPP-DG is or becomes unavailable with an inoperable DG, then action is required to restore the SUPP-DG to available status or to restore the DG to OPERABLE status within 7 days from discovery of an unavailable SUPP-DG. However, if the SUPP-DG unavailability occurs sometime after 6 days of continuous DG inoperability, then the remaininq time to restore the SUPP-DG to available status or to restore the DG to OPERABLE status is limited to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

The 7 day and 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Times allow for an exception to the normal "time zero" for beginning the allowed outage time "clock." The 7 day Completion Time only begins on discovery that both:

a. An inoperable DG exists: and

b. The SUPP-DG is unavailable.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time only begins on discovery that:

a. An inoperable DG exists for > 6 days: and

b. The SUPP-DG is unavailable.

Brunswick Unit 2 B 3.8.8-9 Revision No. 30 1

Distribution Systems-Shutdown B 3.8.8 Therefore, when one required DG is inoperable due to either preplanned maintenance (preventive or corrective) or unplanned corrective maintenance work, the Completion Time can be extended from 7 days to 14 days if the SUPP-DG is verified available for backup operation.

In Condition D, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. The 147- day Completion Time takes into account the capacity and capability of the remaining AC sources (including SUPP-DG), a reasonable time for repairs, and the low probability of a DBA occurring during this period.

(continued)

Brunswick Unit 2 B 3.8.8-10 Revision No. 30 I

Distribution Systems-Shutdown B 3.8.8 BASES ACTIONS D.54 (continued)

The fourthsenepd Completion Time for Required Action D.54 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1.a or b. If Condition D is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This situation could lead to a total of 17--0 days, since initial failure of the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 20.._ days) allowed prior to complete restoration of the LCO. The 174-0 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet LCO 3.8.1.a or b. This limit is considered reasonable for situations in which Conditions C and D are entered concurrently. The "AND" connector between the 147-day and 174-0 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.

As in Required Action C.3-.Q, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that LCO 3.8.1 .a or b was initially not met, instead of the time that Condition D was entered.

E.1 and E.2 Required Action E.1 addresses actions to be taken in the event of inoperability of redundant required features concurrent with inoperability of two or more offsite circuits. Required Action E.1 reduces the vulnerability to a loss of function. The Completion Time for taking these actions is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed with one 4.16 kV emergency bus without offsite power (Required Action C.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref. 9) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two offsite circuits inoperable, based upon the assumption that two complete safety divisions are OPERABLE.

While this Action allows more than two circuits (continued)

Brunswick Unit 2 B 3.8.8-11 Revision No. 30 I

BSEP 11-0097 Enclosure 3 DIESEL GENERATOR COMPLETION TIME EXTENSION PROPOSED BSEP TS (RETYPED PAGES)

PROPOSED BSEP TS (RETYPED PAGES)

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One offsite circuit inoperable C.1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for reasons other than OPERABLE offsite Condition A or B. circuit(s). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND C.2 Declare required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from with no offsite power discovery of no available inoperable when offsite power to one the redundant required 4.16 kV emergency feature(s) are inoperable. bus concurrent with inoperability of redundant required feature(s)

AND C.3 Restore offsite circuit to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

AND 17 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 1 3.8-3 Amendment No. 205

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One DG inoperable for D.1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months reasons other than OPERABLE offsite Condition B. circuit(s). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND D.2 Evaluate availability of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months supplemental diesel generator (SUPP-DG). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND D.3 Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from feature(s), supported by discovery of the inoperable DG, Condition D inoperable when the concurrent with redundant required inoperability of feature(s) are inoperable. redundant required feature(s)

AND D.4.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(s) are not inoperable due to common cause failure.

OR D.4.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE DG(s).

AND (continued)

Brunswick Unit 1 3.8-4 Amendment No. 205

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.5 Restore DG to OPERABLE 7 days from status. discovery of unavailability of SUPP-DG AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition D entry

> 6 days concurrent with unavailability of SUPP-DG AND 14 days AND 17 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 1 3.8-5 Amendment No. 205

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One offsite circuit inoperable C.1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for reasons other than OPERABLE offsite Condition A or B. circuit(s). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND C.2 Declare required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from with no offsite power discovery of no available inoperable when offsite power to one the redundant required 4.16 kV emergency feature(s) are inoperable, bus concurrent with inoperability of redundant required feature(s)

AND C.3 Restore offsite circuit to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

AND 17 days from discovery of failure to meet LCO 3.8. 1.a or b (continued)

Brunswick Unit 2 3.8-3 Amendment No. 235

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One DG inoperable for D.1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months reasons other than OPERABLE offsite Condition B. circuit(s). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND D.2 Evaluate availability of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months supplemental diesel generator (SUPP-DG). AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND D.3 Declare required feature(s), 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from supported by the inoperable discovery of I DG, inoperable when the Condition D redundant required concurrent with feature(s) are inoperable. inoperability of redundant required feature(s)

AND D.4.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(s) are not inoperable due to common cause failure.

OR D.4.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE DG(s). I AND I.

(continued)

Brunswick Unit 2 3.8-4 Amendment No. 235

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.5 Restore DG to OPERABLE 7 days from status. discovery of unavailability of SUPP-DG AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition D entry

> 6 days concurrent with unavailability of SUPP-DG AND 14 days AND 17 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 2 3.8-5 Amendment No. 235

BSEP 11-0097 Enclosure 4 DIESEL GENERATOR COMPLETION TIME EXTENSION PRA EVALUATION OF RISK IMPACT INCLUDING TREATMENT OF UNCERTAINTIES PRA EVALUATION OF RISK IMPACT INCLUDING TREATMENT OF UNCERTAINTIES

PRA Evaluation of Risk Impact, Including Treatment of Uncertainties Tier 1: Risk Assessment 4.1. Acronyms AOT Allowed Outage Time AOV Air Operated Valve BNP Brunswick Nuclear Plant BOP Balance of Plant BSEP Brunswick Steam Electric Plant BWROG Boiling Water Reactor Owners Group CCF Common Cause Failure CDF Core Damage Frequency CET Containment Event Tree CRD Control Rod Drive CSP Core Spray Pump CSW Conventional Service Water CT Completion Time DG Diesel Generator EPRI Electric Power Research Institute ET Event Tree F&O Findings and Observations FTR Fail to Run FTS Fail to Start FV Fusel Vesley HCLPF High Confidence of Low Probability of Failure HEP Human Error Probability HPCI High Pressure Coolant Injection HRA Human Reliability Analysis HRR Heat Release Rate HVAC Heating Ventilating and Air Conditioning ICCDP Incremental Conditional Core Damage Probability ICLERP Incremental Conditional Large Early Release Probability IPE Individual Plant Examination IPEEE Individual Plant Examination for External Events LERF Large Early Release Frequency LOCA Loss of Coolant Accident LOOP Loss of Offsite Power LPCI Low Pressure Coolant Injection MOR Model of Record MOV Motor Operated Valve MSO Multiple Spurious Operations NSW Nuclear Service Water RAW Risk Achievement Worth RCIC Reactor Core Isolation Cooling Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 1

RHRSW Residual Heat Removal Service Water SBO Station Blackout SR Supporting Requirement SRV Safety Relief Valve SSC Structure, System or Component SUPP-DG Supplemental Diesel Generator T&M Test and Maintenance TS Technical Specifications URI Uncertainty Risk Impact 4.2. PRA Scope This section documents the Probabilistic Risk Assessment (PRA) conducted in support of the proposed Technical Specifications (TS) change to extend the Completion Time (CT) from 7 days to 14 days associated with an inoperable diesel generator (DG) while a unit is in Mode 1, 2, or 3. The impact of the proposed TS changes for this application on the risk metrics ACDF, ICCDP, ALERF, and ICLERP were evaluated with four BNP specific PRA models; a Level 1 Internal Events model with external and internal flooding, a Level 1 fire model, a Level 1 high winds model, and a LERF model. Seismic and other external events were qualitatively evaluated using the IPEEE methodologies.

The review history and associated quality of these models is presented in the attached PRA Quality Report (Enclosure 5). A discussion of the qualitative risk impact of a dual unit shutdown as currently required to support extended diesel maintenance is discussed in section 4.5 of this enclosure.

The BNP PRA models in detail the DG's, support systems, interactions with the other plant systems and components, unavailability's, and the important human actions needed for success. The model developed to evaluate the conditions for the application includes the same level of detail for the proposed supplemental diesel generator (SUPP-DG).

4.3. PRA Quality A report documenting the quality of the PRA was developed and is included as to this submittal.

4.4. PRA Model Development for Application The baseline model was modified to enhance portions of the model that might significantly impact the application which involves two changes to risk due to the addition of a SUPP-DG that backs up a DG in an extended outage. The first is adding a new 14 day test and maintenance (T&M) interval for each DG. Since the normal T&M unavailability is represented in the PRA baseline model by a T&M event, the application was modeled by a new T&M unavailability (in addition to the existing T&M event) to represent 14 days of unavailability (consistent with RG 1.177 approach). The second is the addition of a SUPP-DG capable of powering the same loads that any one DG can Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 2

power. This SUPP-DG is capable of backing up the DG that is unavailable due to the extended T&M. The SUPP-DG is new and was not credited in the baseline PRA model.

It was added to the application model in the same level of detail as the existing DG's.

Though the SUPP-DG is intended to backup the DG that is out-of-service, and power that E-Bus under the SBO Licensing Basis event, the SUPP-DG can be aligned to any of the four E-buses under the SBO licensing event in consideration of which single DG is the single AC source of power, and in consideration of the SBO Procedure (OAOP-36.2) to cross-tie E-buses within the division to power battery chargers on the opposite unit. However, it is only modeled in this application as backing up the DG that is in the extended maintenance outage.

The SUPP-DG must be manually started and aligned. The SUPP-DG installation has 5 new tie breakers, one for each Balance of Plant (BOP) bus and one SUPP-DG output breaker. Each of the 4 breakers ties into its respective unit bus (1 C, 1D, 2C or 2D). The SUPP-DG and its support equipment are housed in seismically rugged enclosures that are elevated to protect the equipment from flooding caused by storm surges and strong enough to withstand a 3 second wind burst of 155 mph.

To model the application, the baseline BNP PSA 2011 model (including high winds and internal flooding) was modified by AND'ing logic for the SUPP-DG with each DG extended test and maintenance event. The MOR utilizes DG T&M events with unavailability's based on plant experience and limited to 7 days. Therefore, an extended T&M event (14 days) was added to the model for each DG. These new events were made mutually exclusive with each other and with the normal DG T&M events. The logic therefore allows each DG to be placed in an extended outage during the same critical power year, but not at the same time another DG is unavailable. The logic only credits the SUPP-DG for the time that a DG is in an extended outage. It does NOT credit the SUPP-DG at any other time.

The logic for the SUPP-DG includes:

Fail to start Fail to run Operator action failure Bus breaker failure (4 for each line-up; 2 new breakers and 2 existing breakers between the BOP bus and the essential bus)

Failure due to high winds Failure due to external flooding DC power for existing breakers After a scram, the SUPP-DG does not depend on any plant support system other than DC control power for the breakers. The entire SUPP-DG system, excluding the tie breakers to the BOP busses, is considered a super-component and modeled as such.

The feeder breakers between the BOP bus and the applicable essential bus are open at the time of the action and need to be closed for SUPP-DG success. Closing these breakers is in the application PRA model and the HRA. The breakers from the Unit Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 3

Auxiliary Transformer and the Start-up Transformers to the BOP busses have to open along with the supply feeding the common busses from BOP busses 1C, 1D, 2C, and 2D.

4.4.1. Development of Basic Events The basic events developed to support the application modeling are presented in Table A4-1 below. Explanations for the evaluation of probabilities for the new events are provided following the table.

Table A4-1: New Basic Events for Application Model New Basic Event Description Probability EF SDG1DGN-FS-001 SUPPLEMENTAL DIESEL GENERATOR FAILS TO START 5.38E-03 /D 1.8 SDG1DGN-FR-001 SUPPLEMENTAL DIESEL GENERATOR FAILS TO RUN 5.90E-02 /hr 1.7 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL 5.20E-03 5.0 GENERATOR

%EXTFL I Probability of a 23 Foot Storm Surge 5.OOE-05 /yr N/A

%EXTFL 2 Probability of a 20 Foot Flood 7.40E-04 /yr N/A FL EXTFLOOD Flag to enable external flood evaluation 1.OOE+00 N/A EDGilDGN-EXTTM-D001 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 3.84E-02 /yr 1.0 EDG1DGN-EXTTM-D001 days)

EDGi DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 3.84E-02 /yr 1.0 days)

EDG2DGN-E)(TTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 3.84E-02 /yr 1.0 EDG2DGN-EXTTM-D003______ days)

EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 3.84E-02 /yr 1.0 days)

ACPOBKR-OO-SDG AC CIRCUIT BREAKER FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-SDG1 AC CIRCUIT BREAKER FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-SDG2 AC CIRCUIT BREAKER FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-SDG3 AC CIRCUIT BREAKER FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-SDG4 AC CIRCUIT BREAKER FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-1AD1 CIRCUIT BREAKER 1-AD1 FAILS TO CLOSE (1 demand - use type 2.55E-03 4.7 code)

ACPOBKR-OO-AE6 CIRCUIT BREAKER AE6 FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-AG4 CIRCUIT BREAKER AG4 FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-1AC8 CIRCUIT BREAKER 1-AC8 FAILS TO CLOSE (1 demand - use type 2.55E-03 4.7 code)

ACPOBKR-OO-AI2 CIRCUIT BREAKER A12 FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-2AD1 AC CIRCUIT BREAKER FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-AJ9 CIRCUIT BREAKER AJ9 FAILS TO CLOSE (1 demand - use type code) 2.55E-03 4.7 ACPOBKR-OO-2AC8 CIRCUIT BREAKER 2-AC8 FAILS TO CLOSE (1 demand - use type 2.55E-03 4.7 code)

HW SDG H1 01 FAILURE OF SDG FOR HIGH WIND INTERVAL 1 0.00e+0 N/A HW SDG T1 01 TORNADO-INDUCED FAILURE OF SDG FOR HIGH WIND INTERVAL 1 0.00e+0 N/A 11WSDGMi_01 WIND BORN MISSILE STRIKE FAILURE OF SDG FOR HIGH WIND 0.O0e+0 N/A INTERVAL1 HW SDG H1 02 FAILURE OF SDG FOR HIGH WIND INTERVAL 2 0.00e+0 N/A HW SDG Ti 02 TORNADO-INDUCED FAILURE OF SDG FOR HIGH WIND INTERVAL 2 0.00e+0 N/A HWSOGMi 02 WIND BORN MISSILE STRIKE FAILURE OF SDG FOR HIGH WIND 2.09E-04 N/A INTERVAL 2 HW SDG H1 03 FAILURE OF SDG FOR HIGH WIND INTERVAL 3 0.00e+0 N/A HW SDG T1 03 TORNADO-INDUCED FAILURE OF SDG FOR HIGH WIND INTERVAL 3 0.00e+0 N/A 11WSDGMi_03 WIND BORN MISSILE STRIKE FAILURE OF SDG FOR HIGH WIND 3.68E-04 N/A INTERVAL 3 HW SDG H1 04 FAILURE OF SDG FOR HIGH WIND INTERVAL 4 1.OOE+0 N/A HW SDG T1 04 TORNADO-INDUCED FAILURE OF SDG FOR HIGH WIND INTERVAL 4 1.00E+0 N/A 11WSDGMi_04 WIND BORN MISSILE STRIKE FAILURE OF SDG FOR HIGH WIND i.OOE+0 N/A INTERVAL 4 HW SDG H1 05 FAILURE OF SDG FOR HIGH WIND INTERVAL 5 1.OOE+0 N/A HW SDG T1 05 TORNADO-INDUCED FAILURE OF SDG FOR HIGH WIND INTERVAL 5 1.OOE+0 N/A 11WSDG Mi HWSD M1 055 WIND BORN MISSILE STRIKE FAILURE OF SDG FOR HIGH WIND i.OOE+0 N/A I INTERVAL5 Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 4

HW SDG HI 06 FAILURE OF SDG FOR HIGH WIND INTERVAL 6 1.OOE+0 N/A HW SDG TI 06 TORNADO-INDUCED FAILURE OF SDG FOR HIGH WIND INTERVAL 6 1.OOE+0 N/A HWSDG M1_06 WIND BORN MISSILE STRIKE FAILURE OF SDG FOR HIGH WIND 1.OOE+ N WS M INTERVAL 6 Basic Event OPER-SDSTART is a new operator action added to reflect the assigned operator to perform those actions necessary to start and align the SUPP-DG to the applicable essential bus. The human failure event was developed using the EPRI HRA Calculation tool consistent with the other internal events HRA actions in the BNP Plant Specific Model. It incorporated input from site operations.

%EXTFL_2 is the initiating event for external flooding and utilizes the value of 7.4E-4/yr to represent the frequency of a hurricane that would generate a storm surge sufficient to fail the switchyard. The value and supporting evidence is obtained from the BNP IPEEE discussion of Other External Events.

%EXTFL_1 is the initiating event for external flooding and utilizes the value of 5.OE-5/yr to represent the frequency of a hurricane that would generate a storm surge sufficient to fail the switchyard, flood the diesel fire pumps, and prevent access to the supplemental DG. This frequency was developed from site specific historical hurricane data and associated conditions.

SDG1 DGN-FS-001 The Fail-To-Start probability used is the same as for the current model for a DG FTS.

This is conservative since the SUPP-DG is newer with digital control systems and does not rely on automatic start circuitry.

SDGlDGN-FR-001 The Fail-To-Run probability used is the same as for the current model DG FTR. This is conservative since the SUPP-DG is newer with digital control systems.

EDG1 DGN-EXTTM-D001 (2), EDG2DGN-EXTTM-D003(4)

The DG unavailabilities for the extended outage events are calculated on 14 days out of the year. (Freq = 14/365 /yr = 3.84E-2 /yr) This unavailability is in addition to the currently modeled DG unavailabilities.

The circuit breaker open-fail open probabilities used are the same as for the existing modeled AC breaker open-fail open failure mode.

The SUPP-DG is designed for a 3 sec wind gust of 155 mph. Therefore, the failure probability of the SUPP-DG for wind intervals below 135 mph (see Table A4-1 above) is assumed to be 0.0 except for missile strikes at high wind intervals 2 and 3, and the failure probability of the SUPP-DG for wind intervals above 135 mph is assumed to be 1.0.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 5

4.4.2. Baseline Model Changes The following changes were made to the baseline MOR:

1. Eliminated subtree #V-LP. This entirely deleted event OPER-NPSH, but did not eliminate subtree #V-LP1 for other tops it supported.

2. Under gates HWDGEX_001, HW_DG_EX_002, HWDGEX_003, and HWDGEX_004 deleted all of the sub trees for high wind and tornado failures of the exhausts. That left the model with only failures due to missiles (6 events for each DG). The BNP FSAR [Ref 6] states that the DG exhaust silencers were designed to withstand the effects of high winds and tornados (but not missile strikes).

3. Two external flooding initiating events were added to the baseline model. They both fail the LOOP recovery. The new flooding event %EXTFL_I also fails the diesel fire pump.

4.4.3. Application Modeling The following changes were made to the edited (as above) baseline model to form the application model:

1. Added the logic for the SUPP-DG and the new extended outage event to the appropriate power supply gates.

2. A new high winds model for the SUPP-DG was added to the SUPP-DG subtrees.

It uses the same wind initiator modeling as for the other high winds impacted systems.

3. The same external flooding events that were added to the baseline model were used in the application model. In addition, the new external flooding event

%EXTFL_1 also fails the supplemental DG.

The SUPP-DG does not add any new ignition sources to the Fire PRA, other than at the SUPP-DG itself, and no new targets other than those related to the cables connecting the SUPP-DG to the 4kV switchgears. The SUPP-DG and its associated support equipment, bus and tie breakers are located in an outside area adjacent to the switchyard and not in a fire zone within an existing building. A fire in the Startup Transformer for Unit 1 has the potential to fail the SUPP-DG due to proximity of SUPP-DG cables being routed to the 1C, 1D, 2C, or 2D buses. Similarly a fire in the switchgear room has the potential to fail the SUPP DG due to cable proximity in these areas. A fire in the SUPP-DG zone would not impact any SSC's other than the SUPP-DG itself. The failure frequencies of the SUPP-DG include the effects of fires. Since the SUPP-DG is normally separated from the remainder of the plant with open 4kv breakers, a SUPP-DG fire would not cause failures or spurious operations of other Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 6

SCC's associated with the 4kv electrical systems. A fire that fails the E-bus that the SUPP-DG is backing up while the associated DG is in an extended CT would have also failed the applicable DG if it were in-service. The intermediate non-essential 4kv bus the SUPP-DG is tied to is already modeled for the effects of fires. The addition of the SUPP-DG does not change those modeling requirements. The SUPP-DG is connected to a balance of plant 480vac bus that provides power to support auxiliary equipment during standby conditions. The worst effect a fire at the SUPP-DG could have on this 480v supply would be to trip the protective devices between the bus and the SUPP-DG and could not fail the 480v bus itself. Additionally, the above 480v bus is a BOP bus and does not supply critical equipment. The SUPP-DG breakers are connected to an existing 250vdc system for breaker control. These breakers are normally open during power operation.

Human Reliability Analysis changes in the baseline model involved changes that were made to the recovery rule file (A common recovery rule file is used for both baseline and application models):

New HEP (human error probability) combinations were identified after quantifying both the baseline and application models to a truncation level discussed in section 4.6 Only the combinations that were in the delta cutset file were developed. The delta cutset file presents the cutsets remaining after the common cutsets between the associated baseline and application files were removed using the delete term function of CAFTA.

In the dependency analyses, discussed in the PRA Uncertainty Analysis section (section 4.8 of this enclosure), the two actions to cross tie the 4kv and 480v busses before the SUPP-DG start showed up consistently throughout the combinations. The 4kv action was always placed first in consideration when evaluating the combinations.

These actions are SBO licensing basis actions (AOP-36.2).

4.4.4. Common Cause Failure Evaluation Because the SUPP-DG system in connected to the remainder of the plant SSC's through normally open and manually operated breakers, it has no effect on initiator frequencies or non-SUPP-DG system or component failure rates. Also, the SUPP-DG is not susceptible to Common Cause failure due to physical separation, different manufacturers, different design, different fuel oil supply, different environmental and operating conditions, the use of radiator cooling, and different operating and maintenance procedures, thus common cause was not modeled between the SUPP-DG and the DGs Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 7

4.5. Qualitative Evaluation of Shutdown Risk The risk of having a DG unavailable during a plant shutdown is considered to be greater than having it unavailable during power operation. The primary reason for this is the unavailability of non-AC dependent high pressure injection sources such as HPCI and RCIC during shutdown when steam is not available for these systems. This is a significant reduction in core cooling capability and, while not quantified, has a major negative impact on plant risk. Only the diesel fire pump remains available as a non-AC power dependent injection source. Therefore, the almost complete dependency on AC powered injection sources during plant shutdowns makes the diesel generator availabilities more important during shutdown than during power operation.

4.6. Quantitative Evaluation of Application Risk The baseline and application models for internal events, high winds, and fire were evaluated and cutsets were identified that were unique to the application results (delta cutset file). For each of these analyses, the top 25 cutsets, the RAW rankings above 10, and the FV rankings above 5E-3 are provided in Enclosure 6: PRA Quantification Data Tables. Because the initial quantification resulted in metrics within an order of magnitude of the initial 1E-1 1 truncation limit, both the baseline and application models were quantified with a truncation limit of 1E-12. The delta cutset file was reviewed and operator action combinations identified that were not yet defined. These combinations were evaluated for dependencies and the new combinations placed in the recovery rule file. A subsequent quantification provided metrics that were more than one order of magnitude from the 1E-1 1 truncation limit. All subsequent Level 1 quantifications were performed with a truncation limit of 1E-11. The LERF model was truncated at 1E-12.

Due to the fact that most of the top 25 Level 1 cutsets were long term non-SBO loss of decay heat removal sequences, it was clear that the application has a very small impact on LERF. Therefore, the LERF models were not quantified at a lower truncation limit.

Four models were used to quantify the metrics specified for consideration in Reg.

Guides 1.174 and 1.177, the Internal Events model with both external and internal flooding, the fire PRA model, the high winds PRA model, and the LERF model.

The baseline and application model cutsets and importance rankings for the IE model with internal and external flooding were evaluated. Diesel generator redundancy is not contributing significantly to the delta risk. Except for two external flooding sequences, the failed sequences in the top 25 cutsets are non-SBO, long term loss of decay heat removal sequences. The primary contributor to these sequences is the failure of the operator to cross-tie 4kv and 480v AC emergency busses. This in turn fails one or more valves preventing the success of suppression pool cooling. The top 50 cutsets were scanned for different types of sequences and none were found.

For Unit 1, DG-2 is the most risk significant diesel generator. DG 3 and DG 4 generally serve Unit 2 via 4160V AC emergency buses E3 and E4. DG 1 and DG 2 generally serve Unit 1 via 4160V AC emergency buses El and E2. These buses can be cross Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 8

connected within a unit (i.e., El to E2 and E3 to E4) and in the opposite unit (i.e., El to E3 and E2 to E4). On Unit 1 side, 4160V bus El supply power to 480V AC substation bus E5. Similarly, 4160V bus E2 supply power to 480V AC substation bus E6. On Unit 2 side, 4160V bus E3 supply power to 480V AC substation bus E7. Similarly, 4160V bus E4 supply power to 480V AC substation bus E8. DG2 and DG 4 are important for the following reasons:

1-480V AC bus E8 provide power to the Diesel Generator Building Ventilation control logic through MCC 2-DGD. MCC 2-DGD carries most of the Diesel Generator Building loads per 001-50.4, "4160 Emergency Bus E-4 Electrical Load List" and Drawing F-03057. This is important because the Diesel Generator Building houses the Emergency Diesel Generators. Loss of HVAC would fail the DGs due to DG cell heat up or require manual recovery action.

2- Two Low Pressure Coolant Injection (LPCI) MOVs, 1-Ell-FO15A and l-Ell-F015B are supplied power from 480V AC buses E7 and E8 respectively. While their counterparts in Unit 2, 2-El 1-F015A and 2-El 1-F015B are supplied power from 480V AC buses E5 and E6 respectively..

3-4160V Emergency bus E4 carries most load which include the following pumps per 001-50.4, "4160 Emergency Bus E-4 Electrical Load List" and Drawing F-03003:

o CSP 2B o RHR 1B o RHR 2B o NSW 2B o CSW 1A o CSW 2B o CRD 2B o RHRSW 1B o RHRSW 2B o Fire PP (Alt)

The Electric Fire Pump is powered from one of two buses via a transfer switch. DG 4 is one of the two power supplies. The other is DG 2. Other significant loads on DG 4, as noted above when compared to the other DG loads, are the CSW pumps. DG 4 is one of the two Diesels that can support two different CSW pumps. The other is DG 1.

The results from those model evaluations are delineated in Table A4-2, A4-3, and A4-4 below.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 9

Table A4-2: Internal Events Model w/o External Flooding Evaluation Results Evaluation Metric J Result Unit 1 Baseline CDF 7.9E-06 /yr Unit 1 ACDF 3.9E-08 /yr Unit 1 ICCDP for DG 1 in extended maintenance 1.3E-08 Unit 1 ICCDP for DG 2 in extended maintenance 2.7E-08 Unit 1 ICCDP for DG 3 in extended maintenance 1.5E-08 Unit 1 ICCDP for DG 4 in extended maintenance 1.8E-08 Unit 2 Baseline CDF 7.5E-06 /yr Unit 2 ACDF 4.1E-08 /yr Unit 2 ICCDP for DG 1 in extended maintenance 1.6E-08 Unit 2 ICCDP for DG 2 in extended maintenance 1.7E-08 Unit 2 ICCDP for DG 3 in extended maintenance 1.6E-08 Unit 2 ICCDP for DG 4 in extended maintenance 2.6E-08 Table A4-3: Internal Events Model w/ External Flooding Evaluation Results Evaluation Metric ] Result Unit 1 Baseline CDF 7.9E-06 /yr Unit 1 ACDF 4.6E-08 /yr Unit 1 ICCDP for DG 1 in extended maintenance 1.4E-08 Unit 1 ICCDP for DG 2 in extended maintenance 3.1E-08 Unit 1 ICCDP for DG 3 in extended maintenance 1.7E-08 Unit 1 ICCDP for DG 4 in extended maintenance 2.2E-08 Unit 1 ALERF 4.6E-12 /yr Unit 1 ICLERP for DG 1 in extended maintenance 9.2E-12 Unit 1 ICLERP for DG 2 in extended maintenance 1.9E-11 Unit 1 ICLERP for DG 3 in extended maintenance 4.2E-12 Unit 1 ICLERP for DG 4 in extended maintenance 1.5E-1 1 Unit 2 Baseline CDF 7.6E-06 yr Unit 2 ACDF 4.8E-08 yr Unit 2 ICCDP for DG 1 in extended maintenance 1.9E-08 Unit 2 ICCDP for DG 2 in extended maintenance 2.2E-08 Unit 2 ICCDP for DG 3 in extended maintenance 1.8E-08 Unit 2 ICCDP for DG 4 in extended maintenance 3.OE-08 Unit 2 ALERF 4.OE-12 /yr Unit 2 ICLERP for DG 1 in extended maintenance 2.6E-12 Unit 2 ICLERP for DG 2 in extended maintenance 1.3E-1 1 Unit 2 ICLERP for DG 3 in extended maintenance 8.2E-12 Unit 2 ICLERP for DG 4 in extended maintenance 2.1 E-1 1 Table A4-4: Internal Events Model w/ Flooding and High Winds Evaluation Results Evaluation Metric F Result Unit 1 Baseline CDF 9.8E-06 /yr Unit 1 ACDF 8.7E-08 /yr Unit 1 ICCDP for DG 1 in extended maintenance 4.1E-08 Unit 1 ICCDP for DG 2 in extended maintenance 6.2E-08 Unit 1 ICCDP for DG 3 in extended maintenance 2.6E-08 Unit 1 ICCDP for DG 4 in extended maintenance 3.2E-08 Unit 2 Baseline CDF 9.4E-06 /yr Unit 2 ACDF 8.OE-08 /yr Unit 2 ICCDP for DG 1 in extended maintenance 2.6E-08 Unit 2 ICCDP for DG 2 in extended maintenance 3.OE-08 Unit 2 ICCDP for DG 3 in extended maintenance 4.1E-08 Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 10

Table A4-4: Internal Events Model w/ Flooding and High Winds Evaluation Results Evaluation Metric ] Result Unit 2 ICCDP for DG 4 in extended maintenance 5.6E-08 Unit 1 ALERF <1.OE-09 /yr Unit 1 ICLERP for DG 1 in extended maintenance <1.OE-09 Unit 1 ICLERP for DG 2 in extended maintenance <1.OE-09 Unit 1 ICLERP for DG 3 in extended maintenance <1.OE-09 Unit 1 ICLERP for DG 4 in extended maintenance <1.OE-09 Unit 2 ALERF <1.OE-09 /yr Unit 2 ICLERP for DG 1 in extended maintenance <1.OE-09 Unit 2 ICLERP for DG 2 in extended maintenance <1.OE-09 Unit 2 ICLERP for DG 3 in extended maintenance <1.OE-09 Unit 2 ICLERP for DG 4 in extended maintenance <1.OE-09 Conclusion for internal events, internal flooding, high winds and external flooding The risk increase for these hazards shows a small increase in risk when compared to the guidelines in Reg. Guide 1.177 and 1.174 of less than 1E-06/yr ACDF and ICCDP of less than 1E-06 as well as ALERF of less than 1 E-07/yr and ICLERP of less than 1E-07. Thus for these hazards the results are acceptable.

4.6.1. Fire Risk Evaluation The BNP Fire PRA model used the methodology in NUREG/CR-6850-ERPI TR-1019259, EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities and the approved FAQs 07-035, 08-048 and 08-50. The EPRI document TR-1011986, "Fire PRA Methods enhancements" was applied. The results are still believed to be conservative, but acceptable for this application. The SUPP-DG was assumed failed in those areas where the cables are projected to be routed and are not protected as well as the Fires in the 1C, 2C, 1D and 2D switchgear where the SUPP-DG will connect to the existing plant AC power distribution system. For this case three new fire scenarios were added to fail the SUPP-DG when appropriate. In a number of other fire scenarios the SUPP-DG or the applicable operator action was evaluated for fire impact. If a fire occurs anywhere in the Turbine Building area near the 4Kv Switchgear rooms no credit is given for operator actions to start and connect the SUPP-DG to a 4Kv bus.

Segmented Bus duct locations were reviewed against the planned SUPP-DG cable routing locations. When appropriate the SUPP-DG was failed due the high energy arcing fault. The operator action "OPER-SDGSTART" which is the operator action to start the SUPP-DG is increased by a factor of 10 for those fire scenarios where it can be credited. This is consistent with the rest of the fire PRA methodology. The fires in the Main Control Room contribute most of the change in risk as shown below in Table A4-5 below. The important fire sources for ACDF are provided below in Table A4-7. As can be seen the resulting increases in CDF/LERF and ICCDP/ICLERP are acceptably small when compared to the guideline values in R.G. 1.177 and 1.174.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 11

Multi-compartment analysis was not included as part of the increase in CDF or LERF because the compartments providing a small overall increase in risk due to multi-compartment analysis. The multi-compartment areas are for Unit 1:

FC 389 (TB1-04)

FC 390 (TB1-05)

Both of these fire areas could expose Fire Area FC 381 (TB1-01A/B) to a fire from these adjacent areas caused by failed fire area walls. FC 390 has a very minor contribution to the overall fire CDF and increase CDF and FC 389 has a negligible contribution, thus for Unit 1 Multi-compartment analysis for the application does not add any additional risk. For Unit 2 the multi-compartment area are:

FC 409 (TB2-04)

FC 410 (TB2-05)

Both of these fire areas could expose Fire Area FC 401 (TB2-01A/B) to a fire from these adjacent areas caused by failed fire area walls. FC 410 has a very minor contribution to the overall fire CDF and increase CDF and FC 409 has a negligible contribution, thus for Unit 2 Multi-compartment analysis for the application does not add any additional risk.

Table A4-5 shows the dominant fire areas and sums them up to show the values less than 1E-06. Further, Table A4-6 exhibits the components the are dominant. Table A4-7 shows the important fire sources and the final model results are encapsulated in Table A4-8.

Table A4-5: Dominant Fire Area CDF and LERF Impact of EDG CT Change Compartment [ Description [ Base Application Delta

___________________ CDF CDF CDF Unit 1 CDF FC382 Unit 1 Turbine Building TB1-01 20ft Elevation 6.33E-07 7.33E-07 9.98E-08 FC230 Control Room 49' Elevation 4.60E-05 4.61 E-05 5.12E-08 FC423 Transformer Yard 2.85E-07 3.15E-07 2.97E-08 FC210 Unit 1 Cable Spreading Room 23ft 8.56E-06 8.58E-06 1.60E-08 Elevation FC213 Battery Room 1B 23ft Elevation 2.81 E-07 2.94E-07 1.22E-08 FC390 Unit 1 TB 1A RFPT Room, 20ft 3.24E-09 4.88E-09 1.64E-09 FC384 Unit 1 TB South 38ft and 45ft Elevation 3.27E-08 3.44E-08 1.63E-09 FC263 Switchyard AND Circwater Yard AND 1.12E-08 1.22E-08 1.05E-09 East Yard Open Area AND Northwest Yard Open Area Total Unt 1 Dominant 2.13E-07 Increase in Fire CDF Unit 2 CDF FC230 Control Room 49' Elevation 4.67E-05 4.68E-05 1.11E-07 FC402 Unit 2 Turbine Building TB2-01 20 ft 5.54E-07 6.30E-07 7.57E-08 Elevation FC423 Transformer Yard 2.39E-07 2.56E-07 1.72E-08 FC215 Battery Room 2B 23' Elevation 9.31 E-08 1.10E-07 1.66E-08 Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 12

Table A4-5: Dominant Fire Area CDF and LERF Imnact of EDG CT Chanae Compartment Description Base Application Delta CDF CDF CDF FC410 Unit 2 TB 2A RFP Room, 20ft 2.25E-08 2.97E-08 7.23E-09 FC211 Unit 2 Cable Spreading Room 23 ft 9.63E-06 9.64E-06 4.01 E-09 Elevation FC404 Unit 2 TB North 38ft and 45ft 1.40E-08 1.70E-08 3.03E-09 Total Unt 2 Dominant 2.4Ei07 Increase in Fire CDF ,,

Unit 1 LERF FC230 Control Room 49' Elevation 1.57E-05 1.57E-05 6.84E-09 FC382 Unit 1 Turbine Building TBl-01 20 ft 3.47E-09 3.82E-09 3.51E-10 Elevation FC227 Unit 1 Northwest Back Panel Area 4.46E-06 4.46E-06 3.10E-11 FC242 Diesel Generator Cell 1, 20ft 0.OOE+00 1.62E-1 1 1.62E-1 1 Total Unt 1 Dominant -+ 7.24E-09 Increase in Fire LERF Unit 2 LERF FC230 Control Room 49' Elevation 1.08E-05 1.08E-05 1.62E-09 FC402 Unit 2 Turbine Building TB2-01 20 ft 5.20E-09 5.79E-09 6.OOE-10 Elevation FC410 Unit 2 TB 2A RFP Room, 20ft 1.37E-10 2.OOE-10 6.30E-11 FC228 Unit 2 Southwest Back Panel Area 6.59E-09 6.62E-09 2.46E-1 1 Total Unt 2 Dominant "i .2.31 E-09 Increase in Fire LERF Table A4-6: Identification of Important Components for Dominant Delta CDF Fire Scenarios Fire Scenario Fire Source Description Delta CDF Important Components Zone Unit 1 FC230_4740 Control 1-XU NODE HJ5, HJ6, 1.09E-08 4.16 KV load breakers for Bus E3, B75 Room HJ7: GENERATOR, UAT cross tie breakers between E3 and

& MPT RELAY PANEL El, diesel generators FC230_4837 Control 2-XU NODE HJ5, HJ7: 2.12E-08 4.16 KV load breakers for Bus E2, B98 Room GENERATOR,UAT & MPT cross tie breakers for E2, Diesel RELAY PANEL generator FC382_1560 Unit 1 1-1D - 4160V BOP SWGR 3.21E-08 4.16 KV load breakers for Bus E2, B75 TB1-01 1D. diesel generator FC382_1560 Unit 1 1-1D - 4160V BOP SWGR 1.07E-08 4.16 KV load breakers for Bus E2, B98 TB1-01 1D. diesel generator FC382_1562 Unit 1 1-1C - 4160V BOP SWGR 1.71E-08 4.16 KV load breakers for Bus El, B75 TBl-01 1C. diesel generator FC382_1564 Unit 1 1-COM-A - 4KV BUS 1.04E-08 4.16 KV load breakers for Bus El, B75 TB1-01 COMMON 'A' diesel generator Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 13

Table A4-6: Identification of Important Components for Dominant Delta CDF Fire Scenarios Fire Scenario Fire Source Description Delta CDF Important Components Zone Unit 2 FC230_4752 Control 1-H12-P614 - NODE JF3, 4.27E-08 4.16 KV load breakers for Bus E3, B75 Room JP5: NSSS TEMP REC & cross tie breakers for E3, Diesel LEAK DET VERTICAL generator BOARD FC230_4752 Control 1-H12-P614 - NODE JF3, 1.42E-08 4.16 KV load breakers for Bus E3, B98 Room JP5: NSSS TEMP REC & cross tie breakers for E3, Diesel LEAK DET VERTICAL generator BOARD FC230_4837 Control 2-XU NODE HJ5, HJ7: 2.09E-08 4.16 KV load breakers for Bus E2, B98 Room GENERATOR,UAT & MPT cross tie breakers for E2, Diesel RELAY PANEL generator FC402_2598 Unit 2 2-2D - SWGR Bus 2D 2.95E-08 4.16 KV load breakers for Bus E4, B75 TB2-01 Diesel generator FC402_2600 Unit 2 2-2C - SWGR Bus 2C 2.93E-08 4.16 KV load breakers for Bus E3, B75 TB2-01 diesel generator Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 14

Table A4-7, Important Fire Sources for EDG CT Impact Source Scen Source Description Base CDF Application CDF Unit 1 CDF FC382_1560 B75 1-1D - 4160V BOP SWGR 1D. 9.49E-08 1.27E-07 FC230_4837 B98 2-XU NODE HJ5, HJ7: GENERATOR,UAT & 8.70E-08 1.08E-07 MPT RELAY PANEL FC382_1562 B75 1-1C - 4160V BOP SWGR 1C. 1.20E-07 1.37E-07 FC230_4740 B75 1-XU NODE HJ5, HJ6, HJ7: GENERATOR, UAT 3.57E-08 4.66E-08

& MPT RELAY PANEL FC382_1560 B98 1-1D - 4160V BOP SWGR 1 D. 3.16E-08 4.23E-08 FC382_1564 B75 1-COM-A - 4KV BUS COMMON 'A'. 7.27E-08 8.31E-08 FC423_9034 B75 1-CASBCH-XFMR CASWELL BEACH XFMR NO. 6.00E-08 6.83E-08 1 230KV - 24KV FC423_9043 B75 1-SAT-START-AUX-XFMR - START UP AUX 6.00E-08 6.83E-08 TRANSFORMER 1 FC210_4525 B75 1-COM-C -480V UNIT SUBSTATION COM-C 6.45E-08 7.17E-08 FC230_4741 B75 1-XU NODE HJ8: CASWELL BEACH LINE RLY 1.19E-08 1.85E-08 PNL & SWYD TERM CAB FC382_1598 B75 1-1TB - 480V MCC 1TB 1.12E-08 1.69E-08 FC382_1599 B75 1-1TC - 480V MCC 1TC 1.12E-08 1.69E-08 FC382_1558 B98 1-1B - 4160V BOP SWGR 1B. 1.45E-08 1.94E-08 FC230_4740 B98 1-XU NODE HJ5, HJ6, HJ7: GENERATOR, UAT 2.22E-08 2.68E-08

& MPT RELAY PANEL FC382_1558 B75 1-1B - 4160V BOP SWGR lB. 7.44E-09 1.19E-08 FC2104528 B75 1-COM-C-FD6-XFMR - UNIT SUB TRANSFORMER 9.94E-09 1.43E-08 4160-480V FC382_1564 B98 1-COM-A - 4KV BUS COMMON 'A'. 2.42E-08 2.77E-08 FC423_9034 B98 1-CASBCH-XFMR CASWELL BEACH XFMR NO. 2.OOE-08 2.28E-08 1 230KV - 24KV FC423_9043 B98 1-SAT-START-AUX-XFMR - START UP AUX 2.OOE-08 2.28E-08 TRANSFORMER 1 FC213_4621 B75 1-1B-2-125VDC-CHRGR - NODE GB7: 125VDC 6.56E-08 6.82E-08 BATTERY 1B-2 CHARGER FC213_4622 B75 1-1B-1-125VDC-CHRGR - NODE GB6: 125VDC 6.56E-08 6.82E-08 BATTERY 1B-1 CHARGER FC423_9033 BOS 1-CASBCH-XFMR CASWELL BEACH XFMR NO. 1.73E-08 1.97E-08 1 230KV - 24KV FC423_9042 BOS 1-SAT-START-AUX-XFMR - START UP AUX 1.73E-08 1.97E-08 TRANSFORMER 1 FC230_4781 B75 1-C95-P652 - NODE JOJ: DATA AQUISITION 1.34E-08 1.54E-08 PANEL FC213_4628 B75 1-1B-250VDC - 125/25OVDC SWITCHBOARD 1B 3.43E-08 3.63E-08 FC382_1598 B98 1-1TB - 480V MCC 1TB 3.73E-09 5.62E-09 FC382 1599 B98 1-1TC - 480V MCC 1TC 3.73E-09 5.62E-09 Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 15

Table A4-7, Important Fire Sources for EDG CT Impact Source Scen Source Description Base CDF Application CDF FC230_4741 B98 1-XU NODE HJ8: CASWELL BEACH LINE RLY 5.22E-09 6.79E-09 PNL & SWYD TERM CAB FC210_4528 B98 1-COM-C-FD6-XFMR - UNIT SUB TRANSFORMER 3.31 E-09 4.76E-09 4160-480V FC213_4617 B75 1-1B-1-125VDC-BAT - 125 VDC BATTERY FOR 3.63E-08 3.77E-08 125/250 VDC.. DISTRIBUTION SWITCHBOARD 1B FC390_1777 BHG 1-FW-IA-FEED-PMP - RX FEEDWATER PUMP 1A 2.79E-09 4.20E-09 L

Unit 2 CDF FC230_4752 B75 1-H12-P614 - NODE JF3, JP5: NSSS TEMP REC & 1.68E-07 2.11E-07 LEAK DET VERTICAL BOARD FC402_2598 B75 2-2D - SWGR Bus 2D 1.03E-07 1.33E-07 FC402 2600 B75 2-2C - SWGR Bus 2C 9.94E-08 1.29E-07 FC230_4837 B98 2-XU NODE HJ5, HJ7: GENERATORUAT & 9.56E-08 1.17E-07 MPT RELAY PANEL FC230_4752 B98 1-H12-P614 - NODE JF3, JP5: NSSS TEMP REC & 5.60E-08 7.02E-08 LEAK DET VERTICAL BOARD FC402_2598 B98 2-2D - SWGR Bus 2D 3.45E-08 4.43E-08 FC230_4740 B75 1-XU NODE HJ5, HJ6, HJ7: GENERATOR, UAT 3.56E-08 4.38E-08

& MPT RELAY PANEL FC230_4758 B98 1-H12-P612 - NODE JN5, JG2: FEEDWATER & 2.68E-08 3.40E-08 REACTOR RECIRC INSTR PANEL FC4102783 BHG 2-FW-2A-FEED-PMP - RX FEEDWATER PUMP 2A 1.94E-08 2.56E-08 L

FC230_4741 B75 1-XU NODE HJ8: CASWELL BEACH LINE RLY 1.18E-08 1.77E-08 PNL & SWYD TERM CAB FC423_9018 B75 2-SAT-START-AUX-XFMR - UNIT 2 START UP AUX 3.75E-08 4.27E-08 XFMR FC423_9028 B75 2-CASBCH-XFMR CASWELL BEACH XFMR NO. 3.75E-08 4.27E-08 2 230KV - 24KV FC230_4740 B98 1-XU NODE HJ5, HJ6, HJ7: GENERATOR, UAT 1.25E-08 1.77E-08

& MPT RELAY PANEL FC215_4648 B75 2-2B-2-125VDC-CHRGR - NODE GB7: 125VDC 2.09E-08 2.47E-08 BATTERY 2B-2 CHARGER FC215_4649 B75 2-2B-1-125VDC-CHRGR - NODE GB6: 125VDC 2.09E-08 2.47E-08 BATTERY 2B-1 CHARGER FC402_2599 B75 2-COM-B - Common B 4.73E-09 7.35E-09 FC211_4571 B75 2-COM-D-FP0-CPT - SUBSTN FANS AND HTRS 5 5.93E-09 8.07E-09 KVA PWR XFMR FC230_4741 B98 1-XU NODE HJ8: CASWELL BEACH LINE RLY 3.94E-09 5.92E-09 PNL & SWYD TERM CAB FC423_9018 B98 2-SAT-START-AUX-XFMR - UNIT 2 START UP AUX 1.25E-08 1.42E-08 XFMR FC423_9028 B98 2-CASBCH-XFMR CASWELL BEACH XFMR NO. 1.25E-08 1.42E-08 2 230KV - 24KV Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 16

Table A4-7, Important Fire Sources for EDG CT Impact Source Scen Source Description Base CDF Application CDF FC215 4655 B75 2-2B-250VDC - 125/250VDC SWITCHBOARD 2B 8.17E-09 9.68E-09 FC423_9017 BOS 2-SAT-START-AUX-XFMR - UNIT 2 START UP AUX 1.30E-08 1.45E-08 XFMR FC423_9027 BOS 2-CASBCH-XFMR CASWELL BEACH XFMR NO. 1.30E-08 1.45E-08 2 230KV - 24KV FC215_4644 B75 2-2B-1-125VDC-BAT - 125 VDC BATTERY FOR 9.63E-09 1.10E-08 125/250 VDC.. DISTRIBUTION SWITCHBOARD 2B FC404_2694 B75 2-HC-HYDROGEN-CONT-PNL - Node: 2HN8 GEN 1.96E-09 3.33E-09 H2 GAS & STATOR .... COOLING CONT PANEL FC215_4650 B98 2-C72-SO01B - NODE GG1: HIGH INERTIA AC 7.74E-09 9.03E-09 MOTOR-GENERATOR SET 'B' FC215_4649 B98 2-2B-1-125VDC-CHRGR - NODE GB6: 125VDC 6.96E-09 8.24E-09 BATTERY 2B-1 CHARGER FC215_4648 B98 2-2B-2-125VDC-CHRGR - NODE GB7: 125VDC 6.96E-09 8.24E-09 BATTERY 2B-2 CHARGER FC402 2597 B75 2-2B - SWGR Bus 2B 1.87E-09 3.10E-09 Unit 1 LERF FC230_4740 B98 1-XU NODE HJ5, HJ6, HJ7: GENERATOR, UAT 1.40E-08 1.85E-08

& MPT RELAY PANEL FC230_4741 B98 1-XU NODE HJ8: CASWELL BEACH LINE RLY 2.41 E-09 3.91 E-09 PNL & SWYD TERM CAB FC382 1560 B75 1-1D -4160V BOP SWGR 1D. 5.OOE-10 7.36E-10 FC230_4770 B98 1-XU NODE JJ5: BOP TERM CAB FOR HD, 3.09E-09 3.27E-09 EX, CFD, CW SYSTEMS FC230_4771 B98 1-XU NODE JJ6: BOP TERMINATION CAB 3.09E-09 3.27E-09 FOR SYSTEM CW & CD FC230_4747 B75 1-H12-P606 - NODE JG5, JH9: RADIATION 2.45E-07 2.45E-07 MONITORING CABINET FC230 4769 B75 1-XU NODE H58: DG1 ESS LOGIC CAB 2.42E-08 2.43E-08 FC382_1560 B98 1-1D -4160V BOP SWGR 1D. 1.67E-10 2.45E-10 FC230_4799 B75 1-XU NODE JJ1: BOP TERMINAL CAB FOR 7.43E-09 7.48E-09 CONDENSATE SYSTEM FC230 4769 B98 1-XU NODE H58: DG1 ESS LOGIC CAB 7.63E-09 7.67E-09 FC382 1558 B98 1-1B -4160V BOP SWGR 1B. 7.69E-11 1.13E-10 FC227_4683 B98 1-XU NODE J1C: TSC/EOF COMPUTER 1.25E-08 1.26E-08 ISOLATOR CABINET FC230_4742 B98 1-XU NODE JD6: BOP ANNUNCIATOR LOGIC 8.25E-11 1.10E-10 CAB FOR UA-7 TO 11 FC230_4781 B75 1-C95-P652 - NODE JOJ: DATA AQUISITION 4.14E-11 6.84E-11 PANEL FC230_4740 B75 1-XU NODE HJ5, HJ6, HJ7: GENERATOR, UAT 5.49E-11 7.67E-11

& MPT RELAY PANEL FC230_4751 B75 1-XU-6 - NODE JF4: DCS ELECTRONIC 1.56E-10 1.76E-10 EQUIPMENT ROOM CONTROLLER CABINET Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 17

Table A4-7, Important Fire Sources for EDG CT Impact Source Scen Source Description Base CDF Application CDF FC230_4750 B75 1-XU NODE JX1: TERMINATING CABINET DIV 1.29E-10 1.50E-10 II FC242 9629 B98 TRANS-DG+23Z05-E - Transient 0.OOE+00 1.62E-11 FC230_4741 B75 1-XU NODE HJ8: CASWELL BEACH LINE RLY 1.83E-11 3.28E-11 PNL & SWYD TERM CAB Unit 2 LERF FC230_4752 B75 1-H12-P614 - NODE JF3, JP5: NSSS TEMP REC & 1.62E-09 2.30E-09 LEAK DET VERTICAL BOARD FC230_4837 B98 2-XU NODE HJ5, HJ7: GENERATORUAT & 1.46E-09 2.05E-09 MPT RELAY PANEL FC402 2600 B75 2-2C - SWGR Bus 2C 5.51 E-10 8.06E-10 FC402 2598 B75 2-2D - SWGR Bus 2D 5.68E-10 8.22E-10 FC230_4752 B98 1-H12-P614 - NODE JF3, JP5: NSSS TEMP REC & 5.39E-10 7.68E-10 LEAK DET VERTICAL BOARD FC402 2598 B98 2-2D - SWGR Bus 2D 1.89E-10 2.74E-10 FC230_4758 B98 1-H12-P612 - NODE JN5, JG2: FEEDWATER & 1.32E-10 1.99E-10 REACTOR RECIRC INSTR PANEL FC4102783 BHG 2-FW-2A-FEED-PMP - RX FEEDWATER PUMP 2A 1.18E-10 1.72E-10 L

FC228_4693 B75 2-XU NODE J1C: TSC/EOF COMPUTER 2.56E-09 2.57E-09 ISOLATOR CAB FC230_4741 B75 1-XU NODE HJ8: CASWELL BEACH LINE RLY 1.83E-11 3.28E-11 PNL & SWYD TERM CAB FC230_4888 B98 2-XU NODE JE9: DIV 1 ANNUN LOGIC CAB 2.75E-09 2.76E-09 FOR UA-17 & 21 Notes on Table A4-6; Under Scenario B98 is the 9 8th percentile file B75 is the 7 5 " percentile fire BHEAF is High energy arcing fault fire BOL is an oil fire.

BHGL is a hot gas layer (full room burnup)

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 18

Table A4-8: Fire Model Evaluation Results Only Evaluation Metric Result Unit 1 Baseline Fire CDF 6.27E-05/yr. 1 Unit 1 Application Fire CDF- All EDGs using nominal UA for extended 6.29E-05 /yr.

maintenance Unit 1 ACDF - All EDGs using nominal UA for extended maintenance 2.1E-07 /yr.

Unit 1 ICCDP - All EDGs using nominal UA for extended maintenance 2.1E-07 Unit 1 Application CCDP - EDG 2 unavailable 6.57E-05 Unit 1 ACCDP - EDG 2 unavailable 3.OE-6 Unit 1 ICCDP - EDG 2 unavailable

AOT fraction of 14/365 1.15E-7 Unit 1 ICCDP - EDG 2

4 EDG Maintenance Events 2 4.6E-7 Unit 1 ALERF- All EDGs using nominal UA for extended maintenance 7.2E-09 /yr.

Unit 1 ICLERP - All EDGs using nominal UA for extended maintenance 7.2E-09 Unit 2 Baseline Fire CDF 6.18E-05 /yr.

Unit 2 Application Fire CDF- All EDGs using nominal UA for extended 6.21 E-05 /yr.

maintenance Unit 2 ACDF - All EDGs using nominal UA for extended maintenance 2.4E-07 /yr.

Unit 2 ICCDP - All EDGs using nominal UA for extended maintenance 2.4E-07 Unit 2 Application CCDP - EDG 4 unavailable 6.38E-5 Unit 2 ACCDP - EDG 4 unavailable 2.OE-6 Unit 2 ICCDP - EDG 4 unavailable

AOT fraction of 14/365 7.67E-8 Unit 2 ICCDP - EDG 4 UA *4 EDG Maintenance Events ' 3.1 E-7 Unit 2 ALERF- All EDGs using nominal UA for extended maintenance 2.3E-09 /yr.

Unit 2 ICLERP - All EDGs using nominal UA for extended maintenance 2.3E-09 1- Does not contain multi-compartment or control room evacuation which, when added, total 6.70E-05 for unit 1 and 6.61 E-05 for unit 2.

2 - Multiplying the ICCDP of the most significant DG by 4 maintenance events is bounding.

4.6.2. Seismic Evaluation The seismic hazard is not considered to have a significant impact on this application when considering a seismic event while a DG is in an extended AOT. The four emergency diesel generators are all designed to the same seismic criteria, that being a 0.16g horizontal and 0.1g vertical seismic event. The HCLPF value for the DGs is 0.26g. The HCLPF for the El, E2, E3 and E4 buses is 0.24. Since the existing DGs are the same equipment and highly coupled, they would all be expected to be failed by the same seismic event. Therefore, the unavailability of one DG during a seismic event would be of little significance since it would be expected to fail if the other DG's failed due to the seismic event. Similarly the buses are expected to withstand up to a static 0.08g seismic event, thus the buses are considered the limiting equipment in a seismic event.

4.7. Application Metrics Analysis The metrics developed in Reg. Guides 1.174 [Ref. 2] and 1.177 [Ref. 3] assist in determining the overall risk associated with the application. These metrics are A CDF, A Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 19

LERF, ICCDP and ICLERP for the internal events, internal flooding portions, high winds, external flooding and fire of the BNP PRA model. They are calculated for the application model. Key uncertainties are analysis within each hazard evalation. Results of the Unit 1 and Unit 2 model runs to the aforementioned metrics is presented in the Table A4-9 below.

Table A4-9: CDF and LERF Metrics Analysis Summary CDF Unit 1 Risk Metric Risk Metric Risk Significance Guideline Meets Acceptance Guideline Results ACDF 9.OE-08 <1.OE-06 (Region III) Yes ICCDPDG 1 4.1E-08 <1.OE-06 (Region III) Yes ICCDPDG 2 6.2E-08 <1.OE-06 (Region III) Yes ICCDPDG 3 3.OE-08 <1.OE-06 (Region III) Yes ICCDPDG4 3.2E-08 <1.OE-06 (Region III) Yes ICCDP (total non- <1.OE-06 (Region III) Yes fire) 1.7E-07 Unit 1 Fire ACDF (fire) 2.1E-07 <1.OE-06 (Region IlI) Yes ICCDP (fire) 4.6E-07 <1.OE-06 (Region Ill) Yes Unit 1 Totals ACDF 3.OE-07 <1.OE-06 (Region II1) Yes ICCDP 6.3E-07 <1.OE-06 (Region Ill) Yes Unit 2 Risk Metric Risk Metric Risk Significance Guideline Meets Acceptance Guideline Results ACDF 8.OE-08 <1.OE-06 (Region III) Yes ICCDPDG 1 3.OE-08 <1.OE-06 (Region III) Yes ICCDPDG 2 3.OE-08 <1.OE-06 (Region Ill) Yes ICCDPDG 3 4.1E-08 <1.OE-06 (Region II1) Yes ICCDPDG 4 6.OE-08 <1.0E-06 (Region III) Yes ICCDP (total non- <1.OE-06 (Region Ill) Yes fire) 1.6E-07 Unit 2 Fire ACDF (fire) 2.4E-07 <1.OE-06 (Region IlI) Yes ICCDP (fire) 3.1E-07 <1.OE-06 (Region IlI) Yes Unit 2 Totals ACDF 3.2E-07 <1.OE-06 (Region II) Yes ICCDP 4.7E-07 <1.OE-06 (Region III) Yes LERF Unit 1 ALERF <1.OE-09 <1.OE-07 (Region III) Yes ICLERPDG 1 <1.OE-09 <1.OE-07 (Region III) Yes ICLERPDG 2 <1.OE-09 <1.OE-07 (Region III) Yes ICLERPDG 3 <1.OE-09 <1.OE-07 (Region II1) Yes ICLERPDG4 <1.OE-09 <1.OE-07 (Region III) Yes Unit 1 Fire ALERF (fire) 7.2E-09 <1.OE-07 (Region III) Yes ICLERP (fire) 7.2E-09 <1.OE-07 (Region Ill) Yes Unit 1 Totals ALERF <8.2E-09 <1.OE-07 (Region III) Yes Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 20

Table A4-9: CDF and LERF Metrics Analysis Summary CDF Unit 1 Risk Metric Risk Metric Risk Significance Guideline Meets Acceptance Guideline Results ICLERP <1.1E-08 <1.OE-07 (Region III) Yes Unit 2 ALERF <1.OE-09 <1.OE-07 (Region 111) Yes ICLERPDG 1 <1.OE-09 <1.OE-07 (Region III) Yes ICLERPDG 2 <1.OE-09 <1.OE-07 (Region III) Yes ICLERPDG 3 <1.OE-09 <1.OE-07 (Region II1) Yes ICLERPDG 4 <1.OE-09 <1.OE-07 (Region III) Yes Unit 2 Fire ALERF(fire) 2.3E-09 <1.OE-07 (Region IlI) Yes ICLERP (fire) 2.3E-09 <1.OE-07 (Region IlI) Yes Unit 2 Totals ALERF <3.3E-09 <1.0E-07 (Region 111) Yes ICLERP <6.3E-09 <1.OE-07 (Region IlI) Yes 4.8. PRA Uncertainty Analysis Reg. Guides 1.174 and 1.177 require that appropriate consideration of uncertainty be given in analysis and interpretation of findings. The impact of uncertainty is characterized and these uncertainties are recognized when assessing whether the principles stated in Reg. Guides 1.174 and 1.177 are being met. The following evaluation demonstrates that, within reasonable assurance, the numerical risk results of this application fall within Region III even when the uncertainties associated with the PRA model are taken into consideration.

Three types of uncertainty are evaluated; parameter uncertainty, model uncertainty, and completeness uncertainty. These are defined extensively in Reg. Guides 1.174 [Ref 2],

Reg. Guide 1.177 [Ref 3], NUREG 1855 [Ref 4], and EPRI Report 1016737 [Ref 5].

4.8.1. Parametric Uncertainty The parametric uncertainty for the BNP 2011 model PRA model before changes were made for this application analysis was evaluated using a Monte Carlo approach to determine the mean, and upper and lower uncertainty bounds [Ref. 4]. This analysis was performed for both the Level 1 and LERF models. The peer review found the ASME Capability Category for the two Level I Supporting Requirements (SR), QU-A3 and QU-E3, and the two LERF SRs, LE-E4 and LE-F3, dealing with parameter uncertainty to meet or exceed capability category II as defined in the ASME standard

[Ref 1]. The parameter values for both CDF and LERF for each unit in the base model are provided in Tables A4-10 and A4-11 and Figures A4-1 through A4-4 below. The point estimate CDF calculated by the BNP 2011 model is 7.87E-06 for Unit 1 and 7.86E-6 for Unit 2.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 21

Table A4-1 0: Calculated Parameters for the CDF Monte Carlo Assessment CDF Parameter Value BNP 1 BNP 2 Mean 7.92E-06 7.96E-06 Median 6.87E-06 6.90E-06 95% Upper Bound 1.46E-05 1.46E-05 5% Lower Bound 4.44E-06 4.43E-06

[F U.-*~ie 2MWi 3E-1 2E5 3LE5 41E-5 51-5 &E-5 71-5 H-5 11E.4.

I . . ................... Fr c b y . -

Figure A4-1: Unit 1 CDF Parametric Uncertainty Distribution Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 22

Me.w.o :796E-06 5%I1 4.43E-06 50r/-, ESCIE-0S 95%.) :1.46E05

sawp~n2M05 3.E-6 5.E-S SE-S 7.E-S 1.E-5 ZE-5 HE-5 41E-5 515-5 655-67.E5 11E4 Freoq*,ecy / %babl Figure A4-2: Unit 2 CDF Parametric Uncertainty Distribution The point estimate LERF calculated by the BNP 2011 model is 5.67E-07 for Unit 1 and 5.65E-07 for Unit 2.

Table A4-1 1: Calculated Parameters for the LERF Monte Carlo Assessment LERF Parameter Value BNP 1 BNP 2 Mean 5.67E-07 5.64E-07 Median 5.36E-07 5.40E-07 95% Upper Bound 7.61E-07 7.34E-07 5% Lower Bound 4.63E-07 4.68E-07 Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 23

Me-, 5.97E-07 5%- 4.63E-07 7~ 5r.-

95%-]

.e-pl 5.36E.7 7.61E:0l7 200 51E7 .E-7' 7.E-7 9E-7 E-7 1.E-6 E6 E 41- &ý6 &E-6 71E-6 9EG- 9LE6 Figure A4.. UR Figure A4-3: Unit 1 LERF Parametric Uncertainty Distribution Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 24

- .::. " /5=- T a54DE-071 95% : 7.34E-07 4m :25000 5.-7 .E- 7. E-7 5.-7"lEO E-67 2E-6 3E- 4.2E3 51-6 G.E-S Frose.Jecy/ Prdkbiy Figure A4-4: Unit 2 LERF Parametric Uncertainty Distribution The propagation of parametric uncertainty in the CDF equation demonstrated that the point estimate mean and calculated mean are within 10%; therefore, additional uncertainty evaluations are not warranted according to the guidance in Section 3.1.1 of the EPRI report [Ref 5]. The propagation of parametric uncertainty in the LERF equation demonstrated that the point estimate mean is equal to the calculated parametric mean; and according to the guidance in Section 3.1.1 of the EPRI report, additional sensitivity studies are also not warranted. [Ref 5]

The range of the uncertainty interval is not expected to significantly change for the application model. The added DG unavailabilities apply only to the DG extended outage evolutions and are not state-of-knowledge correlated basic events. The SUPP-DG fail to start and run event data are based on the existing DG data. They are state-of-knowledge correlated basic events, but are expected to be conservative and the application model is not very sensitive to this data. The failure events due to high winds (above 135 mph) for the SUPP-DG are conservatively set at 1.0 and are not state-of-knowledge correlated events. The 5 new breaker fail-to-open events are state-of-knowledge correlated basic events because they are based on data for all other AC breaker failure events. The application model is not very sensitive to these new events.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 25

Because only a few events were added to the application model that is state-of-knowledge correlated events, and because the application model results are not very sensitive to these events, their impact on the baseline uncertainty interval is expected to be small. A separate parametric uncertainty analysis for the application model is deemed unnecessary because a bulk of the contributing scenarios do not involve multiple events that are impacted by state-of-knowledge correlation effects.

4.8.2. Model Uncertainty Model Uncertainty was evaluated in three parts; BNP plant specific uncertainty, BWR generic uncertainty, and application specific uncertainty. This was done to capture all of the sources of model uncertainty that could affect the analysis results. All uncertainties determined to be key uncertainties for the application are evaluated further with sensitivity studies.

4.8.2.1. BNP Plant Specific Uncertainty The BNP PRA uncertainty analysis classifies each plant specific source of uncertainty as one of three levels (URI); high, medium, and low. One basis for the high classification is the uncertainty contributes to more than 10% of the CDF. These uncertainties with a high classification were further evaluated below as potential key uncertainties. No classifications less than high were found to be hig h due to the application. Table A4-12 delineates the results of that analysis. No key uncertainties were identified during this evaluation.

Table A4-12: Plant Specific Hiah Level Uncertainty Evaluations No FURI [ Uncertainty Description [Uncertainty Evaluation 1 High An excessive vessel LOCA initiator, e.g. reactor vessel Not applicable for this application rupture, is assumed to result in inadequate flow to the vessel from the RHR system.

2 High If the minimum flow bypass line is not isolated when Application is not impacted by RHR required, flow will be diverted. However, this diversion flow path is not large enough to fail the associated RHR pump's discharge.

3 High The RHR system is available during testing and for Application is not impacted by RHR LPCI during suppression pool cooling 4 High For the LPCI model, the water level is assumed to be Application is not impacted by RHR below the LL#1 permissive level.

5 High The actuation of the ADS is assumed to be Not applicable for this application uninhibited for all initiating events except ATWS.

6 High SRV failure to open data is highly uncertain. SRV failures did not contribute to the delta risk 7 High BNP Unit 2 digital upgrades are appropriately Realistically conservative bias represented by the analog components that they replaced. The PRA model uses the same analog failure modes; no model changes were made.

8 High Use of distribution panel 1A(B) as an alternative Realistically conservative bias power source to the 125V DC distribution panel 2A(B) or the reverse is not modeled.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 26

Thhk~ A4-1% PI~nt Sn~r~ifin Hinh I ~v~I IJnc.~rt~intv Fv~Iii~tinn~

No Uncertainty Description

[URI -Uncertainty Evaluation 9 High Following battery failure or during charger Realistically conservative bias maintenance, it is assumed that the associated charger output breaker will trip on overvoltage from motors starting on the bus, such that DC power to the bus will fail.

10 High As with any data collection effort, uncertainties arise Peer reviewed cat II in evaluating and categorizing the data.

11 High Components located near each other should be Peer reviewed cat II included.

12 High There is some uncertainty introduced with the Peer reviewed cat II assignment of staggered and non-staggered testing bases for common cause failure rate determination 13 High Failure of five SRVs to lift is assumed to result in Applicable to ATWS only. Not vessel overpressure and core damage. applicable for this application 14 High Failure to relieve pressure is postulated to result in Not applicable for this application a failure of the reactor vessel that cannot be mitigated by injection sources.

15 High A time constraint on manual scram and ARI during Not applicable for this application ATWS scenarios is considered conservative.

16 High Equipment survivability beyond design basis Realistically conservative bias environments is not included.

17 High In the event of failed containment cooling or Realistically conservative bias venting, injection after containment failure is not credited prior to core damage.

18 High Actions that contributed directly to the occurrence of Not applicable for this application an initiating event (type B events) were not quantified explicitly. Efforts during the modeling process were primarily directed at identifying interactions of types A and C.

19 High For all actions except for the short term actions Self-reviewed to meet cat II associated with a response to an anticipated transient without scram (ATWS), the median response times and execution times were estimated based on discussions with operations personnel.

20 High For each type Cp interactions, the corresponding Peer reviewed cat II failure event was initially assigned a screening probability of 0.1.

21 High To quantify the cognitive portion, the higher of the Realistically conservative bias probabilities suggested by the HCR/ORE model or the cause-based approach was used.

22 High Flooding is assumed to occur in all rooms at an Not applicable for this application equal rate.

23 High For fixed volume sources, such as the RCC system, Not applicable for this application all inventory is assumed to be lost from the system at the pump flow rate.

24 High The very large flow rate is selected as approximately Not applicable for this application factor of ten greater than the large flow rate.

25 High Flow rate is estimated assuming a 360 degree Not applicable for this application through-wall crack with a width equivalent to one-half the wall thickness of the pipe.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 27

Table A4-12: Plant Specific High Level Uncertainty Evaluations No I URI I Uncertainty Description FUncertainty Evaluation 26 High To simplify the assessment, the flow rate for pipes Not applicable for this application greater in size than EPRI classification class 1 (> 2 inches) is reduced by a factor of two to conservatively address the likelihood of a lesser break and, therefore, lower flow.

27 High The EPRI methodology used makes a general Not applicable for this application assumption that there is an equal likelihood that the pipe failure will result in either maximum possible or any lower flow rate.

28 High An assumption is made that selects an average Not applicable for this application break size based on the class size and the frequency is not altered. This simplification results in a somewhat conservative result for the larger break sizes.

29 High The probability of a flood given a maintenance Not applicable for this application event is uncertain and human error dominates this type of event.

30 High Operator isolation is assumed to be ten times more Not applicable for this application likely for maintenance events than for pipe breaks.

31 High The starting air accumulators can provide up to five Realistically conservative bias hours of air for engine operation.

32 High Common cause failures are assumed to occur Peer reviewed cat II simultaneously.

33 High DC battery life is assumed to be 2 to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Realistically conservative bias 34 High The release may be impacted when the source of Delta LERF too small for fission products is at a very high temperature. consideration 35 High For Arrest Core Melt Progress in in-Vessel, the best ALERF at or below 1E-1 1 and not estimate success criteria used in this evaluation significantly impacted by application are based on the time available from the initiation of core degradation until just before substantial core relocation occurs. This typically is on the order of 30-40 minutes.

36 High Estimating containment fragility associated with ALERF at or below 1E-1 1 and not flooded vessel loads, extreme thermal, and shear significantly impacted by application loads on pipe extensions through the biological shield includes considerable uncertainty.

37 High There are minimal or no credit for recovery of failed ALERF at or below 1E-11 and not equipment and the loss of adequate injection at the significantly impacted by application time of containment failure.

38 High It is judged that the SRVs may reclose or not be ALERF at or below 1E-11 and not capable of being opened. significantly impacted by application 39 High Injection flow rate of approximately 1000 gpm is ALERF at or below 1E-1 1 and not assumed required to overcome the heat of significantly impacted by application oxidation and to prevent the core melt progression.

40 High The BNP model assumes that the crew will Initiate ALERF at or below 1E-1 1 and not drywell venting if combustible gases are present in significantly impacted by application the containment. This results in a high and early release for accidents such as Class IA and IBE when RPV breach occurs. The model assumes that the crew will accomplish the actions defined In the SAMGs.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 28

Table A4-12: Plant Soecific Hiah Level Uncertainty Evaluations No I URI I Uncertainty Description FUncertainty Evaluation 41 High The vacuum breaker fail to close (FTC) basic events ALERF at or below 1 E-1 1 and not are quantified based on an estimated number of significantly impacted by application vacuum breaker cycles assumed to occur during the event.

42 High It is not possible to reach definitive conclusions ALERF at or below 1E-11 and not regarding steam explosion phenomena in the significantly impacted by application Brunswick Mark I containment.

43 High It is assumed that common cause failures are The common cause treatment meets most often discovered as a result of scheduled ASME Capability Category II testing 4.8.2.2. BWR Generic Uncertainty The EPRI uncertainty guideline [Ref 5] provides a generic table of uncertainties. These uncertainties were evaluated to determine if any were key uncertainties for this application. The results of that evaluation are delineated in Table A4-13. No key uncertainties were identified during this evaluation.

Table A4-13: Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application Initiating Event Analysis (IE)

1. Grid stability The LOOP frequency is a LOOP sequences Applicable function of several factors Not a key uncertainty including switchyard design, because consensus the number and independence model was used to of offsite power feeds, the local determine LOOP power production and frequencies.

consumption environment and Consequential LOOP the degree of plant control of Consequential LOOP sequences were added the local grid and grid sequences before the last peer maintenance. review and found to meet Three different aspects relate LOOP or capability category I1.A to this issue: consequential LOOP consensus model was sequences with offsite used for offsite power la. LOOP initiating event power recovered, recovery.

frequency values and recovery probabilities lb. Conditional LOOP probability 1c. Availability of dc power to perform restoration actions 2 Support Increasing use of plant-specific Support system event Not applicable - Only System Initiating models for support system sequences loss of offsite power or Events initiators (e.g., loss of SW, AC bus initiators could CCW, or IA, and loss of ac or dc affect the applicable buses) have led to metrics for this inconsistencies in approaches application.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 29

T~hl* A4-13" I Inn.rfrtinti*_. *.ngd*r frnm F:PRI 1 N1FR737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application across the industry. A number of challenges exist in modeling of support system initiating events:

2a. Treatment of common cause failures 2b. Potential for recovery 3 LOCA It is difficult to establish values LOCA sequences Not applicable - Only initiating event for events that have never loss of offsite power or frequencies occurred or have rarely AC bus initiators could occurred with a high level of affect the applicable confidence. metrics for this The choice of available data application. NUREG 5750 sets or use of specific and NUREG 1420 are the methodologies in the BNP reference determination of LOCA documents for LOCAs frequencies could impact base and excessive LOCA model results and some respectively applications.

Accident Sequence Analysis (AS) 4 Operation of Station Blackout events are Credit for continued Applicable - addressed equipment after important contributors to operation of these adequately for this battery depletion baseline CDF at nearly every systems with batteries application in the BNP US NPP. In many cases, depleted (e.g., long- 2011 model battery depletion may be term SBO sequences) assumed to lead to loss of all system capability. Some PSAs have credited manual operation of systems that normally require dc for successful operation (e.g., turbine-driven systems such as RCIC and AFW).

5 RCP seal The assumed timing and Accident sequences Not Applicable for BWR LOCA treatment magnitude of RCP seal LOCAs involving loss of seal

- PWRs given a loss of seal cooling can cooling have a substantial influence on the risk profile.

6 Recirculation Recirculation pump seal Accident sequences Not Applicable for BWR pump seal leakage can lead to loss of the with long-term use of w/o isolation condenser.

leakage Isolation Condenser. While isolation condenser treatment - recirculation pump seal leakage BWRs w/ is generally modeled, there is Isolation no consensus approach on the Condensers likelihood of such leaks.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 30

Table A4-13: Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application Success Criteria (SC) 7 Impact of Many BWR core cooling Loss of containment Applicable - addressed containment systems utilize the suppression heat removal adequately for this venting on core pool as a water source. Venting scenarios with application in the BNP cooling system of containment as a decay heat containment venting 2011 model. The NPSH removal mechanism can successful suppression pool is not substantially reduce NPSH, credited as a water even lead to flashing of the source after a successful pool. The treatment of such containment vent.

scenarios varies across BWR PSAs.

8 Core cooling Loss of containment heat Long term loss of Applicable - Vent paths success removal leading to long-term decay heat other than the hardened following containment over-pressurization removal sequences wetwell vent path are not containment and failure can be a significant credited for non-ATWS failure or venting contributor in some PSAs. sequences and are through non Consideration of the considered to be a failure hard pipe vent containment failure mode might of the venting function.

paths result in additional mechanical failures of credited systems.

Containment venting through "soft" ducts or containment failure can result in loss of core cooling due to environmental impacts on equipment in the reactor/auxiliary building, loss of NPSH on ECCS pumps, steam binding of ECCS pumps, or damage to injection piping or valves. There is no definitive reference on the proper treatment of these issues.

9 Room heat up Loss of HVAC can result in Dependency on HVAC Applicable - DG HVAC is calculations room temperatures exceeding for system modeling explicitly modeled. Other equipment qualification limits, and timing of accident HVAC systems do not Treatment of HVAC progressions and impact the metrics for this requirements varies across the associated success application.

industry and often varies within criteria.

a PSA. There are two aspects to this issue. One involves whether the SSCs affected by loss of HVAC are assumed to fail (i.e., there is uncertainty in the fragility of the components).

The other involves how the rate of room heat up is calculated and the assumed timing of the failure.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 31

Table A4-13: Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application 10 Battery life Station Blackout events are Determination of Applicable - The calculations important contributors to battery depletion sequences dominating baseline CDF at nearly every time(s) and the risk metrics for this US NPP. Battery life is an associated accident application are non-SBO important factor in assessing a sequence timing and sequences or external plant's ability to cope with an related success flooding sequences SBO. Many plants only have criteria, where AC power recovery Design Basis calculations for is not credited. Higher battery life. Other plants have SBO recovery very plant/condition specific probabilities would not calculations of battery life. have a significant impact Failing to fully credit battery on the metrics for this capability can overstate risks, application.

and mask other potential contributors and insights.

Realistically assessing battery life can be complex.

11 Number of PWR EOPs direct opening of all System logic modeling Not Applicable for BWR's PORVs required PORVs to reduce RCS representing success for bleed and pressure for initiation of bleed criterion and accident feed - PWRs and feed cooling. Some plants sequence timing for have performed plant-specific performance of bleed analysis that demonstrate that and feed and less than all PORVs may be sequences involving sufficient, depending on ECCS success or failure of characteristics & initiation feed and bleed.

timing.

12 Containment All PWRs are improving ECCS Recirculation from Not Applicable - This is a sump / strainer sump management practices, sump (PWRs) or from LOCA concern and not a performance including installation of new the suppression pool LOOP concern.

sump strainers at most plants. (BWRs) system All BWRs have improved their modeling and suppression pool strainers to sequences involving reduce the potential for injection from these plugging. However, there is not sources (Note that the a consistent method for the modeling should be treatment of suppression pool relatively strainer performance. straightforward, the uncertainty is related to the methods or references used to determine the likelihood of plugging the sump strainer and common cause failure by blockage of the strainers.)

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 32

Table A4-13: Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application 13 Impact of Certain scenarios can lead to Success criterion for Not Applicable - This is a failure of RCS/RPV pressure transients prevention of RPV condition that would pressure relief requiring pressure relief. overpressure. (Note occur very soon after Usually, there is sufficient that uncertainty exists scram. The BNP SRV's capacity to accommodate the in both the are either mechanically pressure transient. However, in determination of the operated or dependent on some scenarios, failure of global CCF values that drywell nitrogen and DC adequate pressure relief can be may lead to RPV control power. The SRV's a consideration. Various overpressure and what have accumulators that assumptions can be taken on is done with the are good for several the impact of inadequate subsequent RPV hours after scram and the pressure relief. overpressure DC power is provided by sequence modeling.) batteries. Short term SRV operation is therefore not dependent on DG operability. The initial pressure transient is determined by operation of the SRVs and this the potential for overpressure is not DG or AC or DC power dependent Systems Analysis (SY) 14 Operability Due to the scope of PSAs, System and accident Applicable - These of equipment in scenarios may arise where sequence modeling of conditions are modeled in beyond design equipment is exposed to available systems and the BNP 2011 model; basis beyond design basis required support however, the risk metrics environments environments (w/o room systems for this application are not cooling, w/o component cooling, sensitivity to these w/ deadheading, in the ISLOCA conditions.

presence of an un-isolated LOCA in the area, etc.).

Human Reliability Analysis (HR) 15 Credit For Most PSAs do not give much, if System or accident Applicable - The ERO any credit, for initiation of the sequence modeling sequences dominating Emergency response with incorporation of the risk metrics are long Organization (ERO), including HFEs and HEP value term accidents driven actions included in plant- determination in both primarily by the failure to specific SAMGs and the new the Level 1 and Level cross tie 4kv and 480v B5b mitigation strategies. The 2 models busses. The ERO could additional resources and have an impact on these capabilities brought to bear via sequences. This is the ERO can be substantial, addressed in the especially for long-term events, application specific sensitivity studies involving operator actions.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 33

Table A4-13: Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application Internal Flooding (IF) 16 Piping One of the most important, and Likelihood and Not Applicable -

failure mode uncertain, inputs to an internal characterization of Application is not flooding analysis is the internal flooding sensitive to non-LOOP frequency of floods of various sources and internal initiators such as pipe magnitudes (e.g., small, large, flood event sequences breaks.

catastrophic) from various and the timing sources (e.g., clean water, associated with human untreated water, salt water, actions involved in etc.). EPRI has developed flooding mitigation.

some data, but the NRC has not formally endorsed its use. I LERF Analysis (LE) 17 Core melt Typically, the treatment of core LERF / Level 2 Applicable - Impact from arrest in-vessel melt arrest in-vessel has been containment event tree Level 2 events on the risk limited. However, recent NRC sequences metrics is at or less than work has indicated that there 1E-1 1 for LERF may be more potential than previously credited. An example is credit for CRD in BWRs.

18 Thermally NRC analytical models and LERF / Level 2 Not Applicable for BWR induced failure research findings continue to containment event tree of hot leg/SG show that a thermally induced sequences tubes - PWRs steam generator tube rupture (TISGTR) is more probable than predicted by the industry. There is a need to come to agreement with NRC on the thermal hydraulics modeling of TI SGTR.

19 Vessel The progression of core melt to LERF / Level 2 Applicable - Impact from failure mode the point of vessel failure containment event tree Level 2 events on the risk remains uncertain. Some codes sequences metrics is at or less than (MELCOR) predict that even 1E-1 1 for LERF vessels with lower head penetrations will remain intact until the water has evaporated from above the relocated core debris. Other codes (MAAP),

predict that lower head penetrations might fail early.

The failure mode of the vessel and associate timing can impact LERF binning, and may influence HPME characteristics (especially for some BWRs and PWR ice condenser plants).

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 34

ThhIe A4-1~ IJnc~rt~inti~ flnn~irh~r~r1 frnm FPRI 1O1R7~7 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application 20 Ex-vessel The lower vessel head of some LERF / Level 2 Applicable - Impact from cooling of lower plants may be submerged in containment event tree Level 2 events on the risk head water prior to the relocation of sequences metrics is at or less than core debris to the lower head. 1E-1 1 for LERF This presents the potential for the core debris to be retained in-vessel by ex-vessel cooling.

This is a complex analysis impacted by insulation, vessel design and degree of submergence.

21 Core debris In some plants, core debris can LERF / Level 2 Applicable - Impact from contact with come in contact with the containment event tree Level 2 events on the risk containment containment shell (e.g., some sequences metrics is at or less than BWR Mark Is, some PWRs 1E-11 for LERF including free-standing steel containments). Molten core debris can challenge the integrity of the containment boundary. Some analyses have demonstrated that core debris can be cooled by overlying water pools.

22 ISLOCA IE ISLOCA is often a significant ISLOCA initiating Not Applicable -

Frequency contributor to LERF. One key event sequences Application not sensitive Determination input to the ISLOCA analysis to non-LOOP initiators are the assumptions related to such as ISLOCA's.

common cause failure of isolation valves between the RCS/RPV and low pressure piping. There is no consensus approach to the data or treatment of this issue.

Additionally, given an overpressure condition in low pressure piping, there is uncertainty surrounding the failure mode of the piping.

23 Treatment of The amount of hydrogen Level 2 containment Not Applicable for BNP-Hydrogen burned, the rate at which it is event tree sequences no Ice condenser combustion in generated and burned, the BWR Mark III pressure reduction mitigation and PWR ice credited by the suppression condenser pool, ice condenser, structures, plants etc. can have a significant impact on the accident sequence progression development.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 35

Table A4-13: Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application 24 Basis for There is not a consistent Entire Model The HRA treatment HEPs method for the treatment of pre meets ASME Capability initiator and post initiator human Category II errors. However, human failures events are typically significant contributors to CDF and LERF.

25 Treatment of There is not a consistent Entire Model The HRA treatment HFE method for the treatment of meets ASME Capability dependencies potentially dependent post- Category II initiator human errors. SPAR models do not generally include dependencies 26 Intra-system Common cause failures have Entire Model The common cause common cause been shown to be important failure treatment meets events contributors in PRAs. As limited ASME Capability plant specific data is available, Category II generic common cause factors are commonly used.

Sometimes, plant specific evidence can indicate that the generic values are inappropriate.

4.8.2.3. Application Specific Uncertainty The baseline and application models for internal events, high winds, and fire were evaluated and cutsets were identified that were unique to the application results (delta cutset file). For each of these analyses, the top 10 cutsets, the RAW rankings above 10, and the FV rankings above 5E-3 are provided in Enclosure 6: PRA Quantification Data Tables. Using this data, an effort was made to detect any potential uncertainties not previously evaluated that are unique to this application or made more important by the application. These identified uncertainties were evaluated with the following sensitivity studies.

4.8.2.3.1. Unit 1 Sensitivity Studies The baseline and application models cutsets and importance rankings were evaluated.

Diesel generator redundancy is not contributing significantly to the delta risk. Except for two external flooding sequences, the failed sequences are non-SBO, long term loss of decay heat removal sequences. The primary contributor to these sequences is the failure of the operator to cross-tie 4kv and 480v AC emergency busses. This in turn fails one or more valves preventing the success of suppression pool cooling. Therefore, the HEPs assigned to the operator actions to perform those cross-ties are potential key sources of uncertainty that were evaluated by a sensitivity study. Since these and other actions that have the same effect occur in most HFE combinations and have dependencies, the risk significant combinations were evaluated as a family of events by Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 36

increasing the operator action combination probabilities by a factor of 5. Diesel generator 2, with a FV (Fusel-Vesley) of 0.37 for its extended maintenance unavailability event, is the most risk significant DG due to the loads that it supplies (see section 4.6 of this enclosure); therefore, the ICCDP was computed for this DG and not the other 3. The results of this analysis are delineated in Table A4-14.

Table A4-14: Unit 1 Sensitivity Study for Operator Action to Cross-tie AC Busses Evaluation Metric Result Unit 1 ACDF 1.9E-07

ý Unit 1 ICCDP for DG 2 in extended maintenance 9.OE-08 Another family of events considered important to these sequences is the offsite power loss initiators. These are the grid centered, weather centered, and plant centered loss of offsite power initiators. These were evaluated by increasing their probabilities by a factor of 5. The results of this analysis are delineated in Table A4-15.

Table A4-15: Unit 1 Sensitivity Study for Offsite Power Loss Initiators Evaluation Metric I Result Unit 1 ACDF I 1.7E-07 Unit 1 ICCDP for DG 2 in extended maintenance 9.9E-08 Two external flooding cutsets were in the top 25 cutsets. These are dominated by the 23 ft storm surge external flooding initiator. The probabilities for both of the external flooding initiators were increased by a factor of 5 to assess their sensitivity. The results of this analysis are delineated in Table A4-16.

Table A4-16: Unit 1 Sensitivity Study for External Flooding Initiator Evaluation Metric I Result Unit 1 ACDF T 7.2E-08 Unit 1 ICCDP for DG 2 in extended maintenance 4.8E-08 Two high wind initiators, %HW_5 and %HW_4, had RAW values greater than 10. These were treated as a family of events and were increased by a factor of 5 to assess their sensitivity. These events were also in combination with the SUPP-DG probability of failure for that respective range of high winds. These latter probabilities were set to a value of 1.0 in the model; therefore, they were not included in the sensitivity analysis.

The results of this analysis are delineated in Table A4-17.

Table A4-17: Unit 1 Sensitivity Study for High Wind Initiators Evaluation Metric Result Unit 1 ACDF 1A.4E-07 Unit 1 ICCDP for DG 4 in extended maintenance 1.2E-07 The above results show the metrics remain well within the boundary of Region III and the guidelines of Reg. Guide 1.177 even after the sensitivities are applied.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 37

4.8.2.3.2. Unit 2 Sensitivity Studies The sensitivities of the Unit 2 models to the application specific key uncertainties is judged to be no different than the sensitivities of the Unit 1 models. The Unit 1 and Unit 2 models are known to be almost identical, and the difference between the application metrics were shown to be insignificant. A comparison of the top 25 cutsets also confirmed this as the accident sequences depicted by the cutsets were the same.

Therefore, it was determined that Unit 2 sensitivity studies would mimic the Unit 1 sensitivity studies and they were not performed.

Both units will have a new set of breaker buses lined up at the end of the existing BOP switchgear. A sensitivity to fire risk was performed and shown in Table A4-18 Table A4-18: ICCDP Sensitivity to Addition of 4kV Breaker Ignition Sources Evaluation Metric Result Unit 1 Application CCDP - EDG 2 unavailable for 1 year A 6.572E-5 Unit 1 Application CCDP - EDG 2 unavailable with Increased IGF B 6.585E-5 Unit 1 ACCDP from increased IGF: (B-A) C 1.3E-7 Unit 1 ICCDP from increased IGF: (C* 14/365

4)1 2.OE-8 Unit 2 Application CCDP - EDG 4 unavailable for 1 year A 6.38E-5 Unit 2 Application CCDP - EDG 4 unavailable with Increased IGF B 6.394E-5 Unit 2 ACCDP from increased IGF: (B-A) C 1.4E-7 Unit 2 ICCDP from increased IGF: (C* 14/365

4)1 2.2E-8 1 - Multiplying the ICCDP of the most significant DG by 4 DG maintenance events is bounding 4.8.2.3.3. Uncertainties with High Winds and Fire To supplement the uncertainty discussions provided above, Table A4-19 and Table A4-20 provide additional information in regard to uncertainties associated with High Winds and Fire portions of the PRA model.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 38

Table A4-19: Additional High Winds Uncertainties Uncertainty Evaluation Impact discussion Wind damage to DG exhaust which is This is consistent with equipment No impact.

exposed. It is assumed consistent with design.

the BNP FSAR that these components if damaged the DG function is not compromised.

Missile damage to DG exhaust lines, in These exhaust lines are on top of Small potential risk that no single event can damage more the DG building, greater than 30 increase than one. feet above ground. Additionally the DG can function with the loss of the DG exhaust muffler, and thus should have no effect on results Missile or wind damage to Supplemental This is a bounding assumption. This would make the DG is assumed to be 1.0. The SUPP-DG enclosure is risk metrics associated designed for 155 mph and thus with high winds has significant robustness. smaller.

Additionally it is a small target for a missile to hit and thus this is a very conservative assumption.

The operator cannot start the SUPP DG This is true however based upon This would make the until after the storm has passed the size and strength of the storm, risk metrics associated the actual delay could be short with high winds compared to time available, smaller.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 39

Table A4-20: Additional Fire Uncertainties

Uncertainty Evaluation Impact Discussion 1 Fire frequency data is uncertain Industry and NRC agreed upon The Fire CDF/LERF would be and a collaborative effort data is used. directly impacted and the between EPRI and NRC to change in fire CDF/LERF would determine an improved be changed by the same component based fire fraction of any component fire frequency frequency bins impacted by improved data.

2 Fire Growth curves with the fire Fire growth curves for non-high This has a significant impact on growth of 12 minutes and then energy events are not realistic fire CDF with a slower fire steady HRR until burnout is not and much too fast. growth provides significant realistic more time for fire suppression.

3 Fire zones of influence used a This would reduce the impacted Evaluation is that the actual cylinder with a radius of the targets impact is very small and maximum fire plume distance negligible change in for the individual fire source, CDF/LERF.

around the source vertical to capture all of the potentially impacted sources. This is conservative, since the fire ZOI is smaller at the lower portion and again decreases in size for those sources with no cable trays.

4 Cabinet fires are postulated to Many cabinets the fire growth This would reduce the fire CDF exit the cabinet regardless of outside of the cabinet is not and impact of fire with a much the amount of ventilation for the likely based upon analysis that small zone of influence.

cabinet indicates these fires are suffering from oxygen starvation.

5 BNP cables in certain locations Fire propagation and time to fire This would reduce the fire CDF are protected with a flame damage would be longer up to in selected locations and retardant; this delays the 10 minutes and delay ignition for reduce the overall CDF. Would damage and retards the up to 12 minutes based upon have a minor decrease in propagation of the fire to other NUREG/CR-6850 Table Q-1. ACDF/ALERF impact on this cable tray. This flame retardant This was developed by testing application due to the locations coating is not credited in the of non-rated cables and BNP where the flame retardant current fire PRA. has IEEE-383 rated cables. coatings are applied.

6 At BNP, Motor Control Center Cabinets are not considered This is consistent with similar construction is such that the sealed, but are considered constructed MCCs treatment access panel doors are closed reduced capability for fire growth with other Peer Reviewed Fire with multiple fasteners. These outside of the cabinet. This is a PRAs and the treatment MCC doors also have gaskets much more realistic evaluation discussed in BWR OG report around the door. This results in of the affects of a MCC fire. 0000-0125-8912-RO (Report for essentially a closed cabinet. BWR Owners Group Fire PRA Projects on Fire Propagation on Electrical Cabinets and DC Hot Shorts- Draft) on MCC fire propagation. The effect of considering the cabinets sealed would reduce CDF/dCDF.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 40

Table A4-20: Additional Fire Uncertainties

Uncertainty Evaluation Impact Discussion 7 The BNP isophase buses This is a slight non- Based upon the actual location contain "quick disconnects" conservatism in that if counted of these quick disconnects and which are used to disconnect would increase the locations for targets no impact would be the main generator from the bus ducts fires, but very slightly expected for the EDG CT. The switchyard. Because there is reduce the fire frequency of failure of one of these no guidance in Section 7 of each individual bus duct fire disconnects in the past did not NUREG/CR-6850, Supplement source. (due to have more cause any damage to cables.

1 for treating these disconnects, locations) they have been excluded from consideration in determining the end components used to apportion the isophase bus duct ignition frequency.

8 By excluding certain locations Not counting components in The effects of changes to the containing equipment areas that have been screened ignition frequency for ignition unimportant to fire risk, the from the global analysis source bins would affect both criteria for selection of the boundary is performed as per the base Fire CDF/LERF and Global Plant Analysis Boundary the guidance in NUREG/CR- LAR Fire CDF/LERF similarly.

could result in an undercount of 6850. The resultant increase Thus this is not expected to be components for some bin(s) apportionment of Fire Ignition a significant source of and thereby the conservative Frequency among the remaining uncertainty related to delta risk calculation of ignition ignition sources is conservative for the application.

frequencies for those to the base model and the final components that are counted. fire risk.

9 Bounding values from This bounds 98% of possible The effects of changes to the NUREG/CR-6850 were typically HRR scenarios as described in HRR of ignition sources would used for the 98%ile files based NUREG/CR-6850. affect both the base Fire on the HRR case. For a limited The most accurate method CDF/LERF and LAR Fire delta number of sources these values would be to use HRR from CDF/LERF similarly. The effect were adjusted based on fire oxygen restricted cabinets for is most apparent in scenarios modeling insights, those cabinets with small with large numbers of targets or ventilation openings. This those which achieve HGL. In methodology has not been these cases masking may approved at the time of this contribute to a smaller delta analysis. CDF/LERF. Reduction in HRR would reduce masking effects and therefore potentially slightly increase the delta CDF/LERF for the application. The EDG AOT and base fire CDF/LERF are mostly driven by fires in the Main Control Room area.

Those sources that contributed most to base fire CDF/LERF were inspected to obtain an accurate 98% HRR. A number of sources were than assigned a significantly lower HRR based upon actual contents of the cabinets.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 41

Table A4-20: Additional Fire Uncertainties

Uncertainty Evaluation Impact Discussion 10 Fires involving oil are assumed This method is conservative, The effects of instant ignition of to instantly spill and instantly especially for treatment of large oil would affect both the base ignite to maximum HRR with no quantities of oil. Fire CDF/LERF and LAR Fire fire growth. CDF/LERF similarly in scenarios where cables affecting EDGs are damaged.

Many areas containing oil also affect the EDGs, electrical distribution (in the TB), or SUPP-DG. Thus no impact on EDG CT LAR 11 Generic ZOls calculated are Targets on the edge of the ZOI The effects of changes to the based on damage thresholds may require prolonged time to damage at the edges of that do not incorporate heat exposures (up to 30 minutes) the ZOI would affect both the soak time. prior to damage, but are treated base Fire CDF/LERF and LAR as instantly failed in the Fire Fire CDF/LERF similarly. This PRA after the time delay to is not expected to be a damage for each tray in stacked significant source of uncertainty tray configuration related to delta risk for the application.

12 The vertical and horizontal Using a larger square footage This is not expected to impact components of the ZOI were for the fuel package for the any results due to more realistic based on bounding vertical component of the ZOI ZOI was determined for the assumptions for the size of the results in a smaller ZOI and cabinets in the Main Control fuel package (i.e. 1 ft 2 for the consequently fewer targets Room, which is over 50% of the vertical component and 6 ft2 for being impacted. Similarly, using base fire CDF/LERF and the the horizontal component). a smaller footprint for the EDG CT LAR delta CDF/ LERF.

horizontal ZOI results in a The Main Control Room cabinet smaller horizontal ZOI dimensions were used to dimension. This treatment reduce the ZOI to more realistic results in an exaggerated ZOI, sizes.

and therefore, provides for a conservative selection of targets.

13 Cable fires due to Cutting and The impact on CDF/LERF of The effects of cutting and Welding ignition sources (Bins applying no target sets to cutting welding sources on cables 05, 11, and 31) are given no and welding ignition sources is would affect both the base Fire target sets. Procedures require considered negligible for the CDF/LERF and LAR Fire a fire watch with an extinguisher initial quantification input since CDF/LERF similarly. This is not to be present during hot work thermoset cable is assumed. A expected to be a significant activities; therefore it is thermoset cable is expected to source of uncertainty related to assumed that fires caused by self extinguish in the absence of delta risk for the application.

cutting and welding sources will a sustained ignition source.

not spread beyond the original I tray. I I Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 42

Table A4-20: Additional Fire Uncertainties

Uncertainty Evaluation Impact Discussion 14 Transient fires due to Cutting Placement of transient ignition The effects of target sets for and Welding (Bins 06, 24, and sources is based on selection of cutting and welding sources

36) involve the same target sets vulnerable targets. These are would affect both the base Fire as the general transients (Bins expected to be the same targets CDF/LERF and LAR Fire 03, 07, 25, 37). Separate sets for transient fires caused by CDF/LERF similarly. This is not ignition source to target set cutting and welding activities, expected to be a significant relationships are not defined in source of uncertainty related to this calculation for transients delta risk for the application.

fires caused by Cutting and Welding.

15 Target sets were collected Fires resulting in significant The effects of smoke would using heat based zone of smoke production could cause affect both the base Fire influence values or were additional damage beyond the CDF/LERF and LAR Fire developed using fire modeling heat based zone of influence CDF/LERF similarly. The as described in the base target sets collected. However, components that could be analysis. The damaging effects targets that are susceptible to affected by smoke in the Main of fire generated smoke are not smoke damage have not been Control Room also have cables specifically represented in the identified and are currently not which are damaged in many target data. evaluated in this calculation. cases by the various fires and thus achieving the same risk impact as smoke damage.

Equipment related to EDGs, SUPP-DG, or electrical distribution is not expected to be susceptible to smoke damage. This is not expected to be a significant source of uncertainty related to delta risk for the application.

16 In some cases field conditions This method of target There was very limited use of did not allow for raceways to be identification is not expected to drawing only for raceway located. For these, Fixed and affect the results of this analysis. location determination. The use Transient ignition source targets Where possible, uncertainty has of drawings for target set were determined through been reduced through determination would affect both review of controlled drawings. determination of ignition sources the base Fire CDF/LERF and from which the raceways should LAR Fire CDF/LERF similarly.

be excluded. In the event of a This is not expected to be a HGL scenario all routing is failed significant source of uncertainty based on what is listed as in the related to delta risk for the compartment, and is therefore application.

not subject to this uncertainty.

17 A heat release rate for Use of a bounding HRR for oil The effects of oil HRR would lubrication oil of 2,000 kW/m is applications may result in affect both the base Fire assumed to provide a bounding conservative target set CDF/LERF and LAR Fire value over that which is used in determination. No method has CDF/LERF similarly thus no all oil applications described in been determined for an impact is expected.

this calculation. alternate HRR. I Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 43

ThhI~ A4-90 Ar1rIitinn~I Firp IJnc~rt~inti~s

Uncertainty Evaluation Impact Discussion 18 A reduction factor of 5 is This is a referenced value. No None applied to the heat release rate uncertainty is identified for this for unconfined oil fires to treatment.

account for the fact that the floor slab must be heated up before propagation in an oil spill fire. This is supported through reference which states that the unit heat release rate for unconfined spills is about one fifth that of a deep pool having the same exposed surface area. This reduction is applied I only to unconfined oil fires.

19 The target set for some ignition Loss of all components in the The effects of sources with sources was assumed to compartment may be proven as assumed HGL would affect both encompass entire not probable by the use of the base Fire CDF/LERF and compartments regardless of the detailed fire modeling. This may LAR Fire CDF/LERF similarly.

ability of the ignition source to be needed to remove the These compartments where create a HGL. This was based conservatism for these areas. results were giving significant on the either a lack of Fire CDF/LERF were further information or uncertainty about investigated to reduce the HGL fire size or heat release of the uncertainty. Most of the Fire ignition source. CDF/LERF and application delta CDF/LERF are from the Main Control Room and this uncertainly does not impact this I area.

20 Target Damage time is based A higher temperature may be A higher damage threshold will on 400F due to Thermoplastic more appropriate. Note that the provide more time for cable 400F temperature was only suppression and potentially used in the time to damage reduce CDF and dCDF.

calculation. 625F was used for generating the ZOls.

21 Electrical cabinets, relay Although direct equipment The effects of fire on sensitive cabinets, and some sensitive damage may occur at a point equipment would affect both the equipment may have damage below the HGL threshold base Fire CDF/LERF and LAR thresholds below the 625 0 F temperature, it is expected that Fire CDF/LERF similarly.

utilized for cable failure. the impacts are captured Additionally cables attached to indirectly though the cable the electrical cabinets, some of failures due to either a ZOI fire which are in the fire ZOI fail the or HGL resulting from cable function giving the same or involvement, worse affect. The equipment related to EDGs, SUPP-DG, or electrical distribution functionality is not expected to be sensitive to temperature.

This is not expected to be a significant source of uncertainty related to delta risk for the I application.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 44

Table A4-20: Additional Fire Uncertainties

Uncertainty Evaluation Impact Discussion 22 A manual suppression A dedicated fire watch with an The effects of manual response time of 2 minutes is extinguisher is required to be suppression response time utilized for Cutting and Welding stationed at the hot work site. would affect both the base Fire ignition sources. Utilization of manual CDF/LERF and LAR Fire suppression times based on CDF/LERF similarly. This is not FAQ-08-0050 during expected to be a significant quantification will remove this source of uncertainty related to conservatism, delta risk for the application.

23 Credit is given in the Fire PRA For example, a modification to Modifications are similarly for conceptual modifications. the CST/ Condenser Hotwell credited in the base FPRA and level control valve has been the LAR FPRA to reflect the to-identified as implemented (close be as built plants. As either the valve on loss of air or loss of modification will be determined power). One alternative is to to not be required, or will be obtain complete circuit routing installed. This is not expected and failure analysis of the to be a significant source of associated circuits to show the uncertainty related to delta risk modification is not necessary. for the application as discussed the majority of the risk increase is from Main Control Room fires.

24 The event trees credit extended Not crediting extended RCIC Crediting extended RCIC RCIC operation without operation is somewhat operation would tend to suppression pool cooling if conservative. The impact on decrease the impact of having there is a station blackout CDF/LERF if RCIC was credited an EDG unavailable for event. For non-station for extended operation without maintenance and reduce the blackout events, extended suppression pool cooling is an expected CDF.

operation of HPCI and RCIC is area of uncertainty.

not credited unless RHR supplies suppression pool cooling.

25 The PSA model includes failure The probability of damage is More realistic treatment of several piping systems due considered to be conservatively resulting in reduction of water to water hammer. The high. The potential for failure of hammer damage probability possibility of MSO induced HPCI or RCIC due to water would decrease the risk water hammer failing RCIC or hammer is an area of importance of an EDG in HPCI due to loss of steam uncertainty, maintenance.

exhaust vacuum breaker is modeled in the PSA as loss of RCIC or HCPI due to water canon seizing the isolation check valve closed.

26 The power cables running from In the absence of detailed Detailed fire modeling of impact the SUPPDG along the outside evaluation, this considered to be of transformer yard fires on of the turbine are armored somewhat conservative. The SUPP-DG cables may provide cables. The PSA assumes that actual potential degree of results that reduce contribution fire in the adjacent auxiliary and damage to the supply cables to CDF and dCDF.

main transformers will damage from transformer fires in an area these cables. No credit is given of uncertainty for their armor shielding. I I Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 45

ThhI~ A4-90 ArIdition~I Fire IJnc~rt~inti~

Uncertainty Evaluation Impact Discussion 27 Operator Action "OPER- The action could receive Reduction in HEP would reduce SDGSTART" is increased by a increased credit if a dedicated the LERF and CDF impact of factor of ten over the nominal operator were to be assigned to the extended AOT.

value during fire scenarios that start the SUPP-DG or if credit it is credited for. were taken for pre-briefing or pre-aligning components.

28 Human actions performed For large compartments, small For fires in the turbine building outside the control room are fire scenarios, and actions with areas near the 4kV bus, some assumed to be unsuccessful if long performance time available, credit could be given for they require traversing or the environmental affect of a fire aligning the SUPP-DG. A more performing an action in a are limited and some credit realistic HRA assessment compartment with a fire. could be given, would reduce the CDF contribution of fires in these I_ I_ Iareas.

4.8.3. Tier 2 Evaluation To address Tier 2 concerns, the delta cutset file for the Unit 1 IE model with internal and external flooding was used to determine the ranking of the T&M events. Based on that ranking, an assessment was made as to the impact of having that component out for maintenance at the same time a DG was in extended maintenance. The component T&M events and their ranking are shown in Table A4-21 below.

Table A4-21: Tier 2 Sensitivity Study (DG 2 in extended maintenance)

T&M Event Component RAW EDG1DGN-TM-DO01 DG1 3.5 EDG1DGN-TM-D003 DG3 6.0 EDG2DGN-TM-D004 DG4 3.5 FPS2EDP-TM-P-1 Diesel Fire Pump 1.0 RHR1PTF-TM-LOOPA RHR Loop A 44.0 RHR1PTF-TM-LOOPB RHR Loop B Not listed DCP1BAT-TM1A1 DC Batteries Al 7.0 DCPlBAT-TM1A2 DC Batteries A2 7.0 DCP1 BAT-TM1 B2 DC Batteries B2 Not Listed Based on the RAW values, it is recommended that a battery or an RHR loop not be in T&M at the same time a DG is in extended maintenance.

4.8.4. Completeness Uncertainty With the exception of seismic, the BNP PRA model is constructed according to ASME standards. The PRA Quality Report provided in Enclosure 5 report discusses in detail the level in which the model meets the ASME requirements for the internal events model, the flooding model, the high winds model, and the fire model. Other external events, including seismic, are addressed by the IPEEE report and are not deemed to be significant with respect to this application due to their low contribution to CDF and their Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 46

low frequency of occurrence. The IPEEE treated the Transportation and Nearby Facility Accidents in the following manner:

Aircraft Impact - The IPEEE determined the CDF due to an aircraft impact to be less than 1 E-6/yr

Industrial Accidents - The IPEEE determined that no credible risk to the safe operation of BSEP is considered to be posed from the operation of nearby facilities.

Military Accidents - The IPEEE determined that the worst military accident would be an explosion of a cargo load of TNT. The blast pressure from this explosion is bounded by tornado loads.

" Pipeline Accidents - The IPEEE determined that a nearby natural gas pipeline fire would be less than a flat surface receives in the midday sun.

Hydrogen Storage Failures - The IPEEE determined that no credible threat existed based on hydrogen detonation.

Transportation Accidents - The IPEEE determined that transportation accidents were bounded by the worst case explosion as discussed in Military Accidents above.

Seismic is not considered to have a significant impact on this application. See section 4.6.2 of this enclosure for the discussion on seismic.

The most likely external flooding threat comes from a storm surge. The plant would have advance warning of this event, during which time preparations could be implemented to protect vital equipment against the anticipated flooding. If the flood magnitude was such that it could overwhelm the protective measures taken by the plant and damage the DG's, it would affect all 4 DG's the same and having one out for maintenance would be of little significance. The external storm surge generated flood was evaluated with the BNP IE model to assess the impact of failure of offsite power recovery, failure of the diesel driven fire pump, and failure to gain access to the SUPP-DG. These results are included in the evaluation of the baseline and application IE (with flooding) models in section 4.6 of this enclosure.

4.9. Key Uncertainty Sensitivity Studies Section 4.8.2.3 for the Unit 1 and Unit 2 sensitivites contain the dominate sensitivities that made an impact on the DG model. There were four major areas that dominated the results:

In review of the results, and based upon Brunswick electrical system, the Human Failure Events (HFEs) dominate the results. The operator actions to cross-tie either the 480 vac buses (E5/E6, or E7/E8) or the 4160 Essential Bus tie actions (El/E3 or E2/E4) were increased by a factor of 5.

" A second area of effect with a DG in maintenance is the potential increase in Loss of off-site power. In this case the LOOP initiators (Grid, Plant, Switchyard and Weather) were increased by a factor of 5.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 47

A third area of effect with a DG in maintenance is the potential increase in the external flooding initiator. In this case, the external flooding initiators were increased by a factor of 5.

" A fourth area of effect with a DG in maintenance is the potential increase in two of the high winds initiators. In this case, these initiators were increased by a factor of 5..

Each case is documented in Table A2-14 through A2-17. Conclusions derived from the sensitivities are that these four factors were the individual events that were the most important to this risk informed application and that with the postulated increase in failure frequency the resulting metrics are small as defined by Reg. Guidel.174 and Reg.

Guide 1.177.

4.10. Responses to Requirements of Reg. Guide 1.177 The following Table A4-22 presents responses to requirements put forth in various sections of Reg. Guide 1.177 pertaining to aspects of the model alterations made for the application. The specific section, requirement, and associated response are all indicated.

Table A4-22: Rea. Guide 1.177 Reauirements Requirement T Response The following address the requirements of Reg. Guide 1.177 Section 2.3.3.1, Details Needed for Technical Specification Changes To evaluate a TS change, specific systems or The Brunswick PRA for Unit 1 and Unit 2 include components involved in the change should be detailed system and component modeling. The modeled in the PRA. modeling largely meets the Capability Category 2 with F&Os associated with gaps being addressed in the PRA Quality Report, attached. The added Supplemental Diesel Generator is modeled as a super-component with some exceptions such as output breaker, which is consistent with industry failure data and it's stand alone design.

The model should also be able to treat the The alignments of components with testing and alignments of components during periods when maintenance are implemented in the Brunswick Ul testing and maintenance are being carried out and U2 PRA using mutually exclusive logic to constrain the configuration of DG maintenance outages. No more than one DG is allowed to be out of service at a time and remain at power for a significant amount of time, which is consistent with BNP Technical Specifications.

System fault trees should be sufficiently detailed to The BNP PRA fault trees specifically address specifically include all the components for which maintenance and testing on the diesel generator surveillance tests and maintenance are performed and support systems. This is done on either the and are to be evaluated component or train level as appropriate to match I the way testing and maintenance is conducted.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 48

Table A4-22: Reg. Guide 1.177 Requirements Requirement Response Component unavailability models should include The changes to the component unavailability model contributions from random failure, CCF, test for test downtime and maintenance downtime are downtime, and maintenance downtime. both based on plant specific test and maintenance experience. This includes the near term extended AOT realistic projections of maintenance practices after the TS change is approved and implemented.

For the emergency diesel generators random failure and CCF is included in the fault tree. The Supplemental Diesel Generator has a random failure probability as part of its fault tree. No common cause is assigned to the Supplemental Diesel generator due to large number of factors that make this new machine unique, as previously discussed in this report.

Change in the component unavailability model for The BNP PRA model as modified for the change in test downtime and maintenance downtime should risk includes the realistic estimate for DG pre-be based upon a realistic estimate of expected planned unavailability during the DG reliability surveillance and maintenance practices after the improvement project. There is no planned change TS change is approved and implemented (e.g. how in the DG surveillance testing frequency postulated often the extended CT is expected to be entered for for this risk evaluation.

maintenance or surveillance).

The component unavailability model for test The BNP PRA is based upon plant actual operating downtime and maintenance downtime should be experience for downtime due to either testing or based upon plant specific or industry wide maintenance.

operatinq experience, or both, as appropriate.

The component unavailability model should have The BNP PRA component unavailability model the flexibility to separate contributions from test and could have the flexibility of separate testing and maintenance downtime. For evaluating CT, the maintenance downtime. However for this risk contribution from maintenance can be equated to application the existing test and maintenance zero to delete maintenance activities, if desired. contributions were not separated since it would provide no benefit to the results. The testing associated with the extended maintenance is integral to the maintenance and thus is no value in separating it into separate contributions from test and maintenance downtime.

Additional details in terms of separating the failure The BNP PRA did not take this approach for the rate contributions into cyclic demand-related and DGs AOT as this was not justified.

standby time-related contributions can be incorporated, if justifiable, for evaluating surveillance requirements.

The CCF contributions should be modeled so that The BNP DG model does include CCF they can be modified to reflect the condition in contributions and they could be modified if which one or more of the components are required. In this case modify the CCF for having on unavailable. DG in the extended AOT was not performed as the risk results were not CCF sensitive The following address the requirements of Reg. Guide 1.177 Section 2.3.3.2, Modeling of Initiating Events The effect of TS changes on these initiating event The application does not impact initiating event frequencies should be considered. frequencies. Placing a single DG in maintenance unavailability is not an initiating event.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 49

Table A4-22: Reg. Guide 1.177 Requirements Requirement Response Some test and maintenance activities can The DG's are normally standby components and as contribute to some transients. such are started in response to a transient, thus the extended maintenance activity cannot contribute to any transient initiator.

The following address the requirements of Reg. Guide 1.177 Section 2.3.3.3, Screening Criteria The main qualitative considerations regarding the The BNP PRA results did not use any screening screening of sequences in TS change evaluations criteria of sequences.

in the inclusion of sequences directly affected by the TS change that would have been truncated by the frequency-based screening criteria alone.

The following address the requirements of Reg. Guide 1.177 Section 2.3.3.4, Truncation Limits Truncation limits should be used appropriately to The delta CDF, R1 and R2 values computed during ensure significant underestimation, caused by the risk Level 1 metric analysis were greater than truncation of cutsets, does not occur. one order of magnitude higher than the 1 E-1 1 truncation limit.

Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 50

4.11. References

1. ASME/ANS RA-Sa-2009, Addenda to ASME/ANS RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications

2. USNRC Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Rev. 2

3. USNRC Regulatory Guide 1.177, An Approach for Plant-Specific, Risk-Informed Decision Making: Technical Specifications, Rev. 1

4. USNRC NUREG 1855, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making, Vol. 1, March 2009

5. EPRI Report 1016737, Treatment of Parameter and Modeling Uncertainty for Probabilistic Risk Assessments, December 2008

6. Updated FSAR Brunswick Steam Electric Plant, Units 1 and 2, Revision 22 Enclosure 4: Evaluation of Risk Impact, Including Treatment of Uncertainties, Page 51

BSEP 11-0097 Enclosure 5 DIESEL GENERATOR COMPLETION TIME EXTENSION PRA QUALITY REPORT PRA QUALITY REPORT

Technical Adequacy of the Probabilistic Risk Assessment Analysis for BNP DG AOT Extension 5.1. Identification The PRA supports the extension of the BNP Emergency Diesel Generator Allowed Outage Time to 14 days. This is achieved by demonstrating that the impact of the proposed extension on plant risk remains within the guidelines of Regulatory Guide 1.174 [Ref. 2] and Regulatory Guide 1.177 [Ref. 3].

5.2. Determination of Required Capability Categories The BNP internal events PRA model, including internal flooding, fire and high winds, is utilized to calculate CDF/LERF given the proposed DG AOT extension. Any elements of the supporting requirements detailed in ASME/ANS RA-Sa-2009 that could be significantly affected by the proposed extension are required to meet capability category II requirements.

Although a Peer Review has not been conducted on the High Winds and Fire portions of the risk model, a Self Assessment was performed to evaluate the performance of these portions with regard to the ASME/ANS RA-Sa-2009 standard [Ref 1]. An additional Peer Review for the BNP PRA Fire portion of the model has been scheduled.

External events were initially assessed in the IPEEE. These included seismic events which were evaluated using the Seismic Margin Analysis method. Seismic was assessed as a single train IPEEE update.

The tables A5-1, A5-2, A5-3, and A5-4 below present a summary of the High Level Requirements specified in ASME/ANS RA-Sa-2009 [Ref. 1], the capability category required for the application and the F&O's documented with Level of Significance "Finding". These findings and their resolution or application impact for Internal Events and Internal Flooding PRA are addressed further in Table A5-6.

Table A5-1: High Level Requirements for Internal Events Capability Requirement Category F&O's Required Initiating Event Analysis (IE) II 1-3 4-2, 6-1, 6-2, 6-4, 6-5 Accident Sequence Analysis II 1-15 (AS)

Success Criteria (SC) II 1-11, 6-8 Systems Analysis (SY) II 4-5 Human Reliability Analysis 2-3, 3-3, 3-4, 3-6, 3-8 (HR) II23,33_3__-6_-

Enclosure 5: PRA Quality Report, Page 1

Table A5-1: High Level Requirements for Internal Events Capability Requirement Category F&O's Required Data Analysis (DA) II 1-2, 2-2 Quantification (QU) II 2-7, 2-11, 3-9, 4-7, 5-6 LERF Analysis (LE) I 1-19, 3-11, 3-12, 3-13, 6-12 Capability Category (CC) I are acceptable for LE, because the current results are acceptable and CCII those supporting requirements (SR) would further reduce the LERF and ALERF values. The SRs that do not meet the CC II criteria are generally those with not crediting scrubbing or using a realistic release analysis to allow equipment repair or to function in adverse environment. See Table A5-6 for details.

Table A5-2: High Level Requirements for Internal Floods Capability Requirement Category F&O's Required Internal Flood Plant 11 None Partitioning (IFPP)

Internal Flood Source Identification and 11 1-21, 1-22, 1-23, 1-24, 1-31 Characterization (IFSO)

Internal Flood Scenarios 1-20, 1-24, 1-25, 1-26, 1-27, 1-(IFSN) 28, 1-31, 6-16, 6-18 Internal Flood Induced Initiating Events (IFEV) 1-27, 1-31, 3-14, 6-15 Internal Flood Accident 1-31, 1-32, 1-33, 2-9, 2-10, 6-13, Sequences and 11 6-14, 6-17, 6-20, 6-21 Quantification (IFQU) 6-14,_6-17,_6-20,_6-21 5.3. Self Assessment To ensure PRA quality was upheld throughout the model a Self Assessment was conducted to evaluate the High Wind and Fire Portions of the BNP PRA model. These results are presented in Tables A5-7 and A5-8 in the following sections "BNP High Wind External Events PRA Capability Categories" and "BNP Fire External Events PRA Enclosure 5: PRA Quality Report, Page 2

Capability Categories". Furthermore, an additional Peer Review for the Fire PRA which will address these parts of the model has been scheduled.

Table A5-3: High Level Requirements for High Winds (Self-Assessment)

Capability Requirement Category F&O's Required High Wind Hazard Analysis 11 N/A (Self-Assessment)

(WHA) IIN/A_(Se_-Assessment High Wind Fragility 11 N/A (Self-Assessment)

Evaluation (WFR)

High Wind Plant Response 11 N/A (Self-Assessment)

Model (WPR) IIN/A_(Self-Assessment)

Table A5-4: High Level Requirements for Fire (Self-Assessment)

Capability Requirement Category F&O's Required Plant Boundary Definition 11 N/A (Self-Assessment) and Partitioning (PP)

Fire PRA Equipment 11 N/A (Self-Assessment)

Selection (ES)

Fire PRA Cable Selection 11 N/A (Self-Assessment)

(CS)__ _ _ _ _ _ _ _ _ _ _ _

Qualitative Screening (QLS) II N/A (Self-Assessment)

Fire PRA Plant Response N/A (Self-Assessment)

Model (PRM)

Fire Scenario Selection and N/A (Self-Assessment)

Analysis (FSS)

Fire Ignition Frequency (IGN) II N/A (Self-Assessment)

Quantitative Screening N/A N/A (Self-Assessment)

(QNS)

Circuit Failure Analysis (CF) II N/A (Self-Assessment)

Post-fire Human Reliability 11 N/A (Self-Assessment)

Analysis (HRA)

Fire Risk Quantification (FQ) II N/A (Self-Assessment)

Seismic/Fire Interactions I N/A (Self-Assessment)

(SF)

Uncertainty and Sensitivity 11 N/A (Self-Assessment)

Analyses (UNC) IIN/A_(Self-Assessment)

Enclosure 5: PRA Quality Report, Page 3

Sesimic/ Fire interaction is acceptable as CC I because the EDGs are not in the turbine building where most of the Seismic Fire interaction would occur and many of the power cable that connect the emergency diesel generators and off-site sources are run through the electrical tunnel underneath the turbine building. Thus damage due to fire and failure of fire suppression in the turbine building is not important for this application.

5.4. Necessary Scope and Results The BNP Internal Events PRA consists of a full scope Level 1 model to measure CDF that includes modeling of fire, high winds, internal flooding, external flooding, and station blackout (SBO). Furthermore, Level 2 risks are evaluated with an additional LERF model. Note that seismic and additional external events were evaluated with the IPEEE and are not integrated into the current BNP PRA models.

5.5. Peer Review In accordance with RG 1.200 Rev. 2 and ASME/ANS RA-Sa-2009 [Ref. 1], a Peer Review of the BNP PRA was conducted in 2010 by eight PRA experts. The review provided findings and suggestions regarding the model and identified 38 supporting requirements within the internal events and internal flood portions of the model that did not meet capability category I1. The significance of any possible effects associated with these requirements in the scope of the application for the proposed extension were analyzed and addressed prior to proceeding with the use of the model. The section BNP Internal Events PRA Capability Categories includes a summary of the findings of the Peer Review and how these are addressed. The requirements discussed and their resolutions are presented in Table A5-6 in the same section, located in this enclosure.

5.6. Update and Review History The BNP PRA model has undergone numerous updates and reviews in an attempt to maintain a representation of the as built, as operated plant in response to improvements in technology, methods, and state of knowledge. This section presents summaries of both the BNP PRA Model of Record updates as well as comprehensive reviews performed. Table A5-5 provides a summary of the BNP Model of Record updates.

Enclosure 5: PRA Quality Report, Page 4

Table A5-5: BNP Model of Record Update Summary MOR REV Unit CDF (freq/yr) LERF (freq/yr)

Unit 1 2.7E-05 NA MOR 92* NA Unit 2 2.7E-05 NA Unit 1 9.1E-06 NA MOR 96* NA Unit 2 9.1E-06 NA Unit 1 2.54E-05 4.27E-06 MOR 98* NA Unit 2 2.54E-05 4.27E-06 MOR Unit 1 4.92E-05 4.78E-06 98R1"* Unit 2 4.92E-05 4.78E-06 MORO02* 2 Unit 1 4.97E-05 Not updated Unit 2 4.97E-05 Not updated Unit 1 4.19E-05 2.13E-06 MOR 03* 3 Unit 2 4.19E-05 2.13E-06 MOR04 4 Unit 1 4.11E-05 Not updated Unit 2 4.04E-05 Not updated Unit 1 3.59E-05 Not updated MOR05 0 Unit 2 3.32E-05 Not Updated Unit 1 3.34E-05 Not updated MOR06 6 Unit 2 3.07E-05 Not Updated MOR07 7 Unit 1 1.22E-05 Not updated Unit 2 1.17E-05 Not Updated Unit 1 1.09E-05 Not updated MOR08 8 Unit 2 1.10E-05 Not Updated BNP 2010 Unit 1 8.91E-06 1.08E-07 Model Unit 2 7.79E-06 1.11E-07 BNP 2011 Unit 1 7.87E-06 5.67E-07 Model Unit 2 7.86E-06 5.65E-07

Unitized model for Units 1 and 2, thus no delta in CDFbetween Units MOR04 addresses findings and observations from 2001 Peer Review along with failure and unavailability data and success criteria update.

MOR05 updated HRAs and answered findings and observations from 2001 Peer Review to support Mitigating System Performance Index (MSPI), this included some revisions to the Human Reliability Analysis.

Enclosure 5: PRA Quality Report, Page 5

MOR06 revision used the on-line EOOS-06 model as its starting point. The major enhancement associated with the EOOS-06 model was the incorporation of the ability to cross-tie service air between units, which also required extensive addition of cross unit service water support and AC power. Changed MOV and AOV data from time based failure to demand based failure.

MOR07 changes includes several items: implemented a new diesel room heat analysis, additionally added two independent generators to support DC power; removal of safety Bus initiators; updated HRA events for post initiators and included consideration of improved battery life analysis; addition of new initiating event for loss of intake structure; update of DG data to 2007; update LOSP to 2007; air operated valve data update; incorporated a conversion from calendar years to reactor years per the PRA standard; added additional water source for circulation water pump seals; provided logic to credit swing turbine building closed cooling water system for both units.

MOR08 involved improved logic for the instrument air system modification and improved ATWS logic.

BNP 2010 Model incorporates updates to the common cause failure analysis for batteries and other equipment with major revisions to meet Reg. Guide 1.200 improvements, including revisions to accident sequences, data (NUREG 6928 for generic data) and initiating event updates, and plant configuration through 2009.

Resolves remaining items identified in 2007 Reg. Guide 1.200 Self Assessment.

BNP 2011 Model addressed a majority of Facts and Observations (F&Os) from the 2010 peer review. Many of the F&Os resolved were on the flooding model, which this effort resolved technical issues and improved the documentation. As part of this effort the significant flooding scenarios were examined for realism and some adjustments were made based upon material of piping and design attributes. Additionally external events such as simplified seismic and high winds were implemented into the CAFTA fault tree with applicable documentation from the vendor that performed the effort. A change to the Station Blackout tree was implemented to address concerns over the conservatism of the model. Finally some HRAs were revised to address F&O comments.

5.6.1. BNP Review Summary 1988: The original Brunswick PRA, docketed in May 1988, included a Level 1 PRA and external events PRA. The PRA was reviewed by INEL under contract to NRC and the results documented in November 1989 (NUREG/CR-5465). Many of the insights provided by this review were incorporated into the IPE PRA submittal to the NRC.

1990-1992: Results from the IPE analysis were reviewed by Progress Energy's Nuclear Fuels section; BNP plant personnel (operations, training, engineering); as well as other external organizations. External consultants performed a comprehensive external review of the major elements within the Level 1 PRA and Level 2 analysis.

Enclosure 5: PRA Quality Report, Page 6

1994-1995: A variety of peer reviews were performed, as documented in the IPEEE.

These reviews included analyses for seismic, fire, and external events. Corporate and BNP plant personnel within operations, training, fire protection, licensing, and nuclear engineering formed an independent review team to assess the results of the IPEEE analysis. The evaluation was performed by referencing NEI 91-04 closure guidelines for potential plant vulnerabilities, identifying alternative solutions, and recommending actions to resolve severe accident issues.

2000: An independent peer review was performed by an individual outside expert.

2001: The BWROG Peer Certification Review consisted of a comprehensive review of the BNP Level 1 and Level 2 (LERF) models based on the NEI 00-02 quality process.

2007: A gap assessment of the PRA model and associated documentation was conducted to provide BNP plant management and Progress Energy input for decision making regarding the viability of the PRA and its use for applications. The review was performed in accordance with the ASME PRA Standard Addendum B.

2010: A full-scope peer review of the PRA model and documentation was conducted under the guidance of NEI 05-04, ASME/ANS RA-Sa-2009, and NRC clarifications provided in Regulatory Guide 1.200, Rev. 2. The review included models for internal flooding and LERF.

5.7. BNP Model Update Process The BNP PRA model update process may be initiated by a number of factors, ultimately governed by the necessity to maintain a model that represents the as built, as operated plant, as specified in Regulatory Guide 1.200. Possible reasons for a model update include changes in risk significance of systems or components, plant data, procedures, analysis methods, operating experience and state of knowledge regarding the subject.

Progress Energy maintains procedures in addition to industry standards that specify when model updates are necessary. Progress Energy procedures require engineering changes to be evaluated for applicability to the PRA model and further estimation of the CDF/LERF impact, which determines the timing of the incorporation into the site specific PRA model.

5.8. BNP Quality Control Quality Control for the BNP PRA is ensured through the use of Peer Reviews and subsequent resolution of F&Os, self assessments, periodic model updates, staff training and qualification requirements, as well as procedure controls. Procedures are in place to mandate adequate model control, documentation of model development and changes, and specification of corrective actions to be used if errors are discovered.

Enclosure 5: PRA Quality Report, Page 7

5.9. BNP Internal Events PRA Capability Categories The 2010 Peer Review of the BNP PRA identified 38 supporting requirements (SR's) from ASME/ANS RA-Sa-2009 that did not meet capability category I1. All other SR's met or exceeded capability category II. The 38 SR's identified, as well as SR's with F&O's Level of Significance "Finding", are listed in table A5-6 below and cite the appropriate F&O number, the applicable SR, and the finding. The majority of the issues raised were addressed in the response to the F&O's and documentation is provided. A description of the impact to the DG AOT extension application is given for any items that were not included in the response to the F&O's. The Self Assessment findings are discussed in the next section and are presented in Tables A5-7 and A5-8 for the High Wind and Fire portions of the BNP PRA model. Note that documents cited in Table A5-6 are primarily BNP PRA calculations that document the development of the current model but do not impact this submittal beyond the information already presented in the submittal report and documentation. As such these documents are not referenced or included as a part of this submittal.

Enclosure 5: PRA Quality Report, Page 8

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review DG AOT Impact Number SR Capability Finding Category cat not Only evaluations provided were for systems used as Resolved with system evaluation completed and 4-2 IE-A5 tme t mitigating provided. systems. No evidence of other system reviews documented in BNP 2011 MODEL.

The use of a single pipe section as the basis for IE frequency 1-3 IE-C1 Cat 1-3 met for breaks outside of containment could be nonconservative A sensitivity analysis was performed and no impact was 6-5 by a factor of 100 to 1000 compared to latest EPRI pipe determined with regard to the application.

failure frequency methodology.

Cat 1-2 met, 6-1 IE-C5 Cat 3 not Plant availability factor not updated Resolved, updated in BNP 2011 MODEL assessed Addressed in BNP 2011 MODEL. The pipe rupture Controlled plant shutdowns are screened from being frequencies for Break Outside Containment have been considered plant specific initiating events if there is a greater revised to incorporate the latest Pipe Rupture than 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LCO time, per IE calc BNP-PSA-032 sec.2.7. Frequencies from EPRI's Pipe Rupture Frequencies for Reference leg breaks outside containment are screened from Internal Flooding Probabilistic Risk Assessments, consideration based on negligible contribution (BNP-PSA- Revision 2 Report 1021086. The 032) but there is no documented value for frequency to analysis assesses piping systems that can contribute to 6-2 IE-C6 Cat 1-3 not support this decision. There are questionable assumptions on high energy line breaks outside containment and includes 6-4 met Breaks Outside Containment, particularly the use of a non- Main Steam Lines, Feedwater Lines, High Pressure conservatively small pipe break frequency for Main Steam Coolant Injection Lines, Reactor Core Isolation Cooling and Main Feedwater piping through use of old EPRI pipe Lines, Reactor Water Clean Up Lines and Scram section methodology vice consideration of piping length (see Discharge Volume. The analysis, using the new method also IE-C1; however the issue here is screening of potential resulted in un-isolated pipe break frequencies that were initiators as opposed to a too low IE frequency for a modeled near the values of the old EPRI pipe break analysis event). values and thus the high energy Break Outside Containment initiators are still screened from the model.

For SBO, the event tree model does not guarantee that a safe stable state has been achieved. The LOSP convolution Resolved in BNP 2011 MODEL, the event tree was 1-15 AS-A2 Cat 1-3 met analysis (BNP-PSA-036) includes recovery AC power expanded to address required questions for a safe stable implicitly. However, the accident sequence analysis does not state.

consider the possibility of failure of suppression pool cooling following AC power recovery.

Enclosure 5: PRA Quality Report, Page 9

Table A5-6: 2010 Peer Review F&Os (Findinas only included)

Peer F&O Applicable Review DG AOT Impact Number SR Capability Finding Category For the majority of small breaks it was determined that RCIC would be acceptable. All other BWRs referenced for the Success Criteria Notebook developed for the BNP PRA model credit RCIC. The RCIC system was designed to deliver 460gpm for transient events with MSIV closure rather than LOCA. A review of the LOCA cases in the GE NEDO-24708A study, case 26 (Figures 3.1.1.1-26.1 through 26.8) always pairs RCIC with CRD to satisfy For small break LOCA, the high end of water break is makeup requirements for the upper limit small liquid LOCA. MAAP analysis Case BR0039 supports use of 1-11 SC-3 Cat 1-3 met approximately 1" dia., RCIC is credited for HPI for success, RCIC and a single CRD pump for a SORV which is at the but no MAAP run was performed to demonstrate the lower end of the medium steam line LOCA range.

success. However, it assumed that the large majority (>95%) of the small break LOCA contribution is from the CRD withdraw (3/4" diameter) and insert (1" diameter) lines which would result in limited break flow due to flow restrictions from these lines that would result in break flow well below the RCIC capacity. As such, RCIC is credited as a viable injection method for small break LOCAs consistent with other PRAs. The ability of RCIC to mitigate small liquid breaks is addressed as an area of uncertainty.

There does not appear to be a centralized discussion of computer code limitations. Codes used in generic references and SAR (and associated limitations) are not discussed.

6-8 SC-C2 Cat 1-3 met System level success criteria for meeting Top Event gate Ti isoadcen success criteria are not as well documented in BNP-PSA-033 DG importance.

but appear to be documented on a distributed basis in Heatup Calculations and in System Notebooks.

Failures of the F032A and F032B outboard feedwater check valves are not modeled. The system notebooks state that 4-5 SY-A13 Cat 1-3 met such failure is considered "improbable". However, the model Resolved in BNP 2011 MODEL.

does include the failure of inboard check valve F010A to reopen.

Enclosure 5: PRA Quality Report, Page 10

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review Finding DG AOT Impact Number SR Capability Category Operator interview insights are documented in the HRA Calculator. The information contained in the HRA Calculator was sufficient to demonstrate the Capability Category I was met. However, the information in the HRA did not demonstrate that detailed interviews with Operations and Training Personnel were conducted for the purpose of This is a documentation concern. Detailed operator Cat 1 met confirming procedure interpretations. For example, many of interviews were conducted for the purpose of confirming 3-3 HR-E3 Cat 2-3 not the calculations referred only to an interview conducted with procedure interpretations. PRA documents have been updated to improve their clarity in this area. The HFE's assessed single a operator areferred "talk through" in January A on 9/16-17/2008. few an 2008, calculations operator mentioned are no longer used in the PRA.

interview on 3/11/2010, or simulator runs conducted on 1/19/2010. A few calculations (OPER-BLACKSTART, OPER-CNS, OPER-CWSIE) did not have any input on operator interviews. The purpose and content of these interviews is not evident. Based on the information provided, Capability Il/111 was not demonstrated.

While it was documented that simulator observations and operator interviews were performed in most HRA 3-4 HR-E4 Cat2-3 Cat 1 met not calculations, interviews were there is no used evidencethethat to confirm these observations response or models for the Resolved in documentation BNP of both2011simulator MODEL interviews with added and assessed scenarios modeled in the PRA. For example, there was no checklists.

interview checklist, simulator/scenario checklist, or other documentation to demonstrate that the HRA analyst confirmed the response models.

Problems were noted with the HRA calculation for OPER-Cat 1-2 met, DCDG. Specifically, no execution failure probabilities were Resolved in BNP 2011 MODEL with execution evaluation N/A HR-F2 Cat 3 not assigned to the tasks of starting and connecting the DG.

assessed Additionally, the calculation may not have considered all of the necessary breaker manipulations.

Enclosure 5: PRA Quality Report, Page 11

Table A5-6: 2010 Peer Review F&Os (Findinas only included)

Peer F&O Applicable Review DG AOT Impact Number SR Capability Finding Category In general, the HRA calculator file was reviewed and found to provide an assessment of the performance shaping factors listed in the SR for the HEP calculations. Some detail in the calculations could be enhanced. For example, the 3-6 operator action OPER-LDSHD calculation does not have the Resolved in BNP 2011 MODEL with missing information 3-8 HR-G3 Cat 1-3 met cognitive procedure listed and does not address the training added to HRA Calculator requirements. Calculations for OPERMSIVCBP and OPER-DEPRESS1 state that simulator and classroom training are provided but does not provide a frequency. The calculations for OPER-DCDG and OPER-N2SUPPLY do not address training, the cognitive procedure or the staffing requirements.

In BNP-PSA-034, Attachment 3 describes the Type A human error screening methodology employed for the Brunswick PRA model. The methodology follows the screening methodology suggested in NUREG 1792. The screening values used in Tables 1 and 2 contradict the values said to be employed in Section E.3.1 (i.e. 0.008 applied to Type A human errors affecting a single train and 0.0008 for common Documentation only, the ambiguity in the documentation 2-3 HR-12 Cat 1-3 met cause human failure events), will be addressed at a later point. No impact to DG AOT Nonetheless, Tables 1 & 2 in Attachment 3 utilize screening application.

values of 0.01 for single train Type A human errors and 5E-03 for common cause errors. When these screening values were used for the HEPs and the model subsequently quantified, all cross-train Type A HEPs using screening values of 5E-03 having a Fussell-Vesely Importance < 5E-03 are stated to be screened.

Based on the information presented in the system notebooks (BNP-PSA-062), the PRA estimates the standby time for Cat 1 met components based on the number of trains available vs. the Issues were investigated and based on the investigation it 2-2 DA-C8 Cat 2-3 not number of running trains (e.g., 50% for a 1 of 2 system). was determined the results are realistic and in turn met Actual plant specific data concerning standby time is not documented.

collected and evaluated in the BNP PRA. However, may be available from OSI PI to support this.

Enclosure 5: PRA Quality Report, Page 12

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review DG AOT Impact Number SR Capability Finding Category Unavailability data was taken from MR databases, and outage periods were excluded from the UA calculations (as documented in the BNPUnavail spreadsheet that is part of the BNP-PSA-004 notebook). In the case of the shared DGs, the BNPUnavail spreadsheet is incorrectly 1-2 DA-C13 Cat 1-3 met deleting all DG OOSs that occur when either unit is in an Resolved in BNP 2011 MODEL, DG unavailability was outage. Based on the modeling of the shared DGs, the corrected.

correct treatment would be to NOT exclude any DG outage (regardless of unit outage condition). This error results in an DG unavailability that is too low. It should be noted, that based on current data, the impact of this error appears to not be too significant on the results.

Dependency analysis was performed on the identified HFE combinations (see BNP-PSA-034 and associated spreadsheets). The dependency assessment approach used appears to be appropriate. In developing recovery rules to be applied to the cutsets, maximum combinations of 3 HFEs were included. Any cutsets with greater than three HFEs that meet the recovery rule criteria are recovered to a minimum joint HFE of 1E-6 (and often higher). As a result, there are cutsets that contain more than three HFEs that are being recovered to a higher frequency than may be warranted Resolved in BNP 2011 MODEL, combinations of operator 3-9 QU-C2 Cat 1-3 met (either because one or more of the additional HFEs may be actions and dependencies were analyzed to ensure a independent of the others, or because the joint HFE correct value.

probability is still above the floor value of 1E-6 (and often higher). As a result, there are cutsets that contain more than three HFEs that are being recovered to a higher frequency than may be warranted (either because one or more of the additional HFEs may be independent of the others, or because the joint HFE probability is still above the floor value of 1E-6 and hence could be reduced further). This conservatism appears to increase the calculated CDF/LERF by at least a modest amount.

Enclosure 5: PRA Quality Report, Page 13

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review Number SR Capability Finding DG AOT Impact Category It is stated in BNP-PSA-030 that the top 200 cutsets have been reviewed. However, to determine if there are logic problems buried deeper down in the cutsets, a sample should be taken of significant cutsets. The correct definition of 2-11 significance is stated in the quantification notebook. The Resolved in BNP 2011 MODEL, cutsets and accident 2-7 QU-D1 Cat met 1-3 not review should include a sampling of cutsets over the full Resolved 5-6 range of significance (i.e., top 95% of cutsets contributing to CDF/LERF). sequences inwere Bo cutetan accien reviewed and documentation of review improved.

In addition, the QU notebook attachments (cutset tables) for CDF and LERF Cutsets, discusses only the top 20 CDF cutsets. No discussion of the top 20 LERF cutsets was found.

The discussion should be expanded.

Section 3.9 of BNP-PSA-030 compares BNP PSA results Cat 1 met against other units. However, there is no analysis of Resolved in BNP 2011 MODEL, BNP Quantification 4-7 QU-D4 Cat 2-3 not contributors as required for Cat I1.In addition, no references calculation was revised to include an enhanced similar met are provided for the other PRAs that are compared to (e.g., plant review.

are these IPE results, or current results, etc.)

As discussed in BNP-PSA-049, Appendix D, Section D.1, the CET structure allows for the identification of recovery and repair actions that can terminate or mitigate the progression Cat 1 met of a severe accident. This process was incorporated into the Capability category I provides reasonable results for 3-12 LE-C3 Cat 2-3 not original analysis, rather than performing a review of Capabiliy cateoryprovid reaobe res met significant accident progression sequences and then LERF. Any credit of repair would reduce LERF.

incorporating repair, as would be inferred from the standard.

However, it does not appear that significant accident progression sequences were reviewed.

There is no evidence that significant accident sequences Cat 1 met were reviewed to determine if engineering analyses could Cat 2 not support continued equipment operation or operator actions to Capability category I provides reasonable results for 3-11 LE-C10 met reduce LERF. It was noted that this conservative approach LERF. Any credit for equipment survivability would reduce Cat 3 not with respect to equipment survivability was documented in LERF.

assessed the uncertainty analysis (BNP-PSA-075, Table 1, Item 236)

Cat 1 met Cat 1 met There is no evidence that significant accident sequences Capability category I provides reasonable results for 3-11 LE-C12 met were reviewed to determine if engineering analyses could LERF. Any analysis supporting equipment or operators Cat 3 not support continued equipment operation or operator actions to would reduce LERF.

Cassessed reduce LERF.

assessed Enclosure 5: PRA Quality Report, Page 14

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review DG AOT Impact Number SR Capability Finding Category Cat 1 met BNP-PSA-049, Section 3.1.2 notes that the treatment of Capability category I provides reasonable results for 3-13 LE-C13 Cat 2-3 not scrubbing by the reactor building is treated in a conservative LERF. Any additional treatment of scrubbing would met method. This conservative approach was noted in the reduce LERF.

uncertainty analysis (BNP-PSA-075, Table 1, Item 217).

Parameter values were selected with regards to the PRA Standard's requirements for HR and DA. Consideration of severe accident conditions upon these parameters is provided in Appendix M, or in some instances Appendix C, of the BNP-PSA-049 notebook. Section G of LE notebook captures the human error modeling, and incorporated the general methodology approach used in Level 1 HRA.

However, the data values documented in BNP-PSA-049 were 1-19 LE-El Cat 1-3 met developed during a previous PRA update. It appears that Resolved in BNP 2011 MODEL, LOSP curves and some values may need to be updated to be consistent with component failures were updated.

changes in the Level 1 data. For example, OSP recovery values (such as ACP1XHE-MN-OFFE) are not consistent with the current OSP recovery curve (and LOSP is now categorized by type of OSP failure as opposed to a composite value). On the other hand, changes in component failure data appear to have been updated in the Level 2 trees. However, the documentation does not indicate that the values shown in BNP-PSA-049 have been superseded.

There is very limited discussion of the impact of variability /

sensitivity in time to core damage amongst different methodologies upon potential applications in Appendix C of Cat 1-3 not BNP-PSA-049. While limitations of the quantification process Resolved in BNP 2011 MODEL, discussed uncertainties 6-12 LE-G5 met are discussed in BNP-PSA-030 Sec.3.6, that discussion is and limitations of use.

not pertinent to SR LE-G-5. It is concluded there is not sufficient discussion of the limitations of the LERF analysis that could impact different applications, thus this documentation requirement is NOT MET.

Table F.5 of RSC 10-05 lists all of the potential flooding sources; however one of the major assumptions is that all fire 1-2 F-A protection sprinkler systems are dry-type systems. SD-41 Resolved in BNP 2011 MODEL, information corrected 1-21Cat 1-3 not contains a listing of fire protection systems and most are wet Resoldin anP 21deLo met type systems. Since the inclusion of fire protection could and flooding analysis updated.

significantly alter the screening and scenario development, this is considered to be not met.

Enclosure 5: PRA Quality Report, Page 15

Table A5-6: 2010 Peer Review F&Os (Findinas only included)

Peer F&O Applicable Review DG AOT Impact Number SR Capability Finding Category Pipe breaks and valve body failures were the only failure 1-3 not mechanisms identified. Although plant experience includes a Cat met Resolved in BNP 2011 MODEL, gasket and expansion 1-22 IFSO-A4 gasket failure, failures of gaskets, expansion joints, etc. are joint caused flooding and human induced mechanisms not discussed. Therefore, SR is not met as all required are now covered.

mechanisms are not considered.

The temperatures and pressures of condensate, feedwater, Cat 1-3 not and nuclear service piping are not considered. The flow rates Resolved in BNP 2011 MODEL, characteristics of flood met for circulating water piping are based on one pump instead of sources are described.

all four. This SR is judged to be not met.

Most of the level of detail required to relate the flood sources 1-24 IFSO-B1 Cat 1-3 not to actual rooms and piping is located in a vendor database Resolved in BNP 2011 MODEL, maps are provided for 1-31 met that is not part of the documentation file. Therefore this SR is flood sources, initiating events, and propagation.

not met.

The flooding analysis (as documented in RSC 10-05) discusses sumps and drains, curbs, spray shields, and watertight doors. No mention is made of flood alarms (or Cat 1-3 not other information that would alert operators of the flood), Resolved in BNP 2011 MODEL, flooding analysis in the 1-25 IFSN-A2 met blowout performedpanels based oronHVAC dampers.

assumed operatorAsintervention, flood screening the lackis HRA Calculator is a flood implements occurring alarms to tell operators there in the system.

of information concerning alarms impacts the ability to accurately assess the probability of successful flood termination.

RSC 10-05 does not identify any automatic flood isolation features. No operator indications are discussed. However, the qualitative screening of flood areas evaluates successful Cat 1-3 not operator action to isolate any flood assuming that the flood is Resolved in BNP 2011 MODEL, alarms are documented 1-20 IFSN-A3 met immediately detected. The flood documentation needs to in the HRA calculator.

indicate how each flood would be detected and the time to identify the occurrence of the flood needs to be factored into the HEP calculation. As the current evaluation is non-conservative, this SR is assessed as not met Enclosure 5: PRA Quality Report, Page 16

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review Finding DG AOT Impact Number SR Capability Category The flooding documentation in RSC 10-05 does not provide a comprehensive listing of PRA-modeled equipment in each area. Similarly the walk down notebook (RSC 10-03) does not contain this information. It appears that additional component location information is contained in the flooding database tool; however this database was not available for review. Flooding mitigating features (e.g.,berms, spray shields, etc.) are described for some components, but it is not The flooding findings have been resolved by improved Cat 1-3 not clear if all such features are documented in either RSC 10-03 1-24 IFSN-A5 met and RSC 10-05. Using the database, the specific PRA documentation and PRA model analysis. Flooding events equipment impacted by floods in each area (due to direct do not have a significant impact on this application.

flooding or propagation) are supposed to be automatically identified.

While major components are discussed in the documentation, smaller electrical items that might be impacted by a flood in an area are not discussed (e.g., any non-watertight junction boxes). Based on the information available, it cannot be verified that this SR is met.

The methodology is considered sufficient and robust for identifying flood damage due to submergence. EPRI TR-1019194 recommends that at least a 10 foot radius from a pipe be considered for impact of spray due to pipe failure.

Many industry PRAs assume up to 30 feet for spray impact.

While spray due to water falling down propagation pathways has been assessed for impact (or lack thereof) on SSCs, there is no evidence that this was done for any equipment.

Cat 1-2 not Equipment in flood zones such as upper levels of the reactor met building would likely be subject to this failure mechanism. Resolved in BNP 2011 MODEL, impacts of spray and Cat 3 not Equipment in zones where submergence occurs (e.g., lower effects of high energy line break are discussed.

assessed level of Reactor Building) could be damaged by spray prior to being damaged by submergence, which could change the timing associated with equipment failures in scenario development.

The R.G. 1.200 qualification for this SR requires that a qualitative assessment of pipe whip, jet impingement, humidity, condensation and temperature concerns in the flooding analysis. The current flooding documentation does not provide this assessment.

Enclosure 5: PRA Quality Report, Page 17

Table A5-6: 2010 Peer Review F&Os (Findinas only included)

Peer F&O Applicable Review FindingDG AOT Impact Number SR Capability Finding Category Section F.1.3 of RSC10-05 states that flows through drains were considered, but there is no discussion concerning drain Cat 1 met paths as a possible propagation path between rooms in the Cat 2 not Auxiliary Building basement nor the basis for not considering The flooding findings have been resolved by improved 1-26 IFSN-A8 met such paths. Discussion of drain paths not included, documentation and PRA model analysis. Flooding events Cat 3 not Propagation through wall penetrations, cable trays, and do not have a significant impact on this application.

assessed HVAC ducts do not appear to be considered. As only propagation through doors, stairwells, and gratings are considered, the requirements for Cat II are not met.

While multi-unit flooding was considered, all scenarios were screened out on the basis of physical barriers that are assumed to prevent flood propagation between units.

However, the turbine building has complete communication Cat 1-3 not between unit 1 and unit 2. Therefore, water can spread from The flooding findings have been resolved by improved 1-27 IFSN-A1 1 met one unit to the other and vice versa. The flood scenario is documentation and PRA model analysis. Flooding events described more detail in Section F.2.1.2 of the notebook. In do not have a significant impact on this application.

addition, turbine building roll-up doors on elevation 20' do not appear to have been considered as a propagation path between units. So, it appears that the screening of all inter-unit turbine building floods may not be correct.

Brunswick Flooding PRA credits operation of drains for mitigating flooding events. Per EPRI TR-1019194, there is wide variability in modeling on this issue, with widespread Cat 1-3 not industry practice of not crediting the functioning of drains due Resolved in BNP 2011 MODEL, drains are not credited 6-18 IFSN-A13 met to the high probability of sump pump failures and clogging of for mitigation paths.

drains. There is no discussion in RSC 10-05 concerning the reliability of the drains as a mitigating system for flooding. As there is not a definitive basis for crediting the drains, this SR is considered not met.

Cat 1 not Flood sources were screened if more than 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is required to reach a one foot depth in an area. However, there is no The flooding findings have been resolved by improved 1-28 IFSN-A16 Cat 2-3 not discussion of whether indication is available to identify the documentation and PRA model analysis. Flooding events 2-3enotdflood or if isolation can be performed given the flooding is do not have a significant impact on this application.

occurring.

While RSC 10-05 provides some of the documentation of the scenario development process, it is not believed to be The flooding findings have been resolved by improved 1-31 IFSN-B1 met adequate to support future PRA maintenance and documentation and PRA model analysis. Flooding events applications. Discussion of propagation pathways could have do not have a significant impact on this application.

been at a greater level of detail. (Also see IFSN-B2.)

Enclosure 5: PRA Quality Report, Page 18

Table A5-6: 2010 Peer Review F&Os (Findinas only included'/

Peer F&O Applicable Review Finding DG AOT Impact Number SR Capability Category As noted in IFSN-B1, the flood scenario development documentation does not provide all of the information needed to fully describe the scenario development process. In 1-31 IFSN-B2 Cat 1-3 not addition to other items noted in the IFSN-A SRs, items The flooding findings have been resolved by improved met (c),(d),(e), and (f) need to be included as part of the documentation and PRA model analysis. Flooding events documentation. Also, a listing of the specific components do not have a significant impact on this application.

assumed to be failed in each flood area needs to be provided.

An older EPRI pipe break method based upon piping segments is used. This methodology had been the subject of previous F&O IF-D5a-1. The latest EPRI methodology is based upon piping length, and differentiates between whether the Service Water is sea water, lake water, or river water. The Brunswick Service Water System is considered a salt water system and thus would be in the category with the highest failure frequencies. Note, using as an example 6' Service Water piping, the segment-based methodology (Section F.8.1) corresponds to a frequency of 5.8E-06/year, which The flooding findings have been resolved by improved 1-27 IFEV-A4 Cat 1-3 not would correspond to about 2 1/2 feet of piping based on the documentation and PRA model analysis. Flooding events met 'spray' failure frequency (100 gpm or less) of sea water docntave a nt impanathisalicain.

service water pipe per EPRI TR-1013141. (It is noted these do not have a significant impact on this application.

are not a direct comparison and this probably underestimates the pipe length corresponding to one section) Thus, use of the segment-based approach is questioned since it results in underestimating the pipe failure frequency, particularly for the Service Water system which is an important contributor to Internal Flooding scenarios. It is recommended, as it was by the previous F&O, that the pipe failure frequency methodology be updated. A sampling of frequency calculations were reviewed which concludes that the flood IE frequencies were calculated as described.

Enclosure 5: PRA Quality Report, Page 19

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review DG AOT Impact Number SR Capability Finding Category Basis: An older EPRI pipe break method based upon piping segments is used. This methodology had been the subject of previous F&O IF-D5a-1. The latest EPRI methodology is based upon piping length, and differentiates between whether the Service Water is sea water, lake water, or river water. The Brunswick Service Water System is considered a salt water system and thus would be in the category with the highest failure frequencies. Note, using as an example 6' Service Water piping, the segment-based methodology (Section F.8.1) corresponds to a frequency of 5.8E-06/year, 6-15 IFEV-A Cat 1-3 not which would correspond to about 2 1/2 feet of piping based Resolved in BNP 2011 MODEL, the pipe break frequency met on the 'spray' failure frequency (100 gpm or less) of sea methodology has been updated.

water service water pipe per EPRI TR-1013141. (It is noted these are not a direct comparison and this probably underestimates the pipe length corresponding to one section)

Thus, use of the segment-based approach is questioned since it results in underestimating the pipe failure frequency, particularly for the Service Water system which is an important contributor to Internal Flooding scenarios. It is recommended, as it was by the previous F&O, that the pipe failure frequency methodology be updated. A sampling of frequency calculations were reviewed which concludes that the flood IE frequencies were calculated as described.

RS 10-03, Section F.5.1 and F.5., discuss the use of plant specific piping configuration and walk downs to determine Cat 1 met flood initiating event frequency. Additionally, generic failure Resolved in BNP 2011 MODEL, plant specific nature of 3-14 IFEV-A6 Cat 2-3 not rates were used for pipe break frequency. It did not appear potential plant systems impacts on flooding frequency met that plant-specific information was gathered with respect to evaluated.

the flood LIKELIHOOD. Specifically, there was no operating experience related to water hammer or material condition of fluid systems at Brunswick.

The review of the flooding-induced initiating events was not The flooding findings have been resolved by improved 1-31 IFEV-B1 met conducive to a peer review as the raw data used in the flood documentation and PRA model analysis. Flooding events database was not available for review, do not have a significant impact on this application.

1-31CaFE1-B2n Cat 1-3 not The flooding documentation was not clear in identifying the HE The flooding findings have been resolved by improved 1-31 IFEV-B2 met HEPs that potentially mitigate floods. Operating experience is documentation and PRA model analysis. Flooding events not documented. do not have a significant impact on this application.

Enclosure 5: PRA Quality Report, Page 20

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review Finding DG AOT Impact Number SR Capability Category There is no evidence of documentation of review or modification of accident sequences. Discussions with the PRA Staff state that IF IEs are evaluated using the Transient ET. Specific flood impacted equipment is taken out of service in conjunction with the specific flooding IE. All sequences were added to the general transient event sequence. No new event trees were generated. The quantification section of the flooding report does not discuss how it was determined that there were no special flooding sequences that warranted special handling. The Flooding Analysis document RSC 10-2-9 IFQU-A1 Cat2-9 1-3 et not FQUA1 05 does not provideailresdueto ystm/coponnt information concerning modeling hatdocumentation ppe ailresin of The flooding findings have and PRA been model resolved analysis. by improved Flooding events met system/component failures due to pipe failures in that do not have a significant impact on this application.

system, as opposed to failure due to flooding and flood propagation. Detailed discussions were necessary to establish the logic by which, for example, Fire Protection Water and Service Water systems can still be credited for injection to the vessel after piping failures in the respective systems. Sequence modifications are not documented. Some fire protection and service water pipe breaks will fail the system as a LPI source by failing the injection path, including consideration of flow diversion effects; this may not be fully accounted for.

Documentation of SR IFQU-A2 does not provide a link between the flooding IE and the equipment failed for that specific flooding initiator. By inspection of the model, Cat 1-3 not equipment and system fault trees have been modified to Resolved in BNP 2011 MODEL, maps provided for flood 1-32 IFQU-A2 met include or events flood-induced failures. isNoincluded documentation of the initiating events, components to flood zones, and flood systems impacted in the flooding propagation.

analysis (maintained as a separate spreadsheet, see IFQU-81). Thus, it is not possible to fully verify if the modifications were done correctly.

Enclosure 5: PRA Quality Report, Page 21

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review Finding DG AOT Impact Number SR Capability Category The analyses of all HRA are documented in the HRA Calculator and were not readily available for review. Based on the time available for HRA Calculator review, the following issues and comments are provided. This should not be considered an all inclusive list given the time restraints on the review. While the HRA analyses did include many important factors used to determine a human error probabilities (HEPs) associated with isolating flood events, the following issues were judged to potentially impact the calculated HEPs:

- The methodology used for calculating the HEPs for the flooding termination was the annunciator response methodology. There was no discussion in the flooding documentation regarding the use of, or acceptability of the use of, this methodology.

Flooding HRA documentation should be enhanced to include a discussion of the methodology, and the justification thereof, for calculating HEPs.

The use of the annunciator response methodology did not Resolved in BNP 2011 MODEL, the flooding HRAs now Cat 1-3 not 2-10 IFQU-A5 appear to account for all expected annunciators. For use a CBDTM method, alarms implemented, operator met example, for large turbine building floods, it does not appear discussion implemented and documented.

reasonable that only one annunciator would be received.

Under the large turbine building flood conditions, it would be expected that the loss of circulating water pumps and the plant transient would cause multiple alarms. Therefore, this HEP could be significantly under-estimated as the annunciator response methodology modeling only assumed that one alarm would be received.

- Since the detection and diagnosis of a flooding situation is critical to flood mitigate, a detailed discussion of the detection systems and alarms available for diagnosis is necessary to ensure a realistic HRA. Neither the flooding documentation, nor the HRA calculator files, contains a complete description of the cues available to the operator for flood detection.

Therefore, the accuracy of the HEP for flood termination is questionable.

Enclosure 5: PRA Quality Report, Page 22

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review Finding DG AOT Impact Number SR Capability Category

- It does not appear that operator interviews or walk-throughs were used to determine the flooding HEPs. Interviews with operators and their response to various alarms would provide invaluable insights into the flood response and would provide for a more realistic approach.

- It is not clear that the "time available" value used in the HEP was appropriate for some scenarios. The time available used was the time to which the flood would reach the height of critical equipment. However, the time of the flood to reach the flood isolation valves, in some scenarios, may be time Resolved in BNP 2011 MODEL, the flooding HRAs now 2-10 Cat 1-3 not limiting. Additionally, the impact on timing if damage is due to use a CBDTM method, alarms implemented, operator (Cont.) IFQU-A5 met spray, vice submergence, must be considered. The analysis discussion implemented and documented.

should be more specific regarding which valves need to be isolation, their locations, and the ability to isolate before the flood scenarios cause them to be un-isolable., vice submergence, must be considered. The analysis should be more specific regarding which valves need to be isolation, their locations, and the ability to isolate before the flood scenarios cause them to be un-isolable.

No consideration is documented for the impact of flooding on operator actions modeled in the HRA which require operator actions in areas subject to flooding. There is no discussion in Cat 1-3tnot the 6-13 IFQU-A6 thusdocumentation no discussion of how the flood would be discovered and of the time it would take plant personnel to flooding on internal with credited operatorevents, actions,flooding alarms and affects associated of the flood on met start to respond. There is no documentation or discussion of with ediperto this in Section F.11. No discussion of whether or not the mitigation equipment.

mitigating equipment listed in table F.20 would be affected by the flood itself.

1-33 IFQU-9 Cat 1-3 not Direct effects were included. The only indirect effect included Resolved in BNP 2011 MODEL, discusses impacts of met was submergence. spray and effects of high energy line break.

Cat 1-3 not There is no evidence that this requirement was addressed. Resolved in BNP 2011 MODEL, the impacts of internal 6-14 IFQU-A10 met The flooding analysis did not appear to analyze any impact flooding on LERF were evaluated using cutset reviews.

met_ on the LERF model due to the flooding initiators.

Enclosure 5: PRA Quality Report, Page 23

Table A5-6: 2010 Peer Review F&Os (Findings only included)

Peer F&O Applicable Review Finding DG AOT Impact Number SR Capability Category The methods of incorporating the flooding results into the 6-17 Cat 1-3 not model are not discussed in the flooding documentation. Due The flooding findings have been resolved by improved 6-21 IFQU-B1 met to weak level of detail and missing information documentation documentation and PRA model analysis. Flooding events 1-31 does not facilitate peer review, PRA maintenance and do not have a significant impact on this application.

upgrades, or application support.

The report RSC 10-05 does not contain the information that lists what equipment is damaged for each pipe failure 6-20 scenario, thus there is no documentation available for review Resolved in BNP 2011 MODEL, maps provided for flood 1-31 IFQU-B2 Cat 1-3 met for this aspect of defining the plant equipment subject to initiating events, components to flood zones, and flood damage from each flooding initiator. This information may be propagation.

contained in the database used in performing the flooding analysis, but it could not be confirmed.

Enclosure 5: PRA Quality Report, Page 24

5.10. BNP Self Assessment PRA Capability Categories The 2010 Peer Review included internal flooding as part of the Peer Review evaluation discussed above. The High Winds and Fire PRA have had a self assessment performed against the PRA standards to identify any gaps. These gap SRs identified in the self assessments for high winds and fire that did not meet capability category II are listed in Tables A5-7 and A5-8 below. Additionally, external flooding was evaluated and determined to have low significance due to similarities to a loss of offsite power event as well as the fact it is a low frequency event as it could only occur during hurricane season. Note that documents cited in Tables A5-7 and A5-8 are primarily BNP PRA calculations that document the development of the current model but do not impact this submittal beyond the information already presented in the submittal report and documentation. As such these documents are not referenced or included as a part of this submittal.

5.11. BNP High Wind External Events PRA Capability Categories The Self Assessment Review of the BNP PRA was performed to evaluate the High Wind and Fire portions of the PRA. The review identified 9 SR's for High Winds that did not meet capability category II. All other SR's met or exceeded capability category II.

The 9 SR's identified are listed in Table A5-7 below and cite the applicable SR, the finding, and a description of the impact to the DG AOT application.

Table A5-7: Self Assessment Review of High Winds Applicable Finding DG AOT Impact

-SR_____________ _

Sources of model uncertainty and related Improvement in documentation is needed WHA-B33 assumptions are scattered in the documentation as does the listing of sources of and not summarized in one location in the assumptions and uncertainty. Does not documentation. affect the application.

Sources of model uncertainty and related Improvement in documentation is needed WFR-B3 assumptions are scattered in the documentation as does the listing of sources of and not summarized in one location in the assumptions and uncertainty. Does not documentation. affect the application.

(a) Initiating events developed (documented in Attachment 3 of BNP-PSA-088).

(b) No new accident sequence analysis performed.

(c) No new success criteria developed. This is a documentation issue and does (d) No new systems analysis developed, not impact the application. The WPR-A4 (e) No new equipment failure/unavailability events documentation lacks discussion of these added to the adde model.

mdel.attributes to he and how the high wind model (f) Human Reliability events altered in the model to atrutedh account for changed performance shaping factors.

(g) No expert judgment used.

Need to expand the discussion of these aspects.

Enclosure 5: PRA Quality Report, Page 25

Table A5-7: Self Assessment Review of High Winds Applicable Finding DG AOT Impact SR Section 3.3.3 of attachment 3 of BNP-PSA-088 describes the methodology used to adjust HRA events for the performance shaping factors of a Documentation of HRA analysis needs to WPR-A5 high wind event. be improved. Does not affect the application.

Need better description of what was done and why only some of the HRAs were adjusted.

Documentation of HRA analysis needs to WPR-A1 Need more (detailed) discussion of human action be improved. Does not affect the 0viability following an event, application.

Need documentation (and review) of evaluation of Documentation of HRA analysis needs to WPR-A1 1 be improved. Does not affect the post high wind event system recovery viability, application.

The current splitting of the initiator frequency does Documentation of HRA analysis needs to not allow for effective accounting of uncertainties.,

WPR-B2 Assumptions on the fragilities also do not lend be improved. Does not affect the themselves to effective accounting of uncertainties, application.

(a) The adaptation of the internal events model and the motivation are described in the documentation. Based upon review of FSAR the EDG (b) The model is not sufficiently refined to produce exhaust lines are capable of withstanding WPR-C2 reasonable results. wind loading and are designed to not result in loss of EDG function. The DG exhaust vent wind fragilities need additional masking effect is removed.

analysis - they currently appear to mask other risk information Improvement in documentation is needed WPR-C3 Sources of uncertainty and assumptions are as does the listing of sources of currently not easily identified. assumptions and uncertainty. Does not affect the application.

5.12. BNP Fire External Events PRA Capability Categories The BNP Fire model was developed using the guidance provided in NUREG/CR-6850 and incorporates the risk due to fire sources. An internal review process was held to compare and contrast the BNP Fire work against the ASME/ANS RA-S-2008 standard (incorporating the ASME/ANS RA-Sa-2009 addenda). Since the initial modeling is ongoing, the findings that are presented are preliminary and may incorporate anticipated findings for the BNP Fire PRA based on similar Fire PRAs that have been reviewed for other sites. The preliminary findings of the Self Assessment are presented in this document. The review identified SR's for Fire that did not meet capability category II or were addressed with a Finding. All other SR's evaluated met or exceeded capability category II. The SR's identified are listed in Table A5-8 below and cite the applicable SR, the finding, and a description of the impact to the DG Extended AOT application. A Peer Review of the BNP PRA which will include evaluation of the Fire portion of the model has been scheduled.

Enclosure 5: PRA Quality Report, Page 26

Table A5-8: Self Assessment Review of Fire Applicable SR Finding DG AOT Impact Overcurrent coordination and protection has been reviewed in Change Package BNP-0157. Circuit coordination was addressed The change package documents cables under BNP-0157. However, the credited for overcurrent protective device circuit coordination needs to be CS-B1 coordination whose failure could challenge updat andian needsnto be power supply availability. Analysis of the will be addresses such that the PRA identified cables in BNP-0157 to determine the results are not impacted.

susceptibility to failure of coordination has not been performed and is not incorporated into the FPRA documentation.

Need further analysis of CDF contributors of concern including accident sequences, Primarily a documentation issue equipment failures, and operator errors for the seeking more insight into the model.

Fire PRA model.

Document non-applicability of requirements in Documentation, where statement of PRM-B4 Section 2 of the PRA standard for those IE no-applicability is weak or not made.

requirements that do not apply no-applcabiliyiswekorntmade Document changes to PRM consistent with System Notebooks have not been PRM-B9 requirements in Section 2 of the PRA standard. updated to reflect changes in Fire PRA PRM.

The incorporation of instrumentation for No impact on results, as common Containment Isolation signal to replace the cause failures of these instruments point estimate in the Level 2 model did not in a very low probability event, and PRMB312 include the modeling of common cause failure most likely below the level of or related unavailability due to truncation. Removal of an test/maintenance, instrument string from service during maintenance and testing is also a negligible impact on results.

Documentation only, no new Documentation of non applicability was not components were added which were PRM-B13 found for components added to PRA to support not already with the PRA data Fire PRA PRM. analysis.

The screening value applied to MCR abandonment scenarios for abandonment No impact would be expected. The success is not a developed HEP. SR Supp-DG is connected via outside FSS-B32 requirements for CAT I includes a bounding control room action, and breaker estimate of MCR abandonment risk. SR for manipulation would also be CAT II needs realistic characterization, which governed by AO action outside cannot be justified with an undeveloped control room.

screening value.

This is conservative and provides a Damage to all targets within the ignition source slight increase in CDF, due to the ZOI is assumed at time zero. A time dependent non-credited 5 minutes (to first tray FSS-C2 fire growth/decay profile is used out of damage) that could allow NUREG/CR-6850 for determination of fire suppression to prevent cable tray propagation and HGL capability, damage. Impact would be very target specific on cable tray and source interaction.

Detection and suppression use generic Data is not available and it is estimates of system unavailability based on expected the BNP is with the generic NURE/CR-6850. A review of system estimate, No impact on EDG AOT unavailability data is not performed to delta CDF is expected Enclosure 5: PRA Quality Report, Page 27

Table A5-8: Self Assessment Review of Fire Applicable SR Finding DG AOT Impact determine if the system has experienced any outlier behavior relative to the generic data.

Failing all control cabinets in the fire location would be overly conservative since most cabinets would not experience smoke No evaluation has been performed to determine damage the area was full of untilpast smoke and the point where FSS-D9 the effect of smoke on FPRA equipment or qualify its significance. applicable cable would be postulated to be damaged. Thus the equipment that is potentially effected by smoke will also be generally lost due to cable damage and so no impact on EDG AOT is expected.

Probability of fire spread to adjacent Random failure is considered a very compartments is calculated based on rated and low probability particularly beyond non-rated barriers between compartments. low ba bility p lant. be ver, FSS-G4 Rated fire barriers are confirmed and evaluated during Hot Gas Layer scenarios, the with a screening value for failure which bounds barrier is given a 0.1 or 0.2 estimate availability, reliability, and effectiveness data. for failure to include random effects.

No evaluation of random failure is performed.

Target damage thresholds are Target damage thresholds are developed in based upon NUREG/CR 6850 for FSS-H2 NUREG/CR-6850 and damage mechanisms IEEE 383 qualified Thermoset are mainly described in the Hughes Report. cables, vice any plant specific testing. No impact or change in CDF/LERF would be expected.

No effect in EDG AOT analysis. This is a question about "all". A large number of CF failures were Circuit probability analysis is not performed for performed and if the CDF value CF-Al al r s all risk significant ccontributors, would decrease significantly additional CF would have been analyzed. Important EDG fire failures have been specifically included.

The HEP uncertainties estimates were not HRA-Cl documented consistent with the quantification Documentation of uncertainty only approach No effect on CDF or LERF. The The BNP Fire PRA uses plant trip/ Loss of BNP model is constructed such that Feed Water or loss of off-site power as the the actual initiating transient does initiator. No other PRM initiators were used not change the results as long as the beyond those. correct fire damage effects are included.

The CDF is a mean estimate with no correlation The use of FRANC does not allow for the state of knowledge. this correlation to be performed. No direct impact on CDF or LERF FQ-A4 results. The state of knowledge correlation does not allow evaluating the large and important uncertainties for issues such as HRR and fire Igrowth.

Enclosure 5: PRA Quality Report, Page 28

Table A5-8: Self Assessment Review of Fire Applicable SR Finding DG AOT Impact No documentation of comparison to other Documentation only, no impact on plants has been made. There has been some results comparison but the results are generally much higher CDF and of little value.

Determine LERF for Fire PRA response model: LERF results are not the driver for FQ-D1 This was performed; however the results are the acceptance of the EDG CT and higher than expected. thus no impact on application.

The assumptions and uncertainties are identified and the sources of uncertainty and whether the affect on the model is expected to No impact on CDF or LERF results be conservative. as the HRR, fire growth and fire cabinet response are the largest However, there was no estimate of the cainties. The unert est UNC-Al uncertainty interval of the CDF and LERF Bere-intias he postaintiato results. Also, there was no estimate of BE, pre-initiators HEPs, post initiator uncertainty intervals associated with significant HEPs and initiating events are small basic events, pre-initiators HEPs, post-initiator compared to the impact of the HRR HEPs and initiating events which would take etc.

into account the state-of-knowledge correlation.

The BNP Fire PRA documentation describes the sources of uncertainty. No impact on CDF or LERF results However, there is no discussion of the as the HRR, fire growth and fire uncertainty distribution of total CDF, uncertainty cabinet response are the largest uncertainties. The uncertainties with UNC-A2 analysis for LERF, and no sensitivity analysis. BE pre-initiators HEPs, post initiator Also, the results provided for significant fire BE, pre-initiators e vs as small scenarios only include mean CDF and no HEPs and initiating events as small statistical representation of the associated compared to the impact of the HRR uncertainty interval. etc.

Enclosure 5: PRA Quality Report, Page 29

5.13. BNP External Events PRA for Nearby Facility Accidents In order to account for human errors outside the normal operation of BNP, the IPEEE identified the hazards below for analysis. The threats listed were analyzed and determined to be dominated by fire and high winds events that have been previously discussed, therefore eliminating the need for further investigation at this point. A summary of the reviews performed for each hazard is provided for completeness.

5.13.1. Aircraft Impact When the IPEEE was performed available information regarding military, commercial, and general aviation traffic was used to estimate a core damage frequency due to aircraft impact. Given the information available at the time of the analysis, the increase in CDF was determined to be less than 1E-6/yr. Therefore further analysis was not considered to be warranted.

Progress Energy recognizes that the credible threat to nuclear facilities by aircraft has changed since the IPEEE was published and is following industry efforts to address this issue in conjunction with other forms of sabotage. Yet at this point in time, the impact of such analysis is not within the scope of this application.

5.13.2. Industrial Accidents The BNP IPEEE reviewed industries close to the site to determine if any of the facilities posed a hazard to the safe operation of the plant. The following facilities were identified as potential hazards:

" Archer Daniels Midland (ADM) Company

" A natural gas pipeline

" Cogentrix Southport Cogeneration Plant Further investigation revealed that ADM only produces citric acid and has no known explosive materials on-site. Any threat posed by ADM is considered to be bounded by Military Ocean Terminal Sunny Point (included in Military Accidents).

The natural gas pipeline is addressed in the Pipeline Accidents subsection below.

Southport Cogeneration Plant, owned and operated by Cogentrix Energy, Inc., is a coal-fired power plant that provides steam to ADM and electric power to Progress Energy.

The worst postulated accident at the Cogentrix facility is a turbine missile ejection or a high-energy steam line break. However, similar hazards are considered to be design base accidents at BNP itself and are addressed in the plant's PRA. Therefore, given the space between the sites and smaller size of the Cogentrix facilities, further review of Southport Cogeneration Plant initiators is not warranted.

The assumptions and analysis originally put forth in the IPEEE is still considered to be valid. Therefore the operation of nearby facilities results in no credible risk to the safe operation of BNP.

Enclosure 5: PRA Quality Report, Page 30

5.13.3. Military Accidents Military Ocean Terminal Sunny Point's cargo load was analyzed for the BNP IPEEE.

The largest explosives concentration at the site was identified as two fully loaded barges equivalent to 19.2 million pounds of TNT. The blast pressure experienced at BNP resulting from the detonation of this explosive source was determined to be 0.5 psi overpressure and 1 psi reflected overpressure. This pressure load is less than the tornado loads that were used for design basis at BNP. Therefore postulated military accidents result in no credible risk to the safe operation of BNP.

5.13.4. Pipeline Accidents A 12-inch natural gas pipeline runs immediately beyond the 3000 foot BNP exclusion zone. The impact on the BNP site due to the worst case failure of the pipeline, assumed to be a guillotine rupture, was examined. The resulting radiant heat experienced at the nearest safety structure due to a potential fire would be less than that received by a flat surface from the sun. Control room habitability analysis revealed that for a postulated un-ignited gas leak the control room ventilation system would continue to meet the requirements set forth in Regulatory Guide 1.78. Therefore postulated pipeline accidents result in no credible risk to the safe operation of BNP.

5.13.5. Hydrogen Storage Failures Detonation of the BNP hydrogen storage tanks was investigated to determine the impact of such an explosion. Industry guidance specifies the minimum separation distance between plant structures and hydrogen storage units to be 200 feet. Due to the fact that this distance is less than the distance between the hydrogen tanks and buildings containing safe shutdown equipment, no credible threat was determined to exist based on hydrogen detonation.

5.13.6. Transportation Accidents Transportation accidents were assessed to include accidents on the roadways around the plant (river traffic was addressed in "Military Accidents"). The highest concentration of explosives on Highway 87, one mile from the plant, was determined to be 50,000 pounds of TNT. The impact on the plant from an explosive load from this source was bounded by the worst case explosion at Military Ocean Terminal Sunny Point. All chemical and hazardous materials accidents that could occur on the highway were also considered to be bounded by the worst case explosion at Military Ocean Terminal Sunny Point. Therefore postulated transportation accidents result in no credible risk to the safe operation of BNP.

5.14. References References listed in Enclosure 4, section 4.11 of this submittal.

Enclosure 5: PRA Quality Report, Page 31

BSEP 11-0097 Enclosure 6 DIESEL GENERATOR COMPLETION TIME EXTENSION PRA QUANTIFICATION TABLES PRA QUANTIFICATION TABLES

PRA Quantification Data Tables Table A6-1: Unit 1 Top 25 Cutsets for the IE w/internal Flooding Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 5.90E-02 EDG1 DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 2 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 5.90E-02 EDG1 DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 3 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 4 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN Enclosure 6: PRA Quantification Data Tables, Page 1

Table A6-1: Unit 1 Top 25 Cutsets for the IE w/internal Flooding Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 11.00E+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 5 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 6 3.35E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 7 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-DOO1 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power Enclosure 6: PRA Quantification Data Tables, Page 2

Table A6-1: Unit 1 Top 25 Cutsets for the IE w/internal Flooding Models Cutset Cutset Cutset outset Basic Event basicvt Basic Event Name Basic Event Description Number Probability Probability 9.62E-01 X-AC-CO1S WC 11.00E-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 8 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.OOE+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM3-08 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL 9 2.71 E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.00E+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1 S WC Offsite Power Recovery 11.00E-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 10 2.71 E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.00E+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.00E+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION Enclosure 6: PRA Quantification Data Tables, Page 3

Table A6-1: Unit 1 Top 25 Cutsets for the IE w/internal Floodina Models Cutset Outset Cutset outset Basic basitEvent Basic Event Name Basic Event Description Number Probability Probability ___ ______________

9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-C01S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 11 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 12 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.00E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 13 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.00E+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power Enclosure 6: PRA Quantification Data Tables, Page 4

Table A6-1: Unit 1 Top 25 Cutsets for the IE w/internal Floodina Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability- Probability 7.06E-01 X-AC-C01U1 WC 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT120V+OPER-N2SUPPLY 14 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 11.00E+00 FL-NSBO NO STATION BLACKOUT FLAG 1.00E+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 11.00E+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.00E+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-C01U1 WC Offsite Power Recovery 1.00E-06 XOP-COM3-08 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL 15 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.00E+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 11.00E+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 11.00E+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-C01U1 WC Offsite Power Recovery 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 16 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 11.00E+00 FL-NSBO NO STATION BLACKOUT FLAG 1.00E+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.00E+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION Enclosure 6: PRA Quantification Data Tables, Page 5

Table A6-11: Unit 1 Top 25 Cutsets for the IE w/internal Flooding Models Cutset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-CO1U1 WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 17 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-CO1U1 WC Offsite Power Recovery 11.00E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 18 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDGIDGN-EXTTM-DOO1 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG4 Failure to restore EDG #4 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 19 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG3 Failure to restore EDG #3 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power I 9.62E-01 X-AC-CO1S WC Offsite Power Recovery I 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 20 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

Enclosure 6: PRA Quantification Data Tables, Page 6

Table A6-1: Unit 1 Top 25 Cutsets for the IE w/internal Flooding Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability BasicEventNameBasicEventDescription 8.OOE-03 EDGlXHE-MN-DG1 Failure to restore EDG #1 or subsystem following test or maintenance 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 21 2.06E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 8.OOE-03 EDGlXHE-MN-DG2 Failure to restore EDG #2 or subsystem following test or maintenance 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.00E+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-C01S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 22 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG4 Failure to restore EDG #4 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-C01S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 23 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG3 Failure to restore EDG #3 or subsystem following test or maintenance 1.00E+00 FL-NSBO NO STATION BLACKOUT FLAG 1.00E+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-C01S WC Offsite Power Recovery Enclosure 6: PRA Quantification Data Tables, Page 7

Table A6-1 Unit 1 Ton 25 Cutsete for the IE w/internal Floodino Mnrdel*

CTabet OutsetA61:Utset 1 Cutset 2 Bautesi Event Basic fovtent /nenlFl oMdl Basic Event Name Basic Event Description Number Probability Probability 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 24 1.97E-10 2.92E-04 %1T DClB LOSS OF DC SWITCHBOARD 1B 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-DCPALTDCl FAILURE TO ALIGN DC BUS TO STANDBY DC POWER SUPPLY - UNIT 1 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.90E-05 XOP-COM3-16 OPER-4160X+OPER-DCPALTDC1 +OPER-SWRHR-C 25 1.84E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT I (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 7.15E-03 EDG2DGN-TM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1SWC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART Table A6-2 Unit 2 Top 25 Cutsets for the IE w/internal Flooding Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN I 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 2 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D001 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG I 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT Enclosure 6: PRA Quantification Data Tables, Page 8

Table A6-2 Unit 2 Top 25 Cutsets for the IE w/internal Flooding Models Cutset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT-1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 3 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 1.00E+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 4 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART S 3.36E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 5.90E-02 EDGlDGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 6 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

Enclosure 6: PRA Quantification Data Tables, Page 9

Table A6-2 Unit 2 Too 25 Cutsets for the IE w/internal Floodina Models Table A6-. Unit...............

.... . ..................... lood n M odels..

Cutset Outset Cutset outs Basic basitEvent Basic Event Name Basic Event Description Number Probability Probability 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 7 2.77E-10 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 11.00E+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 8 2.77E-10 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.00E+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 9 2.77E-10 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT Enclosure 6: PRA Quantification Data Tables, Page 10

Table A6-2 Unit 2 Top 25 Cutsets for the IE w/internal Flooding Models Cutset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 10 2.77E-1 0 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 11 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY I.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 12 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.00E+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR Enclosure 6: PRA Quantification Data Tables, Page 11

T~hIA AR-2 Unit~ Thn ~'5 C~ijt~k fnr th~ IF w/int~rn~I FIr~nc1ino Mnc1~k CTabetA62Utset2 2 Bautesi fovtent /nenlFlooMdl Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-COIS WC Offsite Power Recovery 11.00E-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 13 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 11.00E-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 14 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG I.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.00E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 15 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY Enclosure 6: PRA Quantification Data Tables, Page 12

Table A6-2 Unit 2 Top 25 Cutsets for the IE w/internal Flooding Models Cutset Outset Cutset outset Basic basitEvent Basic Event Name Basic Event Description Number Probability Probability __________________________________________

1.00E+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 16 2.08E-10 5.85E-03 %2TE U2 PC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.00E+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 11.00E+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 17 2.08E-10 5.85E-03 %2TE U2 PC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 11.00E+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 18 2.08E-10 5.85E-03 %2TE U2 PC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE Enclosure 6: PRA Quantification Data Tables, Page 13

ThbIe AS-2 Unit 2 Too 25 Cijt~t~ for th~ IF w/intp.rn~I Floodino MocI~k Cutset Outset Cutset outset Basic Event basicvt Basic Event Name Basic Event Description Number Probability Probability __________________________________________

1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 19 2.08E-10 5.85E-03 %2TE U2 PC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 20 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDGlXHE-MN-DG2 Failure to restore EDG #2 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 21 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG4 Failure to restore EDG #4 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery I 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 22 2.06E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDGlXHE-MN-DG1 Failure to restore EDG #1 or subsystem following test or maintenance Enclosure 6: PRA Quantification Data Tables, Page 14

Table A6-2 Unit 2 Top 25 Cutsets for the IE w/internal Flooding Models Cutset Nutset Cutset outs Basic basitEvent Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 23 2.06E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG3 Failure to restore EDG #3 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 24 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 8.OOE-03 EDGlXHE-MN-DG1 Failure to restore EDG #1 or subsystem following test or maintenance 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 25 2.06E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 8.OOE-03 EDGlXHE-MN-DG2 Failure to restore EDG #2 or subsystem following test or maintenance 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-416OX FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART Enclosure 6: PRA Quantification Data Tables, Page 15

Table A6-3 Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1 3.66E-10 5.OOE-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 3.50E-03 RHR1PTF-TM-LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 9.24E-01 X-POWEROP1 Fraction of annual year at power 2 3.66E-1 0 5.OOE-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 3.50E-03 RHR1PTF-TM-LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 9.24E-01 X-POWEROP1 Fraction of annual year at power 3 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 4 3.36E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.O0E+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.O0E+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 Enclosure 6: PRA Quantification Data Tables, Page 16

Table A6-3 Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 5 3.36E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 5.90E-02 EDG1DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 6 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 7 3.36E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 8 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT I 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR Enclosure 6: PRA Quantification Data Tables, Page 17

Table A6-3 Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 9 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-DOO1 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.O0E-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 10 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.OOE+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.O0E-06 XOP-COM3-08 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL 11 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION IIISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR Enclosure 6: PRA Quantification Data Tables, Page 18

Table A6-3 Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding Models Outset Number Outset Basic Event Prbbet Babit Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1SWC Offsite Power Recovery 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 12 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 13 2.72E-10 7.96E-03 %TE_S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 14 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT I 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+OO OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE Enclosure 6: PRA Quantification Data Tables, Page 19

Table A6-3 Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding Models Cutset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.O0E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 15 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-CO1U1 WC Offsite Power Recovery 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 16 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.OOE+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-CO1U1 WC Offsite Power Recovery 1.OOE-06 XOP-COM3-08 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL 17 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION I1ISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR Enclosure 6: PRA Quantification Data Tables, Page 20

Table A6-3 Unit 1 Too 25 Cutsets for the IE w/internal and external Floodina Models CTabetA63UtsetI 2 Bautesi fovtent /nenl n xenlFl aMdl Cutset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-CO1U1 WC Offsite Power Recovery 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 18 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.00E+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-CO1U1 WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 19 2.35E-10 9.38E-03 %1TE Ul WC UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDGI DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 7.06E-01 X-AC-CO1U1 WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 20 2.06E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG4 Failure to restore EDG #4 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power Enclosure 6: PRA Quantification Data Tables, Page 21

Table A6-3 Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.62E-01 X-AC-CO1S WC 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 21 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG3 Failure to restore EDG #3 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 22 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG4 Failure to restore EDG #4 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 23 2.06E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG3 Failure to restore EDG #3 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1SWC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 24 2.06E-10 7.96E-03 %TE SWC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 8.OOE-03 EDGlXHE-MN-DG1 Failure to restore EDG #1 or subsystem following test or maintenance 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT I SUBSTATIONS E5 AND E6 Enclosure 6: PRA Quantification Data Tables, Page 22

Table AA-3 Unit I Ton 2~ Ctikpt~ mr thA IF w/intArn~I ~nd ~xtArn~l Flonrlinn Mnd~k CTabetA63Utset1 2 Ba utesi fovtent /nenl n xenlFl oMdl Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 25 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 8.OOE-03 EDG1XHE-MN-DG2 Failure to restore EDG #2 or subsystem following test or maintenance 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.00E+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART Table A6-4: Unit 2 Top 25 Cutsets for the IE w/internal and external Flooding Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1 3.66E-10 5.O0E-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 5.90E-02 EDG1 DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 3.50E-03 RHR2PTF-TM-LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 9.24E-01 X-POWEROP1 Fraction of annual year at power 2 3.66E-1 0 5.OOE-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 3.50E-03 RHR2PTF-TM-LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 9.24E-01 X-POWEROP1 Fraction of annual year at power 3 3.36E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG Enclosure 6: PRA Quantification Data Tables, Page 23

Table A6-4: Unit 2 Top 25 Cutsets for the IE w/internal and external Flooding Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 4 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 5 3.36E-1 0 7.96E-03 %TESWC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 6 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 7 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

I_5.90E-02 EDG1DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN Enclosure 6: PRA Quantification Data Tables, Page 24

Table A6-4: Unit 2 Top 25 Cutsets for the IE w/internal and external Flooding Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 8 3.36E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 5.90E-02 EDG1 DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 9 2.77E-10 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-416OX FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 10 2.77E-10 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY Enclosure 6: PRA Quantification Data Tables, Page 25

Table A6-4: Unit 2 Top 25 Cutsets for the IE w/internal and external Flooding Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 11 2.77E-1 0 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.00E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 12 2.77E-10 7.80E-03 %2TEU2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 13 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power Enclosure 6: PRA Quantification Data Tables, Page 26

Thhk~ A6-4 Unit 2 Thn 2~ flijt~k fnrth~ IF w/int~rn~I ~nd AytI~rn~I FItndini, Mnr~~k Cutset Outset Cutset outset Basic basit Event Basic Event Name Basic Event Description Number Probability Probability 9.62E-01 X-AC-C01S WC 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 14 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 15 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 16 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION Enclosure 6: PRA Quantification Data Tables, Page 27

Table A6-4: Unit 2 Top 25 Cutsets for the IE w/internal and external Flooding Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 17 2.72E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 18 2.08E-10 5.85E-03 %2TE U2 PC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT120V+OPER-N2SUPPLY 19 2.08E-1 0 5.85E-03 %2TE U2 PC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE Enclosure 6: PRA Quantification Data Tables, Page 28

Table A6-4: Unit 2 Top 25 Cutsets for the IE w/internal and external Flooding Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.00E-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 20 2.08E-1 0 5.85E-03 %2TE U2 PC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.00E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 21 2.08E-1 0 5.85E-03 %2TE U2 PC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 22 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDGlXHE-MN-DG2 Failure to restore EDG #2,or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 23 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG4 Failure to restore EDG #4 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG Enclosure 6: PRA Quantification Data Tables, Page 29

ThhI~ A~-4 Unit 2 Tnn 2~ C~i~tqptq fnr th~ IF w/intprn~I ~nrI AvtPrn~I FInr,,-Iin,-, Mn,-I~k CTabetA64:Utset2 Outset Outset 2 Ba utesi Basic fovtent Event /nenl n xenlFl Basic Event Name nMdl Basic Event Description Number Probability Probability 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 24 2.06E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDGlXHE-MN-DG1 Failure to restore EDG #1 or subsystem following test or maintenance 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 25 2.06E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 8.OOE-03 EDG2XHE-MN-DG3 Failure to restore EDG #3 or subsystem following test or maintenance 1.00E+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART Table A6-5: Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1 3.66E-10 5.O0E-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 3.84E-02 EDGlDGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1O.O00E+00 10 FL-NSBO NO STATION BLACKOUT FLAG 3.50E-03 RHR1 PTF-TM-LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE Enclosure 6: PRA Quantification Data Tables, Page 30

Table A6-5: Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.24E-01 X-POWEROP1 Fraction of annual year at power 2 3.66E-10 5.00E-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 5.90E-02 EDG1 DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.00E+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 3.50E-03 RHR1 PTF-TM-LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 9.24E-01 X-POWEROP1 Fraction of annual year at power 3 3.53E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG1DGN-EXTTM-D001 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 11.00E+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.00E+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-FPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.00E+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.00E+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.00E-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 4 3.53E-1 0 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1 =86-110 MPH) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1 DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.00E+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.00E+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.00E+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 5 3.53E-1 0 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF =86-110 MPH)

Enclosure 6: PRA Quantification Data Tables, Page 31

Table A6-5: Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Cutset Cutset Cutset outset Basic basitEvent Basic Event Name Basic Event Description Number Probability Probability __________________________________________

3.84E-02 EDGI DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1 DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 1.00E+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.00E+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-FPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.00E-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 6 3.53E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-1 10 MPH) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1 DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.0OE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.OOE+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 7 3.35E-1 0 7.96E-03 %TE SWC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 5.90E-02 EDG1DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.0OE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART Enclosure 6: PRA Quantification Data Tables, Page 32

Table A6-5: Unit 1 TOo 25 Cutsets for the IE w/internal and external Floodina and Hiah Winds Models CTabet OutsetA65:Utset I Outset 2 Bautesi Event fovtent /n ladetra lodn n ihWnsMdl Basic Basic Event Name Basic Event Description Number Probability Probability 8 3.35E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-CO5 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 9 3.35E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 10 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 11 3.35E-1 0 7.96E-03 %TES WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-416OX FAILURE TO ALIGN POWER FROM OPPOSITE UNIT Enclosure 6: PRA Quantification Data Tables, Page 33

Table A6-5: Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 12 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 13 3.24E-10 5.43E-02 %HWM 2 HIGH WIND MISSILE INITIATING EVENT (EF1=86-1 10 MPH) 3.84E-02 EDGlDGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-FPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 14 3.24E-10 5.43E-02 %HWM 2 HIGH WIND MISSILE INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.OOE+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO Enclosure 6: PRA Quantification Data Tables, Page 34

Table A6-5: Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Cutset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 15 3.24E-10 5.43E-02 %HWM 2 HIGH WIND MISSILE INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDGI DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1 DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-FPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.00E+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROPI Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 16 3.24E-10 5.43E-02 %HWM 2 HIGH WIND MISSILE INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1 DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.OOE+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 17 2.71 E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D001 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.00E+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 Enclosure 6: PRA Quantification Data Tables, Page 35

ThhIA AA-~ Unit 1 Tnn 2~ Cijt~k fnrth~ IF w/int~rn~I arid ~~t~rn~I FInn,-Iin,-, ~nd I-Iinh Winr1~ Mn*~k CTabetA65:Utset1 Outset 2 Ba utesi fovtent /nenladexenlFodn ndHn sMdl Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 18 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-DFPFUEL FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS 1.OOE+00 OPER-FPXFER FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM3-08 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL 19 2.71E-10 7.96E-03 %TESWC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION IIISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 20 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG Enclosure 6: PRA Quantification Data Tables, Page 36

Table A6-5: Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-416OX FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1SWC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 21 2.71 E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.00E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 22 2.71 E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-C01S WC Offsite Power Recovery 1.00E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 23 2.53E-1 0 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG1DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION Enclosure 6: PRA Quantification Data Tables, Page 37

Table A6-5: Unit 1 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 6.80E-04 XOP-COM2-56WH OPER-4160X-WH+OPER-SWRHR-O 24 2.53E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDGI DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDGI DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 3.00E-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 6.80E-04 XOP-COM2-56WH OPER-4160X-WH+OPER-SWRHR-O 25 2.45E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG1 DGN-EXTTM-DO01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1 DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 6.60E-04 XOP-COM2-57WH OPER-4160X-WH+OPER-SWRHR-C Enclosure 6: PRA Quantification Data Tables, Page 38

Thble AA-6 Unit 2 Too 2~ Cut~p.t~ for th~ IF w/intp.rn~I ~nd ~tArn~l Floodino ~nd Hioh Wiork MorI~I~

Cutset Cutset Cutset Cutt Basic basitEvent Basic Event Name Basic Event Description Number Probability Probability 1 3.66E-10 5.OOE-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 3.50E-03 RHR2PTF-TM-LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 9.24E-01 X-POWEROP1 Fraction of annual year at power 2 3.66E-10 5.OOE-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 3.50E-03 RHR2PTF-TM-LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 9.24E-01 X-POWEROP1 Fraction of annual year at power 3 3.53E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNiT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-FPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 4 3.53E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT Enclosure 6: PRA Quantification Data Tables, Page 39

T~hl~ AA-R Unit 2 Ton 2~ Cist~k for th~ IF w/int~rn~I ~nd ~YtArn~I Floodino ~nd I-Iinh Winc1~ Mod~I~

uTabetA66:Utset2 2 Bautesi fovtent /nenladexenlFodn ndHn sMdl Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-FPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 5 3.35E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 5.90E-02 EDGlDGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 6 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 5.90E-02 EDGI DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 7 3.35E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D001 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 8 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

Enclosure 6: PRA Quantification Data Tables, Page 40

ThbI~ AR-R Unit 2 Tnn 2~ fliit~k f~r th~ IF w/intprn~I ~nd ~~t~rn~I Flnndinn ~nr1 Rinh Winrk Mnd~i~

CTabetA66:Utnet2 2 Bautesi fovtent /nenladetra lod n hWnsMdl Cutset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 3.84E-02 EDG1DGN-EXTTM-DOO1 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG S1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 9 3.35E-10 7.96E-03 %TES WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG1DGN-FR-001 DIESEL GENERATOR 1 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 10 3.35E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDGlDGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 9.24E-01 X-POWEROP1 Fraction of annual year at power 2.12E-01 X-AC-C05 S WC WC SITE LOSP CASE 5 9.50E-05 XOP-COM2-39 OPER-4160X+OPER-SDGSTART 11 3.24E-10 5.43E-02 %HWM 2 HIGH WIND MISSILE INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT Enclosure 6: PRA Quantification Data Tables, Page 41

Table A6-6: Unit 2 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-FPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 12 3.24E-1 0 5.43E-02 %HWM 2 HIGH WIND MISSILE INITIATING EVENT (EF1=86-1 10 MPH) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-FPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.50E-04 XOP-COM2-40WH OPER-4160X-WH+OPER-SDGSTART 13 2.76E-10 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-416OX FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT1 20V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY 14 2.76E-10 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 Enclosure 6: PRA Quantification Data Tables, Page 42

Table A6-6: Unit 2 Too 25 Cutsets for the IE w/internal and exeternal Flondinoa nd Hinh Windk MndAI~q uTabetA66:Utnet2 2 Bautesi fovtent nenladetra lod n hWnsMdl Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION 11ISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 15 2.76E-1 0 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 16 2.76E-1 0 7.80E-03 %2TE U2 SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.00E+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 17 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG1 DGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE Enclosure 6: PRA Quantification Data Tables, Page 43

Table A6-6: Unit 2 Top 25 Cutsets for the IE w/internal and external Flooding and High Winds Models Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability BasicEventNameBasicEventDescription 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 18 2.71 E-1 0 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ALT120V FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-CO1S WC Offsite Power Recovery 1.OOE-06 XOP-COM4-01 OPER-SPCE+OPER-480X+OPER-ALT120V+OPER-N2SUPPLY 19 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-ISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.OOE+00 OPER-N2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-C01S WC Offsite Power Recovery 1.OOE-06 XOP-COM3-12 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY 20 2.71E-10 7.96E-03 %TE S WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE Enclosure 6: PRA Quantification Data Tables, Page 44

ThbI~ A6-A Unit 2 Ton 2~ CLJt~At~ for thA I~ w/intArn~I ~nd AYtAm~I Flooding ~nd High Winds ModAl~

CTabetA66:Utset2 2 Bauesic fovtent /nenladexenlFodn ndHn sMdl Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-C01S WC Offsite Power Recovery 1.OOE-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 21 2.71 E-10 7.96E-03 %TES WC SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.OOE+00 OPER-SPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.24E-01 X-POWEROP1 Fraction of annual year at power 9.62E-01 X-AC-C01S WC Offsite Power Recovery 1.00E-06 XOP-COM2-12 OPER-4160X+OPER-SPCL 22 2.53E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 6.80E-04 XOP-COM2-56WH OPER-4160X-WH+OPER-SWRHR-O 23 2.53E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT Enclosure 6: PRA Quantification Data Tables, Page 45

ThhlA AR-A Unit 2 Tnn 2A flhit~t~ fnr th~ IF w/int~rn~aI ~nd AYt~rn~I FInr~din~, ~nr~ Hirih Winr1~ Mnr~I~

CTabetA C6:Utset 2 2 Bautesi fovtent /nenladexenlFodn ndHn sMdl Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-O FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 6.80E-04 XOP-COM2-56WH OPER-4160X-WH+OPER-SWRHR-O 24 2.45E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG2DGN-EXTTM-D003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 6.60E-04 XOP-COM2-57WH OPER-4160X-WH+OPER-SWRHR-C 25 2.45E-10 5.92E-02 %HW 2 HIGH WIND INITIATING EVENT (EF1=86-110 MPH) 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-003 DIESEL GENERATOR 3 FAILS TO RUN 1.OOE+00 FL-CSTMU FAILURE OF CST MAKEUP AFTER STATION BLACKOUT 1.OOE+00 FL-HIGHWINDS FLAG TO ENABLE HIGH WINDS EVALUATION 1.OOE+00 FL-SBO STATION BLACKOUT FLAG 1.OOE+00 OPER-4160X-WH FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.OOE+00 OPER-CSTMU OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT 1.OOE+00 OPER-HWLVLCV FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO 1.OOE+00 OPER-SDGSTART OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR 1.OOE+00 OPER-SWRHR-C FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 3.OOE-03 TRAN-LOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 9.24E-01 X-POWEROP1 Fraction of annual year at power 6.60E-04 XOP-COM2-57WH OPER-4160X-WH+OPER-SWRHR-C Enclosure 6: PRA Quantification Data Tables, Page 46

Table A6-7: Units 1 and 2 Top Cutsets for the IE w/internal and external flooding LERF Model (Same cutsets for both unit models)

Outset Outset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1 2.32E-12 5.OOE-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 3.84E-02 EDGlDGN-EXTTM-D002 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 5.90E-02 EDG2DGN-FR-004 DIESEL GENERATOR 4 FAILS TO RUN 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-LPISTART-1 20 FLAG TO ACTIVATE OPERATOR ACTION TO START LPI IN 120 MIN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 2.22E-05 PCI1AOV-CF22-001 1 CCF - VALVES G16-F003 & G16-F004 FAIL TO CLOSE ON DEMAND 1.OOE+00 X-ID1-43 LERF-No cool MU w/low RPV press: Isolation fails 9.24E-01 X-POWEROP1 Fraction of annual year at power 2 2.32E-1 2 5.OOE-05 %EXTFL 1 PROBABILITY OF A 23 FOOT STORM SURGE 5.90E-02 EDG1DGN-FR-002 DIESEL GENERATOR 2 FAILS TO RUN 3.84E-02 EDG2DGN-EXTTM-D004 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days) 1.OOE+00 FL-EXTFLOOD FLAG TO ENABLE EXTERNAL FLOOD EVALUATION 1.OOE+00 FL-LPISTART-120 FLAG TO ACTIVATE OPERATOR ACTION TO START LPI IN 120 MIN 1.OOE+00 FL-NSBO NO STATION BLACKOUT FLAG 2.22E-05 PCI1AOV-CF22-001 1 CCF - VALVES G16-F003 & G16-F004 FAIL TO CLOSE ON DEMAND 1.OOE+00 X-ID1-43 LERF-No cool MU w/low RPV press: Isolation fails 9.24E-01 X-POWEROP1 Fraction of annual year at power

1. PC12AOV-CF22-001 for unit 2 Table A6-8: Unit 1 RAW Ranking for the IE w/internal Flooding Models Event Name Probability Ach W Description XOP-COM2-12 1.OOE-06 1.21E+05 OPER-4160X+OPER-SPCL XOP-COM3-12 1.OOE-06 4.12E+04 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 4.09E+04 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY XOP-COM3-08 1.OOE-06 3.34E+04 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL XOP-COM2-14 1.OOE-06 2.30E+04 OPER-4160X+OPER-DEPRESS1 XOP-COM2-39 9.50E-05 5.48E+03 OPER-4160X+OPER-SDGSTART XOP-COM2-10 1.OOE-06 5.18E+03 OPER-SPCE+OPER-WVDHR XOP-COM2-36 3.85E-05 1.68E+03 OPER-4160X+OPER-SWRHR-O XOP-COM2-35 1.OOE-06 1.31E+03 OPER-4160X+OPER-FPS1 XOP-COM2-22 1.OOE-06 784.11 OPER-DCPALTDC 1+OPER-MANSW-120 XOP-COM2-19 1.00E-06 523.07 OPER-DCPALTDCl +OPER-N2SUPPLY XOP-COM2-26 1.00E-06 523.07 OPER-4160X+OPER-WVDHR XOP-COM2-41 1.OOE-06 523.07 OPER-4160X+OPER-DCPALTDC1 XOP-COM3-06 1.OOE-06 523.07 OPER-4160X+OPER-DCPALTDC1 +OPER-FPXFER Enclosure 6: PRA Quantification Data Tables, Page 47

Table A6-8: Unit 1 RAW Ranking for the IE w/internal Flooding Models Event Name Probability Ach W Description XOP-COM3-116 1.90E-05 323.64 OPER-4160X+OPER-DCPALTDC1 +OPER-SWRHR-C XOP-COM3-09 1.00E-06 262.04 OPER-DCPALTDC1 +OPER-SWRHR-O+OPER-SPCL XOP-COM3-10 1.OOE-06 262.04 OPER-DCPALTDC1 +OPER-SWRHR-C+OPER-SPCL

%TE S WC 7.96E-03 54.29 SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

XOP-COM2-13 9.59E-05 46.48 OPER-4160X+OPER-480X XOP-4160X 1.90E-04 46.36 OPER-4160X

%TE S SC 5.55E-03 30.67 SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

%TE S GC 6.79E-03 29.81 SITE LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

%1T DC1B 2.92E-04 25.35 LOSS OF DC SWITCHBOARD 1B RHR1 PTF-TM-LOOPA 3.50E-03 21.62 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE XOP-DCDG 2.80E-04 19.28 OPER-DCDG

%1T DC1B2 2.92E-04 19.09 LOSS OF 125V DC PANEL 1B2 XOP-SPCL 8.10E-05 17.96 OPER-SPCL XOP-FPS1 4.10E-03 11.37 OPER-FPS1 XOP-SDGSTART 5.20E-03 10.77 Operator fails to start Supp-DG EDG1DGN-EXTTM-D002 3.84E-02 10.39 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

ACPOBKR-CC-1AC5 2.55E-03 10.07 CIRCUIT BREAKER FROM UAT #1 TO lC (1AC5) FAILS TO OPEN ACPOBKR-OO-1AC7 2.55E-03 10.07 CIRCUIT BREAKER FROM SAT #1 TO 1C (1-AC7) FAILS TO CLOSE Table A6-9: Unit 1 FV Ranking for the IE w/internal Flooding Models Event Name Probability Fus Ves Description X-POWEROP1I 9.24E-01 1.OOE+00 Fraction of annual year at power FL-NSBO 1.00E+00 9.86E-01 NO STATION BLACKOUT FLAG OPER-SDGSTART 1.OOE+00 9.43E-01 OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR OPER-4160X 1.OOE+00 8.73E-01 FAILURE TO ALIGN POWER FROM OPPOSITE UNIT OPER-480X 1.OOE+00 7.48E-01 FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 XOP-COM2-39 9.50E-05 5.20E-01 OPER-4160X+OPER-SDGSTART

%TE S WC 7.96E-03 4.28E-01 SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

EDG1 DGN-EXTTM-D002 3.84E-02 3.75E-01 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

X-AC-C01S WC 9.62E-01 3.06E-01 Offsite Power Recovery OPER-SPCE 1.OOE+00 2.68E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY OPER-SWRHR-C 1.OOE+00 2.45E-01 FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION OPER-SPCL 1.OOE+00 2.44E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE EDG2DGN-EXTTM-D004 3.84E-02 2.33E-01 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

EDG2DGN-EXTTM-D003 3.84E-02 2.13E-01 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

%TE S GC 6.79E-03 1.97E-01 SITE LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

X-AC-C01S GC 7.63E-01 1.97E-01 Offsite Power Recovery Enclosure 6: PRA Quantification Data Tables, Page 48

Table A6-9: Unit 1 FV Rankinc for the IE w/internal Flooding Models Event Name Probability Fus Ves Description EDGlDGN-EXTTM-D001 3.84E-02 1.79E-01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

%TE S SC 5.55E-03 1.66E-01 SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

X-AC-C01S SC 7.96E-01 1.66E-01 Offsite Power Recovery XOP-COM2-12 1.OOE-06 1.21E-01 OPER-4160X+OPER-SPCL OPER-SWRHR-O 1.OOE+00 1.14E-01 FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION X-AC-C05 S WC 2.12E-01 1.O0E-01 WC SITE LOSP CASE 5

%1T T 8.24E-01 8.37E-02 TURBINE TRIP INITIATOR OPER-N2SUPPLY 1.OOE+00 8.27E-02 FAILURE TO ALIGN NITROGEN SUPPLY OPER-GENDISC 1.OOE+00 8.25E-02 FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED RHR1 PTF-TM-LOOPA 3.50E-03 7.24E-02 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE XOP-COM2-36 3.85E-05 6.45E-02 OPER-4160X+OPER-SWRHR-O OPER-FPS1 1.OOE+00 6.44E-02 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT)

XOP-SDGSTART 5.20E-03 5.11 E-02 Operator fails to start Supp-DG EDG2DGN-FR-004 5.90E-02 4.63E-02 DIESEL GENERATOR 4 FAILS TO RUN SDG1 DGN-FR-001 5.90E-02 4.55E-02 SUPPLEMENTAL DIESEL GENERATOR FAILS TO RUN EDG2DGN-FR-003 5.90E-02 4.41E-02 DIESEL GENERATOR 3 FAILS TO RUN

%1TE Ul WC 9.38E-03 4.31E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

X-AC-C01U1 WC 7.06E-01 4.31 E-02 Offsite Power Recovery XOP-FPS1 4.1OE-03 4.27E-02 OPER-FPS1 OPER-ALT120V 1.OOE+00 4.12E-02 FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY OPER-ISOSWAP 1.OOE+00 4.12E-02 FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY XOP-COM3-12 1.OOE-06 4.12E-02 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 4.10E-02 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY OPER-TBCMGT 1.OOE+00 3.93E-02 FAILURE TO THROTTLE TBCCW FLOW (INITIATOR)

OPER-DCDG 1.OOE+00 3.57E-02 FAILURE TO ALIGN PORTABLE DC GENERATOR TO BATTERY CHARGERS OPER-DFPFUEL 1.OOE+00 3.54E-02 FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS OPER-FPXFER 1.OOE+00 3.40E-02 FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW XOP-COM3-08 1.OOE-06 3.35E-02 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL EDG2XHE-MN-DG3 8.OOE-03 3.30E-02 Failure to restore EDG #3 or subsystem following test or maintenance EDG1DGN-FR-002 5.90E-02 3.26E-02 DIESEL GENERATOR 2 FAILS TO RUN EDG2XHE-MN-DG4 8.OOE-03 3.22E-02 Failure to restore EDG #4 or subsystem following test or maintenance EDG2DGN-TM-D003 7.15E-03 2.95E-02 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

OPER-LDSDN 6.90E-01 2.95E-02 SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPER-LDSHD)

EDG2DGN-TM-D004 7.15E-03 2.83E-02 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

%1TE Ul SC 7.81E-03 2.79E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

X-AC-C01U1 SC 5.95E-01 2.79E-02 Offsite Power Recovery ACPOXHE-MN-E2E4 8.OOE-03 2.65E-02 Failure to properly restore breaker following maintenance Enclosure 6: PRA Quantification Data Tables, Page 49

Table A6-9: Unit 1 FV Rankina for the lE w/internal Floodine Models Event Name Probability Fus Ves Description FL-BATDEPL1B 1.OOE+00 2.42E-02 BATTERY BANK 1B DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER ACPOBKR-CC-IAC5 2.55E-03 2.32E-02 CIRCUIT BREAKER FROM UAT #1 TO lC (1AC5) FAILS TO OPEN ACPOBKR-OO-1AC7 2.55E-03 2.32E-02 CIRCUIT BREAKER FROM SAT #1 TO lC (1-AC7) FAILS TO CLOSE EDG1XHE-MN-DG2 8.OOE-03 2.31E-02 Failure to restore EDG #2 or subsystem following test or maintenance OPER-DEPRESS1 1.OOE+00 2.30E-02 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES XOP-COM2-14 1.OOE-06 2.30E-02 OPER-4160X+OPER-DEPRESS1 EDG1DGN-FR-001 5.90E-02 2.28E-02 DIESEL GENERATOR 1 FAILS TO RUN

%1TE U1 GC 4.21E-03 2.12E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

X-AC-C01U1 GC 8.48E-01 2.12E-02 Offsite Power Recovery EDG2DGN-FS-003 5.38E-03 2.08E-02 DIESEL GENERATOR 3 FAILS TO START EDG1DGN-TM-D002 7.15E-03 2.02E-02 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

EDG2DGN-FS-004 5.38E-03 1.95E-02 DIESEL GENERATOR 4 FAILS TO START TRAN-LOOP 3.OOE-03 1.83E-02 CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA)

ACPOBKR-CC-1AD7 2.55E-03 1.81 E-02 UAT #1 TO 1D (1-AD7) CIRCUIT BREAKER FAILS TO OPEN ACPOBKR-OO-1AD5 2.55E-03 1.81 E-02 CIRCUIT BREAKER FROM SAT #1 TO 1D (1-AD5) FAILS TO CLOSE RHR1 PTF-TM-LOOPB 3.50E-03 1.70E-02 RHR LOOP B UNAVAILABLE DUE TO TEST OR MAINTENANCE X-AC-C09 S WC 1.32E-01 1.52E-02 WC SITE LOSP CASE 9 ACP0XHE-MN-E1E3 8.OOE-03 1.51 E-02 Failure to properly restore breaker following maintenance FL-SBO 1.OOE+00 1.45E-02 STATION BLACKOUT FLAG EDG1XHE-MN-DG1 8.OOE-03 1.45E-02 Failure to restore EDG #1 or subsystem following test or maintenance EDGlDGN-FS-002 5.38E-03 1.41 E-02 DIESEL GENERATOR 2 FAILS TO START EDG1DGN-TM-D001 7.15E-03 1.29E-02 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

OPER-DCPALTDC1 1.OOE+00 1.24E-02 FAILURE TO ALIGN DC BUS TO STANDBY DC POWER SUPPLY - UNIT 1 FL-BATDEPL1A 1.00E+00 1.15E-02 BATTERY BANK 1A DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER OPER-CRD-FO-INJ 1.OOE+00 1.09E-02 FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP RHR1FPS-NO-NO21A 1.08E-03 9.24E-03 FLOW SWITCH El1-PDIS-NO21A FAILS TO OPERATE EDG1DGN-FS-001 5.38E-03 9.08E-03 DIESEL GENERATOR 1 FAILS TO START ACPOBKR-OO-DGE3 2.55E-03 8.99E-03 CIRCUIT BREAKER A15 FAILS TO CLOSE ACP2BKR-CC-1AI6 2.55E-03 8.99E-03 CIRCUIT BREAKER 2-AI6 FAILS TO OPEN ACP2BKR-CC-1AI9 2.55E-03 8.99E-03 CIRCUIT BREAKER 2-A19 FAILS TO OPEN ACP2BKR-CC-1AJ1 2.55E-03 8.99E-03 CIRCUIT BREAKER 2-AJ1 FAILS TO OPEN ACP2BKR-CC-IAJ3 2.55E-03 8.99E-03 CIRCUIT BREAKER 2-AJ3 FAILS TO OPEN ACP2BKR-CC-2AI7 2.55E-03 8.99E-03 CIRCUIT BREAKER 2-AI7 FAILS TO OPEN ACP2BKR-CC-2AI8 2.55E-03 8.99E-03 CIRCUIT BREAKER 2-AI8 FAILS TO OPEN ACP2BKR-CC-2AJ2 2.55E-03 8.99E-03 CIRCUIT BREAKER 2-AJ2 FAILS TO OPEN ACP2BKR-CC-2AJ4 2.55E-03 8.99E-03 CIRCUIT BREAKER 2-AJ4 FAILS TO OPEN XOP-4160X 1.90E-04 8.62E-03 OPER-4160X Enclosure 6: PRA Quantification Data Tables, Page 50

Table A6-9: Unit 1 FV Ranking for the IE w/internal Floodinq Models Event Name Probability Fus Ves Description

%1T C 1.35E-01 7.97E-03 LOSS OF CONDENSER VACUUM ACPOBKR-OO-DGE4 2.55E-03 7.79E-03 CIRCUIT BREAKER AK2 FAILS TO CLOSE ACP2BKR-CC-2AK3 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-AK3 FAILS TO OPEN ACP2BKR-CC-2AK4 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-AK4 FAILS TO OPEN ACP2BKR-CC-2AK5 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-AK5 FAILS TO OPEN ACP2BKR-CC-2AK6 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-AK6 FAILS TO OPEN ACP2BKR-CC-2AK8 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-AK8 FAILS TO OPEN ACP2BKR-CC-2AK9 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-AK9 FAILS TO OPEN ACP2BKR-CC-2ALO 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-ALO FAILS TO OPEN ACP2BKR-CC-2AL1 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-ALl FAILS TO OPEN ACP2BKR-CC-2AL2 2.55E-03 7.79E-03 CIRCUIT BREAKER 2-AL2 FAILS TO OPEN

%1T DC1lB 2.92E-04 7.11E-03 LOSS OF DC SWITCHBOARD 1B FL TEMP<90 1.00E+00 7.05E-03 OUTSIDE AIR TEMP < 90 DEG F

%1T M 1.19E-01 7.02E-03 MSIV CLOSURE INITIATOR OPER-LDSHD 3.10E-01 6.25E-03 FAILURE TO COMPLETE DC LOAD SHED XOP-COM3-16 1.90E-05 6.13E-03 OPER-4160X+OPER-DCPALTDC1 +OPER-SWRHR-C SWS1MDP-FS-CSW1B 1.69E-03 5.82E-03 MOTOR-DRIVEN PUMP CSW 1B FAILS TO START OPER-WVDHR 1.00E+00 5.71 E-03 FAILURE TO INITIATE WETWELL VENTING FOR DHR OPER-DGHMAN 1.OOE+00 5.70E-03 FAILURE TO MANUALLY START EDG EXHAUST FAN(S)

ACPOBKR-OO-DGE2 2.55E-03 5.57E-03 CIRCUIT BREAKER AG7 FAILS TO CLOSE ACP1BKR-CC-IAG8 2.55E-03 5.57E-03 CIRCUIT BREAKER 1-AG8 FAILS TO OPEN ACP1BKR-CC-IAG9 2.55E-03 5.57E-03 CIRCUIT BREAKER 1-AG9 FAILS TO OPEN ACP1BKR-CC-1AH0 2.55E-03 5.57E-03 CIRCUIT BREAKER 1-AHO FAILS TO OPEN ACP1BKR-CC-1AH2 2.55E-03 5.57E-03 CIRCUIT BREAKER 1-AH2 FAILS TO OPEN ACP1BKR-CC-IAH3 2.55E-03 5.57E-03 CIRCUIT BREAKER 1-AH3 FAILS TO OPEN ACP1BKR-CC-IAH4 2.55E-03 5.57E-03 CIRCUIT BREAKER 1-AH4 FAILS TO OPEN ACP1BKR-CC-1AH5 2.55E-03 5.57E-03 CIRCUIT BREAKER 1-AH5 FAILS TO OPEN ACPIBKR-CC-IAH6 2.55E-03 5.57E-03 CIRCUIT BREAKER 1-AH6 FAILS TO OPEN

%1T DC11B2 2.92E-04 5.28E-03 LOSS OF 125V DC PANEL 1B2 XOP-COM2-1 0 1.OOE-06 5.18E-03 OPER-SPCE+OPER-WVDHR X-AC-C10 S WC 1.23E-01 5.12E-03 WC SITE LOSP CASE 10 XOP-DCDG 2.80E-04 5.12E-03 OPER-DCDG E

Table A6-10: Unit 2 RAW Ranking for the IE w/internal Flooding Models Event Name Probability Ach W Description XOP-COM2-12 1.OOE-06 1.24E+05 OPER-4160X+OPER-SPCL Enclosure 6: PRA Quantification Data Tables, Page 51

Table A6-1 0: Unit 2 RAW Ranking for the IE w/internal Flooding Models Event Name Probability Ach W Description XOP-COM3-12 1.00E-06 4.40E+04 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.00E-06 4.38E+04 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY XOP-COM2-14 1.00E-06 2.21 E+04 OPER-4160X+OPER-DEPRESS1 XOP-COM2-39 9.50E-05 5.31 E+03 OPER-4160X+OPER-SDGSTART XOP-COM2-10 1.OOE-06 4.99E+03 OPER-SPCE+OPER-WVDHR XOP-COM2-36 3.85E-05 1.71 E+03 OPER-4160X+OPER-SWRHR-O XOP-COM2-35 1.OOE-06 1.OOE+03 OPER-4160X+OPER-FPS1 XOP-COM2-22 1.00E-06 753.99 OPER-DCPALTDC1 +OPER-MANSW-1 20 XOP-COM2-41 1.00E-06 753.99 OPER-4160X+OPER-DCPALTDC1 XOP-COM2-19 1.00E-06 503 OPER-DCPALTDC1 +OPER-N2SUPPLY XOP-COM2-26 1.00E-06 503 OPER-4160X+OPER-WVDHR XOP-COM3-09 1.00E-06 252 OPER-DCPALTDCl +OPER-SWRHR-O+OPER-SPCL XOP-COM3-10 1.00E-06 252 OPER-DCPALTDCI +OPER-SWRHR-C+OPER-SPCL

%TE S WC 7.96E-03 54.43 SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

XOP-4160X 1.90E-04 37.64 OPER-4160X

%TE S SC 5.55E-03 30.99 SITE LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

XOP-COM2-13 9.59E-05 30.3 OPER-4160X+OPER-480X

%TE S GC 6.79E-03 29.79 SITE LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

XOP-FPS1 4.10E-03 25.25 OPER-FPS1 RHR2PTF-TM-LOOPA 3.50E-03 22.1 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE XOP-DCDG 2.80E-04 18.57 OPER-DCDG

%2T DC2B2 2.92E-04 14.75 LOSS OF 125V DC PANEL 2B2 XOP-SPCL 8.1OE-05 10.07 OPER-SPCL RHR2FPS-NO-NO21A 1.08E-03 10.04 FLOW SWITCH E11-PDIS-NO21A FAILS TO OPERATE Table A6-111: Unit 2 FV Ranking for the IE w/internal Flooding Models Event Name Probability Fus Ves Description X-POWEROP1 9.24E-01 1.OOE+00 Fraction of annual year at power FL-NSBO 1.OOE+00 9.91 E-01 NO STATION BLACKOUT FLAG OPER-SDGSTART 1.OOE+00 9.57E-01 OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR OPER-4160X 1.OOE+00 8.24E-01 FAILURE TO ALIGN POWER FROM OPPOSITE UNIT OPER-480X 1.OOE+00 7.67E-01 FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 XOP-COM2-39 9.50E-05 5.04E-01 OPER-4160X+OPER-SDGSTART

%TE S WC 7.96E-03 4.29E-01 SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

EDG2DGN-EXTTM-D004 3.84E-02 3.50E-01 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

X-AC-CO1S WC 9.62E-01 3.07E-01 Offsite Power Recovery OPER-SWRHR-C 1.OOE+00 2.45E-01 FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION Enclosure 6: PRA Quantification Data Tables, Page 52

Table A6-1 1: Unit 2 FV Ranking for the IE w/internal Flooding Models Event Name Probability Fus Ves Description OPER-SPCE 1.OOE+00 2.42E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY EDG1DGN-EXTTM-DO01 3.84E-02 2.32E-01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

EDG1DGN-EXTTM-D002 3.84E-02 2.19E-01 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

OPER-SPCL 1.OOE+00 2.19E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE EDG2DGN-EXTTM-D003 3.84E-02 1.99E-01 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

%TE S GC 6.79E-03 1.97E-01 SITE LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

X-AC-C01S GC 7.63E-01 1.97E-01 Offsite Power Recovery

%TE S SC 5.55E-03 1.67E-01 SITE LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

X-AC-CO1S SC 7.96E-01 1.67E-01 Offsite Power Recovery XOP-COM2-12 1.00E-06 1.25E-01 OPER-4160X+OPER-SPCL OPER-FPS1 1.00E+00 1.21 E-01 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT)

OPER-SWRHR-O 1.OOE+00 1.19E-01 FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION X-AC-C05 S WC 2.12E-01 1.03E-01 WC SITE LOSP CASE 5 XOP-FPS1 4.10E-03 9.99E-02 OPER-FPS1 OPER-N2SUPPLY 1.OOE+00 8.98E-02 FAILURE TO ALIGN NITROGEN SUPPLY OPER-GENDISC 1.OOE+00 7.93E-02 FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED

%2T T 8.24E-01 7.84E-02 TURBINE TRIP INITIATOR RHR2PTF-TM-LOOPA 3.50E-03 7.41 E-02 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE XOP-COM2-36 3.85E-05 6.60E-02 OPER-4160X+OPER-SWRHR-O SWS2MDP-TM-NSW2B 8.54E-03 5.39E-02 NSW PUMP 2B UNAVAILABLE DUE TO TEST OR MAINTENANCE OPER-ALT120V 1.OOE+00 4.54E-02 FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY XOP-SDGSTART 5.20E-03 4.53E-02 Operator fails to start Supp-DG OPER-ISOSWAP 1.OOE+00 4.41 E-02 FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY XOP-COM3-12 1.OOE-06 4.41 E-02 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 4.38E-02 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY EDG1DGN-FR-001 5.90E-02 4.36E-02 DIESEL GENERATOR 1 FAILS TO RUN

%2TE U2 SC 7.80E-03 4.28E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

EDGIDGN-FR-002 5.90E-02 4.10E-02 DIESEL GENERATOR 2 FAILS TO RUN OPER-TBCMGT 1.OOE+00 3.78E-02 FAILURE TO THROTTLE TBCCW FLOW (INITIATOR)

SDG1 DGN-FR-001 5.30E-02 3.73E-02 SUPPLEMENTAL DIESEL GENERATOR FAILS TO RUN EDG1XHE-MN-DG1 8.OOE-03 3.65E-02 Failure to restore EDG #1 or subsystem following test or maintenance OPER-DCDG 1.OOE+00 3.43E-02 FAILURE TO ALIGN PORTABLE DC GENERATOR TO BATTERY CHARGERS EDGIDGN-TM-DO01 7.15E-03 3.19E-02 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

EDG2DGN-FR-004 5.90E-02 3.06E-02 DIESEL GENERATOR 4 FAILS TO RUN

%2TE U2 PC 5.85E-03 2.98E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED)

EDG1XHE-MN-DG2 8.OOE-03 2.93E-02 Failure to restore EDG #2 or subsystem following test or maintenance OPER-LDSDN 6.90E-01 2.83E-02 SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPER-LDSHD)

Enclosure 6: PRA Quantification Data Tables, Page 53

Table A6-111: Unit 2 FV Ranking for the IE w/internal Flooding Models Event Name Probability Fus Ves Description ACPOXHE-MN-E2E4 8.OOE-03 2.80E-02 Failure to properly restore breaker following maintenance EDG2DGN-FR-003 5.90E-02 2.72E-02 DIESEL GENERATOR 3 FAILS TO RUN EDG1DGN-TM-D002 7.15E-03 2.60E-02 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

FL-BATDEPL2B 11.00E+00 2.32E-02 BATTERY BANK 2B DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER EDG1DGN-FS-001 5.38E-03 2.28E-02 DIESEL GENERATOR 1 FAILS TO START ACPOBKR-CC-2AC4 2.55E-03 2.23E-02 UAT #2 TO 2C (2-AC4) CIRCUIT BREAKER FAILS TO OPEN ACPOBKR-OO-2AC6 2.55E-03 2.23E-02 CIRCUIT BREAKER FROM SAT #2 TO 2C (2-AC6) FAILS TO CLOSE OPER-DEPRESS1 1.00E+00 2.22E-02 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES XOP-COM2-14 1.OOE-06 2.22E-02 OPER-4160X+OPER-DEPRESS1 EDG2XHE-MN-DG4 8.OOE-03 2.08E-02 Failure to restore EDG #4 or subsystem following test or maintenance

%2TE U2 GC 4.20E-03 2.06E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

EDG2XHE-MN-DG3 8.OOE-03 1.89E-02 Failure to restore EDG #3 or subsystem following test or maintenance EDG2DGN-TM-D004 7.15E-03 1.84E-02 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

EDG1DGN-FS-002 5.38E-03 1.81 E-02 DIESEL GENERATOR 2 FAILS TO START RHR2PTF-TM-LOOPB 3.50E-03 1.74E-02 RHR LOOP B UNAVAILABLE DUE TO TEST OR MAINTENANCE ACPOBKR-CC-2AD6 2.55E-03 1.74E-02 CIRCUIT BREAKER FROM UAT #2 TO 2D (2-AD6) FAILS TO OPEN ACPOBKR-OO-2AD4 2.55E-03 1.74E-02 CIRCUIT BREAKER FROM SAT #2 TO 2D (2-AD4) FAILS TO CLOSE EDG2DGN-TM-D003 7.15E-03 1.62E-02 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

TRAN-LOOP 3.OOE-03 1.48E-02 CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA)

ACPOXHE-MN-E1 E3 8.OOE-03 1.47E-02 Failure to properly restore breaker following maintenance

%2TE U2 WC 3.12E-03 1.37E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

EDG2DGN-FS-004 5.38E-03 1.33E-02 DIESEL GENERATOR 4 FAILS TO START X-AC-C09 S WC 1.32E-01 1.31 E-02 WC SITE LOSP CASE 9 EDG2DGN-FS-003 5.38E-03 1.1 8E-02 DIESEL GENERATOR 3 FAILS TO START FL-BATDEPL2A 11.00E+00 1.11 E-02 BATTERY BANK 2A DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER OPER-CRD-FO-INJ 11.00E+00 1.05E-02 FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP ACPOBKR-OO-DGE1 2.55E-03 9.97E-03 CIRCUIT BREAKER AE9 FAILS TO CLOSE ACP1BKR-CC-IAFO 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AFO FAILS TO OPEN ACP1BKR-CC-1AF1 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AF1 FAILS TO OPEN ACP1BKR-CC-1AF2 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AF2 FAILS TO OPEN ACP1BKR-CC-1AF3 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AF3 FAILS TO OPEN ACP1BKR-CC-1AF4 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AF4 FAILS TO OPEN ACP1BKR-CC-1AF5 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AF5 FAILS TO OPEN ACP1BKR-CC-1AF6 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AF6 FAILS TO OPEN ACP1BKR-CC-1AF7 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AF7 FAILS TO OPEN ACP1BKR-CC-1AF9 2.55E-03 9.97E-03 CIRCUIT BREAKER 1-AF9 FAILS TO OPEN RHR2FPS-NO-NO21A 1.08E-03 9.79E-03 FLOW SWITCH E11-PDIS-NO21A FAILS TO OPERATE Enclosure 6: PRA Quantification Data Tables, Page 54

Table A6-11: Unit 2 FV Rankina for the IE w/internal Floodina Models Event Name Probability Fus Ves Description FL-SBO 1.OOE+00 8.60E-03 STATION BLACKOUT FLAG ACPOBKR-OO-DGE2 2.55E-03 7.49E-03 CIRCUIT BREAKER AG7 FAILS TO CLOSE ACP1BKR-CC-1AG8 2.55E-03 7.49E-03 CIRCUIT BREAKER 1-AG8 FAILS TO OPEN ACP1BKR-CC-1AG9 2.55E-03 7.49E-03 CIRCUIT BREAKER 1-AG9 FAILS TO OPEN ACP1BKR-CC-1AH0 2.55E-03 7.49E-03 CIRCUIT BREAKER 1-AHO FAILS TO OPEN ACP1BKR-CC-1AH2 2.55E-03 7.49E-03 CIRCUIT BREAKER 1-AH2 FAILS TO OPEN ACP1BKR-CC-1AH3 2.55E-03 7.49E-03 CIRCUIT BREAKER 1-AH3 FAILS TO OPEN ACP1BKR-CC-1AH4 2.55E-03 7.49E-03 CIRCUIT BREAKER 1-AH4 FAILS TO OPEN ACP1BKR-CC-1AH5 2.55E-03 7.49E-03 CIRCUIT BREAKER 1-AH5 FAILS TO OPEN ACP1BKR-CC-1AH6 2.55E-03 7.49E-03 CIRCUIT BREAKER 1-AH6 FAILS TO OPEN

%2T C 1.35E-01 7.31 E-03 LOSS OF CONDENSER VACUUM XOP-4160X 1.90E-04 6.96E-03 OPER-4160X

%2T M 1.19E-01 6.44E-03 MSIV CLOSURE INITIATOR OPER-DCPALTDC2 1.OOE+00 6.08E-03 FAILURE TO ALIGN DC BUS TO STANDBY DC POWER SUPPLY - UNIT 1 OPER-LDSHD 3.10E-01 6.01E-03 FAILURE TO COMPLETE DC LOAD SHED OPER-WVDHR 1.OOE+00 5.49E-03 FAILURE TO INITIATE WETWELL VENTING FOR DHR ACPOBKR-OO-DGE4 2.55E-03 5.36E-03 CIRCUIT BREAKER AK2 FAILS TO CLOSE ACP2BKR-CC-2AK3 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-AK3 FAILS TO OPEN ACP2BKR-CC-2AK4 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-AK4 FAILS TO OPEN ACP2BKR-CC-2AK5 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-AK5 FAILS TO OPEN ACP2BKR-CC-2AK6 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-AK6 FAILS TO OPEN ACP2BKR-CC-2AK8 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-AK8 FAILS TO OPEN ACP2BKR-CC-2AK9 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-AK9 FAILS TO OPEN ACP2BKR-CC-2ALO 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-ALO FAILS TO OPEN ACP2BKR-CC-2AL1 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-ALl FAILS TO OPEN ACP2BKR-CC-2AL2 2.55E-03 5.36E-03 CIRCUIT BREAKER 2-AL2 FAILS TO OPEN Table A6-12: Unit 1 RAW Ranking for the IE w/internal and external Flooding Models Event Name Probability Ach W Description XOP-COM2-12 1.OOE-06 1.05E+05 OPER-4160X+OPER-SPCL XOP-COM3-12 1.00E-06 3.60E+04 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 3.58E+04 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY XOP-COM3-08 1.OOE-06 2.93E+04 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL XOP-COM2-14 1.OOE-06 1.98E+04 OPER-4160X+OPER-DEPRESS1 XOP-COM2-39 9.50E-05 4.98E+03 OPER-4160X+OPER-SDGSTART XOP-COM2-1 0 1.OOE-06 4.46E+03 OPER-SPCE+OPER-WVDHR Enclosure 6: PRA Quantification Data Tables, Page 55

ThhI~ AA-1~ Unit I RAW R~nkinr, fnrth~ IF w/int~rn~l ~nd PYtArn~I FInr~rIini, MndAl~

Event Name Probability Ach W Description

%EXTFL 1 5.00E-05 1.83E+03 PROBABILITY OF A 23 FOOT STORM SURGE XOP-COM2-36 3.85E-05 1.51 E+03 OPER-4160X+OPER-SWRHR-O XOP-COM2-35 1.00E-06 1.12E+03 OPER-4160X+OPER-FPS1 XOP-COM2-22 1.00E-06 674.33 OPER-DCPALTDC1 +OPER-MANSW-1 20 XOP-COM2-19 1.00E-06 449.89 OPER-DCPALTDC1 +OPER-N2SUPPLY XOP-COM2-26 1.OOE-06 449.89 OPER-4160X+OPER-WVDHR XOP-COM2-41 1.OOE-06 449.89 OPER-4160X+OPER-DCPALTDC1 XOP-COM3-06 1.OOE-06 449.89 OPER-4160X+OPER-DCPALTDC1 +OPER-FPXFER XOP-COM3-16 1.90E-05 278.41 OPER-4160X+OPER-DCPALTDC1 +OPER-SWRHR-C XOP-COM3-09 1.OOE-06 225.45 OPER-DCPALTDC1 +OPER-SWRHR-O+OPER-SPCL XOP-COM3-10 1.OOE-06 225.45 OPER-DCPALTDC1 +OPER-SWRHR-C+OPER-SPCL

%EXTFL 2 7.40E-04 66.74 PROBABILITY OF A 20 FLOOD ENTERING SWITCHYARD XOP-COM2-13 9.59E-05 49.17 OPER-4160X+OPER-480X XOP-4160X 1.90E-04 48.49 OPER-4160X

%TE S WC 7.96E-03 46.82 SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

RHR1 PTF-TM-LOOPA 3.50E-03 27.3 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE

%TE S SC 5.55E-03 26.51 SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

%TE S GC 6.79E-03 25.77 SITE LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

XOP-DCDG 2.80E-04 24.91 OPER-DCDG

%1T DC1B 2.92E-04 21.93 LOSS OF DC SWITCHBOARD 1B

%1T DC1B2 2.92E-04 16.55 LOSS OF 125V DC PANEL 1B2 XOP-SPCL 8.1OE-05 15.59 OPER-SPCL RHR1FPS-NO-NO21A 1.08E-03 14.44 FLOW SWITCH E11 -PDIS-NO21A FAILS TO OPERATE RHR1FST-HI-NO14A 8.34E-04 11.72 FLOW ELEMENT El 1-FE-NO1 4A FAILS HIGH RHR1MOV-CC-FO07A 8.34E-04 11.72 MOTOR-OPERATED VALVE El1-FO07A FAILS TO OPEN RHR1 MOV-CC-F024A 8.34E-04 11.72 MOTOR OPERATED VALVE El 1-F024A FAILS TO OPEN RHR1 MOV-CC-F028A 8.34E-04 11.72 MOTOR OPERATED VALVE El1 -F028A FAILS TO OPEN RHR1MOV-OO-F048A 8.34E-04 11.72 MOTOR-OPERATED VALVE E11-F048A FAILS TO CLOSE SWS1MOV-CC-F068A 8.34E-04 11.72 MOTOR OPERATED VALVE SW F068A FAILS TO OPEN SWS1HTX-HW-RHR1A 7.12E-04 10.91 RHR HEAT EXCHANGER 1A LOSS OF COOLING/PLUGGED XOP-FPS1 4.10E-03 10.38 OPER-FPS1 EDG1 DGN-EXTTM-D002 3.84E-02 10.37 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

Table A6-13: Unit 1 FV Ranking for the IE w/internal and external Flooding Models Event Name Probability Fus Ves Description X-POWEROP1 9.24E-01 1.OOE+00 Fraction of annual year at power FL-NSBO 1.OOE+00 9.84E-01 NO STATION BLACKOUT FLAG Enclosure 6: PRA Quantification Data Tables, Page 56

Table A6-13: Unit 1 FV Ranking for the IE w/internal and external Flooding Models Event Name Probability Fus Ves Description OPER-SDGSTART 1.OOE+00 8.49E-01 OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR OPER-4160X 1.00E+00 7.85E-01 FAILURE TO ALIGN POWER FROM OPPOSITE UNIT OPER-480X 1.OOE+00 6.69E-01 FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 XOP-COM2-39 9.50E-05 4.73E-01 OPER-4160X+OPER-SDGSTART EDGlDGN-EXTTM-D002 3.84E-02 3.74E-01 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

%TE S WC 7.96E-03 3.68E-01 SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

X-AC-CO1S WC 9.62E-01 2.63E-01 Offsite Power Recovery EDG2DGN-EXTTM-D004 3.84E-02 2.58E-01 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

OPER-SPCE 11.00E+00 2.34E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY OPER-SWRHR-C 11.00E+00 2.20E-01 FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION OPER-SPCL 11.00E+00 2.13E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE EDG2DGN-EXTTM-D003 3.84E-02 2.03E-01 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

%TE S GC 6.79E-03 1.69E-01 SITE LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

X-AC-C01S GC 7.63E-01 1.69E-01 Offsite Power Recovery EDG1DGN-EXTTM-DO01 3.84E-02 1.64E-01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

%TE S_SC 5.55E-03 1.42E-01 SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

X-AC-C01S SC 7.96E-01 1.42E-01 Offsite Power Recovery FL-EXTFLOOD 1.OOE+00 1.40E-01 FLAG TO ENABLE EXTERNAL FLOOD EVALUATION XOP-COM2-12 1.OOE-06 1.06E-01 OPER-4160X+OPER-SPCL OPER-SWRHR-O 1.OOE+00 1.01 E-01 FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION EDG2DGN-FR-004 5.90E-02 9.26E-02 DIESEL GENERATOR 4 FAILS TO RUN RHR1PTF-TM-LOOPA 3.50E-03 9.24E-02 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE

%EXTFL 1 5.OOE-05 9.15E-02 PROBABILITY OF A 23 FOOT STORM SURGE X-AC-C05 S WC 2.12E-01 8.61E-02 WC SITE LOSP CASE 5 OPER-N2SUPPLY 1.OOE+00 7.23E-02 FAILURE TO ALIGN NITROGEN SUPPLY

%1T T 8.24E-01 7.20E-02 TURBINE TRIP INITIATOR OPER-GENDISC 1.OOE+00 7.09E-02 FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED EDG1DGN-FR-002 5.90E-02 7.07E-02 DIESEL GENERATOR 2 FAILS TO RUN EDG2DGN-FR-003 5.90E-02 6.35E-02 DIESEL GENERATOR 3 FAILS TO RUN XOP-COM2-36 3.85E-05 5.81 E-02 OPER-4160X+OPER-SWRHR-O OPER-FPS1 11.00E+00 5.73E-02 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT)

SDG1DGN-FR-001 5.90E-02 4.91 E-02 SUPPLEMENTAL DIESEL GENERATOR FAILS TO RUN

%EXTFL 2 7.40E-04 4.87E-02 PROBABILITY OF A 20 FLOOD ENTERING SWITCHYARD XOP-SDGSTART 5.20E-03 4.57E-02 Operator fails to start Supp-DG XOP-FPS1 4.10E-03 3.86E-02 OPER-FPS1

%1TE Ul WC 9.38E-03 3.71E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

X-AC-C01U1 WC 7.06E-01 3.71E-02 Offsite Power Recovery Enclosure 6: PRA Quantification Data Tables, Page 57

Table A6-13: Unit 1 FV Ranking for the IE w/internal and external Flooding Models Event Name Probability Fus Ves Description OPER-ALT120V 1.OOE+00 3.60E-02 FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY OPER-ISOSWAP 1.OOE+00 3.60E-02 FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY XOP-COM3-12 1.OOE-06 3.60E-02 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 3.58E-02 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY OPER-TBCMGT 1 .OOE+0O 3.38E-02 FAILURE TO THROTTLE TBCCW FLOW (INITIATOR)

OPER-DCDG 1.OOE+00 3.30E-02 FAILURE TO ALIGN PORTABLE DC GENERATOR TO BATTERY CHARGERS EDG1DGN-FR-001 5.90E-02 3.26E-02 DIESEL GENERATOR 1 FAILS TO RUN EDG2XHE-MN-DG4 8.OOE-03 3.17E-02 Failure to restore EDG #4 or subsystem following test or maintenance OPER-DFPFUEL 1.OOE+00 3.1OE-02 FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS OPER-FPXFER 1.OOE+00 2.98E-02 FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW XOP-COM3-08 1.OOE-06 2.93E-02 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL EDG2XHE-MN-DG3 8.OOE-03 2.92E-02 Failure to restore EDG #3 or subsystem following test or maintenance ACPOXHE-MN-E2E4 8.OOE-03 2.88E-02 Failure to properly restore breaker following maintenance EDG2DGN-TM-D004 7.15E-03 2.77E-02 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

OPER-LDSDN 6.90E-01 2.76E-02 SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPER-LDSHD)

EDG2DGN-TM-D003 7.15E-03 2.61 E-02 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

%1TE Ul SC 7.81E-03 2.40E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

X-AC-C01UI SC 5.95E-01 2.40E-02 Offsite Power Recovery EDG1XHE-MN-DG2 8.OOE-03 2.35E-02 Failure to restore EDG #2 or subsystem following test or maintenance FL-BATDEPL1B 1.OOE+00 2.31E-02 BATTERY BANK 1B DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER EDG1DGN-TM-D002 7.15E-03 2.04E-02 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

ACPOBKR-CC-1AC5 2.55E-03 1.99E-02 CIRCUIT BREAKER FROM UAT #1 TO 1C (1AC5) FAILS TO OPEN ACPOBKR-OO-1AC7 2.55E-03 1.99E-02 CIRCUIT BREAKER FROM SAT #1 TO IC (1-AC7) FAILS TO CLOSE OPER-DEPRESS1 1.OOE+00 1.98E-02 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES XOP-COM2-14 1.OOE-06 1.98E-02 OPER-4160X+OPER-DEPRESS 1 ACP0XHE-MN-E1 E3 8.OOE-03 1.90E-02 Failure to properly restore breaker following maintenance EDG2DGN-FS-003 5.38E-03 1.85E-02 DIESEL GENERATOR 3 FAILS TO START EDG2DGN-FS-004 5.38E-03 1.83E-02 DIESEL GENERATOR 4 FAILS TO START

%1TE Ul GC 4.21E-03 1.82E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

X-AC-C01U1 GC 8.48E-01 1.82E-02 Offsite Power Recovery TRAN-LOOP 3.OOE-03 1.57E-02 CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA)

FL-SBO 1.OOE+00 1.57E-02 STATION BLACKOUT FLAG RHR1 PTF-TM-LOOPB 3.50E-03 1.55E-02 RHR LOOP B UNAVAILABLE DUE TO TEST OR MAINTENANCE ACPOBKR-CC-1AD7 2.55E-03 1.55E-02 UAT #1 TO 1D (1-AD7) CIRCUIT BREAKER FAILS TO OPEN ACPOBKR-OO-1AD5 2.55E-03 1.55E-02 CIRCUIT BREAKER FROM SAT #1 TO 1D (1-AD5) FAILS TO CLOSE RHR1FPS-NO-NO21A 1.08E-03 1.46E-02 FLOW SWITCH E11-PDIS-NO21A FAILS TO OPERATE EDGlDGN-FS-002 5.38E-03 1.34E-02 DIESEL GENERATOR 2 FAILS TO START Enclosure 6: PRA Quantification Data Tables, Page 58

T~hI~ A~~1 ~ I nit ~ P~/ P~nLeini, fnr tI,~ II~ ,.,/nt~rn~I ~n,'4 ~vt~rn~I FInrrlinn Mrr4~k Event Name Probability Fus Ves Description X-AC-C09 S WC 1.32E-01 1.30E-02 WC SITE LOSP CASE 9 EDGlXHE-MN-DG1 8.OOE-03 1.29E-02 Failure to restore EDG #1 or subsystem following test or maintenance EDG1DGN-TM-DO01 7.15E-03 1.15E-02 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

OPER-DCPALTDC1 1.00E+00 1.07E-02 FAILURE TO ALIGN DC BUS TO STANDBY DC POWER SUPPLY - UNIT 1 FL-BATDEPL1A 1.00E+00 9.92E-03 BATTERY BANK 1A DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER OPER-CRD-FO-INJ 1.OOE+00 9.35E-03 FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP XOP-4160X 1.90E-04 9.03E-03 OPER-4160X FL V101 1.OOE+00 8.95E-03 FLAG FOR FAILURE OF FLOW PATH THROUGH RHR HX 1A RHR1MOV-CC-FO07A 8.34E-04 8.95E-03 MOTOR-OPERATED VALVE El 1-FO07A FAILS TO OPEN RHR1 MOV-CC-F024A 8.34E-04 8.95E-03 MOTOR OPERATED VALVE El 1-F024A FAILS TO OPEN RHR1MOV-CC-F028A 8.34E-04 8.95E-03 MOTOR OPERATED VALVE El1-F028A FAILS TO OPEN RHRlMOV-OO-F048A 8.34E-04 8.95E-03 MOTOR-OPERATED VALVE Ell -F048A FAILS TO CLOSE SWSlMOV-CC-F068A 8.34E-04 8.95E-03 MOTOR OPERATED VALVE SW F068A FAILS TO OPEN RHRlFST-HI-NO14A 8.34E-04 8.94E-03 FLOW ELEMENT E11-FE-NO14A FAILS HIGH FL TEMP<90 1.OOE+00 8.36E-03 OUTSIDE AIR TEMP < 90 DEG F EDGlDGN-FS-001 5.38E-03 8.09E-03 DIESEL GENERATOR 1 FAILS TO START ACPOBKR-OO-DGE3 2.55E-03 7.73E-03 CIRCUIT BREAKER A15 FAILS TO CLOSE ACP2BKR-CC-IAI6 2.55E-03 7.73E-03 CIRCUIT BREAKER 2-AI6 FAILS TO OPEN ACP2BKR-CC-IAI9 2.55E-03 7.73E-03 CIRCUIT BREAKER 2-AI9 FAILS TO OPEN ACP2BKR-CC-lAJ1 2.55E-03 7.73E-03 CIRCUIT BREAKER 2-AJ1 FAILS TO OPEN ACP2BKR-CC-IAJ3 2.55E-03 7.73E-03 CIRCUIT BREAKER 2-AJ3 FAILS TO OPEN ACP2BKR-CC-2AI7 2.55E-03 7.73E-03 CIRCUIT BREAKER 2-AI7 FAILS TO OPEN ACP2BKR-CC-2AI8 2.55E-03 7.73E-03 CIRCUIT BREAKER 2-AI8 FAILS TO OPEN ACP2BKR-CC-2AJ2 2.55E-03 7.73E-03 CIRCUIT BREAKER 2-AJ2 FAILS TO OPEN ACP2BKR-CC-2AJ4 2.55E-03 7.73E-03 CIRCUIT BREAKER 2-AJ4 FAILS TO OPEN OPER-DGHMAN 1.OOE+00 7.20E-03 FAILURE TO MANUALLY START EDG EXHAUST FAN(S)

SWS1HTX-HW-RHR1A 7.12E-04 7.06E-03 RHR HEAT EXCHANGER 1A LOSS OF COOLING/PLUGGED ACPOBKR-OO-DGE4 2.55E-03 7.04E-03 CIRCUIT BREAKER AK2 FAILS TO CLOSE ACP2BKR-CC-2AK3 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-AK3 FAILS TO OPEN ACP2BKR-CC-2AK4 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-AK4 FAILS TO OPEN ACP2BKR-CC-2AK5 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-AK5 FAILS TO OPEN ACP2BKR-CC-2AK6 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-AK6 FAILS TO OPEN ACP2BKR-CC-2AK8 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-AK8 FAILS TO OPEN ACP2BKR-CC-2AK9 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-AK9 FAILS TO OPEN ACP2BKR-CC-2ALO 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-ALO FAILS TO OPEN ACP2BKR-CC-2ALl 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-ALl FAILS TO OPEN ACP2BKR-CC-2AL2 2.55E-03 7.04E-03 CIRCUIT BREAKER 2-AL2 FAILS TO OPEN Enclosure 6: PRA Quantification Data Tables, Page 59

Table A6-1 3: Unit 1 FV Rankina for the IE w/internal and external Floodina Mnd*..

Event Name Probability Fus Ves Description

%1T C 1.35E-01 6.85E-03 LOSS OF CONDENSER VACUUM XOP-DCDG 2.80E-04 6.70E-03 OPER-DCDG

%1T DC1B 2.92E-04 6.11E-03 LOSS OF DC SWITCHBOARD 1B

%1T M 1.19E-01 6.04E-03 MSIV CLOSURE INITIATOR SWS1MDP-FS-CSWl B 1.69E-03 5.60E-03 MOTOR-DRIVEN PUMP CSW 1B FAILS TO START OPER-LDSHD 3.1OE-01 5.37E-03 FAILURE TO COMPLETE DC LOAD SHED XOP-COM3-16 1.90E-05 5.27E-03 OPER-4160X+OPER-DCPALTDC1+OPER-SWRHR-C ACPOBKR-OO-DGE2 2.55E-03 5.13E-03 CIRCUIT BREAKER AG7 FAILS TO CLOSE ACP1BKR-CC-1AG8 2.55E-03 5.13E-03 CIRCUIT BREAKER 1-AG8 FAILS TO OPEN ACP1BKR-CC-1AG9 2.55E-03 5.13E-03 CIRCUIT BREAKER 1-AG9 FAILS TO OPEN ACP1BKR-CC-1AH0 2.55E-03 5.13E-03 CIRCUIT BREAKER 1-AHO FAILS TO OPEN ACP1BKR-CC-1AH2 2.55E-03 5.13E-03 CIRCUIT BREAKER 1-AH2 FAILS TO OPEN ACP1BKR-CC-1AH3 2.55E-03 5.13E-03 CIRCUIT BREAKER 1-AH3 FAILS TO OPEN ACP1BKR-CC-1AH4 2.55E-03 5.13E-03 CIRCUIT BREAKER 1-AH4 FAILS TO OPEN ACP1BKR-CC-1AH5 2.55E-03 5.13E-03 CIRCUIT BREAKER 1-AH5 FAILS TO OPEN ACP1BKR-CC-1AH6 2.55E-03 5.13E-03 CIRCUIT BREAKER 1-AH6 FAILS TO OPEN Table A6-14: Unit 2 RAW Ranking for the IE w/internal and external Flooding Models Event Name Probability Ach W Description XOP-COM2-12 1.OOE-06 1.09E+05 OPER-4160X+OPER-SPCL XOP-COM3-12 1.00E-06 3.86E+04 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.00E-06 3.84E+04 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY XOP-COM2-14 1.00E-06 1.91E+04 OPER-4160X+OPER-DEPRESS1 XOP-COM2-39 9.50E-05 4.85E+03 OPER-4160X+OPER-SDGSTART XOP-COM2-10 1.00E-06 4.31E+03 OPER-SPCE+OPER-WVDHR

%EXTFL 1 5.00E-05 1.77E+03 PROBABILITY OF A 23 FOOT STORM SURGE XOP-COM2-36 3.85E-05 1.55E+03 OPER-4160X+OPER-SWRHR-O XOP-COM2-35 1.OOE-06 868.38 OPER-4160X+OPER-FPS1 XOP-COM2-22 1.OOE-06 651.54 OPER-DCPALTDC1 +OPER-MANSW-1 20 XOP-COM2-41 1.OOE-06 651.54 OPER-4160X+OPER-DCPALTDC1 XOP-COM2-119 1.OOE-06 434.69 OPER-DCPALTDC1 +OPER-N2SUPPLY XOP-COM2-26 1.OOE-06 434.69 OPER-4160X+OPER-WVDHR XOP-COM3-09 1.00E-06 217.85 OPER-DCPALTDC1 +OPER-SWRHR-O+OPER-SPCL XOP-COM3-10 1.00E-06 217.85 OPER-DCPALTDC1 +OPER-SWRHR-C+OPER-SPCL

%EXTFL 2 7.40E-04 65.36 PROBABILITY OF A 20 FLOOD ENTERING SWITCHYARD

%TE S WC 7.96E-03 47.16 SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

XOP-4160X 1.90E-04 40.47 OPER-4160X Enclosure 6: PRA Quantification Data Tables, Page 60

Table A6-14: Unit 2 RAW Rankina for the IE w/internal and external Floodina Models Event Name Probability Ach W Description XOP-COM2-13 9.59E-05 35.08 OPER-4160X+OPER-480X RHR2PTF-TM-LOOPA 3.50E-03 27.51 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE

%TE S SC 5.55E-03 26.91 SITE LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

%TE S GC 6.79E-03 25.87 SITE LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

XOP-DCDG 2.80E-04 24.1 OPER-DCDG XOP-FPS1 4.10E-03 23.07 OPER-FPS1 RHR2FPS-NO-NO21A 1.08E-03 14.71 FLOW SWITCH Eli -PDIS-NO21A FAILS TO OPERATE

%2T DC2B2 2.92E-04 12.88 LOSS OF 125V DC PANEL 2B2 RHR2FST-HI-N014A 8.34E-04 11.57 FLOW ELEMENT E11-FE-NO14A FAILS HIGH RHR2MOV-CC-FO07A 8.34E-04 11.57 MOTOR-OPERATED VALVE El1-FO07A FAILS TO OPEN RHR2MOV-CC-F024A 8.34E-04 11.57 MOTOR OPERATED VALVE El 1-F024A FAILS TO OPEN RHR2MOV-CC-F028A 8.34E-04 11.57 MOTOR OPERATED VALVE El 1-F028A FAILS TO OPEN RHR2MOV-OO-F048A 8.34E-04 11.57 MOTOR-OPERATED VALVE El1-F048A FAILS TO CLOSE SWS2MOV-CC-F068A 8.34E-04 11.57 MOTOR OPERATED VALVE SW F068A FAILS TO OPEN SWS2HTX-HW-RHR2A 7.12E-04 11.04 RHR HEAT EXCHANGER 2A LOSS OF COOLING/PLUGGED Table A6-15: Unit 2 FV Ranking for the IE w/internal and external Flooding Models Event Name Probability Fus Ves Description X-POWEROP1 9.24E-01 1.OOE+00 Fraction of annual year at power FL-NSBO 1.OOE+00 9.89E-01 NO STATION BLACKOUT FLAG OPER-SDGSTART 1.OOE+00 8.65E-01 OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR OPER-4160X 1.00E+00 7.44E-01 FAILURE TO ALIGN POWER FROM OPPOSITE UNIT OPER-480X 1.OOE+00 6.90E-01 FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 XOP-COM2-39 9.50E-05 4.60E-01 OPER-4160X+OPER-SDGSTART

%TE S WC 7.96E-03 3.70E-01 SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

EDG2DGN-EXTTM-D004 3.84E-02 3.51 E-01 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

X-AC-C01S WC 9.62E-01 2.65E-01 Offsite Power Recovery EDG1DGN-EXTTM-D002 3.84E-02 2.43E-01 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

EDGIDGN-EXTTM-D001 3.84E-02 2.22E-01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

OPER-SWRHR-C 1.OOE+00 2.21E-01 FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION OPER-SPCE 1.00E+00 2.12E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY OPER-SPCL 1.OOE+00 1.92E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE EDG2DGN-EXTTM-D003 3.84E-02 1.85E-01 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

%TE S GC 6.79E-03 1.70E-01 SITE LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

X-AC-C01S GC 7.63E-01 1.70E-01 Offsite Power Recovery

%TE S SC 5.55E-03 1.45E-01 SITE LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

X-AC-C01SSC 7.96E-01 1.45E-01 Offsite Power Recovery Enclosure 6: PRA Quantification Data Tables, Page 61

Table A6-15: Unit 2 FV Ranking for the IE w/internal and external Flooding Models Event Name Probability Fus Ves Description FL-EXTFLOOD 1.OOE+00 1.36E-01 FLAG TO ENABLE EXTERNAL FLOOD EVALUATION XOP-COM2-12 1.OOE-06 1.09E-01 OPER-4160X+OPER-SPCL OPER-FPS1 1.OOE+00 1.09E-01 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT)

OPER-SWRHR-O 1.OOE+00 1.05E-01 FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION RHR2PTF-TM-LOOPA 3.50E-03 9.31 E-02 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE XOP-FPS1 4.1 OE-03 9.08E-02 OPER-FPS1 X-AC-C05 S WC 2.12E-01 8.87E-02 WC SITE LOSP CASE 5

%EXTFL 1 5.OOE-05 8.84E-02 PROBABILITY OF A 23 FOOT STORM SURGE EDG1DGN-FR-002 5.90E-02 8.37E-02 DIESEL GENERATOR 2 FAILS TO RUN OPER-N2SUPPLY 1.00E+00 7.87E-02 FAILURE TO ALIGN NITROGEN SUPPLY OPER-GENDISC 1.OOE+00 6.85E-02 FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED

%2T T 8.24E-01 6.77E-02 TURBINE TRIP INITIATOR EDG2DGN-FR-004 5.90E-02 6.68E-02 DIESEL GENERATOR 4 FAILS TO RUN EDG1DGN-FR-001 5.90E-02 6.34E-02 DIESEL GENERATOR 1 FAILS TO RUN XOP-COM2-36 3.85E-05 5.95E-02 OPER-4160X+OPER-SWRHR-O SWS2MDP-TM-NSW2B 8.54E-03 4.88E-02 NSW PUMP 2B UNAVAILABLE DUE TO TEST OR MAINTENANCE

%EXTFL 2 7.40E-04 4.77E-02 PROBABILITY OF A 20 FLOOD ENTERING SWITCHYARD SDG1DGN-FR-001 5.30E-02 4.09E-02 SUPPLEMENTAL DIESEL GENERATOR FAILS TO RUN XOP-SDGSTART 5.20E-03 4.03E-02 Operator fails to start the Supp-DG OPER-ALT120V 1.OOE+00 3.98E-02 FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY EDG2DGN-FR-003 5.90E-02 3.88E-02 DIESEL GENERATOR 3 FAILS TO RUN OPER-ISOSWAP 1.OOE+00 3.86E-02 FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY XOP-COM3-12 1.OOE-06 3.86E-02 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 3.84E-02 OPER-SPCE+OPER-480X+OPER-ALT120V+OPER-N2SUPPLY

%2TE U2 SC 7.80E-03 3.70E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

OPER-TBCMGT 1.OOE+00 3.27E-02 FAILURE TO THROTTLE TBCCW FLOW (INITIATOR)

EDG1XHE-MN-DG1 8.OOE-03 3.23E-02 Failure to restore EDG #1 or subsystem following test or maintenance OPER-DCDG 1.OOE+00 3.19E-02 FAILURE TO ALIGN PORTABLE DC GENERATOR TO BATTERY CHARGERS ACPOXHE-MN-E2E4 8.OOE-03 2.97E-02 Failure to properly restore breaker following maintenance EDG1XHE-MN-DG2 8.OOE-03 2.92E-02 Failure to restore EDG #2 or subsystem following test or maintenance EDG1DGN-TM-DO01 7.15E-03 2.83E-02 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

OPER-LDSDN 6.90E-01 2.67E-02 SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPER-LDSHD)

%2TE U2 PC 5.85E-03 2.57E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED)

EDG1DGN-TM-D002 7.15E-03 2.57E-02 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

FL-BATDEPL2B 1.OOE+00 2.23E-02 BATTERY BANK 2B DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER EDG2XHE-MN-DG4 8.OOE-03 2.15E-02 Failure to restore EDG #4 or subsystem following test or maintenance EDG1DGN-FS-001 5.38E-03 2.02E-02 DIESEL GENERATOR 1 FAILS TO START Enclosure 6: PRA Quantification Data Tables, Page 62

Table A6-15: Unit 2 FV Ranking for the IE w/internal and external Flooding Models Event Name Probability Fus Ves Description ACPOBKR-CC-2AC4 2.55E-03 1.93E-02 UAT #2 TO 2C (2-AC4) CIRCUIT BREAKER FAILS TO OPEN ACPOBKR-OO-2AC6 2.55E-03 1.93E-02 CIRCUIT BREAKER FROM SAT #2 TO 2C (2-AC6) FAILS TO CLOSE OPER-DEPRESS1 1.OOE+00 1.91 E-02 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES XOP-COM2-14 1.OOE-06 1.91 E-02 OPER-4160X+OPER-DEPRESS1 EDG2DGN-TM-D004 7.15E-03 1.88E-02 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

ACPOXHE-MN-E1 E3 8.OOE-03 1.83E-02 Failure to properly restore breaker following maintenance

%2TE U2 GC 4.20E-03 1.78E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

EDG1 DGN-FS-002 5.38E-03 1.71 E-02 DIESEL GENERATOR 2 FAILS TO START EDG2XHE-MN-DG3 8.OOE-03 1.67E-02 Failure to restore EDG #3 or subsystem following test or maintenance RHR2PTF-TM-LOOPB 3.50E-03 1.60E-02 RHR LOOP B UNAVAILABLE DUE TO TEST OR MAINTENANCE ACPOBKR-CC-2AD6 2.55E-03 1.50E-02 CIRCUIT BREAKER FROM UAT #2 TO 2D (2-AD6) FAILS TO OPEN ACPOBKR-OO-2AD4 2.55E-03 1.50E-02 CIRCUIT BREAKER FROM SAT #2 TO 2D (2-AD4) FAILS TO CLOSE RHR2FPS-NO-NO21A 1.08E-03 1.48E-02 FLOW SWITCH E11-PDIS-NO21A FAILS TO OPERATE EDG2DGN-TM-D003 7.15E-03 1.43E-02 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

TRAN-LOOP 3.OOE-03 1.28E-02 CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA)

EDG2DGN-FS-004 5.38E-03 1.26E-02 DIESEL GENERATOR 4 FAILS TO START

%2TE U2 WC 3.12E-03 1.18E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

X-AC-C09 S WC 1.32E-01 1.13E-02 WC SITE LOSP CASE 9 FL-SBO 1.OOE+00 1.06E-02 STATION BLACKOUT FLAG EDG2DGN-FS-003 5.38E-03 1.04E-02 DIESEL GENERATOR 3 FAILS TO START FL-BATDEPL2A 1.OOE+00 9.58E-03 BATTERY BANK 2A DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER OPER-CRD-FO-INJ 1.OOE+00 9.03E-03 FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP FL V101 11.00E+00 8.82E-03 FLAG FOR FAILURE OF FLOW PATH THROUGH RHR HX 2A RHR2MOV-CC-FO07A 8.34E-04 8.82E-03 MOTOR-OPERATED VALVE El 1-FO07A FAILS TO OPEN RHR2MOV-CC-F024A 8.34E-04 8.82E-03 MOTOR OPERATED VALVE El 1-F024A FAILS TO OPEN RHR2MOV-CC-F028A 8.34E-04 8.82E-03 MOTOR OPERATED VALVE El 1-F028A FAILS TO OPEN RHR2MOV-OO-F048A 8.34E-04 8.82E-03 MOTOR-OPERATED VALVE El 1-F048A FAILS TO CLOSE SWS2MOV-CC-F068A 8.34E-04 8.82E-03 MOTOR OPERATED VALVE SW F068A FAILS TO OPEN RHR2FST-HI-NO14A 8.34E-04 8.82E-03. FLOW ELEMENT El 1-FE-NO14A FAILS HIGH ACPOBKR-OO-DGE1 2.55E-03 8.61 E-03 CIRCUIT BREAKER AE9 FAILS TO CLOSE ACP1BKR-CC-1AF0 2.55E-03 8.61E-03 CIRCUIT BREAKER 1-AFO FAILS TO.OPEN ACP1BKR-CC-1AF1 2.55E-03 8.61 E-03 CIRCUIT BREAKER 1-AF1 FAILS TO OPEN ACP1BKR-CC-1AF2 2.55E-03 8.61E-03 CIRCUIT BREAKER 1-AF2 FAILS TO OPEN ACP1BKR-CC-1AF3 2.55E-03 8.61E-03 CIRCUIT BREAKER 1-AF3 FAILS TO OPEN ACP1BKR-CC-1AF4 2.55E-03 8.61E-03 CIRCUIT BREAKER 1-AF4 FAILS TO OPEN ACP1BKR-CC-1AF5 2.55E-03 8.61E-03 CIRCUIT BREAKER 1-AF5 FAILS TO OPEN ACP1BKR-CC-1AF6 2.55E-03 8.61E-03 CIRCUIT BREAKER 1-AF6 FAILS TO OPEN Enclosure 6: PRA Quantification Data Tables, Page 63

T~ahI~ AR-I R I Init 9 F\/ R~nkine, fnr th~ IF w/int~rn~I ~ncI ~~t~rn~I Flnntlinn Mnrt~I~

Event Name Probability Fus Ves Description ACP1BKR-CC-1AF7 2.55E-03 8.61 E-03 CIRCUIT BREAKER 1-AF7 FAILS TO OPEN ACP1BKR-CC-1AF9 2.55E-03 8.61 E-03 CIRCUIT BREAKER 1-AF9 FAILS TO OPEN XOP-4160X 1.90E-04 7.50E-03 OPER-4160X SWS2HTX-HW-RHR2A 7.12E-04 7.15E-03 RHR HEAT EXCHANGER 2A LOSS OF COOLING/PLUGGED ACPOBKR-OO-DGE2 2.55E-03 6.80E-03 CIRCUIT BREAKER AG7 FAILS TO CLOSE ACP1BKR-CC-1AG8 2.55E-03 6.80E-03 CIRCUIT BREAKER 1-AG8 FAILS TO OPEN ACP1BKR-CC-1AG9 2.55E-03 6.80E-03 CIRCUIT BREAKER 1-AG9 FAILS TO OPEN ACP1 BKR-CC-1AH0 2.55E-03 6.80E-03 CIRCUIT BREAKER 1-AHO FAILS TO OPEN ACP1BKR-CC-1AH2 2.55E-03 6.80E-03 CIRCUIT BREAKER 1-AH2 FAILS TO OPEN ACP1BKR-CC-1AH3 2.55E-03 6.80E-03 CIRCUIT BREAKER 1-AH3 FAILS TO OPEN ACP1BKR-CC-1AH4 2.55E-03 6.80E-03 CIRCUIT BREAKER 1-AH4 FAILS TO OPEN ACP1BKR-CC-1AH5 2.55E-03 6.80E-03 CIRCUIT BREAKER 1-AH5 FAILS TO OPEN ACP1BKR-CC-1AH6 2.55E-03 6.80E-03 CIRCUIT BREAKER 1-AH6 FAILS TO OPEN OPER-DGHMAN 1.OOE+00 6.47E-03 FAILURE TO MANUALLY START EDG EXHAUST FAN(S)

XOP-DCDG 2.80E-04 6.47E-03 OPER-DCDG

%2T C 1.35E-01 6.32E-03 LOSS OF CONDENSER VACUUM

%2T M 1.19E-01 5.57E-03 MSIV CLOSURE INITIATOR OPER-DCPALTDC2 1.OOE+00 5.26E-03 FAILURE TO ALIGN DC BUS TO STANDBY DC POWER SUPPLY - UNIT 1 OPER-LDSHD 3.1OE-01 5.19E-03 FAILURE TO COMPLETE DC LOAD SHED Table A6-16: Unit 1 RAW Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Ach W Description XOP-COM2-12 1.OOE-06 5.58E+04 OPER-4160X+OPER-SPCL XOP-COM3-12 1.OOE-06 1.91E+04 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 1.89E+04 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY XOP-COM3-08 1.OOE-06 1.55E+04 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL XOP-COM2-14 1.OOE-06 1.05E+04 OPER-4160X+OPER-DEPRESS1 XOP-COM2-39 9.50E-05 2.64E+03 OPER-4160X+OPER-SDGSTART XOP-COM2-10 1.00E-06 2.36E+03 OPER-SPCE+OPER-WVDHR

%EXTFL 1 5.OOE-05 969.7 PROBABILITY OF A 23 FOOT STORM SURGE XOP-COM2-36 3.85E-05 799.42 OPER-4160X+OPER-SWRHR-O XOP-COM2-35 1.OOE-06 595.09 OPER-4160X+OPER-FPS1 XOP-COM2-22 1.00E-06 357.46 OPER-DCPALTDC1 +OPER-MANSW-1 20

%HW 5 2.32E-04 329.77 HIGH WIND INITIATING EVENT (EF4=166-200 MPH)

XOP-COM2-19 1.OOE-06 238.64 OPER-DCPALTDC1 +OPER-N2SUPPLY XOP-COM2-26 1.00E-06 238.64 OPER-4160X+OPER-WVDHR XOP-COM2-41 1.00E-06 238.64 OPER-4160X+OPER-DCPALTDCl Enclosure 6: PRA Quantification Data Tables, Page 64

ThhI~ A~-1~ unit I RAW R~nkint, fnr thA IF w/int~rn~I ~nd ~YtArn~I FI~ndinn antI I-Iinh Winr1~ MndAI~

Event Name Probability Ach W Description XOP-COM3-06 1.00E-06 238.64 OPER-4160X+OPER-DCPALTDC1 +OPER-FPXFER XOP-COM2-40WH 9.50E-04 215.43 OPER-4160X-WH+OPER-SDGSTART XOP-COM3-16 1.90E-05 147.86 OPER-4160X+OPER-DCPALTDC1 +OPER-SWRHR-C XOP-COM3-09 1.00E-06 119.82 OPER-DCPALTDC1 +OPER-SWRHR-O+OPER-SPCL XOP-COM3-1 0 1.OOE-06 119.82 OPER-DCPALTDC1 +OPER-SWRHR-C+OPER-SPCL TRAN-LOOP 3.00E-03 91.13 CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA)

XOP-COM2-56WH 6.80E-04 90.16 OPER-4160X-WH+OPER-SWRHR-O XOP-COM2-57WH 6.60E-04 84.21 OPER-4160X-WH+OPER-SWRHR-C XOP-4160-WH 9.50E-04 52.28 High Winds recovery of OPER-4160X XOP-COM2-53WH 2.90E-05 43.64 OPER-4160X-WH+OPER-RCICEXT XOP-COM2-61WH 1.40E-04 42.67 OPER-4160X-WH+OPER-DEPRESS-WH

%HW 4 3.40E-03 39.85 HIGH WIND INITIATING EVENT (EF3=136-165 MPH)

%EXTFL 2 7.40E-04 35.8 PROBABILITY OF A 20 FLOOD ENTERING SWITCHYARD XOP-COM2-13 9.59E-05 26.5 OPER-4160X+OPER-480X XOP-4160X 1.90E-04 26.14 OPER-4160X

%TE S WC 7.96E-03 25.26 SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

EDGODGN-CF34-018 1.01E-04 22.57 CCF - DIESEL GENERATORS 1 & 2 AND 3 FAIL TO RUN EDGODGN-CF34-019 1.01E-04 22.57 CCF - DIESEL GENERATORS 1 & 2 AND 4 FAIL TO RUN EDGODGN-CF34-020 1.01E-04 22.57 CCF - DIESEL GENERATORS 1 & 3 AND 4 FAIL TO RUN EDGODGN-CF34-021 1.01E-04 22.57 CCF - DIESEL GENERATORS 2 & 3 AND 4 FAIL TO RUN RHR1 PTF-TM-LOOPA 3.50E-03 18.38 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE

%TE S SC 5.55E-03 14.5 SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

%TE S GC 6.79E-03 14.11 SITE LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

XOP-DCDG 2.80E-04 13.66 OPER-DCDG

%1T DC1B 2.92E-04 12.08 LOSS OF DC SWITCHBOARD 1B EDG1DGN-EXTTM-D002 3.84E-02 11.17 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

RHR1FPS-NO-NO21A 1.08E-03 10.66 FLOW SWITCH E11-PDIS-NO21A FAILS TO OPERATE HW SWRH H4 1.31 E-02 10.59 FAILURE OF SWITCHYARD RELAY HOUSE FOR HIGH WIND INTERVAL 4 Table A6-17: Unit 1 FV Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Fus Ves Description X-POWEROP1 9.24E-01 1.OOE+00 Fraction of annual year at power OPER-SDGSTART 1.OOE+00 7.62E-01 OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR FL-NSBO 1.OOE+00 6.05E-01 NO STATION BLACKOUT FLAG FL-HIGHWINDS 1.OOE+00 4.71 E-01 FLAG TO ENABLE HIGH WINDS EVALUATION OPER-4160X 1.OOE+00 4.16E-01 FAILURE TO ALIGN POWER FROM OPPOSITE UNIT EDG1DGN-EXTTM-D002 3.84E-02 4.06E-01 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

Enclosure 6: PRA Quantification Data Tables, Page 65

Table A6-17: Unit 1 FV Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Fus Ves Description FL-SBO 1.00E+00 3.95E-01 STATION BLACKOUT FLAG OPER-480X 1.00E+00 3.95E-01 FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 OPER-4160X-WH 1.OOE+00 3.75E-01 FAILURE TO ALIGN POWER FROM OPPOSITE UNIT TRAN-LOOP 3.OOE-03 2.71 E-01 CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA)

EDG1DGN-EXTTM-DO01 3.84E-02 2.67E-01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

XOP-COM2-39 9.50E-05 2.50E-01 OPER-4160X+OPER-SDGSTART EDG1DGN-FR-002 5.90E-02 2.27E-01 DIESEL GENERATOR 2 FAILS TO RUN FL-CSTMU 1.OOE+00 2.25E-01 FAILURE OF CST MAKEUP AFTER STATION BLACKOUT OPER-HWLVLCV 1.OOE+00 2.25E-01 FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO XOP-COM2-40WH 9.50E-04 2.04E-01 OPER-4160X-WH+OPER-SDGSTART

%TE S WC 7.96E-03 1.95E-01 SITE LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

EDGlDGN-FR-001 5.90E-02 1.83E-01 DIESEL GENERATOR 1 FAILS TO RUN EDG2DGN-EXTTM-D004 3.84E-02 1.79E-01 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

OPER-DCDG 1.OOE+00 1.76E-01 FAILURE TO ALIGN PORTABLE DC GENERATOR TO BATTERY CHARGERS FL-BATDEPL1B 1.00E+00 1.72E-01 BATTERY BANK 1B DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER OPER-SWRHR-C 1.00E+00 1.72E-01 FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION EDG2DGN-EXTTM-D003 3.84E-02 1.48E-01 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

X-AC-CO1S WC 9.62E-01 1.39E-01 Offsite Power Recovery OPER-LDSDN 6.90E-01 1.36E-01 SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPER-LDSHD)

%HW 4 3.40E-03 1.33E-01 HIGH WIND INITIATING EVENT (EF3=136-165 MPH)

HW SWRH H4 1.31 E-02 1.27E-01 FAILURE OF SWITCHYARD RELAY HOUSE FOR HIGH WIND INTERVAL 4 OPER-SPCE 1.OOE+00 1.24E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY OPER-FPS1 1.OOE+00 1.22E-01 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT)

OPER-SWRHR-O 1.OOE+00 1.14E-01 FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION

%HW 2 5.92E-02 1.14E-01 HIGH WIND INITIATING EVENT (EF1=86-110 MPH)

OPER-CSTMU 1.OOE+00 1.13E-01 OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT OPER-SPCL 1.OOE+00 1.13E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE EDG2DGN-FR-004 5.90E-02 1.10E-01 DIESEL GENERATOR 4 FAILS TO RUN OPER-DFPFUEL 1.OOE+00 1.06E-01 FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS OPER-FPXFER 1.OOE+00 1.02E-01 FAILURE TO CLOSE MD FIRE PUMP TRANSFER SWITCH 2-FP-P2-XFER-SW

%HWM 2 5.43E-02 9.86E-02 HIGH WIND MISSILE INITIATING EVENT (EF1=86-110 MPH)

EDG2DGN-FR-003 5.90E-02 9.36E-02 DIESEL GENERATOR 3 FAILS TO RUN HW SDG H1 04 1.OOE+00 9.23E-02 FAILURE OF SDG FOR HIGH WIND INTERVAL 4

%TE S GC 6.79E-03 8.96E-02 SITE LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

X-AC-C01S GC 7.63E-01 8.96E-02 Offsite Power Recovery

%HW 5 2.32E-04 7.63E-02 HIGH WIND INITIATING EVENT (EF4=166-200 MPH)

HW SWRH H5 1.07E-01 7.63E-02 FAILURE OF SWITCHYARD RELAY HOUSE FOR HIGH WIND INTERVAL 5 Enclosure 6: PRA Quantification Data Tables, Page 66

Table A6-17: Unit 1 FV Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Fus Ves Description

%TE S SC 5.55E-03 7.54E-02 SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

X-AC-C01S SC 7.96E-01 7.54E-02 Offsite Power Recovery FL-EXTFLOOD 11.00E+00 7.42E-02 FLAG TO ENABLE EXTERNAL FLOOD EVALUATION RHR1 PTF-TM-LOOPA 3.50E-03 6.1 OE-02 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE XOP-COM2-56WH 6.80E-04 6.07E-02 OPER-4160X-WH+OPER-SWRHR-O HW SDG H1 05 1.00E+00 5.74E-02 FAILURE OF SDG FOR HIGH WIND INTERVAL 5 XOP-COM2-12 1.00E-06 5.59E-02 OPER-4160X+OPER-SPCL XOP-COM2-57WH 6.60E-04 5.50E-02 OPER-4160X-WH+OPER-SWRHR-C XOP-ONE 1.00E+00 5.31 E-02 Operator screening value set to 1.0 XOP-4160-WH 9.50E-04 4.88E-02 High Winds recovery of OPER-4160X

%EXTFL 1 5.OOE-05 4.84E-02 PROBABILITY OF A 23 FOOT STORM SURGE X-AC-C05 S WC 2.12E-01 4.56E-02 WC SITE LOSP CASE 5 FL-BATDEPL1A 1.00E+00 4.30E-02 BATTERY BANK 1A DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER OPER-LDSHD 3.10E-01 4.17E-02 FAILURE TO COMPLETE DC LOAD SHED OPER-N2SUPPLY 1.OOE+00 3.83E-02 FAILURE TO ALIGN NITROGEN SUPPLY

%1T T 8.24E-01 3.81E-02 TURBINE TRIP INITIATOR OPER-GENDISC 1.00E+00 3.75E-02 FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED FPSOTNK-H4-FPTNK 4.03E-01 3.53E-02 FAILURE OF FIRE WATER STORAGE TANK FOR HIGH WIND INTERVAL 4 SDG1DGN-FR-001 5.90E-02 3.12E-02 SUPPLEMENTAL DIESEL GENERATOR FAILS TO RUN XOP-COM2-36 3.85E-05 3.07E-02 OPER-4160X+OPER-SWRHR-O FL TEMP<90 1.OOE+00 2.73E-02 OUTSIDE AIR TEMP < 90 DEG F

%EXTFL 2 7.40E-04 2.58E-02 PROBABILITY OF A 20 FLOOD ENTERING SWITCHYARD FPSOTNK-H5-FPTNK 5.55E-01 2.50E-02 FAILURE OF FIRE WATER STORAGE TANK FOR HIGH WIND INTERVAL 5

%HW 3 1.63E-02 2.43E-02 HIGH WIND INITIATING EVENT (EF2=111-135 MPH)

XOP-SDGSTART 5.20E-03 2.42E-02 Operator fails to start the Supp-DG EDG1XHE-MN-DG2 8.00E-03 2.34E-02 Failure to restore EDG #2 or subsystem following test or maintenance XOP-FPS1 4.10E-03 2.04E-02 OPER-FPS1 EDG2XHE-MN-DG4 8.OOE-03 1.97E-02 Failure to restore EDG #4 or subsystem following test or maintenance

%HWM 3 1.63E-02 1.97E-02 HIGH WIND MISSLE INITIATING EVENT (EF2=1 11-135 MPH)

%1TE Ul WC 9.38E-03 1.96E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (WEATHER-CENTERED)

X-AC-C01U1 WC 7.06E-01 1.96E-02 Offsite Power Recovery EDG1DGN-TM-D002 7.15E-03 1.95E-02 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

OPER-ALT120V 1.00E+00 1.91 E-02 FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY OPER-ISOSWAP 1.OOE+00 1.91 E-02 FAILURE TO SWAP DIVISION il ISOLATION SIGNAL POWER SUPPLY XOP-COM3-12 1.00E-06 1.91 E-02 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 1.90E-02 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY ACPOXHE-MN-E2E4 8.00E-03 1.87E-02 Failure to properly restore breaker following maintenance Enclosure 6: PRA Quantification Data Tables, Page 67

Table A6-17: Unit 1 FV Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Fus Ves Description FPS2EDP-H4-P-1 2.47E-01 1.80E-02 FAILURE OF DIESEL-DRIVEN FIRE PUMP FOR HIGH WIND INTERVAL 4 EDG2XHE-MN-DG3 8.OOE-03 1.80E-02 Failure to restore EDG #3 or subsystem following test or maintenance OPER-TBCMGT 1.OOE+00 1.79E-02 FAILURE TO THROTTLE TBCCW FLOW (INITIATOR)

EDGlXHE-MN-DG1 8.OOE-03 1.70E-02 Failure to restore EDG #1 or subsystem following test or maintenance FPS2EDP-H5-P-1 4.14E-01 1.69E-02 FAILURE OF DIESEL-DRIVEN FIRE PUMP FOR HIGH WIND INTERVAL 5 EDG2DGN-TM-D004 7.15E-03 1.64E-02 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

OPER-DGHMAN-WH 1.OOE+00 1.62E-02 FAILURE TO MANUALLY START EDG EXHAUST FAN(S)

XOP-COM3-08 1.OOE-06 1.55E-02 OPER-4160X+OPER-FPXFER+OPER-DFPFUEL EDG2DGN-TM-D003 7.15E-03 1.54E-02 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

EDG1DGN-TM-DO01 7.15E-03 1.43E-02 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

ACPOXHE-MN-E1 E3 8.OOE-03 1.42E-02 Failure to properly restore breaker following maintenance

%1TE U1 SC 7.81 E-03 1.27E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARD-CENTERED)

X-AC-C01U1 SC 5.95E-01 1.27E-02 Offsite Power Recovery EDG1DGN-FS-002 5.38E-03 1.17E-02 DIESEL GENERATOR 2 FAILS TO START ACPOBKR-CC-1AC5 2.55E-03 1.06E-02 CIRCUIT BREAKER FROM UAT #1 TO lC (1AC5) FAILS TO OPEN ACPOBKR-OO-1AC7 2.55E-03 1.06E-02 CIRCUIT BREAKER FROM SAT #1 TO IC (1-AC7) FAILS TO CLOSE OPER-DEPRESS1 1.OOE+00 1.05E-02 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES XOP-COM2-14 1.OOE-06 1.05E-02 OPER-4160X+OPER-DEPRESS1 RHR1FPS-NO-NO21A 1.08E-03 1.05E-02 FLOW SWITCH E11-PDIS-NO21A FAILS TO OPERATE EDG2DGN-FS-004 5.38E-03 1.02E-02 DIESEL GENERATOR 4 FAILS TO START EDG2DGN-FS-003 5.38E-03 1.02E-02 DIESEL GENERATOR 3 FAILS TO START

%1TE Ul GC 4.21 E-03 9.65E-03 UNIT LOSS OF OFFSITE POWER TO UNIT 1 (GRID-CENTERED)

X-AC-C01U1 GC 8.48E-01 9.65E-03 Offsite Power Recovery EDG1 DGN-FS-001 5.38E-03 8.78E-03 DIESEL GENERATOR 1 FAILS TO START RHR1 PTF-TM-LOOPB 3.50E-03 8.69E-03 RHR LOOP B UNAVAILABLE DUE TO TEST OR MAINTENANCE ACPOBKR-CC-1AD7 2.55E-03 8.22E-03 UAT #1 TO 1D (1-AD7) CIRCUIT BREAKER FAILS TO OPEN ACPOBKR-OO-1AD5 2.55E-03 8.22E-03 CIRCUIT BREAKER FROM SAT #1 TO 1D (1-AD5) FAILS TO CLOSE X-AC-C09 S WC 1.32E-01 6.90E-03 WC SITE LOSP CASE 9 FL V101 1.OOE+00 6.86E-03 FLAG FOR FAILURE OF FLOW PATH THROUGH RHR HX 1A RHR1MOV-CC-FO07A 8.34E-04 6.86E-03 MOTOR-OPERATED VALVE E11-FO07A FAILS TO OPEN RHR1 MOV-CC-F024A 8.34E-04 6.86E-03 MOTOR OPERATED VALVE El1 -F024A FAILS TO OPEN RHR1 MOV-CC-F028A 8.34E-04 6.86E-03 MOTOR OPERATED VALVE El1 -F028A FAILS TO OPEN RHRlMOV-OO-F048A 8.34E-04 6.86E-03 MOTOR-OPERATED VALVE El1 -F048A FAILS TO CLOSE SWSlMOV-CC-F068A 8.34E-04 6.86E-03 MOTOR OPERATED VALVE SW F068A FAILS TO OPEN RHR1FST-HI-NO14A 8.34E-04 6.85E-03 FLOW ELEMENT El 1-FE-NO14A FAILS HIGH XOP-DGHMAN-WH 3.15E-03 6.42E-03 High Winds Recovery for OPER-DGHMAN OPER-DEPRESS-WH 1.OOE+00 6.08E-03 FAILURE TO MANUALLY INITIATE AND ALIGN LOW-PRESSURE SYSTEMS Enclosure 6: PRA Quantification Data Tables, Page 68

Table A6-17: Unit 1 FV Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Fus Ves Description XOP-COM2-61WH 1.40E-04 5.83E-03 OPER-4160X-WH+OPER-DEPRESS-WH OPER-DCPALTDC1 1.00E+00 5.64E-03 FAILURE TO ALIGN DC BUS TO STANDBY DC POWER SUPPLY - UNIT 1 SWS1HTX-HW-RHR1A 7.12E-04 5.55E-03 RHR HEAT EXCHANGER 1A LOSS OF COOLING/PLUGGED

%HWM 4 3.42E-03 5.27E-03 HIGH WIND MISSILE INITIATING EVENT (EF3=136-165 MPH)

Table A6-18: Unit 2 RAW Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Ach W Description XOP-COM2-12 1.00E-06 6.48E+04 OPER-4160X+OPER-SPCL XOP-COM3-12 1.OOE-06 2.29E+04 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 2.28E+04 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY XOP-COM2-14 1.00E-06 1.14E+04 OPER-4160X+OPER-DEPRESS1 XOP-COM2-39 9.50E-05 2.88E+03 OPER-4160X+OPER-SDGSTART XOP-COM2-10 1.00E-06 2.56E+03 OPER-SPCE+OPER-WVDHR

%EXTFL 1 5.O0E-05 1.05E+03 PROBABILITY OF A 23 FOOT STORM SURGE XOP-COM2-36 3.85E-05 918.06 OPER-4160X+OPER-SWRHR-O XOP-COM2-35 1.00E-06 515.96 OPER-4160X+OPER-FPS1 XOP-COM2-22 1.OOE-06 387.22 OPER-DCPALTDC1 +OPER-MANSW-1 20 XOP-COM2-41 1.OOE-06 387.22 OPER-4160X+OPER-DCPALTDC1

%HW 5 2.32E-04 315.36 HIGH WIND INITIATING EVENT (EF4=166-200 MPH)

XOP-COM2-19 1.OOE-06 258.48 OPER-DCPALTDC1 +OPER-N2SUPPLY XOP-COM2-26 1.00E-06 258.48 OPER-4160X+OPER-WVDHR XOP-COM2-40WH 9.50E-04 149.12 OPER-4160X-WH+OPER-SDGSTART XOP-COM3-09 1.00E-06 129.74 OPER-DCPALTDC1 +OPER-SWRHR-O+OPER-SPCL XOP-COM3-1 0 1.00E-06 129.74 OPER-DCPALTDC1 +OPER-SWRHR-C+OPER-SPCL XOP-COM2-56WH 6.80E-04 92.86 OPER-4160X-WH+OPER-SWRHR-O XOP-COM2-57WH 6.60E-04 87.92 OPER-4160X-WH+OPER-SWRHR-C TRAN-LOOP 3.OOE-03 72.84 CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA)

XOP-COM2-61WH 1.40E-04 46.15 OPER-4160X-WH+OPER-DEPRESS-WH

%EXTFL 2 7.40E-04 39.21 PROBABILITY OF A 20 FLOOD ENTERING SWITCHYARD XOP-COM2-53WH 2.90E-05 37.96 OPER-4160X-WH+OPER-RCICEXT XOP-4160-WH 9.50E-04 37.77 High Winds Recovery for OPER-4160X

%HW 4 3.40E-03 37.67 HIGH WIND INITIATING EVENT (EF3=136-165 MPH)

%TE S WC 7.96E-03 28.41 SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

XOP-4160X 1.90E-04 24.43 OPER-4160X EDGODGN-CF34-018 1.01 E-04 24.37 CCF - DIESEL GENERATORS 1 & 2 AND 3 FAIL TO RUN EDGODGN-CF34-019 1.01 E-04 24.37 CCF - DIESEL GENERATORS 1 & 2 AND 4 FAIL TO RUN EDGODGN-CF34-020 1.01 E-04 24.37 CCF - DIESEL GENERATORS 1 & 3 AND 4 FAIL TO RUN Enclosure 6: PRA Quantification Data Tables, Page 69

Table A6-18: Unit 2 RAW Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Ach W Description EDGODGN-CF34-021 1.01E-04 24.37 CCF - DIESEL GENERATORS 2 & 3 AND 4 FAIL TO RUN XOP-COM2-13 9.59E-05 21.23 OPER-4160X+OPER-480X RHR2PTF-TM-LOOPA 3.50E-03 20.48 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE

%TE S SC 5.55E-03 16.38 SITE LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

%TE S GC 6.79E-03 15.76 SITE LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

XOP-DCDG 2.80E-04 14.71 OPER-DCDG XOP-FPS1 4.1OE-03 14.1 OPER-FPS1 RHR2FPS-NO-NO21A 1.08E-03 11.89 FLOW SWITCH E11 -PDIS-NO21A FAILS TO OPERATE EDG2DGN-EXTTM-D004 3.84E-02 10.64 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

HW SWRH H4 1.31E-02 10.1 FAILURE OF SWITCHYARD RELAY HOUSE FOR HIGH WIND INTERVAL 4 RHR2FST-HI-NO14A 8.34E-04 10.03 FLOW ELEMENT E11-FE-NO14A FAILS HIGH RHR2MOV-CC-FO07A 8.34E-04 10.03 MOTOR-OPERATED VALVE El 1-FO07A FAILS TO OPEN RHR2MOV-CC-F024A 8.34E-04 10.03 MOTOR OPERATED VALVE El 1-F024A FAILS TO OPEN RHR2MOV-CC-F028A 8.34E-04 10.03 MOTOR OPERATED VALVE El 1-F028A FAILS TO OPEN RHR2MOV-OO-F048A 8.34E-04 10.03 MOTOR-OPERATED VALVE El 1-F048A FAILS TO CLOSE SWS2MOV-CC-F068A 8.34E-04 10.03 MOTOR OPERATED VALVE SW F068A FAILS TO OPEN Table A6-19: Unit 2 FV Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Fus Ves Description X-POWEROP1 9.24E-01 11.00E+00 Fraction of annual year at power OPER-SDGSTART 1.OOE+00 7.67E-01 OPERATOR FAILS TO START AND ALIGN SUPPLEMENTAL DIESEL GENERATOR FL-NSBO 11.00E+00 6.69E-01 NO STATION BLACKOUT FLAG OPER-480X 1.OOE+00 4.44E-01 FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 OPER-4160X 1.OOE+00 4.42E-01 FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FL-HIGHWINDS 11.00E+00 4.06E-01 FLAG TO ENABLE HIGH WINDS EVALUATION EDG2DGN-EXTTM-D004 3.84E-02 3.84E-01 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

FL-SBO 1.OOE+00 3.31E-01 STATION BLACKOUT FLAG OPER-4160X-WH 1.OOE+00 3.03E-01 FAILURE TO ALIGN POWER FROM OPPOSITE UNIT XOP-COM2-39 9.50E-05 2.73E-01 OPER-4160X+OPER-SDGSTART EDG2DGN-EXTTM-D003 3.84E-02 2.64E-01 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

%TE S WC 7.96E-03 2.20E-01 SITE LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

TRAN-LOOP 3.OOE-03 2.16E-01 CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA)

EDG2DGN-FR-004 5.90E-02 2.05E-01 DIESEL GENERATOR 4 FAILS TO RUN OPER-SWRHR-C 1.OOE+00 1.89E-01 FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION EDGlDGN-EXTTM-D002 3.84E-02 1.86E-01 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

FL-CSTMU 1.OOE+00 1.85E-01 FAILURE OF CST MAKEUP AFTER STATION BLACKOUT OPER-HWLVLCV 1.OOE+00 1.85E-01 FAILURE TO ISOLATE HOTWELL MAKEUP FOLLOWING AN SBO Enclosure 6: PRA Quantification Data Tables, Page 70

Table A6-19: Unit 2 FV Rankina for the IF w/internal and external Floodina and Hiah Winds Modelk Event Name Probability Fus Ves Description EDG2DGN-FR-003 5.90E-02 1.68E-01 DIESEL GENERATOR 3 FAILS TO RUN EDGlDGN-EXTTM-DO01 3.84E-02 1.66E-01 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

OPER-FPS1 1.OOE+00 1.61 E-01 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT)

X-AC-C01S WC 9.62E-01 1.57E-01 Offsite Power Recovery OPER-DCDG 1.OOE+00 1.56E-01 FAILURE TO ALIGN PORTABLE DC GENERATOR TO BATTERY CHARGERS FL-BATDEPL2B 1.OOE+00 1.52E-01 BATTERY BANK 2B DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER XOP-COM2-40WH 9.50E-04 1.41 E-01 OPER-4160X-WH+OPER-SDGSTART OPER-SPCE 1.OOE+00 1.26E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY OPER-SWRHR-O 1.OOE+00 1.25E-01 FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION

%HW 4 3.40E-03 1.25E-01 HIGH WIND INITIATING EVENT (EF3=136-165 MPH)

HW SWRH H4 1.31 E-02 1.21 E-01 FAILURE OF SWITCHYARD RELAY HOUSE FOR HIGH WIND INTERVAL 4 OPER-LDSDN 6.90E-01 1.20E-01 SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPER-LDSHD)

OPER-CSTMU 1.OOE+00 1.15E-01 OPERATOR FAILS TO MAKEUP THE CST AFTER STATION BLCAKOUT OPER-SPCL 1.00E+00 1.14E-01 FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE EDG1DGN-FR-002 5.90E-02 1.07E-01 DIESEL GENERATOR 2 FAILS TO RUN

%TE S GC 6.79E-03 1.01E-01 SITE LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

X-AC-C01S GC 7.63E-01 1.01E-01 Offsite Power Recovery

%HW 2 5.92E-02 9.15E-02 HIGH WIND INITIATING EVENT (EF1=86-110 MPH)

HW SDG H1 04 1.OOE+00 9.OOE-02 FAILURE OF SDG FOR HIGH WIND INTERVAL 4 EDG1DGN-FR-001 5.90E-02 8.91 E-02 DIESEL GENERATOR 1 FAILS TO RUN

%TE S SC 5.55E-03 8.59E-02 SITE LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

X-AC-C01S SC 7.96E-01 8.59E-02 Offsite Power Recovery FL-EXTFLOOD 1.OOE+00 8.08E-02 FLAG TO ENABLE EXTERNAL FLOOD EVALUATION

%HWM 2 5.43E-02 7.59E-02 HIGH WIND MISSILE INITIATING EVENT (EF1=86-110 MPH)

%HW 5 2.32E-04 7.30E-02 HIGH WIND INITIATING EVENT (EF4=166-200 MPH)

HW SWRH H5 1.07E-01 7.30E-02 FAILURE OF SWITCHYARD RELAY HOUSE FOR HIGH WIND INTERVAL 5 RHR2PTF-TM-LOOPA 3.50E-03 6.84E-02 RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE XOP-COM2-12 1.OOE-06 6.50E-02 OPER-4160X+OPER-SPCL XOP-COM2-56WH 6.80E-04 6.25E-02 OPER-4160X-WH+OPER-SWRHR-O XOP-ONE 1.OOE+00 5.75E-02 Operator screening value set to 1.0 XOP-COM2-57WH 6.60E-04 5.74E-02 OPER-4160X-WH+OPER-SWRHR-C HW SDG H1 05 1.OOE+00 5.71 E-02 FAILURE OF SDG FOR HIGH WIND INTERVAL 5 XOP-FPS1 4.10E-03 5.39E-02 OPER-FPS1 X-AC-C05 S WC 2.12E-01 5.26E-02 WC SITE LOSP CASE 5

%EXTFL 1 5.OOE-05 5.25E-02 PROBABILITY OF A 23 FOOT STORM SURGE OPER-N2SUPPLY 1.00E+00 4.67E-02 FAILURE TO ALIGN NITROGEN SUPPLY FL-BATDEPL2A 1.OOE+00 4.44E-02 BATTERY BANK 2A DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER Enclosure 6: PRA Quantification Data Tables, Page 71

Table A6-19: Unit 2 FV Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Fus Ves Description OPER-GENDISC 1.00E+00 4.07E-02 FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED

%2T T 8.24E-01 4.02E-02 TURBINE TRIP INITIATOR OPER-LDSHD 3.1OE-01 3.85E-02 FAILURE TO COMPLETE DC LOAD SHED FPSOTNK-H4-FPTNK 4.03E-01 3.82E-02 FAILURE OF FIRE WATER STORAGE TANK FOR HIGH WIND INTERVAL 4 XOP-COM2-36 3.85E-05 3.53E-02 OPER-4160X+OPER-SWRHR-O XOP-4160-WH 9.50E-04 3.50E-02 High Winds recovery for OPER-4160 SWS2MDP-TM-NSW2B 8.54E-03 3.11 E-02 NSW PUMP 2B UNAVAILABLE DUE TO TEST OR MAINTENANCE

%EXTFL 2 7.40E-04 2.83E-02 PROBABILITY OF A 20 FLOOD ENTERING SWITCHYARD SDG1DGN-FR-001 5.30E-02 2.77E-02 SUPPLEMENTAL DIESEL GENERATOR FAILS TO RUN FPSOTNK-H5-FPTNK 5.55E-01 2.71 E-02 FAILURE OF FIRE WATER STORAGE TANK FOR HIGH WIND INTERVAL 5 XOP-SDGSTART 5.20E-03 2.39E-02 Operator Fails to start the Supp-DG OPER-ALT120V 1.00E+00 2.36E-02 FAILURE TO ALIGN ALTERNATE 120V AC POWER SUPPLY OPER-ISOSWAP 1.OOE+00 2.29E-02 FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY XOP-COM3-12 1.OOE-06 2.29E-02 OPER-SPCE+OPER-ISOSWAP+OPER-N2SUPPLY XOP-COM4-01 1.OOE-06 2.28E-02 OPER-SPCE+OPER-480X+OPER-ALT1 20V+OPER-N2SUPPLY EDG2XHE-MN-DG4 8.OOE-03 2.27E-02 Failure to restore EDG #4 or subsystem following test or maintenance

%2TE U2 SC 7.80E-03 2.20E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARD-CENTERED)

EDG1XHE-MN-DG1 8.OOE-03 2.18E-02 Failure to restore EDG #1 or subsystem following test or maintenance ACPOXHE-MN-E2E4 8.OOE-03 2.14E-02 Failure to properly restore breaker following maintenance

%HW 3 11.63E-02 2.08E-02 HIGH WIND INITIATING EVENT (EF2=1 11-135 MPH)

EDG1XHE-MN-DG2 8.OOE-03 2.06E-02 Failure to restore EDG #2 or subsystem following test or maintenance OPER-TBCMGT 1.OOE+00 1.94E-02 FAILURE TO THROTTLE TBCCW FLOW (INITIATOR)

EDG2XHE-MN-DG3 8.OOE-03 1.92E-02 Failure to restore EDG #3 or subsystem following test or maintenance EDG2DGN-TM-D004 7.15E-03 1.89E-02 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

EDGIDGN-TM-DO01 7.15E-03 1.84E-02 DIESEL GENERATOR 1 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

EDG1DGN-TM-D002 7.15E-03 1.72E-02 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

FPS2EDP-H4-P-1 2.47E-01 1.66E-02 FAILURE OF DIESEL-DRIVEN FIRE PUMP FOR HIGH WIND INTERVAL 4 EDG2DGN-TM-D003 7.15E-03 1.59E-02 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

%HWM 3 1.63E-02 1.58E-02 HIGH WIND MISSLE INITIATING EVENT (EF2=1 11-135 MPH)

FPS2EDP-H5-P-1 4.14E-01 1.55E-02 FAILURE OF DIESEL-DRIVEN FIRE PUMP FOR HIGH WIND INTERVAL 5 ACP0XHE-MN-E1 E3 8.OOE-03 1.54E-02 Failure to properly restore breaker following maintenance

%2TE U2 PC 5.85E-03 1.53E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (PLANT-CENTERED)

OPER-DFPFUEL 1.OOE+00 1.43E-02 FAILURE TO REFILL DIESEL DRIVEN PUMP FUEL OIL TANK WITHIN 8 HOURS EDGlDGN-FS-001 5.38E-03 1.25E-02 DIESEL GENERATOR 1 FAILS TO START RHR2FPS-NO-NO21A 1.08E-03 1.18E-02 FLOW SWITCH E11-PDIS-NO21A FAILS TO OPERATE EDG2DGN-FS-004 5.38E-03 1.18E-02 DIESEL GENERATOR 4 FAILS TO START ACPOBKR-CC-2AC4 2.55E-03 1.14E-02 UAT #2 TO 2C (2-AC4) CIRCUIT BREAKER FAILS TO OPEN Enclosure 6: PRA Quantification Data Tables, Page 72

Table A6-19: Unit 2 FV Ranking for the IE w/internal and external Flooding and High Winds Models Event Name Probability Fus Ves Description ACPOBKR-OO-2AC6 2.55E-03 1.14E-02 CIRCUIT BREAKER FROM SAT #2 TO 2C (2-AC6) FAILS TO CLOSE OPER-DEPRESS1 1.OOE+00 1.14E-02 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES XOP-COM2-14 1.00E-06 1.14E-02 OPER-4160X+OPER-DEPRESS1 EDGI DGN-FS-002 5.38E-03 1.08E-02 DIESEL GENERATOR 2 FAILS TO START

%2TE U2 GC 4.20E-03 1.06E-02 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (GRID-CENTERED)

EDG2DGN-FS-003 5.38E-03 1.03E-02 DIESEL GENERATOR 3 FAILS TO START RHR2PTF-TM-LOOPB 3.50E-03 9.98E-03 RHR LOOP B UNAVAILABLE DUE TO TEST OR MAINTENANCE ACPOBKR-CC-2AD6 2.55E-03 8.90E-03 CIRCUIT BREAKER FROM UAT #2 TO 2D (2-AD6) FAILS TO OPEN ACPOBKR-OO-2AD4 2.55E-03 8.90E-03 CIRCUIT BREAKER FROM SAT #2 TO 2D (2-AD4) FAILS TO CLOSE OPER-DGHMAN-WH 1.00E+00 7.56E-03 FAILURE TO MANUALLY START EDG EXHAUST FAN(S)

FL V101 1.00E+00 7.54E-03 FLAG FOR FAILURE OF FLOW PATH THROUGH RHR HX 2A RHR2MOV-CC-FO07A 8.34E-04 7.54E-03 MOTOR-OPERATED VALVE El 1-FO07A FAILS TO OPEN RHR2MOV-CC-F024A 8.34E-04 7.54E-03 MOTOR OPERATED VALVE E11-F024A FAILS TO OPEN RHR2MOV-CC-F028A 8.34E-04 7.54E-03 MOTOR OPERATED VALVE El 1-F028A FAILS TO OPEN RHR2MOV-OO-F048A 8.34E-04 7.54E-03 MOTOR-OPERATED VALVE El 1-F048A FAILS TO CLOSE SWS2MOV-CC-F068A 8.34E-04 7.54E-03 MOTOR OPERATED VALVE SW F068A FAILS TO OPEN RHR2FST-HI-NO14A 8.34E-04 7.53E-03 FLOW ELEMENT El 1-FE-NO14A FAILS HIGH

%2TE U2 WC 3.12E-03 7.OOE-03 UNIT LOSS OF OFFSITE POWER TO UNIT 2 (WEATHER-CENTERED)

XOP-DGHMAN-WH 3.15E-03 6.95E-03 High Winds recovery for OPER-DGHMAN X-AC-C09 S WC 1.32E-01 6.72E-03 WC SITE LOSP CASE 9 OPER-DEPRESS-WH 1.OOE+00 6.59E-03 FAILURE TO MANUALLY INITIATE AND ALIGN LOW-PRESSURE SYSTEMS XOP-COM2-61WH 1.40E-04 6.32E-03 OPER-4160X-WH+OPER-DEPRESS-WH SWS2HTX-HW-RHR2A 7.12E-04 6.21E-03 RHR HEAT EXCHANGER 2A LOSS OF COOLING/PLUGGED OPER-CRD-FO-INJ 1.OOE+00 5.36E-03 FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP ACPOBKR-OO-DGE1 2.55E-03 5.11 E-03 CIRCUIT BREAKER AE9 FAILS TO CLOSE ACPlBKR-CC-IAFO 2.55E-03 5.11 E-03 CIRCUIT BREAKER 1-AFO FAILS TO OPEN ACPlBKR-CC-IAF1 2.55E-03 5.11E-03 CIRCUIT BREAKER 1-AF1 FAILS TO OPEN ACPIBKR-CC-1AF2 2.55E-03 5.11E-03 CIRCUIT BREAKER 1-AF2 FAILS TO OPEN ACP1BKR-CC-1AF3 2.55E-03 5.11E-03 CIRCUIT BREAKER 1-AF3 FAILS TO OPEN ACP1BKR-CC-1AF4 2.55E-03 5.11 E-03 CIRCUIT BREAKER 1-AF4 FAILS TO OPEN ACP1BKR-CC-1AF5 2.55E-03 5.11 E-03 CIRCUIT BREAKER 1-AF5 FAILS TO OPEN ACP1BKR-CC-1AF6 2.55E-03 5.11 E-03 CIRCUIT BREAKER 1-AF6 FAILS TO OPEN ACP1BKR-CC-1AF7 2.55E-03 5.11 E-03 CIRCUIT BREAKER 1-AF7 FAILS TO OPEN ACP1 BKR-CC-1AF9 2.55E-03 5.11 E-03 CIRCUIT BREAKER 1-AF9 FAILS TO OPEN Table A6-20: Units 1 and 2 RAW Ranking for the IE w/internal and external Flooding LERF Models Enclosure 6: PRA Quantification Data Tables, Page 73

Event Name Probability Ach W Description PCI1AOV-CF22-001 2.22E-05 4.50E+04 CCF - VALVES G16-F003 & G16-F004 FAIL TO CLOSE ON DEMAND

%EXTFL 1 5.OOE-05 2.OOE+04 PROBABILITY OF A 23 FOOT STORM SURGE EDG1DGN-EXTTM-D002 3.84E-02 13.54 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

EDG2DGN-EXTTM-D004 3.84E-02 13.54 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

Table A6-21: Units 1 and 2 FV Ranking for the IE w/internal and external Flooding LERF Models Event Name Probability Fus Ves Description

%EXTFL 1 5.OOE-05 1.OOE+00 PROBABILITY OF A 23 FOOT STORM SURGE FL-EXTFLOOD 1.OOE+00 1.00E+00 FLAG TO ENABLE EXTERNAL FLOOD EVALUATION FL-LPISTART-120 1.OOE+00 1.OOE+00 FLAG TO ACTIVATE OPERATOR ACTION TO START LPI IN 120 MIN FL-NSBO 1.OOE+00 1.OOE+00 NO STATION BLACKOUT FLAG PCI1AOV-CF22-001 2.22E-05 1.OOE+00 CCF - VALVES G16-F003 & G16-F004 FAIL TO CLOSE ON DEMAND X-ID1-43 1.OOE+00 1.OOE+00 LERF-No cool MU w/low RPV press: Isolation fails X-POWEROP1 9.24E-01 1.OOE+00 Fraction of annual year at power EDGIDGN-EXTTM-D002 3.84E-02 5.OOE-01 DIESEL GENERATOR 2 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

EDG1DGN-FR-002 5.90E-02 5.OOE-01 DIESEL GENERATOR 2 FAILS TO RUN EDG2DGN-EXTTM-D004 3.84E-02 5.OOE-01 DIESEL GENERATOR 4 UNAVAILABLE DUE TO MAINTENANCE (>7 days)

EDG2DGN-FR-004 5.90E-02 5.OOE-01 DIESEL GENERATOR 4 FAILS TO RUN Enclosure 6: PRA Quantification Data Tables, Page 74

BSEP 11-0097 Enclosure 7 DIESEL GENERATOR COMPLETION TIME EXTENSION COMMITMENT LIST COMMITMENT LIST

BSEP 11-0097 Enclosure 7 DIESEL GENERATOR COMPLETION TIME EXTENSION COMMITMENT LIST The following table identifies those actions committed to by Carolina Power and Light Company (CP&L), now doing business as Progress Energy Carolinas, Inc., in this document. Any other statements in this submittal are provided for information purposes and are not considered to be commitments.

Comritmn Schedule

1. The SUPP-DG will be protected, as defense-in-depth, during the extended DG CT.

2. The SUPP-DG will be routinely monitored during Operator Rounds, with monitoring criteria identified in the Operator Rounds. The SUPP-DG will be monitored for fire hazards during Operator Rounds.

3. Component testing or maintenance of safety systems and important nonsafety equipment in the offsite power systems which can increase the likelihood of a plant transient (i.e., unit trip) or LOOP, will be avoided during the extended DG CT

4. No discretionary switchyard maintenance will be allowed during the extended DG CT.

5. Weather conditions will be evaluated prior to intentionally entering the extended DG CT and will not be entered if official weather forecasts are predicting severe weather conditions (i.e.,

thunderstorm, tornado, or hurricane warnings). Operators will monitor weather forecasts each shift during the extended DG CT. Prior to startup from the If severe weather or grid instability is expected after a DG outage 2013 Brunswick Unit 2 begins, station managers will assess the conditions and refueling outage.

determine the best course for returning the DG to an operable status.

6. Licensed Operators and Auxiliary Operators, for the operating crews on-shift when the extended DG CT is in use, will be briefed on the DG work plan, the revised TS 3.8.1, and procedural actions regarding LOOP, SBO, and SUPP-DG alignment and use prior to entering the extended DG CT.

7. Licensed Operators and Auxiliary Operators will be appropriately trained on the purpose and use of the SUPP-DG and the revised AOP actions. Personnel performing maintenance on the SUPP-DG will be appropriately trained.

8. The High Pressure Coolant Injection (HPCI) pump, the Reactor Core Isolation Cooling (RCIC) pump, and the Residual Heat Removal (RHR) pump associated with the operable DG will not be removed from service for elective maintenance activities during the extended DG CT.

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BSEP 11-0097 Enclosure 7 DIESEL GENERATOR COMPLETION TIME EXTENSION COMMITMENT LIST

9. The PRA Fire Peer Review is scheduled for December 2011. The PRA Fire Peer CP&L expects to receive the Fire Peer Review Final Report in Review is scheduled for January 2012, and will provide the Fire Peer Review December 2011. CP&L supplemental information within 30 days of receipt of the Final expects to receive the Fire Report. Peer Review Final Report in January 2012, and will provide the Fire Peer Review supplemental information within 30 days of receipt of the Final Report.

Page 2 of 2

BSEP 11-0097, Request for License Amendments - Diesel Generator (DG) Completion Time Extension for Technical Specification (TS) 3.8.1, AC Sources Operating.

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BSEP 11-0097, Request for License Amendments - Diesel Generator (DG) Completion Time Extension for Technical Specification (TS) 3.8.1, AC Sources Operating.

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Subject:

Enclosures:

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