Text

Request for Risk-Informed Exigent License Amendment - Technical Specification 3.8.1, AC Sources Operating, One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements
	ML17332B024
Person / Time
Site:	Brunswick
Issue date:	11/28/2017
From:	William Gideon; Duke Energy Progress
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	BSEP 17-0111
	Download: ML17332B024 (236)
	v • d • e

William R. Gideon Vice President Brunswick Nuclear Plant P.O. Box 10429 Southport, NC 28461 o: 910.832.3698 November 28, 2017 Serial: BSEP 17-0111 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

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 Risk-Informed Exigent License Amendment - Technical Specification 3.8.1, AC Sources - Operating, One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements

References:

1. Letter from Duke Energy to the U.S. Nuclear Regulatory Commission, Request for Emergency License Amendment - Technical Specification 3.8.1, AC Sources -

Operating, One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements, dated November 22, 2017, ADAMS Accession Number ML17326B619

2. Letter from the U.S. Nuclear Regulatory Commission to Duke Energy BSEP, Issuance of Amendments For Technical Specification 3.8.1, AC [Alternating Current] Sources -

Operating One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements (Emergency Situation), dated November 26, 2017, ADAMS Accession Number ML17328B072 Ladies and Gentlemen:

In accordance with 10 CFR 50.90 and 10 CFR 50.91(a)(6), Duke Energy Progress, LLC (Duke Energy), is requesting a one-time, risk-informed exigent license amendment associated with Technical Specification (TS) 3.8.1, AC Sources - Operating, for the Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2.

Emergency Diesel Generator 4 (EDG 4) was removed from service, in support of planned maintenance, on November 13, 2017, at 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months Eastern Standard Time (EST). Due to the shared electrical distribution system at BSEP, both Unit 1 and Unit 2 entered TS 3.8.1, Condition D (i.e., one DG inoperable for reasons other than Condition B). On November 22, 2017 (i.e., Reference 1), Duke Energy requested a one-time, deterministic emergency license amendment request (LAR) to (1) extend the Completion Time for Required Action D.5 from 14 days to 30 days; with a commensurate change to extend the maximum Completion Time of Required Action D.5 associated with discovery of failure to meet LCO 3.8.1.a or b (i.e., from 17 days to 33 days) and (2) suspend monthly testing of EDGs 1, 2, and 3 per Surveillance Requirement (SR) 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the proposed extended

U.S. Nuclear Regulatory Commission Page 2 of 4 Completion Times. The NRC approved the requested LAR on November 26, 2017 (i.e.,

Reference 2).

As part of the LAR, Duke Energy indicated that an additional extension of the Completion Times may be required and that, if necessary, a second, risk-informed, exigent LAR would be submitted in a timely manner. Disassembly, inspection, and repair of EOG 4 have been aggressively and continuously pursued. However, restoration of EOG 4 will not be completed within the currently approved Completion Time (i.e., 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months EST on December 13, 2017).

Therefore, Duke Energy is requesting an additional 14 day extension to the Completion Times of TS 3.8.1, Required Action D.5. Thus, the proposed Completion Time for TS 3.8.1, Required Action D.5, would be extended from the original 14 days to 44 days. A commensurate change is also proposed to extend the maximum Completion Time of Required Action D.5 associated with discovery of failure to meet LCO 3.8.1.a orb (i.e., from the original 17 days to 47 days). If EOG 4 is not restored to operable status by 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months EST on December 27, 2017, TS 3.8.1, Condition H will be entered and both units will be required to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (i.e.,

by 1945 hours0.0225 days 0.54 hours 0.00322 weeks 7.400725e-4 months EST on December 27, 2017). In order to minimize risk, consistent with defense-in-depth philosophy, Duke Energy is also requesting to suspend monthly testing of EDGs 1, 2, and 3 per SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the proposed extended Completion Times. Surveillance testing of EDGs 1, 2, and 3, per SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6, will resume and be completed within seven days of restoration of EOG 4 operability or by January 3, 2018, whichever occurs first.

Duke Energy is requesting that the NRC review and approve this LAR on an exigent basis in accordance with 10 CFR 50.91 (a)(6). Approval of the proposed amendment is requested by December 12, 2017.

In accordance with the Duke Energy Quality Assurance Program Description, the Plant Nuclear Safety Committee has reviewed and concurred with this proposed amendment.

In accordance with 10 CFR 50.91, Duke Energy is providing a copy of the proposed license amendment to the designated representative for the State of North Carolina.

The enclosure provides a description and assessment of the proposed change, including a discussion as to the exigent nature of this submittal and why the exigent circumstances are necessitated. The existing Unit 1 and Unit 2 TS pages, marked to show the proposed changes, are provided in Attachments 1 and 2 of the enclosure, respectively. Attachments 3 and 4 provide revised (i.e., typed) TS pages for Units 1 and 2, respectively. Attachments 5 and 6 provide revised (i.e., typed) Operating License (OL) pages for Units 1 and 2, respectively.

Attachments 7 through 11 provide the probabilistic risk assessment input that supports the proposed extension of the Completion Times.

This document contains no new regulatory commitments.

I declare, under penalty of perjury, that the foregoing is true and correct. Executed on November 28, 2017.

Sincerely, William R. Gideon

U.S. Nuclear Regulatory Commission Page 3 of 4 MAT/mat

Enclosure:

Description and Assessment of the Proposed Change Attachment 1: Proposed Technical Specification Changes (Mark-Up) - Unit 1 Attachment 2: Proposed Technical Specification Changes (Mark-Up) - Unit 2 Attachment 3: Revised (Typed) Technical Specification Pages - Unit 1 Attachment 4: Revised (Typed) Technical Specification Pages - Unit 2 Attachment 5: Revised (Typed) Operating License Pages - Unit 1 Attachment 6: Revised (Typed) Operating License Pages - Unit 2 Attachment 7: PRA Evaluation of Risk Impact Attachment 8: PRA Technical Adequacy Attachment 9: PRA Uncertainty Evaluation Attachment 10: PRA Seismic Evaluation Attachment 11: PRA Quantification Data Tables

U.S. Nuclear Regulatory Commission Page 4 of 4 cc:

U. S. Nuclear Regulatory Commission, Region II ATTN: Ms. Catherine Haney, Regional Administrator 245 Peachtree Center Ave, NE, Suite 1200 Atlanta, GA 30303-1257 U. S. Nuclear Regulatory Commission, Region II ATTN: Mr. Mark E. Franke, Acting Director Division of Reactor Projects 245 Peachtree Center Ave, NE, Suite 1200 Atlanta, GA 30303-1257 U. S. Nuclear Regulatory Commission ATTN: Undine Shoop, Chief Plant Licensing Branch II-2 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission ATTN: Mr. Andrew Hon (Electronic Copy Only) 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission ATTN: Mr. Gale Smith, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 Chair - North Carolina Utilities Commission P.O. Box 29510 Raleigh, NC 27626-0510 Mr. W. Lee Cox, III, Section Chief (Electronic Copy Only)

Radiation Protection Section North Carolina Department of Health and Human Services 1645 Mail Service Center Raleigh, NC 27699-1645 lee.cox@dhhs.nc.gov

BSEP 17-0111 Enclosure Page 1 of 31 Description and Assessment of the Proposed Change

Subject:

Request for Risk-Infomed Exigent License Amendment Technical Specification 3.8.1, AC Sources - Operating, One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements

1.

SUMMARY

DESCRIPTION

2. DETAILED DESCRIPTION 2.1 System Design and Operation 2.2 Current Technical Specification Requirements 2.3 Reason for the Proposed Change / Basis for Exigent Circumstances 2.4 Cause Determination / Common Cause Evaluation 2.5 Description of Proposed Change

3. TECHNICAL EVALUATION 3.1 Deterministic Evaluation 3.2 Risk Assessment 3.2.1 Tier 1: Risk Evaluation 3.2.1.1 PRA Scope and Applicable Hazards 3.2.1.2 One-Time Completion Time Extension Model Changes 3.2.1.3 Qualitative Risk Insights 3.2.2 Tier 2: Avoidance of Risk Significant Plant Conditions 3.2.2.1 Risk Insights for Internal Events 3.2.2.2 Risk Insights for Fire Events 3.2.2.3 Other Hazards 3.2.2.4 Component Evaluation 3.2.3 Tier 3: Configuration Risk Management 3.2.3.1 Maintenance Rule Risk Management Program 3.2.3.2 Traditional Engineering Considerations 3.2.3.3 Defense-in-Depth 3.2.3.4 Safety Margin 3.2.4 Conclusions 3.3 Compensatory Actions

4. REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 No Significant Hazards Consideration Determination Analysis 4.4 Conclusions

BSEP 17-0111 Enclosure Page 2 of 31

5. ENVIRONMENTAL CONSIDERATION

6. REFERENCES ATTACHMENTS:

1. Proposed Technical Specification Changes (Mark-Up) - Unit 1

2. Proposed Technical Specification Changes (Mark-Up) - Unit 2

3. Revised (Typed) Technical Specification Pages - Unit 1

4. Revised (Typed) Technical Specification Pages - Unit 2

5. Revised (Typed) Operating License Pages - Unit 1

6. Revised (Typed) Operating License Pages - Unit 2

7. PRA Evaluation of Risk Impact

8. PRA Technical Adequacy

9. PRA Uncertainty Evaluation

10. PRA Seismic Evaluation

11. PRA Quantification Data Tables

BSEP 17-0111 Enclosure Page 3 of 31

1.

SUMMARY

DESCRIPTION The proposed one-time, risk-informed exigent license amendment request (LAR) revises Technical Specification (TS) 3.8.1, AC Sources - Operating, to provide an extension of the Completion Time for Required Action D.5 from the original 14 days to 44 days for Emergency Diesel Generator 4 (EDG 4). A commensurate change is also proposed to extend the maximum Completion Time of Required Action D.5 associated with discovery of failure to meet Limiting Condition for Operation (LCO) LCO 3.8.1.a or b (i.e., from the original 17 days to 47 days). The exigent LAR is requested in order to avoid an unnecessary shutdown of both Brunswick Steam Electric Plant (BSEP), Units 1 and 2 without a commensurate benefit in nuclear safety. In order to minimize risk, consistent with defense-in-depth philosophy, Duke Energy Progress, LLC (Duke Energy), is also requesting to suspend monthly testing of EDGs 1, 2, and 3 per Surveillance Requirement (SR) 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the proposed extended Completion Times.

EDG 4 was removed from service, in support of planned maintenance, on November 13, 2017, at 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months Eastern Standard Time (EST). Due to the shared electrical distribution system at BSEP, both Unit 1 and Unit 2 entered TS 3.8.1, Condition D (i.e., one DG inoperable for reasons other than Condition B). On November 22, 2017 (i.e., Reference 1), Duke Energy requested a one-time, deterministic emergency license amendment request (LAR) to (1) extend the Completion Time for Required Action D.5 from 14 days to 30 days; with a commensurate change to extend the maximum Completion Time of Required Action D.5 associated with discovery of failure to meet LCO 3.8.1.a or b (i.e., from 17 days to 33 days) and (2) suspend monthly testing of EDGs 1, 2, and 3 per Surveillance Requirement (SR) 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the proposed extended Completion Times. The NRC approved the requested LAR on November 26, 2017 (i.e., Reference 2).

As part of the original LAR, Duke Energy indicated that an additional extension of the Completion Times may be required and that, if necessary, a second, risk-informed, exigent LAR would be submitted in a timely manner. Disassembly, inspection, and repair of EDG 4 have been aggressively and continuously pursued. However, restoration of EDG 4 will not be completed within the currently approved Completion Time (i.e., 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months EST on December 13, 2017). Due to the nature of the repairs and potential discovery items, Duke Energy is requesting an additional 14 days to ensure that there is sufficient time available to complete repairs, address any emergent issues, perform post-maintenance testing, and re-establish operability of EDG 4.

The need for this exigent LAR was unavoidable. Based on information available prior to the ongoing EDG 4 maintenance outage, Duke Energy took prudent action to address an identified elevated aluminum trend in the EDG 4 lubricating oil. The aluminum levels were well below action levels prior to the planned maintenance outage. Planning for the EDG 4 outage included the parts and resources necessary to accomplish the expected scope of work, including main bearing replacements, well within the current TS 3.8.1, Required Action D.5 Completion Times.

Identification of a bowed EDG 4 crankshaft has resulted in additional work scope that cannot be completed within the current Completion Time. There was no available data which could have indicated that the EDG 4 crankshaft was bowed.

The extended Completion Times are necessary due to the complex and extensive nature of the work necessary to restore EDG 4 to operable status. This work includes additional bearing replacements as well as the crankshaft repair. A specialty vendor service has been contracted to correct the crankshaft bow. This has required additional disassembly within the crankcase to

BSEP 17-0111 Enclosure Page 4 of 31 access and correct the condition and coordination of vendor resources and equipment necessary to perform the repairs.

In order to minimize risk, consistent with defense-in-depth philosophy, Duke Energy is also requesting to suspend monthly testing of EDGs 1, 2, and 3 per SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the proposed extended Completion Times. Performance of SR 3.8.1.2 and SR 3.8.1.3 require the affected EDG to be declared inoperable. For EDGs 1 and 3, this is a short duration inoperability which occurs when the EDGs are being barred. The existing EDG 2 governor will not automatically return the EDG to ready-to-load operation when the EDG is in manual mode. During performance of SR 3.8.1.2 or SR 3.8.1.3, EDG 2 is in manual mode for approximately four hours. Duke Energy has completed EDG governor upgrades on EDGs 1, 3, and 4; however, the modification has not been completed on EDG 2. SR 3.8.1.6 verifies the fuel oil transfer system transfers fuel oil from the day fuel oil storage tank to the engine mounted tank. This SR is performed in conjunction with the EDG operation when fuel is consumed from the engine mounted tank.

2. DETAILED DESCRIPTION 2.1 System Design and Operation The BSEP Class 1E Electrical Power Distribution System AC sources consist of the offsite power sources (i.e., preferred and alternate power sources), and the onsite standby power sources (i.e., EDGs 1, 2, 3, and 4). The design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The Class 1E AC distribution system is divided into redundant load groups, so loss of any one group does not prevent the minimum safety functions from being performed. Each load group has access to two offsite power supplies (i.e., one preferred and one alternate) via a balance of plant (BOP) circuit path. This BOP circuit path consists of the BOP bus and the associated circuit path (i.e., master/slave breakers and interconnecting cables) to a 4160 V emergency bus.

Each load group can also be connected to a single EDG.

The onsite standby power source for 4160 V emergency busses E1, E2, E3, and E4 consists of four EDGs. The EDGs are manufactured by Nordberg, Model No. FS-1316-HSC. Each EDG is dedicated to its associated emergency bus. An EDG starts automatically on a loss of coolant accident (LOCA) signal from either Unit 1 or Unit 2 or under emergency bus degraded voltage or undervoltage conditions. After the EDG has started, it automatically ties to its respective bus after offsite power is tripped as a consequence of emergency bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The EDGs also start and operate in the standby mode without tying to the emergency bus on a LOCA signal alone. Following the trip of offsite power, all loads are stripped from the emergency bus except the 480 V emergency bus. When the EDG is tied to the emergency bus, select safety related loads are then sequentially connected to their respective emergency bus by individual timers associated with each auto-connected load following a permissive from a voltage relay monitoring each emergency bus.

The capability is provided to connect a supplemental diesel generator (SUPP-DG) to supply power to any of the four 4160 V emergency busses via a BOP circuit path. This BOP circuit path consists of the BOP bus and the associated circuit path (i.e., master/slave breakers and interconnecting cables) to a 4160 V emergency bus. The SUPP-DG is commercial-grade and

BSEP 17-0111 Enclosure Page 5 of 31 not designed to meet Class 1E requirements. The SUPP-DG is made available to support extended Completion Times in the event of an inoperable EDG. The SUPP-DG is rated at 4000 kW, 4160 V, and can be connected to the 4160 V emergency busses (i.e., E1, E2, E3, or E4) in approximately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . 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 (SBO) event. The SUPP-DG would remain disconnected from the Class 1E distribution system except for testing or as required during a loss of power condition.

BSEP has also permanently installed two 500 kW FLEX diesel generators. Each is a fully contained system, capable of starting and operating with no reliance on other equipment or systems. Each has an integral 526 gallon sub-base fuel tank, a self-contained, closed loop cooling system, and an exhaust system. Each FLEX diesel generator is sized to supply the Unit 2 Division II and Unit 1 Division II identified critical loads simultaneously. The FLEX diesel generators feed emergency busses E6 and E8 via the new FLEX switchboards. Identified FLEX loads are then fed from E6, E8, and through bus ties, from E5, and E7 using the existing electrical system. The two FLEX switchboards can be cross connected to provide the capabilities of connecting each FLEX diesel generator to Unit 1 and Unit 2 Division II emergency busses E6 and E8. The FLEX critical loads are primarily battery chargers and uninterruptible power supplies (UPS), but other loads may be added as required.

INNA Oil is the contracted fuel oil supplier for BSEP. INNA Oil is a local supplier with a facility within 10 miles of the site. INNA Oil is able to deliver a tanker of fuel oil to the site given a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months notice. The SUPP-DG has a 10,000 gallon storage tank with a minimum of 6,700 gallons (i.e., 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months supply) available. The FLEX diesels have a system to draw from the EDG 4-day tanks. Duke Energy also has approximately 5,000 gallons of additional diesel fuel oil on site which can be used to supply the SUPP-DG or permanently installed FLEX DGs, as needed, using the site fuel truck.

2.2 Current Technical Specification Requirements EDG 4 was removed from service, in support of planned maintenance, on November 13, 2017, at 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months EST. Due to the shared electrical distribution system at BSEP, both Unit 1 and Unit 2 entered TS 3.8.1, Condition D (i.e., one DG inoperable for reasons other than Condition B). On November 22, 2017, Duke Energy requested a one-time, deterministic emergency LAR to (1) extend the Completion Time for Required Action D.5 from 14 days to 30 days; with a commensurate change to extend the maximum Completion Time of Required Action D.5 associated with discovery of failure to meet LCO 3.8.1.a or b (i.e., from 17 days to 33 days) and (2) suspend monthly testing of EDGs 1, 2, and 3 per SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the proposed extended Completion Times, The NRC approved the requested LAR on November 26, 2017, with the following Note added to the Completion Time for Required Action D.5.

NOTE----------------------------------------------

Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 13, 2017, the 14 day and 17 day Completion Times are extended to 30 days and 33 days, respectively.

As a result, EDG 4 must be restored to operable status by 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months EST on December 13, 2017, or Condition H will be entered and both units will be required to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (i.e., by 1945 hours0.0225 days 0.54 hours 0.00322 weeks 7.400725e-4 months on December 13, 2017).

BSEP 17-0111 Enclosure Page 6 of 31 SR 3.8.1.2 verifies that each EDG starts from standby conditions and achieves steady state voltage 3750 V and 4300 V and frequency 58.8 Hz and 61.2 Hz. The Frequency of SR 3.8.1.2 is "In accordance with the Surveillance Frequency Control Program." The current Frequency for SR 3.8.1.2, in the BSEP Surveillance Frequency Control Program, is 31 days.

SR 3.8.1.3 verifies that each EDG is synchronized and loaded and operates for 60 minutes at a load 2800 kW and 3500 kW. The Frequency of SR 3.8.1.3 is "In accordance with the Surveillance Frequency Control Program." The current Frequency for SR 3.8.1.3, in the BSEP Surveillance Frequency Control Program, is 31 days.

SR 3.8.1.6 verifies that the fuel oil transfer system operates to transfer fuel oil from the day fuel oil storage tank to the engine mounted tank. The Frequency of SR 3.8.1.6 is "In accordance with the Surveillance Frequency Control Program." The current Frequency for SR 3.8.1.6, in the BSEP Surveillance Frequency Control Program, is 31 days.

The NRC approved LAR added a note, similar to the following, to each of the SRs.

NOTE(S)---------------------------------------------

Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 13, 2017, performance of SR [3.8.1.2] for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or December 20, 2017, whichever occurs first.

2.3 Reason for the Proposed Change / Basis for Exigent Circumstances EDG 4 was removed from service, in support of planned maintenance, on November 13, 2017, at 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months EST. The original scope of work included investigation into the cause of an increasing trend of aluminum in the diesel lubricating oil. The elevated trend in aluminum has been at very low levels, well below action level, dating back to 2013. During the planned maintenance window, main bearings 7 and 8 were found degraded. A total of five main bearings were replaced to correct the condition of the bearings. The investigation also identified that the EDG 4 crankshaft has a bow, as indicated by a total runout of 0.010 inches on main bearing 7.

The crankshaft bow is believed to have occurred over several years of normal EDG operation, with low levels of bearing heating causing the bowed condition. In June 2009, BSEP took hot web deflection measurements which confirmed crankshaft straightness. Subsequent to that inspection, two events occurred in September 2009 that put a higher than normal stress on the rotating mass of EDG 4. During the governor tuning evolution on or about September 21, 2009, EDG 4 was operated up to the overspeed trip, which actuated as designed to protect the machine, on four occasions. The overspeed trip setpoint is approximately 12 percent above nominal run speed. On September 24, 2009, EDG 4 was operated above the 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months rating of 3850 kW for a total of 8 seconds over the course of four minutes. The peak loading was 4154.2 kW (i.e., approximately 19 percent above continuous rated load). Additionally, in November 2009, lead was first detected in an oil sample and this was confirmed during the next sample taken in February 2010. In both samples, the levels detected were well below the trigger value for further action and continued to be so in subsequent samples to the present day.

Aluminum first increased above the lower limit of detectability in the first quarter of 2013 and a

BSEP 17-0111 Enclosure Page 7 of 31 trend of increasing aluminum was identified by Strategic Engineering in 2017, driving the original inspection scope of our currently planned EDG maintenance window.

The two 2009 events are believed to have caused initial bearing damage which created a heat input into the crankshaft eventually resulting in a bow. This crankshaft bow is believed to have increased over several years of normal EDG operation post 2009, and, in a self-propagating cycle, increased bearing degradation and the shaft runout. Replacement of the main bearings (i.e., tightening clearances) during the planned maintenance window revealed the need to also correct the crankshaft bow.

The EDG 4 crankshaft has been evaluated, and the shaft is acceptable for continued operation, pending correction of the excessive runout. The shaft hardness is within specifications, and there are no indications of cracking or excessive shaft heating. A specialty vendor service has been contracted to correct the crankshaft bow in-situ (i.e., inside the crankcase). This has required additional disassembly within the crankcase to access and correct the condition.

Straightening of the crankshaft will correct the condition leading to the main bearing degradation, and is in progress.

Based on information available prior to the ongoing EDG 4 maintenance outage, Duke Energy took prudent action to address the elevated aluminum trend in the EDG 4 lubricating oil. The aluminum levels were well below action levels prior to the planned maintenance outage.

Planning for the EDG 4 outage included the parts and resources necessary to accomplish the expected scope of work, including main bearing replacements, well within the current TS 3.8.1, Required Action D.5 Completion Times. Identification of the bowed EDG 4 crankshaft has resulted in additional work scope that cannot be completed within the current Completion Time.

There was no available data which could have indicated that the EDG 4 crankshaft was bowed.

Therefore, the need for this exigent LAR was unavoidable.

The extended Completion Times are necessary due to the complex and extensive nature of the work necessary to restore EDG 4 to operable status. This work includes additional bearing replacements as well as the crankshaft repair. Connecting rods 6R, 7L, 7R, and 8L were removed from the engine and were examined. Each connecting rod was inspected for signs of damage or foreign material. Connecting rod 7L contained small particulate from the degraded main bearing in the oil channel leading to the wrist pin, which were removed via air flush. The connecting rods were deemed acceptable for reinstallation, as no damage was present.

As part of the November 22, 2017, LAR, Duke Energy indicated that an additional extension of the Completion Times may be required and that, if necessary, a second, risk-informed, exigent LAR would be submitted in a timely manner. Disassembly, inspection, and repair of EDG 4 have been aggressively and continuously pursued. However, restoration of EDG 4 will not be completed within the currently approved Completion Time (i.e., 0745 hours0.00862 days 0.207 hours 0.00123 weeks 2.834725e-4 months EST on December 13, 2017).

2.4 Cause Determination / Common Cause Evaluation The direct cause of this event is degradation and failure of the affected EDG 4 bearings over time, as evidenced by the increasing aluminum trend in the EDG 4 lubricating oil. Preliminary investigation has indicated that two events in 2009 (i.e., EDG 4 overspeed and overload) put a higher than normal stress on the rotating mass of EDG 4. This is believed to be the initiator leading to the condition causing bearing degradation over time. Lubricating oil trends have been reviewed for all EDGs, and no other EDGs have any indications of elevated lead or

BSEP 17-0111 Enclosure Page 8 of 31 aluminum (i.e., which would be indicative of EDG bearing degradation), or other adverse performance trends.

Crankshaft runout data was last collected in October/November 1992 for EDG 1. The latest crankshaft runout measurement was 0.002 inches. The manufacturer's maximum allowable crankshaft runout is 0.002 inches. Crankshaft runout data has not been collected for EDGs 2 or 3. The manufacturer's recommended maintenance strategy to assess crankshaft health is to collect hot web deflections. These deflections were last collected on October 30, 2012, for EDG 1; on August 27, 2012, for EDG 2; and on October 12, 2015, for EDG 3. The most recent hot web deflections on each of EDGs 1, 2 and 3 have shown satisfactory results.

EDG 2 had an overload condition in the past. During performance of 0OP-39 (i.e., Diesel Generator Operating Procedure) on June 14, 2014, the kW loading briefly exceeded the 3850 kW limit sporadically over a period of three minutes. The maximum load reached was 3923 kW. The event was due to operating the diesel near 3850 kW to test the Auto-Voltage Regulator (AVR) replacement. Because of the natural fluctuations in load during operation of the diesel, this resulted in some spikes that exceeded the 3850 kW limit.

EDG 3 had an overload condition in the past. During routine performance of 0PT-12.2C, No. 3 Diesel Generator Monthly Load Test, on November 5, 2017, EDG 3 was loaded, in error, to greater than the maximum load. Plant computer data indicates EDG 3 operated above 3850 kW for a total period of 19 seconds, with the maximum load of approximately 4100 kW.

The latest collected vibration data (i.e., early 2017) for EDGs 1, 2, 3, and 4 are similar in magnitude. The latest data has been collected with a Windrock 6320/PA. Older data was collected with a RECIP TRAP RT9260. Each used different sets of software, thus the different representations of data is due to the software capabilities. Each data point captures vibrations for each of the ten bearings on the EDGs. The data shows overall stable vibration data collections, and no bearing defects have been identified.

Latest maximum Fast Fourier Transform (FFT) magnitudes with individual bearing readings were collected for each EDG as follows:

EDG 1

BSEP 17-0111 Enclosure Page 9 of 31 EDG 2 EDG 3 EDG 4 The vibration data shown provided above is from the Windrock MD software. For each EDG, the raw vibration signals for each of the ten main bearings are shown in the bottom portion of the plot. Each plot represents one mechanical cycle (i.e., 720 degrees of crankshaft revolution) of the engine, so the x-axis shows 0 to 720 degrees. The y-axis scale on the lower portion of the plots are the same for all four EDGs (i.e., -5 to +5 g). The top portion of the plot shows the 10 overlaid FFTs of the raw vibration signatures. The x-axis of the upper portion is frequency

BSEP 17-0111 Enclosure Page 10 of 31 from 0 to approximately 6180 Hz. The y-axis is in g, but the maximum y value shown is different for each of the four EDGs because the software auto-scales.

For example, the EDG 3 upper portion is scaled to a maximum of 0.76 g, which is a smaller scale than the other three plots. The dominant vibration on EDG 3 is the main bearing 10, which is the generator inboard bearing (i.e., not one of the nine diesel engine bearings). All vibrations are in the normal range.

Based on the above, there is no similar degraded condition of other EDG bearings or crankshafts and no common cause exists.

2.5 Description of the Proposed Change The proposed change revises the one-time note associated with the Completion Time for TS 3.8.1, Required Action D.5, to read as follows.

NOTE----------------------------------------------

Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, the 14 day and 17 day Completion Times are extended to 44 days and 47 days, respectively.

Duke Energy is also requesting to suspend monthly testing of EDGs 1, 2, and 3 per SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the period when EDG 4 is inoperable. The proposed change revises the existing one-time notes for the affected SRs to be similar to the following.

NOTE(S)---------------------------------------------

Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR [3.8.1.2] for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 are performed concurrently. The following table provides information regarding when the SRs were last performed and their next currently scheduled performance.

Next Scheduled EDG Last Performed Performance 1 October 24, 2017 December 16, 2017 2 October 29, 2017 December 16, 2017 3 November 5, 2017 December 16, 2017 The specific changes to the Unit 1 and 2 TSs are provided in the marked-up and retyped TS pages provided in Attachments 1 and 2, respectively.

BSEP 17-0111 Enclosure Page 11 of 31

3. TECHNICAL EVALUATION 3.1 Deterministic Evaluation During the proposed Completion Time extensions, Units 1 and 2 will be in Mode 1. Neither EDGs 1, 2, and 3 or offsite power sources are affected by the EDG 4 maintenance and are operable. As such, sufficient offsite power supplies remain available to complete their intended safety function. The SUPP-DG, installed to support a 14 day completion time for an inoperable EDG, is available. The SUPP-DG is rated at 4000 kW, 4160 V, and can be connected to the 4160 V emergency busses (i.e., E1, E2, E3, or E4) in approximately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . In addition, BSEP has two permanently installed FLEX diesels. Each FLEX diesel is rated at 500 kW, 480 V, and can be connected to the 480 V emergency busses (i.e., E6 or E8) in less than one hour.

EDG capacity is such that any three of the four diesels can supply all required loads for the safe shutdown of one unit and a design basis accident on the other unit without offsite power. Each of the four EDGs can supply one of the four separate Class 1E emergency busses. Each is started automatically on a loss of offsite power (LOOP) or LOCA. The EDG arrangement provides adequate capacity to supply the ESF loads for the Design Basis Accident, assuming the failure of a single active component in the system.

Since the EDGs can accommodate a single failure, the one-time extension of the Completion Times for an inoperable EDG has no impact on the system design basis. Safety analyses acceptance criteria as provided in the Updated Final Safety Analysis Report (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 EDG is inoperable in Modes 1, 2, and 3, existing TS 3.8.1 Condition D requires verification of the operability of the offsite circuits on a more frequent basis. When the required redundancy is not maintained, action is required within the specified Completion Times to initiate a plant shutdown. The Completion Time 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 Completion Time interval relative to the potential occurrences of design basis events is considered. Since extending the Completion Times for a single inoperable EDG does not change the design basis for the standby emergency power system (i.e., EDGs), the one-time extension of the Required Action D.5 Completion Times is acceptable.

BSEPs coping time during SBO is not affected by the proposed change. The coping time is calculated based on guidance provided in 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 (i.e., Reference 1). During a SBO, the most significant requirement is to quickly restore AC power to the 125 VDC battery chargers. To extend battery capacity to the four hour coping duration, battery chargers are required to be energized within one hour by one of the following methods:

BSEP 17-0111 Enclosure Page 12 of 31 Cross-tying of 4160 volt emergency busses with the non blacked out unit, powered from offsite power or EDGs, and if necessary cross-tie 480 V emergency busses Aligning a FLEX diesel generator to the Division II 480 V emergency bus and if necessary cross-tie 480 V emergency busses Aligning the SUPP-DG Via the BOP 4160 V bus to the associated 4160 V emergency bus If necessary, cross-tie to the other unit's 4160 V emergency bus If necessary, cross-tie 480 V emergency busses To accomplish the above, SBO flow charts and associated text procedures provide instructions for coping with a SBO or an Extended Loss of All AC Power (ELAP) when no EDGs are available, when one EDG is available, when two EDGs are available, or when offsite power is available to one unit, supplying either one or two 4160 V emergency busses. These coping methodologies are not changed by the proposed one-time extension of the Required Action D.5 Completion Times.

The following two scenarios demonstrate compliance with the defense-in-depth guidance of NUREG-0800, Branch Technical Position (BTP) 8-8, Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions.(i.e., Reference 4).

1. Scenario 1 LOOP in both units EDG 4 (Unit 2) inoperable, EDG 3 (Unit 2) fails (i.e., single failure for Unit 2)

EDG 1 (Unit 1) fails (i.e., single failure for Unit 1)

Only the SUPP-DG and EDG 2 are available The following plant procedures are used in responding to Scenario 1.

2EOP-01-SBO, Station Blackout 0EOP-01-SBO-06, 4160V E-Bus Crosstie 0EOP-01-SBO-07, 480V E-Bus Crosstie 0EOP-01-SBO-08, Supplemental DG Alignment 1EOP-01-SBO, Station Blackout 1EOP 01 SBO-11, Unit 1 SBO Torus Cooling 1EOP-01-SBO-12, Unit 1 SBO Drywell Cooling 2EOP-01-SBO-11, Unit 2 SBO Torus Cooling 2EOP-01-SBO-12, Unit 2 SBO Drywell Cooling In this case, Unit 2 would be considered the blacked-out unit and procedure 2EOP-01-SBO would be entered. Electrical configuration in this case would require cross-tie of 4kV bus E2 to E4 (i.e., 0EOP-01-SBO-06) and cross-tie of bus 480V bus E7 to E8 (i.e., 0EOP-01-SBO-07). The SUPP-DG would be aligned to E3 (i.e.,

0EOP-01-SBO-08). 4kV bus E3 would then be cross-tied with E1 (i.e., 0EOP-01-SBO-06). FLEX DG2 would be available, if needed to power limited loads on E8 (i.e., battery chargers).

BSEP 17-0111 Enclosure Page 13 of 31 For coping strategy, the following alignment would be used:

The Unit 1 priority is maintaining reactor pressure vessel (RPV) pressure above 500 psig (i.e., 1EOP-01-SBO).

Suppression Pool Cooling (i.e., 1EOP-01-SBO-11) and Drywell Cooling (i.e.,

1EOP-01-SBO-12) would be established for containment parameters.

The Unit 2 priority is cooling the RPV to 150 to 300 psig (i.e., 2EOP-01-SBO).

Suppression Pool Cooling (i.e., 2EOP-01-SBO-11) and Drywell Cooling (i.e.,

2EOP-01-SBO-12) would be established for containment parameters.

These coping strategies will maintain conditions outside of an ELAP. In the event it is desirable to continue to cold shutdown conditions, suppression pool cooling would be replaced by Shutdown Cooling Mode of Residual Heat Removal (RHR). To achieve RPV pressure below the shutdown cooling suction interlock, an alternative level control method would need to be invoked, such as Control Rod Drive (CRD) injection with the loss of Reactor Core Isolation Cooling (RCIC) on low reactor pressure.

Loading Requirements:

On EDG 2 (E2):

1100 kW for torus cooling 600 kW for drywell cooling 67 kW for control room ventilation 12 kW for battery room ventilation The total would be approximately 1800 kW on E2 from the above.

Battery loading would also be applicable. A very conservative loading would be 500 kW.

This is based on the FLEX DGs being capable of carrying the battery chargers, and having a load limit of 500 kW. This would bring the total E2 load to a worst case of 2300 kW for coping strategies.

In the event it is desirable to continue to cold shutdown, the following additional loads are required:

600 kW for an Residual Heat Removal Service Water (RHRSW) pump 190 kW for a CRD pump.

This would bring the total E2 load to a worst case of 3090 kW for beyond coping strategy evolutions including inventory control and shutdown cooling.

On SUPP-DG (E3):

1100 kW for torus cooling 600 kW for drywell cooling 67 kW for control room ventilation 12 kW for battery room ventilation

BSEP 17-0111 Enclosure Page 14 of 31 The total would be approximately 1800 kW on the SUPP-DG from the above.

Battery loading would also be applicable. A very conservative loading would be 500 kW.

This is based on the FLEX DGs being capable of carrying the battery chargers, and having a load limit of 500 kW. This would bring the total SUPP-DG (E3) load to a worst case of 2300 kW.

In the event it is desirable to continue to cold shutdown, the following additional loads are required:

600 kW for an RHRSW pump 190 kW for a CRD pump.

This would bring the total SUPP-DG (E3) load to a worst case of 3090 kW for beyond coping strategy evolutions including inventory control and shutdown cooling.

2. Scenario 2 LOOP in both units EDG 4 (Unit 2) inoperable, EDG 3 (Unit 2) fails (i.e., single failure for Unit 2)

EDG 2 (Unit 1) fails (i.e., single failure for Unit 1)

Only the SUPP-DG and EDG 1 are available The following plant procedures are used in responding to Scenario 2.

2EOP-01-SBO, Station Blackout 0EOP-01-SBO-06, 4160V E-Bus Crosstie 0EOP-01-FSG-04, FLEX Diesel Generator Alignment 0EOP-01-SBO-08, Supplemental DG Alignment 1EOP-01-SBO, Station Blackout 1EOP 01 SBO-11, Unit 1 SBO Torus Cooling 1EOP-01-SBO-12, Unit 1 SBO Drywell Cooling 2EOP-01-SBO-11, Unit 2 SBO Torus Cooling 2EOP-01-SBO-12, Unit 2 SBO Drywell Cooling In this case, Unit 2 would be considered the blacked-out unit and procedure 2EOP-01-SBO would be entered. Electrical configuration in this case would require cross-tie of 4kV bus E1 to E3 (i.e., 0EOP-01-SBO-06) and powering 480V bus E8 from FLEX DG2 per procedure 0EOP-01-FSG-04. SUPP-DG would be aligned to E4 (i.e.,

0EOP-01-SBO-08). 4kV bus E2 would then be cross-tied with E4 (i.e.,

0EOP-01-SBO-06). Coordinate transfer of E8 to SUPP-DG (E4) with Emergency Response Organization (ERO) team as additional loads are required on bus E8.

For coping strategy, the following alignment would be used:

The Unit 1 priority is maintaining RPV pressure above 500 psig (1EOP-01-SBO).

Suppression Pool Cooling (1EOP-01-SBO-11) and Drywell Cooling (1EOP-01-SBO-12) would be established for containment parameters.

The Unit 2 priority is cooling the RPV to 150 to 300 psig (2EOP-01-SBO).

BSEP 17-0111 Enclosure Page 15 of 31 Suppression Pool Cooling (2EOP-01-SBO-11) and Drywell Cooling (2EOP-01-SBO-12) would be established for containment parameters.

These coping strategies should maintain conditions outside of ELAP. In the event it is desirable to continue to cold shutdown conditions, Suppression Pool Cooling would be replaced by Shutdown Cooling Mode of RHR. To achieve RPV pressure below the shutdown cooling suction interlock, an alternative level control method would need to be invoked such as CRD injection with the loss of RCIC on low reactor pressure.

Loading Requirements On EDG 1 (E1):

1100 kW for torus cooling 600 kW for drywell cooling 67 kW for control room ventilation 12 kW for battery room ventilation The total would be approximately 1800 kW on E1 from the above.

Battery loading would also be applicable. A very conservative loading would be 500 kW.

This is based on the FLEX DGs being capable of carrying the battery chargers, and having a load limit of 500 kW. This would bring the total E1 load to a worst case of 2300 kW for coping strategies.

In the event it is desirable to continue to cold shutdown, the following additional loads are required:

600 kW for an RHRSW pump 190 kW for a CRD pump.

This would bring the total E1 load to a worst case of 3090 kW for beyond coping strategy evolutions including inventory control and shutdown cooling.

On SUPP-DG (E4):

1100 kW for torus cooling 600 kW for drywell cooling 67 kW for control room ventilation 12 kW for battery room ventilation The total would be approximately 1800 kW on the SUPP-DG from the above.

Battery loading would also be applicable. A very conservative loading would be 500 kW.

This is based on the FLEX DGs being capable of carrying the battery chargers, and having a load limit of 500 kW. This would bring the total SUPP-DG (E4) load to a worst case of 2300 kW.

BSEP 17-0111 Enclosure Page 16 of 31 In the event it is desirable to continue to cold shutdown, the following additional loadings are required:

600 kW for an RHRSW pump 190 kW for a CRD pump.

This would bring the total SUPP-DG (E4) load to a worst case of 3090 kW for beyond coping strategy evolutions including inventory control and shutdown cooling.

To provide additional defense-in-depth, Duke Energy will have a temporary diesel generator system available on-site during the proposed Completion Time extensions. The temporary diesel generator system will consist of two 480 V, 2000 kW diesel generators (i.e., 4000 kW total) with synchronization capability, and a 480 V / 4.16 kV transformer. The temporary diesel generator system will be arranged to tie into the 4.16 kV electrical distribution system at the SUPP-DG electrical enclosure. The temporary diesel generator system will remain fueled and available for service, but not physically connected to the BSEP electrical distribution system. In the event of a loss of a 4.16 kV emergency bus (i.e., E1, E2, E3, or E4), concurrent with a failure of the SUPP-DG, the temporary diesel generator system will be capable of supplying 4.16 kV balance of plant bus 2C, which supplies 4.16 kV emergency bus E4. Duke Energy has developed work instructions to support alignment of the temporary diesel generator system.

The work instructions include three options for connecting the temporary diesel generator system to the BSEP electrical distribution system. This ensures the ability to use the temporary diesel generator system should the need arise.

If an offsite power source or an additional EDG becomes inoperable or if the SUPP-DG becomes unavailable during the proposed Completion Time extensions, the appropriate TS 3.8.1 Condition will be entered and Required Actions taken.

The proposed suspension of SR 3.8.1.2 and SR 3.8.1.3 testing requirements during the proposed extended Completion Times minimizes risk by maintaining defense-in-depth.

Performance of SR 3.8.1.2 or SR 3.8.1.3 requires the affected EDG to be declared inoperable.

For EDGs 1 and 3, this is a short duration inoperability which occurs when the EDGs are being barred. The existing EDG 2 governor will not automatically return the EDG to ready-to-load operation when the EDG is in manual mode. During performance of SR 3.8.1.2 or SR 3.8.1.3, EDG 2 is in manual mode for approximately four hours. With EDG 4 inoperable, a second EDG made inoperable for testing requires both Unit 1 and Unit 2 to enter TS 3.8.1, Condition G. If the EDG being tested is not restored to operable status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , Condition H would be entered and both units would be required to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . SR 3.8.1.6 verifies the fuel oil transfer system transfers fuel oil from the day fuel oil storage tank to the engine mounted tank. This SR is performed in conjunction with the EDG operation when fuel is consumed from the engine mounted tank. This amendment requests that these Surveillance Requirements for EDG 1, 2, and 3 be suspended during the proposed extended Completion Times.

3.2 Risk Assessment The change in risk associated with the one-time increase in the Completion Time for the EDG 4 during operation in Modes 1, 2, or 3 has been evaluated for both BSEP units in accordance with the guidance of Regulatory Guide (RG) 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications. A summary of this evaluation is provided in the following sections with additional detailed information provided in Attachment 7.

BSEP 17-0111 Enclosure Page 17 of 31 3.2.1 Tier 1: Risk Evaluation 3.2.1.1 PRA Scope and Applicable Hazards Hazard groups were evaluated to determine which sources of risk could affect the decision. It was determined that the change in risk associated with internal events, internal flooding, fire, and high winds due to tornadoes could affect the decision and these hazard were evaluated quantitatively using the respective BSEP PRA models. The review history and associated technical adequacy of these models is presented in the attached PRA technical adequacy report (i.e., Attachment 8, PRA Technical Adequacy). Also supporting this application, an uncertainty evaluation was performed and is provided in Attachment 9.

Risk associated with seismic, external flooding, and high winds due to hurricanes were evaluated qualitatively and found to be insignificant risk contributors for this application. The seismic hazard does not have a RG 1.200 PRA model, but is evaluated using a bounding analysis in Attachment 10. With this one-time TS Completion Time being established outside of hurricane season, the External Flooding and straight line wind speed risk are negligible and not quantified. Hurricanes are the mechanism for both of these hazards.

3.2.1.2 One-Time Completion Time Extension Model Changes The following changes were made to the baseline models to form the application-specific model configuration:

1. The EDG 4 start failure basic event was set to a failure probability of 1.0 to reflect the diesel generator being out of service during the extended Completion Time.

2. The SUPP-DG is assumed to be protected during the extended completion time and that is reflected in the model by setting the test and maintenance of the SUPP-DG to 0.0.

3. All analyzed models were analyzed for the at-power (i.e., Modes 1, 2, and 3) condition to determine CDF and LERF significance.

4. Common cause failure events associated with the EDGs common cause component group were increased as discussed in Attachment 7, Section 3.1.

3.2.1.3 Quantitative Risk Results The following acceptance guidelines from Regulatory Guide 1.177 are applicable for evaluating the risk associated with a one-time only Completion Time change:

ICCDP of less than 1.0E-06 and ICLERP of less than 1.0E-07, or ICCDP of less than 1.0E-05 and ICLERP of less than 1.0E-06 with effective compensatory measures implemented to reduce the sources of increased risk The ICCDP and ICLERP are estimated for the limiting case CDF/LERF values (i.e., Unit 2) based on an overall EDG 4 Completion Time of 44 days, including the 14 days associated with the current TS limit.

BSEP 17-0111 Enclosure Page 18 of 31 ICCDP and ICLERP for Technical Specification Extension Configuration ICCDP ICLERP (44 Days) (44 Days)

Unit 2 - EDG 4 Out of Service 2.76E-07 5.95E-09 Configuration These risk results are well within the acceptance guidelines in RG 1.177 for one-time Completion Time changes. Attachment 7 provides additional details for the quantification of these results and Attachment 11 provides listings of top cut sets for the quantified sequences.

3.2.2 Tier 2: Avoidance of Risk Significant Plant Configurations Risk insights from the Tier 1 risk analysis results were used to further evaluate risk significant configurations and other actions that could be taken to avoid or mitigate risk. This evaluation was conducted by the review of dominant cut sets and importance measures rankings.

3.2.2.1 Risk Insights for Internal Events The internal events cut sets for this application were reviewed for CDF and LERF. Diesel generator redundancy for EDGs 1, 2, and 3 is not contributing significantly to the delta risk. The majority of the top 25 cut sets are long term loss of decay heat removal sequences with a unit switchyard centered loss of offsite power initiating event. The primary contributor to these sequences is the failure of the operator to cross-tie 4 kV and 480 V AC emergency busses.

This in turn fails one or more valves preventing the success of suppression pool cooling and reactor injection. Failure to align power from the SUPP-DG is also a significant contributor to risk.

The following are compensatory actions that will be in place during the extended Completion Time which will help substantially mitigate the added Internal Events risk from having the EDG 4 out of service:

The SUPP-DG, FLEX diesel generators, station batteries, battery chargers, switchyard, and transformer yard shall be protected, as defense-in-depth, during the extended EDG Completion Times authorized by the proposed license amendment.

Discretionary switchyard maintenance shall not be allowed during the extended EDG Completion Times authorized by the proposed licensed amendment.

During the extended EDG Completion Times authorized by the proposed license amendment, designated non-licensed operators (NLOs) shall be briefed, each shift, regarding cross tying the 4160 V emergency bus E2 to 4160 V emergency bus E4 per plant procedures.

During the extended EDG Completion Times authorized by the proposed license amendment, designated NLOs will be briefed, each shift, regarding cross-tying 480 V E7 bus to the 480 V E8 bus per plant procedures.

During the extended EDG Completion Times authorized by the proposed license amendment, designated NLOs will be briefed, each shift, regarding starting and tying the SUPP-DG to 4160 V emergency bus E4 per plant procedures.

BSEP 17-0111 Enclosure Page 19 of 31 3.2.2.2 Risk Insights for Fire Events The results of the Fire delta CDF and delta LERF cut sets were reviewed for dominant accident sequences and overall contributors. The following two categories of sequences generally define the majority of important contributors to the top 25 delta cut sets.

1. Fire event in Switchgear Bus 2D results in SBO followed by failure to cross-tie power to support long-term suppression pool cooling followed by failure to align Fire Water injection. The risk from this sequence is mitigated by the following planned compensatory measures planned during the EDG 4 extended TS Completion Time:

During the extended EDG Completion Times, a continuous fire watch shall be established for the Unit 1 and Unit 2 Cable Spread Rooms and for the Balance of Plant busses in the Unit 1 and Unit 2 Turbine Building 20 foot elevations.

During the extended EDG Completion Times, designated non-licensed operators (NLOs) shall be briefed, each shift, regarding cross tying the 4160 V emergency bus E2 to 4160 V emergency bus E4 per plant procedures

2. Fire event in Control Room cabinet leading to a loss of offsite power followed by failure to cross-tie power to support long-term decay heat removal.

Fire events in the control room cabinet area are assumed to be readily noticeable and the presence of a continuous fire watch in these areas would not significantly affect the outcome. However, operators successfully cross tying AC power would significantly reduce the risk in this scenario and all others reviewed.

3.2.2.3 Other Hazards The risk insights for other hazards did not specifically warrant additional compensatory measures; however, it was noted that actions taken for internal events also provide some small risk reductions for other hazards such as internal flooding.

The potential increase in risk from high winds or external flooding is negligible due to the plants design and the expected weather conditions during the exposure period. Weather conditions are monitored continually, and if a threat of severe weather or flooding develops, site preparations will be made in accordance with plant emergency response procedures for the anticipated conditions.

3.2.2.4 Component Evaluation Tier 2 evaluations are used to identify high risk equipment that could exist if they are taken out of service along with the equipment involved in the TS change. To address Tier 2 concerns, the cut set results for the Unit 2 internal events model were 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 as the EDG 4 during the extended Completion Time.

BSEP 17-0111 Enclosure Page 20 of 31 Tier 2 Component Evaluation T&M Event Component RAW RHR2PTF-TM-LOOPA RHR Loop A 9.4 DCP2REC-TM2A2 Charger 2A-2 7.6 EDG2XHE-MN-DG3 EDG#3 5.7 EDG1XHE-MN-DG1 EDG#1 3.2 EDG1XHE-MN-DG2 EDG#2 2.1 CSS2XHE-MN-C001A CSP A 1.6 RCI2XHE-MNRCIC RCIC 1.1 FPS0XHE-MN-FPV57 Valve 2-FP-V57 1.1 DCP2REC-TM2A1 Charger 2A-1 1.1 CRD2XHE-MN-PMPA CRD Train A 1.0 In addition to the integrated risk management strategy in place at BSEP as described in the Tier 3 evaluation, the following controls will be in place for the duration of the extended TS Completion Time that will mitigate the high risk equipment test and maintenance configurations identified in the above table.

EDGs 1, 2, and 3 shall be protected during the extended EDG 4 completion time The SUPP-DG, FLEX diesel generators, station batteries, battery chargers, switchyard, and transformer yard shall be protected High Pressure Coolant Injection (HPCI), Reactor Core Isolation Cooling (RCIC), and Residual Heat Removal (RHR) systems will be protected. These controls provide assurance that high risk component configurations involved with the EDG 4 extended TS Completion Time will be avoided, and will remain in place during the duration of the Completion Time.

3.2.3 Tier 3: Configuration Risk Management 3.2.3.1 Maintenance Rule Risk Management Program The proposed LAR will not result in any significant changes to the current configuration risk management program for the Maintenance Rule, 10 CFR 50.65(a)(4). The BSEP on-line computerized risk software (i.e., Equipment Out Of Service or EOOS) considers internal initiating events including LOOP events, including weather and grid related. Thus, the overall change in plant risk during maintenance activities is expected to be addressed adequately considering the proposed amendment.

BSEP has several administrative procedures in place to ensure that risk significant plant configurations are avoided. These documents are used to address the Maintenance Rule requirements, including the on-line and off-line Maintenance Policy requirement to control the

BSEP 17-0111 Enclosure Page 21 of 31 safety impact of combinations of equipment removed from service. The key documents are as follows:

AD-WC-ALL-0410, Work Activity Integrated Risk Management 0AP-025, BNP Integrated Scheduling AD-NF-ALL-0501, Electronic Risk Assessment Tool (ERAT)

More specifically, the administrative procedures referenced above address the process, define the program, and state individual group responsibilities to ensure compliance with the Maintenance Rule. The Work Process Manual procedures provide a consistent process for utilizing the computerized software assessment tool, EOOS, which manages the risk associated with equipment inoperability.

EOOS is a Windows-based computer program used to facilitate risk informed decision making associated with station work activities. Its guidelines are independent of the requirements of the Technical Specifications and Technical Requirements Manual and are based on probabilistic risk assessment studies and deterministic approaches.

Additionally, prior to the release of work for execution, Operations personnel must consider the effects of severe weather and grid instabilities on plant operations. Responses to actual plant risk due to severe weather or grid instabilities are programmatically incorporated into applicable plant emergency or response procedures.

The key safety significant systems impacted by this proposed LAR are currently included in the Maintenance Rule program, and as such, availability and reliability performance criteria have been established to assure that they perform adequately.

3.2.3.2 Traditional Engineering Considerations For a potential SBO during the proposed Completion Time extensions, the SUPP-DG will be available to mitigate the accident, and the units will remain within the bounds of the accident analyses. In addition, there would be no adverse impact to the units, because the Safety Function Determination Program (SFDP) will be utilized to ensure that cross-train checks are performed to ensure a loss of safety function does not go undetected. The SFDP will also ensure appropriate actions are taken if a loss of safety function is identified. Since the probability of a loss of safety function going undetected during the planned maintenance window is low, there is minimal safety impact due to the proposed Completion Time extensions for the inoperable EDG.

The combination of defense-in-depth and safety margin principles inherent in the onsite emergency power system ensures an emergency supply of power will be available to perform the required safety function. These elements of defense-in-depth and safety margin support a Completion Time extension to 44 days to allow EDG 4 to be out-of-service for a longer period of time, as discussed further below.

3.2.3.3 Defense-in-Depth The proposed change to the Completion Times for EDG 4 out-of-service maintains system redundancy, independence and diversity commensurate with the expected challenges to system operation. The other EDGs, offsite sources of power and the associated engineered safety equipment will remain operable and the SUPP-DG will remain available to mitigate the

BSEP 17-0111 Enclosure Page 22 of 31 consequences of any previously analyzed accident. Otherwise, the SFDP will require that a loss of safety function be declared, and the appropriate TS Conditions and Required Actions taken. In addition to the SFDP, the Work Management process provides for controls and assessments to preclude the possibility of simultaneous outages of redundant trains and to ensure system reliability. The proposed increase in the Completion Times associated with the inoperable BSEP EDG 4 will not alter the assumptions relative to the causes or mitigation of an accident.

With the single EDG 4 inoperable at BSEP, a loss of function has not occurred. The remaining offsite power sources and EDGs 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 philosophy is maintained if the following occurs regarding the proposed licensing basis change:

A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation.

BSEP has already installed an additional AC power supply (i.e., SUPP-DG), which will ensure a reasonable balance is preserved between prevention of core damage, prevention of containment failure and consequence mitigation for the proposed extensions to the current BSEP TS 3.8.1 Completion Time for the inoperable EDG 4 to 44 days. The proposed Completion Time extensions will not significantly reduce the effectiveness of any of the following four layers of defense that exist in the BSEP plant design: minimizing challenges to the plants, preventing any events from progressing to core damage, containing the radioactive source term and emergency preparedness. Extending the Completion Times for the inoperable EDG 4 does not increase the likelihood of initiating events and does not create new initiating events.

Furthermore, the proposed Completion Time extensions do not significantly impact the availability and reliability of SSCs that are relied upon to perform safety functions that prevent plant challenges from progressing to core damage. Lastly, the proposed change does not significantly impact the containment function or SSCs that support the containment function and also does not involve the emergency preparedness program or any of its functions.

Over-reliance on programmatic activities as compensatory measures associated with the change in the licensing basis is avoided.

A supplemental power source (i.e., the SUPP-DG at BSEP) has been permanently installed and is available as a backup to the inoperable EDG 4 to maintain the defense-in-depth design philosophy for the electrical power system to meet its intended safety function. The SUPP-DG (i.e., plant equipment) at BSEP reduces the reliance on programmatic activities as compensatory measures associated with the proposed TS Completion Time change. In addition to the SUPP-DG, BSEP has obtained additional temporary diesel generators, as added defense, in case the SUPP-DG fails when needed.

Plant safety systems are designed with redundancy so that when one train is inoperable, a redundant train can provide the necessary safety function. The preferred approach at BSEP for accomplishing safety functions is through engineered systems, rather than overreliance on programmatic activities (i.e., compensatory measures). During the timeframe that EDG 4 is inoperable at BSEP, an existing redundant source of power is maintained operable. As previously highlighted, in the event other equipment becomes inoperable concurrent with the

BSEP 17-0111 Enclosure Page 23 of 31 EDG inoperability, the SFDP requires cross-division checks to ensure a loss of safety function does not go undetected. If a loss of safety function is identified at BSEP, 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.

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

no risk outliers).

The redundancy, independence, and diversity of the onsite emergency power system at BSEP will be maintained during the Completion Time extensions. There were no identified uncertainties in redundancy, independence, and diversity with the introduction of the extended Completion Time to 44 days. The installed supplemental AC power source at BSEP (i.e.,

SUPP-DG) is not susceptible to the same common cause failures as the EDGs since the SUPP-DG has a different manufacturer, operates at different speeds, has different starting systems, etc. The added temporary diesel generators are also independent from common cause due to differences in design and maintenance.

Defenses against potential 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 created as a result of the proposed change to extend the BSEP Completion Times for the inoperable EDG 4. The SUPP-DG does not have any common linkage with the EDGs at BSEP beyond the potential for the same personnel that perform the maintenance on the equipment. The operating environment and operating parameters for the BSEP EDGs remains constant; therefore, new common cause failure modes are not introduced.

Redundant and backup systems are not impacted by the proposed change and no new common cause links between the primary and backup systems are introduced.

Independence of barriers is not degraded.

The barriers protecting the public and the independence of these barriers are maintained at BSEP. Multiple EDGs, systems, and electrical distribution systems will not be taken out-of-service simultaneously, as that could lead to degradation of the barriers and an increase in risk to the public. In the event other equipment becomes inoperable concurrent with the BSEP EDG 4 inoperability, the SFDP 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 at BSEP will require entry into the applicable Conditions and Required Actions for the system that possesses the loss of safety function.

Furthermore, BSEP TS 3.8.1 requires declaring required feature(s) supported by the inoperable EDG, inoperable when its redundant required feature(s) are inoperable. The particular Required Action is intended to provide assurance that a loss of offsite power, during the period that a EDG is inoperable, does not result in a complete loss of safety function of critical systems. These required features within the context of TS 3.8.1 are designed to be powered from redundant safety related 4.16 kV emergency busses. Redundant required feature failures consist of inoperable features associated with an emergency bus redundant to the emergency bus that has an inoperable DG.

BSEP 17-0111 Enclosure Page 24 of 31 In addition, the extended Completion Times do not provide a mechanism that degrades the independence of the barriers at BSEP; fuel cladding, reactor coolant system and containment.

Defenses against human errors are preserved.

The proposed extensions to the BSEP Completion Times do not introduce any new operator actions for the existing plant equipment. Operators are required to align and operate the supplemental AC power source (i.e., SUPP-DG). Licensed Operators and Auxiliary Operators are appropriately trained on the purpose and use of the SUPP-DG and associated procedural actions.

The intent of the plants design criteria is maintained.

The design and operation of the BSEP EDGs are not altered by the proposed Completion Time extensions. The safety analyses safety criteria stated in the BSEP UFSAR are not impacted by the proposed change. Redundancy and diversity of the EDGs are not altered because the system design and operation are not changed by the proposed Completion Time extensions.

The proposed change to the BSEP TS will not allow plant operation in a configuration outside the plants design basis. The requirements credited in the accident analyses regarding the EDGs will remain the same.

3.2.3.4 Safety Margin In the proposed extended Completion Times for the inoperable EDG 4, the plant remains in a condition for which it has already been analyzed; therefore, from a deterministic perspective, the proposed TS change is acceptable. The 44 day Completion Time is a risk-informed Completion Time based on plant specific analyses using the methodology defined in this license amendment request.

Furthermore, the already installed supplemental AC power source (i.e., SUPP-DG) at BSEP supports this exigent TS change request with the capability to power any essential bus within one hour from the time that the SBO emergency procedures direct its use as the emergency power source. The SUPP-DG will have the capacity to bring the affected unit to cold shutdown.

The evaluation that follows, using the principles defined in RG 1.174, demonstrates that the proposed licensing basis change for BSEP is consistent with the principle that sufficient safety margins are maintained.

With sufficient safety margins, the following are true for BSEP:

Codes and standards or their alternatives approved for use by the NRC are met.

The design and operation of the BSEP EDGs is not altered by the proposed Completion Time extensions. Redundancy and diversity of the electrical distribution system will be maintained.

The SUPP-DG at BSEP provides an additional AC power source as a defense-in-depth measure for SBO.

Safety analysis acceptance criteria in the LB (e.g., FSAR, supporting analyses) are met or proposed revisions provide sufficient margin to account for analysis and data uncertainty.

BSEP 17-0111 Enclosure Page 25 of 31 The safety analyses acceptance criteria stated in the BSEP UFSAR is not impacted by the proposed change. The proposed change will not allow plant operation in a configuration outside the design basis. The requirements regarding the EDGs credited in the BSEP accident analyses will remain the same.

Given the above, Duke Energy concludes that safety margins are not impacted by the proposed one-time TS Completion Time change.

3.2.4 Conclusions The analysis for the one time TS Completion Time extension of the EDG 4 shows that the risk from having the EDG out of service for a total of 44 days is acceptable from a quantitative and qualitative risk standpoint. The risk incurred from this one time TS Completion Time extension meets the criteria as outlined in RG 1.177. Where a qualitative analysis was used, the discussion shows that the risk from known sources is minimal and would not impact the overall results of the application.

3.3 Compensatory Actions The following compensatory measures were implemented to support proposed extended Completion Times of Required Action D.5. They will remain in place during the proposed extended Completion Times.

EDGs 1, 2, and 3 shall be protected during the extended EDG Completion Times authorized by the proposed license amendment.

The SUPP-DG, FLEX diesel generators, station batteries, battery chargers, switchyard, and transformer yard shall be protected, as defense-in-depth, during the extended EDG Completion Times authorized by the proposed license amendment.

Component testing or maintenance of safety systems in the off-site power systems and important non-safety equipment in the off-site power systems which can increase the likelihood of a plant transient or LOOP, as determined by plant management, will be avoided during the extended EDG Completion Times authorized by the proposed license amendment.

Discretionary switchyard maintenance shall not be allowed during the extended EDG Completion Times authorized by the proposed licensed amendment.

The High Pressure Coolant Injection (HPCI) pump, Reactor Core Isolation Cooling (RCIC) pump, and the Residual Heat Removal (RHR) pump associated with the operable EDG will not be removed from service for elective maintenance activities during the extended EDG Completion Times authorized by the proposed license amendment.

The system load dispatcher shall be contacted once per day to determine if any significant grid perturbations (i.e., high grid loading unable to withstand a single contingency of line or generation outage) are expected during the extended Completion Times authorized by the proposed license amendment. If significant grid perturbations are expected, station managers will assess the conditions and determine the best course for the plant.

During the extended EDG Completion Times authorized by the proposed license amendment, weather conditions shall be monitored each shift to determine if

BSEP 17-0111 Enclosure Page 26 of 31 forecasts are predicting severe weather conditions (e.g., thunderstorm or tornado warnings). If severe weather is expected, station managers will assess the conditions and determine the best course for the plant.

Additionally, the following compensatory actions associated with the Operations staff will be implemented during the proposed extended Completion Times of Required Action D.5.

During the extended EDG Completion Times authorized by the proposed license amendment, designated non-licensed operators (NLOs) shall be briefed, each shift, regarding cross tying the 4160 V emergency bus E2 to 4160 V emergency bus E4 per plant procedure 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

During the extended EDG Completion Times authorized by the proposed license amendment, designated NLOs will be briefed, each shift, regarding cross-tying 480 V E7 bus to the 480 V E8 bus per 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

During the extended EDG Completion Times authorized by the proposed license amendment, designated NLOs will be briefed, each shift, regarding starting and tying the SUPP-DG to 4160 V emergency bus E4 per plant procedure 0EOP-01-SBO-08, Supplemental DG Alignment.

During the extended EDG Completion Times authorized by the proposed license amendment, designated NLOs will be briefed, each shift, regarding load shed procedures and alignment of the FLEX diesel generators.

During the extended EDG Completion Times authorized by the proposed license amendment, a continuous fire watch shall be established for the Unit 1 and Unit 2 Cable Spread Rooms and for the Balance of Plant busses in the Unit 1 and Unit 2 Turbine Building 20 foot elevations.

During the extended EDG Completion Times authorized by the proposed license amendment, the FLEX pump and FLEX Unit 2 hose trailer shall be staged at the south side of the Unit 2 Condensate Storage Tank to support rapid deployment in the event the FLEX pump is needed for Unit 2 inventory control.

For the compensatory measures described above, Duke Energy is providing operating license conditions to be included in Appendix B, Additional Conditions, of the Renewed Facility Operating Licenses for BSEP, Units 1 and 2. These license conditions describe compensatory measures being implemented during the proposed extended Completion Time. Attachment 3 to this letter provides the updated Operating License, Appendix B pages for each unit.

Consistent with the Bases for TS 3.8.1, Required Action D.2, the SUPP-DG availability was verified within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of entering the 14 day Completion Time and every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter.

SUPP-DG availability requires that:

The load test has been performed within 30 days of entry into the extended Completion Time.

The SUPP-DG fuel tank test is verified locally to be greater than or equal to a 24-hour supply; and SUPP-DG supporting system parameters for starting and operating are verified to be within required limits for functional availability.

BSEP 17-0111 Enclosure Page 27 of 31

4. REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 10 CFR 50.36(c)(2)(ii), stipulates that a TS Limiting Condition for Operation must be established for each item meeting one or more of the following criteria:

Installed instrumentation that is used to detect, and indicate in the Control Room, a significant abnormal degradation of the reactor coolant pressure boundary.

A process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of, or presents a challenge to the integrity of a fission product barrier.

A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

A structure, system, or component which operating experience or PRA has shown to be significant to public health and safety.

The proposed changes do not modify any plant equipment that provides emergency power to the safety-related emergency busses. Evaluation of the proposed changes has determined that the reliability of AC electrical sources is not significantly affected by the proposed changes and that applicable regulations and requirements continue to be met.

The BSEP design was reviewed for construction under the General Design Criteria for Nuclear Power Plant Construction, issued for comment by the Atomic Energy Commission (AEC) in July 1967 and is committed to meet the intent of the General Design Criteria (GDC), published in the Federal Register on May 21, 1971, as Appendix A to 10 CFR Part 50. GDC 17 requires that that nuclear power plants have onsite and offsite electric power systems to permit the functioning of SSCs that are important to safety. The onsite system is required to have sufficient independence, redundancy, and testability to perform its safety function, assuming a 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 BSEPs compliance with the intent of GDC 18.

Section 50.63(a) of 10 CFR, Loss of all alternating current power, requires that each lightwater-cooled nuclear power plant 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 10 CFR 50.63(a).

NUREG-0800, Branch Technical Position (BTP) 8-8, Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions, provides guidance to the NRC staff in

BSEP 17-0111 Enclosure Page 28 of 31 reviewing amendment requests for licensees proposing a one-time or permanent TS change to extend an EDG Completion Times to beyond 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The BTP 8-8 emphasizes that more defense-in-depth is needed for SBO scenarios which are more likely to occur as compared to the likely occurrence of the large and medium size LOCA scenarios. The proposed amendment is consistent with the guidance of BTP 8-8.

Therefore, based on the considerations discussed above:

1. There is a reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner;

2. Such activities will be conducted in compliance with the Commission's regulations; and

3. Issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

Duke Energy has determined that the proposed change does not require any exemptions or relief from regulatory requirements, other than the TS, and does not affect conformance with the intent of any GDC differently than described in the Safety Analysis Report.

4.2 Precedent The proposed license amendment was developed using relevant information from an approved change (i.e., Reference 7) at another nuclear station, as well as Duke Energy's November 22, 2017, LAR and associated November 26, 2017, NRC Safety Evaluation (i.e., References 1 and 2).

4.3 No Significant Hazards Consideration Determination Analysis Duke Energy Progress, LLC (Duke Energy), is requesting that, on a one-time basis, the Completion Time for Technical Specification 3.8.1, Required Action D.5, be extended from the original 14 days to 44 days for Emergency Diesel Generator 4 (EDG 4). A commensurate change is also proposed to extend the maximum Completion Time of Required Action D.5 associated with discovery of failure to meet Limiting Condition for Operation (LCO) LCO 3.8.1.a or b (i.e., from the original 17 days to 47 days). The exigent license amendment request is requested in order to avoid an unnecessary shutdown of both Brunswick Steam Electric Plant (BSEP), Units 1 and 2 without a commensurate benefit in nuclear safety. In order to minimize risk, consistent with defense-in-depth philosophy, Duke Energy is also requesting to suspend monthly testing of EDGs 1, 2, and 3 per Surveillance Requirement (SR) 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the proposed extended Completion Times.

Duke Energy has evaluated whether 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 change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The proposed license amendment provides a one-time 44 day Completion Time allowance in TS 3.8.1, Required Action D.5 for one EDG and a commensurate change to extend the maximum Completion Time of Required Action D.5 (i.e., from the original

BSEP 17-0111 Enclosure Page 29 of 31 17 days to 47 days) and suspension of SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6. These changes will have no effect on accident probabilities since the EDGs are not considered accident initiators. The proposed Completion Times and surveillance suspension do not require any physical plant modifications. Since no individual precursors of an accident are affected, the proposed amendment does not increase the probability of a previously analyzed event.

The consequences of an evaluated accident are determined by the operability of plant systems designed to mitigate those consequences. The EDGs are backup power to components that mitigate the consequences of accidents. The current TSs normally permit a single EDG to be inoperable for up to 14 days. This is acceptable provided the SUPP-DG is available. The proposed license amendment extends the current Completion Times for EDG 4, on a one-time basis, to no more than a total of 44 days with a corresponding maximum completion time of 47 days. The proposed change does not affect any of the assumptions used in deterministic safety analysis. Likewise, the temporary suspension of SR 3.8.1.2, SR 3.8.1.3 and SR 3.8.1.6 has no impact on any of the assumptions used in deterministic safety analysis. Granting the proposed change will not adversely affect the consequences of an accident previously evaluated.

Therefore, the proposed amendment does not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

Response: No Creation of the possibility of a new or different kind of accident requires creating one or more new accident precursors. New accident precursors may be created by modifications of plant configuration, including changes in allowable modes of operation.

The proposed amendment provides a one-time allowance of a 44 day Completion Time for TS 3.8.1, Required Action D.5 and a commensurate change to extend the maximum Completion Time of Required Action D.5 (i.e., from the original 17 days to 47 days). In conjunction, the proposed amendment provides a temporary suspension of SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6. These changes do not involve a modification or the physical configuration of the plant (i.e., no new equipment will be installed), create any new failure modes for existing equipment, or create any new limiting single failures. The plant equipment considered available when evaluating the existing Completion Times remains unchanged. The extended Completion Times and the temporary suspension of SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 will permit completion of repair activities without incurring transient risks associated with performing a dual unit shutdown with the EDG unavailable.

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

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

Response: No

BSEP 17-0111 Enclosure Page 30 of 31 The proposed license amendment provides a, risk-informed, one-time allowance of a 44 day Completion Time for TS 3.8.1, Required Action D.5. A commensurate change is also proposed to extend the maximum Completion Time of Required Action D.5 (i.e., from the original 17 days to 47 days). A deterministic evaluation of the proposed Completion Times demonstrates there is sufficient margin to safety during the extended EDG Completion Time period. During the extended completion times, sufficient compensatory measures including availability of the SUPP-DG will be established to maintain the defense-in-depth design philosophy to ensure the electrical power system meets its design safety function. The SUPP-DG has the capacity to bring an affected unit to cold shutdown, if needed.

The overall risk of not performing SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 during the extended Completion Times is minimal and is consistent with defense-in-depth philosophy. The time period of the temporary suspension is short and historical routine performances of SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 have demonstrated good performance of the EDGs. The proposed suspension of performing SR 3.8.1.2, SR 3.8.1.3, and SR 3.8.1.6 is consistent with the philosophy of SR 3.0.3 in that it is based on the consideration of unit conditions and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the requirements.

Therefore, the proposed amendment does not result in a significant reduction in the margin of safety.

Based on the above, Duke Energy concludes that the proposed amendment presents no 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.

4.4 Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions 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.

5. ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or a significant increase in the amounts of any effluents 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.

BSEP 17-0111 Enclosure Page 31 of 31

6. REFERENCES

1. Letter from Duke Energy to the U.S. Nuclear Regulatory Commission, Request for Emergency License Amendment - Technical Specification 3.8.1, AC Sources -

Operating, One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements, dated November 22, 2017, ADAMS Accession Number ML17326B619

2. Letter from the U.S. Nuclear Regulatory Commission to Duke Energy BSEP, Issuance of Amendments For Technical Specification 3.8.1, AC [Alternating Current] Sources -

Operating One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements (Emergency Situation), dated November 26, 2017 ADAMS Accession Number ML17328B072

3. 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

4. NUREG-0800, Branch Technical Position (BTP) 8-8, Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions, dated February 2012 (i.e., ADAMS Accession No. ML113640138)

5. Letter from the NRC to BSEP, Issuance of Amendments Regarding request to Relocate Specific Surveillance Frequencies to Licensee Controlled Program, May 24, 2017 (ADAMS Accession No. ML ML17096A129)

6. Letter from NRC to BSEP, Issuance of Amendment Regarding Transition to a Risk-Informed, Performance-Based Fire Protection Program in Accordance With 10 CFR 50.48(c), dated January 28, 2015, (ADAMS Accession Number ML14310A808)

7. Letter from NRC to Palo Verde Nuclear Generating Station, Unit 3, Issuance of Amendment Regarding Revision to Technical Specification 3.8.1, "AC [Alternating Current] Sources - Operating" (Emergency Circumstances), dated December 23, 2016, (ADAMS Accession Number ML16358A676)

BSEP 17-0111 Enclosure Attachment 1 Proposed Technical Specification Changes (Mark-Up)

Unit 1

AC SourcesOperating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. (continued) D.5 Restore DG to OPERABLE ---------NOTE----------

status. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, the 14 day and 17 day Completion Times are extended to 44 days and 47 days, respectively.

7 days from 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. 282

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power In accordance with availability for each offsite circuit. the Surveillance Frequency Control Program SR 3.8.1.2 -------------------------------NOTES-------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met.

3. A single test at the specified Frequency will satisfy this Surveillance for both units.

4. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.2 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify each DG starts from standby conditions and In accordance with achieves steady state voltage 3750 V and 4300 V the Surveillance and frequency 58.8 Hz and 61.2 Hz. Frequency Control Program (continued)

Brunswick Unit 1 3.8-7 Amendment No. 282

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 -------------------------------NOTES-------------------------------

1. DG loadings may include gradual loading.

2. Momentary transients outside the load range do not invalidate this test.

3. This Surveillance shall be conducted on only one DG at a time.

4. This SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.7.

5. A single test at the specified Frequency will satisfy this Surveillance for both units.

6. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.3 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify each DG is synchronized and loaded and In accordance with operates for 60 minutes at a load 2800 kW and the Surveillance 3500 kW. Frequency Control Program SR 3.8.1.4 Verify each engine mounted tank contains 150 gal of In accordance with fuel oil. the Surveillance Frequency Control Program SR 3.8.1.5 Check for and remove accumulated water from each In accordance with engine mounted tank. the Surveillance Frequency Control Program (continued)

Brunswick Unit 1 3.8-8 Amendment No. 282

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.6 -------------------------------NOTE-------------------------------

Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.6 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify the fuel oil transfer system operates to transfer In accordance with fuel oil from the day fuel oil storage tank to the engine the Surveillance mounted tank. Frequency Control Program SR 3.8.1.7 -------------------------------NOTES------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG starts from standby condition and In accordance with achieves, in 10 seconds, voltage 3750 V and the Surveillance frequency 58.8 Hz, and after steady state conditions Frequency Control are reached, maintains voltage 3750 V and 4300 V Program and frequency 58.8 Hz and 61.2 Hz.

(continued)

Brunswick Unit 1 3.8-9 Amendment No. 282

BSEP 17-0111 Enclosure Attachment 2 Proposed Technical Specification Changes (Mark-Up)

Unit 2

AC SourcesOperating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. (continued) D.5 Restore DG to OPERABLE ---------NOTE----------

status. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, the 14 day and 17 day Completion Times are extended to 44 days and 47 days, respectively.

7 days from 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. 310

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power In accordance with availability for each offsite circuit. the Surveillance Frequency Control Program SR 3.8.1.2 -------------------------------NOTES-------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met.

3. A single test at the specified Frequency will satisfy this Surveillance for both units.

4. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.2 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify each DG starts from standby conditions and In accordance with achieves steady state voltage 3750 V and 4300 V the Surveillance and frequency 58.8 Hz and 61.2 Hz. Frequency Control Program (continued)

Brunswick Unit 2 3.8-7 Amendment No. 310

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 ----------------------------NOTES----------------------------------

1. DG loadings may include gradual loading.

2. Momentary transients outside the load range do not invalidate this test.

3. This Surveillance shall be conducted on only one DG at a time.

4. This SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.7.

5. A single test at the specified Frequency will satisfy this Surveillance for both units.

6. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.3 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify each DG is synchronized and loaded and In accordance with operates for 60 minutes at a load 2800 kW and the Surveillance 3500 kW. Frequency Control Program SR 3.8.1.4 Verify each engine mounted tank contains 150 gal of In accordance with fuel oil. the Surveillance Frequency Control Program SR 3.8.1.5 Check for and remove accumulated water from each In accordance with engine mounted tank. the Surveillance Frequency Control Program (continued)

Brunswick Unit 2 3.8-8 Amendment No. 310

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.6 -------------------------------NOTE-------------------------------

Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.6 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify the fuel oil transfer system operates to transfer fuel oil from the day fuel oil storage tank to the engine In accordance with mounted tank. the Surveillance Frequency Control Program SR 3.8.1.7 ----------------------------NOTES----------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG starts from standby condition and In accordance with achieves, in 10 seconds, voltage 3750 V and the Surveillance frequency 58.8 Hz, and after steady state conditions Frequency Control are reached, maintains voltage 3750 V and 4300 V Program and frequency 58.8 Hz and 61.2 Hz.

(continued)

Brunswick Unit 2 3.8-9 Amendment No. 310

BSEP 17-0111 Enclosure Attachment 3 Revised (Typed) Technical Specification Pages Unit 1

AC SourcesOperating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. (continued) D.5 Restore DG to OPERABLE ---------NOTE----------

status. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, the 14 day and 17 day Completion Times are extended to 44 days and 47 days, respectively.

7 days from 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. 283

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power In accordance with availability for each offsite circuit. the Surveillance Frequency Control Program SR 3.8.1.2 -------------------------------NOTES-------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met.

3. A single test at the specified Frequency will satisfy this Surveillance for both units.

4. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.2 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify each DG starts from standby conditions and In accordance with achieves steady state voltage 3750 V and 4300 V the Surveillance and frequency 58.8 Hz and 61.2 Hz. Frequency Control Program (continued)

Brunswick Unit 1 3.8-7 Amendment No. 283

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 -------------------------------NOTES-------------------------------

1. DG loadings may include gradual loading.

2. Momentary transients outside the load range do not invalidate this test.

3. This Surveillance shall be conducted on only one DG at a time.

4. This SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.7.

5. A single test at the specified Frequency will satisfy this Surveillance for both units.

6. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.3 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify each DG is synchronized and loaded and In accordance with operates for 60 minutes at a load 2800 kW and the Surveillance 3500 kW. Frequency Control Program SR 3.8.1.4 Verify each engine mounted tank contains 150 gal of In accordance with fuel oil. the Surveillance Frequency Control Program SR 3.8.1.5 Check for and remove accumulated water from each In accordance with engine mounted tank. the Surveillance Frequency Control Program (continued)

Brunswick Unit 1 3.8-8 Amendment No. 283

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.6 -------------------------------NOTE-------------------------------

Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.6 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify the fuel oil transfer system operates to transfer In accordance with fuel oil from the day fuel oil storage tank to the engine the Surveillance mounted tank. Frequency Control Program SR 3.8.1.7 -------------------------------NOTES------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG starts from standby condition and In accordance with achieves, in 10 seconds, voltage 3750 V and the Surveillance frequency 58.8 Hz, and after steady state conditions Frequency Control are reached, maintains voltage 3750 V and 4300 V Program and frequency 58.8 Hz and 61.2 Hz.

(continued)

Brunswick Unit 1 3.8-9 Amendment No. 283

BSEP 17-0111 Enclosure Attachment 4 Revised (Typed) Technical Specification Pages Unit 2

AC SourcesOperating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. (continued) D.5 Restore DG to OPERABLE ---------NOTE----------

status. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, the 14 day and 17 day Completion Times are extended to 44 days and 47 days, respectively.

7 days from 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. 311

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power In accordance with availability for each offsite circuit. the Surveillance Frequency Control Program SR 3.8.1.2 -------------------------------NOTES-------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met.

3. A single test at the specified Frequency will satisfy this Surveillance for both units.

4. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.2 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify each DG starts from standby conditions and In accordance with achieves steady state voltage 3750 V and 4300 V the Surveillance and frequency 58.8 Hz and 61.2 Hz. Frequency Control Program (continued)

Brunswick Unit 2 3.8-7 Amendment No. 311

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 ----------------------------NOTES----------------------------------

1. DG loadings may include gradual loading.

2. Momentary transients outside the load range do not invalidate this test.

3. This Surveillance shall be conducted on only one DG at a time.

4. This SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.7.

5. A single test at the specified Frequency will satisfy this Surveillance for both units.

6. Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.3 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify each DG is synchronized and loaded and In accordance with operates for 60 minutes at a load 2800 kW and the Surveillance 3500 kW. Frequency Control Program SR 3.8.1.4 Verify each engine mounted tank contains 150 gal of In accordance with fuel oil. the Surveillance Frequency Control Program SR 3.8.1.5 Check for and remove accumulated water from each In accordance with engine mounted tank. the Surveillance Frequency Control Program (continued)

Brunswick Unit 2 3.8-8 Amendment No. 311

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.6 -------------------------------NOTE-------------------------------

Until DG 4 is returned to OPERABLE status, not to exceed 0745 EST on December 27, 2017, performance of SR 3.8.1.6 for EDGs 1, 2, and 3 may be suspended. Past due surveillances will be completed within 7 days of restoration of EDG 4 operability or January 3, 2018, whichever occurs first.

Verify the fuel oil transfer system operates to transfer In accordance with fuel oil from the day fuel oil storage tank to the engine the Surveillance mounted tank. Frequency Control Program SR 3.8.1.7 ----------------------------NOTES----------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG starts from standby condition and In accordance with achieves, in 10 seconds, voltage 3750 V and the Surveillance frequency 58.8 Hz, and after steady state conditions Frequency Control are reached, maintains voltage 3750 V and 4300 V Program and frequency 58.8 Hz and 61.2 Hz.

(continued)

Brunswick Unit 2 3.8-9 Amendment No. 311

BSEP 17-0111 Enclosure Attachment 5 Revised (Typed) Operating License Pages Unit 1

(c) Transition License Conditions

1. Before achieving full compliance with 10 CFR 50.48(c), as specified by 2. below, risk-informed changes to the licensees fire protection program may not be made without prior NRC review and approval unless the change has been demonstrated to have no more than a minimal risk impact, as described in 2. above.

2. The licensee shall implement the modifications to its facility, as described in Table S-1, "Plant Modifications Committed," of Duke letter BSEP 14-0122, dated November 20, 2014, to complete the transition to full compliance with 10 CFR 50.48(c) by the startup of the second refueling outage for each unit after issuance of the safety evaluation. The licensee shall maintain appropriate compensatory measures in place until completion of these modifications.

3. The licensee shall complete all implementation items, except item 9, listed in LAR Attachment S, Table S-2, "Implementation Items," of Duke letter BSEP 14-0122, dated November 20, 2014, within 180 days after NRC approval unless the 180th day falls within an outage window; then, in that case, completion of the implementation items, except item 9, shall occur no later than 60 days after startup from that particular outage. The licensee shall complete implementation of LAR Attachment S, Table S-2, Item 9, within 180 days after the startup of the second refueling outage for each unit after issuance of the safety evaluation.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; and is subject to all applicable provisions hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level The licensee is authorized to operate the facility at steady state reactor core power levels not in excess of 2923 megawatts thermal.

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 283, are hereby incorporated in the license. Duke Energy Progress, LLC shall operate the facility in accordance with the Technical Specifications.

For Surveillance Requirements (SRs) that are new in Amendment 203 to Renewed Facility Operating License DPR-71, the first performance is due at the end of the first surveillance interval that begins at implementation of Amendment 203. For SRs that existed prior to Amendment 203, including SRs with modified acceptance criteria and SRs whose frequency of Renewed License No. DPR-71 Amendment No. 283

3. Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 283, are hereby incorporated into this license. Duke Energy Progress, LLC shall operate the facility in accordance with the Additional Conditions.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

J. E. Dyer, Director Office of Nuclear Reactor Regulation Attachments:

1. Unit 1 - Technical Specifications - Appendices A and B Date of Issuance: June 26, 2006 Renewed License No. DPR-71 Amendment No. 283

Amendment Additional Conditions Implementation Number Date 262 The fuel channel bow standard deviation Upon implementation of component of the channel bow model Amendment No. 262.

uncertainty used by ANP-10307PA, AREVA MCPR Safety Limit Methodology for Boiling Water Reactors (i.e., TS 5.6.5.b.11) to determine the Safety Limit Minimum Critical Power Ratio shall be increased by the ratio of channel fluence gradient to the nearest channel fluence gradient bound of the channel measurement database, when applied to channels with fluence gradients outside the bounds of the measurement database from which the model uncertainty is determined.

283 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 283, Diesel Amendment No. 283.

Generators 1, 2, and 3 shall be protected.

283 The SUPP-DG, FLEX diesel generators, station Upon implementation of batteries, battery chargers, switchyard, and Amendment No. 283.

transformer yard shall be protected, as defense-in-depth, during the extended EDG Completion Times authorized by Amendment No. 283.

283 Component testing or maintenance of safety Upon implementation of systems in the off-site power systems and Amendment No. 283.

important non-safety equipment in the off-site power systems which can increase the likelihood of a plant transient or LOOP, as determined by plant management, will be avoided during the extended EDG Completion Times authorized by Amendment No. 283.

283 Discretionary switchyard maintenance shall not Upon implementation of be allowed during the extended EDG Amendment No. 283.

Completion Times authorized by Amendment No. 283.

Brunswick Unit 1 App. B-2 Amendment No. 283

Amendment Additional Conditions Implementation Number Date 283 The High Pressure Coolant Injection (HPCI) Upon implementation of pump, Reactor Core Isolation Cooling (RCIC) Amendment No. 283.

pump, and the Residual Heat Removal (RHR) pump associated with the operable EDGs will not be removed from service for elective maintenance activities during the extended EDG Completion Times authorized by Amendment No. 283.

283 The system load dispatcher shall be contacted Upon implementation of once per day to determine if any significant grid Amendment No. 283.

perturbations (i.e., high grid loading unable to withstand a single contingency of line or generation outage) are expected during the extended Completion Times authorized by Amendment No. 283. If significant grid perturbations are expected, station managers will assess the conditions and determine the best course for the plant.

283 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 283, weather Amendment No. 283.

conditions shall be monitored each shift to determine if forecasts are predicting severe weather conditions (e.g., thunderstorm or tornado warnings). If severe weather is expected, station managers will assess the conditions and determine the best course for the plant.

283 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 283, designated Amendment No. 283.

non-licensed operators (NLOs) shall be briefed, each shift, regarding cross tying the 4160 V emergency bus E2 to 4160 V emergency bus E4 per plant procedure 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

Brunswick Unit 1 App. B-3 Amendment No. 283

Amendment Additional Conditions Implementation Number Date 283 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 283, designated Amendment No. 283.

NLOs will be briefed, each shift, regarding cross-tying 480 V E7 bus to the 480 V E8 bus per 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

283 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 283, designated Amendment No. 283.

NLOs will be briefed, each shift, regarding starting and tying the SUPP-DG to 4160 V emergency bus E4 per plant procedure 0EOP-01-SBO-08, Supplemental DG Alignment.

283 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 283, designated Amendment No. 283.

NLOs will be briefed, each shift, regarding load shed procedures and alignment of the FLEX diesel generators.

283 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 283, a Amendment No. 283.

continuous fire watch shall be established for the Unit 1 Cable Spread Room and for the Balance of Plant busses in the Unit 1 Turbine Building 20 foot elevation.

Brunswick Unit 1 App. B-4 Amendment No. 283

BSEP 17-0111 Enclosure Attachment 6 Revised (Typed) Operating License Pages Unit 2

(c) Transition License Conditions

1. Before achieving full compliance with 10 CFR 50.48(c), as specified by 2. below, risk-informed changes to the licensees fire protection program may not be made without prior NRC review and approval unless the change has been demonstrated to have no more than a minimal risk impact, as described in 2. above.

2. The licensee shall implement the modifications to its facility, as described in Table S-1, "Plant Modifications Committed," of Duke letter BSEP 14-0122, dated November 20, 2014, to complete the transition to full compliance with 10 CFR 50.48(c) by the startup of the second refueling outage for each unit after issuance of the safety evaluation. The licensee shall maintain appropriate compensatory measures in place until completion of these modifications.

3. The licensee shall complete all implementation items, except Item 9, listed in LAR Attachment S, Table S-2, "Implementation Items," of Duke letter BSEP 14-0122, dated November 20, 2014, within 180 days after NRC approval unless the 180th day falls within an outage window; then, in that case, completion of the implementation items, except item 9, shall occur no later than 60 days after startup from that particular outage. The licensee shall complete implementation of LAR Attachment S, Table S-2, Item 9, within 180 days after the startup of the second refueling outage for each unit after issuance of the safety evaluation.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level The licensee is authorized to operate the facility at steady state reactor core power levels not in excess of 2923 megawatts (thermal).

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 311, are hereby incorporated in the license. Duke Energy Progress, LLC shall operate the facility in accordance with the Technical Specifications.

For Surveillance Requirements (SRs) that are new in Amendment 233 to Renewed Facility Operating License DPR-62, the first performance is due at the end of the first surveillance interval that begins at implementation of Amendment 233. For SRs that existed prior to Amendment 233, Renewed License No. DPR-62 Amendment No. 311

M. Mitigation Strategy License Condition Develop and maintain strategies for addressing large fires and explosions and that include the following key areas:

(1) Fire fighting response strategy with the following elements:

1. Pre-defined coordinated fire response strategy and guidance

2. Assessment of mutual aid fire fighting assets

3. Designated staging areas for equipment and materials

4. Command and control

5. Training of response personnel (2) Operations to mitigate fuel damage considering the following:

1. Protection and use of personnel assets

2. Communications

3. Minimizing fire spread

4. Procedures for implementing integrated fire response strategy

5. Identification of readily-available pre-staged equipment

6. Training on integrated fire response strategy

7. Spent fuel pool mitigation measures (3) Actions to minimize release to include consideration of:

1. Water spray scrubbing

2. Dose to onsite responders N. The licensee shall implement and maintain all Actions required by Attachment 2 to NRC Order EA-06-137, issued June 20, 2006, except the last action that requires incorporation of the strategies into the site security plan, contingency plan, emergency plan and/or guard training and qualification plan, as appropriate.

3. Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. 311, are hereby incorporated into this license. Duke Energy Progress, LLC shall operate the facility in accordance with the Additional Conditions.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

J. E. Dyer, Director Office of Nuclear Reactor Regulation Attachments:

1. Unit 2 - Technical Specifications - Appendices A and B Date of Issuance: June 26, 2006 Renewed License No. DPR-62 Amendment No. 311

Amendment Number Additional Conditions Implementation Date 276 Upon implementation of Amendment No. 276 As described in adopting TSTF-448, Revision 3, the determination paragraphs (a), (b),

of control room envelope (CRE) unfiltered air and (c) of this inleakage as required by SR 3.7.3.3, in accordance Additional Condition.

with TS 5.5.13.c.(i), the assessment of CRE habitability as required by Specification 5.5.13.c.(ii),

and the measurement of CRE pressure as required by Specification 5.5.13.d, shall be considered met.

Following implementation:

(a) The first performance of SR 3.7.3.3, in accordance with Specification 5.5.13.c.(i), shall be within the specified Frequency of 6 years, plus the 18-month allowance of SR 3.0.2, as measured from June 11, 2004, the date of the most recent successful tracer gas test.

(b) The first performance of the periodic assessment of CRE habitability, Specification 5.5.13.c.(ii), shall be within the next 9 months.

(c) The first performance of the periodic measurement of CRE pressure, Specification 5.5.13.d, shall be within 18 months, plus the 138 days allowed by SR 3.0.2, as measured from the date of the most recent successful pressure measurement test.

290 The fuel channel bow standard deviation Upon implementation of component of the channel bow model uncertainty Amendment No. 290 used by ANP-10307PA, AREVA MCPR Safety Limit Methodology for Boiling Water Reactors (i.e.,

TS 5.6.5.b.11) to determine the Safety Limit Minimum Critical Power Ratio shall be increased by the ratio of channel fluence gradient to the nearest channel fluence gradient bound of the channel measurement database, when applied to channels with fluence gradients outside the bounds of the measurement database from which the model uncertainty is determined.

311 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 311, Diesel Amendment No. 311.

Generators 1, 2, and 3 shall be protected.

Brunswick Unit 2 App. B-2 Amendment No. 311

Amendment Number Additional Conditions Implementation Date 311 The SUPP-DG, FLEX diesel generators, station Upon implementation of batteries, battery chargers, switchyard, and Amendment No. 311.

transformer yard shall be protected, as defense-in-depth, during the extended EDG Completion Times authorized by Amendment No. 311.

311 Component testing or maintenance of safety Upon implementation of systems in the off-site power systems and Amendment No. 311.

important non-safety equipment in the off-site power systems which can increase the likelihood of a plant transient or LOOP will be avoided during the extended EDG Completion Times authorized by Amendment No. 311.

311 Discretionary switchyard maintenance shall not be Upon implementation of allowed during the extended EDG Completion Amendment No. 311.

Times authorized by Amendment No. 311.

311 The High Pressure Coolant Injection (HPCI) pump, Upon implementation of Reactor Core Isolation Cooling (RCIC) pump, and Amendment No. 311.

the Residual Heat Removal (RHR) pump associated with the operable EDGs will not be removed from service for elective maintenance activities during the extended EDG Completion Times authorized by Amendment No. 311.

311 The system load dispatcher shall be contacted Upon implementation of once per day to determine if any significant grid Amendment No. 311.

perturbations (i.e., high grid loading unable to withstand a single contingency of line or generation outage) are expected during the extended Completion Times authorized by Amendment No. 311. If significant grid perturbations are expected, station managers will assess the conditions and determine the best course for the plant.

311 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 311, weather Amendment No. 311.

conditions shall be monitored each shift to determine if forecasts are predicting severe weather conditions (e.g., thunderstorm or tornado warnings). If severe weather is expected, station managers will assess the conditions and determine the best course for the plant.

Brunswick Unit 2 App. B-3 Amendment No. 311

Amendment Number Additional Conditions Implementation Date 311 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 311, designated Amendment No. 311.

non-licensed operators (NLOs) shall be briefed, each shift, regarding cross tying the 4160 V emergency bus E2 to 4160 V emergency bus E4 per plant procedure 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

311 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 311, designated Amendment No. 311.

NLOs will be briefed, each shift, regarding cross-tying 480 V E7 bus to the 480 V E8 bus per 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

311 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 311, designated Amendment No. 311.

NLOs will be briefed, each shift, regarding starting and tying the SUPP-DG to 4160 V emergency bus E4 per plant procedure 0EOP-01-SBO-08, Supplemental DG Alignment.

311 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 311, designated Amendment No. 311.

NLOs will be briefed, each shift, regarding load shed procedures and alignment of the FLEX diesel generators.

311 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 311, a continuous Amendment No. 311.

fire watch shall be established for the Unit 2 Cable Spread Room and for the Balance of Plant busses in the Unit 2 Turbine Building 20 foot elevation.

311 During the extended EDG Completion Times Upon implementation of authorized by Amendment No. 311, the FLEX Amendment No. 311.

pump and FLEX Unit 2 hose trailer shall be staged at the south side of the Unit 2 Condensate Storage Tank to support rapid deployment in the event the FLEX pump is needed for Unit 2 inventory control.

Brunswick Unit 2 App. B-4 Amendment No. 311

BSEP 17-0111 Enclosure Attachment 7 PRA Evaluation of Risk Impact

BSEP 17-0111 Enclosure Attachment 7 Page 1 of 21 : PRA Evaluation of Risk Impact This attachment provides the details of the quantitative and qualitative analyses of risk used to support the conclusion that the change in risk associated with the proposed one-time Completion Time (CT) increase of the #4 Emergency Diesel Generator (EDG) is acceptable, and is calculated consistent with NRC guidance documents.

Tier 1: Risk Evaluation 1.0 PRA Scope and Applicable Hazards The change in risk associated with the one-time increase in the CT for the #4 EDG during operation in Mode 1 has been evaluated for both Brunswick Steam Electric Plant (BSEP) units in accordance with the guidance of RG 1.177. Hazard groups were evaluated to determine which sources of risk could affect the decision, and the risk from such hazards was assessed quantitatively using a PRA which meets a staff-endorsed standard.

Section 2.3.2 of RG 1.177 identifies the NRCs regulatory position on PRA scope, and states, in part:

in some cases, a PRA of sufficient scope may not be available. This will have to be compensated for by qualitative arguments, bounding analyses, or compensatory measures.

This section further states, in part:

The scope of the analysis should include all hazard groupsunless it can be shown that the contribution from specific hazard groups does not affect the decision.

RG 1.174, Section 2.3.1 further clarifies this concept:

A qualitative treatment of the missing modes and hazard groups may be sufficient when the licensee can demonstrate that those risk contributions would not affect the decision; that is, they do not alter the results of the comparison with the acceptance guidelines Consistent with this regulatory guidance, it was determined that the change in risk associated with internal events, internal flooding, fire, and high winds due to tornadoes

BSEP 17-0111 Enclosure Attachment 7 Page 2 of 21 could affect the decision. Risk associated with seismic, external flooding, and high winds due to hurricanes has been dealt with qualitatively in each respective section.

The impact of the proposed one-time TS change for this application on the risk metrics Delta Core Damage Frequency (CDF), Incremental Conditional Core Damage Probability (ICCDP), Delta Large Early Release Frequency (LERF), and Incremental Conditional Large Early Release Probability (ICLERP) were evaluated with four BSEP-specific PRA models; a Level 1 Internal Events model, a Level 1 Internal Flooding model, a Level 1 Fire Model, and a Level 1 High Winds Model (Tornadoes only), and associated LERF models. The review history and associated technical adequacy of these models is presented in the attached PRA technical adequacy report (Attachment 8, PRA Technical Adequacy).

The seismic hazard does not have a RG.1.200 PRA model, but is evaluated using a bounding analysis in Attachment 10. With this one-time Tech Spec Completion Time being established outside of hurricane season the External Flooding and straight line wind speed risk are negligible and not quantified. Hurricanes are the mechanism for both of these hazards.

2.0 PRA Technical Adequacy A report documenting the technical adequacy of the PRA models including peer review results used to quantitatively assess the change in risk was developed and is included as Attachment 8, PRA Technical Adequacy.

3.0 One-Time Completion Time Extension Model Changes The following changes were made to the baseline model to form the application-specific model configuration:

1. The #4 EDG failure to start failure mode was set to a failure probability of 1.0 to reflect the diesel generator being out of service during the extended completion time.

BSEP 17-0111 Enclosure Attachment 7 Page 3 of 21

2. The supplemental diesel generator is assumed to be protected during the extended completion time and that is reflected in the model by setting the test and maintenance of the supplemental diesel generator to 0.0.

3. All analyzed models were analyzed for the at-power (Mode 1) condition to determine CDF and LERF significance.

4. Common cause failures associated with common cause failure group EDGs 1, 2, 3, and 4 were increased as discussed in Section 3.1.

One additional consideration is that BSEP has brought additional temporary diesel generators on site, capable of providing AC power in the event of a failure of the supplemental diesel generator. Although no quantitative credit is given for these diesel generators, a discussion of this uncertainty is included in Attachment 9, PRA Uncertainty Evaluation.

3.1 Treatment of Common Cause Failures (CCFs)

The potential impact of the #4 EDG event on the reliability of the other EDGs was evaluated and was judged that there are no specific common cause failure concerns on the other EDGs. The #4 EDG was taken out of service because of the adverse trend in the oil sampling program. The preliminary investigation indicates that degradation of the #4 EDG crankshaft and bearings occurred over many years starting with 2 specific events on the #4 EDG in 2009 involving over speed and overload conditions. The other EDGs have not experienced similar events or shown adverse trends in the oil sampling program, and are not exhibiting any other performance issues. Thus, the apparent problems with EDG 4 crankshaft are not considered to be present in other EDGs.

However, a small increase in the EDG common cause basic event probabilities was conservatively applied to address uncertainty in the extent of condition. Specifically, the common cause basic events for diesel generator failure to start were increased by a factor of 5 which is generally higher than the upper bound (95th percentile) for typical equipment reliability distributions. This represents a small risk increase commensurate with the low likelihood of impacts to the other EDGs. The supplemental diesel generator

BSEP 17-0111 Enclosure Attachment 7 Page 4 of 21 is not susceptible to common cause failures with the other 4 EDGs because of the following:

Physical separation Different manufacturers Different design Different fuel oil supply Different environmental and operating conditions The use of radiator cooling Different operating and maintenance procedures.

Therefore, common cause failures were not considered nor adjusted between the supplemental diesel generator and the 4 EDGs.

4.0 Quantitative Evaluation of Risk 4.1 Overall Risk Results The following tables document the Probabilistic Risk Assessment (PRA) conducted in support of the proposed one-time Technical Specifications (TS) change to extend the CT from 30 days (included the previous extension) to a total of 44 days associated with

4 EDG being inoperable. Because the proposed change is not considered a permanent change to the CT, the following acceptance guidelines from Regulatory Guide 1.177 (Ref. 2) are applicable for evaluating the risk associated with one-time only CT changes:

ICCDP of less than 1.0E-06 and ICLERP of less than 1.0E-07, or ICCDP of less than 1.0E-05 and ICLERP of less than 1.0E-06 with effective compensatory measures implemented to reduce the sources of increased risk The results of quantification are presented in Tables 4.1-1 and 4.1-2 below. Because the limiting results are CDF and LERF for Unit 2, the Unit 2 results are presented in Table 4.1-2 and serve as the basis to the remainder of the analysis.

BSEP 17-0111 Enclosure Attachment 7 Page 5 of 21 Table 4.1-1: BSEP Total CDF and LERF Total CDF Total LERF Unit (1/year) (1/year)

Unit 1 1.77E-06 2.67E-10 Unit 2 2.29E-06 4.94E-08 Table 4.1-2: BSEP Unit 2 CDF and LERF Hazard Breakdown Internal Internal High Winds Fire Total Events Flood (Tornadoes)

Base Case (CDF) 3.31E-06 1.80E-06 2.40E-05 8.49E-09

4 EDG Out of Service 4.91E-06 1.92E-06 2.46E-05 3.90E-08 Configuration (CDF)

Base Case (LERF) 1.20E-07 7.05E-08 4.68E-06 2.89E-11

4 EDG Out of Service 1.26E-07 7.06E-08 4.72E-06 2.89E-11 Configuration (LERF)

CDF 1.60E-06 1.20E-07 5.41E-07 3.05E-08 2.29E-06 LERF 6.00E-09 1.00E-10 4.33E-08 < E-13 4.94E-08 Table 4.1-2 Note: CDF and LERF results presented as at-power results for this one-time CT extension, instead of annualized like would be presented in a permanent plant change.

The ICCDP and ICLERP are presented in Table 4.1-3 based on an overall #4 EDG CT of 44 days, including the 14 days associated with the current TS limit. The ICCDP and ICLERP values were calculated using the following equations:

ICCDP = CDF * (44/365)

ICLERP = LERF * (44/365)

Where the CDF and LERF values represent the totals presented in Table 4.1-2.

BSEP 17-0111 Enclosure Attachment 7 Page 6 of 21 Table 4.1-3: ICCDP and ICLERP for Technical Specification Extension Configuration ICCDP ICLERP ICCDP ICLERP (44 Days) (44 Days) (/day) (/day)

Unit 2 - #4 EDG Out of 2.76E-07 5.95E-09 6.28E-09 1.35E-10 Service Configuration The risk results presented in the above 3 tables are shown to not pose a significant challenge to the risk level as presented in RG 1.177 for one-time CT changes.

4.2 Evaluation of Quantitative Results Insights 4.2.1 Internal Events Delta cutsets for this application were reviewed for CDF and LERF. Diesel generator redundancy for #1, 2, and 3 EDGs is not contributing significantly to the delta risk. The majority of the top 25 cutsets are long term loss of decay heat removal sequences with a unit switchyard centered loss of offsite power initiating event. 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 and reactor injection. Failure to align power from the supplemental diesel generator is also a significant contributor to risk.

The following compensatory actions that will be in place during the extended CT will help substantially mitigate the added Internal Events risk from having the #4 EDG out of service:

The SUPP-DG, FLEX diesel generators, station batteries, battery chargers, switchyard, and transformer yard shall be protected, as defense-in-depth, during the extended EDG Completion Times authorized by the proposed license amendment.

Discretionary switchyard maintenance shall not be allowed during the extended EDG Completion Times authorized by the proposed licensed amendment.

During the extended EDG Completion Times authorized by the proposed license amendment, designated non-licensed operators (NLOs) shall be briefed, each

BSEP 17-0111 Enclosure Attachment 7 Page 7 of 21 shift, regarding cross tying the 4160 V emergency bus E2 to 4160 V emergency bus E4 per plant procedure 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

During the extended EDG Completion Times authorized by the proposed license amendment, designated NLOs will be briefed, each shift, regarding cross-tying 480 V E7 bus to the 480 V E8 bus per 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

During the extended EDG Completion Times authorized by the proposed license amendment, designated NLOs will be briefed, each shift, regarding starting and tying the SUPP-DG to 4160 V emergency bus E4 per plant procedure 0EOP SBO-08, Supplemental DG Alignment.

4.2.2 Fire The BSEP Fire PRA model used the methodology in NUREG/CR-6850-ERPI TR-1019259 EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities (Ref. 3) and the approved FAQs 07-035, 08-048 and 08-50 from that NUREG. The fire model produces results which are judged to be conservative based on the successive screening approach which applies increasingly detailed modeling based on the risk importance of the particular area.

The results of the FIRE delta CDF and delta LERF cutsets were reviewed for dominant accident sequences and overall contributors. The following two categories of sequences generally define the majority of important contributors to the top 25 delta cutsets.

1. Fire event in Switchgear Bus 2D results in Station Blackout followed by failure to cross-tie power to support long-term suppression pool cooling followed by failure to align Fire Water injection. The risk from this sequence is mitigated by the following planned compensatory measures planned during the #4 EDG extended TS CT:

During the extended EDG Completion Times authorized by the proposed license amendment, a continuous fire watch shall be established for the Unit 1 and Unit 2 Cable Spread Rooms and for the Balance of Plant busses in the Unit 1 and Unit 2 Turbine Building 20 foot elevations.

During the extended EDG Completion Times authorized by the proposed license amendment, designated non-licensed operators (NLOs) shall be

BSEP 17-0111 Enclosure Attachment 7 Page 8 of 21 briefed, each shift, regarding cross tying the 4160 V emergency bus E2 to 4160 V emergency bus E4 per plant procedure 0AOP-36.1, Loss of Any 4kV OR 480V Bus.

2. Fire event in Control Room cabinet leading to a loss of offsite power followed by failure to cross-tie power to support long-term decay heat removal.

Fire events in the control room cabinet area are assumed to be readily noticeable and the presence of a continuous fire watch in these areas would not significantly affect the outcome. However, operators successfully cross tying AC power would significantly reduce the risk in this scenario and all others reviewed.

One fire uncertainty in the results was identified centering around the ignition frequencies, heat release rates, and cable failure probabilities used in the BSEP fire PRA model. The uncertainty resulted in a sensitivity being performed. This uncertainty was considered and assessed to not have a significant impact on this application. A full discussion of this sensitivity can be found in Section 4.1 of Attachment 9.

4.2.3 Internal Flooding Although the overall contribution to the total ICCDP and ICLERP for Internal Flooding was small, the dominant sequences were reviewed. Similar to Internal Events and Fire risk, Internal flooding risk is characterized by the failure of the operators to crosstie the 4.16kV and 480V buses. This risk is minimized by designated non-licensed operator briefings for the procedures on loss of any 4.16kV or 480V bus. The remaining important contributors center around alternate injection sources for decay heat removal.

Failure to locally close service water valves for firewater injection and failure to locally open the discharge valves for RHR injection are also important when coupled with AC crosstie failures. These local actions are unique for Internal Flooding risk, but, due to the relatively low contribution compared to other more dominant contributors no specific compensatory actions are recommended.

BSEP 17-0111 Enclosure Attachment 7 Page 9 of 21 4.2.4 High Winds The Brunswick PRA High Wind PRA model contains three categories of high wind initiators: high wind, high wind missiles, and tornadoes. High winds events at Brunswick are dominated by hurricane winds (modeled by high wind and high wind missile initiators), which are at an extremely low likelihood in the late fall and winter. Currently there are no hurricane threats in the Atlantic nor extreme weather predicted across the East Coast that could impact Brunswick. NOAA also predicts a weak La Nina for the upcoming winter season as well as shifting the jet stream further north, which reduces the total number of storm systems to affect the area. Therefore, the High Wind initiating events are not credible for the time period of concern for the requested Tech Spec extension.

The potential increase in risk from high winds during the exposure period is negligible due to the plants design and the weather during the exposure period. The weather is monitored continually, and if there were a threat of severe weather, preparations will be made in accordance with plant emergency procedure for response to severe weather warnings. The procedure contains detailed unit guidelines for storm preparation.

Further, the initiators in the internal events model for weather centered loss of offsite power encompass the effect of power loss due to weather related issues. Additionally, weather centered loss of offsite power events sequences only comprise approximately 10% of the conditional case CDF results.

However, for tornadoes, a quantitative study was performed with the high winds model using only the tornado initiators at their nominal values. The results of this quantitative analysis are presented in Section 4.1.

Reviewing the tornado hazard cutsets from failing EDG 4 and increasing the probability of a common cause failure occurring with the other EDGs gave the following insights.

The top two operator actions based on Fussell-Vesely have to do with operators successfully shedding loads off their DC busses. For equipment, the most important components are the #1, 2, and 3 EDGs as shown by their high Fussell-Vesely values.

Additionally, the breakers on the safety busses failing to open in preparation for load sequencing an EDG onto a safety bus grew in importance. Therefore, the importance measures show that with EDG 4 failing to start, the three other EDGs being able to

BSEP 17-0111 Enclosure Attachment 7 Page 10 of 21 power its safety busses and the need for operators to preserve DC power becomes more important.

The Supplemental Diesel Generator is not protected against tornado generated missiles. It is designed and installed to withstand 155mph wind speeds which means that the most likely tornado winds will not fail the supplemental diesel generator, and can be started to support shutdown loads after the tornado has passed by the site. It should be noted that the supplemental diesel generator is not credited in the high winds analysis. The additional temporary diesel generator is also likely to survive the most likely wind events but is not credited in the analysis.

4.3 Qualitative Evaluations 4.3.1 External Flooding The potential increase in risk from external flooding while #4 EDG is unavailable is considered negligible due to the plants design and surrounding topography. For BSEP, the evaluated causes of external flooding are hurricanes events. The weather is monitored frequently given the emergency diesel outage and if there is a threat of severe weather during the extended technical specification window, severe weather preparations would be made in accordance with site procedures. The procedures contain detailed unit guidelines for storm preparation. However, the winter months have no activity time periods for Atlantic Ocean tropical cyclones, with none in any long range forecast. For this reason, the external flooding risk due to the #4 EDG TS CT extension is considered to be negligible for the time period of interest based on the above qualitative considerations.

4.3.2 Seismic A bounding analysis for the evaluation of seismic risk for this application was performed to demonstrate that it would not affect the decision, consistent with RG 1.174 and RG 1.177. In addition to the qualitative discussion as to why seismic risk is a very small

BSEP 17-0111 Enclosure Attachment 7 Page 11 of 21 contributor to the overall risk increase and does not impact the decision, a bounding quantitative study was also performed. A full discussion of these analyses is provided in 0. The conclusion of both the qualitative and quantitative evaluations demonstrate that seismic risk for the #4 EDG extended CT is a small contributor to total plant risk and is well below the RG 1.177 guidelines for implementation of this one-time only TS CT change.

4.3.3 Transportation/Nearby Facility Accidents The potential increase in risk from transportation accidents or nearby facility accidents due to having the #4 EDG unavailable was qualitatively considered and determined to be negligible. There is been no change in the risk from these hazards since the IPEE.

4.4 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 evaluation performed demonstrates that, within reasonable assurance, the numerical risk results of this application lie below the criteria in RG 1.177 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 in Reg. Guides 1.174 (Ref. 1), Reg. Guide 1.177 (Ref. 2), NUREG 1855 (Ref. 4), and EPRI Report 1016737 (Ref. 5). No key sources of uncertainty were identified for this application that would be expected to significantly affect the results. A full discussion of the uncertainty evaluation performed for this application can be found in Attachment 9, PRA Uncertainty Evaluation.

BSEP 17-0111 Enclosure Attachment 7 Page 12 of 21 Tier 2: Avoidance of Risk Significant Plant Configurations 5.0 Tier 2 Component Evaluation Tier 2 evaluations are used to identify high risk equipment that could exist if they are taken out of service along with the equipment involved in the TS change. To address Tier 2 concerns, the delta cutset file for the Unit 2 internal events model 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 as the #4 EDG during the extended CT. The results are presented in Table 5.5-1, ranked by their Risk Achievement Worth (RAW).

Table 5.5-1: Tier 2 Component Evaluation T&M Event Component RAW RHR2PTF-TM-LOOPA RHR Loop A 8.4 DCP2REC-TM2A2 Charger 2A-2 6.8 EDG2XHE-MN-DG3 EDG#3 5.4 EDG1XHE-MN-DG1 EDG#1 2.9 EDG1XHE-MN-DG2 EDG#2 1.9 CSS2XHE-MN-C001A CSP A 1.6 RCI2XHE-MNRCIC RCIC 1.1 FPS0XHE-MN-FPV57 Valve 2-FP-V57 1.1 DCP2REC-TM2A1 Charger 2A-1 1.1 CRD2XHE-MN-PMPA CRD Train A 1.0 In addition to the integrated risk management strategy in place at BSEP as described in the Tier 3 evaluation, the following controls will be in place for the duration of the extended TS CT that will mitigate the high risk equipment test and maintenance configurations identified in Table 5.5-1.

EDGs 1, 2, and 3 shall be protected during the extended #4 EDG completion time

BSEP 17-0111 Enclosure Attachment 7 Page 13 of 21 The supplemental diesel generator, FLEX diesel generators, station batteries, battery chargers, switchyard, and transformer yard shall be protected High Pressure Coolant Injection (HPCI), Reactor Core Isolation Cooling (RCIC), and Residual Heat Removal (RHR) systems will be protected These controls provide assurance that high risk component configurations involved with the #4 EDG extended TS CT will be avoided and remain in place during the duration of the CT.

Tier 3: Risk Evaluation 6.0 Tier 3 Evaluation 10 CFR 50.65(a)(4), RG 1.160 (Ref. 6), RG 1.182 (Ref. 7), and NUMARC 93-01 (Ref. 8) require that prior to performing maintenance activities, risk assessments shall be performed to assess and manage the increase in risk that may result from proposed maintenance activities. These requirements are applicable for all plant modes.

NUMARC 93-01 requires utilities to assess and manage the risks that occur during the performance of outages.

The proposed LAR will not result in any significant changes to the current configuration risk management program. The Brunswick on-line computerized risk software (Equipment Out Of Service or EOOS) considers internal initiating events including LOOP events (including weather and grid related). Thus, the overall change in plant risk during maintenance activities is expected to be addressed adequately considering the proposed amendment.

BSEP has several Administrative (AD) procedures in place to ensure that risk significant plant configurations are avoided. These documents are used to address the Maintenance Rule requirements, including the on-line (and off-line) Maintenance Policy requirement to control the safety impact of combinations of equipment removed from service. The key documents are as follows:

AD-WC-ALL-0410, Work Activity Integrated Risk Management (Ref. 9),

0AP-025, "BNP Integrated Scheduling" (Ref. 10)

AD-NF-ALL-0501, "Electronic Risk Assessment Tool (ERAT)" (Ref. 11)

BSEP 17-0111 Enclosure Attachment 7 Page 14 of 21 More specifically, the ADs referenced above address the process, define the program and state individual group responsibilities to ensure compliance with the Maintenance Rule. The Work Process Manual procedures provide a consistent process for utilizing the computerized software assessment tool, EOOS, which manages the risk associated with equipment inoperability.

EOOS is a Windows-based computer program used to facilitate risk informed decision making associated with station work activities. Its guidelines are independent of the requirements of the Technical Specifications and Technical Requirements Document and are based on probabilistic risk assessment studies and deterministic approaches.

Additionally, prior to the release of work for execution, Operations personnel must consider the effects of severe weather and grid instabilities on plant operations.

Responses to actual plant risk due to severe weather or grid instabilities are programmatically incorporated into applicable plant emergency or response procedures.

The key safety significant systems impacted by this proposed LAR are currently included in the Maintenance Rule program, and as such, availability and reliability performance criteria have been established to assure that they perform adequately.

6.1 Traditional Engineering Considerations For a potential station blackout (SBO) during the proposed Completion Time (CT) extensions, the supplemental diesel generator (SUPP-DG) will be available to mitigate the accident, and the units will remain within the bounds of the accident analyses. In addition, there would be no adverse impact to the units, because the Safety Function Determination Program (SFDP) will be utilized to ensure that cross-train checks are performed to ensure a loss of safety function does not go undetected. The SFDP will also ensure appropriate actions are taken if a loss of safety function is identified. Since the probability of a loss of safety function going undetected during the planned maintenance window is low, there is minimal safety impact due to the proposed CT extensions for the inoperable EDG.

The combination of defense-in-depth and safety margin principles inherent in the onsite emergency power system ensures an emergency supply of power will be available to

BSEP 17-0111 Enclosure Attachment 7 Page 15 of 21 perform the required safety function. These elements of defense-in-depth and safety margin support a CT extension to 44 days to allow EDG 4 to be out-of-service for a longer period of time, as discussed further below.

6.2 Defense-in-Depth The proposed change to the CTs for EDG 4 out-of-service maintains system redundancy, independence and diversity commensurate with the expected challenges to system operation. The other EDGs, offsite sources of power and the associated engineered safety equipment will remain operable and the SUPP-DG will remain available to mitigate the consequences of any previously analyzed accident. Otherwise, the SFDP will require that a loss of safety function be declared, and the appropriate TS Conditions and Required Actions taken. In addition to the SFDP, the Work Management process provides for controls and assessments to preclude the possibility of simultaneous outages of redundant trains and to ensure system reliability. The proposed increase in the CTs associated with the inoperable BNP EDG 4 will not alter the assumptions relative to the causes or mitigation of an accident.

With the single EDG 4 inoperable at BNP, a loss of function has not occurred. The remaining offsite power sources and EDGs 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 philosophy is maintained if the following occurs regarding the proposed licensing basis change:

A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation.

BNP has already installed an additional AC power supply (i.e., supplemental diesel generator) , which will ensure a reasonable balance is preserved between prevention of core damage, prevention of containment failure and consequence mitigation for the proposed extensions to the current BNP TS 3.8.1 CT for the inoperable EDG 4 to 44 days. The proposed CT extensions will not significantly reduce the effectiveness of any

BSEP 17-0111 Enclosure Attachment 7 Page 16 of 21 of the following four layers of defense that exist in the BNP plant design: minimizing challenges to the plants, preventing any events from progressing to core damage, containing the radioactive source term and emergency preparedness. Extending the CTs for the inoperable EDG 4 does not increase the likelihood of initiating events and does not create new initiating events. Furthermore, the proposed CT extensions do not significantly impact the availability and reliability of SSCs that are relied upon to perform safety functions that prevent plant challenges from progressing to core damage. Lastly, the proposed change does not significantly impact the containment function or SSCs that support the containment function and also does not involve the emergency preparedness program or any of its functions.

Over-reliance on programmatic activities as compensatory measures associated with the change in the licensing basis is avoided.

A supplemental power source (i.e., the SUPP-DG at BNP) has been installed and is available as a backup to the inoperable EDG 4 to maintain the defense-in-depth design philosophy for the electrical power system to meet its intended safety function. The SUPP-DG (i.e., plant equipment) at BNP reduces the reliance on programmatic activities as compensatory measures associated with the proposed TS CT change. In addition to the SUPP-DG BNP has obtained an additional temporary 4KV diesel generator as added defense in case the SUPP DG fails when needed.

Plant safety systems are designed with redundancy so that when one train is inoperable, a redundant train can provide the necessary safety function. The preferred approach at BNP for accomplishing safety functions is through engineered systems, rather than overreliance on programmatic activities (i.e., compensatory measures).

During the timeframe that EDG 4 is inoperable at BNP, an existing redundant source of power is maintained OPERABLE. As previously highlighted, in the event other equipment becomes inoperable concurrent with the EDG inoperability, the SFDP requires cross-division checks to ensure a loss of safety function does not go undetected. If a loss of safety function is identified at BNP, 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.

System redundancy, independence, and diversity are preserved commensurate

BSEP 17-0111 Enclosure Attachment 7 Page 17 of 21 with the expected frequency, consequences of challenges to the system, and uncertainties (e.g., no risk outliers).

The redundancy, independence and diversity of the onsite emergency power system at BNP will be maintained during the CT extensions. There were no identified uncertainties in redundancy, independence and diversity with the introduction of the extended CT to 44 days. The installed supplemental AC power source at BNP (i.e.,

SUPP-DG) is not susceptible to the same common cause failures as the EDGs since the SUPP-DG has a different manufacturer, operates at different speeds, has different starting systems, etc. The added temporary diesel generator is also independent from common cause due differences in design and maintenance.

Defenses against potential 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 created as a result of the proposed change to extend the BNP CTs for the inoperable EDG 4. The SUPP-DG does not have any common linkage with the emergency DGs at BNP beyond the potential for the same personnel that performs the maintenance on the equipment. The operating environment and operating parameters for the BNP EDGs remains constant; therefore, new common cause failure modes are not introduced. Redundant and backup systems are not impacted by the proposed change and no new common cause links between the primary and backup systems are introduced.

Independence of barriers is not degraded.

The barriers protecting the public and the independence of these barriers are maintained at BNP. Multiple EDGs, systems and electrical distribution systems will not be taken out-of-service simultaneously, as that could lead to degradation of the barriers and an increase in risk to the public. In the event other equipment becomes inoperable concurrent with the BNP EDG 4 inoperability, the SFDP requires cross-division checks to ensure a loss of safety function does not go undetected. If a loss of safety function is

BSEP 17-0111 Enclosure Attachment 7 Page 18 of 21 identified, TS LCO 3.0.6 at BNP will require entry into the applicable Conditions and Required Actions for the system that possesses the loss of safety function.

Furthermore, BNP TS 3.8.1 requires declaring required feature(s) supported by the inoperable EDG, inoperable when its redundant required feature(s) are inoperable. The particular Required Action is intended to provide assurance that a loss of offsite power, during the period that a EDG is inoperable, does not result in a complete loss of safety function of critical systems. These required features within the context of TS 3.8.1 are designed to be powered from redundant safety related 4.16 kV emergency buses.

Redundant required feature failures consist of inoperable features associated 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 at BNP; fuel cladding, reactor coolant system and containment.

Defenses against human errors are preserved.

The proposed extensions to the BNP CTs do not introduce any new operator actions for the existing plant equipment. Operators are required to align and operate the supplemental AC power source (i.e., SUPP-DG). Licensed Operators and Auxiliary Operators are appropriately trained on the purpose and use of the SUPP-DG and associated procedural actions.

The intent of the plants design criteria is maintained.

The design and operation of the BNP EDGs are not altered by the proposed CT extensions. The safety analyses safety criteria stated in the BNP UFSAR are not impacted by the proposed change. Redundancy and diversity of the EDGs are not altered because the system design and operation are not changed by the proposed CT extensions. The proposed change to the BNP TS will not allow plant operation in a configuration outside the plants design basis. The requirements credited in the accident analyses regarding the EDGs will remain the same.

BSEP 17-0111 Enclosure Attachment 7 Page 19 of 21 6.3 Safety Margin In the proposed extended CTs for the inoperable EDG 4, the plant remains in a condition for which it has already been analyzed; therefore, from a deterministic perspective, the proposed TS change is acceptable. The 44 day CT is a risk-informed CT based on plant specific analyses using the methodology defined in this license amendment request.

Furthermore, the already installed supplemental AC power source (i.e., SUPP-DG) at BNP supports this emergency TS change request with the capability to power any essential bus within one hour from the time that the SBO emergency procedures direct its use as the emergency power source. The SUPP-DG will have the capacity to bring the affected unit to cold shutdown.

The evaluation that follows, using the principles defined in RG 1.174, demonstrates that the proposed licensing basis change for BNP is consistent with the principle that sufficient safety margins are maintained.

With sufficient safety margins, the following are true for BNP:

Codes and standards or their alternatives approved for use by the NRC are met.

The design and operation of the BNP EDGs is not altered by the proposed CT extensions. Redundancy and diversity of the electrical distribution system will be maintained. The SUPP-DG at BNP provides an additional AC power source as a defense-in-depth measure for SBO.

Safety analysis acceptance criteria in the LB (e.g., FSAR, supporting analyses) are met or proposed revisions provide sufficient margin to account for analysis and data uncertainty.

The safety analyses acceptance criteria stated in the BNP UFSAR is not impacted by the proposed change. The proposed change will not allow plant operation in a configuration outside the design basis. The requirements regarding the EDGs credited in the BNP accident analyses will remain the same.

BSEP 17-0111 Enclosure Attachment 7 Page 20 of 21 Given the above, Duke Energy concludes that safety margins are not impacted by the proposed one-time TS CT change.

7.0 Conclusions The analysis for the one time TS CT extension of the #4 EDG shows that the risk from having the EDG out of service for a total of 44 days is acceptable from a quantitative and qualitative risk standpoint. The risk incurred from this one time TS CT extension meets the criteria as outlined in RG 1.177. Where a qualitative analysis was used, the discussion shows that the risk from known sources is minimal and would not impact the overall results of the application.

BSEP 17-0111 Enclosure Attachment 7 Page 21 of 21 8.0 References

1. 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

2. USNRC Regulatory Guide 1.177, An Approach for Plant-Specific, Risk-Informed Decision Making: Technical Specifications, Rev. 1

3. USNRC NUREG 6850/EPRI TR-1019259, EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities, Vol. 1 and 2, October 2004

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. Regulatory Guide 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 3, dated May 2012.

7. Regulatory Guide 1.182, Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants, dated May 2000.

8. NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 4A, dated April 2011.

9. AD-WC-ALL-0410, Revision 4, Work Activity Integrated Risk Management.

10. 0AP-025, Revision 56, BNP Integrated Scheduling.

11. AD-NF-ALL-0501, Revision 0, Electronic Risk Assessment Tool (ERAT).

BSEP 17-0111 Enclosure Attachment 8 PRA Technical Adequacy

BSEP 17-0111 Enclosure Attachment 8 Page 1 of 31 PRA Technical Adequacy Table of Contents 1.0 OVERVIEW .......................................................................................................................... 2 2.0 BASIS TO CONCLUDE THAT THE PRA MODEL REPRESENTS THE AS-BUILT, AS-OPERATED PLANT ....................................................................................................... 5 2.1 BSEP PRA Model Working Model ................................................................................. 5 2.2 PEER REVIEWS .................................................................................................................. 5

3.0 TECHNICAL EVALUATION

.................................................................................................. 6 3.1 Internal Events and Internal Flooding ........................................................................... 6 3.2 Fire Hazards ................................................................................................................. 6 3.3 Seismic Hazards........................................................................................................... 7 3.4 External Flooding.......................................................................................................... 7 3.5 High Winds ................................................................................................................... 7 3.6 Transportation/Nearby Facility Accidents ..................................................................... 7 4.0 KEY ASSUMPTIONS AND APPROXIMATIONS ................................................................. 8 4.1 DC Power Availability and Battery Life ......................................................................... 8 4.2 Loss of Off-Site Power (LOOP) Frequencies ............................................................... 8 4.3 Fire Modeling ................................................................................................................ 8

5.0 CONCLUSION

S ON PRA TECHNICAL ADEQUACY .......................................................... 8

6.0 REFERENCES

..................................................................................................................... 9 List of Tables Table 3-1. Disposition and Resolution of Open Peer Review Findings and Self-Assessment Open Items ........................................................................................ 10

BSEP 17-0111 Enclosure Attachment 8 Page 2 of 31 1.0 OVERVIEW The PRA technical adequacy for the Brunswick Steam Electric Plant (BSEP), Units No 1. and No. 2, has been addressed through Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.200, Revision 2 (Reference 1), which endorsed the American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) PRA Standard, RA-Sa-2009 (Reference 2). The internal events at power, internal flooding, and fire PRA models will be used quantitatively to provide risk insights for this application. External events (including seismic events) will be considered qualitatively for this application as described herein. The level of PRA quality, combined with the disposition of gaps from the facts and observations (F&O) closeout process are sufficient to support the evaluation of the one-time technical specification (TS) change for the emergency diesel generator #4 (EDG #4). The quality of the model is consistent with Regulatory Position 2.3.1 of RG 1.177 (Reference 3) and is compatible with the safety implications of the TS change being requested.

This enclosure demonstrates the technical adequacy of the BSEP PRA model to be used as the basis for the emergency license amendment request (LAR), consistent with the requirements of Section 3.3 and Section 4.2 of RG 1.200, Revision 2. The NRC has previously reviewed the technical adequacy of the BESP PRA models identified in this application, with routine maintenance updates applied:

License Amendment for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee-Controlled Program, May 24, 2017, ADAMS Accession No. ML17096A129 (Reference 4)

Brunswick Steam Electric Plant, Units 1 and 2 - Issuance of Amendment regarding Transition to a Risk Informed, Performance-Based Fire Protection Program in Accordance with 10CFR 50.48(C) (TAC NOS. ME9623 and ME9624), January, 28, 2015. (ADAMS Accession No. ML14310A808) (Reference 5).

Duke Energy requests that the NRC utilize the review of the PRA technical adequacy for these applications when performing the review for this application.

The following changes in the BSEP PRA models have been made since those reviews were completed.

Full Power Internal Events PRA Since completion of previous NRC reviews, Duke Energy has issued a routine Model of Record (MOR) update of the Brunswick Units 1 and 2 full power internal events (FPIE) PRA model. The model designation is updated from MOR13 to MOR16 per the PRA Standard and Duke Energy procedures. The changes to the FPIE PRA are:

Updated plant data and failure data Incorporated recent plant modifications o Incorporated the new RBCCW pump installed in Unit 2

BSEP 17-0111 Enclosure Attachment 8 Page 3 of 31 o Replaced the SAMA diesel logic with FLEX diesel logic o Revised the Instrument/Service Air model to reflect new equipment o Revised Condensate System logic to reflect replacement of air-operated butterfly valves with blank flanges and modified pump suction piping Revised the Safety Relief Valve (SRV) System logic to reflect the fact that operators now inhibit the Automatic Depressurization System (ADS) system for any transient event that results in a low reactor vessel level, and for all Anticipated Transient Without SCRAM (ATWS) transients Added two pre-initiator actions to address new Reactor Building Closed Cooling Water (RBCCW) pumps Added an additional post-initiator action for the Supplemental Diesel for EDG failures not related to planned maintenance Two new operator actions have been added to support the addition of the FLEX Portable Pumps and Air Compressors as an additional means of Reactor Pressure Vessel (RPV) Injection and Hardened Containment Vent support, respectively Updated the HRA dependency analysis.

Included Fact and Observation (F&O) resolutions for findings identified in the previously completed peer reviews against the ASME/ANS PRA Standard.

Performed an independent F&O close-out review in accordance with the process documented in Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13 (Reference 6) as accepted by NRC in the letter dated May 3, 2017 (ADAMS Accession No. ML17079A427) (Reference 7).

No changes were made to the large, early release frequency (LERF) model as part of the MOR16 update.

Internal Flood PRA (IFPRA)

There have been no updates to the Internal Flood PRA model since the safety evaluation (SE) of the Surveillance Frequency Control Program (SFCP) was issued (Reference 3). The IFPRA model includes the updates from the 2016 focused scope peer review and F&O resolution developed and submitted for the SFCP LAR. The independent F&O close-out review of the FPIE model included review of the IFPRA as well and was completed in accordance with the process documented in Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13. All remaining Open finding-level F&Os for the internal flood model are included in the current LAR.

Fire PRA There have been no updates to the Fire model since the safety evaluation of the Surveillance Frequency Control Program (SFCP) was issued (Reference 3). An F&O close-out review of the

BSEP 17-0111 Enclosure Attachment 8 Page 4 of 31 model has been performed in accordance with the process documented in Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13, (Reference 6). All remaining Open finding-level F&Os are included in the current LAR.

In the time since the BNP FPRA was developed, some new data have been developed. In particular, NUREG-2169 (ignition frequencies), NUREG-2178 (heat release rates/obstructed plume), and NUREG/CR-7150 (cable failure probabilities) are most relevant to the BNP FPRA.

The individual impacts of these unincorporated changes are mixed, but the net effect on total risk is bounded by a factor of 2 as a sensitivity. Bin 15 (electrical enclosure) is the dominant contributor to fire risk and the updated ignition frequency increased by less than a factor of 2. The ignition frequencies for Bin 4 (main control boards) and Bin 8 (diesel generators) also increased. But, the risk increases associated with updated ignition frequencies for Bin 15 and Bin 4 are at least partially mitigated by decreases in the associated heat release rates. Where applicable, the incorporation of the obstructed plume effect would further decrease the calculated risk. There were also significant decreases in the ignition frequency for other Bins, including Bin 7 (transients) and Bin 16a (HEAF). In general, the updated cable failure probabilities also tend to decrease the calculated risk. While it is not possible to precisely quantify the change in risk without actually incorporating these new data, the trend has historically been toward risk reduction.

In addition, FAQ 08-0046 (Incipient Fire Detection Systems) was retired in conjunction with the development of NUREG-2180. Because both FAQ 08-0046 and NUREG-2180 were developed for Bin 15 (electrical enclosures) fires, this change has no effect on the BNP FPRA, in which in-cabinet incipient detection is only credited for Bin 4 (main control boards) fires, as is described in Section 3.2.6 of the Safety Evaluation for the NFPA 805 LAR. No additional PRA credit is taken for area-wide incipient detection.

High Winds PRA The BSEP High Winds model has been updated to address the Open facts and observations (F&Os) from the 2012 peer review. The model updates included an upgrade of the high winds HRA from the multiplier method to the HRA Calculator used in the internal events model. A focused scope peer review on the high winds HRA was completed in 2017, and an F&O close-out review was performed in conjunction with the focused scope peer review. The F&O close-out was performed in accordance with the process documented in Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13, (Reference 6). All Open findings have been closed as a result of the F&O close-out process.

BSEP 17-0111 Enclosure Attachment 8 Page 5 of 31 Other External Hazards The seismic, external flood, and transportation/nearby facility accidents were assessed qualitatively for the EDG #4 LAR. There are no relevant model updates for these hazards.

2.0 BASIS TO CONCLUDE THAT THE PRA MODEL REPRESENTS THE AS-BUILT, AS-OPERATED PLANT The BSEP PRA Model of Record (MOR) is maintained as a controlled document and is updated on a periodic basis to represent the as-built, as-operated plant. Duke Energy procedures provide the guidance, requirements, and processes for the maintenance, update, and upgrade of the PRA:

a. The process includes a review of plant changes, relevant plant procedures, and plant operating data as required, through a chosen freeze date to assess the effect on the PRA model.

b. The PRA model and controlling documents are revised as necessary to incorporate those changes determined to impact the model.

c. The determination of the extent of model changes includes the following:

Accepted industry PRA practices, ground rules, and assumptions consistent with those employed in the ASME/ANS PRA Standard (i.e., Reference 2),

Current industry practices, NRC guidance (i.e., References 1 and 3),

Advances in PRA technology and methodology, and Changes in external hazard conditions.

For plant changes of small or negligible impact, the model changes can be accumulated and a single revision is performed at an interval consistent with major PRA revisions. The results of each evaluation determine the necessity and timing of incorporation of a particular change into the PRA model. An electronic tracking database is utilized to document pending model changes and updates. Previous major PRA model revisions are summarized in Section 2.1, and there are currently no major plant changes that have not been incorporated into the model.

2.1 BSEP PRA MODEL WORKING MODEL The working model for the BSEP represents the most up-to-date versions of the constituent PRA internal and external hazard models. The September 2017 working model is used for this analysis of the EDG #4. The latest version of the internal events model is Model of Record 16 issued in June 2017. The other PRA models are built on internal event MORs with enhancements to resolve findings from the 2017 F&O close-out review.

2.2 PEER REVIEWS The PRA models have been assessed against RG 1.200, Rev. 2 (Reference 1), and the 2009 PRA Standard (Reference 2). Gap analysis to capability category II in the Standard has been

BSEP 17-0111 Enclosure Attachment 8 Page 6 of 31 completed in response to fact and observation (F&O) findings, and with resolution of the F&Os, all of the BSEP models are sufficient to support the evaluation of the one-time TS change for EDG #4. The peer reviews that have been completed are:

The BSEP internal events PRA model was subject to a self-assessment and a full-scope peer review conducted in June 2010.

The BSEP internal flood PRA model was subject to a self-assessment and a full-scope peer review conducted in June 2010 and a focused scope peer review covering 28 SRs conducted in December 2016.

The BSEP Fire PRA model was subject to a self-assessment and a full-scope peer review conducted in February 2012 and a focused scope peer review May 2015.

The BSEP High Winds PRA model was subject to a self-assessment and a full-scope peer review conducted in February 2012 and a focused scope peer review in July 2017.

The BSEP External Flood PRA model was subject to a self-assessment and a full-scope peer review conducted in February 2012.

Closed findings were reviewed and closed in August 2017 for BSEP Internal Events, Internal Flood, High Winds, and Fire models using the process documented in Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13, Close-out of Facts and Observations (F&Os) (ADAMS Accession No. ML17086A431) (Reference 6) as accepted by NRC in the letter dated May 3, 2017 (ADAMS Accession No. ML17079A427) (Reference 7).

Table 3-1 provides a summary of the remaining findings and open items, including open findings and disposition of the BSEP peer reviews.

3.0 TECHNICAL EVALUATION

The following sections demonstrate that the quality and level of detail of the PRA are adequate.

All the PRA models described below have been peer reviewed and there are no PRA upgrades that have not been peer reviewed.

3.1 Internal Events and Internal Flooding The internal events and internal flooding assessment of the EDG #4 is done quantitatively using the plant-specific PRA model. The Duke Energy risk management process ensures that the PRA model used in this application reflects the as-built and as-operated plant for each of the BSEP units.

3.2 Fire Hazards The fire assessment of the EDG #4 will be done quantitatively using the peer reviewed plant-specific fire PRA model. The internal Fire PRA model was developed consistent with NUREG/CR-6850 and only utilizes methods previously accepted by the NRC. The Duke Energy risk management process ensures that the PRA model used in this application reflects the as-built and as-operated plant for each of the BSEP units.

BSEP 17-0111 Enclosure Attachment 8 Page 7 of 31 3.3 Seismic Hazards A qualitative and quantitative bounding estimate of contributions to the change in risk from seismic events has been developed based on the internal events model. The results show that neither the bounding seismic ICCDP nor the seismic ICLERP are significant contributors to risk during the EDG #4 maintenance period. The assessment is an extreme bounding estimate in that off-site power and the failed components are all assumed to fail at the OBE seismic event.

Switchyards are not expected to fail at the OBE, and the other important equipment are very robust and are also not expected to fail at the OBE level. In addition, no credit is taken for repair of any failed equipment, nor is credit taken for the supplemental diesel, the FLEX diesels, or the temporary contingency diesels that have been pre-staged as a compensatory measure. Each of these would further reduce the ICCDP and ICLERP. It is concluded, therefore, that the BSEP risk increase is negligible when considering a potential seismic event during the use of the Emergency Diesel Generator (EDG) #4 Technical Specification extended completion time.

3.4 External Flooding The potential increase in risk from external flooding while EDG #4 is unavailable is considered negligible due to the plants design and surrounding topography. For BSEP, the evaluated causes of external flooding are hurricanes. The weather is monitored continually, and if there were a threat of severe weather, preparations will be made in accordance with plant emergency procedure for response to severe weather warnings. The procedure contains detailed unit guidelines for storm preparation. It is not currently hurricane season, and there are no threats in the Atlantic.

3.5 High Winds The potential increase in risk from High Winds during the exposure period is considered qualitatively and quantitatively using the peer reviewed model of record which contains three categories of high wind initiators: high wind, high wind missiles, and tornadoes. High winds events at Brunswick are dominated by hurricane winds (modeled by high wind and high wind missile initiators), which are at an extremely low likelihood in the winter. Currently there are no hurricane threats in the Atlantic nor extreme weather predicted across the East Coast that could impact Brunswick. NOAA also predicts a weak La Nina for the upcoming winter season as well as shifting the jet stream further north, which reduces the total number of storm systems to affect the area. Therefore, adjusting these initiating events to realistically represent current conditions reduces the risk impact from hurricanes down to negligible. Given the unpredictable nature of tornados, a quantitative study was performed with the high winds model using only the tornado initiators at their nominal values. Further, the initiators in the internal event model for weather centered loss of offsite power (%TE_S_WC) encompass the effect of power loss due to weather related issues.

3.6 Transportation/Nearby Facility Accidents The potential increase in risk from transportation accidents or nearby facility accidents due to having the EDG #4 unavailable was qualitatively considered based on the IPEEE analyses (Reference 8) and determined to be negligible.

BSEP 17-0111 Enclosure Attachment 8 Page 8 of 31 4.0 KEY ASSUMPTIONS AND APPROXIMATIONS Three types of uncertainty have been evaluated for the BSEP PRA models: parametric uncertainty, model uncertainty, and completeness uncertainty. Sources of model uncertainty and related assumptions were identified using the guidance of NUREG-1855 and EPRI TR-1016737. All uncertainties determined to be key uncertainties for the application were evaluated further with sensitivity studies. The list below represents the modeling assumptions and uncertainty that are considered to have the greatest impact on the BSEP PRA results if different reasonable alternative assumptions were utilized. The approaches taken for the assumptions below represent industry best practices.

4.1 DC Power Availability and Battery Life The DC power system at BSEP is one of the largest contributors to plant risk. Determination of battery depletion times and associated accident sequence timing and related success criteria can potentially have an impact on results. The assessment of the DC power system in the BSEP PRA model uses NRC-approved methods and is used to develop the key important measures for the modeled SSCs.

4.2 Loss of Off-Site Power (LOOP) Frequencies Loss of off-site power initiating events have been shown to be important contributors to plant core damage due to the potential for station blackout and the reliance of many frontline systems on AC power. The LOOP initiator was separated into plant, grid, switchyard and weather induced LOOPs, which allowed the model to apply recovery actions to the higher frequency events (i.e., plant and switchyard). The LOOP frequency has an impact on CDF and Emergency Diesel Generator (EDG) importance. The approach utilized for modeling the LOOP frequencies and recovery probabilities is consistent with industry practice.

4.3 Fire Modeling Fire modeling, although following the technical guidance of NUREG/CR-6850, contains several risk important elements that are judged to contain uncertainties for their respective elements of fire risk methodology. These elements include the fire ignition frequency, heat release rates, fire growth curves, fire suppression failure probabilities, severity factors, and post-initiator human failure event probabilities. While the approaches taken in the BSEP Fire PRA represent the state of the art methodology, they are still constrained by the relatively limited data on fire events at Nuclear Power Plants.

5.0 CONCLUSION

S ON PRA TECHNICAL ADEQUACY The BSEP PRA is of sufficient quality and level of detail to support assessment of the one-time TS change requested in this LAR. The PRA is consistent with Regulatory Position 2.3.1 of RG 1.177 and is compatible with the safety implications of the TS change being requested. It has been subjected to a peer review process assessed against the PRA Standard that is endorsed by the NRC. The level of PRA quality, combined with the disposition of gaps from the facts and observations (F&O) closeout process are sufficient to support the evaluation of the one-time technical specification (TS) change for the Emergency Diesel Generator #4 (EDG #4).

BSEP 17-0111 Enclosure Attachment 8 Page 9 of 31

6.0 REFERENCES

1. Regulatory Guide 1.200, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Revision 2, US Nuclear Regulatory Commission, March 2009.

2. ASME/ANS RA-Sa-2009, Standard for Level l/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, Addendum A to RA-S-2008, ASME, New York, NY, American Nuclear Society, La Grange Park, Illinois, dated February 2009

3. Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decision Making:

Technical Specifications," Revision 1, U.S. Nuclear Regulatory Commission, May 2011.

4. Letter from the NRC to BSEP, "Issuance of Amendments Regarding request to Relocate Specific Surveillance Frequencies to Licensee Controlled Program," May 24, 2017 (ADAMS Accession No. ML17096A129)

5. Brunswick Steam Electric Plant, Units 1 and 2 - Issuance of Amendment regarding Transition to a Risk Informed, Performance-Based Fire Protection Program in Accordance with 10CFR 50.48(C) (TAC NOS. ME9623 and ME9624), January, 28, 2015. (ADAMS Accession No. ML14310A808)

6. Letter from NEI to USNRC, Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close-Out of Facts and Observations (F&Os), February 21, 2017, Accession Number ML17086A431.

7. Letter from NRC to NEI, U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance 05-04, 7-12, and 12-13, Close Out of Facts and Observations (F&Os), May 3, 2017, Accession Number ML17079A427.

8. NRC letter NRC Staffs Evaluation of the Brunswick Steam Electric Plant, Units 1 and 2, Individual Plant Examination of External Events (IPEEE) Submittal, (TAC Nos. M83598 and M83599), Adams Accession No. 9811270046 & 9811270044, November 20, 1998.

BSEP 17-0111 Enclosure Attachment 8 Page 10 of 31 Table 3-1: Disposition and Resolution of Open Peer Review Findings and Self-Assessment Open Items Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment Dependency analysis was performed on the identified HFE combinations (see BNP-PSA-034 (Revision 17),

BNP-PSA-034 and associated Brunswick Nuclear Plant PRA -

spreadsheets). The dependency Human Reliability Analysis, Section assessment approach used appears to 7.1.5, discusses that dependence be appropriate. In developing recovery between any two or more human rules to be applied to the cutsets, failure events that appear in the maximum combinations of 3 HFEs were same cut set were manually included. Any cutsets with greater than examined. Table 9 lists the three HFEs that meet the recovery rule individual HEPs. Table 10 lists the criteria are recovered to a minimum joint Summary of Combinations of Post-HFE of 1E-6 (and often higher). As a Initiator, Procedure-Driven (Type result, there are cutsets that contain CP) HFEs. The highest order QU-C2-1 more than three HFEs that are being dependency event in Table 10 recovered to a higher frequency than includes several cutsets with 4 QU-C2 I/II/III Internal may be warranted (either because one HEPs. However, in examining the Events or more of the additional HFEs may be top 95% cutsets, there were some independent of the others, or because cutsets with 5 and 6 HEP events the joint HFE probability is still above that were not explicitly analyzed for the floor value of 1E-6 (and often dependencies. But with the use of higher). As a result, there are cutsets a minimum combination HEP that contain more than three HFEs that value, there would be little to no are being recovered to a higher change to the current recovery frequency than may be warranted values when adding those (either because one or more of the additional HEPs to the dependency additional HFEs may be independent of analysis. The larger bulk of the others, or because the joint HFE dependencies addressed have probability is still above the floor value of produced an HRA with realistic 1E-6 and hence could be reduced results and further).

BSEP 17-0111 Enclosure Attachment 8 Page 11 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment would not be notably affected by applying additional dependency This conservatism appears to increase QU-C2-1, recoveries that exist in low the calculated CDF/LERF by at least a Continued significant cutsets, and therefore modest amount.

have no effect on the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 12 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment As a resolution to this finding the following was performed:

Detailed operator interviews were Operator interview insights are conducted for the purpose of documented in the HRA Calculator. The confirming procedure information contained in the HRA interpretations. PRA documents Calculator was sufficient to demonstrate have been updated to improve that Capability Category I was met. their clarity in this area.

However, the information in the HRA did not demonstrate that detailed talk

The HFEs mentioned are no throughs with Operations and Training longer used in the PRA.

Personnel were conducted for the purpose of confirming procedure

A generic operator discussion 3-3 sheet was added to the BNP HRA interpretations. For example, many of HR-E3 I the calculations referred only to an calculation.

Internal interview conducted with a single Events

Operator interviews were stated operator on 9/16-17/2008. A few calculations referred a "talk through" in where applicable in the HRA January 2008, an operator interview on calculator. If there were any special 3/11/2010, or simulator runs conducted comments from the operator, they on 1/19/2010. A few calculations were included in the operator (OPER-BLACKSTART, OPER-CNS, response tab for each operator OPER-CWSIE) did not have any input action.

on operator interviews. The purpose and Since this finding already meets content of these interviews is not CAT I this finding simply represents evident.

an opportunity for enhancement to the documentation and does not affect CDF or the risk metrics for the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 13 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment While it was documented that simulator As a resolution to this finding the observations and talk-throughs were HRA documentation has been performed in most HRA calculations, updated to reference applicable there is no evidence that these simulator runs, operator interviews, 3-4 observations or talk-throughs were used and checklists.

to confirm the response models for the HR-E4 I Internal scenarios modeled in the PRA. For This finding meets CAT I and is a Events example, there was no interview document enhancement issue checklist, simulator/scenario checklist, only. This finding does not affect or other documentation to demonstrate CDF or the risk metrics for the that the HRA analyst confirmed the EDG #4 assessment.

response models.

BSEP 17-0111 Enclosure Attachment 8 Page 14 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment The BNP LERF model includes two operator recovery actions for cases of instrumentation or control problems as a part of the original analysis. These recovery actions As discussed in BNP-PSA-049, take into account plant conditions Appendix D, Section D.1, the CET for feasibility, as well as use structure allows for the identification of bounding repair rates for recovery and repair actions that can instrumentation repairs in the terminate or mitigate the progression of exponential failure model. This 3-12 a severe accident. This process was treatment is consistent with the incorporated into the original analysis, LE-C3 I repair justification requirements of Internal rather than performing a review of CCII for SR LE-C3. Because these Events significant accident progression actions were incorporated in the sequences and then incorporating original analysis, this SR is met at repair, as would be inferred from the CCI. If a full review of significant standard. However, it does not appear accident progression sequences that significant accident progression for equipment repair was sequences were reviewed.

performed, credit would be minimal and would not have a significant impact on calculation of importance measures. Therefore, there is no impact on the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 15 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment No credit for equipment survivability or human actions in adverse environments is taken in the BNP LERF model that would There is no evidence that significant satisfy SR LE-C10 or LE-C12. Not accident sequences were reviewed to crediting continued equipment determine if engineering analyses could operation beyond equipment 3-11 support continued equipment operation qualification limits or equipment LE-C10 or operator actions to reduce LERF. It that could be impacted by I

Internal LE-C12 was noted that this conservative containment failure is adequate for Events approach with respect to equipment identifying risk significant SSCs.

survivability was documented in the Credit for equipment survivability uncertainty analysis (BNP-PSA-075, beyond qualification limits or Table 1, Item 236). operator actions in adverse environments is not expected to change the LERF risk profile significantly. Therefore, there is no impact on the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 16 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment The BNP LERF model does not provide any credit for scrubbing in the reactor building, and therefore is treated in a conservative manner consistent with CCI. This lack of BNP-PSA-049, Section 3.1.2 notes that scrubbing credit does not affect the the treatment of scrubbing by the 3-13 CDF results or the relative reactor building is treated in a component importances to CDF.

LE-C13 I conservative method. This conservative Internal Including a scrubbing credit to approach was identified in the Events applicable LERF scenarios would uncertainty analysis (BNP-PSA-075, result in some level of reduction in Table 1, Item 217).

the overall LERF results, but would not have a significant impact on the relative component importance measures. Therefore, there is no impact on the EDG #4 assessment.

No changes have been made to the model in response to this F&O.

For small break LOCA, the high end of 1-11 A specific MAAP analysis was water break is approximately 1" dia.,

performed to confirm that RCIC is a SC-B3 I/II/III RCIC is credited for HPI for success, but Internal success path for a 1-inch diameter no MAAP run was performed to Events break. This is a documentation demonstrate the success.

issue and does not impact the EDG

4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 17 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment The CDF and LERF contributions from gasket and expansion joint failures, including effects from propagation, have been included in the internal flooding models. BNP IFPRA calculations contain the listing of expansion joints and gaskets along with their failure rates. The component failures have From IFSO-A4, the effects of gaskets been mapped to the associated and expansion joint failures were not initiating events in the model. New propagated beyond failing the attached scenarios and their propagation IFSN-A8 equipment.

impacts based on similar pipes in IFSN-A8 I the flood zone have been Internal Section F.4.8 discusses the propagation developed and assessed for the Flood between rooms, and basis for drain expansion joint and gasket flooding paths. No propagation from gaskets or scenarios. The circulating expansion joints was modeled.

expansion joints are not risk significant to the BNP IFPRA risk as circulating water piping does not contribute a significant amount to CDF/LERF and circulating water expansion joint ruptures represent a small portion of the total rupture frequency for IFPRA. Therefore this will not impact the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 18 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment The IFSO-A section lacks documentation on several modeling

The system diagrams and system requirements that are shown to be description for the Liquid Radwaste correct through investigation.

System were collected, reviewed, and documented in the IFPRA

In IFSO-A1, no drain backflow calculation as described in the propagation identification provided in the response to IFSN-B2. The floor documentation. Investigation shows that drain flow to the Radwaste Building drains flow to an exterior rad waste and the conclusion that drain building floor drain collection tank from backflow is not a flooding concern all locations which would justify the in the other buildings was verified.

IFSO-B2 assumption in [BNP-PSA-035 Section]

F.1.3; however there is no discussion, IFSO-B2 II

The documentation of door failure Internal drawings, or justification provided in the critical height determination has Flood analysis for screening been included per the response to IFSN-A2.

In IFSO-A1 there is little to no documentation of doors and door

A list of all potential flood sources failures contributing to propagation and was updated and documented as critical height determination.

described in the response to IFSNA15. The capacities of those

Capacity of the sources per IFSO-A5 is systems retained for further not documented, it was identified this assessment are included in the information is in the flooding database updated documentation and but it is not discussed in the flooding calculation.

BSEP 17-0111 Enclosure Attachment 8 Page 19 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment were compared to the capacities from the database table used in the flooding propagation analysis.

Capacities used for all sources in the original propagation analysis IFSO-B2, bounded the capacities for all Continued systems described in the response to IFSN-A15.

There is no impact on the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 20 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment 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 As a resolution to this finding example, the operator action OPER-HFEs were analyzed and plant LDSHD calculation does not have the specific and scenario-specific cognitive procedure listed and does not performance shaping factors such address the training requirements.

as training were added if Calculations for OPERMSIVCBP and 3-6 applicable. Procedures and training OPER-DEPRESS1 state that simulator frequencies for operator actions HR-G3 I/II/III and classroom training are provided but Internal noted in the finding have been does not provide a frequency. The Events added to the documentation. The calculations for OPER-DCDG and standard is met and this is an OPER-N2SUPPLY do not address opportunity for enhancement to the training, the cognitive procedure or the documentation and does not affect staffing requirements. Problems were CDF or the risk metrics for the noted with the HRA calculation for EDG #4 assessment.

OPER-DCDG. Specifically, no execution failure probabilities were assigned to the tasks of starting and connecting the DG.

Additionally, the calculation may not have considered all of the necessary breaker manipulations.

BSEP 17-0111 Enclosure Attachment 8 Page 21 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment 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 A check was performed on the notebook captures the human error level 2 model for both BNP units to modeling, and incorporated the general determine if any data needed to be methodology approach used in Level 1 updated due to their risk HRA.

significance. Only 4 events were found and all of them had either a 1-19 However, the data values documented FV in the x10-3 range or a RAW of in BNP-PSA-049 were developed during LE-E1 I/II/III 1. Because of the small number of Internal a previous PRA update. It appears that events that could have a need to Events some values may need to be updated to be updated but were not, the be consistent with changes in the Level relatively low value of FV for three 1 data. For example, OSP recovery of the retained events, and the values (such as ACP1XHE-MN-OFFE) relatively low RAW value on the are not consistent with the current OSP remaining event, the effect on the recovery curve (and LOSP is now EDG #4 assessment.is negligible.

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.

BSEP 17-0111 Enclosure Attachment 8 Page 22 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment The existing flood scenario frequencies have been adjusted to include both the Electric Power Research Institute (EPRI) Flood and Major Flood initiating event frequencies. Table F.15 of the New Methodology was applied to use internal flooding calculation pipe length and flood and major flood provides a mapping of piping frequency based on diameter and flow frequencies and their associated rate. The analysis should have system designation. The updated evaluated flood frequency for small pipe EPRI values are from TR and flows, and Flood frequency AND 3002000079. Since the flooding IFEV-A5 Major Flood frequency for large pipe frequency data in the calculation and flows. However, the analysis only and the EPRI data have different IFEV-A5 Not Met Internal applied major flood frequencies to large pipe size breakpoints, the pipe size Flood pipe, omitting flood frequency from large intervals were adjusted to match.

pipe which is the dominant frequency. The corresponding frequencies were then adjusted by the ratio of Table F.15 provides the different new EPRI flood and major flood frequencies from the EPRI Tech Report, frequency to existing major flood but they are applied incorrectly in the frequency. The appropriate analysis as shown in Table F.16. multiplier was then applied to each scenario based on pipe size and fluid system type. This assumes all floods are Major Floods that bound both Flood and Major Flood frequency contributions. This does not affect the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 23 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment A scenario-specific human error probability (HEP) that meets the requirements of the Standard was developed (i.e., see response to F&Os IFSN-A3 and IFQU-A6) and included in the updated model and quantification. The guidance in SR HR-F1 of Section 2-2.5 of the Standard for developing human The operator action referred to in the failure events (HFEs) was followed, resolution for mitigation of SW floods and the HRA Calculator, v5.1, and the XOPER_F25 HFE satisfy which meets the requirements of IFQU-A5 approved HRA methodology. The the Standard, was used. An assumed screening value for HFE operator interview was conducted IFQU-A5 Not Met Internal XOPER_F60 (1E-3/XOPER_F25) is still on February 6, 2017, to validate Flood credited in the analysis and satisfies the the procedures and assumptions condition specified in the ASME PRA used as the basis for the modeling.

Standard for a significant event with All assumptions and bases for the regard to the FV importance measure. performance shaping factors (PSFs) were documented in the HRA Calculator. Dependency analysis was considered for both CDF and LERF in regards to the new flooding operator action, and documentation of dependency levels has been included in the assessment. The accident sequences were assessed

BSEP 17-0111 Enclosure Attachment 8 Page 24 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment in the cutset review, and descriptions of the top cutsets were included in the documentation.

Detailed modeling of XOPER_F60 yields a human error probably IFQU-A5, lower than the one previously used Continued (combination human error probability of 1E-3 (XOPER_F25 and XOPER_F60)). Therefore the current analysis is conservative and does not impact risk insights for the EDG #4 assessment.

IFQU-A6 IFQU-A6 Not Met See IFQU-A5 Finding See IFQU-A5 Finding Internal Flood

BSEP 17-0111 Enclosure Attachment 8 Page 25 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment Documentation of the processes used to determine the applicable flooding sequences and the quantification of the model has been added in accordance with the requirements of the Standard. The accident sequences/cutsets were reviewed of consistency and correctness, and the sequence-The documentation did not justify specific HEP that was added was screening of the flood sources, and did validated. The basis for this not explain sufficiently the description of documentation F&O included IFQU-B2 cutsets and sequences for dominant several specific items that have floods. There is an inconsistency in also been addressed individually.

IFQU-B2 Internal documentation between how The process that describes how Flood conventional service water and nuclear flood sources were screened was service water are identified in the flood documented, and the list of analysis, flood database, and PRA potential flood sources retained for model sequences. further analysis has been updated (i.e., see F&O responses IFSN-A15 and IFSN A16). The fault trees and initiating event frequencies have been updated based on changes documented in the other F&O responses, and the model has been requantified. The detailed descriptions of the cutsets and accident sequences have been

BSEP 17-0111 Enclosure Attachment 8 Page 26 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment added. The Conventional Service Water and Nuclear Service Water modeling has been validated and clarified.

Differences were attributed to a variation in the initiating event IFQU-B2, frequencies used. These Continued frequencies were reviewed and modifications made to ensure both units used the same methodology.

These corrections eliminated differences in the results between units, so there is no impact on the EDG #4 assessment.

The BNP fire PRA quantification calculation has been revised and the screening of HGL Multi Compartment Analysis has been performed in accordance with NUREG/CR-6850. The screening A screening value for rated barrier value of 0.1 was used on the 1-34 probability of 1E-2 was applied. This exposing compartment to screen FSS-G2 Met I/II/III may not be bounding depending on the out compartments from the MCA Fire features of the barrier (doors, analysis. However, the 0.1 barrier penetrations, dampers).

failure probability was also applied for certain fire compartment combinations where the partitioning element was open. This has a minimal impact on the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 8 Page 27 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment Truncation in the CDF and LERF was varied, based upon the CCDP/CLERP.

For example, CCDP of 1.0 uses a truncation of 1.0, while a CCDP of 1E-03 uses a truncation of 1E-07. Overall, The truncation approach has been the process using the ones run results in changed in Rev 1 of the difficultly running FRANC at a very low quantification calculation in cutoff. response to this F&O. Scenarios are now run at an effective QU-B2 NOT MET A review of the truncation levels was truncation of 1E-09/yr for CDF and performed. Hundreds of the sequences 1E-10/yr for LERF which is more QU-B3 NOT MET have truncation within a factor of 100 or than four orders of magnitude 1-36 less of the CCDP. Several of these below the resulting CDF and LERF FQ-B1 MET I/II/III sequences were re-run, and the new plant totals. The previously Fire CDFs were compared to the original identified software limitations, that QU-F2 MET I/II/III CDFs. Changes in the results vary from prevent meeting the 5%

about 5% to as much as 25%. Many of convergence criterion when the FQ-F1 MET I/II/III the sequences affected are in the top 25 model is quantified with ONEs to fire sequences. diagnose fire effects, would not be applicable when the model is Additionally, a large number of quantified with TRUEs. Therefore, scenarios are listed with zero CCDP. there is no impact on the EDG #4 When these were re-run with lower assessment.

truncation values, cutsets were generated. This can be important for scenarios with higher ignition frequencies.

BSEP 17-0111 Enclosure Attachment 8 Page 28 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment BNP-PSA-080 Section 4.3.4, Fire Induced Spurious Event Probabilities, document the methods used for conditional failure probabilities for fire- Spurious cable failures were induced circuit failures. Circuit Analysis analyzed, and probabilities were was performed in change package BNP- included in the Fire PRA.

0137 to determine the probability of a Conditional failure probabilities spurious operation for various cables. were assigned to the most risk Risk significant contributors were not significant contributors, causing identified (quantification was complete them to become less risk later in the process) and utilized thus significant and allowing these less cannot met the capability category CC- risk significant contributors to II. appear relatively more risk significant. More could have been 2-22 CF-A1 Met I For example, the Unit 1 CDF importance done, but the iterative process results include the following spurious stopped when satisfactory results Fire CF-B1 Met I/II/III events for which conditional probabilities were obtained.

have not been developed:

HPC1PPS-SA-N12A_TPRESSURE SWITCH E41-N012A SPURIOUSLY The current analysis is ACTUATES conservative in that for cases HPC1PPS-SA-N12C_TPRESSURE where specific conditional SWITCH E41-N012C SPURIOUSLY probabilities have not been ACTUATES developed, failure or spurious RCI1TME-HI-021B_TTEMPERATURE operation is given a probability of ELEMENT E51-TE-N021B SPURIOUS 1.0. Therefore, there is no impact OPERATION on the EDG #4 assessment.

RCI1TME-HI-022B_TTEMPERATURE ELEMENT E51-TE-N022B SPURIOUS OPERATION

BSEP 17-0111 Enclosure Attachment 8 Page 29 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment RCI1PPS-SA-N012A_TPRESSURE SWITCH E51-N012A SPURIOUS OPERATION RCI1PPS-SA-N012C_TPRESSURE SWITCH E51-N012C SPURIOUS OPERATION HPC1PPS-SA-N12B_TPRESSURE SWITCH E41-N012B SPURIOUSLY ACTUATES HPC1PPS-SA-N12D_TPRESSURE SWITCH E41-N012D SPURIOUSLY ACTUATES SRV1SRV-CO-F013G_TNON-ADS SAFETY RELIEF VALVE B21-F013G SPURIOUSLY OPENS 2-22, contd RHR1MDP-SA-C002C_TRHR PUMP E11-C002C SPURIOUS START DUE TO FIRE RCI1PPS-SA-N012B_TPRESSURE SWITCH E51-N012B SPURIOUS OPERATION RCI1PPS-SA-N012D_TPRESSURE SWITCH E51-N012D SPURIOUS OPERATION HPC1PPS-SA-N17A_TPRESSURE SWITCH E41-N017A SPURIOUS OPERATION HPC1PPS-SA-N17B_TPRESSURE SWITCH E41-N017B SPURIOUS OPERATION

BSEP 17-0111 Enclosure Attachment 8 Page 30 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment SWS1PPS-SAP129L_TPRESSURE SWITCH PS129 SPURIOUS OPERATION FAILS LOW ISOLATES SWS1PPS-SAP129L_TPRESSURE SWITCH PS129 SPURIOUS OPERATION FAILS LOW ISOLATES HEADER 2-22, contd Note that if the instrument spurious operations above are not caused by a hot short, detailed circuit analysis is likely not needed. However, the valve and pump spurious operation would likely benefit from additional analysis.

In lieu of an accepted generic The BNP FPRA calculates using: method at the time, BNP used the

1) A severity factor 0.1, where 90% of analysis method piloted at HNP.

4-1 the fires are contained within the MCC However, FAQ 14-0009 has since FSS-A1 NOT MET

2) HRR severity factors are treated been issued and uses a breaching Fire independently, similar to other cabinets. factor of 0.23. The impact of MCC fires on the EDG #4 assessment is minimal.

Passive fire barriers with a fire resistance rating are credited in the Walkdowns were performed to 6-4 multi-compartment analysis. The failure gather the targets and barriers FSS-G4 MET I rates used are those prescribed in between the exposed Fire NUREG 6850, however, the worst case compartment. This has a minimal value for failure probability of the barrier impact on the EDG #4 assessment.

is used.

BSEP 17-0111 Enclosure Attachment 8 Page 31 of 31 Finding Supporting Capability Disposition for EDG #4 Description Number Requirement(s) Category (CC) Assessment As described in Attachment 7 to BNP-PSA-080, plant walkdowns were performed to identify targets in the exposed compartments near the barriers separating the exposing and exposed compartments. The localized Screening methodology is provided in damage in the adjacent BNP-PSA-080, Section 6.0. compartment near barriers for all compartments that screened out However: the MCA screening did not and for compartments where MCA consider the impact of possible localized was performed but did not achieve 6-5 effect (e.g., damage to equipment) near a HGL in the combined FSS-G2 MET I/II/III penetrations and barriers. compartments was included. The Fire localized targets of the adjacent In addition, a screening value was used compartment were added to the without justification and the cumulative HGL evaluation for the exposed risk for the screened scenarios was not compartment. Neither the evaluated. guidance in NUREG/CR-6850 nor Supporting Requirement FSSG2 in ASME/ANS RA-Sa-2009 requires an evaluation of the cumulative risk of the screened scenarios to justify the definition of a screening value.

There is no impact on the EDG #4 assessment.

BSEP 17-0111 Enclosure Attachment 9 PRA Uncertainty Evaluation

BSEP 17-0111 Enclosure Attachment 9 Page 1 of 26

1. Purpose Regulatory Guides 1.174 (Ref. 5.1) and 1.177 (Ref. 5.2) 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 are within the guidelines of Reg Guide 1.177 even when the uncertainties associated with the PRA model are taken into consideration.

2. Approach Sources of model uncertainty and related assumptions have been identified for the BSEP PRA models using the guidance of NUREG-1855 (Ref. 5.3) and EPRI TR-1016737 (Ref. 5.4) to identify those items that are potentially significant for the evaluation of this application. Although these guidance documents were primarily developed to evaluate the uncertainties associated with the internal events PRA model the approach can be applied to other types of hazard groups as well. For this analysis, uncertainties were considered for Internal Events and Fire models, since these models contribute significantly for the overall delta CDF and delta LERF for the application relative to the other quantitative hazards.

If the BSEP PRA model used a non-conservative treatment, or methods which are not commonly accepted, the underlying assumption or source of uncertainty was reviewed to determine its impact on this application. Only those assumptions or sources of uncertainty that could significantly impact the configuration risk calculations were considered key for this application.

3. PRA Uncertainty Analysis Three types of uncertainty are evaluated; parameter uncertainty, model uncertainty, and completeness uncertainty. These are defined extensively in Reg Guides 1.174, Regulatory Guide 1.177, NUREG 1855, and EPRI Report 1016737.

BSEP 17-0111 Enclosure Attachment 9 Page 2 of 26 3.1. Parametric Uncertainty Because the Brunswick model is fully populated with failure data EFs and correlated failure rates, parametric uncertainty was evaluated for the base model (Ref. 5.6) (that is, a detailed Monte Carlo calculation was performed on the base model CDF and LERF values) using the latest BSEP PRA model for internal events. This model does not include internal flooding, seismic, external flooding, high winds, or fire. The point estimate CDF calculated by that model is 2.85E-06 for Unit 1 and 2.87E-6 for Unit 2.

Note that the CDF uncertainty data is delineated in Table 1 and Figures 1 and 2.

Table 1 Calculated Parameters for the CDF Monte Carlo Assessment CDF Parameter Value BNP 1 BNP 2 Mean 2.87E-06 2.96E-06 Median 2.52E-06 2.57E-06 95% Upper Bound 5.47E-06 5.52E-06 5% Lower Bound 1.32E-06 1.36E-06

BSEP 17-0111 Enclosure Attachment 9 Page 3 of 26 Figure 1: Unit 1 CDF Parametric Uncertainty Distribution Figure 2: Unit 2 CDF Parametric Uncertainty Distribution The point estimate LERF calculated by that model is 8.75E-08 for Unit 1 and 9.04E-08 for Unit 2. The LERF uncertainty data is delineated in Table 2 and Figures 3 and 4.

Table 2 Calculated Parameters for the LERF Monte Carlo Assessment LERF Parameter Value BNP 1 BNP 2 Mean 8.89E-08 9.04E-08 Median 7.37E-08 7.65E-08 95% Upper Bound 1.76E-07 1.79E-07 5% Lower Bound 3.90E-08 4.13E-08

BSEP 17-0111 Enclosure Attachment 9 Page 4 of 26 Figure 3: Unit 1 LERF Parametric Uncertainty Distribution Figure 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%.

BSEP 17-0111 Enclosure Attachment 9 Page 5 of 26 The range of the uncertainty interval is not expected to significantly change for the application model of the one-time extended CT. The added unavailability due to the #4 EDG maintenance evolution is not related to a state-of-knowledge correlated basic event and therefore would have no impact on the as-documented baseline parametric uncertainty analysis. For these reasons, a separate Monte Carlo analysis was not performed on the application delta CDF and LERF cutsets.

3.2. 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.

The BSEP PRA uncertainty analysis (Ref. 5.5) 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 high due to the application. Table 3 delineates the results of that analysis. No key uncertainties were identified during this evaluation.

The EPRI uncertainty guideline (Ref. 5.4) 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 4. No key uncertainties were identified during this evaluation.

A separate evaluation of uncertainty issues pertaining specifically to the BSEP Fire PRA model (Ref. 5.8) was conducted. Table 5 provides a list of fire risk uncertainty issues and the results of that analysis. No key uncertainties were identified during this evaluation.

BSEP 17-0111 Enclosure Attachment 9 Page 6 of 26 Table 3 Plant Specific High Level Uncertainty Evaluations No URI1 Uncertainty Description Uncertainty Evaluation 1 High SRV failure to open data is highly uncertain. SRV failures did not contribute to the delta risk 2 High BNP Unit 2 digital upgrades are appropriately represented by the analog Realistically conservative bias. May reduce components that they replaced. The PRA model uses the same analog potential for spurious plant trips.

failure modes; no model changes were made.

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

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

5 High The Brunswick model makes the assumption that the Emergency Busses Peer reviewed cat II. Generic analysis supports the E1 through E8 located in the Diesel Generator Building Switchgear rooms operation of the electrical equipment in the do not depend on the buildings HVAC system to perform its primary switchgear rooms for a 24-hour mission time.

function during a 24-hour mission time.

6 High The Supplemental Diesel Generator uses generic industry failure data for Peer reviewed cat II standard Emergency Diesel Generators.

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

8 High Components located near each other should be included. Peer reviewed cat II 9 High Failure of five SRVs to lift is assumed to result in vessel overpressure and Applicable to ATWS only. Not applicable for this core damage. application 10 High Failure to relieve pressure is postulated to result in a failure of the reactor Not applicable for this application vessel that cannot be mitigated by injection sources.

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

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

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

14 High For all actions except for the short term actions associated with a Reviewed for this application. No impact on this response to an anticipated transient without scram (ATWS), the median application.

response times and execution times were estimated based on discussions with operations personnel.

BSEP 17-0111 Enclosure Attachment 9 Page 7 of 26 Table 3 Plant Specific High Level Uncertainty Evaluations No URI1 Uncertainty Description Uncertainty Evaluation 15 High For each type Cp interactions, the corresponding failure event was initially Peer reviewed cat II assigned a screening probability of 0.1.

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

17 High Flooding in the CS pump rooms, RHR pump rooms and HPCI rooms is Not applicable for this application assumed to occur in all rooms at an equal rate for a pipe break that occurs above the 20 foot elevation in the reactor buildings.

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

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

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

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

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

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

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

25 High Common cause failures are assumed to occur simultaneously. Peer reviewed cat II 26 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 27 High The release may be impacted when the source of fission products is at a Delta LERF too small for consideration very high temperature.

28 High For Arrest Core Melt Progress in in-Vessel, the best estimate success LERF at or below 6E-09 and not significantly criteria used in this evaluation are based on the time available from the impacted by application initiation of core degradation until just before substantial core relocation occurs. This typically is on the order of 30-40 minutes.

29 High Estimating containment fragility associated with flooded vessel loads, LERF at or below 6E-09 and not significantly extreme thermal, and shear loads on pipe extensions through the impacted by application biological shield includes considerable uncertainty.

BSEP 17-0111 Enclosure Attachment 9 Page 8 of 26 Table 3 Plant Specific High Level Uncertainty Evaluations No URI1 Uncertainty Description Uncertainty Evaluation 30 High There are minimal or no credit for recovery of failed equipment and the LERF at or below 6E-09 and not significantly loss of adequate injection at the time of containment failure. impacted by application 31 High It is judged that the SRVs may reclose or not be capable of being LERF at or below 6E-09 and not significantly opened. impacted by application 32 High Injection flow rate of approximately 1000 gpm is assumed required to LERF at or below 6E-09 and not significantly overcome the heat of oxidation and to prevent the core melt impacted by application progression.

33 High The BNP model assumes that the crew will Initiate drywell venting if LERF at or below 6E-09 and not significantly combustible gases are present in the containment. This results in a high and impacted by application 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.

34 High The vacuum breaker fail to close (FTC) basic events are quantified based LERF at or below 6E-09 and not significantly on an estimated number of vacuum breaker cycles assumed to occur impacted by application during the event.

35 High It is not possible to reach definitive conclusions regarding steam explosion LERF at or below 6E-09 and not significantly phenomena in the Brunswick Mark I containment. impacted by application 36 High Loss of containment heat removal sequences with the RPV intact are LERF at or below 6E-09 and not significantly assumed in the model to result in a probabilistic split between containment impacted by application leakage and large failure.

37 High Loss of adequate in-vessel injection coupled with inadequate containment LERF at or below 6E-09 and not significantly heat removal results in moderately high temperatures and also conditional impacted by application probability of leakage versus rupture.

38 High The size of containment failures may vary over the spectrum of accident LERF at or below 6E-09 and not significantly sequences. impacted by application 39 Section F.1.3 of RSC10-05 states that flows through drains were Not applicable for this application considered, but there is no discussion concerning drain paths as a possible propagation path between rooms in the Auxiliary Building basement nor the basis for not considering such paths. Discussion of drain paths not included. Propagation through wall penetrations, cable trays, and 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.

As indicated in the BNP PRA Model Uncertainty Calculation (Ref 5.5)

BSEP 17-0111 Enclosure Attachment 9 Page 9 of 26 Table 4 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 function of several LOOP sequences Applicable factors including switchyard design, the number Not a key uncertainty because and independence of offsite power feeds, the consensus model was used to local power production and consumption determine LOOP frequencies.

environment and the degree of plant control of Consequential LOOP sequences the local grid and grid maintenance. were added before the last peer Three different aspects relate to this issue: review and found to meet capability Consequential LOOP category II. A consensus model was 1a. LOOP initiating event frequency values and sequences used for offsite power recovery.

recovery probabilities 1b. Conditional LOOP probability LOOP or consequential LOOP 1c. Availability of dc power to sequences with offsite power perform restoration actions recovered.

2 Support System Increasing use of plant-specific models for Support system event Not applicable - Only loss of offsite Initiating Events support system initiators (e.g., loss of SW, CCW, sequences power or AC bus initiators could affect or IA, and loss of ac or dc buses) have led to the applicable metrics for this inconsistencies in approaches across the application.

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

BSEP 17-0111 Enclosure Attachment 9 Page 10 of 26 Table 4 Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application 4 Operation of Station Blackout events are important Credit for continued operation Applicable - addressed adequately equipment after contributors to baseline CDF at nearly every US of these systems with batteries for this application in the BNP MOR battery depletion NPP. In many cases, battery depletion may be depleted (e.g., long-term SBO assumed to lead to loss of all system capability. sequences)

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 LOCA The assumed timing and magnitude of RCP seal Accident sequences involving Not Applicable for BWR treatment - PWRs LOCAs given a loss of seal cooling can have a loss of seal cooling substantial influence on the risk profile.

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

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

Success Criteria (SC) 7 Impact of Many BWR core cooling systems utilize the Loss of containment heat Applicable - addressed adequately containment suppression pool as a water source. Venting of removal scenarios with for this application in the BNP MOR.

venting on core containment as a decay heat removal mechanism containment venting The suppression pool is not credited cooling system can substantially reduce NPSH, even lead to successful as a water source after a successful NPSH flashing of the pool. The treatment of such containment vent.

scenarios varies across BWR PSAs.

BSEP 17-0111 Enclosure Attachment 9 Page 11 of 26 Table 4 Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application 8 Core cooling Loss of containment heat removal leading to Long term loss of decay heat Applicable - Vent paths other than the success following long-term containment over-pressurization and removal sequences hardened wetwell vent path are not containment failure failure can be a significant contributor in some credited for non-ATWS sequences or venting through PSAs. Consideration of the containment failure and are considered to be a failure of non hard pipe vent mode might result in additional mechanical the venting function..

paths 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 room temperatures Dependency on HVAC for Applicable - DG HVAC is explicitly calculations exceeding equipment qualification limits. system modeling and timing of modeled. Other HVAC systems do not Treatment of HVAC requirements varies across accident progressions and impact the metrics for this application.

the industry and often varies within a PSA. There associated success criteria.

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.

10 Battery life Station Blackout events are important Determination of battery Applicable - The sequences calculations contributors to baseline CDF at nearly every US depletion time(s) and the dominating risk metrics for this NPP. Battery life is an important factor in associated accident sequence application include some SBO assessing a plants ability to cope with an SBO. timing and related success sequences where AC power recovery Many plants only have Design Basis calculations criteria. is not credited. However, more for battery life. Other plants have very realistic (longer) battery depletion plant/condition specific calculations of battery life. times would not have a significant Failing to fully credit battery capability can impact on the metrics for this overstate risks, and mask other potential application.

contributors and insights. Realistically assessing battery life can be complex.

BSEP 17-0111 Enclosure Attachment 9 Page 12 of 26 Table 4 Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application 11 Number of PWR EOPs direct opening of all PORVs to System logic modeling Not Applicable for BWRs PORVs required reduce RCS pressure for initiation of bleed and representing success criterion for bleed and feed feed cooling. Some plants have performed plant- and accident sequence timing

- PWRs specific analysis that demonstrate that less than for performance of bleed and all PORVs may be sufficient, depending on feed and sequences involving ECCS characteristics & initiation timing. success or failure of feed and bleed.

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

performance new sump strainers at most plants. All BWRs suppression pool (BWRs) have improved their suppression pool strainers to system modeling and reduce the potential for plugging. However, there sequences involving injection is not a consistent method for the treatment of from these sources (Note that suppression pool strainer performance. the modeling should be relatively 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.)

BSEP 17-0111 Enclosure Attachment 9 Page 13 of 26 Table 4 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 RCS/RPV pressure Success criterion for Not Applicable - This is a condition failure of pressure transients requiring pressure relief. Usually, there prevention of RPV that would occur very soon after relief is sufficient capacity to accommodate the overpressure. (Note that scram. The BNP SRVs are either pressure transient. However, in some scenarios, uncertainty exists in both the mechanically operated or dependent failure of adequate pressure relief can be a determination of the global on drywell nitrogen and DC control consideration. Various assumptions can be taken CCF values that may lead to power. The SRVs have accumulators on the impact of inadequate pressure relief. RPV overpressure and what is that are good for several hours after done with the subsequent RPV scram and the DC power is provided overpressure sequence by batteries. Short term SRV modeling.) operation is therefore not dependent on EDG operability. The initial pressure transient is determined by operation of the SRVs and this the potential for overpressure is not EDG or AC or DC power dependent Systems Analysis (SY) 14 Operability of Due to the scope of PSAs, scenarios may arise System and accident Applicable - These conditions are equipment in where equipment is exposed to beyond design sequence modeling of modeled in the BNP MOR; however, beyond design basis environments (w/o room cooling, w/o available systems and required the risk metrics for this application are basis environments component cooling, w/ deadheading, in the support systems not sensitivity to these ISLOCA presence of an un-isolated LOCA in the area, conditions.

etc.).

Human Reliability Analysis (HR) 15 Credit For ERO Most PSAs do not give much, if any credit, for System or accident sequence Applicable - This issue does not initiation of the Emergency response modeling with incorporation of adversely impact this application.

Organization (ERO), including actions included in HFEs and HEP value Important operator actions and plant-specific SAMGs and the new B5b mitigation determination in both the Level recovery actions have been identified strategies. The additional resources and 1 and Level 2 models and crews briefed accordingly. The capabilities brought to bear via the ERO can be ERO could have an positive impact on substantial, especially for long-term events. these sequences that would reduce actual plant risk.

Internal Flooding (IF)

BSEP 17-0111 Enclosure Attachment 9 Page 14 of 26 Table 4 Uncertainties Considered from EPRI 1016737 Issue Description Issue Characterization Topic Discussion of Issue Part of Model Affected Applicability and Resolution for this Application 16 Piping failure One of the most important, and uncertain, inputs Likelihood and characterization Not Applicable - Application is not mode to an internal flooding analysis is the frequency of of internal flooding sources sensitive to non-LOOP initiators such floods of various magnitudes (e.g., small, large, and internal flood event as pipe breaks.

catastrophic) from various sources (e.g., clean sequences and the timing water, untreated water, salt water, etc.). EPRI associated with human actions has developed some data, but the NRC has not involved in flooding mitigation.

formally endorsed its use.

LERF Analysis (LE) 17 Core melt Typically, the treatment of core melt arrest in- LERF / Level 2 containment Applicable - Impact from Level 2 arrest in-vessel vessel has been limited. However, recent NRC event tree sequences events on the risk metrics is at or less work has indicated that there may be more than 1E-11 for LERF potential than previously credited. An example is credit for CRD in BWRs.

18 Thermally NRC analytical models and research findings LERF / Level 2 containment Not Applicable for BWR induced failure continue to show that a thermally induced steam event tree sequences of hot leg/SG tubes generator tube rupture (TISGTR) is more

- PWRs 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 failure The progression of core melt to the point of LERF / Level 2 containment Applicable - Impact from Level 2 mode vessel failure remains uncertain. Some codes event tree sequences events on the risk metrics is at or less (MELCOR) predict that even vessels with lower than 1E-11 for LERF 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).

BSEP 17-0111 Enclosure Attachment 9 Page 15 of 26 Table 4 Uncertainties Considered from EPRI 1016737 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 plants may be LERF / Level 2 containment Applicable - Impact from Level 2 cooling of lower submerged in water prior to the relocation of core event tree sequences events on the risk metrics is at or less head debris to the lower head. This presents the than 1E-11 for LERF 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 come in contact LERF / Level 2 containment Applicable - Impact from Level 2 contact with with the containment shell (e.g., some BWR Mark event tree sequences events on the risk metrics is at or less containment Is, some PWRs including free-standing steel than 1E-11 for LERF 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 contributor to LERF. ISLOCA initiating event Not Applicable - Application not Frequency One key input to the ISLOCA analysis are the sequences sensitive to non-LOOP initiators such Determination assumptions related to common cause failure of as ISLOCAs.

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

BSEP 17-0111 Enclosure Attachment 9 Page 16 of 26 Table 4 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 HEPs There is not a consistent method for the Entire Model Applicable - The HRA treatment treatment of pre initiator and post initiator human meets ASME Capability Category II errors. However, human failures events are and not considered to be significant to typically significant contributors to CDF and the application. However, several LERF. important operator actions were identified for additional staff briefings on recovery actions.

25 Treatment of There is not a consistent method for the Entire Model Applicable - The HRA treatment HFE treatment of potentially dependent post-initiator meets ASME Capability Category II dependencies human errors. SPAR models do not generally and not considered to be significant to include dependencies the application. However, several important operator actions were identified for additional staff briefings on recovery actions.

26 Intra-system Common cause failures have been shown to be Entire Model Applicable - The common cause common cause important contributors in PRAs. As limited plant failure treatment meets ASME events specific data is available, generic common cause Capability Category II, and the factors are commonly used. Sometimes, plant uncertainty of the generic CCF values specific evidence can indicate that the generic is included parametric uncertainty values are inappropriate. results. This is not considered to be significant to this application.

BSEP 17-0111 Enclosure Attachment 9 Page 17 of 26 Table 5 Fire Uncertainties

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

See sensitivity in section 4.1.

2 Fire Growth curves with the fire Fire growth curves for nonhigh This has a significant impact on growth of 12 minutes and then energy events are not realistic and fire CDF with a slower fire growth steady HRR until burnout is not much too fast. provides significant more time for realistic fire suppression, and lower likelihood of cable failure. This issue will be addressed by a sensitivity analysis presented in Section 4.1.

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 negligible maximum fire plume distance for change in CDF/LERF.

the individual fire source, 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 exit Many cabinets the fire growth This would reduce the fire CDF the cabinet regardless of the outside of the cabinet is not likely and impact of fire with a much amount of ventilation for the based upon analysis that indicates smaller zone of influence.

cabinet these fires are suffering from oxygen starvation.

5 BNP cables in certain locations are Fire propagation and time to fire This would reduce the fire CDF in protected with a flame retardant; damage would be longer up to 10 selected locations and reduce the this delays the damage and retards minutes and delay ignition for up to overall CDF. Would have a minor the propagation of the fire to other 12 minutes based upon NUREG/CR decrease in CDF/LERF impact cable tray. This flame retardant 6850 Table Q1. This was developed on this application due to the coating is not credited in the by testing of nonrated cables and locations where the flame current fire PRA. BNP has IEEE383 rated cables. retardant coatings are applied.

BSEP 17-0111 Enclosure Attachment 9 Page 18 of 26 Table 5 Fire Uncertainties

Uncertainty Evaluation Impact Discussion 6 At BNP, Motor Control Center Cabinets are not considered sealed, This is consistent with similar construction is such that the access but are considered reduced constructed MCCs treatment with panel doors are closed with capability for fire growth outside of other Peer Reviewed Fire PRAs multiple fasteners. These MCC the cabinet. This is a much more and the treatment discussed in doors also have gaskets around the realistic evaluation of the effects of a BWR OG report 000001258912 door. This results in essentially a MCC fire. R0 (Report for BWR Owners closed cabinet. 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/delta CDF.

7 The BNP isophase buses contain This is a slight nonconservatism in Based upon the actual location of quick disconnects which are used that if counted would increase the these quick disconnects and to disconnect the main generator locations for bus ducts fires, but very targets no impact would be from the switchyard. Because slightly reduce the fire frequency of expected for the EDG CT. The there is no guidance in Section 7 of each individual bus duct fire source. failure of one of these disconnects NUREG/CR6850, Supplement 1 for (due to have more locations) in the past did not cause any treating these disconnects, they damage to cables.

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 areas The effects of changes to the containing equipment unimportant that have been screened from the ignition frequency for ignition to fire risk, the criteria for selection global analysis boundary is source bins would affect both the of the Global Plant Analysis performed as per the guidance in base Fire CDF/LERF and LAR Fire Boundary could result in an NUREG/CR6850. The resultant CDF/LERF similarly. Thus this is undercount of components for increase apportionment of Fire not expected to be a significant some bin(s) and thereby the Ignition Frequency among the source of uncertainty related to conservative calculation of ignition remaining ignition sources is delta risk for the application.

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

BSEP 17-0111 Enclosure Attachment 9 Page 19 of 26 Table 5 Fire Uncertainties

Uncertainty Evaluation Impact Discussion 9 Bounding values from NUREG/CR This bounds 98% of possible HRR The effects of changes to the HRR 6850 were typically used for the scenarios as described in NUREG/CR of ignition sources would affect 98%ile fires based on the HRR case. 6850. both the base Fire CDF/LERF and For a limited number of sources The most accurate method would be LAR Fire delta CDF/LERF similarly.

these values were adjusted based to use HRR from oxygen restricted The effect is most apparent in on fire modeling insights. cabinets for those cabinets with scenarios with large numbers of small ventilation openings. This targets or those which achieve methodology has not been approved HGL. In these cases masking may at the time of this analysis. contribute to a smaller delta CDF/LERF. Reduction in HRR would reduce masking effects and therefore potentially slightly increase the delta CDF/LERF for the application. 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.

10 Fires involving oil are assumed to This method is conservative, The effects of instant ignition of instantly spill and instantly ignite especially for treatment of large oil would affect both the base Fire to maximum HRR with no fire quantities of oil. CDF/LERF and LAR Fire CDF/LERF growth. 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 ZOIs calculated are based Targets on the edge of the ZOI may The effects of changes to the time on damage thresholds that do not require prolonged exposures (up to to damage at the edges of the ZOI incorporate heat soak time. 30 minutes) prior to damage, but are would affect both the base Fire treated as instantly failed in the Fire CDF/LERF and LAR Fire CDF/LERF PRA after the time delay to damage similarly. This is not expected to for each tray in stacked tray be a significant source of configuration uncertainty related to delta risk for the application.

BSEP 17-0111 Enclosure Attachment 9 Page 20 of 26 Table 5 Fire Uncertainties

Uncertainty Evaluation Impact Discussion 12 The vertical and horizontal Using a larger square footage for the This is not expected to impact any components of the ZOI were based fuel package for the vertical results due to more realistic ZOI on bounding assumptions for the component of the ZOI results in a was determined for the cabinets size of the fuel package (i.e. 1 ft2 smaller ZOI and consequently fewer in the Main Control Room. The for the vertical component and 6 targets being impacted. Similarly, Main Control Room cabinet ft2 for the horizontal component). using a smaller footprint for the dimensions were used to reduce horizontal ZOI results in a smaller the ZOI to more realistic sizes.

horizontal ZOI dimension. This treatment results in an exaggerated ZOI, and therefore, provides for a conservative selection of targets.

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

caused by cutting and welding absence of a sustained ignition sources will not spread beyond the source.

original tray.

14 Transient fires due to Cutting and Placement of transient ignition The effects of target sets for Welding (Bins 06, 24, and 36) sources is based on selection of cutting and welding sources involve the same target sets as the vulnerable targets. These are would affect both the base Fire general transients (Bins 03, 07, 25, expected to be the same targets sets CDF/LERF and LAR Fire CDF/LERF 37). Separate ignition source to for transient fires caused by cutting similarly. This is not expected to target set relationships are not and welding activities. be a significant source of defined in this calculation for uncertainty related to delta risk transients fires caused by Cutting for the application.

and Welding.

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

BSEP 17-0111 Enclosure Attachment 9 Page 21 of 26 Table 5 Fire Uncertainties

Uncertainty Evaluation Impact Discussion 16 In some cases field conditions did This method of target identification There was very limited use of not allow for raceways to be is not expected to affect the results drawing only for raceway location located. For these, Fixed and of this analysis. Where possible, determination. The use of Transient ignition source targets uncertainty has been reduced drawings for target set were determined through review through determination of ignition determination would affect both of controlled drawings. sources from which the raceways the base Fire CDF/LERF and LAR should be excluded. In the event of a Fire CDF/LERF similarly. This is HGL scenario all routing is failed not expected to be a significant based on what is listed as in the source of uncertainty related to compartment, and is therefore not delta risk for the application.

subject to this uncertainty.

17 A heat release rate for lubrication Use of a bounding HRR for oil The effects of oil HRR would oil of 2,000 kW/m2 is assumed to applications may result in affect both the base Fire provide a bounding value over that conservative target set CDF/LERF and LAR Fire CDF/LERF which is used in all oil applications determination. No method has been similarly thus no impact is described in this calculation. determined for an alternate HRR. expected.

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

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 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 not assumed HGL would affect both encompass entire compartments probable by the use of detailed fire the base Fire CDF/LERF and LAR regardless of the ability of the modeling. This may be needed to Fire CDF/LERF similarly. These ignition source to create a HGL. remove the conservatism for these compartments where results This was based on the either a lack areas. were giving significant Fire of information or uncertainty CDF/LERF were further about fire size or heat release of investigated to reduce the HGL the ignition source. uncertainty.

20 Target Damage time is based on A higher temperature may be more A higher damage threshold will 400F due to Thermoplastic cable appropriate. Note that the 400F provide more time for temperature was only used in the suppression and potentially time to damage calculation. 625F reduce CDF and delta CDF.

was used for generating the ZOIs.

BSEP 17-0111 Enclosure Attachment 9 Page 22 of 26 Table 5 Fire Uncertainties

Uncertainty Evaluation Impact Discussion 21 Electrical cabinets, relay cabinets, Although direct equipment damage The effects of fire on sensitive and some sensitive equipment may may occur at a point below the HGL equipment would affect both the have damage thresholds below the threshold temperature, it is expected base Fire CDF/LERF and LAR Fire 625°F utilized for cable failure. that the impacts are captured CDF/LERF similarly. Additionally indirectly though the cable failures cables attached to the electrical due to either a ZOI fire or HGL cabinets, some of which are in the resulting from cable involvement. fire ZOI fail the function giving the same or 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 application.

22 A manual suppression response A dedicated fire watch with an The effects of manual suppression time of 2 minutes is utilized for extinguisher is required to be response time would affect both Cutting and Welding ignition stationed at the hot work site. the base Fire CDF/LERF and LAR sources. Utilization of manual suppression Fire CDF/LERF similarly. This is times based on FAQ080050 during not 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 All plant modifications credited in None.

conceptual modifications. the BNP FPRA for the NFPA 805 submittal are now complete.

Therefore, this is no longer an uncertainty issue.

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

operation of HPCI and RCIC is not an area of uncertainty.

credited unless RHR supplies suppression pool cooling.

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

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

BSEP 17-0111 Enclosure Attachment 9 Page 23 of 26 Table 5 Fire Uncertainties

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

transformers will damage these in an area of uncertainty cables. No credit is given for their armor shielding.

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

during fire scenarios that it is or if credit were taken for pre credited for. briefing or prealigning components.

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

29 The Fire PRA is taking credit for EC Main Control Room cabinets Fire PRA includes plant features as 50724, Integrate/Activate the crediting incipient detection are: designed and operated.

Control Building Fire Panel.

BNP1 BNP2 1H12P601 2H12P601 (2 drops) (2 drops) 1H12P603 2H12P603 1XU1 2XU1 1XU2 2XU2 1XU3 2XU3 1XU51 2XU51 1XU4 2XU4 2XU69 1XU80 2XU80 30 The coordination study BNP157, It is assumed the length difference The actual cable length could be ignores cable drop length, but between the drop and addition shorter or longer than actually credits the entire length of the length of partially tray run are used in the coordination endpoint cable tray. negligible. study. This difference is expected to be within the uncertainty of the coordination study method and application in the PRA model.

31 Operator Actions to supply A screening value is applied due to The undeveloped HEPs were alternate power to DC panels the actions being undeveloped. applied only in the battery rooms.

19A and 210A utilize a screening Detailed HRA analysis would provide A detailed HEP applied to a value of 0.1 a smaller HEP. broader set of compartments would provide greater CDF reduction.

BSEP 17-0111 Enclosure Attachment 9 Page 24 of 26 4.0 Application Specific Uncertainty Analysis For this application, the baseline and application risk results were evaluated and cutsets were identified that were unique to the application results (delta cutset file). 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. This evaluation was conducted qualitatively, and no additional quantitative sensitivity analyses were performed.

One area of uncertainty in the conservative direction is that as a part of the extended CT, BSEP has brought an additional temporary 4kV diesel generator system consisting of two 480V, 2000 kW diesel generators with synchronization capability, and a 480V/4.16kV transformer. The Temporary Diesel generator system is arranged to tie into the 4.16KV electrical distribution system at the supplemental diesel generator electrical enclosure. The temp diesel system will remain fueled and available for service, but not physically connected to the Brunswick Electrical distribution system. In the event of a loss of a 4KV vital bus (E1, E2, E3, or E4) and concurrent failure of the supplemental diesel generator, the temp diesel generator will be capable of supplying a 4.16KV balance of plant bus 2C, which supplies 4.16kV vital bus E4. In the PRA analysis of the extended TS CT, no credit is given for this temporary diesel generator.

This is an uncertainty to the analysis which would further lower the overall risk of the #4 EDG out of service configuration.

4.1 Fire Frequency Uncertainty Analysis In the time since the BSEP FPRA was developed, new data has been developed. In particular, NUREG-2169 (ignition frequencies), NUREG-2178 (heat release rates), and NUREG/CR-7150 (cable failure probabilities) are most relevant to the BNP FPRA. The individual impacts of these unincorporated changes are mixed, but the net effect on total risk is expected to be bounded by a factor of 2. Bin 15 (electrical enclosure) is the dominant contributor to fire risk and the updated ignition frequency increased by less than a factor of 2. The ignition frequencies for Bin 4 (main control boards) and Bin 8 (diesel generators) also increased. But, the risk increases associated with updated ignition frequencies for Bin 15 and Bin 4 are at least partially mitigated by decreases in

BSEP 17-0111 Enclosure Attachment 9 Page 25 of 26 the associated heat release rates. There were also significant decreases in the ignition frequency for other Bins, including Bin 7 (transients) and Bin 16a (HEAF). In general, the updated cable failure probabilities also tend to decrease the calculated risk. While it is not possible to precisely quantify the change in risk without actually incorporating these new data, the trend has historically been toward risk reduction. In order to assess the impact this uncertainty has on the Fire PRA results in this application, a bounding assessment was performed by increasing the Fire risk contribution for both CDF and LERF by a factor of 2. The results of this assessment can be seen in Table 6.

Table 6: ICCDP and ICLERP for Fire Uncertainty Impact ICCDP ICLERP (44 Days) (44 Days)

Unit 2 - #4 EDG Out of Service Configuration (Fire 2.76E-07 5.95E-09 Results Nominal)

Unit 2 - #4 EDG Out of Service Configuration (Fire 3.41E-07 1.12E-08 Results 2x Nominal)

With the bounding assessment of the increased fire risk, there would still maintain significant margin to the 1E-06 and 1E-07 limits for ICCDP and ICLERP respectively.

Based on this assessment, the uncertainty associated with the ignition frequencies, heat release rates, and cable failure probabilities for the BSEP fire PRA model would not have a significant impact on the application.

4.2 Conclusion This evaluation demonstrates that following a review of BSEP PRA model uncertainties that none are key sources of uncertainty for the application and not expected to have a significant impact on the results. The results provide that within reasonable assurance, the numerical risk results of this application are within the guidelines of Reg Guide 1.177 even when the uncertainties associated with the PRA model are taken into consideration.

BSEP 17-0111 Enclosure Attachment 9 Page 26 of 26 5.0 References 5.1 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 5.2 USNRC Regulatory Guide 1.177, An Approach for Plant-Specific, Risk-Informed Decision Making: Technical Specifications, Rev. 1 5.3 USNRC NUREG 1855, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making, Vol. 1, March 2009 5.4 EPRI Report 1016737, Treatment of Parameter and Modeling Uncertainty for Probabilistic Risk Assessments, December 2008 5.5 BNP Calculation BNP-PSA-075, BNP Uncertainty Analysis, Rev. 3 5.6 BNP Calculation BNP-PSA-030, PRA Model Sequence Quantification, Rev. 13 5.7 USNRC Regulatory Guide 1.200, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Rev. 2 5.8 BNP Calculation BNP-PSA-080, BNP Fire PRA - Quantification, Rev. 5

BSEP 17-0111 Enclosure Attachment 10 PRA Seismic Evaluation

BSEP 17-0111 Enclosure Attachment 10 Page 1 of 9 4.1.5 Bounding Seismic Evaluation This section provides a bounding analysis for the evaluation of seismic risk for this application to demonstrate it would not affect the decision, consistent with RG 1.174 and RG 1.177. In addition to the qualitative discussion as to why seismic risk is a very small contributor to the overall risk increase and does not impact the decision, a bounding quantitative study is also provided.

BSEP previously developed a bounding qualitative and quantitative analysis of seismic risk with an inoperable diesel generator to support a request to extend the Completion Time (CT) Technical Specifications (TS) 3.8.1 (Reference 1). A supplemental AC power source (i.e., a supplemental diesel generator (SUPP DG)) with the capability to power any E-bus within one hour from a Station Blackout (SBO) event, and with the capacity to bring the affected unit to cold shutdown was added at the same time. The analysis demonstrated that the bounding risk was below the RG 1.177 guidelines for impact on plant risk, and that implementation of that TS change was acceptable.

The BSEP bounding seismic risk analysis is updated herein to incorporate the updated seismic hazard analysis from the BSEP review of the Fukushima Dai-ichi (F-D) accident (Reference 2) and to assess the proposed CT for the EDG #4 repair. This updated analysis demonstrates that seismic risk for the EDG #4 maintenance activity is a small contributor to total plant risk and is well below the RG 1.177 guidelines for implementation of this one-time only TS CT change impact on plant risk.

Qualitative Analysis of Seismic Risk:

The original geologic and seismic siting investigations for BSEP were performed in accordance with Appendix A to 10 CFR Part 100 and meet General Design Criterion 2 in Appendix A to 10 CFR Part 50. The Safe Shutdown Earthquake Ground Motion (SSE) was developed in accordance with Appendix A to 10 CFR Part 100 and used for the design of Seismic Class I systems, structures and components.

Earthquakes in the vicinity of the BSEP are relatively infrequent. This is attributable to presence of broad coastal plains and mountains of ancient geologic origin occurring 100 miles inland, physiographic conditions generally indicative of relative seismic stability.

Based on the seismic history of the site, the Operating Basis Earthquake (OBE) for the

BSEP 17-0111 Enclosure Attachment 10 Page 2 of 9 site was chosen as a high intensity VI on the Modified Mercalli Scale with a ground acceleration of 0.08 g. The SSE was considered to be a high intensity VII on the Modified Mercalli Scale. For BSEP, the site response spectra are based on peak horizontal ground accelerations of 0.08g and 0.16g, for an OBE and an SSE respectively.

Plant Equipment: The High Pressure Core Injection pumps and the Reactor Core Isolation Cooling pumps, as well as the other safety grade pumps, are located on the -

17 foot elevation. In addition to the inherent seismic robustness of these components in this location, these components will see little additional seismic acceleration and thus would be expected to be undamaged in the event of a seismic event. Similarly both the essential and non-essential switchgear is located low in seismic structures and would be expected to be undamaged in the event of a seismic event.

In January 2011 seismic walk-downs and evaluations were performed to validate the previous IPEEE findings and review plant modifications. As with the IPEEE the Review Level earthquake of 0.3g was generally used, which is about twice the Safe Shutdown Earthquake (SSE of 0.16g). No significant changes were noted for the IPEEE results.

The results confirmed that in addition to the EDGs, other methods of core cooling are also very robust, such as the HPCI Pump, which has a HCLPF of 0.95g. The equipment installed at BSEP is monitored for equipment degradation and vibration issues which provide a basis for the expectation that the inherent equipment ruggedness has not been degraded. An example of this is the US industry experience with the North Anna seismic event, where the NRC has stated that no equipment failures were caused by the seismic event. This provides additional support that a seismic event does not pose an additional risk when a BSEP DG is out of service.

Additional defense in depth against a seismic induced loss of off-site power have been added at BSEP with the replacement of the SAMA diesels with FLEX diesels to support the station batteries in the event of a DG failure, and the re-enforcement of the block wall near the Diesel Driven Fire Pump, which is a low pressure injection source. The added supplemental diesel generator (SUPP DG) provides another layer of defense in depth beyond the DG and the FLEX Diesels. The SUPP DG is inherently rugged as are all similar diesels, in a separate location from the other DGs, and could be started after the seismic event if required.

BSEP 17-0111 Enclosure Attachment 10 Page 3 of 9 Seismic Induced Flooding: The seismic induced flooding does not add risk because the two most sensitive areas for internal flooding are the Cable Spread Rooms where a water source could break and the consequences potentially fail the battery chargers, which results in loss of DGs when DC power is lost. In this scenario the unavailability of a DG does not change the outcome. The second area is the -17 foot elevation of the Reactor Building. At this elevation failure could encompass the HPCI, RCIC and RHR.

Again in this case the unavailability of the diesel does not change the outcome of this second important flooding scenario.

Conclusion of Qualitative Analysis of Risk: Given the capacity for high shear wave velocity for the BSEP structures and the inherent ruggedness of installed plant equipment, with recent industry experience and the added multiple layers of defense in depth provides reasonable assurance that the seismic contribution is very small portion of the overall risk increase for a increased CT for a DG out of service. Additionally seismically induced flooding was considered and the unavailability of DG would not impact the outcome of these scenarios.

Quantitative Assessment of Seismic Risk:

The bounding quantitative analysis developed previously (Reference 1) involved the following steps:

1. Determine a bounding scope of equipment assumed failed by any seismic event above the Operating Basis Earthquake(OBE)/Safe Shutdown Earthquake (SSE) event

2. Determine a CDF/LERF for base case failing equipment not seismically qualified to the OBE/SSE (no DG extended CT applied)

3. Determine a CDF/LERF with extended CT applied for each DG and failing equipment not seismically qualified to OBE/SSE.

The mean annual frequency of exceedance for a Safe Shutdown Earthquake (SSE)

(0.16g) at BSEP used in the analysis was estimated to be 1.4E-4 per year from EPRI Probabilistic Seismic Hazard Evaluations (Reference 3). Also, the EPRI mean annual frequency of exceedance for an Operating Basis Earthquake (OBE) (0.08g) at BSEP was estimated to be 6.0E-4 per year.

BSEP 17-0111 Enclosure Attachment 10 Page 4 of 9 In response to NRC 10 CR 50.54(f) (Reference 4), and following the guidance provided in the SPID (Reference 5), a seismic hazard reevaluation has been performed for BSEP (Reference 2). The resulting mean hazard curves for Brunswick are shown below in Figure 2.3.7-1 from Reference 2 for the seven spectral frequencies for which ground motion equations are defined. Tabulated values of mean and fractile seismic hazard curves for PGA at Brunswick are also provided below in Table A-1a from Reference 2.

From this table, the revised value for the mean annual frequency of exceedance for a SSE (0.16g) at BSEP is estimated to be 1.05E-04 per year. The mean annual frequency of exceedance for an OBE (0.08g) at BSEP is estimated to be 4.17E-4 per year.

To estimate the risk due to seismic hazard the BSEP PRA internal events model was used to develop a bounding delta Core Damage Frequency (CDF) and a bounding delta Large Early Release Frequency (LERF) resulting from having any one EDG out of service along with a non-recoverable LOOP and failing equipment not evaluated to remain functional following an OBE or SSE. This included the following inputs and failed equipment:

Non-recoverable loss of off-site power at 1.0 All other initiating events at 0.0 HPCI retained in PRA model Condensate Storage Tank failed Both FLEX diesels failed Both Fire Pumps failed RCIC pump failed SUPP DG not credited Non-safety related equipment failed (lost power)

The Grid Centered LOOP Initiating Event was set to the annual probability of exceeding the SSE, or 1.4E-4/yr (EPRI value) for the baseline analysis, with all other initiating events set to 0.0. The result of the base condition with no additional EDG CT considered, and with the equipment conditions above, results in a base CDF of 6.2E-08 for Unit 1 and 6.5E-08 Unit 2. Calculations were repeated for LERF and for the EPRI OBE (6.0E-04/yr), The results of the base cases are shown in Tables 4-1-5a through 4-1-5d. The same inputs were then used with applying DG extended CT for each diesel is

BSEP 17-0111 Enclosure Attachment 10 Page 5 of 9 evaluated, and a ratio of the Fukushima Dai-ichi (F-D) exceedance probabilities were applied.

EPRI F-D Factor SSE -

1.4E-04 1.05E-04 0.75 0.16g OBE -

6.0E-04 4.17E-04 0.70 0.08g The results for all cases at the SSE and OBE are shown in the tables below. The ICDF, ICCDP and ICLERP were determined as follows:

ICDF = (Seismic Initiating Event Frequency) x CDF (w/ a LOOP and DG out of service)

ICCDP = (ICDF-Base CDF, or CDF) x (AOT; per day, 14 days, 28 days, 60 days)

ICLERP = (ILERF-Base LERF, or LERF) x (AOT; per days, 14 days, 28 days, 60 days)

BSEP 17-0111 Enclosure 0 Page 6 of 9

BSEP 17-0111 Enclosure Attachment 10 Page 7 of 9 The results show that neither the bounding seismic ICCDP nor the seismic ICLERP are significant contributors to risk during the EDG #4 maintenance period. This is an extreme bounding estimate in that off-site power and the listed components above all are assumed to fail at the OBE seismic event. This is not realistic given switchyards are not expected to fail at the OBE and the other important equipment are very robust and are also not expected to fail at the OBE level. In addition, no credit is taken for repair of any failed equipment, nor is credit taken for: the SUPP DG, the FLEX diesels, or the Contingency Diesels that have been pre-staged as a compensatory measure. Each of these would further reduce the ICCDP and ICLERP. Setting the initiating event frequency to the annual probability of exceeding the OBE of 0.08g does not result in an ICCDP greater than 1.0E-7 or an ICLERP greater than 1.0E-8 for the assumed maintenance period for EDG #4.

It is concluded, therefore, that the BSEP risk increase is negligible when considering a potential seismic event during the use of the Emergency Diesel Generator (EDG) #4 Technical Specification extended completion time.

References:

1. Progress Energy Letter BSEP 12-0050, 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,: dated June 19, 2012, ADAMS Accession No. ML12173A112.

2. Duke Energy Letter BSEP 14-0028, Seismic Hazard and Screening Report (CEUS Sites), Response to NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding the Seismic Aspects of Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 31, 2014, ADAMS Accession No. ML14106A461.

3. Electric Power Research Institute (EPRI) NP-6395-D, Probabilistic Seismic Hazard Evaluations at Nuclear Power Plant Sites in the Central and Eastern United States: Resolution of the Charleston Earthquake Issue, May 1. 1989.

BSEP 17-0111 Enclosure Attachment 10 Page 8 of 9

4. United States Nuclear Regulatory Commission (USNRC), E. Leeds and M.

Johnson, Letter to All Power Reactor Licensees et al., "Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident", March 12, 2012.

5. Electric Power Research Institute (EPRI), Report 1025287, "Seismic Evaluation Guidance: Screening, Prioritization and Implementation Details (SPID) for the Resolution of Fukushima Near-Term Task Force Recommendation 2.1: Seismic,"

November 2012.

BSEP 17-0111 Enclosure Attachment 10 Page 9 of 9 Table 4-1-5a: CDF and ICCDP of SSE (0.16g, F-D frequency of 1.05E-4 /year) during EDG AOT ICDF ICDF per day Base F-D -CDF ICCDP ICCDP ICCDP ICCDP Days to EDG #4 (w/ EPRI SSE (w/ F-D SSE factor CDF Factor (F-D SSE) (per day) (14 days) (44 days) (60 days) 1.0E-06 Frequency) Frequency) (1/365)

Unit 1 6.2E-08 5.2E-07 0.75 3.9E-07 3.3E-07 2.7E-03 9.0E-10 1.3E-08 3.95E-08 5.4E-08 1,113 Unit 2 6.5E-08 5.1E-07 0.75 3.8E-07 3.2E-07 2.7E-03 8.7E-10 1.2E-08 3.83E-08 5.2E-08 1,150 Table 4-1-5b: LERF and ILERF of SSE (0.16g, F-D frequency of 1.05E-4 /year) during EDG AOT ILERF ILERF per day Base F-D -LERF ICLERP ICLERP ICLERP ICLERP Days to EDG #4 (w/ EPRI SSE (w/ F-D SSE factor LERF Factor (F-D SSE) (per day) (14 days) (44 days) (60 days) 1.0E-07 Frequency) Frequency) (1/365)

Unit 1 8.7E-10 5.6E-09 0.75 4.2E-09 3.3E-09 2.7E-03 9.1E-12 1.3E-10 4.01E-10 5.5E-10 10,961 Unit 2 8.7E-10 5.9E-09 0.75 4.4E-09 3.6E-09 2.7E-03 9.7E-12 1.4E-10 4.29E-10 5.8E-10 10,267 Table 4-1-5c: CDF and ICCDP of OBE (0.08g, F-D frequency of 4.17E-4 /year) during EDG AOT ICDF ICDF per day Base F-D -CDF ICCDP ICCDP ICCDP ICCDP Days to EDG #4 (w/ EPRI OBE (w/ F-D OBE factor CDF Factor (F-D OBE) (per day) (14 days) (44 days) (60 days) 1.0E-06 Frequency) Frequency) (1/365)

Unit 1 3.4E-07 2.3E-06 0.70 1.6E-06 1.3E-06 2.7E-03 3.4E-09 4.8E-08 1.52E-07 2.1E-07 290 Unit 2 3.5E-07 2.3E-06 0.70 1.6E-06 1.2E-06 2.7E-03 3.4E-09 4.8E-08 1.51E-07 2.1E-07 292 Table 4-1-5d: LERF and ILERF of OBE (0.08g, F-D frequency of 4.17E-4 /year) during EDG AOT ILERF ILERF per day Base F-D -LERF ICLERP ICLERP ICLERP ICLERP Days to EDG #4 (EPRI OBE (F-D OBE factor LERF Factor (F-D OBE) (per day) (14 days) (44 days) (60 days) 1.0E-07 Frequency) Frequency) (1/365)

Unit 1 4.9E-09 3.4E-08 0.70 2.4E-08 1.9E-08 2.7E-03 5.1E-11 7.2E-10 2.26E-09 3.1E-09 1,949 Unit 2 4.9E-09 3.6E-08 0.70 2.5E-08 2.0E-08 2.7E-03 5.5E-11 7.7E-10 2.43E-09 3.3E-09 1,814

BSEP 17-0111 Enclosure Attachment 11 PRA Quantification Data Tables

BSEP 17-0111 Enclosure Attachment 11 Page 1 of 77 1: PRA Quantification Data Tables Cutsets for BSEP Unit 2 have been provided below for both CDF and LERF for Internal Events, Internal Flooding & Fire.

High Winds (Tornado Only) cutsets are not presented because their contribution to the overall delta CDF and delta LERF is sufficiently small compared to the other hazards. Unit 2 cutsets were chosen because they serve as the basis for the overall ICCDP and ICLERP results presented in the main PRA Evaluation.

Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 5.26E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 2 1.73E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO

BSEP 17-0111 Enclosure Attachment 11 Page 2 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM214 OPER4160X+OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 3 1.73E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERFPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPERSPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM326 1.00E+00 XPOWEROP1 Fraction of annual year at power 4 1.73E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC

BSEP 17-0111 Enclosure Attachment 11 Page 3 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPERSPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM326 1.00E+00 XPOWEROP1 Fraction of annual year at power 5 1.73E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPERSPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM326 1.00E+00 XPOWEROP1 Fraction of annual year at power 6 1.73E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT

BSEP 17-0111 Enclosure Attachment 11 Page 4 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.00E+00 OPERN2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPERSPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM312 OPERSPCE+OPERISOSWAP+OPERN2SUPPLY 1.00E+00 XPOWEROP1 Fraction of annual year at power 7 1.65E08 5.80E01 %2T_T TURBINE TRIP INITIATOR 2.39E03 ACP0BKROO2AC6 CIRCUIT BREAKER FROM SAT #2 TO 2C (2AC6) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 OPERLDSHD FAILURE TO COMPLETE DC LOAD SHED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.19E05 XOPCOM410 1.00E+00 XPOWEROP1 Fraction of annual year at power 8 1.65E08 5.80E01 %2T_T TURBINE TRIP INITIATOR

BSEP 17-0111 Enclosure Attachment 11 Page 5 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 2.39E03 ACP0BKROO2AC6 CIRCUIT BREAKER FROM SAT #2 TO 2C (2AC6) FAILS TO CLOSE 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 OPERLDSHD FAILURE TO COMPLETE DC LOAD SHED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPERSPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.00E+00 OPERWVDHR FAILURE TO INITIATE WETWELL VENTING FOR DHR 1.19E05 XOPCOM410 1.00E+00 XPOWEROP1 Fraction of annual year at power 9 1.32E08 0.00447 %2TE_U2_GC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (GRIDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 9.73E01 XACC01_U2_GC LOSP CASE 1 UNIT(GRIDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 6 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 10 1.26E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START EDG2DGNTM 1.92E02 D003_U2 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 3.79E05 XOPCOM236 OPER4160X+OPERSWRHRO 1.00E+00 XPOWEROP1 Fraction of annual year at power 11 1.25E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START EDG2DGNTM 0.0192 D003_U2 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 3.76E05 XOPCOM245 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 7 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 12 1.15E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.06E03 OPERALTNSW 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO SWS2MOVCC 6.25E04 V101 MOTOR OPERATED VALVE SW V101 FAILS TO OPEN 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E+00 XPOWEROP1 Fraction of annual year at power 13 1.15E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.06E03 OPERALTNSW 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERFPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO SWS2MOVCC 6.25E04 V101 MOTOR OPERATED VALVE SW V101 FAILS TO OPEN 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 8 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 14 1.15E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.06E03 OPERALTNSW 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION SWS2MOVCC 6.25E04 V101 MOTOR OPERATED VALVE SW V101 FAILS TO OPEN 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E+00 XPOWEROP1 Fraction of annual year at power 15 1.15E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.06E03 OPERALTNSW 1 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION SWS2MOVCC 6.25E04 V101 MOTOR OPERATED VALVE SW V101 FAILS TO OPEN

BSEP 17-0111 Enclosure Attachment 11 Page 9 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E+00 XPOWEROP1 Fraction of annual year at power 16 1.15E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.06E03 OPERALTNSW 1.00E+00 OPERISOSWAP FAILURE TO SWAP DIVISION II ISOLATION SIGNAL POWER SUPPLY 1.00E+00 OPERN2SUPPLY FAILURE TO ALIGN NITROGEN SUPPLY 1 OPERSDG Operator Fails to Start and Align SUPPDG During SBO SWS2MOVCC 6.25E04 V101 MOTOR OPERATED VALVE SW V101 FAILS TO OPEN 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E+00 XPOWEROP1 Fraction of annual year at power 17 1.15E08 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.06E03 OPERALTNSW 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERWVDHR FAILURE TO INITIATE WETWELL VENTING FOR DHR SWS2MOVCC 6.25E04 V101 MOTOR OPERATED VALVE SW V101 FAILS TO OPEN 0.772 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED)

BSEP 17-0111 Enclosure Attachment 11 Page 10 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 XPOWEROP1 Fraction of annual year at power 18 1.14E08 5.80E01 %2T_T TURBINE TRIP INITIATOR 2.39E03 ACP0BKROO2AC6 CIRCUIT BREAKER FROM SAT #2 TO 2C (2AC6) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 0.69 XHOSLDSHD_N SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPERLDSHD) 1.19E05 XOPCOM410 1.00E+00 XPOWEROP1 Fraction of annual year at power 19 1.14E08 5.80E01 %2T_T TURBINE TRIP INITIATOR 2.39E03 ACP0BKROO2AC6 CIRCUIT BREAKER FROM SAT #2 TO 2C (2AC6) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY

BSEP 17-0111 Enclosure Attachment 11 Page 11 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERSPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 1.00E+00 OPERWVDHR FAILURE TO INITIATE WETWELL VENTING FOR DHR 6.90E01 XHOSLDSHD_N SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPERLDSHD) 1.19E05 XOPCOM410 1.00E+00 XPOWEROP1 Fraction of annual year at power 20 1.05E08 4.32E03 %TE_S_SC SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 7.96E01 XACC01_S_SC LOSP CASE 1 SITE (SWITCH YARDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 21 8.65E09 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERFPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC

BSEP 17-0111 Enclosure Attachment 11 Page 12 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPERSPCL FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING LATE 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM326 1.00E+00 XPOWEROP1 Fraction of annual year at power 22 8.08E09 3.08E03 %TE_S_GC SITE LOSS OF OFFSITE POWER TO UNIT 1 (GRIDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 8.63E01 XACC01_S_GC LOSP CASE 1 SITE (GRIDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 23 7.98E09 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION

BSEP 17-0111 Enclosure Attachment 11 Page 13 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION RHR2PTFTM 9.71E03 LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 5.94E03 XOPNPSH 1.00E+00 XPOWEROP1 Fraction of annual year at power 24 7.98E09 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERNPSH FAILURE TO INTERMITTENTLY USE LPCI FOR MAKEUP TO VESSEL WITH LOSS OF SPC 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION RHR2PTFTM 9.71E03 LOOPA RHR LOOP A UNAVAILABLE DUE TO TEST OR MAINTENANCE 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 5.94E03 XOPNPSH 1.00E+00 XPOWEROP1 Fraction of annual year at power 25 6.85E09 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.92E02 EDG2DGNTM DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER)

BSEP 17-0111 Enclosure Attachment 11 Page 14 of 77 Table A111: Unit 2 Top 25 Delta CDF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability D003_U2 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERLDSHD FAILURE TO COMPLETE DC LOAD SHED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 3.71E01 XACC02_U2_SC LOSP CASE 2 UNIT(SWITCH YARDCENTERED) 4.29E05 XOPCOM221 OPER4160X+OPERFLEXDG 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 15 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 5.26E10 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E02 CAC2PHEFNINERT CONTAINMENT NOT INERTED; VENTING REQUIRED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERINJTERM OPERATOR INTERVENES AND TERMINATES INJECTION 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPN2DEPOP1SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IA) 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 2 2.63E10 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED)

BSEP 17-0111 Enclosure Attachment 11 Page 16 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 3 2.60E10 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERINJTERM OPERATOR INTERVENES AND TERMINATES INJECTION 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPN2DEPOP1SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IA) 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 4 1.73E10 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E02 CAC2PHEFNINERT CONTAINMENT NOT INERTED; VENTING REQUIRED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT

BSEP 17-0111 Enclosure Attachment 11 Page 17 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERINJTERM OPERATOR INTERVENES AND TERMINATES INJECTION 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPN2DEPOP1SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IA) 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM214 OPER4160X+OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 5 1.23E10 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 1.00E02 CAC2PHEFNINERT CONTAINMENT NOT INERTED; VENTING REQUIRED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS FAILURE TO MANUALLY INITIATE AND ALIGN LOWPRESSURE SYSTEMS 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERDEPRESSRPV FAILURE TO DEPRESS BEFORE RPV FAILS GIVEN RPV DEPRESS. FAILED IN LVL1 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 9.10E01 RXM2XHEMNINJ OPERATOR FAILS TO RECOVER INJECTION BEFORE RPV MELT 1.00E+00 SRV2ALTDEMETH ALTERNATE DEPRESS. METHODS NOT CREDITED 9.00E01 SRV2MCSNOPRES PRESSURE TRANSIENT DOES NOT FAIL MECHANICAL SYSTEMS 9.65E01 SRV2PHENOCMP SRVs DO NOT FAIL OPEN DURING CORE MELT PROGRESSION 9.00E01 SRV2PHENOTEMP HIGH PRIM SYS TEMP DOES NOT CAUSE FAIL OF RCS PRESS. BOUND

BSEP 17-0111 Enclosure Attachment 11 Page 18 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM214 OPER4160X+OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 6 1.04E10 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPN2DEPOP1SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IA) 4.00E01 RXN2INJRX2SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (OP=S, CLASS IA) 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 7 8.65E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START

BSEP 17-0111 Enclosure Attachment 11 Page 19 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM214 OPER4160X+OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 8 8.56E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERINJTERM OPERATOR INTERVENES AND TERMINATES INJECTION 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPN2DEPOP1SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IA) 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM214 OPER4160X+OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 20 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 9 8.25E11 5.80E01 %2T_T TURBINE TRIP INITIATOR 2.39E03 ACP0BKROO2AC6 CIRCUIT BREAKER FROM SAT #2 TO 2C (2AC6) FAILS TO CLOSE 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 OPERLDSHD FAILURE TO COMPLETE DC LOAD SHED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.19E05 XOPCOM410 1.00E+00 XPOWEROP1 Fraction of annual year at power 10 6.61E11 4.47E03 %2TE_U2_GC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (GRIDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY

BSEP 17-0111 Enclosure Attachment 11 Page 21 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 9.73E01 XACC01_U2_GC LOSP CASE 1 UNIT(GRIDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 11 6.29E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START EDG2DGNTM 1.92E02 D003_U2 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 3.79E05 XOPCOM236 OPER4160X+OPERSWRHRO 1.00E+00 XPOWEROP1 Fraction of annual year at power 12 6.24E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START EDG2DGNTM 1.92E02 D003_U2 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS

BSEP 17-0111 Enclosure Attachment 11 Page 22 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 3.76E05 XOPCOM245 1.00E+00 XPOWEROP1 Fraction of annual year at power 13 5.73E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.06E03 OPERALTNSW 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 6.25E04 SWS2MOVCCV101 MOTOR OPERATED VALVE SW V101 FAILS TO OPEN 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E+00 XPOWEROP1 Fraction of annual year at power 14 5.69E11 5.80E01 %2T_T TURBINE TRIP INITIATOR 2.39E03 ACP0BKROO2AC6 CIRCUIT BREAKER FROM SAT #2 TO 2C (2AC6) FAILS TO CLOSE 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES

BSEP 17-0111 Enclosure Attachment 11 Page 23 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 6.90E01 XHOSLDSHD_N SUCCESS OF DC LOAD SHED (COMPLEMENT OF OPERLDSHD) 1.19E05 XOPCOM410 1.00E+00 XPOWEROP1 Fraction of annual year at power 15 5.23E11 4.32E03 %TE_S_SC SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 7.96E01 XACC01_S_SC LOSP CASE 1 SITE (SWITCH YARDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 16 4.35E11 4.47E03 %2TE_U2_GC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (GRIDCENTERED) 1.00E02 CAC2PHEFNINERT CONTAINMENT NOT INERTED; VENTING REQUIRED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT

BSEP 17-0111 Enclosure Attachment 11 Page 24 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERINJTERM OPERATOR INTERVENES AND TERMINATES INJECTION 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPN2DEPOP1SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IA) 9.73E01 XACC01_U2_GC LOSP CASE 1 UNIT(GRIDCENTERED) 1.00E06 XOPCOM214 OPER4160X+OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 17 4.06E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START EDG2DGNTM 1.92E02 D003_U2 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION

BSEP 17-0111 Enclosure Attachment 11 Page 25 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 3.79E05 XOPCOM236 OPER4160X+OPERSWRHRO 1.00E+00 XPOWEROP1 Fraction of annual year at power 18 4.04E11 3.08E03 %TE_S_GC SITE LOSS OF OFFSITE POWER TO UNIT 1 (GRIDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERCRDFOINJ FAILURE TO ALIGN/CONTROL CRD SYSTEM FOR MAKEUP 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 5.00E01 XHOSCRDPMPBR CRD PUMP C11/C12C001B RUNNING C11/C12C001A IN STANDBY 8.63E01 XACC01_S_GC LOSP CASE 1 SITE (GRIDCENTERED) 6.08E06 XOPCOM324 OPERSPCE + OPERCRDFOINJ + OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 19 4.03E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED

BSEP 17-0111 Enclosure Attachment 11 Page 26 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START EDG2DGNTM 1.92E02 D003_U2 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 3.76E05 XOPCOM245 1.00E+00 XPOWEROP1 Fraction of annual year at power 20 3.44E11 4.32E03 %TE_S_SC SITE LOSS OF OFFSITE POWER TO UNIT 1 (SWITCHYARDCENTERED) 1.00E02 CAC2PHEFNINERT CONTAINMENT NOT INERTED; VENTING REQUIRED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERINJTERM OPERATOR INTERVENES AND TERMINATES INJECTION 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPN2DEPOP1SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IA) 7.96E01 XACC01_S_SC LOSP CASE 1 SITE (SWITCH YARDCENTERED) 1.00E06 XOPCOM214 OPER4160X+OPERDEPRESS1

BSEP 17-0111 Enclosure Attachment 11 Page 27 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 XPOWEROP1 Fraction of annual year at power 21 3.42E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERDEPRESS1 FAILURE TO DEPRESSURIZE FOLLOWING HCTL CURVES 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSPCE FAILURE TO INITIATE AND ALIGN SUPPRESSION POOL COOLING EARLY 1.00E+00 OPN2DEPOP1SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IA) 4.00E01 RXN2INJRX2SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (OP=S, CLASS IA) 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 1.00E06 XOPCOM214 OPER4160X+OPERDEPRESS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 22 3.42E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START EDG2DGNTM 1.92E02 D003_U2 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT

BSEP 17-0111 Enclosure Attachment 11 Page 28 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERLDSHD FAILURE TO COMPLETE DC LOAD SHED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 3.71E01 XACC02_U2_SC LOSP CASE 2 UNIT(SWITCH YARDCENTERED) 4.29E05 XOPCOM221 OPER4160X+OPERFLEXDG 1.00E+00 XPOWEROP1 Fraction of annual year at power 23 3.19E11 7.23E04 %2T_DC2A LOSS OF DC SWITCHBOARD 2A 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPERDCPALTDC2 FAILURE TO ALIGN DC BUS TO STANDBY DC POWER SUPPLY 1.00E+00 OPERFLEXDG FAILURE TO ALIGN FLEX DG TO BATTERY CHARGERS 1.00E+00 OPERLDSHD FAILURE TO COMPLETE DC LOAD SHED 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 9.50E01 XHOSDG3NORDC FLAG DG #3 / E3 / E7 ALIGNED TO NORMAL DC CONTROL POWER 5.00E02 XHOSDP10A1A DISTRIBUTION PANEL 10A ALIGNED TO ALTERNATE SUPPLY 2.32E02 XOPCOM240 1.00E+00 XPOWEROP1 Fraction of annual year at power 24 3.11E11 7.23E04 %2T_DC2A1 LOSS OF 125V DC PANEL 2A1 1.00E02 CAC2PHEFNINERT CONTAINMENT NOT INERTED; VENTING REQUIRED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6

BSEP 17-0111 Enclosure Attachment 11 Page 29 of 77 Table A112: Unit 2 Top 25 Delta LERF Cutsets for Internal Events Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERMANSW120 OPERATOR FAILS TO INITIATE RHRSW OR FIREWATER IN 2 HOURS 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 9.10E01 RXM2XHEMNINJ OPERATOR FAILS TO RECOVER INJECTION BEFORE RPV MELT 5.00E02 XHOSDP10A1A DISTRIBUTION PANEL 10A ALIGNED TO ALTERNATE SUPPLY 9.44E05 XOPCOM213 OPER4160X+OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 25 2.84E11 2.24E02 %2TE_U2_SC UNIT LOSS OF OFFSITE POWER TO UNIT 2 (SWITCHYARDCENTERED) 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START EDG2DGNTM 1.92E02 D003_U2 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERFLEXPUMP FAILURE TO STAGE AND ALIGN FLEX PORTABLE PUMP FOR RPV INJECTION 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSDG Operator Fails to Start and Align SUPPDG During SBO 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 4.80E01 RXN2INJRX3SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (CLASS IBE) 7.72E01 XACC01_U2_SC LOSP CASE 1 UNIT(SWITCH YARDCENTERED) 3.79E05 XOPCOM236 OPER4160X+OPERSWRHRO 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 30 of 77 Table A113: Unit 2 Top 25 Delta CDF Cutsets for Internal Flooding Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1 9.78E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.59E05 XOPCOM213 OPER4160X+OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 2 7.43E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 0.0091 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 3 7.43E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 31 of 77 Table A113: Unit 2 Top 25 Delta CDF Cutsets for Internal Flooding Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 4 3.93E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 3.85E05 XOPCOM236 OPER4160X+OPERSWRHRO 1.00E+00 XPOWEROP1 Fraction of annual year at power 5 3.35E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERFPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 4.10E03 XOPFPS1 OPERFPS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 6 2.59E09 2.70E05 %2TF38N2_11 Int Flood: Pipe 1499 2SW562013 in 38.North.2 BE floods area 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.59E05 XOPCOM213 OPER4160X+OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 7 2.22E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area

BSEP 17-0111 Enclosure Attachment 11 Page 32 of 77 Table A113: Unit 2 Top 25 Delta CDF Cutsets for Internal Flooding Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 2.39E03 ACP0BKROOE2E4 CIRCUIT BREAKER FROM E2 TO E4 (AH9) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.10E03 XOP480X OPER480X 1 XPOWEROP1 Fraction of annual year at power 8 2.22E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 2.39E03 ACP0BKROOE2E4 CIRCUIT BREAKER FROM E2 TO E4 (AH9) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 9 2.22E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 2.39E03 ACP0BKROOE4E2 CIRCUIT BREAKER FROM E4 TO E2 (AL5) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 10 2.22E09 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 2.39E03 ACP0BKROOE4E2 CIRCUIT BREAKER FROM E4 TO E2 (AL5) FAILS TO CLOSE

BSEP 17-0111 Enclosure Attachment 11 Page 33 of 77 Table A113: Unit 2 Top 25 Delta CDF Cutsets for Internal Flooding Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 11 1.98E09 2.06E05 %2TF38N2_10 Int Flood: Pipe 1497 2SW562011 in 38.North.2 BE floods area 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.59E05 XOPCOM213 OPER4160X+OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 12 1.97E09 2.70E05 %2TF38N2_11 Int Flood: Pipe 1499 2SW562013 in 38.North.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.10E03 XOP480X OPER480X 1 XPOWEROP1 Fraction of annual year at power 13 1.97E09 2.70E05 %2TF38N2_11 Int Flood: Pipe 1499 2SW562013 in 38.North.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START

BSEP 17-0111 Enclosure Attachment 11 Page 34 of 77 Table A113: Unit 2 Top 25 Delta CDF Cutsets for Internal Flooding Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 14 1.96E09 2.04E05 %2TF20AC2_17 Int Flood: Pipe 1185 2SW5286 in 20.Air Comp.2 BE floods area 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.59E05 XOPCOM213 OPER4160X+OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 15 1.5E09 2.06E05 %2TF38N2_10 Int Flood: Pipe 1497 2SW562011 in 38.North.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 16 1.5E09 0.0000206 %2TF38N2_10 Int Flood: Pipe 1497 2SW562011 in 38.North.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6

BSEP 17-0111 Enclosure Attachment 11 Page 35 of 77 Table A113: Unit 2 Top 25 Delta CDF Cutsets for Internal Flooding Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 17 1.49E09 2.04E05 %2TF20AC2_17 Int Flood: Pipe 1185 2SW5286 in 20.Air Comp.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 0.0091 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 18 1.49E09 2.04E05 %2TF20AC2_17 Int Flood: Pipe 1185 2SW5286 in 20.Air Comp.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 19 1.35E09 1.41E05 %2TF20AC2_5 Int Flood: Pipe 1398 2SW543063 in 20.Air Comp.2 BE floods area 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION

BSEP 17-0111 Enclosure Attachment 11 Page 36 of 77 Table A113: Unit 2 Top 25 Delta CDF Cutsets for Internal Flooding Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 9.59E05 XOPCOM213 OPER4160X+OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 20 1.24E09 1.29E05 %2TF20AC2_4 Int Flood: Pipe 1336 2SW54301 in 20.Air Comp.2 BE floods area 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.59E05 XOPCOM213 OPER4160X+OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 21 1.04E09 2.70E05 %2TF38N2_11 Int Flood: Pipe 1499 2SW562013 in 38.North.2 BE floods area 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 3.85E05 XOPCOM236 OPER4160X+OPERSWRHRO 1.00E+00 XPOWEROP1 Fraction of annual year at power 22 1.03E09 1.41E05 %2TF20AC2_5 Int Flood: Pipe 1398 2SW543063 in 20.Air Comp.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.10E03 XOP480X OPER480X

BSEP 17-0111 Enclosure Attachment 11 Page 37 of 77 Table A113: Unit 2 Top 25 Delta CDF Cutsets for Internal Flooding Cutset Cutset Basic Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 XPOWEROP1 Fraction of annual year at power 23 1.03E09 1.41E05 %2TF20AC2_5 Int Flood: Pipe 1398 2SW543063 in 20.Air Comp.2 BE floods area 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.10E03 XOP480X OPER480X 1.00E+00 XPOWEROP1 Fraction of annual year at power 24 9.99E10 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 0.00239 ACP0BKROOE2E4 CIRCUIT BREAKER FROM E2 TO E4 (AH9) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERFPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 4.10E03 XOPFPS1 OPERFPS1 1.00E+00 XPOWEROP1 Fraction of annual year at power 25 9.99E10 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 2.39E03 ACP0BKROOE4E2 CIRCUIT BREAKER FROM E4 TO E2 (AL5) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERFPS1 FAILURE TO ALIGN FIREWATER FOR COOLANT INJECTION FLOW (ONE UNIT) 4.10E03 XOPFPS1 OPERFPS1 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 38 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 4.55E12 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 2 2.94E12 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION

BSEP 17-0111 Enclosure Attachment 11 Page 39 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 3 2.3E12 5.16E05 %2TF_0CB2_37 Int Flood: Pipe 1148 2CW175241 in 0.Cond Bay.2 BE floods area 0.005 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 4 2.3E12 5.16E05 %2TF_0CB2_38 Int Flood: Pipe 1149 2CW174242 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 40 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 5 2.30E12 5.16E05 %2TF_0CB2_39 Int Flood: Pipe 1208 2CW17624 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 6 2.3E12 5.16E05 %2TF_0CB2_40 Int Flood: Pipe 1211 2CW17724 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 7 2.06E12 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED

BSEP 17-0111 Enclosure Attachment 11 Page 41 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 4.80E01 RXN2INJRX3SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (CLASS IBE) 0.00019 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 8 1.74E12 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.80E02 EDG2DGNTMD003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 9 1.73E12 3.88E05 %2TF_0CB2_16 Int Flood: Pipe 1350 2SW54815 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN

BSEP 17-0111 Enclosure Attachment 11 Page 42 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 10 1.49E12 5.16E05 %2TF_0CB2_37 Int Flood: Pipe 1148 2CW175241 in 0.Cond Bay.2 BE floods area 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 0.047 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 11 1.49E12 5.16E05 %2TF_0CB2_38 Int Flood: Pipe 1149 2CW174242 in 0.Cond Bay.2 BE floods area

BSEP 17-0111 Enclosure Attachment 11 Page 43 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 12 1.49E12 5.16E05 %2TF_0CB2_39 Int Flood: Pipe 1208 2CW17624 in 0.Cond Bay.2 BE floods area 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 0.047 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START

BSEP 17-0111 Enclosure Attachment 11 Page 44 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 13 1.49E12 5.16E05 %2TF_0CB2_40 Int Flood: Pipe 1211 2CW17724 in 0.Cond Bay.2 BE floods area 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 14 1.21E12 2.70E05 %2TF38N2_11 Int Flood: Pipe 1499 2SW562013 in 38.North.2 BE floods area

BSEP 17-0111 Enclosure Attachment 11 Page 45 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 0.005 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 15 1.16E12 2.60E05 %2TF_0CB2_15 Int Flood: Pipe 1308 2SW53866 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 16 1.15E12 2.58E05 %2TF_0CB2_10 Int Flood: Pipe 1216 2CW990S1 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT

BSEP 17-0111 Enclosure Attachment 11 Page 46 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 0.00019 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 17 1.15E12 2.58E05 %2TF_0CB2_11 Int Flood: Pipe 1847 2CW1384S1 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 18 1.15E12 2.58E05 %2TF_0CB2_12 Int Flood: Pipe 1848 2CW1484S1 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 19 1.15E12 2.58E05 %2TF_0CB2_13 Int Flood: Pipe 1851 2CW1584S1 in 0.Cond Bay.2 BE floods area

BSEP 17-0111 Enclosure Attachment 11 Page 47 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.90E04 XOP4160X OPER4160X 1 XPOWEROP1 Fraction of annual year at power 20 1.15E12 2.58E05 %2TF_0CB2_14 Int Flood: Pipe 1852 2CW1684S1 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 21 1.15E12 2.58E05 %2TF_0CB2_7 Int Flood: Pipe 1152 2CW1190S1 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS

BSEP 17-0111 Enclosure Attachment 11 Page 48 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 22 1.15E12 2.58E05 %2TF_0CB2_8 Int Flood: Pipe 1153 2CW1290S1 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 23 1.15E12 2.58E05 %2TF_0CB2_9 Int Flood: Pipe 1215 2CW1090S1 in 0.Cond Bay.2 BE floods area 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 0.047 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 24 1.13E12 1.02E04 %2TF20AC2_18 Int Flood: Pipe 1347 2SW54812 in 20.Air Comp.2 BE floods area

BSEP 17-0111 Enclosure Attachment 11 Page 49 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 0.01 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.80E02 EDG2DGNTMD003 DIESEL GENERATOR 3 UNAVAILABLE DUE TO MAINTENANCE (AT POWER) 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power 25 1.12E12 3.88E05 %2TF_0CB2_16 Int Flood: Pipe 1350 2SW54815 in 0.Cond Bay.2 BE floods area 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 4.70E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START

BSEP 17-0111 Enclosure Attachment 11 Page 50 of 77 Table A114: Unit 2 Top 25 Delta LERF Cutsets for Internal Flooding Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING 1.00E+00 OPERRCICEXT TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.90E04 XOP4160X OPER4160X 1.00E+00 XPOWEROP1 Fraction of annual year at power

BSEP 17-0111 Enclosure Attachment 11 Page 51 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 4.56E08 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 2 3.97E08 1.24E04 %FC402_2602_BHEAF2 Fire Source: 22D SWGR Bus 2D 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 3 3.97E08 1.32E05 %FC230_4769_B751 Fire Source: 1XU7 NODE H58: DG1 ESS LOGIC CAB 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 FLSBO STATION BLACKOUT FLAG

BSEP 17-0111 Enclosure Attachment 11 Page 52 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 3.00E03 TRANLOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 1.00E+00 FAILED_HRA HRA FAILED BY FIRE DUE TO TIMING OR ACCESS 1 FL_HRA 1.00E+00 XOPRCICEXT_F 4 2.02E08 1.32E05 %FC230_4769_B751 Fire Source: 1XU7 NODE H58: DG1 ESS LOGIC CAB 2.55E03 ACP0BKRCC2AC4 UAT #2 TO 2C (2AC4) CIRCUIT BREAKER FAILS TO OPEN ACP0BKROC 6.00E01 DGE1_A1 DG OUTPUT BREAKER E1AE9 SPURIOUSLY CLOSES DUE TO FIRE due to fire 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 FLNSBO NO STATION BLACKOUT FLAG 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 FAILED_HRA HRA FAILED BY FIRE DUE TO TIMING OR ACCESS 1.00E+00 FL_HRA 1.00E+00 XOPGENDISC_F Fire Recovery for OPERGENDISC 5 2.02E08 0.0000132 %FC230_4769_B751 Fire Source: 1XU7 NODE H58: DG1 ESS LOGIC CAB ACP0BKROC 6.00E01 DGE1_A1 DG OUTPUT BREAKER E1AE9 SPURIOUSLY CLOSES DUE TO FIRE due to fire 2.55E03 ACP0BKROO2AC6 CIRCUIT BREAKER FROM SAT #2 TO 2C (2AC6) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 FLNSBO NO STATION BLACKOUT FLAG 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED

BSEP 17-0111 Enclosure Attachment 11 Page 53 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FAILED_HRA HRA FAILED BY FIRE DUE TO TIMING OR ACCESS 1.00E+00 FL_HRA 1.00E+00 XOPGENDISC_F Fire Recovery for OPERGENDISC 6 1.89E08 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 7 1.65E08 1.24E04 %FC402_2602_BHEAF2 Fire Source: 22D SWGR Bus 2D 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F

BSEP 17-0111 Enclosure Attachment 11 Page 54 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 8 1.52E08 4.75E05 %FC402_2598_B982 Fire Source: 22D SWGR Bus 2D 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 9 1.32E08 4.41E06 %FC230_4769_B981 Fire Source: 1XU7 NODE H58: DG1 ESS LOGIC CAB 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 3.00E03 TRANLOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 1.00E+00 FAILED_HRA HRA FAILED BY FIRE DUE TO TIMING OR ACCESS 1.00E+00 FL_HRA 1.00E+00 XOPRCICEXT_F 10 1.23E08 6.54E04 %FC423_9018_B752 Fire Source: 2SATSTARTAUXXFMR UNIT 2 START UP AUX XFMR 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard

BSEP 17-0111 Enclosure Attachment 11 Page 55 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 11 1.23E08 6.54E04 %FC423_9028_B752 Fire Source: 2CASBCHXFMR2 CASWELL BEACH XFMR NO. 2 230KV 24KV 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 12 6.75E09 4.41E06 %FC230_4769_B981 Fire Source: 1XU7 NODE H58: DG1 ESS LOGIC CAB 2.55E03 ACP0BKRCC2AC4 UAT #2 TO 2C (2AC4) CIRCUIT BREAKER FAILS TO OPEN ACP0BKROC 6.00E01 DGE1_A1 DG OUTPUT BREAKER E1AE9 SPURIOUSLY CLOSES DUE TO FIRE due to fire 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev

BSEP 17-0111 Enclosure Attachment 11 Page 56 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FLNSBO NO STATION BLACKOUT FLAG 1.00E+00 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 FAILED_HRA HRA FAILED BY FIRE DUE TO TIMING OR ACCESS 1.00E+00 FL_HRA 1.00E+00 XOPGENDISC_F Fire Recovery for OPERGENDISC 13 6.75E09 4.41E06 %FC230_4769_B981 Fire Source: 1XU7 NODE H58: DG1 ESS LOGIC CAB ACP0BKROC 6.00E01 DGE1_A1 DG OUTPUT BREAKER E1AE9 SPURIOUSLY CLOSES DUE TO FIRE due to fire 2.55E03 ACP0BKROO2AC6 CIRCUIT BREAKER FROM SAT #2 TO 2C (2AC6) FAILS TO CLOSE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 FLNSBO NO STATION BLACKOUT FLAG 1 OPERGENDISC FAILURE TO LOCALLY ALIGN ELECTRICAL BUSSES FOR BACKFEED 1.00E+00 FAILED_HRA HRA FAILED BY FIRE DUE TO TIMING OR ACCESS 1.00E+00 FL_HRA 1.00E+00 XOPGENDISC_F Fire Recovery for OPERGENDISC 14 6.32E09 4.75E05 %FC402_2598_B982 Fire Source: 22D SWGR Bus 2D 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION

BSEP 17-0111 Enclosure Attachment 11 Page 57 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 FL_HRA 1.33E03 XOPCOM236_F 15 5.93E09 3.14E04 %FC423_9018_B751 Fire Source: 2SATSTARTAUXXFMR UNIT 2 START UP AUX XFMR 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 16 5.93E09 3.14E04 %FC423_9028_B751 Fire Source: 2CASBCHXFMR2 CASWELL BEACH XFMR NO. 2 230KV 24KV 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA

BSEP 17-0111 Enclosure Attachment 11 Page 58 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 0.0032 XOP4160X_F Fire Recovery for OPER4160X 17 5.13E09 6.54E04 %FC423_9018_B752 Fire Source: 2SATSTARTAUXXFMR UNIT 2 START UP AUX XFMR 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 18 5.13E09 6.54E04 %FC423_9028_B752 Fire Source: 2CASBCHXFMR2 CASWELL BEACH XFMR NO. 2 230KV 24KV 0.059 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F

BSEP 17-0111 Enclosure Attachment 11 Page 59 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 19 4.11E09 2.18E04 %FC423_9018_B982 Fire Source: 2SATSTARTAUXXFMR UNIT 2 START UP AUX XFMR 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 20 4.11E09 2.18E04 %FC423_9028_B982 Fire Source: 2CASBCHXFMR2 CASWELL BEACH XFMR NO. 2 230KV 24KV 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X

BSEP 17-0111 Enclosure Attachment 11 Page 60 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 21 3.59E09 1.90E04 %FC404_8905_BFM2 Fire Source: 2ISOPHGRID1 Isophase Bus Duct from Unit 2 Main Generator 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC404 Fire in 805_LOC: TB201K U2 TB North 38ft and 45ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 22 3.47E09 1.84E04 %FC423_9017_BOS2 Fire Source: 2SATSTARTAUXXFMR UNIT 2 START UP AUX XFMR 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 23 3.47E09 1.84E04 %FC423_9027_BOS2 Fire Source: 2CASBCHXFMR2 CASWELL BEACH XFMR NO. 2 230KV 24KV 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START

BSEP 17-0111 Enclosure Attachment 11 Page 61 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E01 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 0.0032 XOP4160X_F Fire Recovery for OPER4160X 24 3.2E09 1.07E06 %FC230_4769_B752 Fire Source: 1XU7 NODE H58: DG1 ESS LOGIC CAB 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 3.00E03 TRANLOOP CONDITIONAL PROBABILITY OF A LOOP GIVEN A PLANT TRIP (OTHER THAN A LOCA) 1.00E+00 FAILED_HRA HRA FAILED BY FIRE DUE TO TIMING OR ACCESS 1.00E+00 FL_HRA 1.00E+00 XOPRCICEXT_F 25 2.92E09 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 0.008 ACP0XHEMNE1E3 Failure to properly restore breaker following maintenance 8.00E03 ACP0XHEMNE2E4 Failure to properly restore breaker following maintenance 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS

BSEP 17-0111 Enclosure Attachment 11 Page 62 of 77 Table A115: Unit 2 Top 25 Delta CDF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E01 XOPSWRHRC_F

BSEP 17-0111 Enclosure Attachment 11 Page 63 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1 2.28E09 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 2 1.99E09 1.24E04 %FC402_2602_BHEAF2 Fire Source: 22D SWGR Bus 2D 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 3 1.47E09 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE)

BSEP 17-0111 Enclosure Attachment 11 Page 64 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 0.5 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 4 1.28E09 1.24E04 %FC402_2602_BHEAF2 Fire Source: 22D SWGR Bus 2D 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 0.01 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft

BSEP 17-0111 Enclosure Attachment 11 Page 65 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 5 1.24E09 7.61E07 %FC230_4819_B750 Fire Source: 2I2AHZ3 NODE HZ3: CTRL BLDG 125VDC DISTRIBUTION PANEL 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 1.63E03 XOPCOM213_F Fire Recovery for OPERDILUTE + OPERINHIBITADS 6 1.03E09 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft

BSEP 17-0111 Enclosure Attachment 11 Page 66 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 0.48 RXN2INJRX3SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (CLASS IBE) 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 7 1.01E09 7.61E07 %FC230_4819_B750 Fire Source: 2I2AHZ3 NODE HZ3: CTRL BLDG 125VDC DISTRIBUTION PANEL 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 8 9.47E10 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT

BSEP 17-0111 Enclosure Attachment 11 Page 67 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 9 8.96E10 1.24E04 %FC402_2602_BHEAF2 Fire Source: 22D SWGR Bus 2D 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 4.80E01 RXN2INJRX3SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (CLASS IBE) 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 10 8.25E10 1.24E04 %FC402_2602_BHEAF2 Fire Source: 22D SWGR Bus 2D 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START

BSEP 17-0111 Enclosure Attachment 11 Page 68 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 11 7.6E10 4.75E05 %FC402_2598_B982 Fire Source: 22D SWGR Bus 2D 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 12 6.17E10 6.54E04 %FC423_9018_B752 Fire Source: 2SATSTARTAUXXFMR UNIT 2 START UP AUX XFMR 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard

BSEP 17-0111 Enclosure Attachment 11 Page 69 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 13 6.17E10 6.54E04 %FC423_9028_B752 Fire Source: 2CASBCHXFMR2 CASWELL BEACH XFMR NO. 2 230KV 24KV 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 14 6.12E10 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY

BSEP 17-0111 Enclosure Attachment 11 Page 70 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 15 5.33E10 1.24E04 %FC402_2602_BHEAF2 Fire Source: 22D SWGR Bus 2D 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS

BSEP 17-0111 Enclosure Attachment 11 Page 71 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 16 4.91E10 4.75E05 %FC402_2598_B982 Fire Source: 22D SWGR Bus 2D 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 0.5 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 17 4.28E10 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 0.99 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY

BSEP 17-0111 Enclosure Attachment 11 Page 72 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 4.80E01 RXN2INJRX3SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (CLASS IBE) 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 18 4.13E10 2.54E07 %FC230_4819_B980 Fire Source: 2I2AHZ3 NODE HZ3: CTRL BLDG 125VDC DISTRIBUTION PANEL 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 1.00E+00 FL_HRA 1.63E03 XOPCOM213_F Fire Recovery for OPERDILUTE + OPERINHIBITADS 19 3.99E10 6.54E04 %FC423_9018_B752 Fire Source: 2SATSTARTAUXXFMR UNIT 2 START UP AUX XFMR 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE)

BSEP 17-0111 Enclosure Attachment 11 Page 73 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 20 3.99E10 6.54E04 %FC423_9028_B752 Fire Source: 2CASBCHXFMR2 CASWELL BEACH XFMR NO. 2 230KV 24KV 6.80E01 ACP2XHEMNOFFER OFFSITE AC POWER NOT RECOVERED DURING RX TIME FRAME (IBE) 1 ACP2XHEMNONSER ONSITE EMERG. AC POWER NOT RECOV. DURING RX TIME FRAME (IBE) 1.00E+00 CAC2AOVFNNOACP NO AC POWER AVAILABLE TO OPEN COMBUSTIBLE GAS VENT VALVES 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 5.90E02 EDG2DGNFR003 DIESEL GENERATOR 3 FAILS TO RUN

BSEP 17-0111 Enclosure Attachment 11 Page 74 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC423 Fire in 805_LOC: TY Transformer Yard 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 21 3.73E10 1.24E04 %FC402_2602_BHEAF2 Fire Source: 22D SWGR Bus 2D 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 5.00E01 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 4.80E01 RXN2INJRX3SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (CLASS IBE)

BSEP 17-0111 Enclosure Attachment 11 Page 75 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F 22 3.67E10 0.000142 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLBATDEPL2A BATTERY BANK 2A DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER 1.00E+00 FLBATDEPL2B BATTERY BANK 2B DEPLETION FOLLOWING LOSS OF POWER FROM CHARGER 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERDCDG FAILURE TO ALIGN PORTABLE DC GENERATOR TO BATTERY CHARGERS 1.00E+00 OPERLDSHD FAILURE TO COMPLETE DC LOAD SHED 1.00E+00 FAILED_HRA HRA FAILED BY FIRE DUE TO TIMING OR ACCESS 1.00E+00 FL_HRA 5.15E04 XOPCOM221_F 1.00E+00 XOPLDSHD_F Fire Reovery for OPERLDSHD 23 3.49E10 1.42E04 %FC402_2598_B752 Fire Source: 22D SWGR Bus 2D 5.00E03 CN2PREEXIST PREEXISTING CONTAINMENT FAILURE 1 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERDEPRESS FAILURE TO MANUALLY INITIATE AND ALIGN LOWPRESSURE SYSTEMS

BSEP 17-0111 Enclosure Attachment 11 Page 76 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 FL_HRA 4.90E04 XOPCOM225_F 24 3.43E10 4.75E05 %FC402_2598_B982 Fire Source: 22D SWGR Bus 2D 9.90E01 CAC2PHESCINERT CONTAINMENT INERTED; VENTING NOT REQUIRED 1.00E+00 CZN2PHENOHYDDF HYDROGEN DEFLAGRATION OCCURS GLOBALLY 0.5 CZN2PHENOICONT CONTAINMENT NOT STEAM INERTED 1.00E02 CZN2PHENOO2IN OPERATION DEINERTED OR O2 INTRODUCED 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FL_FC402 Fire in 805_LOC: TB201C/D/E/F/G/H U2 TB Equipment Areas: 20ft 1.00E+00 FLSBO STATION BLACKOUT FLAG 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT 1.00E+00 OPERRCICEXT FAILURE TO EXTEND RCIC OPERATION BY MANAGING HCTL AND DEFEATING TRIPS 1.00E+00 OPERSWRHRC FAILURE TO LOCALLY CLOSE SW VALVES FOR FW INJECTION 9.50E01 OPN2DEPOP7SUC SUCCESSFUL RPV DEPRESSURIZATION (CLASS IBE) 4.80E01 RXN2INJRX3SUC SUCCESSFUL ARREST OF CORE MELT INVESSEL (CLASS IBE) 1.00E+00 FL_HRA 3.20E03 XOP4160X_F Fire Recovery for OPER4160X 25 3.37E10 2.54E07 %FC230_4819_B980 Fire Source: 2I2AHZ3 NODE HZ3: CTRL BLDG 125VDC DISTRIBUTION PANEL 1.00E+00 EDG2DGNFS004 DIESEL GENERATOR 4 FAILS TO START 1.00E+00 FIRELOOP FIRE INDUCED LOSS OF OFFSITE POWER AS INITIAL FAULT FLAG 1.00E+00 FL_FC230 Fire in 805_LOC: CB23 Control Rm 49' Elev 1.00E+00 OPER4160X FAILURE TO ALIGN POWER FROM OPPOSITE UNIT

BSEP 17-0111 Enclosure Attachment 11 Page 77 of 77 Table A116: Unit 2 Top 25 Delta LERF Cutsets for Fire Basic Cutset Cutset Event Basic Event Name Basic Event Description Number Probability Probability 1.00E+00 OPER480X FAILURE TO CONNECT UNIT 1 SUBSTATIONS E5 AND E6 1.00E+00 OPERSWRHRO FAILURE TO LOCALLY OPEN THE DISCHARGE VALVES FOR RHR INJECTION 1.00E+00 FL_HRA 1.33E03 XOPCOM236_F

BSEP 17-0111, Request for Risk-Informed Exigent License Amendment - Technical Specification 3.8.1, AC Sources Operating, One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements

Contents

Text

Subject:

References:

Enclosure:

Subject:

SUMMARY

SUMMARY

3.0 TECHNICAL EVALUATION

5.0 CONCLUSION

6.0 REFERENCES

3.0 TECHNICAL EVALUATION

5.0 CONCLUSION

6.0 REFERENCES

References:

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BSEP 17-0111, Request for Risk-Informed Exigent License Amendment - Technical Specification 3.8.1, AC Sources Operating, One-Time Extension of Emergency Diesel Generator Completion Times and Suspension of Surveillance Requirements

Text

Subject:

References:

Enclosure:

Subject:

SUMMARY

SUMMARY

3.0 TECHNICAL EVALUATION

5.0 CONCLUSION

6.0 REFERENCES

3.0 TECHNICAL EVALUATION

5.0 CONCLUSION

6.0 REFERENCES

References:

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