RA-19-0004, Response to NRC for Additional Information (RAI) Regarding License Amendment Request Proposing Changes to the Technical Specifications 3.8.1 for Catawba Nuclear Station, Units 1 and 2

Response to NRC for Additional Information (RAI) Regarding License Amendment Request Proposing Changes to the Technical Specifications 3.8.1 for Catawba Nuclear Station, Units 1 and 2

ML19066A354
Person / Time
Site:	Mcguire, Catawba, McGuire
Issue date:	03/07/2019
From:	Snider S Duke Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RA-19-0004
Download: ML19066A354 (155)

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U.S. Nuclear Regulatory Commission RA-19-0004

6. Duke Energy letter, Response to NRC Request for Additional Information (RAI)

Regarding License Amendment Request Proposing Changes to the Technical Specifications 3.8.1 For McGuire Nuclear Station, dated December 3, 2018 (ADAMS Accession No. ML18337A277).

Ladies and Gentlemen:

In Reference 1, as supplemented by References 2, 3, and 4, Duke Energy Carolinas, LLC (Duke Energy) submitted a License Amendment Request (LAR) for Catawba Nuclear Station (CNS), Units 1 and 2. The proposed change would extend the Completion Time for an inoperable diesel generator in Technical Specification (TS) 3.8.1, AC Sources - Operating at the station. The proposed change would also alter the AC power source operability requirements for the Nuclear Service Water System (NSWS), Control Room Area Ventilation System (CRAVS), Control Room Area Chilled Water System (CRACWS) and Auxiliary Building Filtered Ventilation Exhaust System (ABFVES) (i.e., shared systems).

By correspondence dated January 9, 2019 (Reference 5), the Nuclear Regulatory Commission (NRC) staff requested additional information from Duke Energy that is needed to complete the LAR review. provides Duke Energys response to the NRC RAI. Attachment 2 contains proposed markups of CNS TS 3.8.1, which supersede all previous submittals. Attachment 3 contains proposed markups of CNS TS 3.8.1 Bases, which supersede all previous submittals. provides the comprehensive list of regulatory commitments that are associated with the LAR. Attachments 5 and 6 contain proposed markups of the CNS Renewed Facility Operating License (FOL) for Units 1 and 2, respectively. Commitment numbers 4 and 10 have been added to the CNS FOL markups as proposed license conditions. The proposed CNS TS 3.7.8 Bases provided in the October 8, 2018 letter (Reference 4) are still valid. The proposed CNS TS Bases 3.8.2, 3.7.10, 3.7.11, and 3.7.12 provided in the May 2, 2017 letter (Reference

1) are also still valid. provides a supplement to the McGuire Nuclear Station (MNS), Units 1 and 2 letter in reference 6. The Attachment 7 supplement provides proposed markups of the MNS Renewed Facility Operating License (FOL) for both units, a comprehensive list of MNS regulatory commitments that are associated with the LAR, and additional information regarding PRA model changes and ESPS diesel generator (DG) failure rates. Commitment Numbers 4 and 10 have been added to the MNS FOL markups as proposed license conditions. Attachment 8 contains proposed markups of the MNS TS 3.8.1 Bases, which supersedes all previous submittals.

The conclusions of the original No Significant Hazards Consideration and Environmental Consideration in the original LAR are unaffected by this RAI response.

In accordance with 10 CFR 50.91, Duke Energy is notifying the states of North Carolina and South Carolina of this LAR by transmitting a copy of this letter and attachments to the designated state official. Should you have any questions concerning this letter, or require additional information, please contact Art Zaremba, Manager - Nuclear Fleet Licensing, at 980-373-2062.

U.S. Nuclear Regulatory Commission RA-19-0004 I ~la re under penalty of J)erjury that the foreg oing is true and correct. Executed on o..rc.h, "?, cl_61C\, .

Sincerely, Steve Snider Vice President, Nuclear Engineering NDE Attachments:

1. Response to NRC Request for Additional Inform ation

2. Revised Catawba Technical Specification 3.8.1 Marked Up Pages

3. Revised Catawba Technical Specification Base s 3.8.1 Marked Up Pages

4. Catawba Regulatory Commitments

5. Markup of Proposed Renewed Facility Operating License - CNS Unit 1

6. Markup of Proposed Renewed Facility Operating License - CNS Unit 2

7. McGuire Nuclear Station Supplemental Information

8. Revised McGuire Technical Specification Base s 3.8.1 Marked Up Pages

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U.S. Nuclear Regulatory Commission RA-19-0004 Page 1 Attachment 1 Response to NRC Request for Additional Information

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 2 NRC Request for Additional Information:

By letter dated May 2, 2017 (Agencywide Documents Access management System (ADAMS)

Accession No. ML17122A116), as supplemented by letters dated July 20, 2017 (ADAMS Accession No. ML17201Q132), November 21, 2017 (ADAMS ML17325A588), and October 8, 2018 (ADAMS Accession No. ML18281A010), Duke Energy Carolinas, LLC (Duke Energy, the licensee), requested an amendment to Renewed License Nos. NPF-35 and NPF-52 for Catawba Nuclear Station (Catawba), Units 1 and 2. The proposed amendment would revise the Catawba Technical Specifications (TS) 3.8.1, AC [Alternating Current] Sources - Operating, to allow the extension of the Completion Time (CT) for an inoperable diesel generator (DG) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days, and to ensure that at least one train of shared components has an operable emergency power supply. The proposed changes to TS 3.8.1 in the October 8, 2018 letter superseded the proposed TS 3.8.1 changes in all other letters.

The proposed TS changes in the October 8, 2018 letter would revise Catawba TS 3.8.1 by adding 1) new LCOs for the opposite unit AC power sources to supply power for the required shared systems; 2) new Required Actions (RAs) and CTs associated with Condition B (inoperable DG); and 3) new Conditions and associated RAs and CTs to address new the LCOs for shared systems. To support the 14-day extended CT request, Catawba will add a supplemental AC power source (i.e., two supplemental diesel generators (SDGs) per station) with the capability to power any emergency bus. The SDGs will have the capacity to bring the affected unit to cold shutdown. The supplemental AC power source will be referred to as the Emergency Supplemental Power Source (ESPS).

The LAR for Catawba, Units 1 and 2, dated May 2, 2017, states that the proposed change to the TS completion time (CT) has been developed using the risk-informed processes described in Regulatory Guide (RG) 1.174, Revision 2, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" ADAMS Accession No. ML100910006), and RG 1.177, Revision 1, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications (ADAMS Accession No. ML100910008). Based on Section 2.3.1 of RG 1.177, the technical adequacy of the probabilistic risk assessment (PRA) must be compatible with the safety implications of the TS change being requested and the role that the PRA plays in justifying that change. The RG 1.177 endorses the guidance provided in RG 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of PRA Results for Risk-Informed Activities (ADAMS Accession No. ML090410014),

on PRA technical adequacy. The RG 1.200 describes a peer review process utilizing American Society of Mechanical Engineers/American Nuclear Society (ASME/ANS) PRA standard RA-Sa-2009, "Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, Addendum A to RA-S-2008," as one acceptable approach for determining the technical adequacy of the PRA once acceptable consensus approaches or models have been established for evaluations that could influence the regulatory decision.

The NRC staff conducted an audit at Duke Energy offices in Charlotte, North Carolina from May 8 - 10, 2018 (ADAMS Accession No. ML18249A046). The Duke Energy staff was provided a set of audit questions that were discussed during the audit. NRC staff provided a verbal brief to Duke Energy at the end of the audit about what changes it intended to make to audit questions to develop requests for additional information (RAIs). Subsequent to the audit, Duke Energy submitted an LAR supplement, the October 8, 2018, addressing a majority of the Catawba, Units 1 and 2, audit questions. The NRC staff reviewed the material provided in the October 8, 2018 letter and determine that the supplemental information did not address all of the concerns raised during the audit.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 3 Regulatory Requirements The NRCs regulatory requirements related to the content of the TS are contained in Title 10 of the Code of Federal Regulations (10 CFR) at 10 CFR 50.36. For Limiting Conditions of Operation at 10 CFR 50.36(c)(2)(i), Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met, (emphasis added).

Applicable regulatory guidance for Catawba, Units 1 and 2, is contained in: 1. Standard Technical Specifications for Westinghouse Plants, NUREG-1431, Revision 4 (STS, ADAMS Accession Number ML12100A222), and 2. Final Policy Statement (FPS) on Technical Specifications Improvements for Nuclear Power Reactors (FPS, 58 FR 39132).

10 CFR, Appendix A of Part 50, General Design Criterion (GDC) 17, Electric Power Systems, requires, in part, that an onsite electric power system and an offsite electric power system be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. The onsite electric power supplies shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.

The NRC staff also considered the following guidance document to evaluate the LAR:

Branch Technical Position (BTP) 8-8, "Onsite (Emergency Diesel Generators) and Offsite Power Sources Allowed Outage Time Extensions," was developed to provide guidance to the NRC staff for reviewing license amendment requests for Allowed Outage Time (AOT) or CT extensions for the onsite and offsite power AC sources to perform online maintenance of the power sources. In the May 2, 2017 letter, the licensee stated that the LAR provides a deterministic technical justification for extending the CTs and has been developed using the guidelines established in NUREG-0800, Branch Technical Position (BTP) 8-8.

Regulatory Guide (RG) 1.93, Availability of Electric Power Sources, Revision 1, which provides guidelines that the NRC staff considers acceptable when the number of available electric power sources are less than the number of sources required by the limiting conditions for operation (LCOs) for a facility.

In order to complete its review, the NRC staff requests the following additional information.

Please provide your response to the following requests for additional information (RAIs) within 30 days of the date of this correspondence.

RAI Safe Shutdown Facility Credit for High Winds Section 4.2 of RG 1.200 states that the LAR should include, [a] discussion of the resolution of the peer review findings and observations that are applicable to the parts of the PRA required for the application. This [discussion] should take the following forms:

• A discussion of how the PRA model has been changed

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 4

• A justification in the form of a sensitivity study that demonstrates the accident sequences or contributors significant to the application decision were not adversely impacted (remained the same) by the particular issue. , PRA Peer Review Findings and Resolutions, of the LAR provides PRA peer review facts and observations (F&Os) and dispositions for the Catawba PRAs.

Catawba F&O WPR-C3-01 addresses questions about eight model assumptions used in the high winds PRA. The disposition in the LAR for this F&O stated that four assumptions were removed from the analysis and the other four were revised and enhanced. During the May 2018 audit, given that modeling assumptions can have a significant impact on core damage frequency (CDF) and large early release frequency (LERF) results, the staff requested further information about how the assumptions were revised and justification that the revisions resolved the F&O.

The October 8, 2018 supplement, in response to audit Question 01.b, describes how the four remaining assumptions were revised to address the F&O. Regarding Assumption 1 in Appendix A Section B.1 (Revision 0) concerning Standby Shutdown Facility (SSF) accessibility following high wind events, the October 8, 2018 supplement states that the assumption in Revision 0 (i.e., straight line or tornado wind conditions will not prevent access to the SSF after one hour) was enhanced to explain that the duration of the high wind events is expected to be less than one hour, that multiple travel pathways are available for the operators to take to the SSF, and debris from F1 wind events are not expected to block access to the SSF. In contrast, the response to audit Question 14.d states, [m]inimal credit is given in the high winds case for the SSF due to operator action feasibility. Based on these statements, it is unclear to the NRC staff how SSF is credited, including SSF accessibility, in the high winds PRA model used for this application and the basis for the assumed credit. Also, it is unclear whether the treatment of SSF accessibility in the high winds PRA could potentially challenge the risk acceptance guidelines (i.e., key source of uncertainty and assumption in accordance with NUREG-1855, Revision 1).

Considering the observations above, the NRC staff requests the following additional information:

a) Provide clarification of the assumptions and associated bases for the accessibility to and credit for the SSF for all high winds events (i.e., F1 and higher high winds initiated events for straight winds, hurricanes, and tornados).

b) The treatment of SSF accessibility during high wind events is a source of model uncertainty. Provide qualitative or quantitative justification for why this source of model uncertainty does not change the conclusions of the LAR (e.g., provide description and results of an aggregate sensitivity study in accordance with NUREG-1855, Revision 1; or identify compensatory measures that will be implemented to reduce the risk and provide an assessment of the risk impact of these measures).

Duke Energy RAI-1 Response a) The credit for the SSF is extended to F1 and F2 straight-line wind and tornado high wind-initiated events only if an EDG run failure occurs after one hour of successful EDG operation. No credit is taken for the SSF in hurricane events. No credit is taken for the SSF in straight line wind or tornado events higher than F2. Because the SSF is credited

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 5 only in sequences with an initial success of an EDG, all of the SSF PRA functionality is credited, including prevention of a reactor coolant pump seal LOCA (RCPSL). The bases for this assumption is that high wind events are expected to be less than one hour, multiple travel pathways are available for the operators to take to get to the SSF, and debris from F1 and F2 wind events are not expected to block access to the SSF.

Thus, SSF accessibility in F1 and F2 windspeeds is not a significant source of uncertainty.

b) An additional sensitivity study was not performed and the current treatment of the SSF accessibility does not change the conclusions of the LAR. The SSF is located in an open area, such that there are multiple pathways from the control room to the SSF. The yard is kept free from debris and storm preparations involve tying down equipment.

Additionally, work control monitors the weather forecasts while scheduling maintenance.

As described in Commitment 1 (Attachment 4), extended EDG maintenance will not be scheduled if high wind weather is anticipated. As described in section 7.2.3.3 of NUREG-1855 Rev.1, a conservative bias is used in this analysis for crediting the SSF during a high wind initiating event. A conservative assumption is that credit for the SSF is available only for F1 and F2 high wind-initiated events, straight-line winds and tornadoes, after the first hour of the initiating event. This conservative assumption leads to a higher risk estimate than if a more realistic assumption was adopted.

RAI ESPS High Wind Fragility Determination The LAR states that Emergency Supplemental Power Source (ESPS) is intended to be the backup power supply for the 4160 volt bus whose emergency diesel generator (EDG) is removed from service and that, by design, the ESPS diesel generators (DGs) can also be readily connected to any of the four 4160 volt busses. The cutset and importance results provided in LAR Tables 7-31 through 7-36 show that crediting the ESPS for high wind events is risk important. Because of the risk importance of the ESPS and that the PRA modeling of the ESPS has not undergone an independent peer review, the NRC staff requires additional information about the modeling of the ESPS. Address the following:

a) The LAR states in Section 3.5.1, in relation to the Catawba ESPS system description, [a]ll three weather enclosures (along with separately mounted components) will be designed to meet commercial International Building Code (IBC) and ASCE 7-10 criteria, including rain, snow, seismic and wind loading up to 130 mph gusts. Discuss how ESPS is credited for each of the high wind categories and provide justification for this credit. Specifically justify the credit for high wind category F2-2 considering the design wind loading of 130 mph.

b) Section 6.1.5.4 of the LAR states that, conservative straight line, and tornado specific, wind pressure fragilities were developed for the ESPS. It provides further clarification in that, the wind missile fragility values used for ESPS were those developed in the high winds PRA for the Main / Auxiliary transformers. This was based on the fact that these transformers are relatively large, outdoor, electrical equipment, similar to the ESPS system. Provide a more detailed justification that the use of main / auxiliary transformer fragilities is appropriate for the ESPS enclosures. Include in this discussion a description of additional SSCs or features (e.g., concrete walls) that provide additional wind pressure and missile protection to the transformers and the equivalency of these features to those being provided for the ESPS enclosures.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 6 c) The SSF and ESPS wind structure failure rates provided in Tables 7-31 through 7-36 of the LAR appear to demonstrate the ESPS structure is more robust than the SSF structure and are modeled somewhat differently. Table 7-35 of the LAR identifies two different failure probabilities for the ESPS for high wind interval 3-1 (i.e., basic events JESPS_HWP_31, Wind Pressure Failure of ESPS due to High Wind Interval F3-1, with a probability of 2.41E-01, and JESPS_HWT_31, Wind Pressure Failure of ESPS due to Tornado Interval F3-1, with a probability of 6.73E-01). For the SSF structure, however, the wind pressure failure probabilities in Tables 7-31 through 7-36 appear to be the same for straight winds, hurricane, and tornado events for the same high wind category. Provide justification for the different modelling approaches for the ESPS and the SSF. Specifically address the basis for using different failure probabilities for the same ESPS structure and wind category (e.g., JESPS_HWP_31 and JESPS_HWT_31) and the reason the SSF high wind failure rates appear to not make this distinction. Also, discuss the significance of these different modeling approaches.

d) If the response to this RAI results in a change to the high winds PRA model, use the high winds PRA model that incorporates the appropriate and consistent treatment of SSF and ESPS structural failure in the aggregate analysis requested in RAI-13.

Duke Energy RAI-2.a Response The fragility of the ESPS system was assumed to be limited by the failure of the enclosures as their failure would be required before exposing the ESPS equipment to the high winds. The fragility was estimated by using the specified design wind speed and then removing the conservatism due to the safety factors following the guidance of EPRI 3002003107. High-Wind Risk Assessment Guidelines. The fragilities based on the wind intervals are:

Straight Winds - Discretized Failure Probabilities for Ten Wind Speed Intervals for CNS Representative Lower Wind Upper Wind Interval Fragility Error Wind Speed Wind Speed By Speed Speed for Representative Factor Interval Arithmetic Mean (MPH) (MPH) Wind Speed (EF)

(MPH)

F1-1 73 85 79 1.40E-11 1.23 F1-2 85 98 92 2.03E-08 F1-3 98 112 105 5.57E-06 F2-1 112 126 119 3.40E-04 F2-2 126 141 134 6.51E-03 F2-3 141 157 149 5.38E-02 F3-1 157 177 167 2.41E-01 F3-2 177 206 192 6.51E-01 F4 206 260 233 9.74E-01 F5 260 320 290 1.00E+00

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 7 Tornado - Discretized Failure Probabilities for Ten Wind Speed Intervals for CNS Representative Wind Lower Wind Upper Wind Interval Fragility Error Wind Speed By Speed Speed Speed for Representative Factor Arithmetic Mean Interval (MPH) (MPH) Wind Speed (EF)

(MPH)

F1-1 73 85 79 1.17E-06 1.27 F1-2 85 98 92 1.05E-04 F1-3 98 112 105 2.93E-03 F2-1 112 126 119 2.93E-02 F2-2 126 141 134 1.36E-01 F2-3 141 157 149 3.67E-01 F3-1 157 177 167 6.73E-01 F3-2 177 206 192 9.18E-01 F4 206 260 233 9.97E-01 F5 260 320 290 1.00E+00 Therefore, the use of the representative fragilities across the entire high wind hazard curve (including for high wind category F2-2 and greater) for ESPS is acceptable and is in alignment with the high wind PRA used for the evaluation.

This information was provided as part of one of the calculations provided for the onsite audit.

(Reference Appendix L of calculation CNC-1535.00-00-0218.) The failure of the ESPS system also includes the fragility of the Turbine building to account for electrical distribution equipment required for the ESPS system to supply a Safety Bus. Also note that the missile fragility contribution for ESPS is applied separately and not included in the previous two tables.

Duke Energy RAI-2.b Response For Catawba, the ESPS wind missile fragility values are assumed to be the same as those applied for the McGuire Main / Auxiliary Transformers. This is an appropriate approximation since, as stated, the transformers are relatively large, outdoor, electrical equipment like the ESPS system and have one of the largest fragilities of the components included in the high winds PRA. Using these fragility values is more conservative because the McGuire Main /

Auxiliary Transformers group is spatially more-open and is not surrounded by concrete walls.

Additionally, since this treatment is an approximation, it provides the benefit of consistency between sites. No concrete walls are modeled in the near vicinity of the Main / Auxiliary Transformers group that was used as the representative ESPS wind missile fragility values.

Given the proximity to the Turbine Building, the ESPS is expected to see a similar missile field as for the Main / Auxiliary Transformers. Additionally, the ESPS design includes weather enclosures which would potentially afford some protection from the missile field and the ESPS cables will be routed to the Turbine Building via trenches rather than exposed as is the case with the Main / Auxiliary Transformers (considered the primary vulnerability for transformers).

The ESPS high wind pressure fragilities were developed separately and do not rely on the McGuire Main / Auxiliary Transformer fragility values.

The assumption of using the McGuire Main / Auxiliary Transformer missile fragility values is conservative and bounding for the Catawba ESPS.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 8 Duke Energy RAI-2.c Response The ESPS high wind fragilities are based only on the required design limits on the weather enclosure and applied as separate factors. The fragilities of the SSF system are based only on the structure housing the equipment and combined into a single fragility for each of the wind hazard intervals. The fragility of the SSF structure is based on the weighted average of various failure modes identified as part of the evaluation of the existing structure and include separate factors for the frame, roof and wall structural elements as well as the louvers. The results of the minor difference in the application of the fragilities are functionally equivalent. The difference between the HWP and HWT fragilities is that tornado loads include a delta pressure due the hazard in addition to the Bernoulli effect lift and drag pressures due to air flowing around and over the structure.

Duke Energy RAI-2.d Response Because the high winds PRA model has been revised to incorporate the Rev. 4 internal events PRA model, the quantification results have been updated and are incorporated in the response to RAI-13. Since the fragilities in the high wind speeds are approaching unity which results in issues with the min-cut upper bound assumption inherent in the CAFTA cutset solution, the fragilities F3 and above are set to true for the ESPS during quantification.

RAI Modeling Alternative Alignments The LAR for Catawba, dated May 2, 2017, states that the proposed change to the TS CT has been developed using the risk-informed processes described in RG 1.174, Revision 2, and RG 1.177, Revision 1. Based on Section 2.3.1 of RG 1.177, the technical adequacy of the PRA must be compatible with the safety implications of the TS change being requested and the role that the PRA plays in justifying that change. RG 1.177 endorses the guidance provided in RG 1.200, Revision 2, on PRA technical adequacy. The RG 1.200 describes a peer review process utilizing ASME/ANS PRA standard RA-Sa-2009 as one acceptable approach for determining the technical adequacy of the PRA once acceptable consensus approaches or models have been established for evaluations that could influence the regulatory decision. The PRA standard Supporting Requirement (SR) SY-A5 requires that both the normal and alternate alignments be modelled to the extent needed for core damage frequency (CDF) and large early release frequency (LERF) determination.

Based on the review of the LAR, as supplemented, the following provides NRC staffs observations on modeling alternate alignments and asymmetries for this application:

y Section 6.1.4.2 of the LAR states that the Catawba internal events model consists of separate models for each unit and accounts for multiple trains, whereas the internal flooding, high winds, and fire models are single unit that generally assumes Train-A operating.

y NRC staff notes, based on the incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP) risk results reported in LAR Attachment 6, that even small changes in the PRA modeling need to reflect either asymmetries or the most limiting alignment that could potentially impact the conclusions of the LAR. It is not clear to NRC staff that the most limiting configurations (i.e., alignments) are always modeled in the PRAs from the point of calculating ICCDP and ICLERP. Because the LAR indicates that the

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 9 ICCDP and ICLERP for the proposed TS change meet the risk acceptance guidelines in RG 1.177 by a small margin, uncertainty in modeling assumptions could impact the conclusions of the application.

y Tables 6-3, 6-4, 6-26 through 6-33, and 6-38 through 6-45 of the LAR show that for each unit the same base case CDF and LERF values were used for both plant operating alignments (i.e., ESPS aligned to Train A bus, ESPS aligned to Train B bus) for internal events; whereas, the CDF and LERF values for the CT case (as well as for the non-CT case) are different between plant operating alignments. The 15&VWDIIQRWHVWKDWWKH,&&'3,&/(53&')DQG/(5)FDOFXODWLRQVVKRXOG use the same alignment for all the calculated cases (i.e., base, CT, and non-CT).

y During the May 2018 audit, the NRC staff identified concerns about not including alternate alignments in the internal flood, high winds, and fire PRA models. NRC staff notes that the internal events results provided in Tables 6-26 through 6-33, and 6-38 through 6-45 of the LAR indicate differences of up to 23 percent for different train alignments. Given that the internal events PRA model provides the underlying basis for the internal flood, high winds, and fire models, issues associated with modelling asymmetries in these PRAs could significantly impact the application.

To address the observations above, the NRC staff requests the following additional information:

a) Provide updated risNUHVXOWV LH,&&'3,&/(53&')DQG/(5)IRULQWHUQDO events, internal flooding, high winds, and fire PRA) for the most limiting configuration (based on ICCDP/ICLERP and using the same plant operating alignment for the base case, CT case, and non-CT case) that aggregate the PRA updates requested in RAI-13.

b) Provide justification that the plant operating alignment(s) used for the internal events, internal flooding, high winds, and fire PRA models in part (a) is the most limiting configuration in terms of calculating the ICCDP and ICLERP for the EDG CT.

Duke Energy RAI-3.a Response Duke Energy provides updated risk results below in Tables 2 through 7 (i.e., ICCDP, ICLERP,

&')DQG/(5)IRULQWHUQDOHYHQWVLQWHUQDOIORRGLQJ, high winds, and fire PRA) for the most limiting configuration (based on ICCDP/ICLERP and using the same plant operating alignment for the base case, CT case, and non-CT case) that aggregate the PRA updates requested in RAI-13. The internal events and high winds PRA model revisions used to provide the updated risk results model both Train-A and Train-B equipment in either the running or standby mode of operation using split fractions. The internal flooding and fire models assume Train A is the running train and Train B is in standby (NOTE: the internal events model used to support the original LAR dated May 2, 2017 previously assumed Train A is the running train and Train B is in standby). Table 1 summarizes the alignments for the various hazard groups as follows and should be considered when reviewing the updated risk results of Tables 2 through 7:

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 10 Table 1 Alignments in Catawba PRA Hazard Models Hazard Train A Train B Internal Events Modeled with split fractions Modeled with split fractions as being either the running as being either the running High Winds or standby train or standby train Internal Flooding Modeled as the running Modeled as the standby Fire train train In addition to the alignments in Table 1 above, industry generic station blackout (SBO) failure rates were used in the PRA models that provide these updated risk results. Finally, point-estimate values were calculated and ACUBE was run on the associated cutsets to improve the accuracy of the Boolean quantification.

Table 2 RG 1.177 ICCDP Summary, ESPS to Train 2A Hazard 14 Day CT Base Multiplier ICCDP Internal Events 5.20E-06 3.95E-06 14/365 4.79E-08 Internal Flooding 2.03E-05 1.66E-05 14/365 1.42E-07 High Winds 2.02E-05 5.60E-06 14/365 5.60E-07 Fire (limiting Unit) 2.85E-05 2.27E-05 14/365 2.22E-07 Sum = 9.72E-07 Table 3 RG 1.177 ICLERP Summary, ESPS to Train 1A Hazard 14 Day CT Base Multiplier ICLERP Internal Events 2.95E-07 2.03E-07 14/365 3.53E-09 Internal Flooding 2.99E-07 4.46E-08 14/365 9.76E-09 High Winds 1.88E-06 7.18E-07 14/365 4.46E-08 Fire (limiting Unit) 2.05E-06 1.54E-06 14/365 1.96E-08 Sum = 7.74E-08 Table 4 351 Day ICCDP Risk Contribution Summary, ESPS to Train 2A Hazard ESPS credit Base Multiplier ICCDP Internal Events 3.27E-06 3.95E-06 351/365 -6.54E-07*

Internal Flooding 1.66E-05 1.66E-05 351/365 0.00E+00 High Winds 2.40E-06 5.60E-06 351/365 -3.08E-06*

Fire (limiting Unit) 2.24E-05 2.27E-05 351/365 -2.88E-07*

Sum = -4.02E-06*

• ICCDP is negative since ESPS adds an additional power source to the base case model.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 11 Table 5 351 Day ICLERP Risk Contribution Summary, ESPS to Train 1A Hazard ESPS credit Base Multiplier ICLERP Internal Events 1.36E-07 2.03E-07 351/365 -6.44E-08 Internal Flooding 4.46E-08 4.46E-08 351/365 0.00E+00 High Winds 1.54E-07 7.18E-07 351/365 -5.42E-07 Fire (limiting Unit) 1.50E-06 1.54E-06 351/365 -3.85E-08 Sum = -6.45E-07

• ICLERP is negative since ESPS adds an additional power source to the base case model.

Table 6 CDF For Entire Change, ESPS to Train 2A Hazard 14 Day CT 351 Day CDF Internal Events 4.79E-08 -6.54E-07 -6.06E-07 Internal Flooding 2.03E-05 0.00E+00 1.42E-07 High Winds 2.02E-05 -3.08E-06 -2.52E-06 Fire (limiting Unit) 2.85E-05 -2.88E-07 -6.60E-08 Sum = -3.05E-06 Table 7 LERF For Entire Change, ESPS to Train 1A Hazard 14 Day CT 351 Day LERF Internal Events 3.53E-09 -6.44E-08 -6.09E-08 Internal Flooding 2.99E-07 0.00E+00 9.76E-09 High Winds 1.88E-06 -5.42E-07 -4.98E-07 Fire (limiting Unit) 2.05E-06 -3.85E-08 -1.89E-08 Sum = -5.68E-07 Duke Energy RAI-3.b Response ICCDP and ICLERP for the EDG CT were calculated for ESPS aligned to Trains 1A, 2A, 1B, and 2B using the internal events, internal flooding, high winds, and fire PRA models. The alignment that resulted in the highest ICCDP is reported in the response to part (a). Similarly, the alignment that resulted in the highest ICLERP is reported in the response to part (a).

RAI Basic Event Failure Rate Anomalies Common Cause Failure Section 5, Quality Assurance, of RG 1.174, Revision 2, states, [w]hen a risk assessment of the plant is used to provide insights into the decisionmaking process, the PRA is to have been subject to quality control.

NRC staff noted in LAR Attachment 7, PRA Quantification Data Tables, which provides a listing of basic events and their corresponding probabilities, some apparent anomalies exist that could impact the LAR. In the October 8, 2018 supplement in response to audit Question 05.a, it states that EDG failure rates were updated; however, it is unclear to the

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 12 NRC staff whether the common cause failure (CCF) probabilities were also updated.

a) Confirm that the CCF probabilities associated with EDG failures were updated in response to audit Question 05.a.

b) Alternatively, if CCF probabilities were not updated, incorporate the appropriate CCF probabilities for the diesel generators into the PRA models used for this LAR that aggregate the PRA updates requested in RAI-13.

Duke Energy RAI-4 Response a) The common cause failure probabilities were not updated in response to the October 8, 2018 supplement audit question 05.a.

b) The RAI-13 response contains the aggregated results with CCF probabilities using the updated internal events model failure rates and CCF parameter estimations for Emergency Diesel Generators from US NRC CCF Parameter Estimations, 2015 Update.

RAI Seismic Analysis Contribution to the Application Section 2.3.2 of RG 1.177, Revision 1, states, [t]he scope of the analysis should include all hazard groups (i.e., internal events, internal flood, internal fires, seismic events, high winds, transportation events, and other external hazards) unless it can be shown that the contribution from specific hazard groups does not affect the decision.

The October 8, 2018 supplement, in response to audit Question 08.a, presents an approach for determining the bounding seismic CDF and LERF increase for the impact of the 14-day EDG outage. As part of the approach, the seismic hazard was divided into six hazard bins and a mean frequency of exceedance was determined for each seismic bin. It appears that these bin frequencies were then combined with conditional core damage probabilities (CCDPs) estimated by using the CCDP resulting from an internal events PRA loss of offsite power (LOOP) initiating event. The response states that seismic events are assumed to result in a LOOP event or to be low enough in magnitude to be subsumed as an internal event. It is not clear to NRC staff that this approach of using internal event CCDPs as a surrogate for seismic event CCDPs produces bounding seismic risk estimates for several reasons. Of primary concern, is that this approach does not account for seismically-induced SSC failures including those that could coincide with the unavailability of an EDG producing potentially significant seismic risk contributions. Also, the response states that human error probabilities (HEPs) are not adjusted to account for seismic scenario specific conditions. NRC staff acknowledges that at a certain magnitude (seismic bin), the fragility of the EDGs may be 100% correlated if they are located on the same elevation and location. In this case, all EDGs either fail or are successful for a given seismic bin, and if all EDGs fail then it is irrelevant whether an EDG is unavailable for test or maintenance. However, for seismic bins in which all EDGS are successful, then the unavailable EDG could coincide with a seismically-induced failure of a non-EDG SSC that produces a significant seismic risk contribution. Considering these observations:

a) Provide justification (e.g., describe and provide the results of an appropriate sensitivity study) that the seismic risk impacts produced by the analysis provided in

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 13 the October 8, 2018 supplement are bounding. As part of this justification, address how the risk contribution of seismic-induced SSC failures and seismic-impacted HFEs are considered b) Alternatively, appropriately update the bounding analysis and provide the revised seismic risk estimates with the new PRA results generated in response to RAI-13.

Duke Energy RAI-5.a Response The October 8, 2018 supplement provided a bounding seismic incremental CCDP of 1.87E-07 for the 14-day CT. The following analyses provide justification that the value provided can be considered as bounding.

For the analysis presented in this revised response, the seismic contribution to risk is addressed via two methodologies: 1) Use of the IPEEE seismic analysis and, 2) Use of a seismic penalty.

Both approaches offer reasonable results and support the original bounding value.

1) Use of the IPEEE Analysis -

The Catawba seismic CDF (SCDF) provided in response to the Individual Plant Examination for External Events (IPEEE) is 1.6E-05 / yr. (Ref. 1). This is an appropriate bounding value for several reasons given below.

x Figure 1 below shows a comparison of the new GMRS to SSE acceleration response spectra (Ref. 2). From that figure, the design basis SSE exceeds the GMRS below 5.5 Hz, and the GMRS begins to exceed the Catawba SSE above 5.5 Hz. The peak acceleration of the new GMRS is 0.75g at 30 Hz. Ground motions at levels up to 2 times the SSE are expected to produce only a small probability of failure for safety-related SSCs due to conservative design practices. In the high frequency range greater than 10 Hz, structural displacements are small and are considered non-damaging. Thus, the seismic hazard used in the IPEEE evaluation is considered to be conservative in the lower frequency ranges.

x The IPEEE SCDF includes failures from relay chatter events. These types of events are found to occur typically in the high spectral frequency range. In 2017, Catawba performed a High Frequency Confirmation evaluation in response to the NRC's 50.54(f) letter using the methods in EPRI Report 3002004396 (Ref. 6). This evaluation (Refs. 4 and 5) identified over 300 components requiring additional assessment, 66 of which were determined to be outliers. These were subsequently resolved by operator action within existing plant procedures. Including the effects of relay chatter in the IPEEE (with a recovery probability of 0.1) is thus considered a conservative measure in the analysis.

Based on its review of the high frequency confirmation report, the NRC staff concluded that the licensee appropriately implemented the high frequency confirmation guidance and identified and evaluated the high frequency seismic capacity of certain key installed plant equipment to ensure critical functions will be maintained following a seismic event up to the GMRS described in Catawba's Seismic Hazard and Screening Report (Ref. 7).

x The IPEEE SCDF does not consider mitigating strategies for accident sequences involving a total loss of power (which are the predominant makeup of the IPEEE cutsets).

Such sequences would now be addressed using Catawbas implementation of FLEX Order EA-12-049 requiring the licensee to develop, implement and maintain guidance and strategies to maintain or restore core cooling (Ref. 3).

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 14

• The IPEEE SCOF does not include the redundancy that would now be provided using ESPS. The ESPS diesel would likely be available and functional for station blackout events.

• The IPEEE SCOF does not include the Standby Shutdown Facility (SSF) which would be helpful with the mitigation of Station Blackout events by providing alternate RCP seal cooling, primary makeup, and instrumentation and controls to support longer term operation of the turbine-driven auxiliary feedwater pump. The SSF structure was initially screened out of the IPEEE due to its relatively low seismic capacity, as first reported in Catawba's IPE submittal (Ref. 8) . However, it is expected the SSF would be available for earthquakes occurring in the lower frequency ranges.

• The IPEEE included random failures of SSCs. The EOG random failure values used in the current Catawba model of record (MOR) are approximately a factor of 3 lower than those used in the IPEEE due to improvements in equipment reliability and maintenance practices. Thus, the accident sequences involving random failures of the EOGs in the IPEEE are conservative.

• Since the IPEEE submittal in 1994, there have been no new plant modifications which would improve or worsen the effects of seismic events.

SSE-GMRS comparison, 0.8

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0 0.1 1.0 10.0 100.0 Spectral frequency, Hz Figure 1 - Catawba Nuclear Station SSE v. GMRS The model used to perform the IPEEE analysis was re-run with one EOG taken out of service.

The resulting COF was 2.0E-05 / yr., resulting in a delta of 4E-06 I yr. Thus, for the 14-day AOT, the CCOP is, 4E-06 x (14 / 365) = 1.SE-07

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 15 The IPEEE also included various HFEs, the most predominant of which was the response to the relay chatter events discussed above. Also, as mentioned previously, the IPEEE analysis does not include the implementation of FLEX equipment. Given the risk significance of LOOP events, these would be the dominant accident sequences where FLEX would be required.

Thus, not including FLEX introduces conservatism in the IPEEE results and further demonstrates the IPEEE SCDF can be considered a reasonable bounding value.

Other HFEs used in the IPEEE include responses to a loss of AFW. Even though high screening values were used for this assessment, all of accident sequences combined involving these other HFEs made only a small contribution to SCDF (< 3%).

2) Use of a Seismic Penalty -

If seismic failures of the same or similar SSCs are assumed to be correlated, the Conditional Core Damage Probability (CCDP) given a seismic event will remain unaltered whether equipment is out of service or not. Thus, for the ESPS configuration, any seismic delta risk is primarily driven by accident sequences involving the loss of offsite power (LOOP), random failures of EDG systems (Fail To Run = 0.0343), seismic failure of non-EDG systems and associated operator actions. Contributions from other accident sequences are negligible due to the aforementioned correlated failure of related SSCs. For the purpose of computing the bounding seismic delta risk, the following conservative assumptions are made:

x All non-EDG SSCs are assumed to be failed or their fragilities are set to one for all hazard bins, irrespective of their seismic capacities.

x All HEPs are set to one for all hazard bins. In other words, there are no bin specific HEPs.

x No credit is given for the potential recovery of the loss of offsite power.

x No consideration of other mitigating equipment such as FLEX.

The seismic LOOP fragility parameter values are taken from NUREG/CR-6544 as follows:

Am = Median peak ground acceleration capacity in terms of peak ground acceleration (PGA)

= 0.3 g R = Lognormal standard deviation for randomness

= 0.3 U = Lognormal standard deviation for uncertainty

= 0.45 HCLPF = High confidence of a low probability of failure capacity

= 0.1 g Based on the above considerations, the bounding seismic SCDF contribution by the accident sequences related to the ESPS configuration can be computed for the base case as follows:

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 16 Hazard Initiator Lower Upper Representative Description Interval Bin Acc Acc Acceleration Frequency

%G01 Seismic Initiating Event (0.1g to < 0.15g) 0.1 0.15 0.12 2.05E-04

%G02 Seismic Initiating Event (0.15g to < 0.3g) 0.15 0.3 0.21 1.46E-04

%G03 Seismic Initiating Event (0.3g to < 0.5g) 0.3 0.5 0.39 3.54E-05

%G04 Seismic Initiating Event (0.5g to < 0.75g) 0.5 0.75 0.61 1.16E-05

%G05 Seismic Initiating Event (0.75g to < 1g) 0.75 1 0.87 4.05E-06

%G06 Seismic Initiating Event (1g to < 1.5g) 1 1.5 1.22 2.77E-06

%G07 Seismic Initiating Event (1.5g to < 10g) 1.5 10 3.87 1.59E-06 Base Case Non-EDG LOOP EDG - EDG - Seismic Initiator Seismic CCDP SCDF Fragility Train A Train B HEP Bin Failure 4.881E-02 3.430E-02 3.430E-02 1.000E+00 1.000E+00 5.74E-05 1.18E-08 %G01 2.608E-01 3.430E-02 3.430E-02 1.000E+00 1.000E+00 3.07E-04 4.47E-08 %G02 6.816E-01 3.430E-02 3.430E-02 1.000E+00 1.000E+00 8.02E-04 2.84E-08 %G03 9.065E-01 3.430E-02 3.430E-02 1.000E+00 1.000E+00 1.07E-03 1.24E-08 %G04 9.750E-01 3.430E-02 3.430E-02 1.000E+00 1.000E+00 1.15E-03 4.65E-09 %G05 9.954E-01 3.430E-02 3.430E-02 1.000E+00 1.000E+00 1.17E-03 3.24E-09 %G06 1.000E+00 3.430E-02 3.430E-02 1.000E+00 1.000E+00 1.18E-03 1.87E-09 %G07 Total SCDF = 1.07E-07 Seismic CDF contribution for each hazard bin is computed by SCDF = SIEF x CCDP SIEF = Seismic Initiating Event Frequency, computed by Hazard Interval Frequency x LOOP Fragility CCDP = Conditional Core Damage Probability, computed by Random failure rate of EDG A (0.0343) x Random failure rate of EDG B (0.0343 for base case and 1 for completion time case) x Seismic failure of non-EDG (conservatively set to 1) x Seismic HEP (conservatively set to 1).

The resulting bounding seismic SCDF contribution for the base case is 1.07E-07. Similarly, the bounding seismic SCDF contribution for the completion time case can be computed as follows:

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 17 Hazard Initiator Lower Upper Representative Description Interval Bin Acc Acc Acceleration Frequency

%G01 Seismic Initiating Event (0.1g to < 0.15g) 0.1 0.15 0.12 2.05E-04

%G02 Seismic Initiating Event (0.15g to < 0.3g) 0.15 0.3 0.21 1.46E-04

%G03 Seismic Initiating Event (0.3g to < 0.5g) 0.3 0.5 0.39 3.54E-05

%G04 Seismic Initiating Event (0.5g to < 0.75g) 0.5 0.75 0.61 1.16E-05

%G05 Seismic Initiating Event (0.75g to < 1g) 0.75 1 0.87 4.05E-06

%G06 Seismic Initiating Event (1g to < 1.5g) 1 1.5 1.22 2.77E-06

%G07 Seismic Initiating Event (1.5g to < 10g) 1.5 10 3.87 1.59E-06 Completion Time Case Non-EDG LOOP EDG - EDG - Seismic Initiator Seismic CCDP SCDF Fragility Train A Train B HEP Bin Failure 4.881E-02 3.430E-02 1.000E+00 1.000E+00 1.000E+00 1.67E-03 3.43E-07 %G01 2.608E-01 3.430E-02 1.000E+00 1.000E+00 1.000E+00 8.95E-03 1.30E-06 %G02 6.816E-01 3.430E-02 1.000E+00 1.000E+00 1.000E+00 2.34E-02 8.28E-07 %G03 9.065E-01 3.430E-02 1.000E+00 1.000E+00 1.000E+00 3.11E-02 3.60E-07 %G04 9.750E-01 3.430E-02 1.000E+00 1.000E+00 1.000E+00 3.34E-02 1.35E-07 %G05 9.954E-01 3.430E-02 1.000E+00 1.000E+00 1.000E+00 3.41E-02 9.46E-08 %G06 1.000E+00 3.430E-02 1.000E+00 1.000E+00 1.000E+00 3.43E-02 5.45E-08 %G07 Total SCDF = 3.12E-06 The resulting bounding seismic SCDF contribution for the completion case is 3.12E-06. Thus, the CCDP for the completion time case is computed as 3.01E-06 (=3.12E 1.07E-07) x 14/365 = 1.16E-07 /yr. It should be noted that the actual risk increase due to out of service equipment cannot be greater than this bounding value due to the conservative assumptions invoked above.

LERF Discussion Catawba does not have a formal seismic LERF model. A qualitative discussion was provided in the IPEEE submittal and addressed LERF from a containment integrity, containment isolation and containment response perspective. No seismic vulnerabilities were identified.

Furthermore, Duke submitted a relief request for responding to the seismic portion of the 50.54(f) letter (Ref. 12) using seismic PRAs. In the relief request, Duke maintained performing SPRAs would not provide significant additional seismic risk insights (other than those already gleaned from the IPEEE submittal). In its response (Ref. 13), the Staff concluded the plant-specific combination of seismic hazard exceedances, the general estimation of the seismic CDF and the insights related to the conditional containment failure probabilities at Catawba indicated that the increase in seismic risk due to the reevaluated seismic hazard was addressed within the margin inherent in the design. Hence, a seismic PRA was deemed as no longer necessary to fulfill the response to the seismic portion of the 50.54(f) letter.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 18 Therefore, since the seismic CDF values generated above using the IPEEE and seismic penalty analyses are conservative in nature and provide reasonable bounding values that are within the bounding value provided in the October 8, 2018 submittal, the corresponding LERF value would also be conservative and reasonable.

==

Conclusion:==

Using two separate analyses, Duke has provided justification that the seismic risk impacts produced by the analysis provided in the October 8, 2018 supplement is bounding. In addition, Duke has addressed how the risk contribution of the seismic-induced SSC failures and seismic-impacted HFEs were considered.

Duke Energy RAI-5.b Response No revision of the analysis is required based on response to part a) of this RAI.

RAI Avoiding Plant Configurations that Contribute to Significant Risk Section 2.3 of RG 1.177, Revision 1, cites the need to avoid risk-significant plant configurations and discusses Tier 2 of a three-tiered approach for evaluating risk associated with proposed TS CT changes. According to Tier 2, the licensee should provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is out of service consistent with the proposed TS change. Once the specific plant equipment are identified, an assessment can be made as whether certain enhancements to the TS or procedures are needed to avoid risk-significant plant configurations. In addition, Section 2.4 of RG 1.177 states, as part of the TS acceptance guidelines specific to permanent CT changes, the licensee should demonstrate that there are appropriate restrictions on dominant risk-significant configurations associated with the change. Section 2.4 of RG 1.177 also provides the risk acceptance guidelines for permanent CT changes, which also includes the need to demonstrate that there are appropriate restrictions on dominant risk-significant configurations associated with the CT change.

The LAR indicates that the ICCDP and ICLERP for the proposed TS change meet the risk acceptance guidelines in RG 1.177 by a small margin, and therefore, in accordance with Tier 2, it is important that plant configurations contributing to risk be avoided when the EDGs are taken out of service for the extended CT. Section 3.12.2 of the LAR provides a discussion of Tier 2 (Avoidance of Risk-Significant Plant Configurations) and identifies in LAR Table 1 those SSCs for Catawba that are important to the 14-day EDG CT based on SSC risk importance values presented in LAR Attachment 7. LAR Section 3.12.2 states that unavailability of the identified SSCs should be avoided during the extended CT. The October 8, 2018 supplement in response to audit Question 10, identifies several methods that are relied upon to avoid risk-significant plant configurations: Technical Specifications (TS), Selected Licensee Commitments (SLCs), cycle schedules, protected equipment schemes, and the Electronic Risk Assessment Tool (ERAT).

Section 6.1.5 of LAR Attachment 6 states, [t]he CT case for Catawba has restricted test and maintenance on the items listed in Table 6-58 [of LAR Attachment 6]. Table 6-58 of the LAR provides the Catawba SSCs important to the 14-day EDG CT (Table 6-58 is identical to Table 1 of the LAR). The October 8, 2018 supplement, in response to audit Question 11.b, states that in the CT-case the test and maintenance probabilities for the

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 19 following SSCs are set to zero in the PRA models: ESPS, opposite train EDG, turbine-driven Auxiliary Feedwater (AFW) pump (TDAFWP), and the SSF. The response states that these SSCs will remain in service utilizing the Protected Equipment and Work Management procedures. NRC staff notes that the calculated ICCDP and ICLERP values used to show alignment with the risk acceptance guidelines in RG 1.177 is based on ensuring this plant configuration. Considering these observations:

Propose a license condition that ensures (e.g., that implements the cited methods) the SSCs listed in LAR Table 1 (Table 6-58) will not be removed from service for planned maintenance or testing during the extended EDG CT.

Duke Energy RAI-6 Response Duke Energy proposes the below license condition be added to the Facility Operating License (FOL) for Catawba Units 1 and 2 that will ensure the SSCs listed in Table 1 of the LAR dated May 2, 2017 will not be removed from service for planned maintenance or testing during the extended EDG CT. The proposed license condition is reflected in the Unit 1 and Unit 2 FOL markup (see Attachments 5 and 6).

Proposed License Condition:

During the extended DG Completion Times authorized by Amendment No. [XXX], the turbine-driven auxiliary feedwater pump will not be removed from service for elective maintenance activities. The turbine-driven auxiliary feedwater pump will be controlled as protected equipment during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safety Shutdown Facility, Nuclear Service Water System, motor driven auxiliary feedwater pumps, and the switchyard will also be controlled as protected equipment.

RAI Risk Calculations for the EDG CT Extension Section 2.3 of RG 1.177, Revision 1, provides guidance on PRA modeling detail needed for TS changes. Section 2.3.3.1 of RG 1.177 states that the PRA model should also be able to treat the alignments of components during periods when testing and maintenance are being carried out. It also states that [s]ystem fault trees should be sufficiently detailed to specifically include all the components for which surveillance tests and maintenance are performed and are to be evaluated.

NRC staff observed that the Catawba internal flooding and high winds PRA risk results reported in LAR Attachment 6 were identical across units. For internal flooding, the October 8, 2018 supplement, in response to audit Question 11.a, states that the only significant difference between units is the addition of one internal flooding scenario to Unit 1 involving a break in the Main Feedwater piping in the Unit 1 doghouse which does not significantly impact the quantification results. For high winds, the supplement states that the Unit 1 results are adequate for Unit 2 based on the assumption that there is a high level of symmetry between units. Even though the response to Question 11.a identifies three shared systems between the units, with one of the systems (i.e., the Nuclear Service Water (RN) System) operating asymmetrically, that [t]his assumption was found to be reasonable based on an update of the high winds analysis that incorporated the Unit 2 internal events model.

However, contrary to the assertions cited above indicating that there is little asymmetry

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 20 between units that impact the risk estimates for internal flooding and high winds, NRC staff notes that the internal events risk results presented in the LAR indicate significant differences in CDF and LERF values between units. Tables 6-15, 6-16, 6-26 through 6-33, and 6-38 through 6-45 of the LAR show the following observations for internal events CDF and LERF risk values (base, CT, and non-CT cases): (1) Unit 1 CDF values are higher than Unit 2 by an average of 36%, (2) Unit 2 LERF values are higher than Unit 1 by an average RI  8QLW&')DQG,&&'3YDOXHVDUHKLJKHUWKDQ8QLWE\DQDYHUDJHRI

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the unit differences were based for the same plant configuration. The results presented in LAR Section 6.1.5.11 and the response to audit Question 14.a, which represent the most limiting configuration relative to CDF (Unit 1 Train A) and LERF (Unit 2 Train A), suggest that there are significant unit asymmetries. Since the internal events PRA model provides the underlying basis for the internal flooding and high winds PRA models, differences that are unaccounted for between units could significantly impact the internal flooding and high winds risk results.

Furthermore, because the LAR indicates that the ICCDP and ICLERP for the proposed TS change meet the risk acceptance guidelines in RG 1.177 by a small margin, uncertainty in modeling assumptions could impact the conclusions of the application.

Considering the observations above, the NRC staff requests the following additional information:

a) Explain how the single unit PRA models are representative or bounding for internal flooding and high winds (e.g., the most limiting) for Units 1 and 2. Include a discussion of how the single unit models account for the differences between units shown in the internal events risk results. Demonstrate that the differences between the single unit PRA models and Units 1 and 2 for risk-significant systems do not change the conclusions of the LAR. [Risk-significant systems considered by the NRC staff are those systems identified in LAR Table 1 and additional systems that appear to be risk-significant to the EDG CT based on information presented in tables provided in LAR Attachment 7 related to Fussell-Vesely (F-V) and Risk Achievement Worth (RAW) values for all Catawba hazard PRA models (e.g., 7-2, 7-3, 7-14, 7-15, 7-32, 7-48). These include, for example, motor-driven auxiliary feedwater, residual heat removal, chemical and volume control, 4160V switchgear, 600V components, 125 V direct current (dc) distribution (including batteries), ESFAS components (i.e. load shed, blackout logic), 6900 V switchgear, transformers, vital instrumentation and control power, main feedwater, hydrogen igniters, and air handling units.]

b) If the current modeling cannot be justified because the PRAs do not reflect the differences between units, then update the PRAs to reflect the difference between units in the Catawba PRA models used for this LAR that aggregate the PRA updates requested in RAI-13.

Duke Energy RAI-7.a Response High Winds As indicated in the response to RAI 9.b, Unit 1 and 2 high wind models are now based on the latest internal events PRA models. These models aggregate the PRA updates requested in RAI-13 and were used to re-evaluate the LAR PRA results.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 21 Internal Flood Since the internal flood (IF) model is based on the Unit 1 internal events model, Unit 2 systems have been investigated for similarity with those for Unit 1 to ensure that the same PRA results generally apply to both units. Because of the similarities in the containments at Unit 1 and Unit 2, the investigation focused on the individual plant systems modeled in the plant fault tree.

The unit comparison focused on differences in the system design or in component fault exposure times which would result in differences in the system fault trees. Design Basis Documents, Technical Specifications, system flow diagrams, electrical drawings, general arrangement drawings, manufacturers drawings and manuals, and training documentation were examined and compared. This comparison was used as a basis to determine if further investigation was warranted.

Shared Systems Instrument Air (VI) System The instrument air system is shared between both units. Because of this, there are no unit differences and interdependencies except the power supplies to the VI compressors and other VI components, which are powered from different units to minimize the impact from an event on any given unit.

Standby Shutdown System (SSS)

During an emergency, the Standby Shutdown Facility (SSF) is used to achieve and maintain hot standby on one or both units. Operators can establish natural circulation in the NC System, initiate auxiliary feedwater, and line up SSS valves either in the control room or locally. Plant control is then to be shifted to the SSF. Primary and secondary inventory is controlled and primary natural circulation is verified once SSF control is established.

Electrical power needed to achieve and maintain hot standby is supplied by the SSF diesel generator. Non-LOOP initiators do not require the SSF diesel generator to be started for electrical power to the SSF functions. For those initiators, normal station power is sufficient.

Nuclear Service Water System (RN)

The source and intake section of the RN system is comprised of the standby nuclear service water dam, the standby nuclear service water intake structure, the nuclear service water intake structure, Lake Wylie, and the Standby Nuclear Service Water Pond (SNSWP). All of these are shared by both CNS units.

Flow enters each pit from either Lake Wylie or the SNSWP, and four RN pumps (1A, 1B, 2A, and 2B) supply nuclear service water to the entire station. RN pumps 1A and 2A draw water from the A pit and discharge into a common train A supply header that serves both units, and RN pumps 1B and 2B draw water from the B pit and discharge into a common train B supply header that serves both units.

Essential Auxiliary Power Systems The 600 V ac essential auxiliary power system consists of two redundant safety trains, Train A and Train B per unit. The unit can be safely shut down with only one train in operation. The

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 22 system consists of four essential load centers, their associated load center transformers, one shared-standby load center transformer per load center pair, and fifteen essential motor control centers.

Other equipment throughout the electrical distribution systems, such as 6.9/4.16 kV shared aux. transformers SATA and SATB, may be fed from either unit to power loads on either unit.

Unit Differences The only significant unit difference identified by the review is that normal power to the SSF is supplied from Unit 1. However, the current modeling treatment is bounding for Unit 2 since for Unit 2, Unit 1 power is a diverse power source.

The following table considers the PRA impact of any unit differences for the specific equipment identified in RAI 7.a.

Table 1 Catawba SSCs Important to the LAR PRA Results SSC Unit Differences (if any) PRA Impact Associated with Using a Single-Unit Model Non-CT EDG None None ESPS System None None Component None None Cooling System (KC)

Turbine Driven AFW None None Pump (CA)

Safe Shutdown Facility Normal power is supplied from Unit 1. Use of the Unit 1 model is (SS) bounding. For Unit 2, Unit 1 is a diverse power source.

Nuclear Service N/A, shared SSC None Water System (RN)

Motor-Driven AFW None None Pumps (CA)

Switchyard N/A, shared SSC None Residual Heat Removal None None (ND) system Chemical and Volume None None Control (NV) system 4160 V switchgear None None 600 V components 600 V components are highly Not significant due to highly symmetric, with some differences in symmetric distribution of power power distribution (e.g., different VI compressors are powered from different units) 125 V dc distribution None None (including batteries)

ESFAS components None None 6900 V switchgear None None transformers None None vital instrumentation and None None control power

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 23 Table 1 Catawba SSCs Important to the LAR PRA Results SSC Unit Differences (if any) PRA Impact Associated with Using a Single-Unit Model Main Feedwater System None None (CF)

Hydrogen Igniters None None Air Handling Units None None battery chargers None None seal water injection None None Internal Flood Considerations The Catawba IF PRA includes Unit 1 and Unit 2 differences as follows. Although the IF PRA is built on the Unit 1 internal events model, Unit 2 is evaluated as well in several ways. First, Unit 2 specific or shared unit piping was included in the analysis for initiating event analysis. If Unit 2 piping was found to impact both units it was included in the model. In addition, Unit 2 specific areas were evaluated to determine whether scenarios could impact Unit 2 only or both units. If both units could be impacted (e.g. dual-unit trip), the scenario was included in the model. Shared or cross tied systems were also evaluated when developing scenarios as to whether they would be successful for the given scenario. During the internal flood walkdowns, the designated CNS Unit 1 flood areas were validated as applicable to CNS Unit 2, and any discrepancies were documented, retained for further analysis, and included in the model as appropriate.

Conclusion Unit 1 and 2 high wind models are now based on the latest internal events PRA models. Thus, the issue of unit differences no longer applies for high winds.

For internal flood, the systems review discussed above and the review of unit differences for the risk-significant SSCs identified in LAR Table 1 and cited in RAI-7.a determined that the Unit 1 model is representative or bounding. The internal flooding analyses evaluated the impacts of Unit 2 on initiator and scenario development. SSCs that are shared between both units are implicitly modeled in the Unit 1 model. Internal flood walkdowns of the CNS Unit 1 flood areas were validated as being applicable to CNS Unit 2, and any discrepancies were documented, retained for further analysis, and included in the model as appropriate.

Thus, the reviews of the Catawba high wind and internal flood models have determined that the conclusions of the LAR remain valid.

Duke Energy RAI-7.b Response As discussed in the response to RAI 7.a, the current modeling is justified because the PRAs adequately reflect the differences between units and aggregate the PRA updates requested in RAI-13.

RAI Implementation Verification of ESPS System Regulatory Guide 1.174, Revision 2, provides quantitative guidelines on CDF, LERF, and

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 24 identifies acceptable changes to these frequencies that result from proposed changes to the plants licensing basis and describes a general framework to determine the acceptability of risk-informed changes. The NRC staffs review of the information in the LAR, as supplemented, has identified additional information that is required to fully characterize the risk estimates.

The estimated risk associated with the EDG CT extension is based on assumptions about an ESPS system that has not yet been installed and operator actions for which procedures have not been completed. Upon completion of these plant modifications and procedures, the PRA models will need to be assessed against the as-built, as-operated plant and updated, as necessary. Then new risk estimates will need to be generated and evaluated to confirm that the conclusions of the LAR have not changed.

In the October 8, 2018 supplement in response to audit Question 12, the licensee identifies eight assignments that involve the review and update of specific aspects of ESPS PRA modeling after the installation of the ESPS and completion of associated operating procedures. The NRC staff interprets these assignments as commitments; however, completing these assignments is necessary to ensure that the PRA modeling represents the as-built, as-operated ESPS system and the risk acceptance guidelines in RG 1.177 and RG 1.174 are met upon completion of the ESPS plant modifications and associated procedures.

Propose a license condition requiring that after the ESPS system is installed and applicable procedures updated and prior to implementing the 14-day EDG CT: (1) update the risk estimates associated with this LAR, as necessary, (including results of sensitivity studies) using PRA models that reflect the as-built, as-operated plant, and (2) confirm these updated risk estimates continue to meet the risk acceptance guidelines of RG 1.174 and RG 1.177.

Duke Energy RAI-8 Response A license condition is proposed in Attachments 5 and 6, for Units 1 and 2, respectively, requiring that the risk estimates associated with the 14-day EDG Completion Time LAR (including those results of associated sensitivity studies) will be updated, as necessary to incorporate the as-built, as-operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance guidelines of RG 1.174 and RG 1.177.

RAI Internal Flooding and High Winds PRA Model Technical Adequacy and Updated Internal Events Logic Transferred to Other Hazard Models The LAR states that the proposed change to the TS CT has been developed using the risk-informed processes described in RG 1.174, Revision 2, and RG 1.177, Revision 1. Based on Section 2.3.1 of RG 1.177, the technical adequacy of the PRA must be compatible with the safety implications of the TS change being requested and the role that the PRA plays in justifying that change. The RG 1.177 endorses the guidance provided in RG 1.200, Revision 2, on PRA technical adequacy. Section 1 in Regulatory Position C of RG 1.200 states, the PRA results used to support an application must be derived from a baseline PRA model that represents the as-built, as-operated plant to the extent needed to support the application. Consequently, the PRA needs to be maintained and upgraded, where necessary, to ensure it represents the as-built, as-operated plant.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 25 The F&O WPR-A4-01, in LAR Attachment 8, states, no evidence of satisfying the requirements of Part 2 [of ASME/ANS RA-Sa-2009], or basis for exceptions to the requirements, was provided. The Part 2 of the ASME/ANS RA-Sa-2009 PRA standard pertains to the technical adequacy of the internal events PRA model used as the starting point for the high winds PRA plant response model. The disposition of this finding, provided in LAR Attachment 8, states the internal events model has undergone an update (i.e., Revision 4) to comply with RG 1.200, Revision 2. However, the response in the October 8, 2018 supplement to audit Question 13.a states that the version of the internal events PRA model used to develop the internal flooding, high winds, and fire PRA models was Revision 3 whose technical adequacy is based on the 2001 peer review. Furthermore, the response to audit Question 13.c states, the 2015 peer reviews were performed on the Rev. 4 internal events models, which are significantly different from the Rev. 3 models.

Therefore, it appears that F&O WPR-A4-01 was not resolved because the updated Revision 4 internal events model was not incorporated in the high winds PRA model.

Additionally, it is also unclear to the NRC staff how the technical adequacy of the underlying PRA model for internal flooding is addressed since it uses the same internal events model as the high winds PRA model. [The NRC staff notes that the licensee provided dispositions of the underlying internal events PRA model F&Os for the fire PRA according to the NRC letter dated February 8, 2017, Catawba Nuclear Station, Units 1 and 2 - Issuance of Amendments Regarding National Fire Protection Association Standard NFPA 805 (CAC NOS. MF2936 and MF2937) (ADAMS Accession No. ML16137A308). These F&Os may have a different impact on the internal flooding and high winds PRAs, and the associated dispositions provided in the NFPA 805 application may not be applicable for the internal flooding and high winds PRAs used for the LAR dated May 2, 2017. In addition, the February 8, 2017 NRC evaluation states that resolution of PRA RAI 02.f.e regarding F&O DA-02 required the incorporation of updated generic data and common cause failure rates in the fire PRA model. It is unclear whether this update was applied to the internal flooding and high winds PRA model.]

The response to audit Question 13.a further states that the internal events model has been updated to Revision 4, in which there are [s]ignificant internal events model changes between revisions 3 and 4. The supplement lists a few of the significant changes that could impact the internal flooding, fire and high winds PRAs, including: updated model data, updated human reliability analysis (HRA) (resulting in a change in HEP values),

development of unit-specific models, addition of a condensate and condenser circulating water system models, addition of support system initiating events (SSIEs), transition from Multiple Greek Letter CCF method to alpha-factor method, and switching from a single alignment model to multiple alignments. Accordingly, it is not clear how the Catawba internal flooding, fire and high winds PRAs address the modeling updates performed for the internal events PRAs. These internal events updates appear to represent modeling improvements that result in a more realistic representation of the as-built, as-operated plant as prescribed in RG 1.200, Revision 2.

To address the above observations, provide the following information.

a) Provide a detailed justification that incorporating the Revision 4 internal events PRA model into the internal flooding, high winds, and fire PRA models does not change the conclusions of the LAR, as supplemented. This justification may include:

x Provide the finding-level F&Os from the 2001 - 2002 internal events PRA model peer review with dispositions related to this application for internal

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 26 flooding and high winds. Include a gap assessment addressing the differences between NEI 00-02 and RG 1.200, Revision 2 and provide justification that the identified gaps do not impact the insights and conclusions of this application.

x Describe all model changes (e.g., model changes to address: Revisions 3 and 4 F&Os, plant representation, level of detail, enhancements), in addition to those provided in the October 8, 2018 supplement, made to the internal events PRA (since Revision 3) that were not incorporated into the internal flooding, high winds, and fire PRA models. Provide detailed justification (e.g., describe and provide the results of an appropriate sensitivity study using the PRA models from the aggregate analysis requested in RAI-13) that incorporating these model changes into the internal flooding, high winds, and fire PRA models does not impact the conclusions of the LAR, as supplemented.

b) Alternatively to part (a), incorporate the Revision 4 internal events PRA model into the internal flooding, high winds and fire PRA model.

Duke Energy RAI-9.a Response See response to RAI 9.b Duke Energy RAI-9.b Response The high winds model was incorporated into Revision 4 of the internal events PRA model and is now used for this application. This high winds PRA model update was aggregated into the PRA updates requested in RAI-13.

The Revision 4 internal event PRA model changes were incorporated into internal flood and fire PRA models and are now used for this application. The changes made to the internal flood and fire models based on the updates made to Revision 4 internal events model are as follows.

Relevant changes that were made to the internal flood and fire PRA models include updated database changes (e.g., failure probabilities and type codes) and the updated model data. Other relevant changes also included fault tree logic changes (e.g.,

ESPS; HVAC logic for selected components, update FWST logic, steam generator success criteria, service water pump logic, and VCT logic for flow diversion) and the use of equivalent modeling where gate mapping was not one-to-one.

Where a review determined a change to not be relevant to the internal flood and fire PRA models, the internal flood and fire models were not updated (e.g., non-fire and non-flood initiators; ATWS, MLOCA, and other non-fire and non-flood accident sequences; and human failure events not appropriate for the fire and flood hazards).

The internal flood and fire PRA models were also not updated to incorporate the Revision 4 internal events PRA model when the change would have no impact on risk (e.g., gate or basic even naming). There is no impact to the LAR for both types of changes since the changes are not relevant to internal flood or fire or they have no impact on risk.

A review of all changes to the internal events PRA model identified only new Human Failure Events (HFE) as potentially impacting the proposed change. However, even if

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 27 the new HFEs were to be incorporated into the updated fire and internal flood PRAs, then the total risk results (i.e., CDF and LERF) would decrease. Therefore, not LQFRUSRUDWLQJWKH+)(VLVFRQVHUYDWLYH5HJDUGLQJWKHGHOWDULVNUHVXOWV LH&')

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related risk contributions for the HFEs in internal events cutsets associated with initiators that are mapped to the fire or flood events in the fire or flood PRAs.

Overall, the risk results using the updated fire and internal flood PRAs with the changes described above supports the assertion that incorporating the discrepancies between the internal events PRA model of record and the fire and internal flood PRA models of record does not impact the conclusions of the ESPS LAR application.

RAI Sources of Model Uncertainty and Parametric Uncertainty The LAR for Catawba, dated May 2, 2017, states that the proposed change to the TS CT has been developed using the risk-informed processes described in RG 1.174, Revision 2, and RG 1.177, Revision 1. Regulatory Position C of RG 1.174 states:

x In implementing risk-informed decisionmaking, LB [licensing basis] changes are expected to meet a set of key principles. In implementing these principles, the staff expects [that]: Appropriate consideration of uncertainty is given in the analyses and interpretation of findings. NUREG-1855 provides further guidance.

x Section 2.5.2 further elaborates, because of the way the [risk] acceptance guidelines were developed, the appropriate numerical measures to use in the initial comparison of the PRA results to the acceptance guidelines are mean values. The mean values referred to are the means of the probability distributions [of the risk metrics] that result from the propagation of the uncertainties on the [PRA] input parameters and those model uncertainties explicitly represented in the model under certain circumstances, a formal propagation of uncertainty may not be required if it can be demonstrated that the state-of-knowledge correlation [SOKC] is unimportant.

a) Revision 0 of NUREG-1855 (2009) primarily addressed sources of model uncertainty for internal events (including internal flooding) and references EPRI report 1016737, Treatment of Parameter and Modeling Uncertainty for Probabilistic Risk Assessments (2008), which provides a generic list of sources of model uncertainty and related assumptions for internal events. Revision 1 of NUREG-1855 (March 2017, ADAMS Accession No. ML17062A466) further clarifies the NRC staff decisionmaking process in addressing uncertainties and addresses all hazard groups (e.g., internal events, internal flooding, internal fire, seismic, low-power and shutdown, Level 2). NUREG-1855, Revision 1, cites use of EPRI reports 1016737 and 1026511, Practical Guidance on the Use of Probabilistic Risk Assessment in Risk-Informed Applications with a Focus on the Treatment of Uncertainty (2012), which complements the NUREG and provides a generic list of sources of model uncertainty for internal events, internal flooding, internal fires, seismic, low-power and shutdown, and Level 2 hazard groups. While LAR Section 3.12.4 states a review of potential modeling uncertainties was performed using Revision 1 of NUREG-1855, the discussion in LAR Section 6.2 and the results provided in LAR Attachment 9 indicate that Revision 0 of NUREG-1855 (and EPRI report 1016737) was used to evaluate sources of uncertainty for only internal events (including

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 28 internal flooding).

i. Clarify which version of NUREG-1855 was used for the uncertainties analysis described in the LAR.

ii. Provide a detailed summary of the process used to evaluate sources of model uncertainty and related assumptions [both generic (e.g., EPRI reports 1016737 and 1026511) and plant-specific sources] in the internal events, internal flooding, high winds, and internal fires PRAs for their potential impact on this application.

Include in this discussion an explanation of how the process aligns with guidance in NUREG-1855, Revision 1, or other NRC-accepted method.

iii. In accordance with the process described in Part (a.ii) above, describe any additional sources of model uncertainty and related assumptions relevant to the application that were not provided in LAR Attachment 9, and describe their impact on the application results.

iv. In accordance with NUREG-1855, Revision 1, for those sources of model uncertainty and related assumptions that could potentially challenge the risk acceptance guidelines (i.e., key uncertainties and assumptions), provide qualitative or quantitative justification for why these key uncertainties and assumptions do not change the conclusions of the LAR (e.g., describe and provide the results of an appropriate sensitivity study(ies) using the PRA models used to perform the aggregate analysis requested in RAI-13); describe and provide the results of a more detailed, realistic analysis to reduce the conservatism and uncertainty; propose compensatory measures and explain how they address the key uncertainties and assumptions).

b) Section 2.3.1 of Regulatory Guide 1.177 states that current good practice (i.e., CC II of the ASME/ANS PRA standard) is the level of detail needed for the PRA to be adequate for the majority of applications. Based on RG 1.174 and Section 6.4 of NUREG-1855, Revision 1, for a CC II risk evaluation, the mean values of the risk metrics (i.e., CDF, LERF) and the means of their incremental values (i.e., ICCDP, ICLERP) need to be compared against the risk acceptance guidelines. The mean values referred to are the means of the risk metrics probability distributions that result from the propagation of the uncertainties on the PRA input parameters and those model uncertainties explicitly represented in the model. In general, the point estimate CDF/LERF obtained by quantification of the cutset probabilities using mean values for each basic event probability does not produce a true mean of the CDF/LERF. Under certain circumstances, a formal propagation of uncertainty may not be required if it can be demonstrated that the state-of-knowledge correlation (SOKC) is unimportant (i.e., the risk results are well below the acceptance guidelines).

Attachment 6 of the LAR, as supplemented, provides the ICCDPs and ICLERPs for the proposed CT extension based on point estimate values of the risk metrics. The basis for using these point estimates is the results of an assessment provided in LAR Section 6.2.3, in which a parametric uncertainty analysis was performed on the internal events PRA to determine the baseline mean CDF and LERF which were then compared to the internal events baseline CDF and LERF determined using point estimate values. The comparison showed that the baseline CDF and LERF determined using point estimate values were within 10% of the means values. However, this approach is not consistent

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 29 with NUREG-1855, Revision 1. For one reason, the licensees parametric uncertainty analysis did not include the other hazards (i.e., internal flooding, high winds, and internal fires) and its impact on ICCDP and ICLERP, which challenge the risk acceptance guidelines (i.e., Regime 3 in NUREG-1855, Revision 1) and could potentially impact the conclusions of the LAR. Additionally, the LAR states that the parametric uncertainty was conducted on the internal events model before changes were made for this application and LAR Figures 1 through 4 do not provide any specific values (i.e., point estimate, mean) to validate the conclusion of Section 6.2.3.

i. Provide a detailed summary of the process used to evaluate parametric uncertainties in the calculation of ICCDP and ICLERP for the internal events, internal flooding, high winds, and internal fires PRAs. Include in this discussion an explanation of how the process is in accordance with Section 6, Stage D -

Assessing Parameter Uncertainty, of NUREG-1855, Revision 1, or other NRC accepted method. Justify any conclusions made that addressing the SOKC is not important to the quantitative conclusions of this application.

ii. In accordance with the process described in Part (b.i) above, provide the ICCDPs and ICLERPs for internal events, internal flooding, high winds, and internal fires as requested in RAI-13.

Duke Energy RAI-10.a Response

i. Revision 0 of NUREG-1855 was used for the uncertainties analysis described in the LAR.

ii. The process described in NUREG-1855 Revision 0 was used to evaluate the model uncertainties and assumptions associated with the PRAs that were presented in the LAR. Subsequently, the results were compared to NUREG-1855, Revision 1, and additional uncertainties in NUREG-1855, Revision 1, were addressed.

As part of the assessment, the plant-specific model uncertainties documented in the notebooks associated with the internal flooding, high winds, and internal fires PRAs were assessed with respect to the ESPS application. The generic sources taken from EPRI reports 1016737 and 1026511 were also assessed.

iii. No additional sources of model uncertainty and related assumptions relevant to the application were identified.

iv. No additional sensitivity runs were required, beyond those given in the LAR, due to no additional sources of model uncertainty and related assumptions relevant to the application were identified.

Duke Energy RAI-10.b Response

i. The parametric uncertainties for all the hazards were evaluated by using the EPRI UNCERT code which samples the basic event / basic event type code parameter

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 30 uncertainty distributions to propagate the uncertainty and develop a mean estimate and distribution for the CDF and LERF values presented. This code effectively accounts for the SOKC impacts as the sampling is performed on a failure mode (type code) basis.

Since the SOKC impacts are evaluated by the UNCERT code, the corrections applied to adjust the CAFTA point estimate are removed before running the code. This results in the point estimate listed for the UNCERT run being reduced from the CAFTA produced point estimate. No peer review findings were identified with the methods used to account for SOKC. The risk results are compared against the risk acceptance guidelines given in Regulatory Guide 1.177, Revision 1. This process aligns with the guidance provided in Section 6 of NUREG-1855, Revision 1.

ii. The ICCDPs and ICLERPs for internal events, internal flooding, high winds, and internal fires for the four potential alignments of ESPS during a 14-day AOT are provided below.

The limiting of these for ICCDP and for ICLERP are also provided in RAI 13. For each alignment, the ICCDP and ICLERP are below the risk acceptance guidelines given in Regulatory Guide 1.177, Revision 1.

RG 1.177 ICCDP Summary (Mean Aggregate Results Unit 1 A)

Hazard 14-Day CT Base Multiplier ICCDP Internal Events 6.46E-06 4.19E-06 14/365 8.73E-08 Internal Flooding 2.03E-05 1.66E-05 14/365 1.42E-07 High Winds 1.76E-05 5.73E-06 14/365 4.55E-07 Fire 2.89E-05 2.40E-05 14/365 1.89E-07 Sum = 8.73E-07 RG 1.177 ICCDP Summary (Mean Aggregate Results Unit 1 B)

Hazard 14-Day CT Base Multiplier ICCDP Internal Events 6.25E-06 4.19E-06 14/365 7.90E-08 Internal Flooding 2.00E-05 1.66E-05 14/365 1.32E-07 High Winds 1.75E-05 5.73E-06 14/365 4.53E-07 Fire 2.71E-05 2.40E-05 14/365 1.21E-07 Sum = 7.85E-07 RG 1.177 ICCDP Summary (Mean Aggregate Results Unit 2 A)

Hazard 14-Day CT Base Multiplier ICCDP Internal Events 5.41E-06 4.16E-06 14/365 4.77E-08 Internal Flooding 2.03E-05 1.66E-05 14/365 1.42E-07 High Winds 2.07E-05 5.72E-06 14/365 5.73E-07 Fire 2.81E-05 2.27E-05 14/365 2.06E-07 Sum = 9.70E-07

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 31 RG 1.177 ICCDP Summary (Mean Aggregate Results Unit 2 B)

Hazard 14-Day CT Base Multiplier ICCDP Internal Events 5.31E-06 4.16E-06 14/365 4.39E-08 Internal Flooding 2.00E-05 1.66E-05 14/365 1.32E-07 High Winds 2.07E-05 5.72E-06 14/365 5.75E-07 Fire 2.77E-05 2.27E-05 14/365 1.90E-07 Sum = 9.41E-07 RG 1.177 ICLERP Summary (Mean Aggregate Results Unit 1 A)

Hazard 14-Day CT Base Multiplier ICCDP Internal Events 3.17E-07 2.16E-07 14/365 3.90E-09 Internal Flooding 2.63E-07 4.46E-08 14/365 8.39E-09 High Winds 1.95E-06 7.46E-07 14/365 4.62E-08 Fire 2.01E-06 1.54E-06 14/365 1.77E-08 Sum = 7.62E-08 RG 1.177 ICLERP Summary (Mean Aggregate Results Unit 1 B)

Hazard 14-Day CT Base Multiplier ICCDP Internal Events 2.88E-07 2.16E-07 14/365 2.78E-09 Internal Flooding 2.62E-07 4.46E-08 14/365 8.33E-09 High Winds 1.80E-06 7.46E-07 14/365 4.04E-08 Fire 1.86E-06 1.54E-06 14/365 1.20E-08 Sum = 6.35E-08 RG 1.177 ICLERP Summary (Mean Aggregate Results Unit 2 A)

Hazard 14-Day CT Base Multiplier ICCDP Internal Events 2.88E-07 2.23E-07 14/365 2.50E-09 Internal Flooding 2.63E-07 4.46E-08 14/365 8.39E-09 High Winds 1.99E-06 6.99E-07 14/365 4.94E-08 Fire 1.72E-06 1.38E-06 14/365 1.30E-08 Sum = 7.33E-08 RG 1.177 ICLERP Summary (Mean Aggregate Results Unit 2 B)

Hazard 14-Day CT Base Multiplier ICCDP Internal Events 2.63E-07 2.23E-07 14/365 1.56E-09 Internal Flooding 2.62E-07 4.46E-08 14/365 8.33E-09 High Winds 1.88E-06 6.99E-07 14/365 4.52E-08 Fire 1.70E-06 1.38E-06 14/365 1.21E-08 Sum = 6.72E-08

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 32 RAI Supplement Fire PRA Results RG 1.174, Revision 2, provides quantitative guidelines on CDF and LERF and identifies acceptable changes to these frequencies that result from proposed changes to the plants licensing basis and describes a general framework to determine the acceptability of risk-informed changes. RG 1.177, Revision 1, provides risk acceptance guidelines on ICCDP and ICLERP that result from permanent changes to the licensees TSs. The NRC staff review of the information in the LAR, as supplemented, has identified additional information that is required to fully characterize the risk estimates.

The October 8, 2018 supplement, in response to audit Question 14.a, shows a decrease in risk (i.e., a negative ICCDP and ICLERP) from the base case (two safety-related EDGs with auto-start capability) to the CT case (one safety-related EDG and one non-safety diesel generator with no auto-start capability) of 3.1E-06 for CDF and 3.7E-07 for LERF. It is unclear to the NRC staff why substituting a safety-related EDG with a non-safety diesel generator with no auto-start capability significantly reduces risk.

Explain how substituting a safety-related EDG with a non-safety diesel generator reduces fire risk. Include in this discussion changes in fire scenarios, significant accident scenarios, and significant cutset results.

Duke Energy RAI-11 Response This response is based on the model used to provide the referenced results in this question.

That model has been updated to address additional questions raised in RAI 9 and thus the model results presented in RAI 13 are slightly different than before. The fire model has been updated to address internal events model changes, which resulted in the reduction of the base and nominal cases mainly due to the data update resulting in lower random failure rates.

The inclusion of the ESPS system to the plant adds redundancy and diversity in the AC power supplies to the plants Safety Buses. There are multiple levels of redundancy and diversity.

The foremost AC power source is offsite power, unless offsite power is lost to the Safety Buses there is no need for emergency or alternate AC. The next layers are the two redundant Emergency Diesel generators per unit and the potential to cross-tie between Units. The next level is the capability of the SSF and Turbine Driven AFW. The final level of mitigation in the form of alternate AC power is the ESPS system.

The fire scenarios that would benefit from the addition of an alternate AC source in the form of the ESPS are scenarios in which offsite power is lost, a transmission path between the ESPS and Safety Bus exists, and other AC power sources (Emergency Diesels and cross-tie between the Units) are unavailable.

The restriction of test and maintenance on risk important equipment (e.g., turbine driven auxiliary feed pump and SSF) during the CT in combination with the diversity in AC power provided by the ESPS resulted in the decrease in risk.

In most scenarios the Turbine Driven AFW pump provides one of the decay heat removal success paths, so the restriction on test and maintenance reduces risk in these scenarios.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 33 The restriction of maintenance on the Safe Shutdown Facility (SSF) is important for the control room abandonment scenarios as it is the only credited success path and the control room abandonment scenarios are independent of the status of the Emergency Diesels and the ESPS system. The SSF can also provide mitigation capabilities following scenarios involving a loss of offsite power and other plant system failures.

The restriction on service water (RN) maintenance is important as it applies to most fire scenarios as support for equipment cooling directly or through Component Cooling Water. This system also supports Emergency Diesel cooling. The ESPS is air cooled and does not require service water.

The scenarios that are impacted by an Emergency Diesel generator being out of service are 1) the turbine building fires that impact the 6.9kV buses that connect the emergency buses to offsite power and 2) fires that impact the safety related Emergency Buses associated with each Emergency Diesel.

In the scenarios where the 6.9kV buses are impacted the ESPS is not credited due to no transmission path to an Emergency Bus. This results in the loss of redundancy of the Emergency Diesel in the CT, leaving only the opposite train Emergency Diesel and the SSF for accident mitigation. But the availability of these power sources has been increased as test and maintenance on them has been restricted.

In the case where the fire was impacting the Emergency Bus associated with the Emergency Diesel in the CT, the alternate train Emergency Bus can be supplied by the non-CT Emergency Diesel or the ESPS. The mitigation capability also includes the SSF. All of these mitigation systems have increased availability due to the restriction on test and maintenance.

The most limiting scenarios would involve a fire on the Emergency Bus associated with the non-CT Emergency Diesel. In this case, the ESPS would be the only power supply besides offsite power to support the remaining Emergency Bus. The mitigation capability would also still include the SSF.

RAI Application of Generic and Bayesian Updated Diesel Generator Failure Rates ASME/ANS 2009 PRA standard SR DA-D1 states for Capability Category (CC)-II,

[c]alculate realistic parameter estimatesWhen it is necessary to combine evidence from generic and plant-specific data, use a Bayes update process.

The October 8, 2018 supplement, in response to audit Question 14.b, states, [t]he generic station blackout diesel failure rates from NUREG/CR-6928 2016 updated parameter estimates were used for ESPS failure rates for the aggregate sensitivity case. Whereas, for the best estimate case, the extensive factory acceptance testing data was used to update the ESPS diesel generator failure rates. NRC staff notes that factory testing data should not be substituted for plant-specific data in the Bayesian update process. Factory data is not plant-specific data and would not account for differences in installation, environment, maintenance, testing, and operation between a factory and nuclear power plant. The staff understands that the ESPS diesel generators have not yet been installed at the site.

Incorporate in the PRA model the non-Bayesian updated failure rates for the ESPS diesels (i.e., the generic station blackout (SBO) diesel failure rates chosen by the licensee for this

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 34 component) for the aggregate and all related sensitivity studies requested in RAI-13.

Duke Energy RAI-12 Response The generic SBO failure rates were used for the ESPS diesels for the aggregate risk sensitivity as stated in the response audit question 5. Duke Energys response to RAI-13 reflects the continued use of these generic failure rates in the aggregate risk sensitivity study.

However, Duke Energys position is that the use of Bayesian update process is warranted for the generic SBO failure rates associated with the best estimate case for the following reasons:

1) The Bayesian update process is based on the performance of the actual equipment installed.

2) The Bayesian update process factors in testing that was performed during the time in which, according to the bathtub curve from reliability engineering, infant mortality causes would be the dominant failure mode.

3) The ESPS diesel generators are of a much newer design than the diesel generators that were added to plants to meet SBO / Appendix R requirements and incorporate over 30 years worth of improvements.

4) The maintenance of the ESPS diesel generators is through the contract OEM, which will maintain the equipment to the factory specifications.

5) The ESPS diesel generators are designed for emergency use vice rail or marine diesel engines which are adopted for emergency use.

RAI Aggregate Update Analysis Regulatory Guide 1.174, Revision 2, provides quantitative guidelines on CDF and LERF and identifies acceptable changes to these frequencies that result from proposed changes to the plants licensing basis and describes a general framework to determine the acceptability of risk-informed changes. Regulatory Guide 1.177, Revision 1, provides risk acceptance guidelines on ICCDP and ICLERP and identifies acceptable changes to these probabilities that result from proposed changes to permanent changes to the licensees TSs. The NRC staff review of the information in the LAR, as supplemented, has identified additional information that is required to fully characterize the risk estimates.

The PRA methods and treatments discussed in the following RAIs may need to be revised to be acceptable by the NRC staff:

y RAI-2.d regarding incorporation of the appropriate and consistent treatment of SSF and ESPS structural failure.

y RAI-3.a regarding modeling the most limiting plant configurations.

y RAI-4.b regarding update of CCFs to account for updated component failure rates.

y RAI-5.b regarding the seismic bounding analysis.

y RAI-7.b regarding modeling the differences between units.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 35 y RAI-9.b regarding incorporation of the Revision 4 internal events PRA model for the underlying model used in the internal flooding and high winds PRA.

y RAI-10.b on providing ICCDP and ICLERP for all hazard groups in accordance with Section 6, Stage D - Assessing Parameter Uncertainty, of NUREG-1855, Revision 1.

y RAI-12 regarding incorporation of the generic industry failure rate of SBO DGs.

In the supplement letter of October 8, 2018 in response to audit Question 14, an aggregate case study was provided that included resolution to audit questions as follows:

y Incorporation of updated NUREG-2169 fire ignition frequencies in the fire PRA (audit Question 04).

y Consistent use of appropriate EDG, SSF, and ESPS failure probabilities across the Catawba hazard PRAs (audit Question 05.a).

y Incorporation of appropriate non-safety equipment failure probabilities for the ESPS DGs in the Catawba PRA models (audit Question 05.b).

The NRC staff notes that no separate sensitivity studies results for each source of uncertainty, such as the ESPS HRA study, were provided in the supplement. In addition, the supplement response did not provide unit and configuration (train) specific results.

Furthermore, the response to audit Question 14.d identifies seven PRA model conservatisms that might be considered if the risk acceptance guidelines of RG 1.174 and 1.177 are exceeded. The NRC staff notes that no bounding quantitative estimates of risk (e.g., CDF, LERF, ICCDP, or ICLERP) were performed for several of these conservatisms.

To fully address the RAIs and the October 8, 2018 supplement aggregate results cited above, provide the following:

a) Provide the results of an aggregate analysis for each unit (including individual results for each hazard group) that reflect the combined impact on the LAR risk results (i.e., change in CDF, change in LERF, ICCDP and ICLERP in accordance with NUREG-1855, Revision 1) of: (1) the PRA updates required in response to the RAIs cited above, and (2) those updates incorporated in the aggregate analysis specified in the October 8, 2018 supplement. Also, provide updated results that reflect the combined updates to the PRA described above for: (1) the separate sensitivity studies discussed in the LAR, as supplemented (e.g., the sensitivity study referred to in LAR Section 6.2.5 and the aggregate sensitivity case in the October 8, 2018 supplement), and (2) the studies that address any identified key sources of uncertainty identified in the NUREG-1855, Revision 1 process.

b) For each RAI listed above, summarize how the issue(s) cited in the RAI were resolved for the PRA or LAR. If the resolution involved an update to the PRA models, then briefly summarize the PRA update. Also, confirm the aggregate analysis in part (a) included the PRA updates from the October 8, 2018 supplement.

c) Provide confirmation that the risk values in part (a) only reflect the modifications

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 36 described in the LAR or in response to audit questions and RAIs. Otherwise, describe any additional changes to the Catawba PRA models in support of the aggregate analysis in part (a) that were not described in the LAR dated May 2, 2017 or in part (b) of this RAI. Provide justification that these additional changes, if any, meet the requirement in RG 1.200 that the PRA results used to support an application must be derived from a baseline PRA model that represents the as-built, as-operated plant to the extent needed to support the application.

d) Confirm that the updated aggregate analysis and sensitivity results still meet the risk acceptance guidelines in RG 1.177, Revision 1, and RG 1.174, Revision 2.

e) If the risk acceptance guidelines are exceeded, then identify which guidelines are exceeded and provide justification that support the conclusions of the LAR in accordance with NUREG-1855, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making, Revision 1. This justification should be of sufficient detail to provide assurance that the risk acceptance guidelines are met for this application and may include, but not be limited to, the following: 1) describing and providing the results of a more detailed, realistic analysis to reduce conservatism and uncertainty; 2) proposing compensatory measures and discuss their quantifiable impact on the risk results; and 3) discussing the conservatisms in the analysis and their quantifiable impact on the risk results.

Duke Energy RAI-13.a Response The most limiting plant and alignment configuration results are presented in the tables below based on the responses to RAIs 3, 9, and 10b.

The differences between Units have been determined and the most limiting result for each case is presented below. For CDF, the overall limiting train and unit is train A on Unit 2. For LERF, the overall limiting train and unit is train A on Unit 1.

The failure rates for the ESPS Diesels are set to the Generic SBO failure rates as provided in RAI 4, for both the aggregate sensitivity and the best estimate cases.

The mean values for the aggregate results of the limiting trains are presented below:

RG 1.177 ICCDP Summary (Mean Aggregate Results Unit 2 A Train limiting)

Hazard 14 Day CT Base Multiplier ICCDP Internal Events 5.41E-06 4.16E-06 14/365 4.77E-08 Internal Flooding 2.03E-05 1.66E-05 14/365 1.42E-07 High Winds 2.07E-05 5.72E-06 14/365 5.73E-07 Fire 2.81E-05 2.27E-05 14/365 2.06E-07 Sum = 9.70E-07

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 37 RG 1.177 ICLERP Summary (Mean Aggregate Results Unit 1 A Train Limiting)

Hazard 14 Day CT Base Multiplier ICLERP Internal Events 3.17E-07 2.16E-07 14/365 3.90E-09 Internal Flooding 2.63E-07 4.46E-08 14/365 8.39E-09 High Winds 1.95E-06 7.46E-07 14/365 4.62E-08 Fire 2.01E-06 1.54E-06 14/365 1.77E-08 Sum = 7.62E-08 The overall CDF and LERF impact of the CT and addition of the ESPS system still represents a risk decrease. (The values presented include the conservatism and changes required for the aggregate risk calculation.)

351 Day ICCDP Risk Contribution Summary (Mean Aggregate Results Unit 2 A Train limiting)

Hazard ESPS credit Base Multiplier ICCDP Internal Events 3.54E-06 4.16E-06 351/365 -6.00E-07 Internal Flooding 1.66E-05 1.66E-05 351/365 0.00E+00 High Winds 2.48E-06 5.72E-06 351/365 -3.12E-06 Fire 2.23E-05 2.27E-05 351/365 -4.14E-07 Sum = -4.14E-06 351 Day ICLERP Risk Contribution Summary (Mean Aggregate Results Unit 1 A Train Limiting)

Hazard ESPS credit Base Multiplier ICLERP Internal Events 1.43E-07 2.16E-07 351/365 -7.00E-08 Internal Flooding 4.46E-08 4.46E-08 351/365 0.00E+00 High Winds 1.62E-07 7.46E-07 351/365 -5.62E-07 Fire 1.50E-06 1.54E-06 351/365 -4.52E-08 Sum = -6.77E-07 The total risk results assuming one 14-day CT entry and ESPS nominal availability for the remainder of the year are shown below:

'CDF For Entire Change (Mean Aggregate Results Unit 2 A Train limiting)

Hazard 14-day CT 351 Day 'CDF Internal Events 4.77E-08 -6.00E-07 -5.52E-07 Internal Flooding 1.42E-07 0.00E+00 1.42E-07 High Winds 5.73E-07 -3.12E-06 -2.55E-06 Fire 2.06E-07 -4.14E-07 -2.07E-07 Sum = -3.17E-06



'LERF For Entire Change (Mean Aggregate Results Unit 1 A Train limiting)

Hazard 14-day CT 351 Day 'LERF Internal Events 3.90E-09 -7.00E-08 -6.61E-08 Internal Flooding 8.39E-09 0.00E+00 8.39E-09 High Winds 4.62E-08 -5.62E-07 -5.15E-07 Fire 1.77E-08 -4.52E-08 -2.75E-08 Sum = -6.01E-07

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 38 The limiting alignments of point estimates from RAI 3 are presented below. For CDF, the overall limiting train and unit is train A on Unit 2. For LERF, the overall limiting train and unit is train A on Unit 1.

RG 1.177 ICCDP Summary (Best Estimate Unit 2 A Train limiting)

Hazard 14 Day CT Base Multiplier ICCDP Internal Events 5.20E-06 3.95E-06 14/365 4.79E-08 Internal Flooding 2.03E-05 1.66E-05 14/365 1.42E-07 High Winds 2.02E-05 5.60E-06 14/365 5.60E-07 Fire 2.85E-05 2.27E-05 14/365 2.22E-07 Sum = 9.72E-07 RG 1.177 ICLERP Summary (Best Estimate Unit 1 A Train limiting)

Hazard 14 Day CT Base Multiplier ICLERP Internal Events 2.95E-07 2.03E-07 14/365 3.53E-09 Internal Flooding 2.99E-07 4.46E-08 14/365 9.76E-09 High Winds 1.88E-06 7.18E-07 14/365 4.46E-08 Fire 2.05E-06 1.54E-06 14/365 1.96E-08 Sum = 7.74E-08 The overall CDF and LERF impact of the AOT and addition of the ESPS system represents a risk decrease, similar to the aggregate sensitivity.

351 Day ICCDP Risk Contribution Summary (Best Estimate Unit 2 A Train limiting)

Hazard ESPS credit Base Multiplier ICCDP Internal Events 3.27E-06 3.95E-06 351/365 -6.54E-07 Internal Flooding 1.66E-05 1.66E-05 351/365 0.00E+00 High Winds 2.40E-06 5.60E-06 351/365 -3.08E-06 Fire 2.24E-05 2.27E-05 351/365 -2.88E-07 Sum = -4.02E-06 351 Day ICLERP Risk Contribution Summary (Best Estimate Unit 1 A Train limiting)

Hazard ESPS credit Base Multiplier ICLERP Internal Events 1.36E-07 2.03E-07 351/365 -6.44E-08 Internal Flooding 4.46E-08 4.46E-08 351/365 0.00E+00 High Winds 1.54E-07 7.18E-07 351/365 -5.42E-07 Fire 1.50E-06 1.54E-06 351/365 -3.85E-08 Sum = -6.45E-07 The total risk results assuming one 14-day CT entry and ESPS nominal availability for the remainder of the year are shown below:

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 39

'CDF For Entire Change (Best Estimate Unit 2 A Train limiting)

Hazard 14-day CT 351 Day 'CDF Internal Events 4.79E-08 -6.54E-07 -6.06E-07 Internal Flooding 1.42E-07 0.00E+00 1.42E-07 High Winds 5.60E-07 -3.08E-06 -2.52E-06 Fire 2.22E-07 -2.88E-07 -6.60E-08 Sum = -3.05E-06

'LERF For Entire Change (Best Estimate Unit 1 A Train limiting)

Hazard 14-day CT 351 Day 'LERF Internal Events 3.53E-09 -6.44E-08 -6.09E-08 Internal Flooding 9.76E-09 0.00E+00 9.76E-09 High Winds 4.46E-08 -5.42E-07 -4.98E-07 Fire 1.96E-08 -3.85E-08 -1.89E-08 Sum = -5.68E-07 A bounding seismic ICCDP estimate for the 14-day CT is 1.87E-7. The two methodologies presented in RAI 5 align with this bounding seismic ICCDP estimate. The overall change of including ESPS is a risk improvement, even when the bounding seismic estimate is considered. The bounding seismic ICLERP estimate for the 14-day CT is 2.60E-8. These bounding seismic ICCDP and ICLERP estimates, as provided in the October 8, 2018 supplement, are not based on a Reg. Guide 1.200 model.

Duke Energy RAI-13.b Response

• RAI-2.d regarding incorporation of the appropriate and consistent treatment of SSF and ESPS structural failure.

The appropriate and consistent treatment of SSF and ESPS structural failures is included in response to RAI 2.d.

• RAI-3.a regarding the incorporation of the most limiting plant configurations.

The most limiting plant and alignment configuration results are included in responses to RAIs 3 and 13.

• RAI-4.b regarding update of CCFs to account for updated component failure rates.

Appropriate CCFs were used for all hazards per response to RAI-4.b.

• RAI-5.b regarding the seismic bounding analysis.

The seismic analysis as described in RAI-5 was used.

y RAI-7.b regarding modeling the differences between units.

The limiting Unit (from fire) was presented in the analysis. Response to RAI-7.b demonstrated no significant differences between the Units for Internal Events, High Winds, and Internal Flooding.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 40 y RAI-9.b regarding incorporation of the Revision 4 internal events PRA model for the underlying model used in the internal flooding and high winds PRA.

The incorporation of the Revision 4 internal events PRA model for the internal flooding and high winds PRA is presented in RAI 9.

y RAI-10.b on providing ICCDP and ICLERP for all hazard groups in accordance with Section 6, Stage D - Assessing Parameter Uncertainty, of NUREG-1855, Revision 1.

The aleatory (parameter) uncertainty values are presented in the response to RAI 10.b.

The modifications that were made for the previous October 8, 2018 supplement RAI-4 response continue to be included unless modified by the RAIs discussed in this (RAI 13.b) response.

y RAI-12 regarding incorporation of the generic industry failure rate of SBO DGs.

Generic industry SBO DG failure rates were incorporated per RAI-12.

Duke Energy RAI-13.c Response The model used for the ESPS RAI 3 response development included minor refinements to ensure that the ESPS system was properly credited for mitigation capabilities. The refinements include:

1) Deletion of power breakers that are already defined to be within the EDG component boundary

2) Added prohibited maintenance combinations to flag file based on commitments and technical specifications

3) Modeling changes to credit hot leg creep rupture phenomena to depressurize the vessel prior to failure in the LERF model

4) Used calc. type 3 (Mission Time, No Repair) for EDG Fail to Run failure modes

5) Refined operator action for ESPS alignment based on developed procedures and subsequently developed HRA dependency analysis for HFE combinations

6) The SSF was credited in F2 straight-line wind and tornado high wind-initiated events after the first hour of the initiating event, as discussed in RAI 1 Duke Energy RAI-13.d Response The overall application associated with adding ESPS to the Catawba Nuclear Station is a risk improvement.

The aggregate sensitivity and best estimate cases continue to meet the acceptance guidelines in RG 1.177, Revision 1, and RG 1.174, Revision 2.

Additionally, the presented analysis contains the following conservatisms:

x Flex equipment is not credited, but would be available and deployed if needed.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 41 y The reliability data collected by the PRA as part of the data update process shows the FLEX equipment is reliable.

• FLEX Generator - Fail to Start as 3E-03 per demand and Fail to Run as 1E-3 per hour

• FLEX Pumps - Fail to Start as 5E-03 per demand and Fail to Run as 2E-3 per hour y The FLEX equipment has been deployed for various reasons, so the operator actions and procedures have been exercised, increasing the reliability of these actions.

x The high winds model does not credit the recovery of offsite power. For F1 and F2 straight-line winds, the recovery of offsite power is credible. In addition, the EDG extended AOT requires a check of weather and a Safety Related EDG will not be removed from service if the weather forecast has potential for severity. Thus, the High Wind contribution is significantly overstated.

Duke Energy RAI-13.e Response The risk acceptance guidelines continue to be met. No additional actions required.

RAI Catawba Facts and Observations (F&O) Closure Process Section 2 of RG 1.200, Revision 2, states for the applicable technical requirements, the staff anticipates that current good practice, i.e., Capability Category II of the ASME/ANS standard, is the level of detail that is adequate for the majority of the applications, and, [a]

peer review is needed to determine if the intent of the requirements in the standard is met.

The NRC staff observed (ADAMS Accession No. ML18117A187) that independent reviews were performed to close F&Os for the Catawba LERF and internal flooding PRAs.

However, it is not clear whether these independent reviews were performed consistent with the process documented in Appendix X to Nuclear Energy Institute (NEI) 05-04, NEI 07-12, and NEI 12-13, Close-out of Facts and Observations, as accepted, with conditions, by NRC in the letter from Joseph Giitter and Mary Jane Ross-Lee (NRC) to Greg Krueger (NEI) dated May 3, 2017 (ADAMS Accession Number ML17079A427).

The October 8, 2018 supplement, in response to audit Question 16, provided details related to the above closure reviews and the approved NEI Appendix X (Independent Assessment Team option). The response indicated that the same individuals who performed the 2015 Independent Review were contracted again in 2017 to perform a second independent review, including an assessment of whether or not each F&O resolution constitutes an upgrade to the PRA. To confirm that the independent reviews were performed consistent with NEI Appendix X, clarify whether any F&O resolutions were determined to be a PRA upgrade(s) and, if so, whether a focused-scope peer review was performed concurrently with these independent reviews. If so, provide the following:

a) Summary of the scope of the peer review, and

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 42 b) Detailed descriptions of any new F&Os generated from the peer review and the associated dispositions for the application.

Duke Energy RAI-14 Response a) All internal flood and LERF F&O resolutions were determined to be updates/maintenance, rather than upgrades. As such, no focused-scope peer review is required.

b) Because no focused-scope peer review is required, no new F&Os were generated for the internal flood and LERF PRA models.

RAI-15

In Attachment 1, Catawba Technical Specification Marked Up Pages, of the supplemental LAR dated October 8, 2018, the licensee proposed to add a new LCO 3.8.1.d that would require the operability of opposite unit DG(s) and a new Required Actions (RAs), and to revise and renumber existing RAs for TS 3.8.1 Condition B (one LCO 3.8.1.b DG inoperable).

New LCO 3.8.1.d would state The DG(s) from the opposite unit necessary to supply power to the NSWS, CRAVS, CRACWS and ABFVES.

New RA B.1 would state Verify both DGs on the opposite unit operable, with a CT of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.

Revised and renumbered RA B.4.2 would state: Perform SR 3.8.1.2 for operable DG(s).

The NRC staff notes the following discrepancies:

It appears that the proposed RA B.1 is similar to the revised and renumbered RA B.4.2 with respect to the operability of the opposite unit DGs because the existing Surveillance Requirements (SR) 3.8.1.2 in RA B.4.2 verifies the operability of the remaining DGs including the opposite unit DG (s) by verifying that each DG can start from standby conditions and achieve steady state voltage and frequency within the required ranges.

It does not appear that a discussion of the basis for the 1-hour and 12-hour CTs for the new RA B.1 was provided.

a. Provide a discussion that explains how the operability of the LCO 3.8.1.d DGs will be verified by RA B.1.

b. Provide a discussion that describes the basis and derivation of the CTs (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter) for RA B.1.

Duke Energy RAI-15 Response

a. The proposed RA B.1 is for an administrative verification of OPERABILITY. There is reasonable expectation of OPERABILITY for the LCO 3.8.1.d DG(s) when licensed operators verify that all the following conditions exist:

y The DG Surveillance Requirements are met.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 43 y The normal operator rounds for the DG are up-to-date and have been performed satisfactorily.

y The DG and its support systems have not been logged as inoperable or non-functional.

y There are no items being tracked via the Adverse Condition Monitoring and Contingency Planning sheet that calls into question OPERABILITY of the DG.

y There are no in-progress OPERABILITY determinations or functionality assessments for the DG and its support systems.

b. The initial CT of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> for RA B.1 is based on the recognized importance of ensuring the LCO 3.8.1.d DG(s) is OPERABLE to power one train of shared systems during the time the LCO 3.8.1.b DG is inoperable. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> allows sufficient time to perform this verification if the inoperability of the LCO 3.8.1.b DG was unplanned.

The proposed 12-hour Completion Time (CT) of RA B.1 was chosen due to the Catawba operator shifts being 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In addition, BTP 8-8 states:

The availability of AAC or supplemental power source shall be checked every 8-12 hours (once per shift).

The proposed change includes provisions for Catawba to ensure availability of ESPS once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Thus, once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for the RA B.1 CT allows Catawba to verify operability of LCO 3.8.1.d DG(s) and availability of ESPS at the same time intervals.

The Calvert Cliffs precedent that was closely followed uses 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. Catawba has proposed a more conservative CT (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> vice 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />).

RAI-16

In Attachment 1 of the October 8, 2018 letter, the licensee proposed to revise TS 3.8.1 Condition B (i.e., one LCO 3.8.1.b DG inoperable) to extend the CT for restoring the DG to operable status beyond the existing 72-hour and up to 14 days, provided the ESPS is available.

The licensee proposed 4 CTs to restore the inoperable LCO 3.8.1.b DG to operable status (RA B.6).

RA B.6 would state: Restore DG to operable status, with the following CTs:

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of unavailable ESPS when in extended Completion Time AND 14 days AND 17 days from discovery of failure to meet LCO 3.8.1.a or LCO 3.8.1.b RA B.5 would state: Ensure availability of Emergency Supplemental Power Source (ESPS), with the following CT:

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 44 Prior to entering the extended CT of Action B.6 AND Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.

In Section 2.1, Catawba Evaluation of the TS 3.8.1 Change Request, of the October 8, 2018 letter, the licensee states:

The CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS of new RA B.6 (formerly RA B.4) is based on the existing CT for an inoperable DG. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> CT of new RA B.6 is based on Branch Technical Position 8-8 and indicates that if the ESPS unavailability occurs sometime after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of continuous DG inoperability (i.e., after entering the extended CT for an inoperable DG), then the remaining time to restore the ESPS to available status or restore the DG to operable status is limited to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

In the Catawba current TS, the existing 72-hour CT is based on RG 1.93, which states, in part:

If the available onsite ac power sources are one less than the LCO, power operation may continue for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, provided that the redundant diesel generator is assessed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to be free from common-cause failure or is verified to be operable in accordance with plant-specific technical specifications.

The guidance in RG 1.93 relates to redundant power sources. The allowed power operation period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> starts from the time the available onsite ac power sources (i.e., DGs) are found to be one less than the LCO (i.e., one DG is inoperable).

The NRC staff has identified the following discrepancies:

The proposed CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS of new RA B.6 (inoperable DG) would begin on discovery that both an inoperable DG exists and the ESPS is unavailable, as stated in the LAR, whereas the existing 72-hour CT for an inoperable DG begins when the DG is inoperable based on RG 1.93. Thus, the proposed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS would not be based on the existing CT for an inoperable DG, as stated in the LAR.

The proposed CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS would allow the DG to remain inoperable beyond the existing 72-hour CT without an available ESPS or a supplemental AC power source since the proposed 72-hour CT would begin on discovery that both an inoperable DG exists and the ESPS is unavailable.

The proposed CTs for RA B.6 do not identify a non-extended CT or a time for entering the extended CT that would indicate when the RA B.5 (ensure the availability of ESPS) would be performed within the first CT (i.e., prior to entering the extended CT of RA B.6) and when the proposed 24-hour CT (i.e., 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of unavailable ESPS when in extended CT) of RA B.6 would be applicable.

a. Provide a discussion that explains how the proposed CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS of RA B.6 is based on the existing 72-hour CT for an inoperable

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 45 DG that begins when the DG is found inoperable. If the proposed CT is not based on the existing 72-hour CT, provide a revised CT for RA B.6 so that the CT for restoring the inoperable LCO 3.8.1.b DG to operable status would not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from the time the LCO 3.8.1.b DG was found inoperable (i.e., Condition B) or provide a justification for the new CT.

b. Provide a discussion that explains how entry into the extended CT is identified in the proposed CTs for RA B.6 to allow the implementation of RA B.5 prior to entering the extended CT of RA B.6, and to apply the 24-hour CT of RA B.6.

Duke Energy RAI-16 Response Duke Energy proposes the following changes in red (also shown in Attachment 2):

The CT for proposed RA B.5 is revised as follows:

B.5 Evaluate availability of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Emergency Supplemental Prior to entering the Power Source (ESPS). extended Completion Time of ACTION B.6 AND Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter The existing RA B.4 is renamed B.6. The associated CT is revised to state:

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS**

AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of &RQGLWLRQ%HQWU\ 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> concurrent with unavailability of ESPS unavailable ESPS when in extended Completion Time AND 14 days AND 17 days from discovery of failure to meet LCO 3.8.1.a or LCO 3.8.1.b Since proposed RA B.5 specifies to evaluate, discovering the ESPS unavailable does not result in the RA being not met. On discovery of an unavailable ESPS, the CT for RA B.6 starts the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and/or 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> clock. This change is consistent with Brunswick Steam Electric Plant TS 3.8.1 precedent (ADAMS Accession No. ML13329A362).

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 46 If the ESPS is or becomes unavailable with an inoperable LCO 3.8.1.b DG, then action is required to restore the ESPS to available status or to restore the DG to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS. However, if the ESPS unavailability occurs at or sometime after 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of continuous LCO 3.8.1.b DG inoperability, then the remaining time to restore the ESPS to available status or to restore the DG to OPERABLE status is limited to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Times allow for an exception to the normal time zero for beginning the allowed outage time clock. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. ESPS is unavailable.

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

D$QLQRSHUDEOH'*H[LVWVIRUKRXUVDQG

b. ESPS is unavailable.

RAI-17

BTP 8-8 recommends that the time to make the supplemental or alternate AC (AAC) power source available, including cross-connection, should be approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to enable restoration of battery chargers and control reactor coolant system inventory. Also, plants must assess their ability to cope with loss of all AC power (i.e., SBO) for one hour independent of an AAC power source to support the one-hour time for making this supplemental power source available In the May 2, 2017 letter, the licensee states:

The SDGs will become one of the options in ECA-0.0 for restoring AC power. Observations of the operators on the plant simulator show that it takes about 20 minutes for the operators to get to the point in the procedure to attempt to restore power from any source. If the ESPS is the chosen source of power, operators would be dispatched to place it in service. []

The ESPS will constitute two supplemental DGs capable of powering any one of the 4160 V essential buses on either unit during an SBO within one hour from the time that the emergency procedures direct their use as the emergency power source. []

CNS [Catawba Nuclear Station] [] take[s] credit for its respective SSF [Standby Shutdown Facility] diesel generator as the AAC Source for coping with a SBO within 10 minutes of a SBO event.

CNSs [] coping times during a SBO are not affected by the proposed change to extend the CT for one inoperable DG. The coping times are calculated based on guidance provided in NUMARC 87-00 [Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors, Revision 1, Nuclear Management and Resources Council, Inc., August 1991].

BTP 8-8 states that plants must assess the capability to cope with the loss of all AC power for one hour independent of a supplemental AC power source. CNS [] ha[s] [] performed calculations for SBO coping that demonstrate each [unit] is a 4-hour coping plant.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 47 The NRC staff has identified the following discrepancies:

It appears that the ESPS would be connected to supply power to the 4160 volts (V) bus within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 20 minutes from the start of the SBO event since the ESPS would power the 4160 V bus within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from the time that the emergency procedures direct their use as the emergency power source, and it would take 20 minutes to get to that time. This indicates that the time to make the ESPS available to supply power to the station would not be within the approximately one hour timeframe described in the LAR.

The 4-hour SBO coping duration for Catawba is the time the plant can cope with an SBO event using the SSF. The availability of the SSF within 10 minutes of an SBO event indicates that Catawba can cope with the SBO without (or independent of) the SSF for 10 minutes and not for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, as stated in the BTP 8-8.

a- Clarify the estimated time it would take to connect the ESPS power source (i.e., the two supplemental DGs) to the stations safety bus from the start of an SBO event.

b- Provide a discussion that summarizes the calculations or analysis performed in accordance with NUMARC 87-00 guidance to assess the Catawba ability to cope with the loss of all AC power (i.e., SBO) for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or the period of time clarified in above question until the ESPS is connected to the shutdown buses, as stated in BTP 8-8. Also, include in the discussion a summary of the coping analysis conclusions.

Duke Energy RAI-17 Response

a. Since the original application for ESPS was submitted, CNS has completed sufficient installation of ESPS equipment and facility tie-ins. A time line was obtained and validated by licensed and auxiliary operators, for implementation of the emergency procedure for station blackout (SBO) and aligning ESPS to power an essential bus on the SBO unit. A team consisting of a licensed operator and Auxiliary operators simulated the operator dispatch times and the time it takes to energize the 4160V safety bus once local actions are completed. Multiple local validations, for both units, were obtained and documented. A breaker at the training center was used to obtain the length of time it takes to rack in and rack out the breakers. The longest and most conservative local times were used.

The validated total time from the loss of power to the 4160V safety bussed to re-energize a 4160V safety bus through a unit transformer using ESPS was 50 minutes. A more conservative time limit, taking into account the CNS standard GHVLUHGPDUJLQIRUWLPHFULWLFDODFWLRQVRIDQGWKH-minute case, is 60 minutes from time power is lost to the 4160V busses. Duke Energy meets the approximated one hour requirement and the operators will be held accountable to a 60-minute timeframe to account for desired margin.

b. Duke Energy has an approved calculation for CNS that assesses the ability to cope with an extended loss of all AC power referred to as an Extended Loss of AC Power (ELAP) event which is equivalent to Station Block Out (SBO) without taking any credit for the Standby Shutdown Facility (SSF). The calculation demonstrates the amount of time available for recovery actions to take place to restore onsite power before the core uncovers and fuel damage becomes imminent. The calculation included a reactor coolant pump seal leak, turbine-driven (T/D) AFW (CA) pump is available, and assumed that the SSF is unavailable. The calculation concludes that

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 48 the length of time between SBO event initiation and the onset of significant core uncover is greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Therefore, CNS clearly demonstrates the ability to cope with the SBO event for the 60-minute duration cited in response to part a.

above until the ESPS is connected to a 4160V safety bus.

RAI-18

In Attachment 1 of the October 8, 2018 letter, the licensee proposed a new Condition C that would state Required Action and associated Completion Time of Required Action B.1 not met.

Two alternate RA C.1.1 and RA C.1.2 are proposed for Condition C.

RA C.1.1 would state Restore both DGs on the opposite unit to operable status, with a CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

RA C.1.2 would state Restore the LCO 3.8.1.b DG to operable status, with a CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

The proposed RA B.1 would state: Verify LCO 3.8.1.d DG(s) operable. The CT for RA B.1 would state: 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.

In Section 2.1 of the October 8 letter, the licensee stated that the 72-hour CT for the new RA C.1.1 and RA C.1.2 is in accordance with Regulatory Guide (RG) 1.93, which indicates operation may continue in this condition for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

RG 1.93 states, in part:

If the available onsite ac electric power sources are two less than the LCO, power operation may continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

If the available onsite ac power sources are one less than the LCO, power operation may continue for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, provided that the redundant diesel generator is assessed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to be free from common-cause failure or is verified to be operable in accordance with plant-specific technical specifications The guidance in RG 1.93 relates to redundant power sources. The power operation period of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is applicable to two inoperable AC power sources, and the period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> starts from the time the available onsite ac power sources (i.e., DGs) are one less than the LCO (i.e., one DG is inoperable). Also, the power operation period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed per RG 1.93 starts from the time the available onsite ac power sources (i.e., DGs) are one less than the LCO (i.e., one DG is inoperable).

The NRC staff has identified the following discrepancies:

If two redundant DGs in the opposite unit would be inoperable in Condition C, the CT for restoring both inoperable DGs to operable status (RA C.1.1) would be 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, as recommended in RG 1.93. However, the proposed CT for RA C.1.1 is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and is not consistent with RG 1.93.

The proposed RA C.1.2 and associated CT would allow the LCO 3.8.1.b DG to remain inoperable for a time longer than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> because the proposed 72-hour CT for C.1.2 would start from the time of discovery of the inoperability of both DGs on the opposite unit by RA B.1 (i.e., 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter), and not from the time of discovery of inoperable

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 49 LCO 3.8.1.b DG, as described in RG 1.93. This indicates that the proposed 72-hour CT for RA C.1.2 would not be in accordance with RG 1.93, as stated in the LAR.

a. Provide a discussion of how the proposed 72-hour CT for new RA C.1.1 (restore both DGs on the opposite unit to operable status) is consistent with RG 1.93 with respect to two inoperable DGs.

b. Provide a discussion that explains how the 72-hour CT for RA C.1.2 (restore LCO 3.8.1.b DG to operable status) is in accordance with RG 1.93 so that the CT for RA C.1.2 would not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from the time the LCO 3.8.1.b DG is found inoperable.

Duke Energy RAI-18 Response

a. The proposed Condition C in the October 8, 2018 submittal is deleted from the CNS TS 3.8.1.

b. RA C.1.2 was not in accordance with RG 1.93 as cited in the October 8, 2018 submittal because the CT could exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Therefore, the proposed Condition C in the October 8, 2018 submittal is deleted from the CNS TS 3.8.1. Condition D from the October 8, 2018 submittal is now renamed to Condition C (Shown in Attachment 2).

RAI-19

In Attachment 1 of the October 8, 2018 letter, the licensee proposed a new Condition D that would state: one LCO 3.8.1.c offsite circuit is inoperable. The RAs would be modified by a Note.

The proposed Note would state: Enter applicable Conditions and Required Actions of LCO 3.8.9, Distribution Systems - Operating, when Condition D is entered with no AC power source to a train.

RA D.3 would state: Declare NSWS, CRAVS, CRACWS and ABFVES supported by the inoperable offsite circuit inoperable, with a CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

In Section 2.1 of the October 8, 2018 letter, the licensee stated that the Note would allow new Condition D to provide requirements for the loss of a LCO 3.8.1.c offsite circuit and LCO 3.8.1.d DG without regard to whether a train is de-energized.

10 CFR 50.36(c)(2) states:

When an LCO of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

The staff notes that the new Condition D is not related to the loss of an LCO 3.8.1.d DG, and as such, would not provide the requirements for the loss of an LCO 3.8.1.d DG. In addition, the proposed RAs would not require the restoration of the LCO 3.8.1.c offsite circuit to operable status or other remedial actions to meet the TS LCO 3.8.1.c, as required by 10 CFR 50.36(c)(2).

1- Clarify how the proposed Note for the new Condition D would allow the new Condition D to provide requirements for the loss of a LCO 3.8.1.d DG, as stated above.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 50 2- Provide a discussion that explains how the proposed RAs for the new Condition D would allow the TS LCO 3.8.1 to be met, as required by 10 CFR 50.36(c)(2).

Duke Energy RAI-19 Response

a. (Note: Condition D in Attachment 2 is marked up and now renamed to Condition C)

The Note above the Required Actions associated with Condition C is consistent with the Calvert Cliffs precedent. Condition C addresses the inoperability of one LCO 3.8.1.c qualified offsite circuit between the offsite transmission network and the opposite units Onsite Essential Auxiliary Power System. If Condition C is entered for one LCO 3.8.1.c offsite circuit inoperable concurrently with one LCO 3.8.1.d DG inoperable associated with the same train of shared systems and the NSWS pump(s), then the NOTE requires the licensed operator to enter all applicable Conditions and Required Actions of TS 3.8.9 "Distribution Systems - Operating".

Specifically, in the case where an inoperable LCO 3.8.1.c qualified offsite circuit and an inoperable LCO 3.8.1.d DG both support the same train of shared systems and NSWS pump(s), TS 3.8.9 Condition A must be entered because there is no longer assurance that the train of "Distribution Systems - Operating" can be energized to the proper voltage. Both units would enter TS 3.8.9 Condition A in this instance since there is no power source to a train of shared systems and NSWS pump(s)

(refer to CNS LCO 3.0.9). This action is consistent with CNS current application of TS 3.8.9 with the concurrent inoperability of a DG and inoperability of a qualified offsite circuit impacting the same train of Distribution Systems - Operating aligned to power shared systems and NSWS pump(s).

b. Proposed RA D.3 (renamed to C.3) from the October 2018 submittal would not allow LCO 3.8.1 to be met. In order to comply with 10 CFR 50.36(c)(2), RA C.3 has been revised as follows:

CD.3 Declare NSWS, CRAVS, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> CRACWS or ABFVES supported by the inoperable offsite circuit inoperable. Restore LCO 3.8.1.c offsite circuit to OPERABLE status.

Consistent with the time provided in ACTION A, operation may continue in Condition C for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. With one required LCO 3.8.1.c offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System. If the LCO 3.8.1.c required offsite circuit cannot be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, then Condition K (now renamed as Condition I in Attachment 2) must be entered immediately.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 51

RAI-20

In Attachment 1 of the October 8, 2018 letter, the licensee proposed a new Condition E that would apply when one LCO 3.8.1.d DG is inoperable. The RAs for new Condition E would be modified by a Note.

The Note would state: Enter applicable Conditions and Required Actions of LCO 3.8.9, Distribution Systems - Operating, when Condition E is entered with no AC power source to a train.

RA E.1 would state: verify both LCO 3.8.1.b DGs operable, the opposite units DG operable and ESPS available, with a CT of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.

RA E.4.2 would state: Perform SR 3.8.1.2 for operable DG(s).

RA E.5 would state: Declare NSWS, CRAVS, CRACWS and ABFVES supported by the inoperable DG inoperable, with a CT of 14 days.

In Section 2.1 of the October 8, 2018 letter, the licensee states:

[The Note] allow new Condition E to provide requirements for the loss of a LCO 3.8.1.c offsite circuit and LCO 3.8.1.d DG without regard to whether a train is de-energized.

The verification in this RA [E.1] provides assurance that the other three safety-related DGs and the ESPS are capable of supplying the Class 1E AC Electrical Power Distribution System.

The CT of 14 days is justified by new RA E.1 (verify both unit-specific DGs are operable, the other opposite unit DG is operable and the ESPS is available). The 14 day CT is also consistent with the proposed CT in ACTION B when ESPS is available.

10 CFR 50.36(c)(2) states:

When an LCO of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

The NRC staff has identified the following discrepancies:

The new Condition E is not related to the loss of an LCO 3.8.1.c offsite circuit, and as such, it appears to not provide the requirements for the loss of an LCO 3.8.1.c offsite circuit.

It does not appear that a discussion of the basis is for the 1-hour and 12-hour CTs for the new RA E.1 was provided.

It does not appear that a CT for the proposed RA E.5 (declare NSWS, CRAVS, CRACWS and ABFVES supported by the inoperable DG inoperable) when the ESPS is unavailable consistent with the proposed CT for Condition B (i.e., one LCO 3.8.1.b DG inoperable) was provided.

The proposed RAs for the new Condition E appear to not require the restoration of the LCO 3.8.1.d DG to operable status to meet the TS LCO 3.8.1, as required by 10 CFR 50.36(c)(2).

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 52

a. Clarify how the proposed Note for the new Condition E would allow the new Condition E to provide requirements for the loss of a LCO 3.8.1.c offsite circuit, as stated above.

b. Provide a discussion that explains the basis for the proposed CTs (i.e., 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter) for new RA E.1.

c. Provide a discussion about the RAs and associated CTs for Condition E for the case when the ESPS is unavailable.

d. Provide a discussion that explains how the proposed RAs for the new Condition E would allow the TS LCO 3.8.1 to be met, as required by 10 CFR 50.36(c)(2).

Duke Energy RAI-20 Response (Note: Condition E in Attachment 2 is marked up and renamed to Condition D)

a. The Note above the Required Actions associated with Condition D is consistent with the Calvert Cliffs precedent. Condition D addresses the inoperability of one LCO 3.8.1.d DG aligned to the opposite unit Onsite Essential Auxiliary Power System that is supplying power to a train of shared systems and to the respective NSWS pump(s). If Condition D is entered for one LCO 3.8.1.d DG concurrently with one LCO 3.8.1.c offsite circuit inoperable associated with the same train of shared systems and NSWS pump(s), then the Note requires the licensed operator to enter all applicable Conditions and Required Actions of TS 3.8.9 "Distribution Systems - Operating". Specifically, in the case where an inoperable LCO 3.8.1.d DG and an inoperable LCO 3.8.1.c qualified offsite circuit both support the same train of shared systems and NSWS pump(s), TS 3.8.9 Condition A must be entered because there is no longer assurance that the train of "Distribution Systems - Operating" can be energized to the proper voltage. Both units would enter TS 3.8.9 Condition A in this instance since there is no power source to a train of shared systems and NSWS pump(s)

(refer to CNS LCO 3.0.9). This action is consistent with CNS current application of TS 3.8.9 with the concurrent inoperability of a DG and inoperability of a qualified offsite circuit impacting the same train of "Distribution Systems - Operating" aligned to power shared systems and NSWS pump(s).

b. The initial CT of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> for RA D.1 is based on the recognized importance of ensuring the LCO 3.8.1.b DGs are OPERABLE when a LCO 3.8.1.d DG is inoperable. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> allows sufficient time to perform this verification if the inoperability of the LCO 3.8.1.d DG was unplanned.

The proposed 12-hour Completion Time (CT) of RA D.1 was chosen due to the Catawba operator shifts being 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In addition, BTP 8-8 states:

The availability of AAC or supplemental power source shall be checked every 8-12 hours (once per shift).

The proposed change includes provisions for Catawba to ensure availability of ESPS once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Thus, once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for the RA D.1 CT allows Catawba to verify operability of the unit DGs.

The Calvert Cliffs precedent that was closely followed uses 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. Catawba has proposed a more conservative CT (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> vice 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />).

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 53

c. RA D.1 is revised to Verify both LCO 3.8.1.b DGs OPERABLE and the opposite units DG OPERABLE. The availability of ESPS has been removed, as shown in Attachment 2.

d. Proposed RA E.5 from the October 8, 2018 submittal would not allow LCO 3.8.1 to be met. In order to comply with 10 CFR 50.36(c)(2), the RA E.5 from the October 8, 2018 submittal has been replaced with RA D.5 and RA D.6 as follows:

E.5 Declare NSWS, CRAVS, 14 days CRACWS or ABFVES supported by the inoperable DG inoperable.

D.5 Evaluate availability of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> ESPS.

AND Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter AND D.6 Restore LCO 3.8.1.d DG to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from OPERABLE status. discovery of unavailable ESPS AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of

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48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> concurrent with unavailability of ESPS AND 14 days AND 17 days from discovery of failure to meet LCO 3.8.1.c or LCO 3.8.1.d In Condition D, the remaining OPERABLE DGs, unavailable ESPS, and offsite power circuits are adequate to supply electrical power to the Class 1E Distribution System. The 14 day Completion Time takes into account the capacity and capability of the remaining AC

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 54 sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

If the ESPS is or becomes unavailable with an inoperable LCO 3.8.1.d DG, then action is required to restore the ESPS to available status or to restore the DG to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of unavailable ESPS. However, if the ESPS unavailability occurs at or sometime after 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of continuous LCO 3.8.1.d DG inoperability, then the remaining time to restore the ESPS to available status or to restore the DG to OPERABLE status is limited to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Times allow for an exception to the normal time zero for beginning the allowed outage time clock. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. ESPS is unavailable.

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

D$QLQRSHUDEOH'*H[LVWVIRU 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />; and

b. ESPS is unavailable.

Therefore, when one LCO 3.8.1.d DG is inoperable due to either preplanned maintenance (preventive or corrective) or unplanned corrective maintenance work, the Completion Time can be extended from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days if ESPS is verified available for backup operation.

RAI-21

In Attachment 1 of the October 8, 2018 letter, the licensee proposed a new Condition F that would be applicable when the RA E.1 (verify both LCO 3.8.1.b DGs operable, the opposite units DG operable and ESPS available) and associated CT (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter) are not met. Three alternate RAs F1.1, F.1.2, and F.1.3 are proposed for Condition F.

RA F.1.1 would state Restore both LCO 3.8.1.b DGs to operable status and ESPS to available status, within the CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

RA F.1.2 would state Restore both LCO 3.8.1.d DG to operable status within the CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

RA F.1.3 would state Declare NSWS, CRAVS, CRACWS and ABFVES supported by the inoperable DG inoperable.

In Section 2.1 of the October 8, 2018 letter, the licensee states:

The 72-hour CT for RA F.1.1 and RA F.1.2 is consistent with Regulatory Guide 1.93 [].

New RA F.1.3 reflects that if the opposite unit DG that is necessary to supply power to the NSWS, CRA VS, CRACWS and ABFVES cannot be restored to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, then the NSWS, CRAVS, CRACWS and ABFVES components associated with the inoperable DG must be declared inoperable.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 55 RG 1.93 states, in part:

If the available onsite ac electric power sources are two less than the LCO, power operation may continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

If the available onsite ac power sources are one less than the LCO, power operation may continue for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, provided that the redundant diesel generator is assessed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to be free from common-cause failure or is verified to be operable in accordance with plant-specific technical specifications The guidance in RG 1.93 relates to redundant power sources. The power operation period of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is applicable to two inoperable AC power sources, and the period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> starts from the time the available onsite ac power sources (i.e., DGs) are one less than the LCO (i.e., one DG is inoperable).

The NRC staff has identified the following discrepancies:

If two redundant LCO 3.8.1.b DGs and two redundant DGs in the opposite unit would be inoperable in Condition F, the CT for restoring either both inoperable LCO 3.8.1.b DGs or one DG in the opposite unit to operable status (RA F.1.1) would be 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, as recommended in RG 1.93. However, the proposed CT for RA F.1.1 is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and is not consistent with RG 1.93.

The proposed RA F.1.2 and associated CT (i.e., restore the LCO 3.8.1.d DG to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) would allow the Catawba power operation to exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if the LCO 3.8.1.d DG would become inoperable (proposed Condition E) because the proposed 72-hour for F.1.2 would start from the time the RA E.1 (i.e., verify both LCO 3.8.1.b DGs operable, the opposite units DG and ESPS available) and associated CT (i.e., 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> [from discovery of LCO 3.8.1.d DG inoperability] and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter) are not met, and not from the time the LCO 3.8.1.d DG is found inoperable. It would appear that the proposed 72-hour CT for RA C.1.2 would not be in accordance with RG 1.93.

Two DGs (i.e., both LCO 3.8.1.b or one LCO 3.8.1.b DG that provides power to the shared systems and one LCO 3.8.1.d DG are inoperable) would be inoperable in Condition F. Thus, the CT for restoring the LCO 3.8.1.d DG to operable status (RA F.1.2) would be 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, as recommended in RG 1.93. However, the proposed CT for RA F.1.2 is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and is not consistent with RG 1.93.

It does not appear that a discussion of the specific inoperable DG which supported shared systems would be declared inoperable in RA F.1.3 was provided, as more than one DG would be inoperable in Condition F.

a. Provide a discussion of how the proposed 72-hour CT for new RA F.1.1 (restore both LCO 3.8.1.b DGs to operable status and ESPS to available status) is consistent with RG 1.93 with respect to two inoperable LCO 3.8.1.b DGs.

b. Provide a discussion that explains how the proposed 72-hour CT for new RA F.1.2 is consistent with RG 1.93 so that the CT for RA F.1.2 would not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from the time the LCO 3.8.1.d DG is found inoperable.

c. Provide a discussion of how the proposed 72-hour CT for new RA F.1.2 (restore LCO 3.8.1.d DG to operable status) is consistent with RG 1.93 with respect to two

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 56 inoperable DGs (i.e., one LCO 3.8.1.b DG and one LCO 3.8.1.d DG) that supply power to the shared systems.

d. Provide a discussion that explains the specific inoperable DG of which the supported shared systems would be declared inoperable in RA F.1.3. Also, provide a discussion that clarifies whether the trains of shared systems supported by all inoperable DGs would be declared inoperable, as more than one DG (i.e., LCO 3.8.1.d DG and LCO 3.8.1.b DG(s)) would be inoperable in Condition F; and provide the basis for the CTs for declaring the train of shared systems supported by each inoperable DG inoperable.

Duke Energy RAI-21 Response If one LCO 3.8.1.b DG is inoperable when in Condition D, then Condition B will be entered for that LCO 3.8.1.b DG. If both LCO 3.8.1.b DGs are inoperable when in Condition D, then the proposed Condition G will be entered. Thus, the proposed Condition F in the October 8, 2018 submittal is deleted from TS 3.8.1. Condition H from the October 8, 2018 submittal is now renamed to Condition F (Shown in Attachment 2).

RAI-22

In Attachment 1 of the October 8, 2018 letter, the proposed Condition K would apply when the RA and associated CT of Condition A, C, F, G, H, I, or J are not met; or RA and associated CT of RA B.2, B.3, B.4.1, B.4.2, or B.6 are not met; or RA and associated CT of RA E.2, E.3, E.4.1, E.4.2, or E.5 are not met.

The proposed RA K.1 would state Be in Mode 3 within a CT of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The proposed RA K.2 would state Be in Mode 5 within a CT of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

The staff has identified the following discrepancies:

The proposed Condition K does not address the case when an RA and associated CT of the proposed new Condition D are not met. In addition, the proposed TS changes does not discuss actions when the RA D.1, D.2, or D.3 and associated CT of Condition D are not met.

In case the proposed LCO 3.8.1.d would require only one opposite unit DG to supply power to the shared systems, Catawba would enter Condition K to bring the unit to Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> if the DG that would not be required by LCO 3.8.1.d would not be restored to operable status (RA C.1.1 and RA F.1.1) within the proposed 72-hour CT. This would subject the unit to transients associated with the orderly shutdown.

In case the ESPS would not be restored to available status as required by the proposed new RA F.1.1 within the proposed 72-hour CT, Catawba would enter Condition K to bring the unit to Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This would subject the unit to transients associated with the orderly shutdown.

a. Provide a discussion of the applicable actions when the RAs and associated CTs of the new Condition D are not met.

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 57

b. In case the proposed LCO 3.8.1.d would require only one opposite unit DG to be operable, provide a discussion that explains the reasons for entering Condition K to shut down the unit and, as a result, subject the unit to transients associated with the shutdown when the opposite unit DG that would not be required by LCO 3.8.1.d could not be restored to operable status by the proposed RA C.1.1 and RA F.1.1.

c. Provide a discussion that explains the reasons for entering Condition K to shut down the unit and, as a result, subject the unit to transients associated with the shutdown when the ESPS cannot be restored to available status, as required by the proposed RA F.1.1.

Duke Energy RAI-22 Response Condition K is renamed to Condition I and revised as follows (Shown in Attachment 2):

I.K. Required Action and IK.1 Be in MODE 3.

Associated Completion Time of Condition A, C, E, AND F, G, or H not met.

IK.2 Be in MODE 5.

OR Required Action and Associated Completion Time of Required Action B.2, B.3, B.4.1, B.4.2, or B.6 not met.

OR Required Action and Associated Completion Time of Required Action D.2, D.3, D.4.1, D.4.2, or D.6 not met.

Condition C (previously named Condition D) has been added to Condition I (previously named Condition K). Condition F from the October 8, 2018 submittal has been deleted.

RAI-23

In Attachment 1 of the October 8, 2018 letter, the proposed note to the SRs section would state:

Note: SR 3.8.1.1 through SR 3.8.1.20 are only applicable to LCO 3.8.1.a and LCO 3.8.1.b AC sources. SR 3.8.1.21 is only applicable to LCO 3.8.1.c and LCO 3.8.1.d AC sources.

The proposed SR 3.8.1.21 would state:

SR 3.8.1.21 For the LCO 3.8.1.c and LCO 3.8.1.d AC electrical sources. SR 3.8.1.1,

U.S. Nuclear Regulatory Commission RA-19-0004, Attachment 1 Page 58 SR 3.8.1.2, SR 3.8.1.4, SR 3.8.1.5, and SR 3.8.1.6 are required to be met.

The NRC staff notes that a discussion about the reasons for excluding SR 3.8.1.3, SR 3.8.1.7, SR 3.8.1.8, SR 3.8.1.9, SR 3.8.1.10, SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.14, SR 3.8.1.15, SR 3.8.1.16, SR 3.8.1.17, SR 3.8.1.18, SR 3.8.1.19, and SR 3.8.1.20 from the SRs required for the LCO 3.8.1.c and LCO 3.8.1.d AC electrical power sources was not provided.

Provide a discussion that explains why the performance of SR 3.8.1.3 and SR 3.8.1.7 through SR 3.8.1.20 are not required for the LCO 3.8.1.c and LCO 3.8.1.d AC power sources.

Duke Energy RAI-23 Response The proposed Note and SR 3.8.1.21 have been deleted, as shown in Attachment 2. All SRs associated with TS 3.8.1 are applicable to LCO 3.8.1.c and LCO 3.8.1.d AC power sources for the proposed change.

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Amendment Implementation Number Additional Condition Date 250 Upon implementation of the Amendment Within 60 days of adopting TSTF-448, Rev. 3, the determination date of amendment of CRE unfiltered air inleakage as required by SR 3.7.10.4, in accordance with Technical Specification 5.5.16.c(i), the assessment of CRE habitability as required by Technical Specification 5.5.16.c.(ii), and the measurement of CRE pressure as required by Technical Specification 5.5.16.d, shall be met.

Following implementation:

{a) The first performance of SR 3.7.10.4 in accordance with Technical Specification 5.5.16.c(i) shall be within the specified Frequency of 6 years, plus the 18 month allowance of SR 3.0.2, as measured from November 12, 2002, the date of the most recent successful tracer gas test, as stated in the December 9, 2003 letter response to Generic Letter (GL) 2003-01, or within the next 18 months if the time period since the most recent successful tracer gas test is greater than 6 years.

(b) The first performance of the periodic assessment of CRE habitability, Technical Specification 5.5.16.c(ii), shall be within 3 years, plus the 9 month allowance of SR 3.0.2 as measured from November 12, 2002, the date of the most recent successful tracer gas test, as stated in the December 9, 2003 letter response to GL 2003-01, or within the next 9 months if the time period since the most recent successful tracer gas test is greater than 3 years.

(c) The first performance of the periodic measurement of CRE pressure, Technical Specification 5.5.16.d, shall be within 18 months, plus the 138 days allowed by SR 3.0.2, as measured from September 1, 2007, the date of the most recent successful pressure measurement test, or within 138 days if not oerformed previously.

Insert 1 Renewed License No. NPF-35 Amendment No. 2-59 Insert 1 Amendment Additional Implementation Number Conditions Date NNN During the extended DG Completion Times Upon implementation of authorized by Amendment No. [NNN], the turbine- Amendment No. [NNN].

driven auxiliary feed water pump will not be removed from service for elective maintenance activities. The turbine-driven auxiliary feed water pump will be controlled as protected equipment during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safe Shutdown Facility, Nuclear Service Water System, motor driven auxiliary feed water pumps, and the switchyard will also be controlled as protected equipment.

NNN The risk estimates associated with the 14-day Upon implementation of EDG Completion Time LAR (including those results Amendment No. [NNN].

of associated sensitivity studies) will be updated, as necessary to incorporate the as-built, as-operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance guidelines of RG 1.174 and RG 1.177.

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Amendment Implementation Number Additional Condition Date 245 Upon implementation of the Amendment Within 60 days of adopting TSTF-448, Rev. 3, the determination date of amendment of CRE unfiltered air inleakage as required by SR 3.7.10.4, in accordance with Technical Specification 5.5.16.c(i), the assessment of CRE habitability as required by Technical Specification 5.5.16.c.(ii), and the measurement of CRE pressure as required by Technical Specification 5.5.16.d, shall be met.

Following implementation:

(a) The first performance of SR 3.7.10.4 in accordance with Technical Specification 5.5.16.c(i) shall be within the specified Frequency of 6 years, plus the 18 month allowance of SR 3.0.2, as measured from November 12, 2002, the date of the most recent successful tracer gas test, as stated in the December 9, 2003 letter response to Generic Letter (GL) 2003-01, or within the next 18 months if the time period since the most recent successful tracer gas test is greater than 6 years.

(b) The first performance of the periodic assessment of CRE habitability, Technical Specification 5.5.16.c(ii), shall be within 3 years, plus the 9 month allowance of SR 3.0.2 as measured from November 12, 2002, the date of the most recent successful tracer gas test, as stated in the December 9, 2003 letter response to GL 2003-01, or within the next 9 months if the time period since the most recent successful tracer gas test is greater than 3 years .

(c) The first performance of the periodic measurement of CRE pressure, Technical Specification 5.5.16.d, shall be within 18 months, plus the 138 days allowed by SR 3.0.2, as measured from September 1, 2007, the date of the most recent successful pressure measurement test, or within 138 days if not performed previously.

Insert 2 Renewed License No. NPF-52 Amendment No. zil:5 Insert 2 Amendment Additional Implementation Number Conditions Date SSS During the extended DG Completion Times Upon implementation of authorized by Amendment No. [SSS], the turbine- Amendment No. [SSS].

driven auxiliary feed water pump will not be removed from service for elective maintenance activities. The turbine-driven auxiliary feed water pump will be controlled as protected equipment during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safe Shutdown Facility, Nuclear Service Water System, motor driven auxiliary feed water pumps, and the switchyard will also be controlled as protected equipment.

SSS The risk estimates associated with the 14-day Upon implementation of EDG Completion Time LAR (including those results Amendment No. [SSS].

of associated sensitivity studies) will be updated, as necessary to incorporate the as-built, as-operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance guidelines of RG 1.174 and RG 1.177.

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Spectral frequency, Figure 1 -McGuire Nuclear Station SSE v. GMRS The model used to perform the IPEEE analysis was re-run with one EOG taken out of service.

The resulting CDF was 1.?E-05 / yr., resulting in a delta of 6E-06 /yr.Thus, for the 14-day AOT, the incremental CCDP is, 6E-06 x (14 / 365) = 2.3E-07 The IPEEE also included various HFEs, the most predominant of which was the response to the relay chatter events discussed above. Also, as mentioned previously, the IPEEE analysis does not include the implementation of FLEX equipment. Given the risk significance of LOOP events, these would be the dominant accident sequences where FLEX would be required.

Thus, not including FLEX introduces conservatism in the IPEEE results and further demonstrates the IPEEE SCDF can be considered a reasonable bounding value.

The IPEEE also included various HFEs, the most predominant of which was the failure of an operator to align the 'A' train of NSW to the NSW Pond (the assured source of AFW). This was assigned a conservative screening value.

Other HFEs used in the IPEEE include responses to relay chatter events and failing to go to an auxiliary control panel following a loss of the main control boards. Even though high screening values were used for this assessment, all of accident sequences combined involving these other HFEs made only a small contribution to SCDF (~ 1%).

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Hazard Initiator Lower Upper Representative Description Interval Bin Acc Acc Acceleration Frequency

%G01 Seismic Initiating Event (0.1g to < 0.15g) 0.1 0.15 0.12 1.58E-04

%G02 Seismic Initiating Event (0.15g to < 0.3g) 0.15 0.3 0.21 1.11E-04

%G03 Seismic Initiating Event (0.3g to < 0.5g) 0.3 0.5 0.39 2.80E-05

%G04 Seismic Initiating Event (0.5g to < 0.75g) 0.5 0.75 0.61 9.59E-06

%G05 Seismic Initiating Event (0.75g to < 1g) 0.75 1 0.87 3.49E-06

%G06 Seismic Initiating Event (1g to < 1.5g) 1 1.5 1.22 2.46E-06

%G07 Seismic Initiating Event (1.5g to < 10g) 1.5 10 3.87 1.46E-06

Base Case Non-EDG LOOP EDG - Train EDG - Train Seismic Initiator Seismic CCDP SCDF Fragility A B HEP Bin Failure 4.881E-02 1.770E-02 1.770E-02 1.000E+00 1.000E+00 1.53E-05 2.42E-09 %G01 2.608E-01 1.770E-02 1.770E-02 1.000E+00 1.000E+00 8.17E-05 9.07E-09 %G02 6.816E-01 1.770E-02 1.770E-02 1.000E+00 1.000E+00 2.14E-04 5.98E-09 %G03 9.065E-01 1.770E-02 1.770E-02 1.000E+00 1.000E+00 2.84E-04 2.72E-09 %G04 9.750E-01 1.770E-02 1.770E-02 1.000E+00 1.000E+00 3.05E-04 1.07E-09 %G05 9.954E-01 1.770E-02 1.770E-02 1.000E+00 1.000E+00 3.12E-04 7.67E-10 %G06 1.000E+00 1.770E-02 1.770E-02 1.000E+00 1.000E+00 3.13E-04 4.57E-10 %G07 Total SCDF = 2.25E-08 6HLVPLF&')FRQWULEXWLRQIRUHDFKKD]DUGELQLVFRPSXWHGE\

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Hazard Initiator Lower Upper Representative Description Interval Bin Acc Acc Acceleration Frequency

%G01 Seismic Initiating Event (0.1g to < 0.15g) 0.1 0.15 0.12 1.58E-04

%G02 Seismic Initiating Event (0.15g to < 0.3g) 0.15 0.3 0.21 1.11E-04

%G03 Seismic Initiating Event (0.3g to < 0.5g) 0.3 0.5 0.39 2.80E-05

%G04 Seismic Initiating Event (0.5g to < 0.75g) 0.5 0.75 0.61 9.59E-06

%G05 Seismic Initiating Event (0.75g to < 1g) 0.75 1 0.87 3.49E-06

%G06 Seismic Initiating Event (1g to < 1.5g) 1 1.5 1.22 2.46E-06

%G07 Seismic Initiating Event (1.5g to < 10g) 1.5 10 3.87 1.46E-06

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Insert 1 Amendment Additional Implementation Number Conditions Date YYY During the extended DG Completion Times Upon implementation of authorized by Amendment No. [YYY], the turbine- Amendment No. [YYY].

driven auxiliary feed water pump will not be removed from service for elective maintenance activities. The turbine-driven auxiliary feed water pump will be controlled as protected equipment during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safe Shutdown Facility, Nuclear Service Water System, Chemical and Volume Control System, Diesel Air Compressors, Residual Heat Removal System, motor driven auxiliary feed water pumps, and the switchyard will also be controlled as protected equipment.

YYY The risk estimates associated with the 14-day Upon implementation of EDG Completion Time LAR (including those results Amendment No. [YYY].

of associated sensitivity studies) will be updated, as necessary to incorporate the as-built, as-operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance guidelines of RG 1.174 and RG 1.177.





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Insert 2 Amendment Additional Implementation Number Conditions Date ZZZ During the extended DG Completion Times Upon implementation of authorized by Amendment No. [ZZZ], the turbine- Amendment No. [ZZZ].

driven auxiliary feed water pump will not be removed from service for elective maintenance activities during the extended CT. The turbine-driven auxiliary feed water pump will be controlled as protected equipment during the extended DG CT. The Non-CT EDGs, ESPS, Component Cooling System, Safe Shutdown Facility, Nuclear Service Water System, Chemical and Volume Control System, Diesel Air Compressors, Residual Heat Removal System, motor driven auxiliary feed water pumps, and the switchyard will also be controlled as protected equipment.

ZZZ The risk estimates associated with the 14-day Upon implementation of EDG Completion Time LAR (including those results Amendment No. [ZZZ].

of associated sensitivity studies) will be updated, as necessary to incorporate the as-built, as-operated ESPS modification. Duke Energy will confirm that any updated risk estimates continue to meet the risk acceptance guidelines of RG 1.174 and RG 1.177.

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