RA-23-0279, Supplement to Application to Adopt Risk-Informed Completion Times TSTF-505, Revision 2 and Application to Adopt 10 CFR 50.69, Risk-informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power

Supplement to Application to Adopt Risk-Informed Completion Times TSTF-505, Revision 2 and Application to Adopt 10 CFR 50.69, Risk-informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power

ML23306A032
Person / Time
Site:	Mcguire, McGuire
Issue date:	11/02/2023
From:	Pigott E Duke Energy Carolinas
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
RA-23-0279
Download: ML23306A032 (1)

Text

Edward R. Pigott Site Vice President McGuire Nuclear Station Duke Energy MG01VP l 12700 Hagers Ferry Road Huntersville, NC 28078 o: 980.875.4111 Edward.Pigott@duke-energy.com November 2, 2023 Serial: RA-23-0279 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 McGuire Nuclear Station, Units 1 and 2 Docket Nos. 50-369 and 50-370, Renewed License Nos. NPF-9 and NPF-17

Subject:

Supplement to Application to Adopt Risk-Informed Completion Times TSTF-505, Revision 2 and Application to Adopt 10 CFR 50.69, Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors

References:

1. Letter from E. R. Pigott (Duke Energy Carolinas, LLC) to U.S. Nuclear Regulatory Commission, License Amendment Request to Revise Technical Specifications to Adopt Risk-Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, dated February 16, 2023 (ADAMS Accession No. ML23047A465).

2. Letter from E. R. Pigott (Duke Energy Carolinas, LLC) to U.S. Nuclear Regulatory Commission, Application to Adopt 10 CFR 50.69, Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors, dated February 17, 2023 (ADAMS Accession No. ML23048A022).

3. Letter from J. Klos (U.S. Nuclear Regulatory Commission) to R. Treadway (Duke Energy Carolinas, LLC), McGuire Nuclear Station, Units 1 and 2 - Regulatory Audit in Support of License Amendment Requests to Adopt TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, and 10 CFR 50.69, Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors, (EPID L-2023-LLA-0021 and EPID L-2023-LLA-0022), dated April 18, 2023 (ADAMS Accession No. ML23094A183).

Ladies and Gentlemen:

By letters dated February 16, 2023 (Reference 1) and February 17, 2023 (Reference 2), Duke Energy Carolinas, LLC (Duke Energy) submitted two separate license amendment requests (LAR) for McGuire Nuclear Station (MNS), Units 1 and 2. The proposed amendment in Reference 1 would modify Technical Specifications (TS) requirements to permit the use of Risk-Informed Completion Times in accordance with TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF [Risk-Informed TSTF] Initiative 4b (ADAMS Accession No. ML18183A493). The proposed amendment in Reference 2 would add a License Condition

U.S. Nuclear Regulatory Commission RA-23-0279 Page2 to allow for the implementation of the provisions of 10 CFR 50.69, "Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors."

Duke Energy participated in a regulatory audit (Reference 3) to respond to questions posed by the Nuclear Regulatory Commission (NRG) staff regarding the Reference 1 and 2 applications.

After audit discussions that occurred on October 3-4, 2023, the NRG staff identified the subset of audit questions requiring additional information on the docket and provided a list of those questions to Duke Energy via e-mail.

The enclosure provides Duke Energy's responses to the subset of regulatory audit questions as a supplement to References 1 and 2. Attachment 1 provides a revised markup of select TS pages from Reference 1. The revised markup of these select TS pages supersedes that which was provided in Reference 1 and all other TS markups remain unchanged. Attachment 2 provides select revised enclosures from the Reference 1 LAR. The revised information is denoted with revision bars in the right-hand column of the impacted page and supersedes that which was provided in Reference 1. Attachment 3 provides a revised enclosure and revised select attachments from the Reference 2 LAR. The revised information is denoted with revision bars in the right-hand column of the impacted page and supersedes that which was provided in Reference 2. Attachment 4 provides a markup of the Renewed Facility Operating Licenses for Units 1 and 2 to reflect the proposed 10 CFR 50.69 license condition and the addition of a license condition for the proposed amendment to adopt TSTF-505, Revision 2.

Duke Energy has reviewed the information supporting the No Significant Hazards Consideration Determination and the Environmental Consideration that was previously provided to the NRG in References 1 and 2. The additional information provided in this LAR supplement does not impact the conclusion that the proposed license amendments in both References 1 and 2 do not involve a significant hazards consideration. Additionally, the information does not impact the conclusion that there is no need for an environmental assessment to be prepared in support of the proposed amendments.

There are no regulatory commitments made in this submittal.

Please refer any questions regarding this submittal to Mr. Ryan Treadway, Director- Nuclear Fleet Licensing, at (980) 373-5873.

I declare, under penalty of perjury, that the foregoing is true and correct. Executed on November 2, 2023.

Edward R. Pigott Site Vice President McGuire Nuclear Station

U.S. Nuclear Regulatory Commission RA-23-0279 Page 3

Enclosure:

Supplemental Information Attachments:

1. Revised Mark-Up of Select Technical Specification Pages

2. Revised Enclosures for License Amendment Request to Adopt TSTF-505, Revision 2

3. Revised Enclosure and Attachments for License Amendment Request to Adopt 10 CFR 50.69

4. Mark-Up of McGuire, Units 1 and 2 Renewed Facility Operating Licenses cc:

L. Dudes, Regional Administrator, Region II J. Klos, NRR Project Manager C. Safouri, NRC Senior Resident Inspector

U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 ENCLOSURE SUPPLEMENTAL INFORMATION

U.S. Nuclear Regulatory Commission Page 2 RA-23-0279 NOTE: The U.S. Nuclear Regulatory Commission (NRC) staffs audit questions (including the introductory discussion) are in italics throughout this enclosure to distinguish from the Duke Energy Carolinas, LLC (Duke Energy) responses.

NRC Introduction to Audit Questions By letters dated February 16 and February 17, 2023 (Agencywide Documents Access and Management System (ADAMS) Accession Nos. ML23047A465 and ML23048A022, respectively), Duke Energy Carolinas, LLC (Duke Energy, the licensee) submitted two license amendment requests (LARs) for McGuire Nuclear Station, Units 1 and 2 (McGuire). The proposed amendments would modify Renewed License Nos. NPF-9 and NPF-17 and the Technical Specifications (TSs) to adopt Technical Specifications Task Force (TSTF) Traveler 505 (TSTF-505), Provide Risk-informed Extended Completion Times, RITSTF Initiative 4b, and to allow for the implementation of the provisions of Title 10 of the Code of Federal Regulations (10 CFR), Part 50.69, Risk-informed categorization and treatment of structures, systems and components [SSCs] for nuclear power reactors. On April 18, 2023, the U.S.

Nuclear Regulatory Commission (NRC) staff issued an audit plan (ADAMS Accession No. ML23094A183) that conveyed intent to conduct a regulatory audit to support its review of the subject license amendments. Based on the commonalities between the LARs and subsequent overlap in technical content and review personnel, the NRC staff is conducting a combined audit that addresses both LARs.

Regulatory Guide 1.174, Revision 3, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis (RG 1.174, ADAMS Accession No. ML17317A256), states that the scope, level of detail, and technical adequacy of the probabilistic risk assessment (PRA) are to be commensurate with the application for which it is intended and the role the PRA results play in the integrated decision process. The NRCs safety evaluation (SE) for Nuclear Energy Institute (NEI) Topical Report NEI 06-09, Revision 0-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, Industry Guidance Document, dated November 6, 2006 (NEI 06-09-A, ADAMS Package Accession No. ML122860402), and the NRCs Final Safety Evaluation for NEI 06-09-A, dated May 17, 2007 (ADAMS Accession No. ML071200238), state that the PRA models should conform to the guidance in Regulatory Guide 1.200, Revision 1, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities. The version applicable to this LAR is Revision 2 (RG 1.200, ADAMS Accession No. ML090410014), which states that the quality of the PRA must be compatible with the safety implications of the proposed change and the role the PRA plays in justifying the change.

The NRC staff has determined that additional information is needed to support its review as shown in the following audit questions. The questions are ordered by number and identified by technical review branch/area and associated LAR (i.e., RICT for the TSTF-505 LAR and 50.69 for the LAR re: risk-informed categorization and treatment of SSCs).

QUESTION-01 (APLC - RICT) - Seismic Risk Contribution Analysis Section 2.3.1, Item 7, of NEI 06-09-A (ADAMS Accession No. ML12286A322), states that the impact of other external events risk shall be addressed in the [Risk Managed Technical Specifications] RMTS program, and explains that one method to do this is by performing a reasonable bounding analysis and applying it along with the internal events risk contribution in calculating the configuration risk and the associated [Risk-Informed Completion Time]

U.S. Nuclear Regulatory Commission Page 3 RA-23-0279 RICT. The NRC staffs safety evaluation for NEI 06-09-A (ADAMS Accession No. ML071200238) states that [w]here PRA models are not available, conservative or bounding analyses may be performed to quantify the risk impact and support the calculation of the RICT.

In Section 3 of Enclosure 4 to the LAR, the licensee provided its seismic risk contribution analysis. The NRC staff reviewed the seismic analysis provided in the LAR and some items are not clear to the NRC staff.

The licensee assumed that seismic risk is evaluated based on peak ground acceleration (PGA),

because it is a common ground motion metric used for nuclear power plants. The statement may be true for most plant sites. However, it appears that the McGuire PGA seismic hazard curve is not conservative and bounding. Based on NEI 06-09-A, if PRA models are not available, conservative or bounding analyses may be performed to quantify the risk impact and support the calculation of the RICT.

a) Evaluate the impacts due to using PGA seismic risk only as compared with other frequencies of seismic hazards and justify the assumption.

The licensee provided the HCLPF [high confidence of low probability of failure] of 0.17g and a composite uncertainty factor (c) of 0.4 as plant level fragility. GI-199 shows c=0.74 and C50=0.45, which can be converted to a HCLPF of 0.08g. The licensee stated that c=0.74 is not used because it could not be traced to McGuires IPEEE information. The NRC staff also noted that an EPRI document dated March 11, 2014 (ADAMS Accession No. ML14080A589) has the same HCLPF and c values as GI-199 for McGuire.

b) Provide detailed justification for the HCLPF and c values used in the LAR compared to those in GI-199.

The licensee proposed a new non-standard convolution method to calculate the seismic core damage frequency (SCDF) by using the fragility complement (i.e., 1.0 minus fragility failure probability) for each hazard interval where the plant level fragility failure probability exceeds 0.5 to calculate the difference between the equipment out of service and baseline case. However, the licensee did not demonstrate that the approach is conservative, consistent with the guidance in NEI 06-09-A and the staffs SE on NEI 06-09-A. The NRC staffs independent evaluation demonstrates that the proposed approach appears to be non-conservative compared to the standard convolution method.

c) Provide a detailed discussion to demonstrate that the proposed non-standard approach for the SCDF penalty is conservative consistent with the guidance in NEI 06-09-A and the corresponding staff SE.

Similarly, the licensee provided a new non-standard convolution method to calculate the seismic large early release frequency (SLERF), which was based on delta SCDF. The NRC staff is unable to understand why the delta SLERF determination is not based on SCDF. Using delta SCDF to determine delta SLERF, as done in the proposed approach, appears to result in an incorrect delta SLERF calculation.

d) Provide justification for why the proposed method to calculate SLERF using delta SCDF instead of SCDF is acceptable and conservative.

U.S. Nuclear Regulatory Commission Page 4 RA-23-0279 In Enclosure 5 of the LAR, the licensee provided a baseline SCDF of 2.85E-5/yr and SLERF of 2.41E-6/yr. However, the licensee did not discuss how these values are developed, nor provide a reference to support these values.

e) Provide calculations of SCDF and SLERF values shown in Enclosure 5.

In Section 3.6 of Enclosure 4 to the LAR, the licensee calculated the total seismically-induced (unrecoverable) loss of offsite power (LOOP) frequency of 7.3E-5/year, which is about 14% of the total unrecovered LOOP frequency addressed in the McGuire internal events PRA. This value is about one order of magnitude higher than that from a typical operating plant.

f) Justify why a separate consideration and inclusion (i.e., in addition to the unrecoverable LOOP frequency in the internal events PRA) of the comparatively high seismically-induced LOOP frequency is unnecessary for the proposed RICT calculations. If such justification cannot be provided, include the seismically-induced LOOP frequency in the RICT calculations and provide the updated calculations.

g) If any values were changed due to questions a) through f), provide the updated values for seismic risk used in the RICT program.

Duke Energy Response to QUESTION-01 (APLC - RICT), Part a In response to this audit question, Duke Energy has used the conventional seismic penalty method with consideration of the spectral hazard frequency (four hertz (Hz) frequencies investigated) influence on the calculated seismic core damage frequency (SCDF) and seismic large early release frequency (SLERF) penalty estimates. This method consists of averaging the SCDF or SLERF estimates computed by convolving the Plant Level Fragility (PLF) curve with the hazard curves for four separate frequencies: 1 Hz, 5 Hz, 10 Hz and PGA (defined as 100Hz) and is often referred to as the simple average method in past fleet risk studies (e.g., GI-199 risk assessment). The following SCDF PLF parameters are used for the SCDF RICT penalty:

x 0.17g PGA HCLPF x c = 0.4 The above McGuire Nuclear Station (MNS) PLF parameter values are justified in Duke Energys response to Part b of this NRC audit question. The obtained PGA-based PLF is converted to PLFs of other frequencies (e.g., 1 Hz, 5 Hz, and 10 Hz) using spectral ratios.

Table 1 compares two types of frequency ratios: IHS (IPEEE Hazard Spectra) spectral ratios associated with the MNS IPEEE seismic analysis and GMRS (Ground Motion Response Spectra) spectral ratios from the MNS near-term task force (NTTF) 2.1 seismic hazard submittal. The IHS spectral ratios are directly from Table C-2 of the NRC GI-199 risk assessment report. As the GMRS is more recent information than the IHS, Duke Energy has used the GMRS spectral ratios for the sake of calculating the SCDF and SLERF RICT penalty values.

U.S. Nuclear Regulatory Commission Page 5 RA-23-0279 Table 1: Spectral Frequency Ratios, IHS vs. GMRS

 10Hz 5Hz 1Hz

IHS 1.88 2.35 1.19

GMRS 1.59 0.98 0.25

The conventional calculation of the SLERF RICT penalty value is performed by convolving the plant seismic core damage penalty with a containment functional seismic fragility based on the seismic fragility of the Solid State Protection System (SSPS) cabinet. The basis for the selection of this containment fragility is provided below:

x The MNS IPEEE seismic analysis did not identify any containment vulnerabilities. The IPEEE seismic analyses evaluated containment performance from structural, isolation and bypass perspectives. The structure was found to be seismically rugged.

x The seismic PRA portion of the MNS IPEEE calculated very high seismic capacities for containment related structures. Some examples are shown below (all in units of PGA):

o Steel containment vessel: Am =9.0g (buckling) o Internal Structures: Am =3.1g (crane wall) o Reactor Building: Am =2.8g (shear wall) o Containment penetrations: Am >2.5g The MNS IPEEE SPRA concluded that seismic failure of the MNS containment related structures are not credible events.

x The SSPS cabinet fragility is a plant-specific MNS calculation and is used as a surrogate to represent the containment isolation function fragility.

Given the above, the use of the MNS SSPS cabinet seismic fragility is assessed as reasonable for use in the MNS SLERF penalty calculation. The associated fragility parameter values are as follows (Table 3-1 of the MNS IPEEE Submittal Report):

x Am = 1.54g PGA or HCLPF = 0.50g PGA x R = 0.29 and U = 0.39 or c = 0.486 Table 2 presents the resulting SCDF and SLERF penalty estimates. As raised by this audit question, the PGA results are not necessarily bounding for both the SCDF and SLERF penalty estimates. In fact, Table 2 shows that the 1Hz and PGA results are the bounding cases for the SCDF and SLERF penalty estimates, respectively. The obtained simple average SCDF and SLERF penalty estimates for use with MNS RICT calculations are 3.57E-05/yr and 2.29E-06/yr, respectively.

Based on the above results, Duke Energy has decided to use the simple average results of the SCDF or SLERF penalty estimates computed by convolving the PLF curve with the hazard curves for four separate frequencies: 1Hz, 5Hz, 10Hz and PGA. The corresponding revision will be made to the seismic penalty report.

U.S. Nuclear Regulatory Commission Page 6 RA-23-0279 Table 2: MNS Seismic Penalty SCDF and SLERF Estimates PLFParametersforCDF PLFParametersforLERF

Case Penalty

HCLPF Penalty

Am(g) c Am(g) c HCLPF(g) SLERF

(g) SCDF(/yr)

(/yr)

PGA 0.43 0.40 0.17 3.04E-05 1.54 0.486 0.50 2.56E-06

10Hz 0.69 0.40 0.27 3.16E-05 2.45 0.486 0.79 2.52E-06

5Hz 0.42 0.40 0.17 3.57E-05 1.51 0.486 0.49 2.29E-06

1Hz 0.11 0.40 0.04 4.53E-05 0.39 0.486 0.12 1.81E-06 Avg.of4curves(PGA,10,5and1Hz) 3.57E-05 Avg.of4curves(PGA,10,5and 2.29E-06 1Hz)

Duke Energy Response to QUESTION-01 (APLC - RICT), Part b As described above in response to Part a of this NRC audit question, Duke Energy performed the seismic probabilistic risk assessment (SPRA) for the seismic portion of the MNS IPEEE (the MNS IPEEE submittal to the NRC was based on the SPRA approach). The calculated SCDF was 1.12E-05 using the EPRI PGA hazard curve. As a HCLPF is defined as the 1% probability of failure on the mean confidence level curve, the IPEEE SPRA-based plant level HCLPF capacity with respect to core damage is computed by identifying the acceleration point along the hazard curve that produces a 1E-2 (i.e., 1%) conditional core damage probability (CCDP).

Using the data in Table 3-4 of the MNS IPEEE submittal and the EPRI seismic hazard curve for MNS, the IPEEE SPRA-based plant level HCLPF is calculated as follows:

1. The MNS IPEEE SPRA mean SCDF based on the EPRI hazard curve for the site is 1.12E-05/yr. The SCDF contribution per each of the modeled nine seismic hazard intervals is provided at the last row of Table 3-4 of the IPEEE submittal.

2. For each seismic hazard interval, an interval-specific Mean Annual Frequency of Exceedance (MAFE) is calculated from the EPRI hazard curve.

3. An interval-specific CCDP (i.e., the plant level fragility, PLF, failure probability) is computed by dividing the hazard interval SCDF by the corresponding hazard interval MAFE.

4. The plant level HCLPF for SCDF is then determined by the g PGA acceleration point along the hazard curve that produces a CCDP of 1E-2.

The obtained results are presented in Table 3.

U.S. Nuclear Regulatory Commission Page 7 RA-23-0279 Table 3: IPEEE SPRA Bin SCDF Contribution, Associated MAFE and CCDP Acc.Bin IPEEESPRASCDF Mean EPRI

CCDP/PLF

(g,PGA) Contribution(%) SCDF MAFE

0.075 1.21 1.35E07 6.40E04 0.000

0.153 6.93 7.75E07 1.79E04 0.004

0.255 9.3 1.04E06 3.30E05 0.032

0.357 11.79 1.32E06 1.03E05 0.128

0.459 15.15 1.69E06 4.30E06 0.394

0.561 13.74 1.54E06 1.60E06 0.960

0.663 13.71 1.53E06 8.00E07 1.000

0.765 14.58 1.63E06 5.00E07 1.000

0.918 13.58 1.52E06 5.00E07 1.000

The above CCDP vs ground acceleration are nine points of a continuous PLF curve. Next, the plant level HCLPF for SCDF is identified by the acceleration associated with a CCDP of 0.01.

As the 0.01 CCDP exists between two hazard intervals, the PLF HCLPF capacity is calculated by the following linear interpolation between the second and third hazard intervals:

x HCLPF Capacity = 0.153 + (0.01-0.004) * (0.255-0.153)/(0.032-0.004) = 0.17g PGA The corresponding median capacity is computed as follows:

x Median Capacity, Am = 0.459 + (0.5-0.394) * (0.561-0.459)/(0.960-0.394) = 0.48g PGA This value is slightly larger than 0.45g reported from GI-199. Note that the MNS IPEEE SPRA-based HCLPF capacity is slightly larger than the safe shutdown earthquake (SSE), but much less than the MNS seismic margin assessment (SMA)-based HCLPF. The lower HCLPF produced by the MNS IPEEE SPRA is due to the conservatism in the approaches used in the calculation of SSC seismic fragilities in the MNS IPEEE SPRA. The main intent of the IPEEE SPRA was to identify major seismic vulnerabilities from seismic induced severe accident sequences, not necessarily to develop a realistic estimate of the plants seismic capacity. The SPRA modeling approach used in the MNS IPEEE does not meet the requirements of Part 5 of the ASME/ANS Standard and as such does not reflect the current standards of a PRA model with respect to quantitative accuracy and reasonableness. A typical modern SPRA model undergoes multiple iterations of fragility refinement in the process to develop an as-built and as-operated model with realistic risk results and insights by eliminating the conservatism in fragility curves. Limited fragility refinement was conducted for the MNS IPEEE SPRA and this is clearly reflected in the obtained plant level HCLPF capacity lower than that produced by the SMA and lower than the expected realistic HCLPF. Using the obtained HCLPF and median capacities, the corresponding composite variability is computed as follows:

x Composite Variability, c = LN(0.17/0.48)x(1/-2.33) = 0.43 It should be noted that this value is much smaller than 0.74 from GI-199. As there is no traceable basis for 0.74, Duke Energy has decided to use the following IHS fragility parameters:

U.S. Nuclear Regulatory Commission Page 8 RA-23-0279 x Am = 0.43g PGA x HCLPF = 0.17g PGA x c = 0.40 Duke Energy Response to QUESTION-01 (APLC - RICT), Part c As discussed above in response to Part a of this NRC audit question, Duke Energy has decided to use the simple average results of the SCDF or SLERF estimates computed by convolving the PLF curve with the hazard curves for four separate frequencies: 1 Hz, 5 Hz, 10 Hz and PGA (defined as 100Hz). The updated SCDF penalty estimate is as follows:

x SCDF Penalty = 3.57E-05/yr The corresponding revision will be made to the MNS seismic penalty report.

Duke Energy Response to QUESTION-01 (APLC - RICT), Part d As discussed above in response to Part a of this NRC audit question, Duke Energy has decided to use the simple average results of the SCDF or SLERF estimates computed by convolving the PLF curve with the hazard curves for four separate frequencies: 1 Hz, 5 Hz, 10 Hz and PGA (defined as 100Hz). The updated SLERF penalty estimate is as follows:

x SLERF Penalty = 2.29E-06/yr The corresponding revision will be made to the MNS seismic penalty report.

Duke Energy Response to QUESTION-01 (APLC - RICT), Part e As described above in the responses to other parts of this NRC audit question, the penalty SCDF and SLERF values have been revised for use in RICT calculations, following the standard penalty approach and using the simple average results of the SCDF or SLERF estimates computed by convolving the PLF curve with the hazard curves for four separate frequencies: 1 Hz, 5 Hz, 10 Hz and PGA (defined as 100Hz). Accordingly, the baseline seismic risk calculations have been updated as well by incorporating the MNS plant availability factor of 0.94 (i.e., fraction of year the plant is at-power) as follows:

x Baseline SCDF = 3.36E-05/yr x Baseline SLERF = 2.16E-06/yr The corresponding revision will be made to the MNS seismic penalty report.

Duke Energy Response to QUESTION-01 (APLC - RICT), Part f The answer to this question exists in the discussions presented in Enclosure 4, Section 3.6 of the MNS LAR to adopt TSTF-505, Revision 2 and summarized by the following sentence at the end of that section:

U.S. Nuclear Regulatory Commission Page 9 RA-23-0279 In addition, as previously stated, the MNS SCDF and SLERF seismic penalty values already address the fraction of seismic-induced LOOP events within (i.e., at or below) the design basis by conservatively including very low magnitude seismic events in the seismic penalty convolution calculations.

Note: Enclosure 4 of the LAR to adopt TSTF-505, Revision 2 is being revised as part of of this supplement. However, the above statement from Section 3.6 remains.

Seismic-induced LOOP is already addressed by the seismic penalty approach in the MNS LAR by incorporation of very small up through very large earthquakes into the calculation of the SCDF and SLERF penalty values. The following points are provided to further clarify.

The general approach to this aspect of the MNS RICT seismic penalty follows the methodology details outlined in the Southern Nuclear Company (SNC) September 27, 2011 letter to the NRC, Vogtle Electric Generating Plant - Units 1 and 2 Methods to be used in the Implementation of Risk-Informed Technical Specifications Initiative 4b (ADAMS Accession No. ML112710169).

This SNC letter was submitted to the NRC because the NEI guideline NEI 06-09 for implementing RICTs provides few details on performing and using penalty calculation values in RICT calculations. SNC followed the methodology details outlined in the aforementioned letter in their TSTF-505 LAR submittals to the NRC, such as that of Vogtle Electric Generating Plant (approved by the NRC; refer to ADAMS Accession No. ML15127A669). The construct outlined in the SNC approach is followed in the majority of industry LARs to adopt TSTF-505.

As outlined in the methodology submitted to the NRC by SNC, a hazard penalty risk value (e.g.,

CDF) is calculated for beyond design basis external events. If a hazard does not screen out of RICT implementation and a hazard penalty value is to be used in RICT calculations, the methodology directs to also consider the impact on RICT calculations from the hazard-induced plant challenges within the design basis (i.e., at or below the design basis). An excerpt from the SNC letter dated September 27, 2011 states:

The process considers two aspects of the external hazard contribution to risk. The first is the contribution from the occurrence of beyond design basis conditions, e.g.,

winds greater than design, seismic events greater than DBE, etc. These beyond design basis conditions challenge the capability of the systems, structures, and components (SSCs) to maintain functionality and support safe shutdown of the plant.

The second aspect addressed are the challenges caused by external conditions that are within the design basis, but still require some plant response to assure safe shutdown, e.g., high winds or seismic events causing loss of offsite power, etc. While the plant design basis assures that the safety related equipment necessary to respond to these challenges are protected, the occurrence of these conditions nevertheless cause a demand on these systems that in and of itself presents a risk.

To address both above aspects, the MNS seismic penalty values (SCDF and SLERF) are calculated not only for beyond design basis earthquakes (up to extremely large magnitude earthquakes that are well beyond the Safe Shutdown Earthquake of 0.15g PGA) but also for extremely low magnitude earthquakes well below the MNS Operating Basis Earthquake, OBE, of 0.08g PGA. As such, the calculated MNS seismic penalty values encompass earthquakes within the design basis and well beyond the design basis.

As an additional clarification, the above question cites the seismic-induced LOOP frequency of 7.3E-5/yr, which is the frequency based on the entire seismic hazard spectrum ranging from

U.S. Nuclear Regulatory Commission Page 10 RA-23-0279 very small earthquakes to very large earthquakes well beyond the design basis. Rather, the seismic-induced LOOP frequency of pertinence to this discussion is the 1.0E-05/yr calculated value which applies to the seismic challenge within the design basis. As discussed in Enclosure 4, Section 3.6 of the LAR and included in Attachment 2 of this submittal, the seismic-induced LOOP frequency within the design basis is only 2% (a small percentage) of the MNS full-power internal events PRA unrecovered LOOP frequency. But, again, the seismic penalty SCDF and SLERF values for the RICT application are calculated including earthquakes both above and below the design basis.

Duke Energy Response to QUESTION-01 (APLC - RICT), Part g As described above in the responses to other parts of this NRC audit question, Duke Energy has decided to use the simple average results of the SCDF or SLERF penalty estimates computed by convolving the PLF curve with the hazard curves for four separate frequencies:

1Hz, 5Hz, 10Hz and PGA. The updated seismic penalty estimates are as follows:

x SCDF Penalty = 3.57E-05/yr x SLERF Penalty = 2.29E-06/ yr Similarly, the baseline seismic risk calculations have been updated as well by using the simple average method as follows:

x Baseline SCDF = 3.36E-05/yr x Baseline SLERF = 2.16E-06/yr The corresponding revision will be made to the MNS seismic penalty report.

QUESTION-02 (APLC - RICT) - Extreme Wind Analysis Section 2.3.1, Item 7, of NEI 06-09-A, states that the impact of other external events risk shall be addressed in the RMTS program, and explains that one method to do this is by performing a reasonable bounding analysis and applying it along with the internal events risk contribution in calculating the configuration risk and the associated RICT. The NRC staffs safety evaluation for NEI 06-09-A states that [w]here PRA models are not available, conservative or bounding analyses may be performed to quantify the risk impact and support the calculation of the RICT.

In Section 4 of Enclosure 4 to the LAR, the licensee stated that McGuire has a high winds (HW)

PRA model but developed HW penalty factors for the RICT program due to current computer resource issues and requested the option to use the high winds PRA in lieu of high wind penalties in the future. The licensee provided the baseline HW core damage frequency (CDF) of 3.0E-6/yr for Unit 1 and 3.1E-6/yr for Unit 2 and large early release frequency (LERF) of 1.1E-7/yr (for both units), and HW penalty factors for CDF of up to 5E-5/yr and LERF of 1E-6/yr.

However, the licensee did not discuss how these penalty factors were developed and why they are significantly higher than its baseline CDF.

The licensee is requested to address the following:

a) The NRC staff noted that the McGuire IPEEE provided HW CDF of 1.9E-5/yr, which is much higher than its HW PRA model prediction. Discuss the plant modifications and HW PRA model improvements to significantly reduce HW risk.

U.S. Nuclear Regulatory Commission Page 11 RA-23-0279 b) Provide detailed discussions on how these HW penalty factors were developed and justify the applicability of these penalty factors in the RICT program.

c) The licensee stated that a large percentage of baseline CDF and LERF (approximately 75% and 65%, respectively) are wind-induced LOOP events, which are already covered in the internal events PRA. Provide a detailed explanation to support the statement.

d) Describe the approach for and the results from uncertainty analysis for the licensees HW PRA, including the identification and characterization of the key assumptions and sources of uncertainty. The description should contain sufficient detail to identify: (1) whether all assumptions and sources of uncertainty related to all aspects of the hazard, fragility, and plant response analysis were evaluated to determine whether they were key, and (2) the criteria that were used to determine whether the modeling assumptions and sources of uncertainty were considered key. The results of the uncertainty analysis should be provided in equivalent detail to the information in Enclosure 9 of the LAR.

e) Given that the use of the HW PRA in the RICT program is dependent on computer resources, describe how the HW PRA model will be maintained to ensure its continued technical acceptability and as-built, as-operated plant representation.

f) Given that the use of the HW PRA in the RICT program is dependent on computer resources, explain how it will be ensured that the integration of the HW PRA into the real-time risk monitor is not prone to errors.

g) While the LAR states that either the HW penalty or the HW PRA will be used in the RICT program, the staff were unable to find an enforceable statement to this effect. Justify why it is appropriate to not include an enforceable basis for ensuring that either the HW penalty or the HW PRA will be used in the RICT program (i.e., not both simultaneously) or provide such an enforceable basis (e.g., license condition).

Duke Energy Response to QUESTION-02 (APLC - RICT), Part a Both plant modifications and HW PRA model improvements have significantly reduced HW risk from the MNS IPEEE as compared to the PRA Standard Capability Category II HW PRA. First, the full power internal events (FPIE) PRA has changed significantly since the IPEEE. The HW PRA uses the FPIE PRA as a backbone or starting point. The FPIE model improvements, therefore, cascaded down to the HW PRA. The list below provides some noteworthy changes.

x Equipment reliability has improved significantly since the IPEEE and is reflected in both the internal events and HW PRA, resulting in a lower CDF. Equipment reliability improved by incorporating generic NUREG 6928 data and using plant specific data for Bayesian updates. For example, the following are the emergency diesel generator (EDG) failure mode changes from the IPEEE to the current HW PRA. The EDG failures are the top consequential equipment failures in the HW PRA.

U.S. Nuclear Regulatory Commission Page 12 RA-23-0279 Failure mode IPEEE Current HW PRA Percent decrease Failure rate Failure Rate in Failure rate EDG fails to Run 2.00E-01 2.03E-02 90%

EDG fails to Start 6.00E-03 2.87E-03 52%

Common Cause 1.39E-02 6.21E-04 96%

Failure (CCF) of EDG fails to Run CCF of EDG fails to 1.20E-04 6.46E-05 46%

Start x Additionally, certain plant operations in accident sequences have been credited in the FPIE PRA and the HW PRA, such as gravity drain cooling of the chemical volume control system pump (i.e., high head safety injection pumps) upon a loss of nuclear service water, which also reduces risk.

x Updated and improved procedures are also reflected in both the internal events and HW PRA, resulting in a lower CDF.

x The newer human reliability analysis (HRA) dependency techniques allow for more HRA dependencies to be captured and reflected in the results.

x The Emergency Core Cooling System (ECCS) water management modification was implemented, which allows for more water from the refueling water storage tank to be directly injected into the core during loss-of-coolant-accident (LOCA) scenarios and gives operators more time to swap over to cold leg recirculation.

x The 300,000-gallon Auxiliary Feedwater Storage Tanks were installed, and they provide an immediate large source of clean water to inject into the steam generators for secondary side heat removal.

x Reactor Coolant Pump (RCP) seals with high-temperature O-rings have been installed on all the RCPs for both units.

x The Emergency Supplemental Power Source (ESPS) has been installed at MNS. The MNS ESPS is a permanently installed, non-safety related, commercial grade system that has two 6.9 kV supplemental diesel generator sets (SDG). The ESPS SDG can provide power to necessary components when an EDG is unavailable. The operator actions associated with starting ESPS are indoors, and not exposed to the elements.

The cables are routed in underground trenches. That modification cut the quantifiable HW CDF approximately in half.

One noteworthy high wind model improvement from the IPEEE HW PRA is that at the lower F1 windspeed a LOOP is not assumed under all conditions.

Narrowing the scope of changes to the HW PRA model down to those made since the EDG extended Completion Time license amendment (ADAMS Accession No. ML17122A116; ESPS was installed in conjunction with this license amendment), primarily one change has contributed to reducing the CDF. That change involved removing the overly conservative wind pressure fragility of the feedwater lines that led to a failure of both EDGs. That change was evaluated to be an update/maintenance to the PRA because it did not implement any

U.S. Nuclear Regulatory Commission Page 13 RA-23-0279 new methodology or meet the upgrade criteria described in Duke Energy PRA procedure AD-NF-NGO-0502, Probabilistic Risk Assessment (PRA) Model Technical Adequacy, Revision 5. All changes to the PRA, whether resultant from closure of Facts and Observations (F&Os) or other maintenance, are evaluated as to whether they constitute an update/maintenance or an upgrade. To further clarify, any changes as a result of resolving and closing out peer review findings are evaluated as update/maintenance or upgrade.

Duke Energy Response to QUESTION-02 (APLC - RICT), Part b , Section 4.1 of the MNS RICT LAR states that non-recoverable wind-induced LOOP events without wind-induced failures can be screened using Criterion C4 (event is included in the definition of another event). The resulting CDF and LERF, after removing the cutsets with only random failures and operator actions, is referred to as the "HW Failures Only" CDF and LERF. The method used to determine the HW Failures Only results is to apply recovery rules to eliminate cutsets that do not include wind pressure or missile fragility basic events. It was confirmed that the sequences being removed from the HW PRA are in fact accounted for in the internal events PRA as part of the weather-related LOOP sequences.

Furthermore, Enclosure 4, Section 4.2 of the MNS RICT LAR states: The TSTF-505 application (i.e., RICT program) is an at-power only application (i.e., Modes 1 and 2) and not for shutdown conditions. Site procedures for response to severe weather directs Operations personnel to place the plant in Mode 3 at least two hours prior to the anticipated arrival of sustained winds in excess of 74 mph at the site. Hurricanes therefore do not apply to the RICT Program and can be screened from inclusion in RICT Program calculations.

Thus, the starting point for the MNS HW penalty factor is the model without hurricane initiators and with HW Failures Only cutsets. To determine the penalty factor, each of the limiting condition for operation (LCO) configurations evaluated in MNS RICT LAR Enclosure 1 for the sample RICT calculations are processed through the HW PRA model (with the hurricane and HW failures only exceptions). All other maintenance terms are set to FALSE for each of the LCO configuration runs. The final results are processed using Advanced Cutset Upper Bound Estimator (ACUBE) to reduce the conservatism associated with the Min Cut Upper Bound (MCUB) method for determining total CDF or LERF. The base case CDF and LERF ACUBE results for both units are provided in Table 4 below (HW Failures Only and no hurricanes).

Table 4 Base Case HW CDF and LERF (ACUBE Results)

Unit End State Average Zero Maintenance Maintenance 1 CDF 6.51E-7/yr 5.23E-7/yr 2 CDF 6.94E-7/yr 5.55E-7/yr 1 LERF 3.47E-8/yr 2.52E-8/yr 2 LERF 3.70E-8/yr 2.55E-8/yr The results of the LCO case runs for each unit and end state are reviewed to select values for the penalty factors. The process of selecting the penalty factor is to choose a value that is reasonably bounding and apply it to all RICT configurations. The general approach is to select the highest case CDF and LERF, then round up the values to provide additional margin. If possible, the Unit 1 and Unit 2 penalty factors should be the same, to avoid complicating the

U.S. Nuclear Regulatory Commission Page 14 RA-23-0279 application of the penalty factor. Multi-tiered penalty factors are generally not preferred, as having multiple penalty factors leads to additional complications and potential error traps.

However, in the case of MNS, several LCOs have CDF values that would be too limiting to apply to all LCO configurations. Therefore, one set of CDF penalty factors is assigned to most LCO configurations, and a higher set is used for a few specific LCO configurations. A single LERF penalty factor is used for all configurations for both units.

CDF/CDF For both units, CDF and CDF for most LCO configurations is less than 1E-5/yr, with a substantial percentage of configurations having a CDF less than 3E-6/yr, and many LCOs (e.g., instrumentation) having essentially no CDF increase. Several LCO configurations have CDF and CDF values between 1E-5/yr and 3E-5/yr:

x LCO 3.3.2.H AFW Actuation Logic x LCOs 3.8.4.A and 3.8.9.C D 125VDC x LCO 3.3.5.B 2 Loss of Power Trains supporting B EDG Table 5 is the list of the top LCO configurations CDF and CDF for Unit 2; the Unit 1 results are similar but with slightly lower CDF and CDF values.

LERF/LERF For both units, LERF and LERF for most LCO configurations are less than ~6E-7/yr; two LCOs for Unit 2 have LERF and LERF slightly greater than 1E-6/yr (see Table 6, including Note (1)).

Many LCOs (e.g., instrumentation) have essentially no LERF increase. Table 6 is the list of the top LCO configurations LERF and LERF for Unit 2; the Unit 1 results are similar but with slightly lower LERF and LERF values.

Table 5 Top LCO Configurations for CDF/CDF (Unit 2)

Case SSCs/Function CDF CDF

332H_3 AFWActuationLogic 2.94E05 2.88E05

384A_4 D125VDC 1.56E05 1.51E05

389C_8 D125VDCI&CPanels 1.56E05 1.50E05

335B_4 BDGLOP(A+C) 1.52E05 1.47E05

335B_5 BDGLOP(A+D) 1.52E05 1.47E05

335B_6 BDGLOP(A+B) 1.52E05 1.47E05

384A_1 A125VDCChannel 9.21E06 8.65E06

389C_7 A125VDCI&CPanels 9.20E06 8.64E06

389A_1 A4kVSwitchgear(BLF) 8.45E06 7.90E06

389A_3 B4kVSwitchgear(BLF) 8.37E06 7.81E06

335B_1 ADGLOP(A+C) 8.09E06 7.53E06

335B_2 ADGLOP(C+D) 8.09E06 7.53E06

335B_3 ADGLOP(B+D) 8.09E06 7.53E06

381F_1 ADG+O/P 8.08E06 7.52E06

381F_3 ADG+O/P 8.08E06 7.52E06

U.S. Nuclear Regulatory Commission Page 15 RA-23-0279 381B_1 ADG 8.08E06 7.52E06

381H_1 ALoadSequencer 8.08E06 7.52E06

389A_21 600V2EMXE 8.08E06 7.52E06

381F_4 BDG+O/P 8.00E06 7.45E06

381F_2 BDG+O/P 8.00E06 7.45E06

381B_2 BDG 8.00E06 7.45E06

381H_2 BLoadSequencer 8.00E06 7.45E06

389A_2 A4kVSwitchgear(TRM) 7.99E06 7.43E06

389A_4 B4kVSwitchgear(TRM) 7.93E06 7.38E06

389A_18 600V2ELXB 3.75E06 3.20E06

384A_11 ABattCharger 3.61E06 3.06E06

389A_17 600V2ELXA 3.55E06 2.99E06

384A_14 DBattCharger 3.06E06 2.51E06

332D_51 ESFAS/AFW 2.26E06 1.71E06

332D_52 ESFAS/AFW 2.26E06 1.71E06

332H_2 TurbTrip/IsoFW 1.76E06 1.20E06

332I_1 TurbTrip/IsoFW 1.76E06 1.20E06

332J_13 TurbTrip/IsoFW 1.76E06 1.20E06

375B_6 CATDP 1.76E06 1.20E06

Table 6 Top LCO Configurations for LERF/LERF (Unit 2)

Case SSCs/Function LERF LERF

332H_3(1) AFWActuationLogic 1.10E06 1.07E06

389A_18 600V1ELXD/2ELXB 6.48E07 6.23E07

389A_17 600V1ELXC/2ELXA 6.26E07 6.01E07

362C_1 ContainmentAirlocks 5.97E07 5.72E07

362C_2 ContainmentAirlocks 5.97E07 5.72E07

332B_2 SIManual 5.97E07 5.72E07

332B_3 SIManual 5.97E07 5.72E07

332C_5 ContISO 5.97E07 5.72E07

332C_6 ContISO 5.97E07 5.72E07

363A_1 ContISO 5.97E07 5.72E07

363C_1 ContISO 5.97E07 5.72E07

384A_4 D125VDC 5.58E07 5.33E07

389C_8 D125VDCI&CPanels 5.56E07 5.31E07

384A_1 A125VDCChannel 5.03E07 4.77E07

389C_7 A125VDCI&CPanels 5.00E07 4.75E07

389A_1 A4kVSwitchgear(BLF) 4.64E07 4.38E07

335B_4 BDGLOP(A+C) 4.51E07 4.26E07

335B_5 BDGLOP(A+D) 4.51E07 4.26E07

335B_6 BDGLOP(A+B) 4.51E07 4.26E07

389A_3 B4kVSwitchgear(BLF) 4.50E07 4.24E07

335B_1 ADGLOP(A+C) 4.27E07 4.01E07

U.S. Nuclear Regulatory Commission Page 16 RA-23-0279 335B_2 ADGLOP(C+D) 4.27E07 4.01E07

335B_3 ADGLOP(B+D) 4.27E07 4.01E07

381B_1 ADG 4.25E07 4.00E07

381F_1 ADG+O/P 4.25E07 4.00E07

381F_3 ADG+O/P 4.25E07 4.00E07

381H_1 ALoadSequencer 4.25E07 4.00E07

389A_21 600V1SLXB/2EMXE 4.25E07 4.00E07

389A_2 A4kVSwitchgear(TRM) 4.22E07 3.96E07

389A_4 B4kVSwitchgear(TRM) 4.11E07 3.85E07

381B_2 BDG 4.06E07 3.80E07

381F_2 BDG+O/P 4.06E07 3.80E07

381H_2 BLoadSequencer 4.06E07 3.80E07

384A_11 ABattCharger 3.03E07 2.78E07

NotestoTable6:

 (1)LERFforthecomparableUnit1configurationsareapproximatelyafactorof2lessthantheUnit2values.

ArefinementtotheUnit1HRAdependencyanalysiswasnotperformedfortheUnit2model,resultingina

dependenthumanerrorprobability(HEP)valuebeingmuchhigherinUnit2thaninUnit1.Giventhis

differenceandthefactthattheLERFforthesetwocasesisonly1.1E6/yr,theyareconsideredlessthan1E 6/yrforthepurposesofdefiningtheLERFpenaltyfactor.Therefore,allLCOLERFandLERFvaluesforboth

unitsareconsideredlessthan1E6/yr.

The final penalty factors chosen are:

x CDF Penalty Factor = 1E-5/yr for both units and all RICT configurations, except for LCO/SSC combinations assigned a higher penalty factor (below).

x CDF Penalty Factor = 3E-5/yr1 for both units, for the following LCO/SSC combinations:

o 3.3.2.H for AFW Actuation Logic o 3.3.5.B for any 2 channels of loss of power signals for B Bus o 3.8.4.A for D 125VDC Channel o 3.8.9.C for D 125VDC I&C Panel Powerboard x LERF Penalty Factor = 1E-6/yr for both units and all RICT configurations.

The following factors result in conservative calculations for the penalty factors:

x The highest CDF and LERF of all the LCO cases are used to determine the penalty factors. The value is rounded up to provide for additional margin. For example, the highest Unit 1 LERF value is 6.0E-7/yr and LERF is 5.8E-7/yr. The LERF penalty factor assigned is 1E-6/yr.

x The CDF and LERF penalty factors are greater than the total CDF and LERF for each configuration, in addition to bounding the configuration CDF and LERF values.

Thus, the total HW CDF and LERF are included in the penalty factor, but they are applied as CDF and LERF.

1 The initial LAR submittal the CDF Penalty Factor for these configurations was 5E-5/yr. However, in discussions with the NRC staff during the audit, it was determined that that 3E-5/yr is a more appropriate value.

U.S. Nuclear Regulatory Commission Page 17 RA-23-0279 x Penalty factors are applied to all LCO configurations, even those with little to no risk increase.

x The CDF and LERF values calculated for each LCO configuration assume that offsite power is not recovered, which is conservative for the lower wind speeds, which are the most dominant contributors.

x The CDF and LERF values calculated for some LCO configurations do not account for procedural guidance (e.g., MNS procedures RP/0/A/5700/006, Natural Disasters and RP/0/B/5700/027, Severe Weather Preparation) to return equipment to service in the event of certain weather situations.

x FLEX is not credited for mitigation in the HW CDF and LERF calculations.

x The Standby Shutdown Facility (SSF) is only credited for F1 windspeed sequences after the first hour of the initiating event. The SSF could be credited for windspeeds at or above F2, if the SSF remains intact.

x The process for using real-time risk (RTR) to calculate the RICT explicitly addresses the weather condition expected during the out of service time when calculating the RICT.

The updated high wind penalty factor is provided in a revised MNS RICT LAR Enclosure 4 as part of Attachment 2 of this submittal.

Duke Energy Response to QUESTION-02 (APLC - RICT), Part c After discussions with the NRC staff during the regulatory audit, Duke Energy is amending its approach to use either a HW penalty factor (as described in the response above to Part b of this audit question) or the HW PRA in its entirety. Thus, if/when the HW PRA is used for the MNS RICT Program, any overlap that may exist in wind-induced LOOP events included in both the HW PRA and FPIE PRA models will be retained, irrespective of potential double-counting.

Duke Energy Response to QUESTION-02 (APLC - RICT), Part d Identification and characterization of the key assumptions and sources of uncertainty for high winds was performed with the same approach as all other PRA hazards. All assumptions and sources of uncertainty related to all aspects of the high wind hazard, fragility, and plant response analysis were evaluated to determine whether they were key.

To determine whether each assumption or uncertainty is key or not for the RICT application, the assumption or uncertainty was individually assessed based on the definitions in Regulatory Guide 1.200 Revision 3, NUREG-1855 Revision 1, and related references (i.e., EPRI 1016737, EPRI 1013491, and EPRI 1026511) and ASME/ANS RA-S-2009. These documents provide definitions and guidance to identify if a specific assumption or uncertainty is key for an application and requires further consideration of the impact to the application.

Consistent with Section 4.1 of EPRI Report 1016737 and ASME/ANS RA-S-2009, a source of uncertainty is labeled key when it could impact the PRA results that are being used in a decision, and consequently, may influence the decision being made. EPRI Report 1016737 and ASME/ANS RA-S-2009 further indicate that this impact would need to be significant

U.S. Nuclear Regulatory Commission Page 18 RA-23-0279 enough that it changes the degree to which the risk acceptance guidelines are met, and therefore, could potentially influence the decision.

Assumptions or sources of uncertainty determined not to be key are those that do not meet the definitions of key uncertainty or key assumption in Regulatory Guide 1.200 Revision 3, NUREG-1855 Revision 1, or related references. Specifically, the following criteria were used to determine those assumptions and sources of uncertainty that do not require further consideration as key to the application:

1. The uncertainty is addressed by implementing a consensus model as defined in NUREG-1855 Revision 1. EPRI 1013491 elaborates on the definition of a consensus model to include those areas of the PRA where extensive historical precedence is available to establish a model that has been accepted and yields PRA results that are considered reasonable and realistic. Thus, assumptions for which there is extensive historical precedent, and for which produced results are reasonable and realistic, can be screened from further consideration.

2. The assumption that addresses an uncertainty will have no impact or insignificant impact on the PRA results and therefore no impact or insignificant impact on the risk significance of a SSC, in the context of the duration of its calculated RICT.

3. The assumption addressing the uncertainty introduces a slight conservative bias in the PRA model results. EPRI 1013491 uses the term realistic conservatisms and notes that judiciously applied realistic conservatism can provide a PRA that avoids many of the traps associated with the use of excess conservatism. This criterion, which allows screening of sources of conservative bias, is intended to be less restrictive than the previous criterion, which does not distinguish between conservative and nonconservative bias. Thus, using this criterion, assumptions that introduce realistic (slight or moderate) conservatisms can be screened from further consideration.

4. There is no reasonable alternative assumption or reasonable modeling refinement to address the uncertainty that would produce different results. For the base PRA, the term different results refers to a change in the risk profile (e.g., total CDF and total LERF, or the set of initiating events and accident sequences that contribute most to CDF and to LERF) and the associated changes in insights derived from the changes in the risk profile. A reasonable alternative assumption is one that has broad acceptance within the technical community and for which the technical basis for consideration is at least as sound as that of the assumption being challenged (Regulatory Guide 1.200 Revision 3).

5. There is no reasonable alternative assumption or reasonable modeling refinement to address the uncertainty that is at least as sound as the assumption under consideration.

A reasonable alternative assumption is one that has broad acceptance within the technical community and for which the technical basis for consideration is at least as sound as that of the assumption being challenged (Regulatory Guide 1.200 Revision 3).

If the manner of addressing an uncertainty does not meet one of the considerations above, then it is retained as key for the application. Following the aforementioned process, there were no modeling assumptions or sources of uncertainty that were considered key for HW.

U.S. Nuclear Regulatory Commission Page 19 RA-23-0279 Duke Energy Response to QUESTION-02 (APLC - RICT), Part e The HW PRA is maintained with the process described in Enclosure 7 of the MNS LAR to adopt TSTF-505, Revision 2, no differently than the FPIE PRA, internal flooding PRA and fire PRA.

The HW PRA can be quantified and maintained using current computer resources. As discussed in the response above to Part a of this audit question, the HW PRA is modeled on the backbone of the FPIE model, and changes made to the FPIE model propagate to the HW PRA.

Changes specific to the HW PRA model itself will (and currently do) follow the process described in Enclosure 7 of the MNS LAR to adopt TSTF-505, Revision 2.

Duke Energy Response to QUESTION-02 (APLC - RICT), Part f The HW PRA was integrated into the all-hazards PRA (i.e., one-top PRA model) alongside internal flooding PRA and fire PRA based on the FPIE PRA. Thus, the HW PRA is already integrated into the all-hazards model that will support the Real-Time Risk model RICT calculations. (NOTE: The HW hazard PRA model will be flagged off when the HW penalty is being used for RICT calculations). The HW model integration into the all-hazards model went through the same rigorous verifications and cutset reviews as the fire PRA integration and the internal flooding PRA integration. The HW PRA model integration process into the Real-Time Risk model will follow the same process as the other hazards, as discussed in Enclosure 8 of the MNS LAR to adopt TSTF-505, Revision 2, in order to be used for the RICT program.

Duke Energy Response to QUESTION-02 (APLC - RICT), Part g Duke Energy proposes the following license condition be added to Appendix B (Additional Conditions) of the Facility Operating License (FOL) for both McGuire Units 1 and 2 to preclude the high winds penalty and high winds PRA from being used in the RICT Program simultaneously:

For the Risk-Informed Completion Time (RICT) calculations within the Risk-Informed Completion Time Program, a singular approach for the high winds external hazard will be specified and utilized for a given RICT. Either a high winds penalty or a high winds probabilistic risk assessment (PRA) will be utilized in the RICT Program calculations. A high winds PRA and high winds penalty shall not be used simultaneously to determine RICTs within the RICT Program.

The implementation date of the above proposed license condition shall be Upon Implementation of Amendment No. [XXX].

A markup of the MNS, Units 1 and 2 FOLs to reflect the above proposed license condition is provided in Attachment 4 of this submittal.

QUESTION-04 (APLC - 50.69) - Extreme Wind Analysis Paragraph 50.69(b)(2)(ii) of 10 CFR requires that the quality and level of detail of the systematic processes that evaluate the plant for external events during operation is adequate for the categorization of SSCs.

In Attachment 4 of the LAR, the licensee stated that the total CDF for HW hazards are 3.0E-6/yr and 3.1E-6/yr for Units 1 and 2, respectively, and LERF is approximately 1.1E-7/yr for both units. The licensee further stated that the CDF and LERF due to scenarios/sequences involving

U.S. Nuclear Regulatory Commission Page 20 RA-23-0279 wind induced failures, either wind pressure or missiles, are estimated to be approximately 8E-7/yr and 4E-8/yr, respectively. Finally, the licensee concluded that extreme winds and tornadoes hazard are considered to be negligible.

Part 6 of the endorsed PRA Standard identifies the screening criterion of CDF < 1E-6/yr using a demonstrably conservative analysis. A peer-reviewed HW PRA does not appear to meet the definition of a demonstrably conservative analysis in the endorsed PRA Standard.

Further, for 50.69 categorization the risk metrics are not CDF and LERF, but Fussell-Vesely (FV) and relative importance for the SSCs. The NRC staff reviewed the licensees HW PRA (MCC-1535.00-00-0178 Revision 4), which provides the FVs > 0.005 and risk achievement worths (RAWs) > 2.0 for many related equipment. Parsing the HW PRA results and inconsistent use of the screening criteria from the PRA Standard can result in incorrect categorization of SSCs as low safety-significant (LSS) and therefore, inappropriate removal of special treatment requirements. The licensee should demonstrate that no additional high-safety-significant (HSS)

SSCs can be identified using the HW PRA, as all HSS SSCs from the HW PRA are covered by using the internal events, internal flooding, or fire PRAs.

The licensee is requested to address the following:

a) Provide detailed analysis to demonstrate that no additional HSS SSCs can be identified using the HW PRA because all HSS SSCs identified from the HW PRA are covered by using the internal events, internal flooding, or fire PRAs.

b) To technically justify the proposed screening please provide:

i. An explanation of how the HW PRA, which is peer-reviewed to Capability Category II of a PRA Standard, is equivalent to a demonstrably conservative analysis as defined in the endorsed PRA Standard.

ii. An explanation for why parsing sequences from a peer-reviewed HW PRA for screening purposes is technically acceptable and consistent with the development of the HW PRA and the endorsed PRA Standard.

iii. An explanation for why parsing sequences from a peer-reviewed HW PRA for screening can be considered acceptable for the 10 CFR 50.69 application when such an approach has not been proposed for the RICT program.

Duke Energy Response to QUESTION-04 (APLC - 50.69)

After discussions with the NRC staff during the regulatory audit, Duke Energy is amending its approach to use the HW PRA model in its entirety for the 10 CFR 50.69 program.

The MNS Units 1 and 2 HW PRA model peer review was performed in October 2014 against ASME/ANS PRA Standard RA-Sb-2013 (Reference 1), RG 1.200 Revision 2 (Reference 2), and NEI 05-04 (Reference 3). A finding closure review was conducted on the HW PRA model in December 2021 where resolved findings were reviewed and closed using the process documented in NEI 17-07 (Reference 4). The results of these reviews have been documented and are available for NRC audit. In conclusion, all the finding level F&Os have been closed, and all associated Supporting Requirements (SRs) are now judged to be met at Capability Category II or higher. There are no PRA upgrades that have not been peer reviewed.

U.S. Nuclear Regulatory Commission Page 21 RA-23-0279 Identification and characterization of the key assumptions and sources of uncertainty for high winds was performed with the same approach as all other PRA hazards. All assumptions and sources of uncertainty related to all aspects of the high wind hazard, fragility, and plant response analysis were evaluated to determine whether they were key for the 10 CFR 50.69 program. The same process of identification and characterization of the key assumptions and sources of uncertainty was used for the 10 CFR 50.69 program as for the RICT program which is described in the response to APLC Question 2, Part d above. There were no modeling assumptions or sources of uncertainty that were considered key for high winds with respect to the 10 CFR 50.69 program.

The approach and discussion above are reflected in the revised 10 CFR 50.69 LAR enclosure and attachments that are provided in Attachment 3 of this submittal.

References for Response to QUESTION-04 (APLC - 50.69)

1. ASME/ANS RA-Sb-2013, "Addenda to ASME/ANS RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," American Society of Mechanical Engineers, New York, NY, September 2013.

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

3. NEI 05-04, "Process for Performing PRA Peer Reviews Using the ASME PRA Standard (Internal Events)," Revision 2, September 2008.

4. NEI 17-07, "Performance of PRA Peer Reviews using the ASME/ANS PRA Standard,"

Nuclear Energy Institute, (ADAMS Accession No. ML19241A615), dated August 2019.

QUESTION-05 (APLC - RICT) - External Flood Hazard Screening Criterion Section 2.3.1, Item 7, of NEI 06-09-A, states that the "impact of other external events risk shall be addressed in the RMTS program," and explains that one method to do this is by documenting prior to the RMTS program that external events that are not modeled in the PRA are not significant contributors to configuration risk. The NRC staffs SE for NEI 06-09-A states that "[o]ther external events are also treated quantitatively, unless it is demonstrated that these risk sources are insignificant contributors to configuration-specific risk."

In Enclosure 4 of the LAR, Table E4-6 screens the External Flood hazard as C1, Event damage is < events for which plant is designed, based on the plant modifications and updated procedures the hazard is considered to be negligible, and that there are no configuration-specific considerations for external floods. Section 5 of Enclosure 4 describes that permanent flood barriers were installed to address some external flood mechanisms that the previous design basis did not mitigate. To address the remaining external flood mechanisms, McGuire relies on procedural guidance to install temporary barriers upon notification of anticipated excessive rainfall.

The NRC staff notes that Criterion C1 is provided within the context of the design basis and notes that, while the permanent flood barrier modification is a design basis update, the use of temporary barriers contingent on procedural compliance and operator action is usually not considered as part of the design basis. Regarding the configuration aspect of the screening, the

U.S. Nuclear Regulatory Commission Page 22 RA-23-0279 staff notes that there are three general configurations for the temporary flood barriers: (1) fully installed, (2) partially installed (either through damage or improper installation), and (3) not installed. It appears the discussion provided in Section 5 of Enclosure 4 only addresses the fully installed configuration.

a) Provide additional justification to screen the external flood hazard for the temporary flood barrier configurations of not being installed or partially installed and that the event damage from these configurations meets Criterion C1. Include in this discussion justification that the use of non-design basis equipment can be included in the evaluation of Criterion C1.

- OR -

b) Propose another screening criterion that allows for the inclusion of the temporary flood barriers and addresses all of the possible configurations of the temporary barriers.

Duke Energy Response to QUESTION-05 (APLC - RICT)

In addition to the listed Criterion C1, Criterion C5 also applies to the external flood hazard.

As described in Enclosure 4 of the MNS LAR to adopt TSTF-505, Revision 2, the external flood hazard at MNS develops slowly, allowing adequate time to eliminate or mitigate the hazard or its impact on the plant. for the MNS LAR to adopt TSTF-505, Revision 2 has been revised to reflect the appropriate screening criteria and is provided in Attachment 2 of this submittal.

QUESTION-06 (APLA - RICT) - In-Scope LCOs and Corresponding PRA Modeling The NRCs SE for NEI 06-09-A specifies that the LAR should provide a comparison of the technical specification functions to the PRA modeled functions to show that the PRA modeling is consistent with the licensing basis assumptions or to provide a basis for when there is a difference. Table E1-1 of LAR Enclosure 1 identifies each Limiting Condition for Operation (LCO) in the technical specifications proposed for inclusion in the RICT program. The table also describes whether the systems and components covered by the LCO are modeled in the PRA and, if so, presents both the design success criteria and PRA success criteria. For certain LCOs, the table explains that the associated SSCs are not modeled in the PRAs but will be represented using a surrogate event that fails the function performed by the SSC. For some LCOs, the LAR did not provide an adequate description for the NRC staff to conclude that the PRA modeling will be sufficient.

a) Regarding TS LCO 3.3.1.D/E, Table E1-1 states the power range neutron flux (high/high rate/low) is not modeled in the PRA, and that trip inputs for one of two trains of the automatic reactor trip system (RTS) are modeled and will be used as a surrogate. It is unclear to the NRC staff how one train of RTS trip inputs is bounding or conservative for the LCOs.

Provide justification that the surrogate bounds each of the power range neutron flux functions.

b) Regarding TS LCO 3.3.1.M, Table E1-1 states the reactor trip system instrumentation for pressurizer water level high and reactor coolant flow low (2 loops) are not modeled in the

U.S. Nuclear Regulatory Commission Page 23 RA-23-0279 PRA, and that a generic 2 of 3 logic input for a train is modeled and will be used as a surrogate. It is unclear to the NRC staff how the generic logic is bounding or conservative for the LCO.

Provide justification that the surrogate bounds the pressurizer water level high and reactor coolant flow low functions.

c) Regarding TS LCO 3.3.1.O, Table E1-1 states the reactor trip system instrumentation for reactor coolant flow low (1 loop) is not modeled in the PRA, and that a generic 2 of 3 logic input for a train is modeled and will be used as a surrogate. It is unclear to the NRC staff how the generic logic is bounding or conservative for the LCO.

Provide justification that the surrogate bounds the reactor coolant flow low function.

Duke Energy Response to QUESTION-06 (APLA - RICT), Part a A different and more appropriate conservative surrogate has been identified for the TS LCO 3.3.1.D/E power range neutron flux (high/high rate/low) channels. The new surrogate is a generical analog channel failure, which is an input into a 2 out of 3 failure scheme. These failures are then inputs to both trains of the Reactor Protection System (RPS) simultaneously.

Thus, if the surrogate is set to failed, a single failure of one of the other generic channels will fail the entire automatic RTS (both Trains). The new surrogate does not change the results of Table E1-2 (See the response to audit Question 11 (APLA/APLC) for an updated Table E1-2).

The new surrogate is conservative because it makes both trains of the automatic RTS trip inputs more likely to become failed in the PRA, regardless of which potential initiating event demands the channels in question. Thus, for all the initiating events in the PRA, both trains of the automatic RTS are more likely to become unavailable (i.e. failed) even if the specific initiating event would not cause a demand to the power range neutron flux (high/high rate/low). As a result, using this surrogate will result in a higher likelihood of an Anticipated Transient Without Scram event due to an RPS failure in the PRA results. Also, with most of the PRA initiating events the automatic reactor trip signal is expected to be generated via diverse sets of channels, but there is no credit taken for that in the PRA model. for the MNS LAR to adopt TSTF-505, Revision 2 has been revised to reflect the approach and discussion above and is provided in Attachment 2 of this submittal.

Duke Energy Response to QUESTION-06 (APLA - RICT), Part b The same new surrogate described in the response to Part a of this audit question will be used for TS LCO 3.3.1.M associated with the reactor trip system instrumentation for pressurizer water level high and reactor coolant flow low (2 loops). for the MNS LAR to adopt TSTF-505, Revision 2 has been revised to reflect the approach and discussion above and is provided in Attachment 2 of this submittal.

Duke Energy Response to QUESTION-06 (APLA - RICT), Part c The same new surrogate described in the response to Part a of this audit question will be used for LCO 3.3.1.O associated with the reactor trip system instrumentation for reactor coolant flow low (1 loop).

U.S. Nuclear Regulatory Commission Page 24 RA-23-0279 for the MNS LAR to adopt TSTF-505, Revision 2 has been revised to reflect the approach and discussion above and is provided in Attachment 2 of this submittal.

QUESTION-07 (APLA - RICT) - Common Cause Failure Treatment, Emergent Conditions The NRCs SE for NEI 06-09-A is based on conformance with Regulatory Guide 1.177, "Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications" (RG 1.177, ADAMS Accession No. ML20164A034). Specifically, SE Section 2.2 states that, specific methods and guidelines acceptable to the NRC staff are [] outlined in RG 1.177 for assessing risk-informed technical specification changes. SE Section 3.2 further states that compliance with the guidance of RG 1.174 and RG 1.177 is achieved by evaluation using a comprehensive risk analysis, which assesses the configuration-specific risk by including contributions from human errors and common cause failures. The guidance in RG 1.177, Section 2.3.3.1, states, CCF

[common cause failure] modeling of components is not simply dependent on the number of remaining inservice components; it is also dependent on the reason the components were removed from service (i.e. whether for preventative or corrective maintenance). According to RG 1.177, if a component from a CCF group is declared inoperable, the CCF of the remaining components should be modified to reflect the reduced number of available components in order to properly model the as-operated plant. of the LAR provides part (d) of TS 5.5.18 (Risk-Informed Completion Time Program), which states:

For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:

1. Numerically accounting for the increased possibility of CCF in the RICT calculation; or

2. Risk Management Actions (RMAs) not already credited in the RICT calculation LAR Enclosure 12 states, If plant personnel establish a high degree of confidence such that no common cause failure mechanism exists that could affect the redundant component(s), or if an adjustment to the RICT calculation is made to numerically account for the increased probability of common cause failure in the CRMP model, then no Common Cause RMAs are required.

However, for emergent conditions, it is unclear in the LAR how the licensee will numerically account for the increased probability of CCF in the RICT calculation if that option is chosen.

Describe and justify how the numerical adjustment for increased probability of CCF will be performed for emergent conditions (e.g., confirm numerical adjustment will be performed in accordance with RG 1.177, as specified in Section A-1.3.2.1 of Appendix A).

Duke Energy Response to QUESTION-07 (APLA - RICT)

Numerical adjustment of CCF events will not typically be performed for a RICT calculation. The procedural process is for plant personnel to complete an extent of condition assessment that addresses the possibility of CCF. If CCF cannot be ruled out, then the RICT will account for the

U.S. Nuclear Regulatory Commission Page 25 RA-23-0279 increased possibility of CCF by method 1 or 2 as described in Section 5.5.18 of the TS markups associated with the original MNS LAR to adopt TSTF-505, Revision 2. This will typically be done using RMAs as described in method 2.

While CCF probabilities will normally not be adjusted for emergent failures, if a numeric adjustment is performed, the RICT calculation would be adjusted to numerically account for the increased possibility of CCF in accordance with RG 1.177, as specified in Section A-1.3.2.1 of Appendix A of the RG. Specifically, when a component fails, the CCF probability for the remaining redundant components will be increased to represent the conditional failure probability due to CCF of these components in order to account for the possibility the first failure was caused by a common cause mechanism.

QUESTION-08 (APLA - RICT) - Performance Monitoring The NRCs SE for NEI 06-09-A, states, The impact of the proposed change should be monitored using performance measurement strategies. NEI 06-09-A considers the use of NUMARC 93-01, Revision 4F, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants (ADAMS Accession No. ML18120A069), as endorsed by Regulatory Guide 1.160, Revision 4, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants (RG 1.160, ADAMS Accession No. ML18220B281), for the implementation of the Maintenance Rule (10 CFR 50.65). NUMARC 93-01, Section 9.0, contains guidance for the establishment of performance criteria.

In addition, the NEI 06-09-A methodology satisfies the five key safety principles specified in RG 1.177, Revision 2, relative to the risk impact due to the application of a RICT. Moreover, NRC staff position C.3.2 provided in RG 1.177 for meeting the fifth key safety principle acknowledges the use of performance criteria to assess degradation of operational safety over a period. It is unclear how the licensees RICT program captures performance monitoring for the SSCs within-scope of the RMTS program. Therefore:

a) Confirm that the McGuire Maintenance Rule program incorporates the use of performance criteria to evaluate SSC performance as described in NUMARC 93-01, as endorsed by RG 1.160.

b) Alternatively, describe the approach or method used by McGuire for SSC performance monitoring, as described in NRC staff position C.3.2 of RG 1.177, Revision 2, for meeting the fifth key safety principle. In the description, include criteria (e.g., qualitative or quantitative), along with the appropriate risk metrics, and explain how the approach and criteria demonstrate the intent to monitor the potential degradation of SSCs in accordance with the NRCs SE for NEI 06-09-A.

Duke Energy Response to QUESTION-08 (APLA - RICT)

The Duke Energy Fleet Maintenance Rule (MR) Program incorporates the use of performance criteria as described in NUMARC 93-01 to evaluate the performance of plant SSCs.

Specifically, Duke Energys MR procedure, AD-EG-ALL-1210, requires the determination of the risk significance of SSCs within the scope of the MR and establishment of performance criteria commensurate with safety significance. The Duke Energy MR Program implements a site-specific Maintenance Rule Expert Panel (MREP) consistent with NUMARC 93-01 recommendations to approve scope determinations, periodically assess program elements, and approve performance criteria and goals for acceptable SSC performance.

U.S. Nuclear Regulatory Commission Page 26 RA-23-0279 QUESTION-09 (APLA - RICT) - Consideration of Shared Systems in Calculation of a RICT RG 1.200, Revision 2, states, [t]he base PRA serves as the foundational representation of the as-built and as-operated plant necessary to support an application. Attachment 1 of the LAR states that some of the RICT LCOs account for shared systems with the opposite unit. of the LAR provides descriptions of these shared systems. However, it is unclear to the NRC staff how these shared systems are represented in the PRA models used for RICT calculations.

Explain how the shared systems are credited for each unit in the PRA models. This discussion should also address the following:

a) Explain how shared systems credited in the real-time risk model that support the RICT calculations are modeled for each unit in a multiunit event. Include in this discussion what aspects of these systems were excluded from the PRA model(s) and why these exclusions do not impact the application.

b) If the impact of events that can create a concurrent demand for a system shared by multiple units and credited in the real-time risk model is not addressed, explain why this modeling exclusion does not have a significant impact on the RICT calculations.

Duke Energy Response to QUESTION-09 (APLA - RICT)

Shared systems described in Enclosure 8 of the MNS LAR to adopt TSTF-505, Revision 2 are explicitly modelled in both the Unit 1 and Unit 2 PRA models and thus in the real-time risk model that support the RICT calculations. If a shared system component is unavailable, it will be unavailable for both units in the real-time risk model. In general, shared systems success criteria accounts for being able to support its shared functions. However, since a shared system, like ESPS, can only be aligned to support a single essential bus (1ETA, 1ETB, 2ETA or 2ETB), in the real-time risk model it can only be credited to a single essential bus as deemed appropriate by the operators. The other busses will receive no credit for ESPS. A similar approach is used for the swing battery charger since it can only be aligned to a single DC bus.

Thus, shared systems that are credited in the real-time risk model are explicitly addressed and Part b of this audit question is not applicable.

The NRC staff also asked the following series of questions during audit discussions that occurred on October 3, 2023. Duke Energy shared a response to the questions on October 4, 2023, and the NRC staff asked that Duke Energy docket the response.

In calculating the RICTs for the analyzed unit, the licensee may credit opposite unit systems (e.g., shared systems) for supplying some function. However, certain conditions may arise in the opposite unit (e.g., TS conditions) that would preclude crediting these opposite unit systems in the RICT calculations for the analyzed unit.

How does the licensee ensure that the RICT estimates for the analyzed unit accurately reflect the availability of shared systems from the opposite unit, considering that conditions and plant configurations are constantly changing, and certain conditions may prevent the crediting of these opposite unit systems in the calculations?

For example, for a site LOOP with loss of offsite power and LOCA for one unit while the second is in a controlled shutdown, does the McGuire PRA model consider shared SSC

U.S. Nuclear Regulatory Commission Page 27 RA-23-0279 specifically those shared systems that, in this example, may be needed for shutdown of the second unit?

Would the RICT estimate for the analyzed unit credit the opposite units shared systems for a site (dual unit) LOOP event, as the shared systems may be in use by the opposite unit?

Duke Energy Response to Additional Questions Pertaining to Question-09 (APLA - RICT)

The MNS PRA addresses all appropriate combinations of initiating events including the impact of shared systems being out of service or failing on demand.

There is nothing in TS that prohibits crediting opposite unit equipment (including power systems as noted in TS 3.8.1) or shared systems during varying modes of operation. If the shared system is inoperable, then it affects both units. All PRA modeled, inoperable equipment (including systems shared between units) is reflected in the configuration specific risk management and RICT calculations. While in a RICT, if additional equipment is removed from service or found inoperable, the configuration risk calculations are rerun and the RICT backstop is updated to reflect the additional out of service equipment - consistent with Duke Energy procedures. Procedure AD-OP-ALL-0212, Section 5.3, Step 12 states: Continuously update the ERAT [Electronic Risk Assessment Tool] configuration AND RICT calculation as plant configuration changes occur.

The PRA success criteria accounts for the shared systems, including electrical power requirements, to be able to support both units when demanded. For example, the shared vital DC system batteries and associated busses account for loads on both units. The impacts of the degradation of the DC bus are propagated to each unit appropriately.

QUESTION-11 (APLA/APLC - RICT) - Exclusion of Hazard Penalties in RICT Estimates Section 2.3.1, Item 7 of NEI 06-09-A, states that the impact of other external events risk shall be addressed in the RMTS program and explains that one method to do this is by performing a reasonable bounding analysis and applying it along with the internal events risk contribution in calculating the configuration risk and the associated RICT. The NRCs SE for NEI 06-09-A states that [w]here PRA models are not available, conservative, or bounding analyses may be performed to quantify the risk impact and support the calculation of the RICT.

Table E1-2 of Enclosure 1 of the LAR provides RICT estimates for technical specification actions proposed to be in the scope of the RICT program. It does not appear the LAR states what PRA models or risk penalties are included in the calculation of the Table E1-2 RICTs. The NRC staff notes that Enclosure 4 of the LAR states that a high wind hazard risk is significant to overall plant risk and calculates two different penalties that are provided. With regards to seismic hazard risk, it was determined to be significant to overall plant risk and an associated risk penalty was developed. The NRC staff notes that the licensee is requesting the use of the McGuire high wind PRA model in lieu of the high wind penalty when the high wind PRA calculation can be performed. It is unclear to the NRC staff whether the RICT values of Table E1-2 include the seismic and high winds penalties (or the high wind PRA results) in the calculation and whether the calculation contains the most limiting value. During the external hazards audit conducted with the licensee on June 27-28, 2023, it appears the licensee will develop new penalty values for both hazard groups.

U.S. Nuclear Regulatory Commission Page 28 RA-23-0279 a) Confirm that the RICT values provided in Table E1-2 of Enclosure 1 of the LAR were calculated considering the seismic and high wind penalties. Include in this discussion whether the most limiting, when applicable, high wind penalty (or PRA result) was included in this table.

b) If Table E1-2 does not include the newest penalty values (including most limiting or PRA result) for seismic and high winds, then provide an updated table that includes these values.

Duke Energy Response to QUESTION-11 (APLA/APLC - RICT)

The RICT values provided in Table E1-2 of Enclosure 1 of the MNS LAR to adopt TSTF-505, Revision 2 were indeed calculated considering the seismic and high wind penalties. The most limiting, when applicable, high wind penalty was included in Table E1-2 of Enclosure 1. As a result of discussions that occurred with the NRC staff during external hazards portion of the regulatory audit on June 27-28, 2023, Duke Energy developed new seismic and high wind penalties, and the updated Table E1-2 below shows the RICT estimates with the newest penalty values (including most limiting) for seismic and high winds. (See the Duke Energy response to audit Question 1, Part g for the updated seismic penalty values and response to audit Question 2, Part b for the updated high wind penalty values.)

Updated Table E1-2: In-Scope TS LCO RICT Estimates Technical RICT Estimate1 Specification Technical Specification Condition (Days)

Reactor Trip System (RTS) Instrumentation - One Manual Reactor Trip 3.3.1.B 30.0 channel inoperable 3.3.1.D Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.E Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.M Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.O Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.Q Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.T Reactor Trip System (RTS) Instrumentation - One train inoperable 30.0 3.3.1.U Reactor Trip System (RTS) Instrumentation - One RTB train inoperable 30.0 Reactor Trip System (RTS) Instrumentation - One trip mechanism 3.3.1.Y 30.0 inoperable for one RTB 3.3.2.B ESFAS Instrumentation - One channel or train inoperable 10.6 3.3.2.C ESFAS Instrumentation - One train inoperable 10.6 3.3.2.D ESFAS Instrumentation - One channel inoperable 30.0 3.3.2.F ESFAS Instrumentation - One channel or train inoperable 11.8 3.3.2.H ESFAS Instrumentation - One train inoperable N/A2 3.3.2.I ESFAS Instrumentation - One train inoperable 30.0 3.3.2.J ESFAS Instrumentation - One channel inoperable 30.0 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation - One or 3.3.5.A 30.0 more Functions with one channel per bus inoperable Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation - One or 3.3.5.B 30.0 more Functions with two or more channels per bus inoperable

U.S. Nuclear Regulatory Commission Page 29 RA-23-0279 Updated Table E1-2: In-Scope TS LCO RICT Estimates Technical RICT Estimate1 Specification Technical Specification Condition (Days)

Pressurizer Power Operated Relief Valves (PORVs) - One Train A PORV 3.4.11.C 9.8 inoperable and not capable of being manually cycled Pressurizer Power Operated Relief Valves (PORVs) - Two Train B PORVs 3.4.11.D 9.3 inoperable and not capable of being manually cycled Pressurizer Power Operated Relief Valves (PORVs) - One Train A block 3.4.11.H 30.0 valve inoperable Pressurizer Power Operated Relief Valves (PORVs) - Two Train B block 3.4.11.I 30.0 valves inoperable Pressurizer Power Operated Relief Valves (PORVs) - One Train B PORV 3.4.11.J inoperable and not capable of being manually cycled AND The other Train B 9.3 block valve inoperable.

Emergency Core Cooling System (ECCS) - Operating - One or more trains 3.5.2.A inoperable AND At least 100% of the ECCS flow equivalent to a single 30.0 OPERABLE ECCS train available.

Containment Air Locks - One or more containment air locks inoperable for 3.6.2.C 10.6 reasons other than Condition A or B Containment Isolation Valves - One or more penetration flow paths with one 3.6.3.A containment isolation valve inoperable except for purge valve or reactor 10.6 building bypass leakage not within limit.

Containment Isolation Valves - One or more penetration flow paths with one 3.6.3.C 10.6 containment isolation valve inoperable.

Containment Spray System (Ice Condenser) - One containment spray train 3.6.6.A 30.0 inoperable Hydrogen Mitigation System (HMS) (Ice Condenser) - One HMS train 3.6.9.A 30.0 inoperable.

Hydrogen Mitigation System (HMS) (Ice Condenser) - One containment 3.6.9.B 30.0 region with no OPERABLE hydrogen ignitor 3.6.11.A Air Return System (ARS) (Ice Condenser) - One ARS train inoperable 30.0 Divider Barrier Integrity (Ice condenser) - One or more personnel access doors or equipment hatches (other than one pressurizer or one steam 3.6.14.A 30.0 generator enclosure hatch addressed by Condition D) open or inoperable, other than for personnel transit entry.

3.7.2.A Main Steam Isolation Valves (MSIVs) - One MSIV inoperable in MODE 1 30.0 Auxiliary Feedwater (AFW) System - One steam supply to turbine driven 3.7.5.A 30.0 AFW pump inoperable Auxiliary Feedwater (AFW) System - One AFW train inoperable in MODE 1, 3.7.5.B 30.0 2 or 3 for reasons other than Condition A.

3.7.6.A Component Cooling Water System (CCW) - One CCW train inoperable 30.0 3.7.7.A Nuclear Service Water System (NSWS) - One NSWS train inoperable 29.1 3.8.1.A AC Sources - Operating - One LCO 3.8.1.a offsite circuit inoperable. 30.0 3.8.1.B AC Sources - Operating - One LCO 3.8.1.b DG inoperable 30.0 3.8.1.C AC Sources - Operating - One LCO 3.8.1.c offsite circuit inoperable. 30.0 AC Sources - Operating - Two LCO 3.8.1.a offsite circuits inoperable OR One LCO 3.8.1.a offsite circuit that provides power to the NSWS, CRAVS, 3.8.1.E 30.0 CRACWS and ABFVES inoperable and one LCO 3.8.1.c offsite circuit inoperable OR Two LCO 3.8.1.c offsite circuits inoperable

U.S. Nuclear Regulatory Commission Page 30 RA-23-0279 Updated Table E1-2: In-Scope TS LCO RICT Estimates Technical RICT Estimate1 Specification Technical Specification Condition (Days)

AC Sources - Operating - One LCO 3.8.1.a offsite circuit inoperable AND 3.8.1.F 30.0 One LCO 3.8.1.b DG inoperable 3.8.1.H AC Sources - Operating - One automatic load sequencer inoperable. 30.0 3.8.4.A DC Sources - Operating - One channel of DC source inoperable N/A2 3.8.7.A Inverters - Operating - One inverter inoperable. 30.0 Distribution Systems - Operating - One or more AC electrical power 3.8.9.A N/A2 distribution subsystem(s) inoperable.

3.8.9.B Distribution Systems - Operating - One AC vital bus inoperable. N/A2 Distribution Systems - Operating - One channel of DC electrical power 3.8.9.C N/A2 distribution subsystem inoperable.

Notes to Table E1-2:

(1) RICTs are based on representative PRA model calculations. RICTs calculated to be greater than 30 days are capped at 30 days based on NEI 06-09-A. RICTs are rounded to nearest tenth of a day.

(2) Per NEI 06-09, Revision 0-A, for cases where the total CDF or LERF is greater than 1E-03/yr or 1E-04/yr, respectively, the RICT Program will not be entered. for the MNS LAR to adopt TSTF-505, Revision 2 has been revised to reflect the approach and discussion above and is provided in Attachment 2 of this submittal.

QUESTION-12 (STSB - RICT) - Editorial Issues in LAR Attachment 2 The NRC staff identified the following editorial issues in Attachment 2 of the LAR, "Proposed Technical Specification Changes (mark-up):

a) For TS 3.3.1, Action Q.1, the licensee revised the action but inadvertently did not remove the term OR from the revised technical specifications. The NRC staff believes OR should be removed. Confirm and revise if necessary.

b) For TS 3.3.2, Action K.1, the NRC staff notes that the Completion Time should be stated as 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> instead of 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Confirm and revise if necessary.

Duke Energy Response to QUESTION-12 (STSB - RICT), Part a Duke Energy has reviewed the TS 3.3.1 markup provided to the NRC staff in the LAR to adopt TSTF-505, Revision 2 dated February 16, 2023 and the OR logical connector following Required Action Q.1 is struck-through. Therefore, Duke Energy believes the markup to appropriately reflect the proposed change for TS 3.3.1.

However, Duke Energy inadvertently did not propose removal of the logical connector OR following Required Action Q.1 for TS 3.3.2 (ESFAS Instrumentation). Duke Energy hereby supplements the LAR to propose removal of the OR logical connector following TS 3.3.2, Required Action Q.1.

U.S. Nuclear Regulatory Commission Page 31 RA-23-0279 A revised markup of the impacted TS 3.3.2 page is provided in Attachment 1 of this submittal.

Duke Energy Response to QUESTION-12 (STSB - RICT), Part b Duke Energy agrees with the NRC staff and confirms that the Completion Time for TS 3.3.2, Required Action K.1 should be 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> instead of 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Therefore, Duke Energy hereby supplements the LAR to propose 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as the Completion Time for TS 3.3.2, Required Action K.1.

A revised markup of the impacted TS 3.3.2 page is provided in Attachment 1 of this submittal.

QUESTION-13 (EEEB/APLA - RICT) - TS 3.8.1, Required Action B.5 (Part b ONLY)

In Attachment 2 of the LAR, "Proposed Technical Specification Changes (mark-up)," TS 3.8.1 is changed to delete Required Action B.5, "Evaluate availability of Emergency Supplemental Power Source (ESPS)":

b) Since Required Action B.5 will be removed, the NRC staff believes the "AND" from TS 8.3.1, Action B.4.2, is redundant and should be removed. Confirm and revise if necessary.

Duke Energy Response to QUESTION-13 (EEEB/APLA - RICT), Part b Duke Energy has reviewed the TS 3.8.1 markup provided to the NRC staff in the LAR to adopt TSTF-505, Revision 2 dated February 16, 2023 and agrees that there is a redundant AND logical connector that should be removed. Therefore, Duke Energy hereby supplements the LAR to propose removal of a redundant AND logical connector after TS 3.8.1, Required Action B.4.2.

The markup of the impacted TS 3.8.1 page is provided in Attachment 1 of this submittal.

QUESTION-14 (APLC - 50.69) - External Flood Hazard Screening for 50.69 LAR Section 5 of NEI 00-04, "10 CFR 50.69 SSC Categorization Guideline" (ADAMS Accession No. ML052910035), states, If the plant does not have an external hazards PRA, then it is likely to have an external hazards screening evaluation that was performed to support the requirements of the IPEEE. NEI 00-04 also states in Section 3.3.2 that the characterization of the adequacy of risk information should include a basis for why the other risk information adequately reflects the as-built, as-operated plant. of the 50.69 LAR screens the external flood hazard as C1, event damage is <

events for which plant is designed, based on the plant modifications and updated procedures the hazard is considered to be negligible, and that there are no configuration-specific considerations for external floods. The 50.69 LAR describes that permanent flood barriers were installed to address some external flood mechanisms that the previous design basis did not mitigate. To address the remaining external flood mechanisms, the licensee relies on procedural guidance to install temporary barriers upon notification of anticipated excessive rainfall.

The NRC staff notes that Criterion C1 is provided within the context of the design basis and notes that, while the permanent flood barrier modification is a design basis update, the use of temporary barriers contingent on procedural compliance and operator action is usually not considered as part of the design basis. Regarding the configuration aspect of the screening, the

U.S. Nuclear Regulatory Commission Page 32 RA-23-0279 staff notes that there are three general configurations for the temporary flood barriers: (1) fully installed, (2) partially installed (either through damage or improper installation), and (3) not installed. It appears the discussion provided in the 50.69 LAR only addresses the fully installed configuration.

a) Provide additional justification to screen the external flood hazard for the temporary flood barrier configurations of not being installed or partially installed and that the event damage from these configurations meets Criterion C1. Include in this discussion justification that the use of non-design basis equipment can be included in the evaluation of Criterion C1.

- OR -

b) Propose another screening criterion that allows for the inclusion of the temporary flood barriers and addresses all of the possible configurations of the temporary barriers.

Duke Energy Response to QUESTION-14 (APLC - 50.69)

In addition to the listed Criterion C1, Criterion C5 also applies to the external flood hazard.

As described in Attachment 4 of the MNS LAR to adopt 10 CFR 50.69, the external flood hazard at MNS develops slowly, allowing adequate time to eliminate or mitigate the hazard or its impact on the plant. for the MNS LAR to adopt 10 CFR 50.69 has been revised to reflect the appropriate screening criteria and is provided in Attachment 3 of this submittal.

U.S. Nuclear Regulatory Commission RA-23-0279 Attachment 1 ATTACHMENT 1 REVISED MARK-UP OF SELECT TECHNICAL SPECIFICATION PAGES

[4 PAGES FOLLOW THIS COVER PAGE]

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME J. One channel inoperable. J.1 -------------NOTE--------------

One channel may be bypassed for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for surveillance testing.

Place channel in trip. 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OR OR J.2 Be in MODE 3. In accordance with the Risk-Informed Completion Time Program 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> K. One Main Feedwater K.1 Place channel in trip. 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Pumps trip channel inoperable. OR K.2 Be in MODE 3. 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> L. One required channel in L.1 Restore the inoperable 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> one train of Doghouse train to OPERABLE status.

Water Level-High High inoperable. OR 73 hours8.449074e-4 days <br />0.0203 hours <br />1.207011e-4 weeks <br />2.77765e-5 months <br /> L.2 Perform continuous monitoring of Doghouse water level.

M. Two trains of Doghouse M.1 Perform continuous 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Water Level-High High monitoring of Doghouse inoperable. water level..

(continued)

McGuire Units 1 and 2 3.3.2-5 Amendment Nos. 248/228

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME Q. One channel inoperable. Q.1 Verify interlock is in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> required state for existing unit condition.

OR Q.2.1 Be in MODE 3. 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> AND Q.2.2 Be in MODE 4. 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> R. One or more R.1 Declare affected supported Immediately Containment Pressure system inoperable.

Control System channel(s) inoperable.

S. Required Action and S.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition B or C AND not met.

S.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> ST. Required Action and ST.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition D, E, AND F, H, P, or Q not met.

ST.2 Be in MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> U. Required Action and U.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition I, J, or K not met.

McGuire Units 1 and 2 3.3.2-7 Amendment Nos. 198/179

No proposed changes on this page. Provided for information only. AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One LCO 3.8.1.b DG B.1 Verify LCO 3.8.1.d DG(s) 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable OPERABLE.

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 B.2 Perform SR 3.8.1.1 for the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> required offsite circuit(s).

AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND B.3 Declare required feature(s) 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from supported by the discovery of inoperable DG inoperable Condition B when its required concurrent with redundant feature(s) is inoperability of inoperable. redundant required feature(s)

AND B.4.1 Determine OPERABLE 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> DG(s) is not inoperable due to common cause failure.

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

AND (continued)

McGuire Units 1 and 2 3.8.1-3 Amendment No. 314/293

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) 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 Power Source (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 B.65 Restore DG to OPERABLE 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from status. discovery of unavailable ESPS OR In accordance with the Risk-Informed Completion Time Program AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of Condition B entry 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 (continued)

McGuire Units 1 and 2 3.8.1-4 Amendment No. 322/301

U.S. Nuclear Regulatory Commission RA-23-0279 Attachment 2 ATTACHMENT 2 REVISED ENCLOSURES FOR LICENSE AMENDMENT REQUEST TO ADOPT TSTF-505, REVISION 2

[125 PAGES FOLLOW THIS COVER PAGE]

U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 ENCLOSURE 1 LIST OF REVISED REQUIRED ACTIONS TO CORRESPONDING PRA FUNCTIONS

U.S. Nuclear Regulatory Commission Page 2 RA-23-0279 1.0 PURPOSE The purpose of this enclosure is to provide a mapping of identified in-scope Technical Specifications (TS) statements to modeled (and surrogate) Probabilistic Risk Assessment (PRA) functions. This mapping provides the basis by which to quantify the increase in risk associated with extending the Completion Time for a given TS Action and to calculate a Risk-Informed Completion Time (RICT) for the RICT Program application.

2.0 REFERENCES

1. NRC Letter from Jennifer M. Golder to Biff Bradley (NEI), Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06-09, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, May 17, 2007 (ADAMS Accession No. ML071200238).

2. Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS)

Guidelines, Revision 0, October 12, 2012 (ADAMS Accession No. ML12286A322).

3. NUREG/CR-5500, Volume 2, Reliability Study: Westinghouse Reactor Protection System, 1984-1995, December 1998.

4. TSTF-505-A, Rev. 2, Technical Specifications Task Force Improved Standard Technical Specifications Change Traveler, November 2018.

5. Updated Final Safety Analysis Report (UFSAR) - McGuire Nuclear Station, Revision 23.

6. TSTF-411, Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376-P), Revision 1, dated August 7, 2002 (ADAMS Accession No. ML022470164).

7. NRC Letter from NRC to McGuire Nuclear Station, McGuire Nuclear Station, Units 1 and 2, Issuance of Amendments Regarding Reactor Trip System and Engineered Safety Features Actuation System Completion Times, Bypass Test Times and Surveillance Test Intervals, Dated December 30, 2008 (ADAMS Accession No. ML083520046).

3.0 INTRODUCTION

Section 4.0, Item 2 of the NRC Final Safety Evaluation (Reference 1) for NEI 06-09-A (Reference 2) identifies the following necessary content:

x The license amendment request (LAR) will provide identification of the TS Limiting Conditions for Operation (LCOs) and Required Actions to which the RICT Program will apply.

x The LAR will provide a comparison of the TS functions to the PRA modeled functions of the structures, systems and components (SSCs) subject to those LCO actions.

x The comparison should justify that the scope of the PRA model, including applicable success criteria such as number of SSCs required, flow rate, etc., are consistent with licensing basis assumptions (i.e., 10 CFR 50.46 emergency core cooling system (ECCS) flowrates) for each of the TS requirements, or an appropriate disposition or programmatic restriction will be provided.

This enclosure provides confirmation that the McGuire Nuclear Station (MNS) PRA models include the necessary scope of SSCs and their functions to address each proposed application of the RICT Program to the proposed scope of TS LCOs. The enclosure also provides the information requested by Section 4.0, Item 2 of Reference 1. The comparison includes each of the TS LCOs and associated Required Actions within the scope of the RICT Program. The

U.S. Nuclear Regulatory Commission Page 3 RA-23-0279 MNS PRA model has the capability to model directly, or using a bounding surrogate, the risk impact of entering each of the Actions associated with the TS LCOs that are in the scope of the RICT Program.

Table E1-1 below lists each MNS TS Action to which the RICT Program is proposed to be applied. The table also documents the following information regarding the TS with the associated safety analyses, the analogous PRA functions and the results of the comparison:

x Column Technical Specification: Lists the LCOs within the scope of the proposed RICT Program x Column Technical Specification Action: Lists the corresponding Action currently in the MNS TS x Column Corresponding SSC(s): Lists the SSC(s) addressed by each TS Action x Column Function Covered by TS LCO Condition: Contains a summary from the design basis analyses x Column Design Success Criteria: Contains a summary of the success criteria from the design basis analyses x Column SSCs Modeled in the PRA: Indicates whether the SSCs addressed by the TS LCO and Action are included in the PRA x Column PRA Success Criteria: Lists the functions success criteria in the PRA model x Column Comments: Provides the justification or resolution to address any inconsistencies between the TS and PRA functions regarding the scope of SSCs and the success criteria. Where the PRA scope of SSCs is not consistent with the TS, additional information is provided to describe how the LCO Action can be evaluated using appropriate surrogate events in the PRA model. Differences in the success criteria for TS functions are addressed to demonstrate PRA criteria provide a realistic estimate of the risk of the TS LCOs and Actions as required by Reference 2.

The corresponding SSCs for each TS Condition and the associated TS functions are identified and compared to the PRA models. This description also includes the design success criteria and the applicable PRA success criteria. Any differences between the scope or success criteria are described in the table. Scope differences are justified by identifying appropriate surrogate events which permit a risk evaluation to be completed using the Configuration Risk Management Program (CRMP) tool for the RICT Program. Differences in success criteria typically arise due to the requirement in the ASME/ANS PRA Standard to make PRAs realistic rather than bounding, whereas design basis criteria are necessarily conservative and bounding.

The use of realistic success criteria is necessary to conform to Capability Category II of the ASME/ANS PRA Standard as required by NEI 06-09-A (Reference 2).

For the purposes of the MNS RICT program, the definition for loss of function or loss of safety function for the subject license amendment request is verbatim from TSTF-505, Revision 2.

That is, a loss of safety function exists when, assuming no concurrent single failure, no concurrent loss of offsite power, or no concurrent loss of onsite diesel generators, a safety function assumed in the accident analysis cannot be performed.

Examples of calculated RICTs are provided in Table E1-2 for each individual Action to which the RICT Program is proposed to apply. These calculations assume the SSC in question is the only SSC out-of-service, and thus the values in Table E1-2 are representative examples only.

Following RICT Program implementation, RICT calculations will be based upon the actual real-time maintenance configuration of the plant and the current revision of the PRA model

U.S. Nuclear Regulatory Commission Page 4 RA-23-0279 representing the as-built, as-operated condition of the plant, as required by NEI 06-09-A (Reference 2) and the NRC Safety Evaluation. Thus, in practice, RICT values may differ from the RICTs presented in Table E1-2.

U.S. Nuclear Regulatory Commission Page 5 RA-23-0279 Table E1 In-Scope TS LCO/Conditions to Corresponding PRA Functions Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.B One Manual 2 channels The Manual Reactor Trip ensures that 1 channel Not Explicitly Same Manual instrumentation is Reactor Trip the control room operator can initiate a not explicitly modeled, but channel inoperable reactor trip at any time by using either of TS condition can be Reactor Trip two reactor trip switches in the control represented through System (RTS) room. A Manual Reactor Trip either failure of human Instrumentation - accomplishes the same results as any action to manually trip Manual Reactor one of the automatic trip Functions. It reactor or failure of Trip (MODES 1 may be used by the reactor operator to individual reactor trip and 2) shut down the reactor whenever any breakers. Surrogate parameter is rapidly trending toward its representation is Trip Setpoint bounding, as RICT entry condition would not prevent manual reactor trip function or operation of the reactor trip breakers.

3.3.1.D One channel 4 channels The Power Range Neutron FluxHigh 2 channels Not Explicitly Same Neutron flux channels not inoperable trip Function ensures that protection is explicitly modeled, but TS provided, from all power levels, against a condition can be Reactor Trip positive reactivity excursion leading to represented by a generic System (RTS) DNB during power operations. These can analog channel failure, Instrumentation - be caused by rod withdrawal or which is an input into a 2 Power Range reductions in RCS temperature. out of 3 failure scheme of Neutron Flux - automatic RTS trip inputs.

High The surrogate channel failures are then inputs to both trains of RPS simultaneously. See response to NRC Audit QUESTION-06 (APLA -

RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

U.S. Nuclear Regulatory Commission Page 6 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.D One channel 4 channels The Power Range Neutron FluxHigh 2 channels Not Explicitly Same Neutron flux channels not inoperable Positive Rate trip Function ensures that explicitly modeled, but TS protection is provided against rapid condition can be Reactor Trip increases in neutron flux that are represented by a generic System (RTS) characteristic of an RCCA drive rod analog channel failure, Instrumentation - housing rupture and the accompanying which is an input into a 2 Power Range ejection of the RCCA. This Function out of 3 failure scheme of Neutron Flux complements the Power Range Neutron automatic RTS trip inputs.

Rate - High Flux-High and Low Setpoint trip The surrogate channel Positive Rate Functions to ensure that the criteria are failures are then inputs to met for a rod ejection from the power both trains of RPS range. simultaneously. See response to NRC Audit QUESTION-06 (APLA -

RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

3.3.1.E One channel 4 channels The LCO requirement for the Power 2 channels Not Explicitly Same Neutron flux channels not inoperable Range Neutron FluxLow trip Function explicitly modeled, but TS ensures that protection is provided condition can be Reactor Trip against a positive reactivity excursion represented by a generic System (RTS) from low power or subcritical conditions. analog channel failure, Instrumentation - which is an input into a 2 Power Range See Note 1.

out of 3 failure scheme of Neutron Flux - automatic RTS trip inputs.

Low The surrogate channel failures are then inputs to both trains of RPS simultaneously. See response to NRC Audit QUESTION-06 (APLA -

RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

U.S. Nuclear Regulatory Commission Page 7 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.E One channel 4 channels The Overtemperature T trip Function is 2 channels Not Explicitly Same Overtemperature inoperable provided to ensure that the design limit channels not explicitly DNBR is met. This trip Function also modeled, but TS Reactor Trip limits the range over which the condition can be System (RTS) Overpower T trip Function must provide represented by a generic Instrumentation - protection. The inputs to the analog channel failure, Overtemperature Overtemperature T trip include which is an input into a 2 T pressurizer pressure, coolant out of 3 failure scheme of temperature, axial power distribution, and automatic RTS trip inputs.

reactor power as indicated by loop T The surrogate channel assuming full reactor coolant flow. failures are then inputs to both trains of RPS simultaneously. See response to NRC Audit QUESTION-06 (APLA -

RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

3.3.1.E One channel 4 channels The Overpower T trip Function ensures 2 channels Not Explicitly Same Overpower channels not inoperable that protection is provided to ensure the explicitly modeled, but TS integrity of the fuel (i.e., no fuel pellet condition can be Reactor Trip melting and less than 1% cladding strain) represented by a generic System (RTS) under all possible overpower conditions. analog channel failure, Instrumentation - which is an input into a 2 Overpower T out of 3 failure scheme of automatic RTS trip inputs.

The surrogate channel failures are then inputs to both trains of RPS simultaneously. See response to NRC Audit QUESTION-06 (APLA -

RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

U.S. Nuclear Regulatory Commission Page 8 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.E One channel 4 channels The Pressurizer Pressure-High trip 2 channels Not Explicitly Same Pressurizer pressure high inoperable Function ensures that protection is channels not explicitly provided against over pressurizing the modeled, but TS Reactor Trip RCS. This trip Function operates in condition can be System (RTS) conjunction with the pressurizer relief and represented by a generic Instrumentation - safety valves to prevent RCS analog channel failure, Pressurizer overpressure conditions. which is an input into a 2 Pressure - High out of 3 failure scheme of automatic RTS trip inputs.

The surrogate channel failures are then inputs to both trains of RPS simultaneously. See response to NRC Audit QUESTION-06 (APLA -

RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

3.3.1.E One channel 4 channels per The SG Water Level-Low Low trip 2 channels Yes Same SSCs are modeled inoperable S/G Function ensures that protection is (per S/G) consistently with the TS provided against a loss of heat sink and scope and so can be Reactor Trip actuates the AFW System prior to directly evaluated by the System (RTS) uncovering the SG tubes. The SGs are CRMP.

Instrumentation - the heat sink for the reactor. In order to Steam Generator The success criteria in act as a heat sink, the SGs must contain the PRA are consistent (SG) Water a minimum amount of water. A narrow Level - Low Low with the design basis range low low level in any SG is criteria.

indicative of a loss of heat sink for the reactor.

U.S. Nuclear Regulatory Commission Page 9 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.M One channel 4 channels The Pressurizer PressureLow trip 2 channels Yes Same SSCs are modeled inoperable Function ensures that protection is consistently with the TS provided against violating the DNBR limit scope and so can be Reactor Trip due to low pressure. directly evaluated by the System (RTS) CRMP.

Instrumentation - See Note 2.

Pressurizer The success criteria in Pressure - Low the PRA are consistent with the design basis criteria.

3.3.1.M One channel 3 channels The Pressurizer Water Level-High trip 2 channels Not Explicitly Same Specific channel input is inoperable Function provides a backup signal for the not explicitly modeled.

Pressurizer PressureHigh trip and also The MNS PRA Reactor Trip provides protection conservatively model System (RTS) generic analog channel Instrumentation - against water relief through the pressurizer safety valves. failure, which is an input Pressurizer into a 2 out of 3 failure Water Level - See Note 2.

scheme of automatic RTS High trip inputs and can be used to conservatively represent the TS condition. The surrogate channel failures are then inputs to both trains of RPS simultaneously.

See response to NRC Audit QUESTION-06 (APLA - RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

U.S. Nuclear Regulatory Commission Page 10 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.M One channel 3 channels (3 The Reactor Coolant Flow-Low (Two 2 channels Not Explicitly Same Specific channel input is inoperable per loop) Loops) trip Function ensures that not explicitly modeled.

protection is provided against violating The MNS PRA Reactor Trip the DNBR limit due to low flow in two or conservatively model System (RTS) more RCS loops while avoiding reactor generic analog channel Instrumentation - trips due to normal variations in loop flow. failure, which is an input Reactor Coolant into a 2 out of 3 failure Flow - Low (Two See Note 4.

scheme of automatic RTS Loops) trip inputs and can be used to conservatively represent the TS condition. The surrogate channel failures are then inputs to both trains of RPS simultaneously.

See response to NRC Audit QUESTION-06 (APLA - RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

3.3.1.M One channel 4 channels (1 The Undervoltage RCPs reactor trip 2 channels Not Explicitly One of two SSPS train Undervoltage RCP inoperable per bus) Function ensures that protection is inputs channels not explicitly provided against violating the DNBR limit modeled, but TS Reactor Trip due to a loss of flow in two or more RCS condition can be System (RTS) loops. represented through a Instrumentation - failure of one of two trains Undervoltage See Note 2.

of automatic RTS trip RCPs inputs.

U.S. Nuclear Regulatory Commission Page 11 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.M One channel 4 channels (1 The Underfrequency RCPs reactor trip 2 channels Not Explicitly One of two SSPS train Underfrequency RCP inoperable per bus) Function ensures that protection is inputs channels not explicitly provided against violating the DNBR limit modeled, but TS Reactor Trip due to a loss of flow in two or more RCS condition can be System (RTS) loops from a major network frequency represented through a Instrumentation - disturbance. failure of one of two trains Underfrequency of automatic RTS trip RCPs See Note 2.

inputs.

3.3.1.O One Reactor 3 channels (3 The Reactor Coolant Flow-Low (Single 2 channels Not Explicitly Same Specific channel input is Coolant Flow - Low per loop) Loop) trip Function ensures that not explicitly modeled.

(Single Loop) protection is provided against violating The MNS PRA Reactor Trip channel inoperable the DNBR limit due to low flow in one or conservatively model System (RTS) more RCS loops, while avoiding reactor generic analog channel Instrumentation - trips due to normal variations in loop flow. failure, which is an input Reactor Coolant into a 2 out of 3 failure Flow - Low See Note 3.

scheme of automatic RTS (Single Loop) trip inputs and can be used to conservatively represent the TS condition. The surrogate channel failures are then inputs to both trains of RPS simultaneously.

See response to NRC Audit QUESTION-06 (APLA - RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

U.S. Nuclear Regulatory Commission Page 12 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.Q One Turbine Trip - 3 channels The Turbine Trip-Low Fluid Oil Pressure 2 channels Not Explicitly Same Specific channel input is Low Fluid Oil trip Function anticipates the loss of heat not explicitly modeled.

Pressure channel removal capabilities of the secondary The MNS PRA Reactor Trip inoperable system following a turbine trip. This trip conservatively model System (RTS) Function acts to minimize the generic analog channel Instrumentation - pressure/temperature transient on the failure, which is an input Turbine Trip - reactor. into a 2 out of 3 failure Low Fluid Oil See Note 3. scheme of automatic RTS

Pressure, trip inputs and can be used to conservatively represent the TS condition. The surrogate channel failures are then inputs to both trains of RPS simultaneously.

See response to NRC Audit QUESTION-06 (APLA - RICT) - [In-Scope LCOs and Corresponding PRA Modeling] for more details.

3.3.1.T One train 2 trains The SI Input from ESFAS ensures that if 1 train Yes Same SSCs are modeled inoperable a reactor trip has not already been consistently with the TS generated by the RTS, the ESFAS scope and so can be Reactor Trip automatic actuation logic will initiate a directly evaluated by the System (RTS) reactor trip upon any signal that initiates CRMP.

Instrumentation - SI.

Safety Injection The success criteria in (SI) Input from the PRA are consistent Engineered with the design basis Safety Features criteria.

Actuation System (ESFAS)

U.S. Nuclear Regulatory Commission Page 13 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.1.T One train 2 trains The LCO requirement for the RTBs and 1 train Yes Same SSCs are modeled inoperable Automatic Trip Logic ensures that means consistently with the TS are provided to interrupt the power to scope and so can be Reactor Trip allow the rods to fall into the reactor core. directly evaluated by the System (RTS) Each RTB is equipped with an CRMP.

Instrumentation - undervoltage coil and a shunt trip coil to RTS Automatic The success criteria in trip the breaker open when needed. Each the PRA are consistent Trip Logic train RTB has a bypass breaker to allow with the design basis testing of the trip breaker while the unit is criteria.

at power. The reactor trip signals generated by the RTS Automatic Trip Logic cause the RTBs and associated bypass breakers to open and shut down the reactor.

3.3.1.U One RTB train 2 trains This trip Function applies to the RTBs 1 train Yes Same SSCs are modeled inoperable exclusive of individual trip mechanisms. consistently with the TS The LCO requires two OPERABLE trains scope and so can be Reactor Trip of trip breakers. A trip breaker train directly evaluated by the System (RTS) consists of all trip breakers associated CRMP.

Instrumentation - with a single RTS logic train that are Reactor Trip The success criteria in racked in, closed, and capable of the PRA are consistent Breakers (RTBs) supplying power to the CRD System. with the design basis Thus, the train may consist of the main criteria.

breaker, bypass breaker, or main breaker and bypass breaker, depending upon the system configuration. Two OPERABLE trains ensure no single random failure can disable the RTS trip capability.

See Note 5.

3.3.1.Y One trip Undervoltage OPERABILITY of both trip mechanisms One trip Yes Same SSCs are modeled mechanism trip mechanism on each breaker ensures that no single mechanism consistently with the TS inoperable for one and Shunt trip trip mechanism failure will prevent scope and so can be Reactor Trip RTB mechanism per opening any breaker on a valid signal. directly evaluated by the System (RTS) RTB (Undervoltage CRMP.

Instrumentation - trip or Shunt Reactor Trip Trip) The success criteria in Breaker (2 per train) the PRA are consistent Undervoltage with the design basis and Shunt Trip criteria.

Mechanisms

U.S. Nuclear Regulatory Commission Page 14 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.B One channel or 2 channels The LCO requires one channel per train 1 channel Not Explicitly Same Switches and instruments train inoperable to be OPERABLE. The operator can not explicitly modeled. An initiate SI at any time by using either of Operator action failure to ESFAS two switches in the control room. This manually initiate SI can Instrumentation action will cause actuation of all be used to conservatively

- Safety Injection components in the same manner as any represent the function.

(Manual of the automatic actuation signals. The The surrogate is Initiation) LCO for the Manual Initiation Function inherently conservative ensures the proper amount of as it fails manual initiation redundancy is maintained in the manual of SI entirely while TS ESFAS actuation circuitry to ensure the condition does not fail the operator has manual ESFAS initiation function.

capability.

3.3.2.B One channel or 2 channels Containment Isolation provides isolation 1 channel Not Explicitly Generally same, but Manual phase A isolation train inoperable of the containment atmosphere, and all surrogate assumes is not explicitly modeled process systems that penetrate failure of containment in the PRA. Failure to ESFAS containment, from the environment. This isolate containment can Instrumentation Function is necessary to prevent or limit be conservatively

- Containment the release of radioactivity to the represented through Isolation (Phase environment in the event of a large break containment bypass.

A Isolation - LOCA.

Manual Initiation)

Manual Phase A Containment Isolation is actuated by either of two switches in the control room. Either switch actuates both trains

U.S. Nuclear Regulatory Commission Page 15 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.B One channel or 1 channel per The Phase B signal isolates CCW and 1 train Not Explicitly Generally same, but Phase B isolation is not train inoperable train (2 trains) NSWS. This occurs at a relatively high surrogate assumes explicitly modeled in the containment pressure that is indicative of failure of containment PRA. Failure to isolate ESFAS a large break LOCA or an SLB. For these containment can be Instrumentation events, forced circulation using the RCPs conservatively

- Containment is no longer desirable. Isolating the CCW represented through Isolation (Phase and NSWS at the higher pressure does containment bypass.

B Isolation - not pose a challenge to the containment Manual Initiation) boundary because the CCW System and NSWS are closed loops inside containment. Manual and automatic initiation of Phase B containment isolation must be OPERABLE in MODES 1, 2, and 3, when there is a potential for an accident to occur. Phase B Containment Isolation is accomplished by Manual Initiation, Automatic Actuation Logic and Actuation Relays, and by Containment Pressure channels The Containment Pressure trip of Phase B Containment Isolation is energized to trip in order to minimize the potential of spurious trips that may damage the RCPs.

3.3.2.C One train 2 trains This LCO requires two trains to be 1 train Yes Same SSCs are modeled inoperable OPERABLE. Actuation logic consists of consistently with the TS all circuitry housed within the actuation scope and so can be ESFAS subsystems, including the initiating relay directly evaluated by the Instrumentation contacts responsible for actuating the CRMP.

- Safety Injection ESF equipment. Manual and automatic (Automatic The success criteria in initiation of SI must be OPERABLE in the PRA are consistent Actuation Logic MODES 1, 2, and 3. In these MODES, and Actuation with the design basis there is sufficient energy in the primary criteria.

Relays) and secondary systems to warrant automatic initiation of ESF systems.

U.S. Nuclear Regulatory Commission Page 16 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.C One train 2 trains This LCO requires two trains to be 1 train Yes Same SSCs are modeled inoperable OPERABLE. Actuation logic consists of consistently with the TS all circuitry housed within the actuation scope and so can be ESFAS subsystems, including the initiating relay directly evaluated by the Instrumentation contacts responsible for actuating the CRMP.

- Containment equipment. Manual and automatic Isolation (Phase The success criteria in initiation of Phase A Containment the PRA are consistent A Isolation - Isolation must be OPERABLE in MODES Automatic with the design basis 1, 2, and 3, when there is a potential for criteria.

Actuation Logic an accident to occur. Phase A and Actuation Containment Isolation is also initiated by Relays) all Functions that initiate SI. The Phase A Containment Isolation requirements for these Functions are the same as the requirements for their SI function.

3.3.2.C One train 2 trains The Phase B signal isolates CCW and 1 train Not Explicitly PRA success criteria for Phase B isolation aspects inoperable NSWS. This occurs at a relatively high chosen surrogate events are not explicitly modeled containment pressure that is indicative of is one of two trains in the PRA. Surrogate ESFAS a large break LOCA or an SLB. For these mapping which fails train Instrumentation events, forced circulation using the RCPs inputs to containment

- Containment is no longer desirable. Isolating the CCW isolation can be used to Isolation (Phase and NSWS at the higher pressure does conservatively represent B Isolation - not pose a challenge to the containment the TS condition.

Automatic boundary because the CCW System and Actuation Logic NSWS are closed loops inside and Actuation containment. Manual and automatic Relays) initiation of Phase B containment isolation must be OPERABLE in MODES 1, 2, and 3, when there is a potential for an accident to occur. Phase B Containment Isolation is accomplished by Manual Initiation, Automatic Actuation Logic and Actuation Relays, and by Containment Pressure channels. The Containment Pressure trip of Phase B Containment Isolation is energized to trip in order to minimize the potential of spurious trips that may damage the RCPs.

U.S. Nuclear Regulatory Commission Page 17 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.D One channel 3 channels This signal provides protection against 2 channels Yes Same SSCs are modeled inoperable the following accidents: consistently with the TS

• SLB inside containment; scope and so can be ESFAS directly evaluated by the Instrumentation

• LOCA; and CRMP.

- Safety Injection

• Feed line break inside containment.

(Containment The success criteria in Containment Pressure-High provides no the PRA are consistent Pressure - High) input to any control functions. Thus, three with the design basis OPERABLE channels are sufficient to criteria.

satisfy protective requirements with a two-out-of-three logic.

3.3.2.D One channel 4 channels This signal provides protection against 2 channels Yes Same SSCs are modeled inoperable the following accidents: consistently with the TS

• Inadvertent opening of a steam scope and so can be ESFAS directly evaluated by the Instrumentation generator (SG) relief or safety valve; CRMP.

- Safety

• SLB; Injection The success criteria in

• A spectrum of rod cluster control (Pressurizer the PRA are consistent assembly ejection accidents (rod Pressure - Low) with the design basis ejection);

criteria.

• Inadvertent opening of a pressurizer relief or safety valve;

• LOCAs; and

• SG Tube Rupture.

Pressurizer pressure provides both control and protection functions: input to the Pressurizer Pressure Control System, reactor trip, and SI. Therefore, the actuation logic must be able to withstand both an input failure to control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. Thus, four OPERABLE channels are required to satisfy the requirements with a two-out-of-four logic.

U.S. Nuclear Regulatory Commission Page 18 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.D One channel 3 per steam line Steam Line Pressure-Low provides 2 per steam Not explicitly Instrumentation not Instrumentation is not inoperable closure of the MSIVs in the event of an line explicitly modeled, but explicitly modeled.

SLB to maintain three unfaulted SGs as a PRA models cooldown Surrogate mapping which ESFAS heat sink for the reactor and to limit the on three un-faulted SGs assumes one train of Instrumentation mass and energy release to containment. ESFAS is inoperable can

- Steam Line This Function provides closure of the be used to conservatively isolation (Steam MSIVs in the event of a feed line break to represent the TS Line Pressure - ensure a supply of steam for the turbine condition.

Low) driven AFW pump. Steam Line Pressure-Low Function must be OPERABLE in MODES 1, 2, and 3 (above P-11), with any main steam valve open, when a secondary side break or stuck open valve could result in the rapid depressurization of the steam lines.

See Notes 6 and 7.

3.3.2.D One channel 3 per S/G This signal provides protection against 2 per S/G Yes Same SSCs are modeled inoperable excessive feedwater flow. The ESFAS consistently with the TS SG water level instruments provide input scope and so can be ESFAS to the SG Water Level Control System. directly evaluated by the Instrumentation Therefore, the actuation logic must be CRMP.

- Turbine Trip able to withstand both an input failure to and Feedwater The success criteria in the control system (which may then the PRA are consistent Isolation require the protection function actuation)

(Feedwater with the design basis and a single failure in the other channels criteria.

Isolation - SG providing the protection function Water Level - actuation. Only three protection channels High High (P- are necessary to satisfy the protective 14)) requirements. The setpoints are based on percent of narrow range instrument span.

See Note 8.

U.S. Nuclear Regulatory Commission Page 19 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.D One channel 4 per S/G SG Water Level-Low Low provides 2 per S/G Yes Same SSCs are modeled inoperable protection against a loss of heat sink. A consistently with the TS feed line break, inside or outside of scope and so can be ESFAS containment, or a loss of MFW, would directly evaluated by the Instrumentation result in a loss of SG water level. SG CRMP.

- Auxiliary Water Level-Low Low provides input to Feedwater (SG The success criteria in the SG Level Control System. Therefore, the PRA are consistent Water Level - the actuation logic must be able to Low Low) with the design basis withstand both an input failure to the criteria.

control system which may then require a protection function actuation and a single failure in the other channels providing the protection function actuation. Thus, four OPERABLE channels are required to satisfy the requirements with two-out-of-four logic. The setpoints are based on percent of narrow range instrument span.

SG Water Level - Low Low in any operating SG will cause the motor driven AFW pumps to start. The system is aligned so that upon a start of the pump, water immediately begins to flow to the SGs. SG Water Level - Low Low in any two operating SGs will cause the turbine driven pumps to start.

U.S. Nuclear Regulatory Commission Page 20 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.D One channel 3 channels per A loss of power to the service buses will 2 channels per Not Explicitly Same Bus channels are not inoperable bus be accompanied by a loss of reactor bus explicitly modeled.

coolant pumping power and the Surrogate representation ESFAS subsequent need for some method of through SBO relays Instrumentation decay heat removal. The loss of power is provide equivalent risk

- Auxiliary detected by a voltage drop on each impact by failing the start Feedwater essential service bus. Loss of power to signals to the pumps.

(Station Blackout either essential service bus will start the

- Loss of voltage) turbine driven and motor driven AFW pumps to ensure that at least two SGs contain enough water to serve as the heat sink for reactor decay heat and sensible heat removal following the reactor trip. The turbine driven pump does not start on a loss of power coincident with a SI signal. Function must be OPERABLE in MODES 1, 2, and 3 to ensure that the SGs remain the heat sink for the reactor.

3.3.2.D One channel 3 channels per A degraded voltage to the service buses 2 channels per Not Explicitly Same Bus channels are not inoperable bus will be accompanied by a loss of reactor bus explicitly modeled.

coolant pumping power and the Surrogate representation ESFAS subsequent need for some method of through SBO relays Instrumentation decay heat removal. The degraded provide equivalent risk

- Auxiliary voltage is detected by a voltage drop on impact by failing the start Feedwater each essential service bus. Degraded signals to the pumps.

(Station Blackout voltage to either essential service bus will

- Degraded start the turbine driven and motor driven voltage)

AFW pumps to ensure that at least two SGs contain enough water to serve as the heat sink for reactor decay heat and sensible heat removal following the reactor trip. The turbine driven pump does not start on a loss of power coincident with a SI signal. Function must be OPERABLE in MODES 1, 2, and 3 to ensure that the SGs remain the heat sink for the reactor.

U.S. Nuclear Regulatory Commission Page 21 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.F One channel or 2 trains Isolation of the main steam lines provides 1 train Not Explicitly Isolate ruptured steam Manual steam line train inoperable protection in the event of an SLB inside line, limiting blowdown to isolation is not explicitly or outside containment. Rapid isolation of 1 SG modeled. Surrogate ESFAS the steam lines will limit the steam break representation through Instrumentation accident to the blowdown from one SG, failure of MSIVs to isolate

- Steam Line at most. For an SLB upstream of the is used as a conservative isolation (Manual main steam isolation valves (MSIVs), surrogate to represent the Initiation) inside or outside of containment, closure TS condition.

(System) of the MSIVs limits the accident to the blowdown from only the affected SG. For an SLB downstream of the MSIVs, closure of the MSIVs terminates the accident as soon as the steam lines depressurize. Steam Line Isolation also mitigates the effects of a feed line break and ensures a source of steam for the turbine driven AFW pump during a feed line break. Manual initiation of Steam Line Isolation can be accomplished from the control room. There are two system level switches in the control room and either switch can initiate action to immediately close all MSIVs.

See Note 7.

3.3.2.F One channel or 1 per train, 2 The P-4 interlock is enabled when a 1 train Not Explicitly PRA models manual P-4 interlocks not train inoperable trains reactor trip breaker (RTB) and its control of safety injection explicitly modeled.

associated bypass breaker is open. and associated master Surrogate representation ESFAS Operators are able to reset SI 60 relays to initiate SI when through failure of human Instrumentation seconds after initiation. If a P-4 is present necessary and to control action to manually

- ESFAS when SI is reset, subsequent automatic inadvertent SI. actuate safety injection is Interlocks SI initiation will be blocked until the RTBs used to represent the TS (Reactor Trip, P- have been manually closed. This condition..

4) Function allows operators to take manual control of SI systems after the initial phase of injection is complete while avoiding multiple SI initiations.

See Note 9.

U.S. Nuclear Regulatory Commission Page 22 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.H One train 2 trains Isolation of the main steam lines provides 1 train Not Explicitly Same Automatic actuation inoperable protection in the event of an SLB inside instrumentation is not or outside containment. Rapid isolation of explicitly modeled.

ESFAS the steam lines will limit the steam break Surrogate representation Instrumentation accident to the blowdown from one SG, through failure of MSIVs

- Steam Line at most. For an SLB upstream of the to isolate conservatively isolation main steam isolation valves (MSIVs), represents TS condition.

(Automatic inside or outside of containment, closure Actuation Logic of the MSIVs limits the accident to the and Actuation blowdown from only the affected SG. For Relays) an SLB downstream of the MSIVs, closure of the MSIVs terminates the accident as soon as the steam lines depressurize. Steam Line Isolation also mitigates the effects of a feed line break and ensures a source of steam for the turbine driven AFW pump during a feed line break. This LCO requires two trains to be OPERABLE. Actuation logic consists of all circuitry housed within the actuation subsystems, including the initiating relay contacts responsible for actuating the equipment. Manual and automatic initiation of steam line isolation must be OPERABLE in MODES 1, 2, and 3 when there is sufficient energy in the RCS and SGs to have an SLB or other accident.

See Note 7.

U.S. Nuclear Regulatory Commission Page 23 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.H One train 2 trains The primary functions of the Turbine Trip 1 train Not Explicitly FW isolate and auxiliary Instrumentation is not inoperable and Feedwater Isolation signals are to feedwater system explicitly modeled.

prevent damage to the turbine due to provides secondary side Surrogate representation ESFAS water in the steam lines, stop the cooling through failure of auxiliary Instrumentation excessive flow of feedwater into the SGs, feedwater is used to

- Turbine Trip and to limit the energy released into represent the TS and Feedwater containment. These Functions are condition, as a failure of Isolation necessary to mitigate the effects of a high feedwater to isolate (Feedwater water level in the SGs, which could result would prevent auxiliary Isolation - in carryover of water into the steam lines feedwater from operating Automatic and excessive cooldown of the primary as required.

Actuation Logic system. The SG high water level is due to and Actuation excessive feedwater flows. Feedwater Relays) isolation serves to limit the energy released into containment upon a feedwater line or steam line break inside containment. This LCO requires two trains to be OPERABLE. Actuation logic consists of all circuitry housed within the actuation subsystems, including the initiating relay contacts responsible for actuating the equipment.

See Note 8.

U.S. Nuclear Regulatory Commission Page 24 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.H One train 2 trains The AFW System is designed to provide 1 train Not Explicitly Same Automatic actuation is not inoperable a secondary side heat sink for the reactor modeled. Surrogate in the event that the MFW System is not representation through ESFAS available. The system has two motor AFW start failures can Instrumentation driven pumps and a turbine driven pump, conservatively represent

- Auxiliary making it available during normal and the TS condition.

Feedwater accident operation. The normal source of (Automatic water for the AFW System is the non-Actuation Logic safety related AFW Storage Tank (Water and Actuation Tower). A low suction pressure to the Relays) AFW pumps will automatically realign the pump suctions to the Nuclear Service Water System (NSWS)(safety related).

The AFW System is aligned so that upon a pump start, flow is initiated to the respective SGs immediately. This LCO requires two trains to be OPERABLE.

Actuation logic consists of all circuitry housed within the actuation subsystems, including the initiating relay contacts responsible for actuating the equipment.

U.S. Nuclear Regulatory Commission Page 25 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.I One train 2 trains The primary functions of the Turbine Trip 1 train Not Explicitly FW isolate and auxiliary Instrumentation is not inoperable and Feedwater Isolation signals are to feedwater system explicitly modeled.

prevent damage to the turbine due to provides secondary side Surrogate representation ESFAS water in the steam lines, stop the cooling through failure of auxiliary Instrumentation excessive flow of feedwater into the SGs, feedwater is used to

- Turbine Trip and to limit the energy released into represent the TS and Feedwater containment. These Functions are condition, as a failure of Isolation necessary to mitigate the effects of a high feedwater to isolate (Turbine Trip - water level in the SGs, which could result would prevent auxiliary Automatic in carryover of water into the steam lines feedwater from operating Actuation Logic and excessive cooldown of the primary as required.

and Actuation system. The SG high water level is due to Relays) excessive feedwater flows. Feedwater isolation serves to limit the energy released into containment upon a feedwater line or steam line break inside containment. This LCO requires two trains to be OPERABLE. Actuation logic consists of all circuitry housed within the actuation subsystems, including the initiating relay contacts responsible for actuating the equipment.

3.3.2.J One channel 3 per S/G This signal prevents damage to the 2 per S/G Yes Same SSCs are modeled inoperable turbine due to water in the steam lines. consistently with the TS The ESFAS SG water level instruments scope and so can be ESFAS provide input to the SG Water Level directly evaluated by the Instrumentation Control System. Therefore, the actuation CRMP.

- Turbine Trip logic must be able to withstand both an and Feedwater The success criteria in input failure to the control system (which the PRA are consistent Isolation may then require the protection function (Turbine Trip - with the design basis actuation) and a single failure in the other criteria.

SG Water Level - channels providing the protection function High High (P- actuation. Only three protection channels 14)) are necessary to satisfy the protective requirements. The setpoints are based on percent of narrow range instrument span.

U.S. Nuclear Regulatory Commission Page 26 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.3.2.J One channel 4 channels (1 This signal provides protection against 2 channels Not Explicitly FW isolate and auxiliary Instrumentation is not inoperable per loop) excessive cooldown, which could feedwater system explicitly modeled.

subsequently introduce a positive provides secondary side Surrogate representation ESFAS reactivity excursion after a plant trip. cooling through failure of auxiliary Instrumentation There are four channels of RCS Tavg- feedwater is used to

- Turbine Trip Low (one per loop), with a two-out-of-four represent the TS and Feedwater logic required coincident with a reactor condition, as a failure of Isolation trip signal (P-4) to initiate a feedwater feedwater to isolate (Feedwater isolation. would prevent auxiliary Isolation - Tavg- feedwater from operating Low) See Note 8.

as required.

3.3.5.A One or more 3 channels per The LCO for LOP DG start 2 channels per Yes Same SSCs are modeled Functions with one function per bus instrumentation requires that three function per consistently with the TS channel per bus channels per bus of both the loss of bus scope and so can be Loss of Power inoperable voltage and degraded voltage Functions directly evaluated by the (LOP) Diesel shall be OPERABLE in MODES 1, 2, 3, CRMP.

Generator (DG) and 4 when the LOP DG start Start The success criteria in instrumentation supports safety systems the PRA are consistent Instrumentation associated with the ESFAS. with the design basis criteria.

3.3.5.B One or more 3 channels per The LCO for LOP DG start 2 channels per Yes Same SSCs are modeled Functions with two function per bus instrumentation requires that three function per consistently with the TS or more channels channels per bus of both the loss of bus scope and so can be Loss of Power per bus inoperable. voltage and degraded voltage Functions directly evaluated by the (LOP) Diesel shall be OPERABLE in MODES 1, 2, 3, CRMP.

Generator (DG) and 4 when the LOP DG start Start The success criteria in instrumentation supports safety systems the PRA are consistent Instrumentation associated with the ESFAS. with the design basis criteria.

U.S. Nuclear Regulatory Commission Page 27 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.4.11.C One Train A PORV 3 Pzr PORVs The LCO requires the PORVs and their 1 Pzr PORV Yes Same, for non-ATWS SSCs are modeled inoperable and not (1 A train, 2 B associated block valves to be scenarios. consistently with the TS capable of being train) OPERABLE for manual operation to PRA requires 2 of 3 or 3 scope and so can be Pressurizer manually cycled mitigate the effects associated with an directly evaluated by the Power Operated of 3 PORVs for ATWS SGTR. sequences. CRMP.

Relief Valves (PORVs) By maintaining two PORVs, one from The success criteria in each train, and their associated block the PRA are consistent valves OPERABLE, the single failure with the design basis criterion is satisfied. Three PORVs are criteria for non-ATWS required to be OPERABLE to meet RCS scenarios, and more pressure boundary requirements. The restrictive for ATWS.

block valves are available to isolate the flow path through either a failed open PORV or a PORV with excessive leakage. Satisfying the LCO helps minimize challenges to fission product barriers.

3.4.11.D Two Train B 3 Pzr PORVs The LCO requires the PORVs and their 1 Pzr PORV Yes Same, for non-ATWS SSCs are modeled PORVs inoperable (1 A train, 2 B associated block valves to be scenarios. consistently with the TS and not capable of train) OPERABLE for manual operation to PRA requires 2 of 3 or 3 scope and so can be Pressurizer being manually mitigate the effects associated with an directly evaluated by the Power Operated of 3 PORVs for ATWS cycled SGTR. sequences. CRMP.

Relief Valves (PORVs) By maintaining two PORVs, one from The success criteria in each train, and their associated block the PRA are consistent valves OPERABLE, the single failure with the design basis criterion is satisfied. Three PORVs are criteria for non-ATWS required to be OPERABLE to meet RCS scenarios, and more pressure boundary requirements. The restrictive for ATWS.

block valves are available to isolate the flow path through either a failed open PORV or a PORV with excessive leakage. Satisfying the LCO helps minimize challenges to fission product barriers.

U.S. Nuclear Regulatory Commission Page 28 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.4.11.H One Train A block 3 block valves The LCO requires the PORVs and their 1 block valve Yes Same, for non-ATWS SSCs are modeled valve inoperable (one per associated block valves to be associated scenarios. consistently with the TS PORV) OPERABLE for manual operation to with an PRA requires 2 of 3 or 3 scope and so can be Pressurizer mitigate the effects associated with an OPERABLE directly evaluated by the Power Operated of 3 PORVs for ATWS SGTR. PORV sequences. CRMP.

Relief Valves (PORVs) By maintaining two PORVs, one from The success criteria in each train, and their associated block the PRA are consistent valves OPERABLE, the single failure with the design basis criterion is satisfied. Three PORVs are criteria for non-ATWS required to be OPERABLE to meet RCS scenarios, and more pressure boundary requirements. The restrictive for ATWS.

block valves are available to isolate the flow path through either a failed open PORV or a PORV with excessive leakage. Satisfying the LCO helps minimize challenges to fission product barriers.

3.4.11.I Two Train B block 3 block valves The LCO requires the PORVs and their 1 block valve Yes Same, for non-ATWS SSCs are modeled valves inoperable (one per associated block valves to be associated scenarios. consistently with the TS PORV) OPERABLE for manual operation to with an PRA requires 2 of 3 or 3 scope and so can be Pressurizer mitigate the effects associated with an OPERABLE directly evaluated by the Power Operated of 3 PORVs for ATWS SGTR. PORV sequences. CRMP.

Relief Valves (PORVs) By maintaining two PORVs, one from The success criteria in each train, and their associated block the PRA are consistent valves OPERABLE, the single failure with the design basis criterion is satisfied. Three PORVs are criteria for non-ATWS required to be OPERABLE to meet RCS scenarios, and more pressure boundary requirements. The restrictive for ATWS.

block valves are available to isolate the flow path through either a failed open PORV or a PORV with excessive leakage. Satisfying the LCO helps minimize challenges to fission product barriers

U.S. Nuclear Regulatory Commission Page 29 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.4.11.J One Train B PORV 3 Pzr PORVs The LCO requires the PORVs and their One Pzr Yes Same, for non-ATWS SSCs are modeled inoperable and not and associated associated block valves to be PORV and scenarios. consistently with the TS capable of being block valves OPERABLE for manual operation to associated PRA requires 2 of 3 or 3 scope and so can be Pressurizer manually cycled mitigate the effects associated with an block valve directly evaluated by the Power Operated of 3 PORVs for ATWS AND The other SGTR. sequences. CRMP.

Relief Valves Train B block valve (PORVs) By maintaining two PORVs, one from The success criteria in inoperable. each train, and their associated block the PRA are consistent valves OPERABLE, the single failure with the design basis criterion is satisfied. Three PORVs are criteria for non-ATWS required to be OPERABLE to meet RCS scenarios, and more pressure boundary requirements. The restrictive for ATWS.

block valves are available to isolate the flow path through either a failed open PORV or a PORV with excessive leakage. Satisfying the LCO helps minimize challenges to fission product barriers.

U.S. Nuclear Regulatory Commission Page 30 RA-23-0279 3.5.2.A One or more trains 2 ECCS trains In MODES 1, 2, and 3, two independent 1 ECCS Train Yes Same SSCs are modeled inoperable AND At (and redundant) ECCS trains are consistently with the TS least 100% of the required to ensure that sufficient ECCS scope and so can be Emergency Core ECCS flow flow is available, assuming a single directly evaluated by the Cooling System equivalent to a failure affecting either train. Additionally, CRMP.

(ECCS) - single OPERABLE individual components within the ECCS Operating The success criteria in ECCS train trains may be called upon to mitigate the the PRA are consistent available. consequences of other transients and with the design basis accidents. In MODES 1, 2, and 3, an criteria.

ECCS train consists of a centrifugal charging subsystem, an SI subsystem, and an RHR subsystem. Each train includes the piping, instruments, and controls to ensure an OPERABLE flow path capable of taking suction from the RWST upon an SI signal and automatically transferring suction to the containment sump. With one or more trains inoperable and at least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available, the inoperable components must be returned to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is based on an NRC reliability evaluation and is a reasonable time for repair of many ECCS components. The LCO requires the OPERABILITY of a number of independent subsystems. Due to the redundancy of trains and the diversity of subsystems, the inoperability of one component in a train does not render the ECCS incapable of performing its function. Neither does the inoperability of two different components, each in a different train, necessarily result in a loss of function for the ECCS. The intent of this Condition is to maintain a combination of equipment such that 100% of the ECCS flow equivalent to a single OPERABLE ECCS train remains available. This allows increased flexibility in plant operations under circumstances when components in opposite trains are inoperable.

U.S. Nuclear Regulatory Commission Page 31 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.6.2.C One or more 2 Doors per With one or more air locks inoperable for 1 door per Air Yes Same SSCs are modeled containment air Airlock reasons other than those described in Lock consistently with the TS locks inoperable for Condition A or B, Required Action C.1 scope and so can be Containment Air reasons other than requires action to be initiated immediately directly evaluated by the Locks Condition A or B to evaluate previous combined leakage CRMP.

rates using current air lock test results. The success criteria in An evaluation is acceptable, since it is the PRA are consistent overly conservative to immediately with the design basis declare the containment inoperable if criteria.

both doors in an air lock have failed a seal test or if the overall air lock leakage is not within limits. In many instances (e.g., only one seal per door has failed),

containment remains OPERABLE, yet only 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> (per LCO 3.6.1) would be provided to restore the air lock door to OPERABLE status prior to requiring a plant shutdown. In addition, even with both doors failing the seal test, the overall containment leakage rate can still be within limits.

U.S. Nuclear Regulatory Commission Page 32 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.6.3.A Note: Only 2 containment The containment isolation valves form 1 containment Not Explicitly Same Not all containment applicable to isolation valves part of the containment pressure isolation valve isolation paths are penetration flow boundary and provide a means for fluid explicitly modeled. For Containment paths with two penetrations not serving accident those cases where Isolation Valves containment consequence limiting systems to be isolation is not explicitly isolation valves. provided with two isolation barriers that modeled, failure to isolate One or more are closed on a containment isolation containment can be penetration flow signal. These isolation devices are either conservatively paths with one passive or active (automatic). Manual represented through containment valves, de-activated automatic valves containment bypass.

isolation valve secured in their closed position (including inoperable except check valves with flow through the valve for purge valve or secured), blind flanges, and closed reactor building systems are considered passive devices.

bypass leakage not Check valves, or other automatic valves within limit. designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system.

These barriers (typically containment isolation valves) make up the Containment Isolation System.

U.S. Nuclear Regulatory Commission Page 33 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.6.3.C Note: Only 2 containment The containment isolation valves form Closed system Not Explicitly Same Not all containment applicable to boundaries (1 part of the containment pressure intact isolation paths are penetration flow containment boundary and provide a means for fluid explicitly modeled. For Containment paths with only one isolation valve penetrations not serving accident those cases where Isolation Valves containment and closed consequence limiting systems to be isolation is not explicitly isolation valve and system provided with two isolation barriers that modeled, failure to isolate a closed system. are closed on a containment isolation containment can be One or more signal. These isolation devices are either conservatively penetration flow passive or active (automatic). Manual represented through paths with one valves, de-activated automatic valves containment bypass.

containment secured in their closed position (including isolation valve check valves with flow through the valve inoperable. secured), blind flanges, and closed systems are considered passive devices.

Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system.

These barriers (typically containment isolation valves) make up the Containment Isolation System.

U.S. Nuclear Regulatory Commission Page 34 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.6.6.A One containment 2 trains During a DBA, one train of Containment 1 train Yes Same SSCs are modeled spray train Spray System is required to provide the consistently with the TS inoperable heat removal capability assumed in the scope and so can be Containment safety analyses. To ensure that this directly evaluated by the Spray System requirement is met, two containment CRMP.

(Ice Condenser) spray trains must be OPERABLE with The success criteria in power from two safety related, the PRA are consistent independent power supplies. Therefore, with the design basis in the event of an accident, at least one criteria.

train operates.

Each Containment Spray System includes a spray pump, headers, valves, heat exchangers, nozzles, piping, instruments, and controls to ensure an OPERABLE flow path capable of being manually initiated to take suction from the Containment Sump and delivering it to the Containment Spray Rings.

Management of gas voids is important to Containment Spray System OPERABILITY.

U.S. Nuclear Regulatory Commission Page 35 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.6.9.A One HMS train 2 trains Two HMS trains must be OPERABLE 1 train Yes Same SSCs are modeled inoperable. with power from two independent, safety consistently with the TS related power supplies. For this unit, an scope and so can be Hydrogen OPERABLE HMS train consists of 34 of directly evaluated by the Mitigation 35 ignitors energized on the train. CRMP.

System (HMS) Operation with at least one HMS train (Ice Condenser) The success criteria in ensures that the hydrogen in containment the PRA are consistent can be burned in a controlled manner. with the design basis Unavailability of both HMS trains could criteria.

lead to hydrogen buildup to higher concentrations, which could result in a violent reaction if ignited. The reaction could take place fast enough to lead to high temperatures and overpressurization of containment and, as a result, breach containment or cause containment leakage rates above those assumed in the safety analyses. Damage to safety related equipment located in containment could also occur.

The 7 day Completion Time is based on the low probability of the occurrence of a degraded core event that would generate hydrogen in amounts equivalent to a metal water reaction of 75% of the core cladding, the length of time after the event that operator action would be required to prevent hydrogen accumulation from exceeding this limit, and the low probability of failure of the OPERABLE HMS train. Alternative Required Action A.2, by frequent surveillances, provides assurance that the OPERABLE train continues to be OPERABLE.

U.S. Nuclear Regulatory Commission Page 36 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.6.9.B One containment 2 hydrogen Two HMS trains must be OPERABLE 1 hydrogen Not Explicitly Same Hydrogen igniters per region with no igniters per with power from two independent, safety igniter per containment region are OPERABLE containment related power supplies. For this unit, an containment not explicitly modeled.

Hydrogen hydrogen ignitor region OPERABLE HMS train consists of 34 of region Surrogate modeling Mitigation 35 ignitors energized on the train. utilizing failure of a train System (HMS) Operation with at least one HMS train of HMS can represent the (Ice Condenser) ensures that the hydrogen in containment TS Condition.

can be burned in a controlled manner.

Unavailability of both HMS trains could lead to hydrogen buildup to higher concentrations, which could result in a violent reaction if ignited. The reaction could take place fast enough to lead to high temperatures and overpressurization of containment and, as a result, breach containment or cause containment leakage rates above those assumed in the safety analyses. Damage to safety related equipment located in containment could also occur.

Condition B is one containment region with no OPERABLE hydrogen ignitor.

Thus, while in Condition B, or in Conditions A and B simultaneously, there would always be ignition capability in the adjacent containment regions that would provide redundant capability by flame propagation to the region with no OPERABLE ignitors.

U.S. Nuclear Regulatory Commission Page 37 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.6.11.A One ARS train 2 trains he ARS is designed to assure the rapid 1 train Not Explicitly PRA models the Ice ARS is not explicitly inoperable return of air from the upper to the lower Condenser for scenarios modeled. Surrogate containment compartment after the initial which rely on ice modeling utilizing failure Air Return blowdown following a Design Basis condenser to prevent of the ice condenser can System (ARS) Accident (DBA). The return of this air to LERF represent the TS (Ice Condenser) the lower compartment and subsequent Condition.

recirculation back up through the ice condenser assists in cooling the containment atmosphere and limiting post accident pressure and temperature in containment to less than design values. Limiting pressure and temperature reduces the release of fission product radioactivity from containment to the environment in the event of a DBA. The ARS also promotes hydrogen dilution by mixing the hydrogen with containment atmosphere and distributing throughout the containment.

The ARS consists of two separate trains of equal capacity, each capable of meeting the design bases. Each train includes a 100% capacity air return fan and associated motor operated damper in the fan discharge line to the containment lower compartment

U.S. Nuclear Regulatory Commission Page 38 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.6.14.A NOTE: For this The divider This LCO establishes the minimum Bypass Not Explicitly PRA models the Ice Divider hatches and action, separate barrier consists equipment requirements to ensure that leakage, in the Condenser for scenarios doors are not explicitly Condition entry is of the operating the divider barrier performs its safety event of a which rely on ice modeled. Surrogate Divider Barrier allowed for each deck and function of ensuring that bypass leakage, DBA, does not condenser to prevent modeling utilizing failure Integrity (Ice personnel access associated in the event of a DBA, does not exceed exceed the LERF of the ice condenser can condenser) door or equipment seals, the bypass leakage assumed in the bypass represent the TS hatch. personnel accident analysis. Included are the leakage Condition.

One or more access doors, requirements that the personnel access assumed in personnel access and equipment doors and equipment hatches in the the accident doors or equipment hatches that divider barrier are OPERABLE and analysis hatches (other than separate the closed and that the divider barrier seal is one pressurizer or upper and properly installed and has not degraded one steam lower with time. An exception to the generator containment requirement that the doors be closed is enclosure hatch compartments. made to allow personnel transit entry addressed by through the divider barrier. The basis of Condition D) open this exception is the assumption that, for or inoperable, other personnel transit, the time during which a than for personnel door is open will be short (i.e., shorter transit entry. than the Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> for Condition A). The divider barrier functions with the ice condenser to limit the pressure and temperature that could be expected following a DBA.

U.S. Nuclear Regulatory Commission Page 39 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.7.2.A One MSIV Four MSIVs This LCO requires that four MSIVs in the MSIV on Yes Same SSCs are modeled inoperable in steam lines be OPERABLE. The MSIVs affected steam consistently with the TS MODE 1 are considered OPERABLE when the line closes or scope and so can be Main Steam isolation times are within limits, and they remaining 3 directly evaluated by the Isolation Valves close on an isolation actuation signal. MSIVs on CRMP.

(MSIVs) The accumulator air pressure must also unaffected The success criteria in be > 60 psig. steam lines the PRA are consistent This LCO provides assurance that the close with the design basis MSIVs will perform their design safety The design criteria.

function to mitigate the consequences of basis of the accidents that could result in offsite MSIVs is exposures comparable to the 10 CFR established by 100 limits or the NRC staff approved the licensing basis. containment With one MSIV inoperable in MODE 1, and SAFETY action must be taken to restore ANALYSES OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Some core response repairs to the MSIV can be made with the analyses for unit hot. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time is the large reasonable, considering the low steam line probability of an accident occurring break (SLB) during this time period that would require events, a closure of the MSIVs. discussed in the UFSAR, The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time is greater Section 6.2 .

than that normally allowed for The design containment isolation valves because the precludes the MSIVs are valves that isolate a closed blowdown of system penetrating containment. These more than one valves differ from other containment steam isolation valves in that the closed system generator.

provides an additional means for containment isolation.

U.S. Nuclear Regulatory Commission Page 40 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.7.5.A One steam supply 2 steam If one of the two steam supplies to the 1 steam Yes Same SSCs are modeled to turbine driven supplies to turbine driven AFW train is inoperable, or supply to consistently with the TS AFW pump turbine driven if a turbine driven pump is inoperable turbine driven scope and so can be Auxiliary inoperable AFW pump while in MODE 3 immediately following AFW pump directly evaluated by the Feedwater refueling, action must be taken to restore CRMP.

(AFW) System 3 trains AFW 1 train AFW pumps) the inoperable equipment to an pump The success criteria in OPERABLE status within 7 days. The 7 the PRA are consistent day Completion Time is reasonable, with the design basis based on the following reasons: criteria.

a. For the inoperability of a steam supply to the turbine driven AFW pump, the 7 day Completion Time is reasonable since there is a redundant steam supply line for the turbine driven pump.

b. For the inoperability of a turbine driven AFW pump while in MODE 3 immediately subsequent to a refueling, the 7 day Completion Time is reasonable due to the minimal decay heat levels in this situation.

c. For both the inoperability of a steam supply line to the turbine driven pump and an inoperable turbine driven AFW pump while in MODE 3 immediately following a refueling, the 7 day Completion Time is reasonable due to the availability of redundant OPERABLE motor driven AFW pumps; and due to the low probability of an event requiring the use of the turbine driven AFW pump.

Condition A is modified by a Note which limits the applicability of the Condition to when the unit has not entered MODE 2 following a refueling. Condition A allows the turbine-driven AFW pump to be inoperable for 7 days vice the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time in Condition B. This longer Completion Time is based on the reduced decay heat following refueling and prior to the reactor being critical.

U.S. Nuclear Regulatory Commission Page 41 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.7.5.B One AFW train 3 trains AFW With one of the required AFW trains 1 train of AFW Yes Same SSCs are modeled inoperable in (pump or flow path) inoperable in MODE consistently with the TS MODE 1, 2 or 3 for 1, 2, or 3 for reasons other than scope and so can be Auxiliary reasons other than Condition A, action must be taken to directly evaluated by the Feedwater Condition A. restore OPERABLE status within 72 CRMP.

(AFW) System hours. This Condition includes the loss of The success criteria in two steam supply lines to the turbine the PRA are consistent driven AFW pump. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with the design basis Completion Time is reasonable, based on criteria.

redundant capabilities afforded by the AFW System, time needed for repairs, and the low probability of a DBA occurring during this time period.

U.S. Nuclear Regulatory Commission Page 42 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.7.6.A One CCW train 2 trains The CCW System provides a heat sink 1 train Yes Adequate KC flow is SSCs are modeled inoperable for the removal of process and operating defined in the PRA as consistently with the TS heat from safety related components having a minimum of two scope and so can be Component during a Design Basis Accident (DBA) or KC pumps and one KC directly evaluated by the Cooling Water transient. During normal operation, the heat exchanger CRMP.

System (CCW) CCW System also provides this function available along with a The success criteria in for various nonessential components, as flow path to the loads the PRA are less well as the spent fuel storage pool. The restrictive than the design CCW System serves as a barrier to the basis criteria but reflect release of radioactive byproducts realistic modeling of the between potentially radioactive systems system in accordance and the Nuclear Service Water System with PRA technical (NSWS), and thus to the environment. adequacy requirements.

The CCW System is arranged as two independent, full capacity cooling loops, and has isolatable nonsafety related components. Each safety related train includes two pumps, surge tank, heat exchanger, piping, valves, and instrumentation. Each safety related train is powered from a separate bus. An open surge tank provides for expansion and contraction of the system. Both pumps in each train are automatically started on receipt of a safety injection or Station Blackout signal, and all nonessential components are isolated.

The CCW trains are independent of each other to the degree that each has separate controls and power supplies and the operation of one does not depend on the other. In the event of a DBA, one CCW train is required to provide the minimum heat removal capability assumed in the safety analysis for the systems to which it supplies cooling water. To ensure this requirement is met, two trains of CCW must be OPERABLE. At least one CCW train will operate assuming the worst case single active failure occurs coincident with a loss of offsite power.

U.S. Nuclear Regulatory Commission Page 43 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.7.7.A One NSWS train 2 trains Two NSWS trains are required to be 1 train Yes PRA success is defined SSCs are modeled inoperable OPERABLE to provide the required as the ability of the RN consistently with the TS redundancy to ensure that the system System to supply flow to scope and so can be Nuclear Service functions to remove post-accident heat essential header A and directly evaluated by the Water System loads, assuming that the worst case essential header B. CRMP.

(NSWS) single active failure occurs coincident The top events in the The success criteria in with the loss of offsite power. PRA consider flow from the PRA reflect realistic An NSWS train is considered the opposite unit RN as modeling of the system in OPERABLE during MODES 1, 2, 3, and well as the RV system to accordance with PRA 4 when: the essential headers. technical adequacy

a. The associated unit's pump is requirements.

OPERABLE; and

b. The associated piping, valves, and instrumentation and controls required to perform the safety related function are OPERABLE.

Portions of the NSWS system are shared between the two units. The shared portions of the system must be OPERABLE for each unit when that unit is in the MODE of Applicability. If a shared NSWS component becomes inoperable, or normal and emergency power to shared components become inoperable, then the Required Actions of this LCO must be entered independently for each unit that is in the MODE of applicability of the LCO.

U.S. Nuclear Regulatory Commission Page 44 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.8.1.A One LCO 3.8.1.a 2 offsite circuits Two qualified circuits between the offsite 1 offsite circuit Yes As needed to supply SSCs are modeled offsite circuit transmission network and the onsite or 1 supported functions consistently with the TS inoperable. Class 1E Electrical Power System and emergency scope and so can be AC Sources - separate and independent DGs for each diesel directly evaluated by the Operating train ensure availability of the required generator CRMP.

power to shut down the reactor and The success criteria in maintain it in a safe shutdown condition the PRA are consistent after an anticipated operational with the design basis occurrence (AOO) or a postulated DBA. criteria.

The loss of an electrical function does not go to core damage unless the supported equipment is required. Risk significant power dependencies are represented in the PRA as built, as operated.

3.8.1.B One LCO 3.8.1.b 2 EDGs Two qualified circuits between the offsite 1 offsite circuit Yes As needed to supply SSCs are modeled DG inoperable transmission network and the onsite or 1 supported functions consistently with the TS Class 1E Electrical Power System and emergency scope and so can be AC Sources - separate and independent DGs for each diesel directly evaluated by the Operating train ensure availability of the required generator CRMP.

power to shut down the reactor and The success criteria in maintain it in a safe shutdown condition the PRA are consistent after an anticipated operational with the design basis occurrence (AOO) or a postulated DBA. criteria.

The loss of an electrical function does not go to core damage unless the supported equipment is required. Risk significant power dependencies are represented in the PRA as built, as operated.

U.S. Nuclear Regulatory Commission Page 45 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.8.1.C One LCO 3.8.1.c Offsite circuit Condition C addresses the inoperability 1 train of Yes As needed to supply SSCs are modeled offsite circuit supply to of the LCO 3.8.1.c qualified offsite shared supported functions consistently with the TS inoperable. opposite Unit circuit(s) between the offsite transmission systems scope and so can be AC Sources - when supplying network and the opposite units Onsite supplied by directly evaluated by the Operating power to 1 train Essential Auxiliary Power System when offsite circuit CRMP.

of shared the LCO 3.8.1.c qualified offsite circuit(s) or EDG The success criteria in systems is necessary to supply power to a train of the PRA are consistent shared systems. The shared systems with the design basis are: NSWS, CRAVS, CRACWS and criteria.

ABFVES The loss of an electrical function does not go to core damage unless the supported equipment is required. Risk significant power dependencies are represented in the PRA as built, as operated.

3.8.1.E Two LCO 3.8.1.a 2 offsite circuits Condition E is entered when both offsite 1 offsite circuit Yes As needed to supply SSCs are modeled offsite circuits circuits required by LCO 3.8.1.a are or 1 EDG supported functions consistently with the TS inoperable OR One inoperable, or when the offsite circuit scope and so can be AC Sources - LCO 3.8.1.a offsite required by LCO 3.8.1.c and one offsite directly evaluated by the Operating circuit that provides circuit required by LCO 3.8.1.a are CRMP.

power to the concurrently inoperable, if the LCO The success criteria in NSWS, CRAVS, 3.8.1.a offsite circuit is credited with the PRA are consistent CRACWS and providing power to the NSWS, CRAVS, with the design basis ABFVES CRACWS and ABFVES. Condition E is criteria.

inoperable and one also entered when two offsite circuits LCO 3.8.1.c offsite required by LCO 3.8.1.c are inoperable. The loss of an electrical circuit inoperable function does not go to OR Two LCO core damage unless the 3.8.1.c offsite supported equipment is circuits inoperable. required. Risk significant power dependencies are represented in the PRA as built, as operated.

U.S. Nuclear Regulatory Commission Page 46 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.8.1.F One LCO 3.8.1.a 2 offsite circuits Pursuant to LCO 3.0.6, the Distribution 1 offsite circuit Yes As needed to supply SSCs are modeled offsite circuit 2 EDGs System ACTIONS would not be entered or 1 EDG supported functions consistently with the TS inoperable AND even if all AC sources to it were scope and so can be AC Sources - One LCO 3.8.1.b inoperable, resulting in deenergization. directly evaluated by the Operating DG inoperable Therefore, the Required Actions of CRMP.

Condition F are modified by a Note to The success criteria in indicate that when Condition F is entered the PRA are consistent with no AC source to any train, the with the design basis Conditions and Required Actions for LCO criteria.

3.8.9, "Distribution SystemsOperating,"

must be immediately entered. This allows The loss of an electrical Condition F to provide requirements for function does not go to the loss of one offsite circuit and one DG, core damage unless the without regard to whether a train is supported equipment is deenergized. LCO 3.8.9 provides the required. Risk significant appropriate restrictions for a deenergized power dependencies are train. represented in the PRA as built, as operated.

In Condition F, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition E (loss of two required offsite circuits).

This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

U.S. Nuclear Regulatory Commission Page 47 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.8.1.H One automatic load 2 automatic The sequencer(s) is an essential support 1 automatic Yes As needed to supply SSCs are modeled sequencer load system to both the offsite circuit and the load supported functions consistently with the TS inoperable. sequencers DG associated with a given Engineered sequencer scope and so can be AC Sources - Safety Features (ESF) bus. Furthermore, directly evaluated by the Operating the sequencer is on the primary success CRMP.

path for most major AC electrically The success criteria in powered safety systems powered from the PRA are consistent the associated ESF bus. Therefore, loss with the design basis of an ESF bus sequencer affects every criteria.

major ESF system in the train. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time provides a period The loss of an electrical of time to correct the problem function does not go to commensurate with the importance of core damage unless the maintaining sequencer OPERABILITY. supported equipment is This time period also ensures that the required. Risk significant probability of an accident (requiring power dependencies are sequencer OPERABILITY) occurring represented in the PRA during periods when the sequencer is as built, as operated.

inoperable is minimal.

U.S. Nuclear Regulatory Commission Page 48 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.8.4.A One channel of DC 2 Trains of DC Each DC channel consisting of one 2 channels of Yes As needed to supply SSCs are modeled source inoperable. Sources battery, battery charger for each battery DC sources to supported functions consistently with the TS 4 channels of and the corresponding control equipment 1 Train scope and so can be DC Sources - and interconnecting cabling supplying directly evaluated by the Operating DC sources (2 channels per power to the associated bus within the CRMP.

Train) train is required to be OPERABLE to The success criteria in ensure the availability of the required the PRA are consistent power to shut down the reactor and with the design basis maintain it in a safe condition after an criteria.

anticipated operational occurrence (AOO) or a postulated DBA. Loss of any channel The loss of an electrical of DC does not prevent the minimum function does not go to safety function from being performed. core damage unless the supported equipment is An OPERABLE channel of DC requires required. Risk significant the battery and respective charger to be power dependencies are operating and connected to the represented in the PRA associated DC bus.

as built, as operated.

Condition A represents one channel of DC with a loss of ability to fully respond to a DBA with the worst case single failure. Two hours is provided to restore the channel of DC to OPERABLE status and is consistent with the allowed time for an inoperable channel of DC distribution system requirement.

U.S. Nuclear Regulatory Commission Page 49 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.8.7.A One inverter 4 Inverters The inverters ensure the availability of 1 train of vital Yes As needed to supply SSCs are modeled inoperable. (2 Inverters per AC electrical power for the systems AC power supported functions consistently with the TS Inverters - train) instrumentation required to shut down the inverters - 2 scope and so can be Operating reactor and maintain it in a safe condition inverters directly evaluated by the after an anticipated operational CRMP.

occurrence (AOO) or a postulated DBA. The success criteria in Maintaining the required inverters the PRA are consistent OPERABLE ensures that the redundancy with the design basis incorporated into the design of the RPS criteria.

and ESFAS instrumentation and controls The loss of an electrical is maintained. The four inverters (two per function does not go to train) ensure an uninterruptible supply of core damage unless the AC electrical power to the AC vital buses supported equipment is even if the 4.16 kV safety buses are de-required. Risk significant energized.

power dependencies are Operable inverters require the associated represented in the PRA vital bus to be powered by the inverter as built, as operated.

with output voltage and frequency within tolerances, and power input to the inverter from a 125 VDC station battery.

3.8.9.A One or more AC 2 trains AC The required power distribution 1 train AC Yes As needed to supply SSCs are modeled electrical power electrical power subsystems ensure the availability of electrical supported functions consistently with the TS distribution distribution AC, DC, and AC vital bus electrical power power scope and so can be Distribution subsystem(s) subsystems. for the systems required to shut down the distribution directly evaluated by the Systems - inoperable. Each train of an reactor and maintain it in a safe condition subsystem, CRMP.

Operating AC power after an anticipated operational not including The success criteria in distribution occurrence (AOO) or a postulated DBA. vital AC the PRA are consistent subsystem, not The AC, DC, and AC vital bus electrical subsystems with the design basis including vital power distribution subsystems are and including criteria.

AC required to be OPERABLE. an essential subsystems, 4160V bus, The loss of an electrical Maintaining the Train A and Train B AC, function does not go to include an channels of DC, and AC vital buses two essential core damage unless the essential 4160V OPERABLE ensures that the redundancy 600V load supported equipment is bus, two incorporated into the design of ESF is not centers and required. Risk significant essential 600V defeated. Therefore, a single failure five 600V power dependencies are load centers within any system or within the electrical motor control and five 600V centers represented in the PRA power distribution subsystems will not motor control as built, as operated.

prevent safe shutdown of the reactor.

centers

U.S. Nuclear Regulatory Commission Page 50 RA-23-0279 Technical Design SSCs Technical Corresponding Function Covered by TS LCO Specification Success Modeled in PRA Success Criteria Comments Specification SSC(s) Condition Action Criteria PRA 3.8.9.B One AC vital bus 2 trains AC vital The required power distribution 1 train AC vital Yes As needed to supply SSCs are modeled inoperable. buses (2 buses subsystems ensure the availability of buses supported functions consistently with the TS per train) AC, DC, and AC vital bus electrical power scope and so can be Distribution for the systems required to shut down the directly evaluated by the Systems - reactor and maintain it in a safe condition CRMP.

Operating after an anticipated operational The success criteria in occurrence (AOO) or a postulated DBA. the PRA are consistent The AC, DC, and AC vital bus electrical with the design basis power distribution subsystems are criteria.

required to be OPERABLE.

The loss of an electrical Maintaining the Train A and Train B AC, function does not go to channels of DC, and AC vital buses core damage unless the OPERABLE ensures that the redundancy supported equipment is incorporated into the design of ESF is not required. Risk significant defeated. Therefore, a single failure power dependencies are within any system or within the electrical represented in the PRA power distribution subsystems will not as built, as operated.

prevent safe shutdown of the reactor.

3.8.9.C One channel of DC 2 trains of DC The required power distribution 1 train of DC Yes As needed to supply SSCs are modeled electrical power electrical power subsystems ensure the availability of electrical supported functions consistently with the TS distribution distribution AC, DC, and AC vital bus electrical power power scope and so can be Distribution subsystem subsystem (2 for the systems required to shut down the distribution directly evaluated by the Systems - inoperable. channels per reactor and maintain it in a safe condition CRMP.

Operating train) after an anticipated operational The success criteria in occurrence (AOO) or a postulated DBA. the PRA are consistent The AC, DC, and AC vital bus electrical with the design basis power distribution subsystems are criteria.

required to be OPERABLE.

The loss of an electrical Maintaining the Train A and Train B AC, function does not go to channels of DC, and AC vital buses core damage unless the OPERABLE ensures that the redundancy supported equipment is incorporated into the design of ESF is not required. Risk significant defeated. Therefore, a single failure power dependencies are within any system or within the electrical represented in the PRA power distribution subsystems will not as built, as operated.

prevent safe shutdown of the reactor.

Notes to table E1-1:

1. Below the P-10 (Power Range Neutron Flux) interlock

2. Above the P-7 (Low Power Reactor Trips Block) interlock

3. Above the P-8 (Power Range Neutron Flux) interlock

4. Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock

5. Including any reactor trip bypass breakers that are racked in and closed for bypassing on RTP

U.S. Nuclear Regulatory Commission Page 51 RA-23-0279

6. Above the P-11 (Pressurizer Pressure) interlock

7. Except when all MSIVs are closed and de-activated

8. Except when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.

9. The functions of the Reactor Trip, P-4 interlock required to meet the LCO are:

x Trip the main turbine - MODES 1 and 2 x Isolate MFW with coincident low Tavg - MODES 1, 2, and 3 x Prevent re-actuation of SI after a manual reset of SI - MODES 1, 2, and 3 x Prevent opening MFIVs if closed on SI or SG Water Level - High High - MODES 1, 2, and 3

U.S. Nuclear Regulatory Commission Page 52 RA-23-0279 Table E1-2: In-Scope TS LCO RICT Estimates Technical RICT Estimate1 Specification Technical Specification Condition (Days)

Reactor Trip System (RTS) Instrumentation - One Manual Reactor Trip 3.3.1.B 30.0 channel inoperable 3.3.1.D Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.E Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.M Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.O Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.Q Reactor Trip System (RTS) Instrumentation - One channel inoperable 30.0 3.3.1.T Reactor Trip System (RTS) Instrumentation - One train inoperable 30.0 3.3.1.U Reactor Trip System (RTS) Instrumentation - One RTB train inoperable 30.0 Reactor Trip System (RTS) Instrumentation - One trip mechanism 3.3.1.Y 30.0 inoperable for one RTB 3.3.2.B ESFAS Instrumentation - One channel or train inoperable 10.6 3.3.2.C ESFAS Instrumentation - One train inoperable 10.6 3.3.2.D ESFAS Instrumentation - One channel inoperable 30.0 3.3.2.F ESFAS Instrumentation - One channel or train inoperable 11.8 3.3.2.H ESFAS Instrumentation - One train inoperable N/A2 3.3.2.I ESFAS Instrumentation - One train inoperable 30.0 3.3.2.J ESFAS Instrumentation - One channel inoperable 30.0 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation - One or 3.3.5.A 30.0 more Functions with one channel per bus inoperable Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation - One or 3.3.5.B 30.0 more Functions with two or more channels per bus inoperable Pressurizer Power Operated Relief Valves (PORVs) - One Train A PORV 3.4.11.C 9.8 inoperable and not capable of being manually cycled Pressurizer Power Operated Relief Valves (PORVs) - Two Train B PORVs 3.4.11.D 9.3 inoperable and not capable of being manually cycled Pressurizer Power Operated Relief Valves (PORVs) - One Train A block 3.4.11.H 30.0 valve inoperable Pressurizer Power Operated Relief Valves (PORVs) - Two Train B block 3.4.11.I 30.0 valves inoperable Pressurizer Power Operated Relief Valves (PORVs) - One Train B PORV 3.4.11.J inoperable and not capable of being manually cycled AND The other Train B 9.3 block valve inoperable.

Emergency Core Cooling System (ECCS) - Operating - One or more trains 3.5.2.A inoperable AND At least 100% of the ECCS flow equivalent to a single 30.0 OPERABLE ECCS train available.

Containment Air Locks - One or more containment air locks inoperable for 3.6.2.C 10.6 reasons other than Condition A or B Containment Isolation Valves - One or more penetration flow paths with one 3.6.3.A containment isolation valve inoperable except for purge valve or reactor 10.6 building bypass leakage not within limit.

Containment Isolation Valves - One or more penetration flow paths with one 3.6.3.C 10.6 containment isolation valve inoperable.

U.S. Nuclear Regulatory Commission Page 53 RA-23-0279 Table E1-2: In-Scope TS LCO RICT Estimates Technical RICT Estimate1 Specification Technical Specification Condition (Days)

Containment Spray System (Ice Condenser) - One containment spray train 3.6.6.A 30.0 inoperable Hydrogen Mitigation System (HMS) (Ice Condenser) - One HMS train 3.6.9.A 30.0 inoperable.

Hydrogen Mitigation System (HMS) (Ice Condenser) - One containment 3.6.9.B 30.0 region with no OPERABLE hydrogen ignitor 3.6.11.A Air Return System (ARS) (Ice Condenser) - One ARS train inoperable 30.0 Divider Barrier Integrity (Ice condenser) - One or more personnel access doors or equipment hatches (other than one pressurizer or one steam 3.6.14.A 30.0 generator enclosure hatch addressed by Condition D) open or inoperable, other than for personnel transit entry.

3.7.2.A Main Steam Isolation Valves (MSIVs) - One MSIV inoperable in MODE 1 30.0 Auxiliary Feedwater (AFW) System - One steam supply to turbine driven 3.7.5.A 30.0 AFW pump inoperable Auxiliary Feedwater (AFW) System - One AFW train inoperable in MODE 1, 3.7.5.B 30.0 2 or 3 for reasons other than Condition A.

3.7.6.A Component Cooling Water System (CCW) - One CCW train inoperable 30.0 3.7.7.A Nuclear Service Water System (NSWS) - One NSWS train inoperable 29.1 3.8.1.A AC Sources - Operating - One LCO 3.8.1.a offsite circuit inoperable. 30.0 3.8.1.B AC Sources - Operating - One LCO 3.8.1.b DG inoperable 30.0 3.8.1.C AC Sources - Operating - One LCO 3.8.1.c offsite circuit inoperable. 30.0 AC Sources - Operating - Two LCO 3.8.1.a offsite circuits inoperable OR One LCO 3.8.1.a offsite circuit that provides power to the NSWS, CRAVS, 3.8.1.E 30.0 CRACWS and ABFVES inoperable and one LCO 3.8.1.c offsite circuit inoperable OR Two LCO 3.8.1.c offsite circuits inoperable AC Sources - Operating - One LCO 3.8.1.a offsite circuit inoperable AND 3.8.1.F 30.0 One LCO 3.8.1.b DG inoperable 3.8.1.H AC Sources - Operating - One automatic load sequencer inoperable. 30.0 3.8.4.A DC Sources - Operating - One channel of DC source inoperable N/A2 3.8.7.A Inverters - Operating - One inverter inoperable. 30.0 Distribution Systems - Operating - One or more AC electrical power 3.8.9.A N/A2 distribution subsystem(s) inoperable.

3.8.9.B Distribution Systems - Operating - One AC vital bus inoperable. N/A2 Distribution Systems - Operating - One channel of DC electrical power 3.8.9.C N/A2 distribution subsystem inoperable.

Notes to Table E1-2:

(1) RICTs are based on representative PRA model calculations. RICTs calculated to be greater than 30 days are capped at 30 days based on NEI 06-09-A. RICTs are rounded to nearest tenth of a day.

(2) Per NEI 06-09, Revision 0-A, for cases where the total CDF or LERF is greater than 1E-03/yr or 1E-04/yr, respectively, the RICT Program will not be entered.

U.S. Nuclear Regulatory Commission Page 54 RA-23-0279 4.0 ADDITIONAL JUSTIFICATION FOR SPECIFIC ACTIONS Table 1, Conditions Requiring Additional Technical Justification, of TSTF-505, Revision 2 (Reference 4) contains a list of Required Actions that may be proposed for inclusion in a RICT Program, but which require additional technical justification to be provided by the licensee. This section contains the specific additional technical justification.

TABLE E1 IDENTIFIED REQUIRED ACTIONS WHICH REQUIRE ADDITIONAL JUSTIFICATION FOR INCLUSION IN TSTF-505 APPLICATION NUREG-1431 LCO Requirements Suggested Corresponding MNS Standard and Condition Information Technical Specification Specification 3.3.1.D LCO: The RTS Licensee must justify Power Range instrumentation for that the condition Neutron Flux - High each Function in does not represent 3.3.1 Action D.1.2 Table 3.3.1-1 shall be the inability to OPERABLE. perform the safety function assumed in Condition: One the FSAR given the Power Range loss of spacial Neutron Flux - High distribution of the channel inoperable. remaining Power Range detectors.

The justification can include that the Actions require periodic monitoring of spacial power distribution and imposition of compensatory limits and reduced power.

3.3.1.U LCO: The RTS The licensee must Reactor Trip Breakers instrumentation for include information 3.3.1 Action U.1 each Function in regarding how the Table 3.3.1-1 shall be TSTF-411 conditions OPERABLE. and limitations will be implemented (or Condition: One RTB similar conditions if train inoperable TSTF-411 has not been adopted),

including discussion of ATWS Mitigation System Actuation (AMSAC), and why those actions are sufficient, including a discussion of defense in depth.

U.S. Nuclear Regulatory Commission Page 55 RA-23-0279 TABLE E1 IDENTIFIED REQUIRED ACTIONS WHICH REQUIRE ADDITIONAL JUSTIFICATION FOR INCLUSION IN TSTF-505 APPLICATION NUREG-1431 LCO Requirements Suggested Corresponding MNS Standard and Condition Information Technical Specification Specification 3.3.5.B LCO: [Three] Licensee must justify LOP Diesel channels per bus of that two or more Generator Start the loss of voltage channels per bus Instrumentation Function and [three] inoperable is not a 3.3.5 Action B.1 channels per bus of condition in which all the degraded voltage required trains or Function shall be subsystems of a TS OPERABLE. required system are inoperable or modify Condition: One or the Action to not more Functions with apply a RICT when two or more channels all required trains or per bus inoperable. subsystems are inoperable.

3.5.2.A LCO: Two ECCS Licensee must justify ECCS - Operating trains shall be that one or more 3.5.2 Action A.1 OPERABLE. ECCS trains inoperable is not a Condition: One or condition in which all more [ECCS] trains required trains or inoperable. subsystems of a TS required system are inoperable.

Acceptable justification is TS Condition requiring 100% flow equivalent to a single ECCS train.

3.6.2.C LCO: [Two] Licensee must justify Containment Air containment air that an inoperable Locks lock[s] shall be containment air lock 3.6.2 Action C.3 OPERABLE. is not a condition in which all required Condition: One or trains or subsystems more containment air of a TS required locks inoperable for system are reasons other than inoperable. An an inoperable door or acceptable argument inoperable interlock may be that a note in mechanism. TS 3.6.2 requires the condition to be assessed in accordance with TS 3.6.1, Containment Integrity, and

U.S. Nuclear Regulatory Commission Page 56 RA-23-0279 TABLE E1 IDENTIFIED REQUIRED ACTIONS WHICH REQUIRE ADDITIONAL JUSTIFICATION FOR INCLUSION IN TSTF-505 APPLICATION NUREG-1431 LCO Requirements Suggested Corresponding MNS Standard and Condition Information Technical Specification Specification excessive leakage would require an immediate plant shutdown under that TS.

3.6.6C.A LCO: Containment Licensee must justify Containment Spray Spray System (Ice the ability to Systems Condenser) calculate a RICT for 3.6.6 Action A.1 the condition, Condition: One including how the containment spray system is modeled in train inoperable. the PRA, whether all functions of the system are modeled, and, if a surrogate is used, why that modeling is conservative.

3.7.2.A LCO: [Four] MSIVs Licensee must justify Main Steam Isolation shall be OPERABLE. that the condition Valves (MSIVs) would not prevent 3.7.2 Action A.1 Condition: One MSIV performance of the inoperable in MODE steam line break

1. isolation function assumed in the accident analysis. An acceptable method may be a second MSIV per steam line, another design feature, or an alternate method of preventing blowdown of more than one steam generator.

Duke Energys justification for each of the MNS Specifications is provided below.

LCO 3.3.1 Action D.1, Power Range Neutron Flux - High As described in Section 7.2.2.3.1, Neutron Flux, of the MNS UFSAR (Reference 5):

Four power range nuclear instrumentation channels are provided for overpower protection. An additional signal for automatic rod control is derived by comparing the four NIS channels and selecting the "2nd highest". If any channel fails in such a way as to produce a high or low output, that channel

U.S. Nuclear Regulatory Commission Page 57 RA-23-0279 does not cause control rod movement because of the "2nd highest" algorithm.

Two out of four overpower trip logic ensure an overpower trip if needed even with an independent failure in another channel.

In addition, channel deviation signals in the control system give an alarm if any significant power range channel deviation occurs. Also, the control system responds only to rapid changes in indicated neutron flux; slow changes or drifts are compensated by the temperature control signals. Finally, an overpower signal from any nuclear power range channel blocks manual and automatic rod withdrawal. The setpoint for this rod stop is below the reactor trip setpoint.

The alarms and actions described above signify periodic monitoring of spatial power distribution and imposition of compensatory limits and reduced power. Also, with one channel inoperable, the safety function assumed in the UFSAR to initiate a reactor trip when the monitored parameter (i.e., Power Range neutron flux) reaches the high setpoint is still maintained.

Consistent with the UFSAR description above and Table 3.3.1-1 of the MNS TS, there are a total of four channels and only two channels are needed for a reactor trip to occur. Therefore, MNS LCO 3.3.1 Condition D, Action D.1 meets the listed requirements for inclusion in the RICT Program.

LCO 3.3.1 Action U.1, Reactor Trip Breakers (RTBs)

TSTF-411, Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376-P) (Reference 6) has been adopted at MNS (Reference 7). The MNS PRA models meet the expectations for PRA scope and quality as presented in RG 1.200, Revision 2, to support the requirements of the RICT Program. Specific discussion of the PRA model technical adequacy is discussed in Enclosure 2.

Section 7.7.1.16 of the McGuire UFSAR (Reference 5), ATWS Mitigation Actuation Circuitry, the AMSAC design allows for independent response to an ATWS event without relying on the Reactor Protection System (RPS). The AMSAC system trips the main turbine, starts the motor driven auxiliary feedwater pumps, and closes blowdown and sampling valves in response to an ATWS event. As stated in the UFSAR, the AMSAC design complies with the NRC Safety Evaluation Report (SER) at MNS.

Therefore, MNS LCO 3.3.1 Condition U, Action U.1 meets the requirements for inclusion in the RICT program.

LCO 3.3.5 Action B.1, Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation Loss of more than one channel affecting a single bus is not a loss of safety function. A note is included for the proposed Completion Time of TS 3.3.5, Required Action B.1, to preclude RICT entry for a loss of function condition.

LCO 3.5.2 Action A.1, ECCS Operating The MNS TS Actions for ECCS are restricted to a single inoperable train. The proposed change will not alter the fact that the Actions are restricted to a single train. Specifically, MNS LCO 3.5.2 does not contain an Action for more than one ECCS subsystem inoperable, and Standard Technical Specifications (i.e., NUREG-1431) and TSTF-505 Specification 3.5.2.A one or more

U.S. Nuclear Regulatory Commission Page 58 RA-23-0279 ECCS subsystems inoperable Condition does not apply. Therefore, MNS LCO 3.5.2 Action A.1 meets the requirements for inclusion in the RICT Program.

LCO 3.6.2 Action C.3, Containment Air Locks As indicated in Table E1-1 of this enclosure above, the containment air locks are modeled in the MNS PRA. The PRA success criteria is the same as the design success criteria (i.e., 2 of 2 air locks).

Compliance with remaining portions of MNS LCO 3.6.2 Action C.1 and Action C.2 ensure that there is a physical barrier (e.g., closed door) and an acceptable overall leakage from containment. Thus, the function is still maintained. Action C.1 of LCO 3.6.2 requires the condition to be assessed in accordance with LCO 3.6.1 (i.e., Initiate action to evaluate overall containment leakage rate per LCO 3.6.1). Note 3 for LCO 3.6.2 applies to all the Specification 3.6.2 Action statements and directs entry into LCO 3.6.1 for Containment when the air lock leakage results exceed the overall containment leakage rate. LCO 3.6.1 requires restoration of Containment Integrity within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or the unit must commence a shutdown.

Therefore, MNS LCO 3.6.2 Action C.3 meets the listed requirements for inclusion in the RICT Program.

LCO 3.6.6 Action A.1, Containment Spray System The SSCs associated with the containment depressurization and cooling function of MNS LCO 3.6.6 following a LOCA or steam line break are explicitly modeled in the MNS PRA. The iodine removal function of the containment spray trains is not required for mitigation of severe accidents and is thus not modeled in the MNS PRA. The PRA success criteria for containment spray is 1 of 2 trains, which is the same as the design success criteria for the system.

The function covered by MNS LCO 3.6.6 is containment heat removal following a LOCA. The SSCs for containment sprays are modeled in the MNS PRA consistent with the TS scope and can be directly evaluated. The success criteria in the PRA for the containment sprays in LCO 3.6.6 (i.e., 1 of 2 containment spray trains) are based on realistic containment heat removal capabilities of the containment spray system consistent with the PRA Standard for Capability Category II.

Since the containment spray SSCs are adequately modeled in the MNS PRA and a RICT can be calculated for the conditions, MNS LCO 3.6.6 Action A.1 meets the listed requirements for inclusion in the RICT Program.

LCO 3.7.2 Action A.1, Main Steam Isolation Valves (MSIVs)

A portion of the MNS licensing basis, as stated in Section 15.1.5, Steam System Piping Failure of the UFSAR (Reference 5), is the following (emphasis in underline):

Steam release from more than one steam generator will be prevented by automatic trip of the fast acting isolation valves in the steam lines by a low steam line pressure signals, high-high containment pressure signals, or high negative steam line pressure rate signals. Even with the failure of one valve, release is ended for the other steam generators while the one generator blows

U.S. Nuclear Regulatory Commission Page 59 RA-23-0279 down. The isolation valves are designed to be fully closed in 8 seconds from receipt of a closure signal.

Even with one MSIV inoperable (but open) in accordance with MNS LCO 3.7.2 (Action A.1), an uncontrolled blowdown of more than one steam generator would not occur following a steam line break. For example, when one MSIV is inoperable on one steam line and a postulated steam line break occurs on a separate steam line, the design function is still performed because the remaining operable MSIVs will close. The steam line break isolation function assumed in the accident analysis is maintained with one MSIV inoperable (but open). Therefore, MNS LCO 3.7.2 (Action A.1) meets the listed requirements for inclusion in the RICT Program.

5.0 MAINTAINING DEFENSE-IN-DEPTH TSTF-505 (Reference 4) sets forth the following as guidance for what is to be included in this

Enclosure:

The description of proposed changes to the protective instrumentation and control features in TS Section 3.3, "Instrumentation," should confirm that at least one redundant or diverse means (other automatic features or manual action) to accomplish the safety functions (for example, reactor trip, SI, containment isolation, etc.) remains available during use of the RICT, consistent with the defense-in-depth philosophy as specified in RG 1.174. (Note that for each application, the staff may selectively audit the licensing basis of the most risk-significant functions with proposed RICTs to verify that such diverse means exist.)

The following sections provide the justification that defense-in-depth, either through redundancy or through diversity, is maintained for the applicable functions throughout the application of the RICT Program. The tables show that for each reactor trip system (RTS) function and each engineered safety features actuation system (ESFAS) instrument function, there is at least one diverse means for initiating the safety function. Table E1-4 shows the diverse means for initiating the safety function (i.e., reactor trip) for RTS instrumentation. Table E1-5 shows the diverse means for initiating the safety function (e.g., safety injection, containment isolation, containment spray, etc.) for each ESFAS instrument.

5.1 Reactor Trip System Instrumentation (TS 3.3.1)

The RTS design creates defense-in-depth through the degree of redundancy for each of its channels for each Functional Unit.

x Each Functional Unit has multiple channels, with a minimum of 2 channels for Functional Units proposed for the RICT Program.

x Each Functional Unit proposed to be in the scope of the RICT Program will cause a reactor trip with 1/2, 2/3, or 2/4 tripped channels.

x A bypassed channel does not trip. It reduces the total available channels by 1, for example from 2/4 to 2/3, or from 2/3 to 2/2.

x When applicable, if 1 channel in the Functional Unit is out of service, then that channel may be placed in a tripped state, for example reducing the redundancy from 2/4 required tripped channels to 1/3 required tripped channels.

U.S. Nuclear Regulatory Commission Page 60 RA-23-0279 The Reactor Trip System also employs diversity in the number and variety of different inputs which will initiate a reactor trip. A given reactor trip will typically be accompanied by several diverse reactor trip inputs from the RTS.

x Manual Reactor Trip - 1/2 channels to trip x Power Range Neutron Flux (High) - 2/4 channels to trip x Power Range Neutron Flux (Low) - 2/4 channels to trip x Power Range Neutron Flux (High Positive Rate) - 2/4 channels to trip x Intermediate Range High Neutron Flux - 1/2 channels to trip x Source Range High Neutron Flux - 1/2 channels to trip x Overtemperature T - 2/4 channels to trip x Overpower T - 2/4 channels to trip x Pressurizer Pressure (Low) - 2/4 channels to trip x Pressurizer Pressure (High) - 2/4 channels to trip x Pressurizer Water Level (High) - 2/3 channels to trip x Reactor Coolant Flow - Low (Single Loop) - 2/3 channels to trip per loop x Reactor Coolant Flow - Low (Two Loops) - 2/3 channels to trip per loop x Undervoltage RCPs - (1 per bus) - 2/4 channels to trip x Underfrequency RCPs - (1 per bus) - 2/4 channels to trip x Steam Generator (SG) Water Level (Low Low) - 2/4 channels to trip per SG x Turbine Trip (Low Fluid Oil Pressure) - 2/3 channels to trip x Turbine Trip (Turbine Stop Valve Closure) - 4/4 stop valves closed x Safety Injection (SI) Input from ESFAS - 1/2 trains to trip x Reactor Trip Breakers - 1/2 trains to trip x Automatic Trip Lock Logic - 1/2 trains to trip TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

1) Two manual reactor trip switches Manual Reactor a. Automatic actuation Reactor Trip 2) Train A and Train B Trip failed trip breakers

3) Automatic reactor trips

a. Feedwater system 1) Automatic Protection Power Range malfunctions causing a. Low-Low Steam Neutron Flux Reactor Trip an increase in Generator Level Reactor Trips feedwater flow b. Overpower T (High & Low)

UFSAR 15.1.2 2) Manual Trip

U.S. Nuclear Regulatory Commission Page 61 RA-23-0279 TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

1) Automatic Protection

a. Intermediate

b. Uncontrolled rod Range High Neutron cluster control Flux Reactor Trip assembly bank b. Source Range withdrawal from a High Neutron Flux subcritical or low Reactor Trip power startup c. Power Range condition Neutron Flux High UFSAR 15.4.1 Positive Rate Reactor Trip

2) Manual Trip

1) Automatic Protection

c. Spectrum of rod

a. Power Range cluster control Neutron Flux High assembly ejection Positive Rate Reactor accidents Trip UFSAR 15.4.8

2) Manual Trip

1) Automatic Protection

a. Overtemperature T

d. Uncontrolled rod

b. High Pressurizer cluster control Pressure Reactor Trip assembly bank

c. Overpower T withdrawal at power

d. High Pressurizer UFSAR 15.4.2 Water Level Reactor Trip

2) Manual Trip

a. Spectrum of rod 1) Automatic Protection Power Range cluster control a. Power Range Neutron Flux High Reactor Trip assembly ejection Neutron Flux Reactor Positive Rate accidents Trips (High & Low)

Reactor Trip UFSAR 15.4.8 2) Manual Trip

1) Automatic Protection

a. High Pressurizer Pressure Reactor Overtemperature a. Loss of external load Trip Reactor Trip T UFSAR 15.2.2 b. High Pressurizer Water Level Reactor Trip

2) Manual Trip

U.S. Nuclear Regulatory Commission Page 62 RA-23-0279 TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

1) Automatic Protection

a. High Pressurizer Pressure Reactor Trip

b. Turbine Trip b. Reactor Trip on UFSAR 15.2.3, Turbine Trip 15.2.5 c. High Pressurizer Water Level Reactor Trip

2) Manual Trip

c. Inadvertent closure 1) Automatic Protection of main steam a. High Pressurizer isolation valves Pressure Reactor Trip UFSAR 15.2.4 2) Manual Trip

d. Chemical and 1) Automatic Protection volume control a. Power Range system malfunction Neutron Flux Reactor that results in a Trips decrease in boron b. Overpower T concentration in the 2) Manual Trip reactor coolant UFSAR 15.4.6

1) Automatic Protection

a. Power Range Neutron Flux Reactor

e. Uncontrolled rod Trips cluster control b. High Pressurizer assembly bank Pressure Reactor Trip withdrawal at power c. Overpower T UFSAR 15.4.2 d. High Pressurizer Water Level Reactor Trip

2) Manual Trip

1) Automatic Protection

a. Power Range Neutron Flux Reactor

f. Rod cluster control Trips assembly

b. Low Pressurizer misoperation Pressure Reactor Trip UFSAR 15.4.3

c. High Pressurizer Pressure Reactor Trip

2) Manual Trip

U.S. Nuclear Regulatory Commission Page 63 RA-23-0279 TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

1) Automatic Protection

a. Low Pressurizer

g. Inadvertent opening Pressure Reactor Trip of a pressurizer

b. Reactor Trip On safety or relief valve Safety Injection UFSAR 15.6.1 Initiation

2) Manual Trip

1) Automatic Protection

a. Low Pressurizer

h. Steam generator Pressure Reactor Trip tube failure b. Reactor Trip On UFSAR 15.6.3 Safety Injection Initiation

2) Manual Trip

1) Automatic Protection

a. Feedwater system a. Low-Low Steam malfunctions causing Generator Level an increase in b. Power Range feedwater flow Neutron Flux UFSAR 15.1.2 Reactor Trips

2) Manual Trip

1) Automatic Protection

a. Low-Low Steam Generator Level

b. Reactor Trip On

b. Steam system piping Safety Injection failure Initiation UFSAR 15.1.5

c. Power Range Neutron Flux Reactor Trips Overpower T Reactor Trip

2) Manual Trip

c. Chemical and 1) Automatic Protection volume control a. Power Range system malfunction Neutron Flux Reactor that results in a Trips decrease in boron b. Overtemperature concentration in the T reactor coolant 2) Manual Trip UFSAR 15.4.6

d. Chemical and 1) Automatic Protection volume control a. High Pressurizer system malfunction Water that increases Level Reactor Trip.

reactor coolant inventory 2) Manual Trip UFSAR 15.5.2

U.S. Nuclear Regulatory Commission Page 64 RA-23-0279 TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

1) Automatic Protection

a. Inadvertent operation

a. Reactor Trip On of the ECCS during Safety Injection power operation Initiation UFSAR 15.5.1

2) Manual Trip

b. Chemical and 1) Automatic Protection volume control a. Overtemperature system malfunction T that decreases 2) Manual Trip reactor coolant inventory UFSAR 15.5.2

1) Automatic Protection Low Pressurizer

a. Overtemperature Pressure Reactor Reactor Trip

c. Steam generator T Trip tube failure b. Reactor Trip On UFSAR 15.6.3 Safety Injection Initiation

2) Manual Trip

1) Automatic Protection

d. Loss of coolant a. Reactor Trip On accident Safety UFSAR 15.6.5 Injection Initiation

2) Manual Trip

e. Rod cluster control 1) Automatic Protection assembly a. Overtemperature misoperation T UFSAR 15.4.3 2) Manual Trip

1) Automatic Protection

a. Overtemperature T

a. Loss of external load

b. High Pressurizer UFSAR 15.2.2 Water Level Reactor Trip

2) Manual Trip High Pressurizer

1) Automatic Protection Pressure Reactor Reactor Trip

a. Overtemperature Trip T

b. Turbine trip b. Reactor Trip on UFSAR Turbine Trip 15.2.3,15.2.5 c. High Pressurizer Water Level Reactor Trip

2) Manual Trip

U.S. Nuclear Regulatory Commission Page 65 RA-23-0279 TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

c. Inadvertent closure 1) Automatic Protection of main steam a. Overtemperature isolation valves T UFSAR 15.2.4 2) Manual Trip

1) Automatic Protection

a. Power Range Neutron Flux Reactor

d. Uncontrolled rod Trips cluster control b. Overtemperature assembly bank T withdrawal at power c. Overpower T UFSAR 15.4.2 d. High Pressurizer Water Level Reactor Trip

2) Manual Trip

e. Rod cluster control 1) Automatic Protection assembly a. Overtemperature misoperation T UFSAR 15.4.3 2) Manual Trip

1) Automatic Protection

a. High Pressurizer

a. Loss of external load Pressure Reactor Trip UFSAR 15.2.2 b. Overtemperature T

2) Manual Trip

1) Automatic Protection

a. High Pressurizer Pressure Reactor Trip

b. Turbine trip

b. Overtemperature UFSAR T

15.2.3,15.2.5 High Pressurizer c. Reactor Trip on Water Level Reactor Trip Turbine Trip Reactor Trip 2) Manual Trip

1) Automatic Protection

a. Power Range Neutron Flux Reactor

c. Uncontrolled rod Trips cluster control b. Overtemperature assembly bank T withdrawal at power c. High Pressurizer UFSAR 15.4.2 Pressure

d. Overpower T Reactor Trip

2) Manual Trip

U.S. Nuclear Regulatory Commission Page 66 RA-23-0279 TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

1) Automatic Protection

a. Partial loss of forced a. RCP undervoltage reactor coolant flow b. RCP UFSAR 15.3.1 underfrequency Low Reactor 2) Manual Trip Coolant Flow Reactor Trip b. Reactor coolant 1) Manual Trip Reactor Trips pump shaft seizure (Single & 2 Loops)

UFSAR 15.3.3

c. Reactor coolant 1) Manual Trip pump shaft break UFSAR 15.3.4

1) Automatic Protection

a. Feedwater system

a. Power Range malfunctions causing Neutron Flux Reactor an increase in Trips feedwater flow

b. Overpower T UFSAR 15.1.2

2) Manual Trip

1) Automatic Protection

a. Power Range Neutron Flux Reactor

b. Steam system piping Trips failure b. Overpower T UFSAR 15.1.5 c. Reactor Trip On Safety Injection Initiation

2) Manual Trip Low-Low Steam 1) Automatic Protection Generator Water Reactor Trip a. Power Range Level Reactor Trip Neutron Flux Reactor

c. Inadvertent opening Trips of a SG relief or

b. Overpower T safety valve

c. Reactor Trip On UFSAR 15.1.4 Safety Injection Initiation

2) Manual Trip

1) Automatic Protection

a. Overtemperature T

d. Feedwater system b. High Pressurizer pipe break Pressure Reactor Trip UFSAR 15.2.8 c. Reactor Trip On Safety Injection Initiation

2) Manual Trip

U.S. Nuclear Regulatory Commission Page 67 RA-23-0279 TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

1) Automatic Protection

a. Low Reactor Coolant Flow Reactor Reactor Coolant a. Complete loss of Trips Pumps forced reactor Reactor Trip b. Reactor Coolant Undervoltage coolant flow Pumps Reactor Trip UFSAR 15.3.2 Underfrequency Reactor Trip

2) Manual Trip

1) Automatic Protection

a. Low Reactor Reactor Coolant a. Complete loss of Coolant Flow Reactor Pumps forced reactor Trips Reactor Trip Underfrequency coolant flow b. Reactor Coolant Reactor Trip UFSAR 15.3.2 Pumps Undervoltage Reactor Trip

2) Manual Trip

1) Automatic Protection

a. High Pressurizer Pressure Reactor Trip

b. Overtemperature T

a. Turbine trip

c. High Pressurizer Reactor Trip On UFSAR 15.2.3, Reactor Trip Water Turbine Trip 15.2.5 Level Reactor Trip

d. Low-Low Steam Generator Water Level Reactor Trip

2) Manual Trip

1) Automatic Protection

a. Power Range Neutron Flux Reactor

a. Inadvertent opening Trips Reactor Trip On of a SG relief or b. Overpower T Safety Injection Reactor Trip safety valve c. Low-Low Steam Initiation UFSAR 15.1.4 Generator Water Level Reactor Trip

2) Manual Trip

U.S. Nuclear Regulatory Commission Page 68 RA-23-0279 TABLE E1 REACTOR TRIP SYSTEM (RTS) INSTRUMENTATION DIVERSITY Plant Function Safety Function Diverse Reactor Trips Condition/Accident

1) Automatic Protection

a. Power Range Neutron Flux Reactor Trips

b. Steam system piping

b. Overpower T failure

c. Low-Low Steam UFSAR 15.1.5 Generator Water Level Reactor Trip

2) Manual Trip

1) Automatic Protection

a. Overtemperature T

b. High Pressurizer

c. Feedwater system Pressure Reactor Trip pipe break

c. Low-Low Steam UFSAR 15.2.8 Generator Water Level Reactor Trip

2) Manual Trip 5.2 Engineered Safety Features Actuation System Instrumentation (TS 3.3.2)

The Engineered Safety Features Actuation System (ESFAS) design creates defense-in-depth through the degree of redundancy for each of its channels for each Functional Unit.

x Each Functional Unit has multiple channels.

x Each Functional Unit will actuate its associated equipment with 1/2, 2/3, or 2/4 tripped channels.

x A bypassed channel does not trip. It reduces the total available channels by 1, for example from 2/4 to 2/3, or from 2/3 to 2/2.

x When applicable, if 1 channel in the Functional Unit is out of service, then that channel may be placed in a tripped state, for example reducing the redundancy from 2/4 required tripped channels to 1/3 required tripped channels.

ESFAS also employs diversity in the number and variety of different inputs which will actuate the associated equipment.

Safety Injection o Manual Initiation - 1/2 channels to actuate o Automatic Actuation Logic and Actuation Relays - 1/2 channels to actuate o Containment Pressure - High - 2/3 channels to actuate o Pressurizer Pressure - Low Low - 2/4 channels to actuate Containment Isolation o Phase A Isolation - Manual Initiation - 1/2 channels to actuate

U.S. Nuclear Regulatory Commission Page 69 RA-23-0279 o Phase A Isolation - Automatic Actuation Logic and Actuation Relays - 1/2 channels to actuate o Phase B Isolation - Manual Initiation - 1/2 channels to actuate o Phase B Isolation - Automatic Actuation Logic and Actuation Relays - 1/2 channels to actuate o Phase B Isolation on Containment Pressure - High High - 2/4 channels to actuate Steam Line Isolation o Manual Initiation (System) - 1/2 channels to actuate o Manual Initiation (Individual) - 1 per line o Automatic Actuation Logic and Actuation Relays - 1/2 channels to actuate o Containment Pressure - High High - 2/4 channels to actuate o Steam Line Pressure - Low - 2/3 channels to actuate o Steam Line Pressure - Negative Rate High - 2/3 channels to actuate Turbine Trip and Feedwater Isolation o Turbine Trip - Automatic Actuation Logic and Actuation Relays - 1/2 channels to actuate o Turbine Trip - SG Water Level High High (P-14) - 2/3 channels to actuate o Feedwater Isolation - Automatic Actuation Logic and Actuation Relays - 1/2 channels to actuate o Feedwater Isolation - SG Water Level High High (P-14) - 2/3 channels to actuate o Feedwater Isolation - Tavg-Low (coincident with Reactor Trip, P-4) - 2/4 channels to actuate o Feedwater Isolation - Doghouse Water Level High High (3 per train per Doghouse)

- 2/3 channels to actuate Auxiliary Feedwater o Automatic Actuation Logic and Actuation Relays - 1/2 channels to actuate o SG Water Level Low Low - 2/4 channels to actuate o Station Blackout - Loss of Voltage - 2/3 channels to actuate o Station Blackout - Degraded Voltage - 2/3 channels to actuate o Auxiliary Feedwater Pump Suction Transfer on Suction Pressure - Low; 2 per MDP, 4 per TDP(2 trains) - 2/2 per train to actuate Automatic Switchover to Containment Sump o Refueling Water Storage Tank (RWST) Level Low (Coincident with Safety Injection) - 2/3 channels Not all McGuire ESFAS TS 3.3.2 Conditions and Required Actions are within the scope of this license amendment request. Table E1-5 does not include out of scope instrumentation.

TABLE E1 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM (ESFAS) INSTRUMENTATION DIVERSITY Accident Diverse ESFAS Instrument Safety Feature Condition Protection

1) Two trains of Automatic manual Manual Initiation Safety Injection (SI) actuation failed pushbuttons

2) Automatic SI

U.S. Nuclear Regulatory Commission Page 70 RA-23-0279 TABLE E1 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM (ESFAS) INSTRUMENTATION DIVERSITY Accident Diverse ESFAS Instrument Safety Feature Condition Protection

1) Two trains of Automatic Actuation Logic Conditions automatic Safety Injection (SI) and Actuation Relays requiring SI actuation

2) Manual SI

1) Automatic SI

a. Pressurizer Steamline break Pressure Low inside containment Low

2) Manual SI Containment Pressure - 1) Automatic SI Safety Injection (SI)

High a. Pressurizer LOCA Pressure Low Low

2) Manual SI Feed line break 1) Manual SI inside containment Inadvertent 1) Manual SI opening of a steam generator relief or safety valve

1) Automatic SI a.

Containment Pressure -

Steamline break High (if break in containment)

2) Manual SI

1) Automatic SI A spectrum of rod a.

cluster control Pressurizer Pressure - Containment Safety Injection (SI) assembly ejection Low Low Pressure -

accidents (rod High ejection)

2) Manual SI

1) Automatic SI Inadvertent a.

opening of a Containment pressurizer relief or Pressure -

safety valve High

2) Manual SI

1) Automatic SI a.

Containment LOCAs Pressure -

High

2) Manual SI

U.S. Nuclear Regulatory Commission Page 71 RA-23-0279 TABLE E1 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM (ESFAS) INSTRUMENTATION DIVERSITY Accident Diverse ESFAS Instrument Safety Feature Condition Protection SG Tube Rupture 1) Manual SI

1) Two trains of manual Containment Isolation Automatic pushbuttons Manual Initiation (Ph A) Actuation failed 2) Two trains of automatic Ph A isolation

1) Two trains of SI conditions automatic Ph Automatic Actuation Logic Containment Isolation requiring Ph A A actuation and Actuation Relays (Ph A) isolation 2) Manual Ph A isolation

1) Two trains of manual Containment Isolation Automatic pushbuttons Manual Initiation (Ph B) Actuation failed 2) Two trains of automatic Ph B isolation

1) Two trains of Conditions automatic Ph Automatic Actuation Logic Containment Isolation requiring Ph B B actuation and Actuation Relays (Ph B) isolation 2) Manual Ph B isolation

1) Manual Ph B

1) LOCA isolation Containment Pressure - Containment Isolation

2) Steamline 2) Two trains of High High (Ph B) break automatic Ph B isolation

1) Two trains of manual pushbuttons Automatic Manual Initiation (System) Steam Line Isolation 2) Two trains of Actuation failed automatic steam line isolation

1) Two trains of automatic Conditions steam line Automatic Actuation Logic Steam Line Isolation requiring steam and Actuation Relays isolation line isolation

2) Manual steam line isolation

U.S. Nuclear Regulatory Commission Page 72 RA-23-0279 TABLE E1 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM (ESFAS) INSTRUMENTATION DIVERSITY Accident Diverse ESFAS Instrument Safety Feature Condition Protection

1) Two trains of automatic steam line isolation

a. Low steam Steam Line Pressure - line pressure Steam Line Isolation Steamline break Low b. High negative steam pressure rate

2) Manual steam line isolation

1) Two trains of automatic steam line isolation

a. Low steam Steam Line Pressure line pressure Steam Line Isolation Steamline break Negative Rate - High b. High negative steam pressure rate

2) Manual steam line isolation

1) Feedwater 1) Manual system turbine trip Turbine Trip - malfunctions switches Turbine Trip and 2) Two trains of Automatic Actuation Logic that result in an Feedwater Isolation automatic And Actuation Relays increase in feedwater flow turbine trip

2) Safety Injection actuation

1) Manual Feedwater system turbine trip Turbine Trip - malfunctions that switches Turbine Trip and SG Water Level - result in an 2) Two trains of Feedwater Isolation High High increase in automatic feedwater flow turbine trip actuation

U.S. Nuclear Regulatory Commission Page 73 RA-23-0279 TABLE E1 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM (ESFAS) INSTRUMENTATION DIVERSITY Accident Diverse ESFAS Instrument Safety Feature Condition Protection

1) Feedwater 1) Manual system feedwater malfunctions isolation that result in an pushbuttons increase in 2) Two trains of Feedwater Isolation - automatic Turbine Trip and feedwater flow Automatic Actuation Logic feedwater Feedwater Isolation 2) Safety Injection And Actuation Relays isolation

3) Excessive actuation cooldown

4) Feedwater break in doghouse

1) Manual feedwater Feedwater system isolation Feedwater Isolation - malfunctions that pushbuttons Turbine Trip and SG Water Level - result in an 2) Two trains of Feedwater Isolation High High increase in automatic feedwater flow feedwater isolation actuation

1) Manual feedwater isolation Feedwater Isolation - Excessive pushbuttons Turbine Trip and Tavg-Low coincident with cooldown after 2) Two trains of Feedwater Isolation Reactor Trip, P-4 Reactor Trip automatic feedwater isolation actuation

1) Two trains of automatic Conditions auxiliary Automatic Actuation Logic Auxiliary Feedwater requiring Auxiliary feedwater And Actuation Relays Feedwater actuation

2) Manually start pump(s)

1) Two trains of automatic auxiliary SG Water Level - Low Auxiliary Feedwater Loss of heat sink feedwater Low actuation

2) Manually start pump(s)

U.S. Nuclear Regulatory Commission Page 74 RA-23-0279 TABLE E1 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM (ESFAS) INSTRUMENTATION DIVERSITY Accident Diverse ESFAS Instrument Safety Feature Condition Protection

1) Two trains of automatic auxiliary Station Blackout - Loss of Auxiliary Feedwater Loss of heat sink feedwater Voltage actuation

2) Manually start pump(s)

1) Two trains of automatic auxiliary Station Blackout -

Auxiliary Feedwater Loss of heat sink feedwater Degraded Voltage actuation

2) Manually start pump(s)

Reduce/prevent 1. Manual excessive NCS turbine trip cooldown for: 2. Manual

1) Trips feedwater turbine isolation

2) Isolate pushbuttons feedwater 3. Operator with actions in coincident EPs.

low Tavg 4. Manually

3) Prevent re- close actuation of feedwater Reactor Trip, P-4 ESFAS Interlocks SI after a isolation manual valves reset of SI 5. Two trains of

4) Prevent P-4 signal opening of feedwater isolation valves if they were closed on SI or SG Water Level

- High High

U.S. Nuclear Regulatory Commission Page 75 RA-23-0279

6.0 DESCRIPTION

OF ELECTRICAL POWER SYSTEMS AND NON-UNIFORM LOADING AT MCGUIRE Offsite Power The offsite power systems consist of all sources of electric power and their associated transmission systems outside of the generating station. The boundary between the Offsite Power System and the Onsite Power System is the main stepup transformer terminations on the low voltage side. On Unit 1, the 230kV switchyard provides offsite power through two separate and independent overhead transmission lines, Buslines (BL) 1A and 1B connected to Main Step-up Transformers (MSUT) 1A and 1B. On Unit 2, the 525kV switchyard provides offsite power through two separate and independent overhead transmission lines, BL 2A and BL 2B, connected to MSUTs 2A and 2B. The secondary (low voltage) side of all 4 MSUTs operates at 24kV and each feeds station auxiliary loads through unit auxiliary transformers 1ATA, 1ATB, 2ATA and 2ATB, respectively. Each of these unit auxiliary transformers has the capacity to carry all the auxiliaries of one operating nuclear unit plus the safety shutdown loads of the other nuclear unit. Also, each unit auxiliary transformer (24kV/6.9kV) has two secondary windings with each winding supplying a 6.9 kV switchgear group. These 6.9kV switchgear groups supply all unit auxiliaries including normal and alternate connections to the essential 4160V ESF buses (1ETA, 1ETB, 2ETA and 2ETB). Upon loss of one of the independent offsite circuits, the affected 6.9kV switchgear groups automatically transfer to the other unit auxiliary transformer.

Essential Bus Power Sources As described above, the essential ESF 4160V buses (1ETA, 1ETB, 2ETA and 2ETB) are normally powered from offsite power via the 6.9kV switchgear groups. Each essential 4160V bus also has a dedicated onsite diesel generator (DG) source. If the normal and alternate offsite sources are unavailable, the onsite emergency DG supplies power to the 4160V ESF bus.

There are also provisions to accommodate the connecting of the Emergency Supplemental Power Source (ESPS) to one train of either units Class 1E AC Distribution System. The ESPS consists of two 50% capacity non-safety related commercial grade DGs. Manual actions are required to align the ESPS to the station and only one of the stations four onsite Class 1E Distribution System trains can be supplied by the ESPS at any given time.

Non-Uniform Loading (Shared Systems)

McGuire has several shared systems/components powered from the essential ESF 4160V buses. These shared systems/components are:

x Nuclear Service Water System (NSWS) shared valves x Control Room Area Ventilation System (CRAVS) x Control Room Area Chilled Water System (CRACWS) x Auxiliary Building Filtered Ventilation Exhaust System (ABFVES) x Groundwater Drainage System The A Train shared loads are normally aligned to Unit 1,1ETA. The B Train shared loads are normally aligned to Unit 2, 2ETB. But if desired or required to maintain operability of the shared systems, they can be swapped to receive power from the other Unit (A Train to 2ETA and B Train to 1ETB).

U.S. Nuclear Regulatory Commission Page 76 RA-23-0279 Table E1-6 below documents the shared loading scheme:

Table E1-6: McGuire Shared Essential Loads Electrical Alignment 1ETA Bus (4160V) 1ETB Bus (4160V) 2ETA Bus (4160V) 2ETB Bus (4160V)

A CRACWS Chiller B CRACWS Chiller A CRACWS Chiller B CRACWS Chiller (Normal) (Alternate) (Alternate) (Normal) 1EMXG 600 V Loads 2EMXG 600 V Loads 1EMXG 600 V Loads 2EMXG 600 V Loads (Normal) (Alternate) (Alternate) (Normal) x A Train x B Train x A Train x B Train CRACWS CRACWS CRACWS CRACWS components components components components x A Train x B Train x A Train x B Train CRAVS CRAVS CRAVS CRAVS components components components components x A Train x B Train x A Train x B Train ABFVES ABFVES ABFVES ABFVES components components components components x One A Train x Three B Train x One A Train x Three B Train Groundwater Groundwater Groundwater Groundwater Drainage Drainage Drainage Drainage Sump Pump Sump Pumps Sump Pump Sump Pumps 1EMXH 600 V Loads 2EMXH 600 V Loads 1EMXH 600 V Loads 2EMXH 600 V Loads (Normal) (Alternate) (Alternate) (Normal) x A Train x B Train x A Train x B Train NSWS shared NSWS shared NSWS shared NSWS shared valves valves valves valves x A Train x B Train x A Train x B Train CRACWS CRACWS CRACWS CRACWS components components components components x A Train x B Train x A Train x B Train CRAVS CRAVS CRAVS CRAVS components components components components x A Train x B Train x A Train x B Train ABFVES ABFVES ABFVES ABFVES components components components components x Two A Train x Two A Train Groundwater Groundwater Drainage Drainage Sump Pumps Sump Pumps (1EMXH-1) (1EMXH-1)

U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 ENCLOSURE 4 INFORMATION SUPPORTING JUSTIFICATION OF EXCLUDING SOURCES OF RISK NOT ADDRESSED BY THE PRA MODELS

U.S. Nuclear Regulatory Commission Page 2 RA-23-0279

1.0 INTRODUCTION

AND SCOPE Topical Report NEI 06-09, Revision 0-A (Reference 1), as clarified by the Nuclear Regulatory Commission (NRC) final safety evaluation (Reference 2), requires that the License Amendment Request (LAR) provide a justification for exclusion of risk sources from the Probabilistic Risk Assessment (PRA) model based on their insignificance to the calculation of configuration risk as well as discuss conservative or bounding analyses applied to the configuration risk calculation.

This enclosure addresses this requirement by discussing the overall generic methodology to identify and disposition such risk sources. This enclosure also provides the McGuire Nuclear Station (MNS) specific results of the application of the generic methodology and the disposition of impacts on the MNS Risk-Informed Completion Time (RICT) Program. Section 3 of this enclosure presents the plant-specific analysis of the MNS seismic hazard. Section 4 of this enclosure presents the plant specific analysis of the MNS high wind hazard. Section 5 presents the justification for excluding External Flooding for MNS. Section 6 of this enclosure presents the justification for excluding analyses of other external hazards from the MNS PRA.

Topical Report NEI 06-09 does not provide a specific list of hazards to be considered in a RICT Program. However, non-mandatory Appendix 6-A in the ASME/ANS PRA Standard (Reference 3) provides a guide for identification of most of the possible external events for a plant site. Additionally, NUREG-1855 (Reference 4) provides a discussion of hazards that should be evaluated to assess uncertainties in plant PRAs and support the risk-informed decision-making process. This information was reviewed for the MNS site and augmented with a review of information on the site region and plant design to identify the set of external events to be considered. The information in the UFSAR regarding the geologic, seismologic, hydrologic, and meteorological characteristics of the site region as well as present and projected industrial activities in the vicinity of the plant were also reviewed for this purpose. No new site-specific and plant-unique external hazards were identified through this review. The list of hazards in Appendix 6-A of the PRA Standard were considered for MNS as summarized in Table E4-6.

The scope of this enclosure is consideration of the hazards in Table E4-6 for MNS. As explained in subsequent sections of this enclosure, risk contributions from seismic and high wind events are evaluated quantitatively, and the other listed external hazards are evaluated and screened as having low risk.

2.0 TECHNICAL APPROACH The guidance contained in NEI 06-09 states that all hazards that contribute significantly to incremental risk of a configuration must be quantitatively addressed in the implementation of the RICT Program. The following approach focuses on the risk implications of specific external hazards in the determination of the risk management action time (RMAT) and RICT for the Technical Specification (TS) Limiting Conditions for Operation (LCOs) selected to be part of the RICT Program.

Consistent with NUREG-1855 (Reference 4), external hazards may be addressed by:

1) Screening the hazard based on a low frequency of occurrence,

2) Bounding the potential impact and including it in the decision-making, or

3) Developing a PRA model to be used in the RMAT/RICT calculation.

U.S. Nuclear Regulatory Commission Page 3 RA-23-0279 The overall process for addressing external hazards considers two aspects of the external hazard contribution to risk.

x The first is the contribution from the occurrence of beyond design basis conditions, e.g.,

winds greater than design, seismic events greater than the design-basis earthquake (DBE), etc. These beyond design basis conditions challenge the capability of the SSCs to maintain functionality and support safe shutdown of the plant.

x The second aspect addressed is the challenges caused by external conditions that are within the design basis, but still require some plant response to assure safe shutdown, e.g., high winds or seismic events causing loss of offsite power, etc. While the plant design basis assures that the safety related equipment necessary to respond to these challenges are protected, the occurrence of these conditions nevertheless causes a demand on these systems that present a risk.

Hazard Screening The first step in the evaluation of an external hazard is screening based on an estimation of a bounding core damage frequency (CDF) for beyond design basis hazard conditions. An example of this type of screening is reliance on the NRCs 1975 Standard Review Plan (SRP)

(Reference 5), which is acknowledged in the NRCs Individual Plant Examination of External Events (IPEEE) procedural guidance (Reference 6) as assuring a bounding CDF of less than 1E-6/yr for each hazard. The bounding CDF estimate for hazard screening is often characterized by the likelihood of the site being exposed to conditions that are beyond the design basis limits and an estimate of the bounding conditional core damage probability (CCDP) for those conditions. If the bounding CDF for the hazard can be shown to be less than 1E-6/yr, then beyond design basis challenges from that hazard can be screened out and do not need to be addressed quantitatively in the RICT Program.

The basis for this hazard screening approach is as follows:

x The overall calculation of a RICT is limited to an incremental core damage probability (ICDP) of 1E-5.

x The maximum time interval allowed for a RICT is 30 days.

x If the maximum CDF contribution from a hazard is <1E-6/yr, then the maximum ICDP from the hazard is <1E-7 (1E-6/yr

• 30 days/365 days/yr).

x Thus, the bounding ICDP contribution from the hazard is shown to be less than 1% of the permissible ICDP in the bounding time for the condition. Such a minimal contribution is not significant to the decision in computing a RICT.

The MNS IPEEE hazard screening analysis (Reference 7) has been updated to reflect current MNS site conditions. The results are discussed in Section 6 and show that all the events listed in Table E4-6 can be screened except seismic events for McGuire. While high winds can be screened at McGuire based on average risk, there are configuration specific conditions identified for McGuire such that development of a High Winds RICT penalty was warranted as discussed in Section 4 below.

U.S. Nuclear Regulatory Commission Page 4 RA-23-0279 Hazard Analysis - CDF and LERF There are two options in cases where the bounding CDF for screening purposes for an external hazard cannot be shown to be less than 1E-6/yr. The first option is to develop a PRA model that explicitly models the challenges created by the hazard and the role of the SSCs included in the RICT Program in mitigating those challenges. The second option for addressing an unscreened external hazard is to compute CDF and LERF estimates for the hazard that are employed conservatively in RICT calculations. This second option is referred to as a hazard penalty approach. Section 3 describes the method used to calculate seismic CDF and LERF penalty values and Section 4 describes the high wind penalty values; both will be used in the calculation of RICT. This seismic and high wind penalty values will be added to the internal events and fire CDF and LERF to calculate the RICT; the seismic and high wind penalty values will apply to all RICT configurations.

High Wind (HW) Hazard Duke Energy requests use of the High Winds PRA to be retained as an option for this application. As noted in other sections of this LAR, the MNS High Winds PRA is a RG 1.200 Revision 2 compliant model that represents the as-built, as-operated plant. Due to current computing limitations the model cannot be quantified in a timely manner to support real-time risk scenarios. As these computing limitations are resolved, Duke Energy could use the High Winds PRA in the real time risk monitor tool similar to how the Fire PRA model is applied in the tool via the one-top all hazard PRA model. Since the High Winds PRA is a realistic model, the risk contribution for most scenarios is actually much less than the reasonably bounding penalty proposed above. The impact to RICTs calculated to be near 30 days is non-trivial when comparing the HW penalty factor to the HW PRA. For example, if a RICT is calculated to be 25 days with the proposed 1E-5 HW penalty factor, using the HWPRA instead of the penalty would provide approximately an additional 2 days on the RICT. Additionally, and more impactful in this application, using the more realistic risk calculation from the HWPRA will allow the risk to accrue at a lower rate against the annual RICT risk budget when any RICTs entered. The ability to use the HW PRA would benefit this application, while maintaining integrity of the risk calculations.

Duke Energy will only use one HW risk assessment methodology, penalty or PRA quantification, for any RICT entry. RICT program documentation will include which method was applied when calculating the results for a particular RICT.

Risks from Hazard Challenges Given the selection of an estimated bounding CDF/LERF, the approach considered must assure that the RICT Program calculations reflect the change in CDF/LERF caused by the out of service equipment. For MNS, as discussed later in this enclosure, the only beyond design basis hazard that could not be screened out are the seismic hazard, and the approach used considers that the change in risk with equipment out of service will not be higher than the estimated seismic CDF. In addition, while the high wind hazard for MNS was screened for the average test and maintenance conditions, it could not be screened under RICT configuration-specific conditions.

The above steps address the direct risks from damage to the facility from external hazards.

While the direct CDF contribution from beyond design basis hazard conditions can be shown to be non-significant using these steps without a full PRA, there are risks that may be addressed.

U.S. Nuclear Regulatory Commission Page 5 RA-23-0279 These risks are related to the fact that some external hazards can cause a plant challenge even for hazard severities that are less than the design basis limit. For example, high winds, tornadoes, and seismic events below the design basis levels can cause extended loss of offsite power conditions. Additionally, depending on the site, external floods can challenge the availability of normal plant heat removal mechanisms.

The approach taken in this step is to identify the plant challenges caused by the occurrence of the hazard within the design basis and evaluate whether the risks associated with these events are either already considered in the existing PRA model or they are not significant to risk.

3.0 SEISMIC RISK CONTRIBUTION ANALYSIS The updated seismic risk contribution analysis is documented in the Response to the NRC audit APLC Question 1 [Seismic Risk Contribution Analysis (For TSTF-505 LAR)]. The response contains the seismic analysis and the derived seismic penalty values that will be used for the TSTF-505 RICT program. Sections 3.1 through 3.5 and 3.7 are superseded by the response to the NRC audit APLC Question 1.

3.6 Seismic Induced Loss of Offsite Power Previous TSTF-505 applications have also included discussion and evaluation of any incremental risk associated with challenges to the facility that do not exceed the design capacity and the past submittals have focused on the challenge of seismically-induced LOOP.

The MNS seismic penalty calculations already encompass seismic events within (i.e., at or below) the design basis by conservatively including very low magnitude seismic events (as low as 0.0005g peak ground acceleration, PGA, i.e., significantly lower than the MNS SSE) in the SCDF and SLERF seismic penalty convolution calculations. Additional discussions and calculations are provided below.

The methodology for computing the seismically-induced LOOP frequency is to convolve the MNS mean seismic hazard curve with the offsite power fragility. Past TSTF-505 applications have approached this discussion conservatively by performing the convolution over the entire hazard curve (not just below the design basis). That same approach is used in this discussion. The MNS seismic hazard curve is discussed in the response to the NRC audit APLC Question 1 [Seismic Risk Contribution Analysis (For TSTF-505 LAR)].

Table E4-4 provides the mean seismic hazard data and the LOOP seismic-induced failure probability (increasing with increase seismic magnitude) based on the fragility of offsite power.

The convolution calculation includes the entire hazard curve from earthquakes magnitudes well below the MNS operating basis earthquake to well beyond the MNS safe shutdown earthquake (SSE=0.15g PGA).

The failure probabilities for LOOP are represented by failure of ceramic insulators in the power distribution system, based on the following fragility data from Table A-0-4 of the NRC RASP Handbook, Volume 2 (Reference 25), this is a common offsite power fragility used for Central and Eastern US SPRAs:

Offsite Power Capacity (ceramic insulators): Am = 0.30g; r = 0.30, u = 0.45 Given the mean frequency and failure probability for each seismic interval, it is straightforward to compute the estimated frequency of seismically induced loss of offsite

U.S. Nuclear Regulatory Commission Page 6 RA-23-0279 power for the MNS site by taking the product of the interval frequency and the offsite power failure probability. As shown in Table E4-4, the total seismic LOOP frequency across the entire seismic hazard curve approximately 7.3E-05/yr. Note that this overstates the below-design challenge frequency but is conservative for this purpose.

Table E4-4: MNS Seismic Induced LOOP Frequency Estimate (Across Entire Hazard Curve)

The FPIE PRA models LOOP frequency is derived from plant-centered, switchyard-centered, grid-related, and weather-related events. Based on the MNS FPIE PRA, the total frequency of unrecovered loss of offsite power (i.e., the sum of the frequency multiplied by the non-recovery probability at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> over these LOOP events), is 5.2E-4/yr.

The total (i.e., across the entire hazard curve) seismically-induced (unrecoverable) LOOP frequency is approximately 14% (i.e., 7.3E-05 / 5.2E-04 = 14%) of the total unrecovered LOOP frequency already addressed in the MNS FPIE PRA. The below-design basis (i.e., less than SSE of 0.15g PGA) seismic-induced LOOP frequency is approximately 2% (i.e., 1.0E-05 / 5.2E-04 =

2%) of the total unrecovered LOOP frequency already addressed in the MNS FPIE PRA; this frequency is judged to be a reasonably small fraction that it will not significantly impact the RICT Program calculations, and it can be omitted. In addition, as previously stated, the MNS SCDF and SLERF seismic penalty values already address the fraction of seismic-induced LOOP events within (i.e., at or below) the design basis by conservatively including very low magnitude seismic events in the seismic penalty convolution calculations.

U.S. Nuclear Regulatory Commission Page 7 RA-23-0279 4.0 EXTREME WINDS ANALYSIS This section provides an analysis of the High Winds / Tornados risk impact for MNS. Since MNS has a High Winds (HW) PRA model, it is used as the primary input to this analysis. The HW PRA model includes CDF and LERF for both units, and includes straight winds, tornado, and hurricane hazards. Detailed documentation of this analysis is provided in Reference 26.

4.1 High Winds Loss of Offsite Power Events Approximately 75% of the MNS HW PRA CDF (~65% of LERF) is due to wind-induced LOOP events with random equipment and operator failures along with failure to recover offsite power.

Thus, a large percentage of the total HW PRA CDF does not involve any wind-induced (wind pressure or missile) failures except for the loss of offsite power.

These lower wind speed scenarios are similar to typical internal event weather-related LOOP scenarios, with the exception that the HW PRA conservatively assumes no offsite power recovery. Ninety-nine percent of the Unit 1 CDF (98% of LERF) from these wind-induced LOOP scenarios (without additional wind-induced failures) is from F1 and F2 wind speeds (i.e., less than or equal to 157 mph) and approximately 83% of CDF and LERF is from F1 wind speeds (less than or equal to 112 mph).

The weather-related LOOP contribution to the internal events CDF subsumes these more frequent low wind speed events and the assumption that offsite power is not recovered for lower wind speed events (especially F1 winds) is very conservative (Reference 27). While it is acknowledged that high intensity winds (e.g., F3 and greater) are rare and may not be fully represented in the (data-based) weather-related LOOP frequency, it is reasonable to expect that the lower intensity events are already accounted for in the internal events model. Since the internal events sequences consider the likelihood of offsite power recovery, they are judged to be more realistic. The higher intensity events are a small contributor to the HW CDF.

Therefore, non-recoverable wind-induced LOOP events without wind-induced failures can be screened using Criterion C4 (event is included in the definition of another event). The resulting CDF and LERF, after removing the cutsets with only random failures and operator actions is referred to as the "HW Failures Only" CDF and LERF. The method used to determine the HW Failures Only results is to apply recovery rules to eliminate cutsets that do not include wind pressure or missile fragility basic events.

For this TSTF-505 application, the "HW Failures Only" CDF is also less than 1E-6/yr. However, this is the average maintenance case and does not reflect the CDF associated with configurations that could be entered into during a RICT configuration. A review of Risk Achievement Worth (RAW) values in the "HW Failures Only" scenarios indicates that the CDF for some configurations (e.g., DC power, emergency diesel generators (EDGs), or Nuclear Service Water (RN) Trains unavailable) would have CDF greater than 1E-6/yr. Therefore, a penalty factor is warranted to account for the HW risk during RICT configurations.

4.2 Hurricanes The TSTF-505 application (i.e., RICT program) is an at-power only application (i.e., Modes 1 and 2) and not for shutdown conditions. Site procedures for response to severe weather directs Operations personnel to place the plant in Mode 3 at least two hours prior to the anticipated arrival of sustained winds in excess of 74 mph at the site (References 28 and 29). Hurricanes

U.S. Nuclear Regulatory Commission Page 8 RA-23-0279 therefore do not apply to the RICT Program and can be screened from inclusion in RICT Program calculations.

4.3 Development of Penalty Factors The current high winds PRA model of record (Reference 26) was used as the primary input into the screening analysis and development of penalty factors. This screening analysis is based on CDF being less than 1E-6/yr (PS4 - Bounding mean CDF is < 1E-6/yr.). For this TSTF-505 application, penalty factors are developed since not all RICT configurations screen.

Conservative penalty factors were developed and are based on the HW PRA.

As discussed in Reference 26, the total CDF for HW hazards is 3.0E-6/yr and 3.1E-6/yr for Units 1 and 2, respectively. LERF is approximately 1.1E-7/yr for both units. These values are above the numerical screening criteria of 1E-6/yr and 1E-7/yr for CDF and LERF. However, a large percentage of CDF and LERF (approximately 75% and 65%, respectively) are wind-induced LOOP events with random equipment and operator failures and failure to recover offsite power.

The CDF and LERF due to scenarios/sequences involving wind-induced failures, either wind pressure or wind-borne missiles, are estimated to be approximately 8E-7/yr and 4E-8/yr, respectively. Nearly all of these scenarios are associated with wind speeds in the F1 to F2 range (less than or equal to 157 mph).

Although average maintenance CDF and LERF are less than 1E-6/yr and 1E-7/yr, the CDF and LERF associated with certain LCO configurations are greater than 1E-6/yr and 1E-7/yr.

Therefore, conservative penalty factors are used to account for the HW hazard risk in configuration RICT calculations. The penalty factors assigned are:

x CDF Penalty Factor = 1E-5/yr for both units, except for LCO/SSC combinations a higher penalty is assigned as shown below.

x CDF Penalty Factor = 3E-5/yr for both units, for the following LCO/SSC combinations:

o 3.3.2.H for AFW Actuation Logic o 3.3.5.B for any 2 channels of loss of power signals for B Bus.

o 3.8.4.A for D 125VDC Channel o 3.8.9.C for D 125VDC I&C Panel Powerboard x LERF Penalty Factor = 1E-6/yr for both units FLEX strategies are not credited in the high wind PRA used to develop the HW penalty values, which contributes to the demonstrably conservative values. Furthermore, the CDF and LERF values calculated for some LCO configurations do not account for procedural guidance (e.g.,

References 29 and 28) to return equipment to service in the event of certain weather situations, which is conservative.

4.4 Extreme Winds Conclusions This screening analysis is based on CDF being less than 1E-6/yr (PS4 - Bounding mean CDF is

< 1E-6/yr.). For this TSTF-505 application, while average yearly CDF and LERF values are below the screening threshold, HW penalty factors were developed since not all RICT configurations screen as discussed below. Conservative penalty factors were developed and are based on the HW PRA.

U.S. Nuclear Regulatory Commission Page 9 RA-23-0279 The CDF and LERF values calculated for some LCO configurations do not account for procedural guidance (e.g., References 27 and 28) to return equipment to service in the event of certain weather situations, which is conservative.

5.0 EXTERNAL FLOODING ASSESSMENT 5.1 Current Risk Basis This analysis reviews all flood causing mechanisms for applicability to MNS and provides a basis for screening the mechanisms from further consideration. Given the new information available following the completion of the post-Fukushima flood reevaluation activities, this calculation will provide the justification for screening the external flood hazard from further consideration in the MNS PRA and future risk-informed applications. The hazards considered in the Flood Hazard Reevaluation Report (FHRR - Reference 30) include:

x Tsunami x Ice-induced Flooding x Channel Diversion x Flooding in Streams and Rivers x Failure of Dams o Upstream (Combined Event) o Standby Nuclear Service Water Pond Dam (downstream) x Probable Maximum Storm Surge x Seiche x Local Intense Precipitation x Combined Effects The FHRR evaluated the nine flooding hazards listed above. Below are the flooding mechanisms exceeding the Current Design Basis (CDB) as per the MNS FHRR and which could pose a potential challenge to MNS key safety functions:

x Local Intense Precipitation (LIP) x Flooding in Streams and Rivers (referred to as Flooding in Reservoirs in MNS FHRR) x Failure of Dams x Probable Maximum Storm Surge and Seiche/Wind Wave Runup The worst-case scenario for mechanisms other than LIP (henceforth referred to as Combined Effects (CE) flooding), produces a maximum still water elevation (SWE) of 778.5 ft mean sea level (msl) for Lake Norman as shown below in Table E4-5: McGuire Flood Scenarios and Parameters (Reference 30). Wind wave runup (part of the storm surge flooding mechanism stated above) was determined to be 778.54 ft msl. Due to the high-water levels on Lake Norman, the protective embankments north of the site would be overtopped due to the reevaluated maximum water surface elevations (WSEs), resulting in an on-site water level of 760.7 ft msl.

The LIP flood causing mechanism also was found to exceed the CDB and produces a maximum WSE of 761.1 ft around the Auxiliary Building (AB) which houses all SSCs related to maintaining key safety functions (KSFs). Additionally, parameters for warning time, site preparation and period of inundation were determined, as they were not previously included in the design basis for MNS.

U.S. Nuclear Regulatory Commission Page 10 RA-23-0279 Table E4-5: McGuire Flood Scenarios and Parameters (Reference 30)

Flood Scenario Parameter CDB Reevaluated Bounded Flood Flood or Not Hazard Hazard Bounded CE Flood Max Still Water Elevation (ft. MSL) 767.9 778.5 NB Max Wave Run-up Elevation 774.75 778.54 NB Local Max Still Water Elevation (ft. MSL) 760.4 761.1 NB Intense Precipitation Warning Time (hours) N/I* 72 NB Period of Site Preparation (hours) N/I* 24 NB Period of Inundation (hours) N/I* 2.5 NB

• Note: N/I is Not Included.

Following the conclusion of the FHRR, permanent protective barriers on the north embankment were installed to raise the flood protection levels at the site to prevent water from the CE flood encroaching on the AB. This modification is permanent, passive protection that does not require any human actions to keep the site dry.

For the LIP mechanism, MNS relies on installing temporary, engineered flood barriers at several locations around the AB. Plant procedures discuss that the site receives warnings of an approaching storm that could produce rainfall greater than 5.35 or more over a 24-hour period within the next 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The site begins preparations to install flood barriers approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before the arrival of the storm. These barriers require approximately 1.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to install (References 32 and 33). The barriers are engineered for rapid deployment and ample recovery time is available should troubleshooting or reinstallation be required. With the barriers in place, all SSCs related to KSFs are maintained free from flood waters throughout the event.

5.2 Challenges Posed Weather induced Loss of Offsite Power (LOSP) is a potential challenge. However, the risk from this challenge is subsumed in the Internal Events PRA, as the initiator and consequences are included in that model. Once the flood barriers are in place, offsite power is not required for a successful response or to screen the XF hazards.

5.3 Disposition for LAR Development for Risk-Informed Applications Disposition for TSTF-505 Program The CE flood requires no actions, modifications, or configuration specific considerations given the permanent installation of flood barriers along the embankment preventing water from

U.S. Nuclear Regulatory Commission Page 11 RA-23-0279 entering the site. The site is considered dry with no postulated impacts from these mechanisms.

For the LIP event, evaluation of the Overall Site Response was provided in Section 6 of the Focused Evaluation (FE - Reference 32) and received staff concurrence in the Staff Assessment of the FE (Reference 33). In their assessment, NRC staff concluded in Section 3.3.5 of Reference 33 that the licensee has demonstrated that adequate passive features exist to provide flood protection of key SSCs against a beyond-design-basis LIP event.

Based on the plant design and procedural response, the CE flood and LIP event are screened from further consideration in the TSTF-505 program based on Criterion C1 where the event damage potential is less than events for which the plant is designed. In addition to Criterion C1, Criterion C5 also applies to the External Flood hazard. The External Flood hazard at MNS develops slowly, allowing adequate time to eliminate or mitigate the hazard or its impact on the plant.

Configuration Specific Considerations There are no configuration specific considerations for this hazard.

6.0 EVALUATION OF EXTERNAL EVENT CHALLENGES AND IPEEE UPDATE RESULTS This section provides an evaluation of other external hazards. The results of the assessment of these hazards are provided in Table E4-6. Table E4-7 provides the summary criteria for screening of the hazards listed in Table E4-6.

Hazard Screening The IPEEE for MNS provides an assessment of the risk to MNS associated with these hazards.

Additional analyses have been performed since the IPEEE to provide updated risk assessments of various hazards, such as aircraft impacts, industrial facilities and pipelines, and external flooding. These analyses are documented in the UFSAR (Reference 38). Table E4-6 reviews and provides the bases for the screening of external hazards, identifies any challenges posed, and identifies any additional treatment of these challenges, if required. The conclusions of the assessment, as documented in Table E4-6, assure that the hazard either does not present a design-basis challenge to MNS, or is adequately addressed in the PRA.

In the application of Risk-Informed Completion Times, a significant consideration in the screening of external hazards is whether particular plant configurations could impact the decision on whether a particular hazard that screens under the normal plant configuration and the base risk profile would still screen given the particular configuration. The external hazards screening evaluation for MNS has been performed accounting for such configuration-specific impacts. The process involves several steps.

As a first step in this screening process, hazards that screen for one or more of the following criteria (as defined in Table E4-7) still screen regardless of the configuration, as these criteria are not dependent on the plant configuration.

x The occurrence of the event is of sufficiently low frequency that its impact on plant risk does not appreciably impact CDF or LERF. (Criterion C2)

U.S. Nuclear Regulatory Commission Page 12 RA-23-0279 x The event cannot occur close enough to the plant to affect it. (Criterion C3) x The event which subsumes the external hazard is still applicable and bounds the hazard for other configurations (Criterion C4) x The event develops slowly, allowing adequate time to eliminate or mitigate the hazard or its impact on the plant. (Criterion C5)

The next step in the screening process is to consider the remaining hazards (i.e., those not screened per the above criteria) to consider the impact of the hazard on the plant given particular configurations for which a RICT is allowed. For hazards for which the ability to achieve safe shutdown may be impacted by one or more such plant configurations, the impact of the hazard to particular SSCs is assessed and a basis for the screening decision applicable to configurations impacting those SSCs is provided.

As noted above, the configurations to be evaluated are those involving unavailable SSCs whose LCOs are included in the RICT program.

Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the IPEEE (Reference 35),

an assessment of aircraft impact risk was performed with the total crash probability listed as 1.3E-08/yr.

Aircraft Impact Y PS4 The assessment was updated using recent air traffic data using the guidance provided in NUREG 0800 Section 3.5.1.6 (Reference 36). The primary change that has occurred 1

The list of hazards and their potential impacts considered those items listed in Tables D-1 and D-2 in Appendix D of RG 1.200, Rev. 3 (Reference 42).

2 See Table E4-7 for descriptions of the screening criteria.

U.S. Nuclear Regulatory Commission Page 13 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 since the conduct of the IPEEE analyses is the increase in air traffic, particularly commercial air traffic that uses the Charlotte-Douglas International Airport (CLT).

To assess the current risk, recent data for CLT were obtained via a query of the Air Traffic Activity System (ATADS) database. Data from 2017 through 2021 (5 years) were obtained (Reference 37).

The largest value of annual air operations was 579,147 for calendar year 2019. Because air traffic was significantly reduced from 2020 - 2022 due to the COVID-19 pandemic, a conservative value of 600,000 annual total air operations for the CLT airport was assumed and then increased by 25% to account for other air operations (e.g., flyovers and landings at secondary airports); this provides a reasonable conservative estimate of 750,000 annual flights in the CLT area. As in

U.S. Nuclear Regulatory Commission Page 14 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 the IPEEE, this total population was apportioned equally among the four possible directions; resulting in a target population of 187,500 flights that would be within the sector that could potentially result in a crash onto the MNS plant site.

The analysis applied the methods used in the IPEEE using the same assumed apportionment among the two applicable air corridors (V37 and V454). This analysis resulted in an updated value of the probability of an aircraft crash onto the MNS site of 3.2E-8, which is a factor of 3 below the risk criteria specified in the NRC Standard Review Plan (SRP) for probability of aircraft accidents that could result in releases that exceed 10CFR100 limits of less than 1E-7 per year.

Based on this review, the Aircraft Impact hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 15 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

there are no mountains in the vicinity of McGuire from which a significant avalanche could be generated.

Based on this review, the Avalanche Y C3 Avalanche hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

This hazard is slow to develop and can be identified via monitoring and managed via standard maintenance process. Actions committed to and completed by MNS in Biological Events Y C5 response to Generic Letter 89-13 provide on-going control of biological hazards. These include performance of periodic maintenance work orders to inspect the intake structures, perform flow

U.S. Nuclear Regulatory Commission Page 16 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 balance/testing, periodic flushing, and heat exchanger cleaning.

Based on this review, the Biological Events hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

McGuire is located more than 150 miles from the nearest coastal area. However, to protect the lake edge from erosion, the yard areas subjected to waves are protected by riprap underlain by a thick subgrade of filter Coastal Erosion Y C1 material. Therefore, lake edge erosion will not be a significant problem.

Based on this review, the Coastal Erosion hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be

U.S. Nuclear Regulatory Commission Page 17 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

The effect of a drought at McGuire is insignificant because there are upstream dams that provide water level control on Lake Norman.

Drought Y C1 Based on this review, the Drought hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

See Section 5.

Based on this review, the External Flood hazard is considered to be negligible.

External Flood Y C1, C5 There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

U.S. Nuclear Regulatory Commission Page 18 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 See Section 4 of this Enclosure for use of high wind penalties. However, Duke Energy requests the option to Extreme Winds use the high winds PRA in lieu N N/A and Tornadoes of high wind penalties. See Section 2, "High Wind Hazard."

Per the IPEEE (Reference 35),

accident data involving surface vehicles or aircraft would include the effects of fog.

Per the UFSAR Section 2.3.2.3 (Reference [38],

consideration has been given to possible environmental effects associated with heat dissipation from the cooling pond (Lake Norman, vicinity of Fog Y C1 McGuire Nuclear Station). A review of the literature and operating experience to date would suggest that effects of fogging and icing are minimal for the properly designed cooling pond.

Based on this review, the Fog hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 19 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

bush and local forest fires are handled by the local fire department. Such fires are not considered to have any impact on the station because the site is cleared and the fire cannot propagate to station buildings or equipment.

Per the UFSAR Section 2.2.3 (Reference 38), the only potential fire hazard in the Forest Fire Y C1 plant vicinity is a brush fire.

The plant fire protection system is adequate to prevent any possible damage from a fire due to this origin.

Based on this review, the Forest Fire hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

U.S. Nuclear Regulatory Commission Page 20 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the IPEEE (Reference 35),

both the Reactor Building and the Auxiliary Building are designed for a combination of snow, ice, and rain. (C1)

In addition, the principal effects of such events would be to cause a loss of off-site power, which is addressed for C1 weather-related LOOP Frost Y scenarios in the FPIE PRA C4 model for McGuire. (C4)

Based on this review, the Frost hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

both the Reactor Building and the Auxiliary Building are designed for a combination of C1 snow, ice, and rain. (C1)

Hail Y C4 In addition, the principal effects of such events would be to cause a loss of off-site power, which is addressed for

U.S. Nuclear Regulatory Commission Page 21 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 weather-related LOOP scenarios in the FPIE PRA model for McGuire. (C4)

Based on this review, the Hail hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

the effect of high summer temperatures at McGuire is insignificant because there are upstream dams that provide water level control on Lake Norman.

In addition, the principal High Summer C1 effects of such events would Y

Temperature C4 be to cause a loss of off-site power, which is addressed for weather-related LOOP scenarios in the FPIE PRA model for McGuire. (C4)

Based on this review, the High Summer Temperature hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 22 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

McGuire is located more than 150 miles from the nearest coastal area.

See also External Flood High Tide Y C4 Based on this review, the High Tide hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

See Section 4, "Hurricanes" and External Flood / Intense Precipitation.

Based on this review, the Hurricane Hurricane (Tropical Cyclone)

Y C4 (Tropical Cyclone) hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be

U.S. Nuclear Regulatory Commission Page 23 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

Both the Reactor Building and the Auxiliary Building are designed for ice. (C1)

In addition, the principal effects of such events would be to cause a loss of off-site power, which is addressed for C1 weather-related LOOP Ice Cover Y scenarios in the FPIE PRA C4 model for McGuire. (C4)

Based on this review, the Ice Cover hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

there are no military or industrial facilities within a 5-Industrial or mile radius of the plant.

Military Facility Y C1 Accident Per UFSAR Section 2.2 (Reference [38]), military and transportation facilities are nearly non-existent and only a

U.S. Nuclear Regulatory Commission Page 24 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 few industrial facilities are located in the vicinity of McGuire. The few facilities that do exist have no effect on the McGuire Nuclear Station nor will McGuire Nuclear Station have any effect on the existing facilities.

Based on this review, the Industrial or Military Facility Accident hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

The McGuire Internal Events Internal Flood N/A N/A and Internal Flood PRA model addresses risk from internal Flood events.

The McGuire Internal Fire Internal Fire N/A N/A PRA model addresses risk from internal fires Per the IPEEE (Reference 35),

Landslides are considered an insignificant hazard at Landslide Y C1 McGuire. The Standby Nuclear Service Water Pond (SNSWP) dam is the only natural or man made slope

U.S. Nuclear Regulatory Commission Page 25 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 which, upon failure, would prevent safe shutdown of the plant. Therefore, the SNSWP was statically designed for stability under all loading conditions Based on this review, the Landslide hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

The most probable effect of lightning is the loss of off-site power due to a strike in the switchyard. These occurrences are accounted for in the loss of off-site power initiating event frequency.

Lightning Y C4 Based on this review, the Lightning hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

U.S. Nuclear Regulatory Commission Page 26 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the IPEEE (Reference 35),

The effect of low lake level, or low river water level at McGuire is insignificant because there are upstream dams that provide water level control on Lake Norman.

Low Lake or River Based on this review, the Low Y C1 Water Level Lake or River Water Level hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

the Reactor Building and the Auxiliary Building are designed for a combination of snow and ice. These hazards are commensurate with low winter Low Winter C1 temperatures. (C1)

Y Temperature C4 In addition, low winter temperatures causing failure of instruments are included in the plant trip frequency data.

(C4)

U.S. Nuclear Regulatory Commission Page 27 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the Low Winter Temperature hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

this event has significantly lower frequency than other events with similar uncertainties. The occurrence of a meteorite event could not result in worse consequences than other external events of a higher frequency. Therefore, this event is excluded because Meteorite/Satellite it will not significantly influence Y PS4 the total risk.

Strikes Based on this review, the Meteorite/Satellite Strikes hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

U.S. Nuclear Regulatory Commission Page 28 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the IPEEE (Reference 35),

gas pipeline maps of the area around the McGuire plant site were reviewed and indicated that there were no changes to the original PRA screening information as contained in the FSAR.

Per the FSAR Section 2.2.3 (Reference 38), there are two gas pipelines: one 36-inch diameter and one 42-inch diameter located one mile south of the plant. The consequences a rupture of the Pipeline Accident Y C3 42-inch gas pipeline rupture was evaluated. The evaluation included the potential effects of the gas at the plant, an unconfined in-air explosion, and surface blast at the point of rupture.

The evaluation found the effects of gas at the plant were well below the flammability threshold. The unconfined in-air explosion and surface blast effects only resulted in a worst-case overpressure of 1.3 to 1.8 psi at the plant, which is considered minor.

U.S. Nuclear Regulatory Commission Page 29 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the Pipeline Accident hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

U.S. Nuclear Regulatory Commission Page 30 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 See analysis in Section 5.

Based on this review, the hazard is considered to be negligible.

There are no configuration-specific considerations for this Precipitation, hazard. This hazard can be Y C1 excluded from the TSTF-505 Intense program evaluation.

Per the IPEEE (Reference 35),

potential hazards from the storage of toxic material on-site is minimal.

Per FSAR Section 2.1.4 Release of (Reference [38]), no large Chemicals from Y C1 quantities of caustic or Onsite Storage flammable material will be stored on site.

MNS updated its Toxic Gas evaluation in July 2022 (Reference 39) to evaluate onsite and offsite chemical

U.S. Nuclear Regulatory Commission Page 31 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 hazards in accordance with Regulatory Guide 1.78, Rev. 1 (Reference 40). The evaluation considered potential onsite and offsite stationary and mobile hazardous chemical sources that could pose a threat to control room habitability upon release within 5 miles of MNS.

The evaluation concluded that there are no toxic gas hazardous chemical threats to control room habitability.

Based on this review, the Release of Chemicals from Onsite Storage hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

No present means exist to divert or reroute the river flow through the dams other than River Diversion Y C1 insignificant amounts of water used for municipal supply.

Per UFSAR Section 2.4.9 (Reference 38), There are five

U.S. Nuclear Regulatory Commission Page 32 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 reservoirs on the Catawba River upstream of Cowans Ford Dam, all of which have operating hydroelectric power plants located on them. Since Duke owns and controls the levels of each reservoir above the site of McGuire Nuclear Station, any upstream diversion or rerouting of the source of cooling water is very unlikely to happen. No present means exist to divert or reroute other than minor amounts used for municipal water supply.

Based on this review, the River Diversion hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

McGuire is located more than 150 miles from the nearest Sandstorm Y C1 area with a large sand deposit.

The likelihood of occurrence is insignificant

U.S. Nuclear Regulatory Commission Page 33 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the Sandstorm hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per FSAR Section 2.4.5.2 (Reference 38), Lake Norman, immediately north of the plant, is a relatively new inland lake with no history of surge or seiche Flood.

See also External Flood.

Seiche Y C1 Based on this review, the Seiche hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Seismic Activity N N/A See Section 3.

Per the IPEEE (Reference 35),

both the Reactor Building and Snow Y C1 the Auxiliary Building are designed for snow.

U.S. Nuclear Regulatory Commission Page 34 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the Snow hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per FSAR Section 2.5 (Reference 38), extensive investigations on soil and rock samples found that subsurface conditions of the site have no adverse impact on the design, construction, or operation of the station.

Soil Shrink-Swell Y C1 Based on this review, the Soil Shrink-Swell hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

See External Flood.

Based on this review, the Storm Surge Y C1 Storm Surge hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 35 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 13),

leaks from containers of chlorine (used for drinking water purification and sanitary waste treatment) and other potential toxic gas sources were evaluated which found that it is unlikely that leaks from these containers would result in dangerous concentrations in the Control Room.

MNS updated its Toxic Gas Toxic Gas Y C1 evaluation in July 2022 (Reference 39) to evaluate onsite and offsite chemical hazards in accordance with Regulatory Guide 1.78, Rev. 1 (Reference 40).

The evaluation considered potential onsite and offsite stationary and mobile hazardous chemical sources that could pose a threat to control room habitability upon release within 5 miles of MNS.

U.S. Nuclear Regulatory Commission Page 36 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 The evaluation concluded that there are no toxic gas hazardous chemical threats to control room habitability.

See also Release of Chemicals from Onsite Storage.

Based on this review, the Toxic Gas hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

there are no industries within 5 miles of McGuire which transport or store products harmful to the station.

Per FSAR Section 2.2.2 Transportation Y C3 (Reference 38), the major Accidents north-south transportation corridors in the vicinity of the site are U.S. 321, located approximately 15 miles west of the site, N.C. 16, located approximately three miles west of the site, and I-77

U.S. Nuclear Regulatory Commission Page 37 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 located approximately five miles east of the site. The major east-west transportation corridors are I-40, located approximately 25 miles north of the site, and I-85, located approximately 12 miles south of the site. N.C. 150, located approximately 11 miles northwest of the site, and N.C.

73, located approximately 0.4 miles south of the site, are primarily used by local residents, commuters, and for recreational access to Lake Norman. There are no manufacturers or suppliers of hazardous materials within 10 miles of the site. The shipment of hazardous materials is, however, regulated by the U.S.

Department of Transportation (USDOT). Based on the USDOT regulations and the proximity of alternate major high-speed highways bypassing the site, the probability of MNS being affected by shipment of hazardous materials is insignificant.

U.S. Nuclear Regulatory Commission Page 38 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the Transportation Accidents hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

McGuire is located more than 150 miles from the nearest coastal area at an elevation of 760 ft. mean sea level.

Therefore, tsunami effects are insignificant.

See also External Flood.

Tsunami Y C3 Based on this review, the Tsunami hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

Turbine-Generated the majority of the structures Y C4 Missiles at MNS are located either along or within close proximity

U.S. Nuclear Regulatory Commission Page 39 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 to the longitudinal centerlines of the respective turbines.

Calculations on turbine missiles prepared for MNS indicate that the contribution to plant risk from the turbines would be insignificant Per FSAR Section 3.5.2.2, the credited turbine-generator missiles are low trajectory. All Category 1 structures, with the exception of the New Fuel Storage Vault exposed to this hazard are designed to withstand their effect and meet Regulatory Guide 1.115, Rev.

1 (Reference 41).

Based on this review, the Turbine-Generated Missiles hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

Per the IPEEE (Reference 35),

No active volcanoes exist Volcanic Activity Y C3 within the vicinity of McGuire.

U.S. Nuclear Regulatory Commission Page 40 RA-23-0279 Table E4-6: Evaluation of Other External Hazards1 Screening Result External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the Volcanic Activity hazard is considered to be negligible.

There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

See External Flood.

Based on this review, the Waves hazard is considered to be negligible.

Waves Y C1 There are no configuration-specific considerations for this hazard. This hazard can be excluded from the TSTF-505 program evaluation.

U.S. Nuclear Regulatory Commission Page 41 RA-23-0279 Table E4-7: Progressive Screening Approach for Addressing External Hazards Event Analysis Criterion Source C1. Event damage potential is NUREG/CR-2300 and

< events for which plant is ASME/ANS Standard designed. RA-Sa-2009 C2. Event has lower mean NUREG/CR-2300 and frequency and no worse ASME/ANS Standard consequences than other events RA-Sa-2009 analyzed.

Initial Preliminary NUREG/CR-2300 and C3. Event cannot occur close Screening ASME/ANS Standard enough to the plant to affect it.

RA-Sa-2009 NUREG/CR-2300 and C4. Event is included in the ASME/ANS Standard definition of another event.

RA-Sa-2009 C5. Event develops slowly, ASME/ANS Standard allowing adequate time to RA-Sa-2009 eliminate or mitigate the threat.

PS1. Design basis hazard ASME/ANS Standard cannot cause a core damage RA-Sa-2009 accident.

PS2. Design basis for the event NUREG-1407 and meets the criteria in the NRC ASME/ANS Standard 1975 Standard Review Plan Progressive Screening RA-Sa-2009 (SRP).

PS3. Design basis event mean NUREG-1407 as modified in frequency is < 1E-5/y and the ASME/ANS Standard mean conditional core damage RA-Sa-2009 probability is < 0.1.

NUREG-1407 and PS4. Bounding mean CDF is <

ASME/ANS Standard 1E-6/y.

RA-Sa-2009 Screening not successful. PRA NUREG-1407 and Detailed PRA needs to meet requirements in ASME/ANS Standard the ASME/ANS PRA Standard. RA-Sa-2009

U.S. Nuclear Regulatory Commission Page 42 RA-23-0279

7.0 CONCLUSION

S Based on this analysis of external hazards for MNS, no additional external hazards other than seismic events need to be added to the existing PRA model. The evaluation concluded that the hazards either do not present a design-basis challenge to MNS, the challenge is adequately addressed in the PRA, or the hazard has a negligible impact on the calculated RICT and can be excluded.

Therefore, MNS will apply a seismic penalty in the risk evaluations performed as part of the process to calculate a RICT. As described in Enclosure 10, MNS will either apply a high wind penalty or use a HW PRA in the risk evaluations performed as part of the process to calculate a RICT. All other external hazards are considered to be insignificant for this application and will not be included in the RICT calculation.

The ICDP/ILERP acceptance criteria of 1E-5/1E-6 will be used within the PHOENIX framework to calculate the resulting RICT and RMAT based on the total configuration-specific delta CDF/LERF attributed to internal events and internal fire, plus the seismic and tornado risk bounding delta CDF/LERF values.

8.0 REFERENCES

[1] Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06-09, "Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines,"

Revision 0-A, October 12, 2012 (ADAMS Accession No. ML12286A322).

[2] Letter from Jennifer M. Golder (NRC) to Biff Bradley (NEI), "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06-09, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines,"

May 17, 2007 (ADAMS Accession No. ML071200238).

[3] ASME/ANS RA-Sa-2009, "Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," Addendum A to RAS-2008, ASME, New York, NY, American Nuclear Society, La Grange Park, Illinois, February 2009.

[4] NUREG-1855, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making," Revision 1, March 2017.

[5] NUREG-75/087, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants, LWR Edition," 1975.

[6] NUREG-1407, "Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," June 1991.

[7] McGuire Nuclear Station, "IPEEE Submittal Report," June 1, 1994.

[8] Electric Power Research Institute (EPRI) NP-6041-SL, "A Methodology for Assessment of Nuclear Power Plant Seismic Margin", Revision 1, August 1991.

U.S. Nuclear Regulatory Commission Page 43 RA-23-0279

[9] McGuire Nuclear Station, Severe Accident Analysis, "McGuire PRA System Documentation; External Events - Seismic Analysis," MCC-1535.00-00-0049, Rev. 3, November 9, 2001.

[10] ENERCON, Report No. DUKCORP042-PR-002, Rev. 0, "Seismic Hazard and Screening Report for McGuire Nuclear Station," March 13, 2014.

[11] Duke Energy Letter to NRC, McGuire Nuclear Station Units 1 and 2, "Seismic Hazard and Screening Report (CEUS Sites), Response to NRC 10 CFR 50.54(f) Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) regarding Recommendations 2.1, 2.3 and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident," (ADAMS Accession No. ML14098A421), dated March 20, 2014.

[12] Electric Power Research Institute (EPRI) 3002000709, "Seismic Probabilistic Risk Assessment Implementation Guide," December 2013.

[13] Generic Letter 88-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f), Supplement 4," USNRC, June 1991.

[14] ARES Corporation, Report No. 030319.13.05.01-001, Rev. B, "IPEEE Adequacy Review for Duke Energys McGuire Nuclear Station," April 2014.

[15] Generic Issue (GI) 199, "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants," U.S. NRC Information Notice (IN) 2010-18, (ADAMS Accession No. ML100270582), dated September 2, 2010.

[16] Souther Nuclear Operating Company, Inc. Letter to the NRC, Vogtle Electric Generating Plant - Units 1 and 2 License Amendment Request to Revise Technical Specifications to Implement NEI 06-09, Revision 0, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, (Enclosure E3), September 13, 2012 (ADAMS Accession No. ML12258A055).

[17] Exelon Generation Company, LLC Letter to NRC, License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 1, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b," February 25, 2016 (ADAMS Accession No. ML16060A223).

[18] Kennedy, R.P., "Overview of Methods for Seismic PRA and Margin Analysis Including Recent Innovations," Conference paper at Tokyo 1999 OECD/NEA Workshop on Seismic Risk, Proceedings of the OECD/NEA Workshop on Seismic Risk, NEA/CSNI/R(99)28, (ADAMS Accession No. ML042960158), August 1999.

[19] Investigation of Seismic Probabilistic Risk Assessment (SPRA) Quantification to Simplify PRA Models Used to Assess Risk-Informed Completion Times, EPRI Configuration Risk Management Forum Research Task. EPRI, Palo Alto, CA: 2021. 3002020744.

U.S. Nuclear Regulatory Commission Page 44 RA-23-0279

[20] Jung, S. (Duke Energy), "Improved Seismic Penalty Approach for RICT," Electric Power Research Institute Configuration Risk Management Forum (CRMF) Conference, Charlotte, NC, March 28, 2022.

[21] McGuire Nuclear Station, "Seismic Hazard Curve Sensitivity Study For the McGuire IPEEE," MCC-1535.00-00-0003, 1994.

[22] NRC letter to Exelon Generation Company, LLC, Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2 - Issuance of Amendments Nos. 206, 206, 212, and 212 RE: Adoption of TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4B' (EPID L-2018-LLA-0727)," (ADAMS Accession No. ML20037B221), dated March 30, 2020.

[23] NRC letter to McGuire Nuclear Station, Unit 1, "Staff Assessment of the Seismic Walkdown Report Supporting Implementation of Near-Term Task Force Recommendation 2.3 Related to the Fukushima Dai-Ichi Nuclear Power Plant Accident," (TAC NO. MF0140),

(ADAMS Accession No. ML14114A305), dated May 8, 2014.

[24] NRC Letter to McGuire Nuclear Station, Unit 2, "Staff Assessment of the Seismic Walkdown Report Supporting Implementation of Near-Term Task Force Recommendation 2.3 Related to the Fukushima Dai-Ichi Nuclear Power Plant Accident," (TAC NO. MF0141),

(ADAMS Accession No. ML14112A497), dated May 8, 2014.

[25] U.S. Nuclear Regulatory Commission, "Risk Assessment of Operational Events, Volume 2

- External Events - Internal Fires - Internal Flooding - Seismic - Other External Events -

Frequencies of Seismically-Induced LOOP Events (RASP Handbook)," Revision 1.02, (ADAMS Accession No. ML17349A301), dated November 2017.

[26] MCC-1535.00-00-0178, McGuire Nuclear Station High Wind Probabilistic Risk Assessment, Revision 4, November 2022.

[27] High Wind Loss of Offsite Power Durations and Recovery. EPRI, Palo Alto, CA: 2020.

3002018232.

[28] RP/0/A/5700/006, Natural Disasters, Revision 036.

[29] RP/0/B/5700/027, Severe Weather Preparation, Revision 013.

[30] Duke Energy Letter to NRC, "Flood Hazard Reevaluation Report, Response to NRC 10 CFR 50.54(f) Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3 and 9.3 of Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident," dated March 12, 2014 (ADAMS Accession No. ML14083A415).

[31] [Not used]

U.S. Nuclear Regulatory Commission Page 45 RA-23-0279

[32] Duke Energy Letter to NRC, "Response to March 12, 2012, Request for Information Enclosure 2, Recommendation 2.1, Flooding, Required Response 3, Flooding Focused Evaluation Summary Submittal" (ADAMS Accession No. ML17187A172), dated June 28, 2017.

[33] NRC Letter to Duke Energy, "McGuire Nuclear Station, Units 1 and 2 - Staff Assessment of Flooding Focused Evaluation (CAC Nos. MG0127 and MG0128; EPID L-2017-JLD-0017)" (ADAMS Accession No. ML18031A564), dated February 12, 2018.

[34] [Not used]

[35] Duke Power letter to NRC, McGuire Nuclear Station, Units 1 and 2, Individual Plant Examination of External Events (IPEEE) Submittal, dated June 1, 1994 (ADAMS Accession No. 9406140331).

[36] NUREG-0800, "Standard Review Plan (SRP) for the Review of Safety Analysis Reports for Nuclear Power Plants," Section 3.5.1.6, "Aircraft Hazards," Revision 4, March 2010.

[37] Calculation MCC-1535.00-00-0252, MNS 50.69 and TSTF-505 LAR Support Calculation, Revision 1

[38] McGuire Nuclear Station Updated Final Safety Analysis Report (UFSAR), April 2020.

[39] Calculation MCC-1211.00-00-0141, "McGuire Nuclear Station Control Room Habitability Toxic Gas Review," Rev. 4, July 2022.

[40] Regulatory Guide (RG) 1.78, "Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release," Revision 1, (ADAMS Accession No. ML013100014), December 2001.

[41] RG 1.115, "Protection Against Low Trajectory Turbine Missiles," U.S. Nuclear Regulatory Commission, Revision 1, July 1977 (ADAMS Accession No. ML003739456).

[42] RG 1.200, "Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 3, December 2020 (ADAMS Accession No. ML20238B871).

U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 ENCLOSURE 5 BASELINE CDF AND LERF

U.S. Nuclear Regulatory Commission Page 2 RA-23-0279 1.0 PURPOSE The purpose of this Enclosure is to document the baseline Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) for the hazards used for the McGuire TSTF-505 license amendment request (LAR) and the RICT Program. The baseline plant risk is an integral part of the calculation of risk-informed completion times (RICTs).

2.0 REFERENCES

1. NRC Letter from Jennifer M. Golder to Biff Bradley (NEI), Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06-09, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, May 17, 2007 (ADAMS Accession No. ML071200238).

2. Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS)

Guidelines, Revision 0, October 12, 2012 (ADAMS Accession No. ML12286A322).

3. Regulatory Guide 1.174, An Approach For Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 1, November 2002.

4. Regulatory Guide 1.174, An Approach For Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 2, May 2011.

5. Regulatory Guide 1.174, An Approach For Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 3, January 2018.

6. NUREG-2169, Nuclear Power Plant Fire Ignition Frequency and Non-Suppression Probability Estimation Using the Updated Fire Events Database, January 2015.

3.0 INTRODUCTION

Section 4.0, Item 6 of the NRC Final Safety Evaluation (Reference 1) for NEI 06-09-A (Reference 2) requires that the LAR provide the plant-specific total CDF and total LERF to confirm that these are less than 10-4/year and 10-5/year, respectively. This assures that the potential risk increases allowed under the RICT Program are consistent with the limits set forth in RG 1.174, Revision 1 (Reference 3). Note that RG 1.174, Revision 2 (Reference 4) and RG 1.174, Revision 3 (Reference 5), did not revise these limits.

4.0 BASELINE RISK Baseline risk, as well as the model files used to reproduce baseline risk, are documented in each hazards quantification calculation. Baseline risk, in these calculations, are documented as nominal maintenance. For the quantitative purposes of this LAR, these nominal-maintenance results are utilized as a bounding representation of CDF and LERF. Note that for RICT Program implementation, the models used will be no-maintenance models.

The baseline results from the McGuire PRA models are provided in Table E5-1a and Table E5-1b below. Values for high winds are reported from the PRA quantification calculation. The PRA is considered a better estimate of contribution to overall site risk than the proposed high winds penalty factor. Baseline seismic risk is estimated using the convolution method described in the Response to the NRC audit APLC Question 1 [Seismic Risk Contribution Analysis (For TSTF-

U.S. Nuclear Regulatory Commission Page 3 RA-23-0279 505 LAR)]. The response contains the seismic analysis as well as the derived seismic baseline values for CDF and LERF.

TableE51a-TotalBaselineUnit1CDF&LERF

Baseline CDF Baseline LERF Source Contribution Source Contribution Internal Internal Events 3.14E-06 Events 3.96E-07 PRA PRA Internal Internal Flooding 4.86E-06 Flooding 5.89E-07 PRA PRA Fire PRA 3.37E-05 Fire PRA 5.12E-06 HW 3.02E-06 HW 1.12E-07 Seismic 3.36E-05 Seismic 2.16E-06 Other Other No significant No significant External External contribution contribution Events Events Total Total 7.83E-05 8.38E-06 CDF LERF

    

TableE51b-TotalBaselineUnit2CDF&LERF

Baseline CDF Baseline LERF Source Contribution Source Contribution Internal Internal Events 3.16E-06 Events 4.20E-07 PRA PRA Internal Internal Flooding 6.38E-06 Flooding 6.17E-07 PRA PRA Fire PRA 4.06E-05 Fire PRA 5.01E-06 HW 3.13E-06 HW 1.08E-07 Seismic 3.36E-05 Seismic 2.16E-06 Other Other No significant No significant External External contribution contribution Events Events Total Total 8.69E-05 8.32E-06 CDF LERF



Note1:TheHWportionisfromthehighwindsPRA.

Note2:TheseismiccontributionisdevelopedbyconvolvingtheseismichazardwithrepresentativefragilitiesforCDFand

LERF.

U.S. Nuclear Regulatory Commission Page 4 RA-23-0279 As demonstrated, CDF is less than the limit of 1E-04 imposed by RG 1.174 (Reference 2.3, 2.4 and 2.5). LERF is also lower than the imposed limit of 1E-05. Thus, the PRAs are acceptable for use in risk-informed applications.

The total risk for Unit 1 is 8.01E-05 for CDF and 8.35E-06 for LERF and the total risk for Unit 2 is 8.88E-5 for CDF and 8.31E-6 for LERF after the internal events, internal flooding, high winds, and fire PRA models have been updated to include the potential impacts in risk associated with state-of-knowledge-correlation (SOKC) as well as the addition of an estimation for risk based on convolving the seismic hazard with representative fragilities for CDF and LERF.

An assessment of parametric uncertainty was performed for Internal Events, Internal Flooding, High Winds, and Fire CDF and LERF using UNCERT with a Monte-Carlo sampling approach with 30,000, 10,000, 50,000, 100,000 samples respectively. The parametric uncertainty analysis addresses SOKC for basic events sharing the same type code and that appear in the same cutset. The impact of the SOKC is reflected by an increase in the calculated risk from the simulation, if applicable. Given that the UNCERT program results do not indicate significant increase in risk over the point estimate risk, it is concluded that there are no significant data correlations from type-coded data events. However, the potential for non-type coded data events specific to the fire analysis needed to be examined as shown below:

Area of Uncertainty Discussion

1. Ignition frequency NUREG-2169 (Reference 2.6) provides the distribution and parameter error factors based on ignition frequency binning.

This parametric uncertainty is applied to each of the ignition source frequencies used in the analysis. The updated Bin 04 and Bin 15 frequencies were not provided with calculated parameter error factors. These were calculated for the lognormal distribution using the provided 95th and 50th percentiles.

2. Non-suppression Since NSP is a combination of automatic and manual probabilities suppression activities it was judged that following the same error factors as the HRA would be appropriate.

3. Severity Factors Generic uncertainty parameters are applied to the severity factor values. The error factors selected were done using engineering judgement. The values follow the HRA error factor assignment, with some additional steps to capture different ranges.

x SF Value < 0.001 o Error Factor = 10 x SF Value 0.001 and < 0.1 o Error Factor = 3 x SF Value 0.1 and < 0.25 o Error Factor = 2 x SF Value 0.25 o Error Factor = 1

U.S. Nuclear Regulatory Commission RA-23-0279 Attachment 3 ATTACHMENT 3 REVISED ENCLOSURE AND ATTACHMENTS FOR LICENSE AMENDMENT REQUEST TO ADOPT 10 CFR 50.69

[67 PAGES FOLLOW THIS COVER PAGE]

U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 Enclosure Description and Assessment of the Proposed Change

Subject:

Application to Adopt 10 CFR 50.69, Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors

1.

SUMMARY

DESCRIPTION

2. DETAILED DESCRIPTION 2.1 Current Regulatory Requirements 2.2 Reason for the Proposed Change 2.3 Description of the Proposed Change

3. TECHNICAL EVALUATION 3.1 Categorization Process Description (10 CFR 50.69(b)(2)(i))

3.1.1 Overall Categorization Process 3.1.2 Passive Categorization Process 3.2 Technical Adequacy Evaluation (10 CFR 50.69(b)(2)(ii))

3.2.1 Internal Events and Internal Flooding 3.2.2 Fire Hazards 3.2.3 Seismic Hazards 3.2.4 Other External Hazards 3.2.5 Low Power & Shutdown 3.2.6 PRA Maintenance and Updates 3.2.7 PRA Uncertainty Evaluations 3.3 PRA Review Process Results (10 CFR 50.69(b)(2)(iii))

3.4 Risk Evaluations (10 CFR 50.69(b)(2)(iv))

3.5 Feedback and Adjustment Process

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

5. ENVIRONMENTAL CONSIDERATION

6. REFERENCES ATTACHMENTS:

1. List of Categorization Prerequisites

2. Description of PRA Models Used in Categorization

3. Disposition and Resolution of Open Peer Review Findings and Self-Assessment Open Items

4. External Hazards Screening

5. Progressive Screening Approach for Addressing External Hazards

6. Disposition of Key Assumptions/Sources of Uncertainty

7. Markup of McGuire, Units 1 and 2 Renewed Facility Operating Licenses

U.S. Nuclear Regulatory Commission Page 2 RA-23-0279

1.

SUMMARY

DESCRIPTION The proposed amendment modifies the licensing basis to allow for the implementation of the provisions of Title 10 of the Code of Federal Regulations (10 CFR), Part 50.69, Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors. The provisions of 10 CFR 50.69 allow adjustment of the scope of equipment subject to special treatment controls (e.g., quality assurance, testing, inspection, condition monitoring, assessment, and evaluation). For equipment determined to be of low safety significance, alternative treatment requirements can be implemented in accordance with this regulation. For equipment determined to be of high safety significance, requirements will not be changed or will be enhanced. This allows improved focus on equipment that has safety significance resulting in improved plant safety.

2. DETAILED DESCRIPTION 2.1 Current Regulatory Requirements The Nuclear Regulatory Commission (NRC) has established a set of regulatory requirements for commercial nuclear reactors to ensure that a reactor facility does not impose an undue risk to the health and safety of the public, thereby providing reasonable assurance of adequate protection to public health and safety. The current body of NRC regulations and their implementation are largely based on a "deterministic" approach.

This deterministic approach establishes requirements for engineering margin and quality assurance in design, manufacture, and construction. In addition, it assumes that adverse conditions can exist (e.g., equipment failures and human errors) and establishes a specific set of design basis events (DBEs). The deterministic approach then requires that the facility include safety systems capable of preventing or mitigating the consequences of those DBEs to protect public health and safety. The Structures, Systems and Components (SSCs) necessary to defend against the DBEs are defined as "safety-related," and these SSCs are the subject of many regulatory requirements, herein referred to as special treatments, designed to ensure that they are of high quality and high reliability, and have the capability to perform during postulated design basis conditions. Treatment includes, but is not limited to, quality assurance, testing, inspection, condition monitoring, assessment, evaluation, and resolution of deviations.

The distinction between "treatment" and "special treatment" is the degree of NRC specification as to what must be implemented for particular SSCs or for particular conditions. Typically, the regulations establish the scope of SSCs that receive special treatment using one of three different terms: "safety-related," "important to safety," or "basic component." The terms "safety-related "and "basic component" are defined in the regulations, while "important to safety," used principally in the general design criteria (GDC) of Appendix A to 10 CFR Part 50, is not explicitly defined.

2.2 Reason for the Proposed Change A probabilistic approach to regulation enhances and extends the traditional deterministic approach by allowing consideration of a broader set of potential challenges to safety, providing a logical means for prioritizing these challenges based on safety significance, and allowing consideration of a broader set of resources to defend against these challenges. In contrast to the deterministic approach, Probabilistic Risk Assessments (PRAs) address credible initiating events by assessing the event frequency. Mitigating system reliability is then assessed, including the potential for common cause failures. The probabilistic approach to regulation is

U.S. Nuclear Regulatory Commission Page 3 RA-23-0279 an extension and enhancement of traditional regulation by considering risk in a comprehensive manner.

To take advantage of the safety enhancements available through the use of PRA, in 2004 the NRC published a new regulation, 10 CFR 50.69. The provisions of 10 CFR 50.69 allow adjustment of the scope of equipment subject to special treatment controls (e.g., quality assurance, testing, inspection, condition monitoring, assessment, and evaluation). For equipment determined to be of low safety significance, alternative treatment requirements can be implemented in accordance with the regulation. For equipment determined to be of high safety significance, requirements will not be changed or will be enhanced. This allows improved focus on equipment that has safety significance resulting in improved plant safety.

The rule contains requirements on how a licensee categorizes SSCs using a risk-informed process, adjusts treatment requirements consistent with the relative significance of the SSC, and manages the process over the lifetime of the plant. A risk-informed categorization process is employed to determine the safety significance of SSCs and place the SSCs into one of four risk-informed safety class (RISC) categories. The determination of safety significance is performed by an integrated decision-making process, as described by Nuclear Energy Institute (NEI) 00-04, 10 CFR 50.69 SSC Categorization Guideline (Reference 1), which uses both risk insights and traditional engineering insights. The safety functions include the design basis functions, as well as functions credited for severe accidents (including external events).

Special or alternative treatment for the SSCs is applied as necessary to maintain functionality and reliability, and is a function of the SSC categorization results and associated bases.

Finally, periodic assessment activities are conducted to make adjustments to the categorization and/or treatment processes as needed so that SSCs continue to meet all applicable requirements.

The rule does not allow for the elimination of SSC functional requirements or allow equipment that is required by the deterministic design basis to be removed from the facility. Instead, the rule enables licensees to focus their resources on SSCs that make a significant contribution to plant safety. For SSCs that are categorized as high safety significant, existing treatment requirements are maintained or enhanced. Conversely, for SSCs that do not significantly contribute to plant safety on an individual basis, the rule allows an alternative risk-informed approach to treatment that provides reasonable, though reduced, level of confidence that these SSCs will satisfy functional requirements.

Implementation of 10 CFR 50.69 will allow Duke Energy Carolinas, LLC (Duke Energy) to improve focus on equipment that has safety significance resulting in improved plant safety.

2.3 Description of the Proposed Change Duke Energy proposes the addition of the following condition to the renewed facility operating licenses (FOL) of MNS Units 1 and 2 to document the NRC's approval of the use of 10 CFR 50.69.

Duke Energy is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC3, and RISC-4 structures, systems, and components (SSCs) using: Probabilistic Risk Assessment (PRA) models to evaluate risk associated with internal events, including internal flooding, internal fire, and high winds; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess

U.S. Nuclear Regulatory Commission Page 4 RA-23-0279 passive component risk for Class 2, Class 3, and non-class SSCs and their associated supports; the results of non-PRA evaluations that are based on the IPEEE Screening Assessment for External Hazards updated using the external hazard screening significance process identified in the ASME/ANS PRA Standard RA-Sa-2009 for other external hazards except seismic, and the alternative seismic approach described in Duke Energys submittal letter RA-18-0090 dated February 17, 2023; as specified in License Amendment No. [XXX] dated [DATE].

Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from a seismic margins approach to a seismic probabilistic risk assessment approach).

A markup of the MNS, Units 1 and 2 FOLs to reflect the proposed change is provided in of Duke Energy letter RA-23-0279.

3. TECHNICAL EVALUATION 10 CFR 50.69 specifies the information to be provided by a licensee requesting adoption of the regulation. This request conforms to the requirements of 10 CFR 50.69(b)(2), which states:

A licensee voluntarily choosing to implement this section shall submit an application for license amendment under § 50.90 that contains the following information:

(i) A description of the process for categorization of RISC-1, RISC-2, RISC-3 and RISC-4 SSCs.

(ii) A description of the measures taken to assure that the quality and level of detail of the systematic processes that evaluate the plant for internal and external events during normal operation, low power, and shutdown (including the plant-specific probabilistic risk assessment (PRA), margins-type approaches, or other systematic evaluation techniques used to evaluate severe accident vulnerabilities) are adequate for the categorization of SSCs.

(iii) Results of the PRA review process conducted to meet § 50.69(c)(1)(i).

(iv) A description of, and basis for acceptability of, the evaluations to be conducted to satisfy § 50.69(c)(1)(iv). The evaluations must include the effects of common cause interaction susceptibility, and the potential impacts from known degradation mechanisms for both active and passive functions, and address internally and externally initiated events and plant operating modes (e.g., full power and shutdown conditions).

Each of these submittal requirements are addressed in the following sections.

The PRA models described within this license amendment request (LAR) are the same as those described within the Duke Energy submittal of the MNS LAR dated February 16, 2023 for the adoption of Technical Specifications Task Force (TSTF) Traveler 505 (Serial: RA-18-0190).

Duke Energy requests that the NRC conduct their review of the PRA technical adequacy details for this application in coordination with the review of the application currently in-process.

This would reduce the number of Duke Energy and NRC resources necessary to complete the review of the applications. This request should not be considered a linked requested licensing action (RLA), as the details of the PRA models in each LAR are complete which will allow the

U.S. Nuclear Regulatory Commission Page 5 RA-23-0279 NRC staff to independently review and approve each LAR on their own merits without regard to the results from the review of the other.

3.1 Categorization Process Description (10 CFR 50.69(b)(2)(i))

3.1.1 Overall Categorization Process Duke Energy will implement the risk categorization process in accordance with NEI 00-04, Revision 0, as endorsed by Regulatory Guide (RG) 1.201, Guidelines for Categorizing Structures, Systems, and Components in Nuclear Power Plants According to their Safety Significance (Reference 2). NEI 00-04 Section 1.5 states Due to the varying levels of uncertainty and degrees of conservatism in the spectrum of risk contributors, the risk significance of SSCs is assessed separately from each of five risk perspectives and used to identify SSCs that are potentially safety-significant. A separate evaluation is appropriate to avoid reliance on a combined result that may mask the results of individual risk contributors.

The process to categorize each system will be consistent with the guidance in NEI 00-04, 10 CFR 50.69 SSC Categorization Guideline, as endorsed by RG 1.201, with the exception of:

x The evaluation of impact of the seismic hazard, which will use the Electric Power Research Institute (EPRI) 3002017583 (Reference 17) approach for seismic Tier 2 sites, which includes MNS, to assess seismic hazard risk for 10 CFR 50.69.

RG 1.201 states that the implementation of all processes described in NEI 00-04 (i.e.,

Sections 2 through 12) is integral to providing reasonable confidence and that all aspects of NEI 00-04 must be followed to achieve reasonable confidence in the evaluations required by

§50.69(c)(1)(iv). However, neither RG 1.201 nor NEI 00-04 prescribe a particular sequence or order for each of the elements to be completed. Therefore, the order in which each of the elements of the categorization process (listed below) is completed is flexible and as long as they are all completed, they may even be performed in parallel. Note that NEI 00-04 only requires Item 3 to be completed for components/functions categorized as Low Safety Significant (LSS) by all other elements. Similarly, NEI 00-04 only requires Item 4 to be completed for safety-related active components/functions categorized as LSS by all other elements. Inclusion of additional process steps discussed below to address seismic considerations will ensure that reasonable confidence in the evaluations required by 10 CFR 50.69(c)(1)(iv) is achieved.

1. PRA-based evaluations (e.g., the internal events, internal flooding, fire, and high winds PRAs)

2. Non-PRA approaches (e.g., other external events screening, and shutdown assessment)

3. Seven qualitative criteria in Section 9.2 of NEI 00-04

4. The defense-in-depth assessment

5. The passive categorization methodology Categorization of SSCs will be completed per the NEI 00-04 process, as endorsed by RG 1.201, which includes the determination of safety significance through the various elements identified above. The results of these elements are used as inputs to arrive at a preliminary component categorization (i.e., High Safety Significant (HSS) or LSS) that is presented to the Integrated Decision-Making Panel (IDP). Note: the term preliminary HSS or LSS is synonymous with the NEI 00-04 term candidate HSS or LSS. A component or function is

U.S. Nuclear Regulatory Commission Page 6 RA-23-0279 preliminarily categorized as HSS if any element of the process results in a preliminary HSS determination in accordance with Table 3-1 below. The safety significance determination of each element, identified above, is independent of each other and therefore the sequence of the elements does not impact the resulting preliminary categorization of each component or function. Consistent with NEI 00-04, the categorization of a component or function will only be preliminary until it has been confirmed by the IDP. Once the IDP confirms that the categorization process was followed appropriately, the final RISC category can be assigned.

The IDP may direct and approve detailed categorization of components in accordance with NEI 00-04 Section 10.2. The IDP may always elect to change a preliminary LSS component or function to HSS, however the ability to change component categorization from preliminary HSS to LSS is limited. This ability is only available to the IDP for select process steps as described in NEI 00-04 and endorsed by RG 1.201. Table 3-1 summarizes these IDP limitations in NEI 00-04. The steps of the process are performed at either the function level, component level, or both. This is also summarized in the Table 3-1. A component is assigned its final RISC category upon approval by the IDP.

Table 3-1: Categorization Evaluation Summary Drives Categorization Step IDP Change Element Evaluation Level Associated

- NEI 00-04 Section HSS to LSS Functions Internal Events Base Case - Not Allowed Yes Section 5.1 Fire, Seismic and Other External Events (including Allowable No Risk (PRA High Winds) Base Component Modeled)

Case PRA Sensitivity Allowable No Studies Integral PRA Assessment - Not Allowed Yes Section 5.6 Other External Component Not Allowed No Hazards Risk (Non- Seismic -

modeled) Alternative Tier 2 Function/Component Allowed1 No Approach Shutdown -

Function/Component Not Allowed No Section 5.5 Core Damage -

Function/Component Not Allowed Yes Defense-in- Section 6.1 Depth Containment -

Component Not Allowed Yes Section 6.2 Qualitative Considerations -

Function Allowable2 N/A Criteria Section 9.2 Passive Passive - Section 4 Segment/Component Not Allowed No

U.S. Nuclear Regulatory Commission Page 7 RA-23-0279 Notes:

1 IDP consideration of seismic insights can also result in an LSS to HSS determination 2

The assessments of the qualitative considerations are agreed upon by the IDP in accordance with Section 9.2. In some cases, a 10 CFR 50.69 categorization team may provide preliminary assessments of the seven considerations for the IDPs consideration, however the final assessments of the seven considerations are the direct responsibility of the IDP.

The seven considerations are addressed preliminarily by the 10 CFR 50.69 categorization team for at least the system functions that are not found to be HSS due to any other categorization step. Each of the seven considerations requires a supporting justification for confirming (true response) or not confirming (false response) that consideration. If the 10 CFR 50.69 categorization team determines that one or more of the seven considerations cannot be confirmed, then that function is presented to the IDP as preliminary HSS. Conversely, if all the seven considerations are confirmed, then the function is presented to the IDP as preliminary LSS.

The System Categorization Document, including the justifications provided for the qualitative considerations, is reviewed by the IDP. The IDP is responsible for reviewing the preliminary assessment to the same level of detail as the 10 CFR 50.69 team (i.e. all considerations for all functions are reviewed). The IDP may confirm the preliminary function risk and associated justification or may direct that it be changed based upon their expert knowledge. Because the Qualitative Criteria are the direct responsibility of the IDP, changes may be made from preliminary HSS to LSS or from preliminary LSS to HSS at the discretion of the IDP. If the IDP determines any of the seven considerations cannot be confirmed (false response) for a function, then the final categorization of that function is HSS.

The mapping of components to system functions is used in some categorization process steps to facilitate preliminary categorization of components. Specifically, functions with mapped components that are determined to be HSS by the PRA-based assessment (i.e., Internal events PRA or Integral PRA assessment) or defense-in-depth evaluation will be initially treated as HSS. However, NEI 00-04 Section 10.2 allows detailed categorization which can result in some components mapped to HSS functions being treated as LSS; and Section 4.0 discusses additional functions that may be identified (e.g., fill and drain) to group and consider potentially LSS components that may have been initially associated with a HSS function but which do not support the critical attributes of that HSS function. Note that certain steps of the categorization process are performed at a component level (e.g. Passive, Non-PRA-modeled hazards - see Table 3-1). Except for seismic, these components from the component level assessments will remain HSS (IDP cannot override) regardless of the significance of the functions to which they are mapped. Components having seismic functions may be HSS or LSS based on the IDPs consideration of the seismic insights applicable to the system being categorized. Therefore, if a HSS component is mapped to an LSS function, that component will remain HSS. If an LSS component is mapped to an HSS function, that component may be driven HSS based on Table 3-1 above or may remain LSS. For the seismic hazard, given that MNS is a seismic Tier 2 (moderate seismic hazard) plant as defined in Reference 17, seismic considerations are not required to drive an HSS determination at the component level, but the IDP will consider available seismic information pertinent to the components being categorized and can, at its discretion, determine that a component should be HSS based on that information.

The following are clarifications to be applied to the NEI 00-04 categorization process:

x The IDP will be composed of a group of at least five experts who collectively have expertise in plant operation, design (mechanical and electrical) engineering, system engineering, safety analysis, and PRA. At least three members of the IDP will have a minimum of five years of experience at the plant, and there will be at least one member of the IDP who has a

U.S. Nuclear Regulatory Commission Page 8 RA-23-0279 minimum of three years of experience in the modeling and updating of the plant-specific PRA.

x The IDP will be trained in the specific technical aspects and requirements related to the categorization process. Training will address at a minimum the purpose of the categorization; present treatment requirements for SSCs including requirements for design basis events; PRA fundamentals; details of the plant specific PRA including the modeling, scope, and assumptions, the interpretation of risk importance measures, and the role of sensitivity studies and the change-in-risk evaluations; and the defense-in-depth philosophy and requirements to maintain this philosophy.

x The decision criteria for the IDP for categorizing SSCs as safety significant or low safety-significant pursuant to § 50.69(f)(1) will be documented in Duke Energy procedures.

x Decisions of the IDP will be arrived at by consensus.

x Differing opinions will be documented and resolved, if possible. However, a simple majority of the panel is sufficient for final decisions regarding HSS and LSS.

x Passive characterization will be performed using the process described in Section 3.1.2.

Consistent with NEI 00-04, an HSS determination by the passive categorization process cannot be changed by the IDP.

x An unreliability factor of 3 will be used for the sensitivity studies described in Section 8 of NEI 00-04. The factor of 3 was chosen as it is representative of the typical error factor of basic events used in the PRA model.

x NEI 00-04 Section 7 requires assigning the safety significance of functions to be preliminary HSS if it is supported by an SSC determined to be HSS from the PRA-based assessment in Section 5 but does not require this for SSCs determined to be HSS from non-PRA-based, deterministic assessments in Section 5. This requirement is further clarified in the Vogtle Safety Evaluation (SE) (Reference 4) which states if any SSC is identified as HSS from either the integrated PRA component safety significance assessment (Section 5 of NEI 00-

04) or the defense-in-depth assessment (Section 6), the associated system function(s) would be identified as HSS.

x Once a system function is identified as HSS, then all the components that support that function are preliminary HSS. The IDP must intervene to assign any of these HSS Function components to LSS.

x With regard to the criteria that considers whether the active function is called out or relied upon in the plant Emergency/Abnormal Operating Procedures, Duke Energy will not take credit for alternate means unless the alternate means are proceduralized and included in Licensed Operator training.

x Duke Energy proposes to apply an alternative seismic approach to those listed in NEI 00-04 Sections 1.5 and 5.3, as discussed in Section 3.2.3 of this LAR.

The risk analysis to be implemented for each hazard is described below:

U.S. Nuclear Regulatory Commission Page 9 RA-23-0279 x Internal Event Risks: Internal events including internal flooding PRA, as submitted to the NRC for the adoption of TSTF-505 by letter dated February 16, 2023 (Refer to the corresponding Enclosure 2).

x Fire Risks: Fire PRA model, as submitted to the NRC for the adoption of TSTF-505 by letter dated February 16, 2023 (Refer to the corresponding Enclosure 2).

x Seismic Risks: EPRI Alternative Approach in EPRI 3002022453 (Reference 17) for Tier 2 plants and additional considerations discussed in Section 3.2.3 of this LAR.

x High Winds Risks: High Winds PRA model, as submitted to the NRC for the adoption of TSTF-505 by letter dated February 16, 2023 (Refer to the corresponding Enclosure 2).

x Other External Risks (e.g., tornados, external floods):

x Using the IPEEE screening process as approved by NRC SE dated February 16, 1999 (Reference 16). The other external hazards were determined to be insignificant contributors to plant risk.

x Low Power and Shutdown Risks: Qualitative defense-in-depth (DID) shutdown model for shutdown configuration risk management (CRM) based on the framework for DID provided in NUMARC 91-06, Guidance for Industry Actions to Assess Shutdown Management (Reference 3), which provides guidance for assessing and enhancing safety during shutdown operations.

A change to the categorization process that is outside the bounds specified above (e.g.,

change from a seismic margins approach to a seismic PRA approach) will not be used without prior NRC approval. The SSC categorization process documentation will include the following elements:

1. Program procedures used in the categorization

2. System functions, identified and categorized with the associated bases

3. Mapping of components to support function(s)

4. PRA model results, including sensitivity studies

5. Hazards analyses, as applicable

6. Passive categorization results and bases

7. Categorization results including all associated bases and RISC classifications

8. Component critical attributes for HSS SSCs

9. Results of periodic reviews and SSC performance evaluations

10. IDP meeting minutes and qualification/training records for the IDP members 3.1.2 Passive Categorization Process For the purposes of 10 CFR 50.69 categorization, passive components are those components that have a pressure retaining function. Passive components and the passive function of active components will be evaluated using the Arkansas Nuclear One (ANO) Risk-Informed Repair/Replacement Activities (RI-RRA) methodology contained in Reference 5 consistent with the related SE issued by the Office of Nuclear Reactor Regulation.

The RI-RRA methodology is a risk-informed safety classification and treatment program for repair/replacement activities (RI-RRA methodology) for pressure retaining items and their

U.S. Nuclear Regulatory Commission Page 10 RA-23-0279 associated supports. In this method, the component failure is assumed with a probability of 1.0 and only the consequence evaluation is performed. It additionally applies deterministic considerations (e.g., DID, safety margins) in determining safety significance. Component supports, if categorized, are assigned the same safety significance as the highest passively ranked component within the bounds of the associated analytical pipe stress model. Consistent with NEI 00-04, an HSS determination by the passive categorization process cannot be changed by the IDP.

The use of this method was previously approved to be used for a 10 CFR 50.69 application by NRC in the final SE for Vogtle dated December 17, 2014 (Reference 4). The RI-RRA method as approved for use at Vogtle for 10 CFR 50.69 does not have any plant specific aspects and is generic. It relies on the conditional core damage and large early release probabilities associated with postulated ruptures. Safety significance is generally measured by the frequency and the consequence of the event. However, this RI-RRA process categorizes components solely based on consequence, which measures the safety significance of the passive component given that it ruptures. This approach is conservative compared to including the rupture frequency in the categorization as this approach will not allow the categorization of SSCs to be affected by any changes in frequency due to changes in treatment. The passive categorization process can apply the same risk-informed process accepted by the NRC in Reference 5 for the passive categorization of Class 2, 3, and non-class components. This is the same passive SSC scope the NRC has conditionally endorsed in ASME Code Cases N-660 and N-662 as published in Regulatory Guide 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1, Revision 15. Both code cases employ a similar risk-informed safety classification of SSCs in order to change the repair/replacement requirements of the affected LSS components. All ASME Code Class 1 SSCs with a pressure retaining function, as well as supports, will be assigned HSS for passive categorization which will result in HSS for its risk-informed safety classification and cannot be changed by the IDP. Therefore, this methodology and scope for passive categorization is acceptable and appropriate for use at MNS for 10 CFR 50.69 SSC categorization.

3.2 Technical Adequacy Evaluation (10 CFR 50.69(b)(2)(ii))

The following sections demonstrate that the quality and level of detail of the processes used in categorization of SSCs are adequate. The PRA models described below have been peer reviewed and there are no PRA upgrades that have not been peer reviewed. The PRA models credited in this request are the same PRA models credited in the MNS application to adopt TSTF-505 dated February 16, 2023.

3.2.1 Internal Events and Internal Flooding The MNS categorization process for the internal events and flooding hazard will use the plant-specific PRA model. The Duke Energy risk management process ensures that the PRA model used in this application reflects the as-built and as-operated plant for each of the MNS units. of this enclosure identifies the applicable internal events and internal flooding PRA models.

3.2.2 Fire Hazards The MNS categorization process for fire hazards will use a peer reviewed plant-specific fire PRA model. The internal Fire PRA model was developed consistent with NUREG/CR-6850 and only utilizes methods previously accepted by the NRC. The Duke Energy risk

U.S. Nuclear Regulatory Commission Page 11 RA-23-0279 management process ensures that the PRA model used in this application reflects the as-built and as-operated plant for each of the MNS units. Attachment 2 of this enclosure identifies the applicable Fire PRA model.

3.2.3 Seismic Hazards 10 CFR 50.69(c)(1) requires the use of PRA to assess risk from internal events. For other risk hazards, such as seismic, 10 CFR 50.69(b)(2) allows, and NEI 00-04 (Reference 6) summarizes, the use of other methods for determining SSC functional importance in the absence of a quantifiable PRA (such as Seismic Margin Analysis or IPEEE Screening) as part of an integrated, systematic process. For the MNS seismic hazard assessment, Duke Energy proposes to use a risk-informed graded approach that meets the requirements of 10 CFR 50.69(b)(2) as an alternative to those listed in NEI 00-04 sections 1.5 and 5.3. This approach is specified in Reference 17 with the EPRI markups provided in Attachment 2 of References 18 and 19 and includes additional considerations that are discussed in this section.

Note: The discussion below pertaining to Reference 17 includes the markups provided in Attachment 2 of References 18 and 19.

EPRI 3002017583 (Reference 17) is an update to EPRI 3002012988, "Alternative Approaches for Addressing Seismic Risk in 10 CFR 50.69 Risk-Informed Categorization," July 2018 (Reference 57) which was referenced in the NRC-issued amendment and SE for Calvert Cliffs Nuclear Power Plant, Units 1 and 2, to implement 10 CFR 50.69 as noted below:

(1) Calvert Cliffs Nuclear Power Plant, Units 1 and 2, "Issuance of Amendment Nos.

332 and 310 Re: Risk-Informed Categorization and Treatment of Structures, Systems, and Components for Nuclear Power Reactors (EPID L-2018-LLA-0482)," February 28, 2020 (Reference 58).

(2) This license amendment incorporated by reference the Clinton Power Station, Unit 1 response to request for additional information DRA/APLC RAI 03 - Alternate Seismic Approach included in the letter dated November 24, 2020 (Reference 59), in particular, the response to the question regarding the differences between the initial EPRI report 3002012988 and the current EPRI report 3002017583.

The proposed categorization approach for MNS is a risk-informed graded approach that is demonstrated to produce categorization insights equivalent to a seismic PRA. This approach relies on the insights gained from the seismic PRAs examined in Reference 17 and plant specific insights considering seismic correlation effects and seismic interactions. Following the criteria in Reference 17, the MNS site is considered a Tier 2 site because the site Ground Motion Response Spectrum (GMRS) to Safe Shutdown Earthquake (SSE) comparison is above the Tier 1 threshold but not high enough that the NRC required the plant to perform a seismic PRA (SPRA) to respond to Recommendation 2.1 of the Near Term Task Force 50.54(f) letter (Reference 20). Reference 17 also demonstrates that seismic risk is adequately addressed for Tier 2 sites by the results of additional qualitative assessments discussed in this section and existing elements of the 10 CFR 50.69 categorization process specified in NEI 00-04.

The trial studies in Reference 17, as amended by their request for additional information (RAI) responses and amendments (References 21, 22, 23, 24, 25, 26, 27, 28, and 29) show that

U.S. Nuclear Regulatory Commission Page 12 RA-23-0279 seismic categorization insights are overlaid by other risk insights even at plants where the GMRS is far beyond the seismic design basis. Therefore, the basis for the Tier 2 classification and resulting criteria is that consideration of the full range of the seismic hazard produces limited unique insights to the categorization process. That is the basis for the following statements in Table 4-1 of Reference 17.

"At Tier 2 sites, there may be a limited number of unique seismic insights, most likely attributed to the possibility of seismically correlated failures, appropriate for consideration in determining HSS SSCs. The special seismic risk evaluation process recommended using a Common Cause impact approach in the FPIE [full power internal events] PRA can identify the appropriate seismic insights to be considered with the other categorization insights by the Integrated Decision-making Panel for the final HSS determinations."

At sites with moderate seismic demands (i.e., Tier 2 range) such as MNS, there is no need to perform more detailed evaluations to demonstrate the inherent seismic capacities documented in industry sources such as Reference 30. Tier 2 seismic demand sites have a lower likelihood of seismically induced failures and less challenges to plant systems than trial study plants.

This, therefore, provides the technical basis for allowing use of a graded approach for addressing seismic hazards at MNS.

Test cases described in Section 3 of Reference 17, as amended by their RAI responses and amendments (References 21, 22, 23, 24, 25, 26, 27, 28, and 29) showed that there are very few, if any, SSCs that would be designated HSS for seismic unique reasons. The test cases identified that the unique seismic insights were typically associated with seismically correlated failures and led to unique HSS SSCs. While it would be unusual even for moderate hazard plants to exhibit any unique seismic insights, it is prudent and recommended by Reference 17 to perform additional evaluations to identify the conditions where correlated failures and seismic interactions may occur and determine their impact in the 10 CFR 50.69 categorization process. The special sensitivity study recommended in Reference 17 uses common cause failures, similar to the approach taken in a FPIE PRA and can identify the appropriate seismic insights to be considered with the other categorization insights by the IDP for the final HSS determinations.

Duke Energy is using test case information from Reference 17, developed by other licensees.

The test case information is being incorporated by reference into this application, specifically Case Study A (Reference 31), Case Study C (Reference 32), and Case Study D (Reference 33), as well as RAI responses and amendments (References 21, 22, 23, 24, 25, 26, 27, 28, and 29) that clarify aspects of these case studies.

Basis for MNS being a Tier 2 Plant As defined in Reference 17, MNS meets the Tier 2 criteria for a "Moderate Seismic Hazard /

Moderate Seismic Margin" site. The Tier 2 criteria are as follows:

"Tier 2: Plants where the GMRS to SSE comparison between 1.0 Hz and 10 Hz is greater than in Tier 1 but not high enough to be treated as Tier 3. At these sites, the unique seismic categorization insights are expected to be limited."

Note: Reference 17 applies to the Tier 2 sites in its entirety except for Sections 2.2 (Tier 1 sites) and 2.4 (Tier 3 sites).

U.S. Nuclear Regulatory Commission Page 13 RA-23-0279 For comparison, Tier 1 plants are defined as having a GMRS peak acceleration at or below approximately 0.2g or where the GMRS is below or approximately equal to the SSE between 1.0 Hz and 10 Hz. Tier 3 plants are defined where the GMRS to SSE comparison between 1.0 Hz and 10 Hz is high enough that the NRC required the plant to perform an SPRA to respond to the Fukushima 10 CFR 50.54(f) letter (Reference 20).

The NRC did not require MNS to perform an SPRA as stated in its revised seismic screening and prioritization letter dated December 22, 2016 (Reference 37):

"the NRC has determined that seismic probabilistic risk assessments (SPRAs) for Catawba and McGuire are no longer necessary to fulfill the March 12, 2012, request for information pursuant to Title 10 of the Code of Federal Regulations, Part 50, Section 50.54(f) (ADAMS Accession No. ML12053A340)."

The letter further states:

"the staff concludes that the plant-specific combination of seismic hazard exceedances, the general estimation of the seismic core damage frequencies for Catawba and McGuire, and insights related to the conditional containment failure probabilities at both these plants indicate that the increase in seismic risk due to the reevaluated seismic hazard is adequately addressed within the margin inherent in the design of these plants and, as such, the completion of SPRAs is not necessary."

As shown in Figure 1, comparing the MNS GMRS (derived from the seismic hazard) to the SSE (seismic design basis capability), the GMRS exceeds the SSE above 6 Hz. As such, it is appropriate that MNS is considered a Tier 2 plant. The basis for MNS being classified as Tier 2 will be documented and presented to the MNS IDP for each system that is categorized.

Figure 1: GMRS and SSE Response Spectra for McGuire (From Reference 35)

U.S. Nuclear Regulatory Commission Page 14 RA-23-0279 The following paragraphs describe additional background and the process to be utilized for the graded approach to categorize the seismic hazard for a Tier 2 plant.

Implementation of the Recommended Process Reference 17 recommends a risk-informed graded approach for addressing the seismic hazard in the 10 CFR 50.69 categorization process. There are a number of seismic fragility fundamental concepts that support a graded approach and there are important characteristics about the comparison of the seismic design basis (represented by the SSE) to the site-specific seismic hazard (represented by the GMRS) that support the selected thresholds between the three evaluation Tiers in the report. The coupling of these concepts with the categorization process in NEI 00-04 are the key elements of the approach defined in Reference 17 for identifying unique seismic insights.

The seismic fragility of an SSC is a function of the margin between an SSC's seismic capacity and the site-specific seismic demand. References such as EPRI NP-6041 (Reference 30) provide inherent seismic capacities for most SSCs that are not directly related to the site-specific seismic demand. This inherent seismic capacity is based on the non-seismic design loads (pressure, thermal, dead weight, etc.) and the required functions for the SSC. For example, a pump has a relatively high inherent seismic capacity based on its design and that same seismic capacity applies at a site with a very low demand and at a site with a very high demand.

There are some plant features such as equipment anchorage that have seismic capacities more closely associated with the site-specific seismic demand since those specific features are specifically designed to meet that demand. However, even for these features, the design basis criteria have intended conservatisms that result in significant seismic margins within SSCs.

These conservatisms are reflected in key aspects of the seismic design process. The SSCs used in nuclear power plants are intentionally designed using conservative methods and criteria to ensure that they have margins well above the required design bases. Experience has shown that design practices result in margins to realistic seismic capacities of 1.5 or more.

In applying the Reference 17 process for Tier 2 sites to the MNS 10 CFR 50.69 categorization process, the IDP will be provided with the rationale for applying the Reference 17 guidance and informed of plant SSC-specific seismic insights that the IDP may choose to consider in their HSS/LSS deliberations. As part of the categorization team's preparation of the System Categorization document (SCD) that is presented to the IDP, a section will be included that provides identified plant seismic insights as well as the basis for applicability of the Reference 17 study and the bases for MNS being a Tier 2 plant. The discussion of the Tier 2 bases will include such factors as:

• The moderate seismic hazard for the plant,

• The definition of Tier 2 in the EPRI study, and

• The basis for concluding MNS is a Tier 2 plant.

At several steps of the categorization process the categorization team will consider the available seismic insights relative to the system being categorized and document their conclusions in the SCD. Integrated importance measures over all modeled hazards (i.e.,

internal events, including internal flooding, internal fire, and high winds for MNS) are calculated per Section 5.6 of NEI 00-04, and components for which these measures exceed the specified

U.S. Nuclear Regulatory Commission Page 15 RA-23-0279 criteria are preliminary HSS which cannot be changed to LSS. For HSS SSCs uniquely identified by the MNS PRA models but having design-basis functions during seismic events or functions credited for mitigation and prevention of severe accidents caused by seismic events, these will be addressed using non-PRA based qualitative assessments in conjunction with any seismic insights provided by the PRA.

For components that are HSS due to fire PRA but not HSS due to internal events PRA, the categorization team will review design-basis functions during seismic events or functions credited for mitigation and prevention of severe accidents caused by seismic events and characterize these for presentation to the IDP as additional qualitative inputs, which will also be described in the SCD.

The categorization team will review available MNS plant-specific seismic reviews and other resources such as those identified above. The objective of the seismic review is to identify plant-specific seismic insights that might include potentially important impacts such as:

x Impact of relay chatter x Implications related to potential seismic interactions such as with block walls x Seismic failures of passive SSCs such as tanks and heat exchangers x Any known structural or anchorage issues with a particular SSC x Components implicitly part of PRA-modeled functions (including relays)

For each system categorized, the categorization team will evaluate correlated seismic failures and seismic interactions between SSCs. This process is detailed in Section 2.3.1 of Reference 17 and is summarized below in Figure 2.

U.S. Nuclear Regulatory Commission Page 16 RA-23-0279 Figure 2: Seismic Correlated Failure Assessment for Tier 2 Plants (Reproduced from Reference 17: Figure 2-4)

Determination of seismic insights will make use of the full power internal events PRA model supplemented by focused seismic walkdowns. An overview of the process to determine the importance of SSCs for mitigating seismic events follows and is utilized on a system basis:

x Gather the population of SSCs in the system being categorized and review existing seismic information (reference Step 1 of Figure 2). This step may use the results of the

U.S. Nuclear Regulatory Commission Page 17 RA-23-0279 required Tier 1 assessment that is performed along with the Tier 2 assessment. As stated in Reference 17 the technical basis for the Tier 1 approach in Section 2.2 of Reference 17 generally applies for Tier 2 plants in addition to the additional sensitivity and walkdowns described herein.

x Assign seismic based SSC equipment class and distributed system IDs, as used for SPRAs, for SSCs in the system being categorized (reference Step 2 of Figure 2).

x Perform a series of screenings to refine the list of SSCs subject to correlation sensitivity studies. Screens will identify (reference Steps 3a/3b/3c of Figure 2):

o Inherently rugged SSCs o SSCs not in Level 1 or Level 2 PRAs o Components already identified as HSS components from the Internal Events PRA or Integrated assessment o The above screened SSCs will still be evaluated for seismic interactions.

x SSCs identified in the above screening can be screened from consideration as functional correlation surrogate events. They are removed from the remainder of the process (can be considered LSS) unless they are subject to interaction source considerations (reference Step 4 of Figure 2).

x Perform Tier 2 Walkdown(s) focusing on identifying seismic correlated or interaction SSC failures (reference Steps 5a/5b of Figure 2).

x Screen out from further seismic considerations SSCs that are determined through the walkdown to be of high seismic capacity and not included in seismically correlated groups or correlated interaction groups since their non-seismic failure modes are already addressed for 50.69 categorization in the FPIE PRA and Fire PRA. Those remaining components proceed forward for inclusion of associated seismic surrogate events in the Tier 2 Adjusted PRA Model (reference Steps 5c/6 of Figure 2).

x Develop a Tier 2 Adjusted PRA Model and incorporate seismic surrogate events into the model to reflect the potential seismically correlated and interaction conditions identified in prior steps (reference Steps 6/7 of Figure 2). The seismic surrogate basic events shall be added to the PRA under the appropriate areas in the logic model (e.g.,

given that the Tier 2 Adjusted PRA Model uses only loss of offsite power (LOOP) and small loss of coolant accident (LOCA) sequences, the seismic surrogate events should be added to system and/or nodal fault tree structures that tie into these sequence types). The probability of each seismic surrogate basic event added to the model should be set to 1.0E-04 (based on guidance in Reference 17).

x Quantify only the LOOP and small LOCA initiated accident sequences of the Tier 2 Adjusted PRA Model (reference Step 8 of Figure 2). The event frequency of the LOOP initiator shall be set to a value of 1.0 and the event frequency for the small LOCA initiator shall be set to a value of 1.0E-02. Remove credits for restoration of offsite power and other functional recoveries (e.g., Emergency Diesel Generator (EDG) and DC power recovery).

U.S. Nuclear Regulatory Commission Page 18 RA-23-0279 x Utilize the Importance Measures from the quantification of the Tier 2 Adjusted PRA Model to identify appropriate SSCs (in the system being categorized) that should be HSS due to correlation or seismic interactions (reference Step 9 of Figure 2).

x SSCs screened out in Steps 5c, 6, or 9 in Figure 2 above can be considered LSS (reference Step 10 of Figure 2).

x Prepare documentation of the Tier 2 analysis results, including identification of seismic unique HSS SSCs, for presentation to the IDP (reference Step 11 of Figure 2).

Seismic impacts would be compiled on an SSC basis. As each system is categorized, the system-specific seismic insights will be documented in the categorization report and provided to the IDP for consideration as part of the IDP review process. The IDP cannot challenge any candidate HSS recommendation for any SSC from a seismic perspective if they believe there is a basis, except for certain conditions identified in Step 10 of Section 2.3.1 of Reference 17.

Any decision by the IDP to downgrade preliminary HSS components to LSS will consider the applicable seismic insights in that decision. SSCs identified from the Fire PRA as candidate HSS, which are not HSS from the internal events PRA or integrated importance measure assessment, will be reviewed for their design basis function during seismic events or functions credited for mitigation and prevention of severe accidents caused by seismic events. These insights will provide the IDP a means to consider potential impacts of seismic events in the categorization process.

If the MNS seismic hazard changes from medium risk (i.e., Tier 2) at some future time, prior NRC approval, under 10 CFR 50.90, will be requested if the MNS feedback process determines that a process different from the proposed alternative seismic approach is warranted for seismic risk consideration in categorization under 10 CFR 50.69. After receiving NRC approval, Duke Energy will follow its categorization review and adjustment process to review the changes to the plant and update, as appropriate, the SSC categorization in accordance with 10 CFR 50.69(e) and the EPRI 3002017583 SSC categorization criteria for the updated Tier. This includes use of the Duke Energy corrective action process.

If the seismic hazard is reduced such that it meets the criteria for Tier 1 in EPRI 3002017583, Duke Energy will implement the following process.

a. For previously completed system categorizations, Duke Energy may review the categorization results to determine if use of the criteria in EPRI 3002017583 Section 2.2, "Tier 1 - Low Seismic Hazard / High Seismic Margin Sites" would lead to categorization changes. If changes are warranted, they will be implemented through the Duke Energy design control and corrective action programs and NEI 00-04, Section 12.

b. Seismic considerations for subsequent system categorization activities will be performed in accordance with the guidance in EPRI 3002017583 Section 2.2, "Tier 1 - Low Seismic Hazard / High Seismic Margin Sites."

U.S. Nuclear Regulatory Commission Page 19 RA-23-0279 If the seismic hazard increases to the degree that a SPRA becomes necessary to demonstrate adequate seismic safety, Duke Energy will implement the following process following completion of the SPRA, including adequate closure of Peer Review Findings and Observations.

a. For previously completed system categorizations, Duke Energy will review the categorization results using the SPRA insights as prescribed in NEI 00-04 Section 5.3, Seismic Assessment and Section 5.6, "Integral Assessment. If changes are warranted, they will be implemented through the Duke Energy design control and corrective action programs and NEI 00-04 Section 12.

b. Seismic considerations for subsequent system categorization activities will follow the guidance in NEI 00-04, as recommended in EPRI 3002017583 Section 2.4, "Tier 3 - High Seismic Hazard / Low Seismic Margin Sites".

Historical Seismic References for MNS The MNS GMRS and SSE curves from the seismic hazard and screening response are shown in Figure 1, as replicated from the seismic hazard and screening report (Reference 35). The NRC's Staff assessment of the MNS seismic hazard and screening response is documented in Reference 37.

Section 1.1.3 of Reference 17 cites various post-Fukushima seismic reviews performed for the U.S. fleet of nuclear power plants. For MNS, the specific seismic reviews prepared by the licensee and the NRC's staff assessments are provided here. These licensee documents were submitted under oath and affirmation to the NRC.

1. Near-Term Task Force (NTTF) Recommendation 2.1 Seismic Hazard Screening (References 35 and 37).

2. NTTF Recommendation 2.1 Spent Fuel Pool assessment (References 44 and 45).

3. NTTF Recommendation 2.3 Seismic Walkdowns (References 46, 47, and 48).

4. NTTF Recommendation 4.2 Seismic Mitigation Strategy Assessment (S-MSA)

(References 49 and 50).

The following additional post-Fukushima seismic reviews were performed for MNS:

5. NTTF Recommendation 2.1 Expedited Seismic Evaluation Process (ESEP)

(References 41, 42, 43 and 51).

6. NTTF Recommendation 2.1 Seismic High Frequency Evaluation (References 38 and 39).

Technical Information Incorporated by Reference Duke Energy will follow the same alternative seismic approach in the 10 CFR 50.69 categorization process for MNS as the approach that was approved by the NRC staff for LaSalle County Station (Reference 52) with two exceptions:

The MNS LAR cites EPRI Report 3002017583 as applicable to the submittal. The citation for EPRI Report 3002017583 is ADAMS Accession No. ML21082A170. Additionally, the

U.S. Nuclear Regulatory Commission Page 20 RA-23-0279 discussion above cites mark-ups to EPRI Report 3002012988 that were submitted with LaSalle 10 CFR 50.69 LAR RAI responses dated October 16, 2020 (Reference 18) and January 22, 2021 (Reference 19).

The MNS LAR also incorporates the following additional LaSalle 10 CFR 50.69 LAR RAI response (Reference 36) that does not include any mark-ups to EPRI Report 3002017583 but addresses process issues associated with the proposed alternative seismic approach, and specifically excludes LaSalle RAI APLC 50.69-RAI No. 12 that addresses a non-seismic topic (external events).

Summary Based on the above, the Summary from Section 2.3.3 of Reference 17 applies to MNS; namely, MNS is a Tier 2 plant for which there may be a limited number of unique seismic insights, most likely attributed to the possibility of seismically correlated failures, appropriate for consideration in determining HSS SSCs. References 18, 19, and 36 (excludes RAI APLC 50.69-RAI No. 12 that addresses a non-seismic topic (external events)) are incorporated into this LAR as they provide additional supporting bases for Tier 2 plants.

The special sensitivity study recommended using common cause failures, similar to the approach taken in a FPIE PRA, can identify the appropriate seismic insights to be considered with the other categorization insights by the IDP for the final HSS determinations. Use of the EPRI approach outlined in Reference 17 to assess seismic hazard risk for 10 CFR 50.69 with the additional reviews discussed above will provide a process for categorization of RISC-1, RISC-2, RISC-3, and RISC-4 SSCs that satisfies the requirements of 10 CFR 50.69(c).

3.2.4 Other External Hazards All external hazards were screened for applicability to MNS, except seismic and high winds, per a plant-specific evaluation in accordance with Generic Letter (GL) 88-20 (Reference 6) and updated to use the criteria in ASME PRA Standard RA-Sa-2009. Attachment 4 provides a summary of the other external hazards screening results. Attachment 5 provides a summary of the progressive screening approach for external hazards.

The MNS categorization process for High Winds will use peer-reviewed plant-specific high winds PRA model. The Duke Energy risk management process ensures that the PRA model used in this application reflects the as-built and as-operated plant for each of the MNS units. at the end of this enclosure identifies the applicable high winds PRA model.

SSCs credited for screening of external hazards will be evaluated using the guidance illustrated in Figure 5-6 of NEI 00-04 during the implementation of the 10 CFR 50.69 categorization process. Local Intense Precipitation (LIP), dispositioned in Attachment 4, credits the SSCs noted in the table below.

Table 3-2: McGuire Flood Protection Barriers for the LIP Event Unit Elevation Door Number Description 1 760 1EXADR1000C Unit 1 SFP to AB 760' Elevation 1 760 1EXADR1000D Unit 1 SFP to AB 760' Elevation

U.S. Nuclear Regulatory Commission Page 21 RA-23-0279 Unit Elevation Door Number Description 1 760 0XCDDR1004A AB First Aid Room Outside Door 1 760 0XCDDF1011A Shredder/Compactor Area to Waste Shipping 1 760 0XCDDRRA10 Shredder/Compactor Area to Waste Shipping Rollup Door 2 760 0XCDDR1024A AB Hot Machine Shop 2 760 0XCDDR1026D AB 760 Corridor to Hot Tool Room Area 2 760 2EXADF1026C Unit 2 SFP to AB 760' Elevation N/A 784 0XCDDR1255 AB 784' Corridor North End N/A 784 0XCDDF0415A AB 784' Corridor to Central Stairwell 3.2.5 Low Power and Shutdown Consistent with NEI 00-04, the MNS categorization process will use the shutdown safety management plan described in NUMARC 91-06 (Reference 3) for evaluation of safety significance related to low power and shutdown conditions. The overall process for addressing shutdown risk is illustrated in Figure 5-7 of NEI 00-04.

NUMARC 91-06 specifies that a defense-in-depth approach should be used with respect to each defined shutdown key safety function. The key safety functions defined in NUMARC 91-06 are evaluated for categorization of SSCs.

SSCs that meet either of the two criteria (i.e., considered part of a primary shutdown safety system or a failure would initiate an event during shutdown conditions) described in Section 5.5 NEI 00-04 will be considered preliminary HSS.

3.2.6 PRA Maintenance and Updates The Duke Energy risk management process ensures that the applicable PRA models used in this application continues to reflect the as-built and as-operated plant for each of the MNS units.

The process delineates the responsibilities and guidelines for updating the PRA models and includes criteria for both regularly scheduled and interim PRA model updates. The process includes provisions for monitoring potential areas affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, and industry operational experience) for assessing the risk impact of unincorporated changes, and for controlling the model and associated computer files. The process will assess the impact of these changes on the plant PRA model in a timely manner but no longer than once every two refueling outages. If there is a significant impact on the PRA model, the SSC categorization will be re-evaluated.

U.S. Nuclear Regulatory Commission Page 22 RA-23-0279 In addition, Duke Energy will implement a process that addresses the requirements in NEI 00-04, Section 11, Program Documentation and Change Control. The process will review the results of periodic and interim updates of the plant PRA that may affect the results of the categorization process. If the results are affected, adjustments will be made as necessary to the categorization or treatment processes to maintain the validity of the processes. In addition, any PRA model upgrades will be peer reviewed prior to implementing those changes in the PRA model used for categorization.

3.2.7 PRA Uncertainty Evaluations Uncertainty evaluations associated with any applicable baseline PRA model(s) used in this application were evaluated during the assessment of PRA technical adequacy and confirmed through the self-assessment and peer review processes as discussed in Section 3.3 of this enclosure.

Uncertainty evaluations associated with the risk categorization process are addressed using the processes discussed in Section 8 of NEI 00-04 and in the prescribed sensitivity studies discussed in Section 5.

In the overall risk sensitivity studies, Duke Energy will utilize a factor of 3 to increase the unavailability or unreliability of LSS components consistent with that approved for Vogtle in Reference 4. Consistent with the NEI 00-04 guidance, Duke Energy will perform both an initial sensitivity study and a cumulative sensitivity study. The initial sensitivity study applies to the system that is being categorized. In the cumulative sensitivity study, the failure probabilities (unreliability and unavailability, as appropriate) of all LSS components modeled in all identified PRA models for all systems that have been categorized are increased by a factor of 3. This sensitivity study together with the periodic review process assures that the potential cumulative risk increase from the categorization is maintained acceptably low. The performance monitoring process monitors the component performance to ensure that potential increases in failure rates of categorized components are detected and addressed before reaching the rate assumed in the sensitivity study.

The detailed process of identifying, characterizing and qualitative screening of model uncertainties is found in Section 5.3 of NUREG-1855 (Reference 8) and Section 3.1.1 of EPRI TR-1016737 (Reference 9). The process in these references was mostly developed to evaluate the uncertainties associated with the internal events PRA model; however, the approach can be applied to other types of hazard groups.

Each PRA element notebook was reviewed for assumptions and sources of uncertainties. The characterization of assumptions and sources of uncertainties are based on whether the assumption and/or source of uncertainty is key to the 10 CFR 50.69 application in accordance with RG 1.200 Revision 2.

Key MNS PRA model specific assumptions and sources of uncertainty for this application were identified and dispositioned in Attachment 6. The conclusion of this review is that no additional sensitivity analyses are required to address MNS PRA model specific assumptions or sources of uncertainty.

U.S. Nuclear Regulatory Commission Page 23 RA-23-0279 3.3 PRA Review Process Results (10 CFR 50.69(b)(2)(iii))

The PRA models described in Section 3.2 have been assessed against RG 1.200, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Revision 2 (Reference 7) consistent with NRC RIS 2007-06.

Internal Events The MNS Units 1 and 2 Internal Events PRA model peer review was performed in June 2015 against ASME/ANS PRA Standard RA-Sa-2009 (Reference 10), RG 1.200 Revision 2 (Reference 7), and NEI 05-04 (Reference 53).

Resolved findings were reviewed and closed in February 2016 using the process documented in the draft of Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13, Close-out of Facts and Observations (F&Os) published at the time of the review. Subsequently, the finding closure review was reperformed in May 2019 to the approved process documented in Appendix X to NEI 05-04/07-12/12-13 (References 11 and 12). A subsequent finding closure review was conducted in November 2021 where resolved findings were reviewed and closed using the process documented in NEI 17-07 Performance of PRA Peer Reviews Using the ASME/ANS PRA Standard (Reference 54).

The results of these reviews have been documented and are available for NRC audit.

In conclusion, all the finding level F&Os have been closed, and all associated supporting requirements (SRs) are now judged to be met at Capability Category II or higher. There are no PRA upgrades that have not been peer reviewed.

Large Early Release Frequency (LERF)

The MNS Units 1 and 2 LERF PRA model peer review was performed in December 2012 against ASME/ANS PRA Standard RA-Sa-2009 (Reference 10), RG 1.200 Revision 2 (Reference 7), and NEI 05-04 (Reference 53).

Resolved findings were reviewed and closed in November 2018 using the process documented in Appendix X to NEI 05-04/07-12/12-13 (References 11 and 12). A subsequent finding closure review was conducted in June 2022 where resolved findings were reviewed and closed using the process documented in NEI 17-07 (Reference 54).

The results of these reviews have been documented and are available for NRC audit.

In conclusion, all the finding level F&Os have been closed, and all associated SRs are now judged to be met at Capability Category II or higher. There are no PRA upgrades that have not been peer reviewed.

Internal Flooding The MNS Units 1 and 2 Internal Flooding PRA model peer review was performed in September 2011 against ASME/ANS PRA Standard RA-Sa-2009 (Reference 10), RG 1.200 Revision 2 (Reference 7), and NEI 05-04 (Reference 53).

U.S. Nuclear Regulatory Commission Page 24 RA-23-0279 A finding closure review was conducted on the Internal Flooding PRA model in November 2018 where resolved findings were reviewed and closed using the process documented in Appendix X to NEI 05-04/07-12/12-13 (References 11 and 12). A subsequent finding closure review was conducted in June 2022 where resolved findings were reviewed and closed using the process documented in NEI 17-07 (Reference 54).

The results of these reviews have been documented and are available for NRC audit.

In conclusion, all the finding level F&Os have been closed, and all associated SRs are now judged to be met at Capability Category II or higher. There are no PRA upgrades that have not been peer reviewed.

Fire The MNS Units 1 and 2 Fire PRA model peer review was performed in 2010 against ASME/ANS PRA Standard RA-Sa-2009 (Reference 10), RG 1.200 Revision 2 (Reference 7),

and NEI 07-12 (Reference 55). In 2019, 2020, 2021, and 2022 Focused Scope Peer Reviews (FSPRs) were performed to address various PRA upgrades where all of the FSPRs were performed against ASME/ANS PRA Standard RA-Sa-2009 (Reference 10), RG 1.200 Revision 2 (Reference 7), and NEI 07-12 (Reference 56) or NEI 17-07 (Reference 54), as applicable at the time of the review.

Finding closure reviews were conducted on the Fire PRA model in January 2019 and December 2020 where resolved findings were reviewed and closed using the process documented in Appendix X to NEI 05-04/07-12/12-13 (References 11 and 12). Subsequent closure reviews were conducted on the Fire PRA model in November 2021 and September 2022 where resolved findings were reviewed and closed using the process documented in NEI 17-07 (Reference 54). In some instances, a FSPR and F&O closure review were conducted in parallel, however, in each instance, the scope for the F&O closure did not include any findings generated from the parallel FSPR. The following list provides a summary of the scope for each review and the detailed reports for each review are available for NRC audit:

x January 2019 FSPR: Assesses a model upgrade to use Human Reliability Analysis (HRA) Calculator Software for Fire PRA Human Failure Event (HFE) Analysis x January 2019 F&O Closure: This closure review was performed in parallel to the January 2019 FSPR and does not assess findings generated in the parallel FSPR x December 2020 FSPR: Assesses a model upgrade to use the Obstructed Radiation Method x December 2020 F&O Closure: Assesses two findings generated in the January 2019 FSPR on HRA x November 2021 FSPR: Assesses two newly applicable SRs and one SR previously assessed at Capability Category I with no open finding x November 2021 F&O Closure: Assesses select findings from 2020 FSPR x August 2022 FSPR: Assesses a newly applicable SR and a model upgrade to use a quantitative analysis for fire impacts to structural steel

U.S. Nuclear Regulatory Commission Page 25 RA-23-0279 x September 2022 F&O Closure: Assesses closure of the finding from the August 2022 FSPR The results of these reviews have been documented and are available for NRC audit.

In conclusion, all the finding level F&Os have been closed, and all associated SRs are now judged to be met at Capability Category II or higher. There are no PRA upgrades that have not been peer reviewed.

High Winds The MNS Units 1 and 2 High Winds PRA model peer review was performed in October 2014 against ASME/ANS PRA Standard RA-Sb-2013 (Reference 60), RG 1.200 Revision 2 (Reference 7), and Nuclear Energy Institute (NEI) 05-04 (Reference 53).

A finding closure review was conducted on the High Winds PRA model in December 2021 where resolved findings were reviewed and closed using the process documented in NEI 17-07 (Reference 54).

The results of these reviews have been documented and are available for NRC audit.

In conclusion, all the finding level F&Os have been closed, and all associated SRs are now judged to be met at Capability Category II or higher. There are no PRA upgrades that have not been peer reviewed. reflects zero open finding level F&Os for MNS PRA models. The attachments identified above demonstrate that the PRA is of sufficient quality and level of detail to support the categorization process and has been subjected to a peer review process assessed against a standard or set of acceptance criteria that is endorsed by the NRC as required 10 CFR 50.69(c)(1)(i).

3.4 Risk Evaluations (10 CFR 50.69(b)(2)(iv))

The MNS 10 CFR 50.69 categorization process will implement the guidance in NEI 00-04. The overall risk evaluation process described in the NEI guidance addresses both known degradation mechanisms and common cause interactions and meets the requirements of

§50.69(b)(2)(iv). Sensitivity studies described in NEI 00-04 Section 8 will be used to confirm that the categorization process results in acceptably small increases to core damage frequency (CDF) and LERF. The failure rates for equipment and initiating event frequencies used in the PRA include the quantifiable impacts from known degradation mechanisms, as well as other mechanisms (e.g., design errors, manufacturing deficiencies, and human errors). Subsequent performance monitoring and PRA updates required by the rule will continue to capture this data and provide timely insights into the need to account for any important new degradation mechanisms.

3.5 Feedback and Adjustment Process If significant changes to the plant risk profile are identified, or if it is identified that a RISC-3 or RISC-4 SSC can (or actually did) prevent a safety significant function from being satisfied, an immediate evaluation and review will be performed prior to the normally scheduled periodic review. Otherwise, the assessment of potential equipment performance changes and

U.S. Nuclear Regulatory Commission Page 26 RA-23-0279 new technical information will be performed during the normally scheduled periodic review cycle.

The performance monitoring process is described in Duke Energys 10 CFR 50.69 program documents. The program requires that the periodic review assess changes that could impact the categorization results and provides the IDP with an opportunity to recommend categorization and treatment adjustments. Station personnel from Engineering, Operations, Risk Management, Regulatory Affairs, and others have responsibilities for preparing and conducting various performance monitoring tasks that feed into this process. The intent of the performance monitoring reviews is to discover trends in component reliability, to help catch and reverse negative performance trends and take corrective action if necessary.

To more specifically address the feedback and adjustment (i.e., performance monitoring) process as it pertains to the proposed MNS Tier 2 approach discussed in Section 3.2.3, implementation of the Duke Energy design control and corrective action programs will ensure the inputs for the qualitative determinations for seismic continue to remain valid to maintain compliance with the requirements of 10 CFR 50.69(e).

Duke Energy has a comprehensive problem identification and corrective action program that ensures that issues are identified and resolved. Any issue that may impact the 10 CFR 50.69 categorization process will be identified and addressed through the problem identification and corrective action program, including seismic-related issues.

The Duke Energy 10 CFR 50.69 program requires that SCDs cannot be approved by the IDP until the panels comments have been resolved to the satisfaction of the IDP. This includes issues related to system-specific seismic insights considered by the IDP during categorization.

Scheduled periodic reviews are completed at least once every two refueling cycles in accordance with Duke Energy procedures and will evaluate new insights resulting from available risk information (i.e., PRA model or other analysis used in the categorization) changes, design changes, operational changes, and SSC performance. If it is determined that these changes have affected the risk information or other elements of the categorization process such that the categorization results are more than minimally affected, then the risk information and the categorization process will be updated. This review will include:

x A review of plant modifications since the last review that could impact the SSC categorization x A review of plant specific operating experience that could impact the SSC categorization, x A review of the impact of the updated risk information on the categorization process results x A review of the importance measures used for screening in the categorization process.

x An update of the risk sensitivity study performed for the categorization x Input from Regulatory Affairs and Operations regarding changes that may affect the bases for the categorization results.

In addition to the normally scheduled periodic reviews, if a PRA model or other risk information is upgraded, a review of the SSC categorization will be performed.

U.S. Nuclear Regulatory Commission Page 27 RA-23-0279

4. REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria The following NRC requirements and guidance documents are applicable to the proposed change.

x The regulations in Title 10 of the Code of Federal Regulations (10 CFR) Part 50.69, "Risk-Informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors."

x NRC Regulatory Guide 1.201, "Guidelines for Categorizing Structures, Systems, and Components in Nuclear Power Plants According to their Safety Significance, Revision 1, May 2006.

x Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 2, April 2015.

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

The proposed change is consistent with the applicable regulations and regulatory guidance.

4.2 No Significant Hazards Consideration Determination Analysis Duke Energy Carolinas, LLC (Duke Energy) proposes to modify the licensing basis for McGuire Nuclear Station, Units 1 and 2, to allow for the voluntary implementation of the provisions of Title 10 of the Code of Federal Regulations (10 CFR), Part 50.69, Risk-informed categorization and treatment of structures, systems and components for nuclear power reactors. The provisions of 10 CFR 50.69 allow adjustment of the scope of equipment subject to special treatment controls (e.g., quality assurance, testing, inspection, condition monitoring, assessment, and evaluation). For equipment determined to be of low safety significance, alternative treatment requirements can be implemented in accordance with this regulation. For equipment determined to be of high safety significance, requirements will not be changed or will be enhanced. This allows improved focus on equipment that has safety significance resulting in improved plant safety.

Duke Energy has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment, as discussed below:

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change will permit the use of a risk-informed categorization process to modify the scope of Structures, Systems and Components (SSCs) subject to NRC special treatment requirements and to implement alternative treatments per the

U.S. Nuclear Regulatory Commission Page 28 RA-23-0279 regulations. The process used to evaluate SSCs for changes to NRC special treatment requirements and the use of alternative requirements ensures the ability of the SSCs to perform their design function. The potential change to special treatment requirements does not change the design and operation of the SSCs. As a result, the proposed change does not significantly affect any initiators to accidents previously evaluated or the ability to mitigate any accidents previously evaluated. The consequences of the accidents previously evaluated are not affected because the mitigation functions performed by the SSCs assumed in the safety analysis are not being modified. The SSCs required to safely shut down the reactor and maintain it in a safe shutdown condition following an accident will continue to perform their design functions.

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

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

Response: No.

The proposed change will permit the use of a risk-informed categorization process to modify the scope of SSCs subject to NRC special treatment requirements and to implement alternative treatments per the regulations. The proposed change does not change the functional requirements, configuration, or method of operation of any SSC.

Under the proposed change, no additional plant equipment will be installed.

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

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

Response: No.

The proposed change will permit the use of a risk-informed categorization process to modify the scope of SSCs subject to NRC special treatment requirements and to implement alternative treatments per the regulations. The proposed change does not affect any Safety Limits or operating parameters used to establish the safety margin.

The safety margins included in analyses of accidents are not affected by the proposed change. The regulation requires that there be no significant effect on plant risk due to any change to the special treatment requirements for SSCs and that the SSCs continue to be capable of performing their design basis functions, as well as to perform any beyond design basis functions consistent with the categorization process and results.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, Duke Energy concludes that the proposed change presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and accordingly, a finding of no significant hazards consideration is justified.

U.S. Nuclear Regulatory Commission Page 29 RA-23-0279 4.3 Conclusions In conclusion, based on the considerations discussed above: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner; (2) such activities will be conducted in compliance with the Commissions regulations; and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5. ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or a significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6. REFERENCES

1. NEI 00-04, 10 CFR 50.69 SSC Categorization Guideline," Revision 0, Nuclear Energy Institute, July 2005.

2. NRC Regulatory Guide 1.201, Guidelines for Categorizing Structures, Systems, and Components in Nuclear Power Plants According to their Safety Significance, Revision 1, May 2006.

3. NUMARC 91-06, Guidelines for Industry Actions to Assess Shutdown Management, December 1991.

4. NRC letter to Southern Nuclear Operating Company, Inc., Vogtle Electric Generating Plant Units 1 and 2 - Issuance of Amendments Re: Use of 10 CFR 50.69 (TAC Nos. ME9472 and ME94473), dated December 17, 2014 (ADAMS Accession No. ML14237A034)

5. NRC letter to Entergy Operations, Inc., Arkansas Nuclear One, Unit 2 - Approval of Request for Alternative AN02-R&R-004, Revision 1, Request to Use Risk-Informed Safety Classification and Treatment for Repair/Replacement Activities in Class 2 and 3 Moderate and High Energy Systems (TAC No. MD5250), dated April 22, 2009 (ADAMS Accession No. ML090930246).

6. Generic Letter 88-20, Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f), Supplement 4, USNRC, June 1991.

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

8. NUREG-1855, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking, Revision 1, March 2017

9. EPRI TR-1016737, Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments, December 2008

U.S. Nuclear Regulatory Commission Page 30 RA-23-0279

10. ASME/ANS RA-Sa-2009, Standard for Level l/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, Addendum A to RA-S-2008, dated February 2009

11. NEI Letter to NRC, Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close-Out of Facts and Observations (F&Os), February 21, 2017 (ADAMS Accession No. ML17086A431).

12. NRC Letter to Mr. Greg Krueger (NEI), U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance 05-04, 07-12, and 12-13, Close-Out of Facts and Observations (F&Os), May 3, 2017 (ADAMS Accession No. ML17079A427).

13. NRC Letter to Mr. Oliver Martinez, U.S. Nuclear Regulatory Commission (NRC)

Comments on Addenda to a Current ANS: ASME RA-SB - 20XX, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment For Nuclear Power Plant Applications, dated July 6, 2011 (ADAMS Accession No. ML111720076).

14. NRC Letter to Duke Energy, McGuire Nuclear Station, Units 1 AND 2, Issuance of Amendments Regarding Revision of the Technical Specifications to Relocate Specific Surveillance Frequencies to a Licensee-Controlled Program Using a Risk-Informed Justification (TSTF-425), dated March 29, 2011 (ADAMS Accession No. ML110680357).

15. Letter from NRC to Duke Energy, McGuire Nuclear Station, Units 1 and 2 - Issuance of Amendments Regarding National Fire Protection Association Standard (NFPA) 805, dated December 6, 2016 (ADAMS Accession No. ML16077A135).

16. Letter from NRC to Duke Energy, Review of McGuire Nuclear Station, Units 1 and 2 -

Individual Plant Examination of External Events Submittal, dated February 16, 1999 (ADAMS Accession No. ML20203J043).

17. Electric Power Research Institute (EPRI) 3002017583, Alternative Approaches for Addressing Seismic Risk in 10 CFR 50.69 Risk-Informed Categorization, February 2020 (ADAMS Accession No. ML21082A170).

18. Exelon Generation Company, LLC Letter to NRC, Response to Request for Additional Information Regarding LaSalle License Amendment Request to Renewed Facility Operating Licenses to Adopt 10 CFR 50.69, Risk-Informed Categorization and Treatment of Structures, Systems, and Components for Nuclear Power Reactors," dated October 16, 2020 (ADAMS Accession No. ML20290A791).

19. Exelon Generation Company, LLC Letter to NRC, "Response to Request for Additional Information Regarding the License Amendment Request to Adopt 10 CFR 50.69," dated January 22, 2021 (ADAMS Accession No. ML21022A130).

20. NRC letter to all Power Reactor Licensees, "Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident,"

March 12, 2012 (ADAMS Accession No. ML12053A340)

21. Exelon Generation Company, LLC Letter to NRC, Seismic Probabilistic Risk Assessment Report, Response to NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident," dated August 28, 2018 (ADAMS Accession No. ML18240A065).

U.S. Nuclear Regulatory Commission Page 31 RA-23-0279

22. NRC Letter to Exelon Generation Company, LLC, Peach Bottom Atomic Power Station, Units 2 and 3 - Staff Review of Seismic Probabilistic Risk Assessment Associated with Reevaluated Seismic Hazard Implementation of the Near-Term Task Force Recommendation 2.1: Seismic," (EPID NO. L-2018-JLD-0010), June 10, 2019 (ADAMS Accession No. ML19053A469)

23. NRC Letter to Exelon Generation Company, LLC, Peach Bottom Atomic Power Station, Units 2 and 3 - Correction Regarding Staff Review of Seismic Probabilistic Risk Assessment Associated with Reevaluated Seismic Hazard Implementation of the Near-Term Task Force Recommendation 2.1: Seismic," (EPID NO. L-2018-JLD-0010), October 8, 2019 (ADAMS Accession No. ML19248C756)

24. Southern Nuclear Operating Company, Inc. Letter to NRC, Vogtle Electric Generating Plant - Units 1 and 2 License Amendment Request to Modify Approved 10 CFR 50.69 Categorization Process," June 22, 2017 (ADAMS Accession No. ML17173A875)

25. NRC Letter to Southern Nuclear Operating Company, Inc., Vogtle Electric Generating Plant, Units 1 and 2 - Issuance of Amendments Regarding Application of Seismic Probabilistic Risk Assessment into the Previously Approved 10 CFR 50.69 Categorization Process," August 10, 2018 (ADAMS Accession No. ML18180A062)

26. Tennessee Valley Authority Letter to NRC, Seismic Probabilistic Risk Assessment for Watts Bar Nuclear Plant, Units 1 and 2, Response to NRC Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident," June 30, 2017 (ADAMS Accession No. ML17181A485)

27. Tennessee Valley Authority Letter to NRC, Tennessee Valley Authority (TVA) - Watts Bar Seismic Probabilistic Risk Assessment Supplemental Information, April 10, 2018 (ADAMS Accession No. ML18100A966)

28. NRC Letter to Tennessee Valley Authority, Watts Bar Nuclear Plant, Units 1 and 2 - Staff Review of Seismic Probabilistic Risk Assessment Associated with Reevaluated Seismic Hazard Implementation of the Near-Term Task Force Recommendation 2.1: Seismic (CAC NOS. MF9879 AND MF9880; EPID L-2017-JLD-0044) July 10, 2018 (ADAMS Accession No. ML18115A138)

29. NRC Letter to Tennessee Valley Authority, Watts Bar Nuclear Plant, Units 1 And 2 -

Issuance of Amendment Nos. 134 And 38 Regarding Adoption of Title 10 of the Code of Federal Regulations Section 50.69, "Risk-Informed Categorization and Treatment Of Structures, Systems, and Components For Nuclear Power Plants (EPID L-2018-LLA-0493), April 30, 2020 (ADAMS Accession No. ML20076A194)

30. EPRI NP-6041-SL, "A Methodology for Assessment of Nuclear Power Plant Seismic Margin", Revision 1, August 1991

31. Exelon Generation Company, LLC, letter to NRC, "Supplemental Information to Support Application to Adopt 10 CFR 50.69, 'Risk-informed categorization and treatment of structures, systems, and components for nuclear power plants," June 6, 2018 (ADAMS Accession No. ML18157A260)

32. Southern Nuclear Operating Company, Inc. letter to NRC, "Vogtle Electric Generating Plant, Units 1 & 2, License Amendment Request to Incorporate Seismic Probabilistic Risk Assessment into 10 CFR 50.69 Categorization Process, Response to Request for Additional Information (RAIs 4-11)," February 21, 2018 (ADAMS Accession No. ML18052B342)

U.S. Nuclear Regulatory Commission Page 32 RA-23-0279

33. Tennessee Valley Authority Letter to NRC, Watts Bar Nuclear Plant, Units 1 and 2, Application to Adopt 10 CFR 50.69, Risk-informed Categorization and Treatment of Structures, Systems, and Components for Nuclear Power Reactors," November 29, 2018 (ADAMS Accession No. ML18334A363)

34. MCC-1535.00-00-0252 Revision 1, MNS 50.69 and TSTF-505 LAR Support Calculation

35. Duke Energy Letter to NRC, "Seismic Hazard and Screening Report (CEUS Sites),

Response to NRC 10 CFR 50.54(f) Request for Information Pursuant to Title 10 of the Code of Federal Regulations Section 50.54(f) regarding Recommendations 2.1, 2.3 and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident,"

(ADAMS Accession No. ML14098A421), dated March 20, 2014.

36. Exelon Generation Company, LLC Letter to NRC, "Response to Request for Additional Information Regarding LaSalle License Amendment Request to Renewed Facility Operating Licenses to Adopt 10 CFR 50.69, Risk-informed categorization and treatment of structures, systems, and components for nuclear power plants," dated October 1, 2020 (ADAMS Accession No. ML20275A292).

37. NRC Letter to Duke Energy Carolinas, LLC, Catawba Nuclear Station, Units 1 and 2, and McGuire Nuclear Station, Units 1 and 2, Screening and Prioritization Results Regarding Seismic Hazard Reevaluations for Recommendation 2.1 of the Near-Term Task Force Review of Insights From the Fukushima Dai-ichi Accident," (ADAMS Accession No. ML16344A313), dated December 22, 2016.

38. Duke Energy Letter to NRC, High Frequency Supplement to Seismic Hazard Screening Report, Response NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, (ADAMS Accession No. ML17230A088), dated August 10, 2017.

39. NRC Letter to Duke Energy Carolinas, LLC, McGuire Nuclear Station, Units 1 and 2 - Staff Review of High Frequency Confirmation Associated with Reevaluated Seismic Hazard Implementing Near-Term Task Force Recommendation 2.1 (ADAMS Accession No. ML17320A770), dated November 20, 2017.

40. Duke Energy Letter to NRC, "Supplemental Information Regarding Reevaluated Seismic Hazard Screening and Prioritization Results - Response to NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendations 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident," (ADAMS Accession No. ML16295A342), dated October 20, 2016.

41. Duke Energy Letter to NRC, Expedited Seismic Evaluation Process (ESEP) Report (CEUS Sites), Response to NRC Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, (ADAMS Accession No. ML15005A085), dated December 17, 2014.

42. Duke Energy Letter to NRC, Expedited Seismic Evaluation Process (ESEP) Report (CEUS Sites), Response to NRC Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, (ADAMS Accession No. ML15313A153), dated October 8, 2015.

U.S. Nuclear Regulatory Commission Page 33 RA-23-0279

43. Duke Energy Letter to NRC, Expedited Seismic Evaluation Process (ESEP) Closeout, Response to NRC Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, ADAMS Accession No. ML16041A173), dated February 4, 2016.

44. Duke Energy Letter to NRC, Spent Fuel Pool Evaluation Supplemental Report, Response to NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, (ADAMS Accession No. ML16236A074), dated August 18, 2016.

45. NRC Letter to Duke Energy Carolinas, LLC, McGuire Nuclear Station, Units 1 and 2 - Staff Review of Spent Fuel Pool Evaluation Associated with Reevaluated Seismic Hazard Implementing Near-Term Task Force Recommendation 2.1, (ADAMS Accession No. ML16237A354), dated August 31, 2016.

46. Duke Energy Letter to NRC, Seismic Walkdown Information Requested by NRC Letter, Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f)

Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident; dated March 12, 2012, (ADAMS Accession No. ML13003A339), dated November 26, 2012.

47. Duke Energy Letter to NRC, Response to Request for Additional Information Regarding the Seismic Hazard Walkdowns Associated With Near-Term Task Force Recommendation 2.3, Seismic Walkdowns, (ADAMS Accession No. ML13338A171), dated November 26, 2013.

48. NRC Letter to Duke Energy Carolinas, LLC, McGuire Nuclear Station, Unit 1- Staff Assessment of The Seismic Walkdown Report Supporting Implementation Of Near-Term Task Force Recommendation 2.3 Related To The Fukushima Dai-Ichi Nuclear Power Plant Accident, (ADAMS Accession No. ML14114A305), dated May 8, 2014.

49. Duke Energy Letter to NRC, McGuire Nuclear Station (MNS) Seismic Mitigating Strategies Assessment (MSA) Report for the Reevaluated Seismic Hazard Information - NEI 12-06, Appendix H, Revision 2, H.4.4 Path 4: GMRS < 2xSSE, (ADAMS Accession No. ML17233A167), dated August 10, 2017.

50. NRC Letter to Duke Energy Carolinas, LLC, McGuire Nuclear Station, Units 1 and 2 - Staff Review of Mitigating Strategies Assessment Report of the Impact of the Re-Evaluated Seismic Hazard Developed in Response to the March 12, 2012, 50.54(f) Letter, (ADAMS Accession No. ML17349A991), dated December 21, 2017.

51. NRC Letter to Duke Energy Carolinas, LLC, McGuire Nuclear Station, Units 1 and 2 - Staff Review of Interim Evaluation Associated with Reevaluated Seismic Hazard Implementing Near-Term Task Force Recommendation 2.1, (ADAMS Accession No. ML16072A038),

dated March 17, 2016.

52. NRC letter to Exelon Generation Company, LLC, Lasalle County Station, Unit Nos. 1 And 2 - Issuance of Amendment Nos. 249 And 235 Related to Application to Adopt 10 CFR 50.69, Risk-Informed Categorization and Treatment of Structures, Systems, and Components for Nuclear Power Reactors, dated May 27, 2021 (ADAMS Accession No. ML21082A422).

53. NEI 05-04 Revision 3, Process for Performing Internal Events Peer Reviews Using the ASME/ANS PRA Standard, November 2009.

U.S. Nuclear Regulatory Commission Page 34 RA-23-0279

54. NEI 17-07 Revision 2, Performance of PRA Peer Reviews Using the ASME/ANS PRA Standard, August 2019.

55. NEI 07-12 Revision 0, Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines," Nuclear Energy Institute, November 2008.

56. NEI 07-12 Revision 1, Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines," Nuclear Energy Institute, June 2010.

57. Electric Power Research Institute (EPRI) 3002012988, Alternative Approaches for Addressing Seismic Risk in 10 CFR 50.69 Risk-Informed Categorization, July 2018.

58. NRC Letter to Exelon Generation Company, LLC, Calvert Cliffs Nuclear Power Plant, Units 1 and 2 - Issuance of Amendment Nos. 332 and 310 Re: Risk-Informed Categorization and Treatment of Structures, Systems, and Components for Nuclear Power Reactors (EPID L-2018-LLA-0482)," February 28, 2020. (ADAMS Accession No. ML19330D909)

59. Exelon Generation Company, LLC Letter to NRC, Response to Request for Additional Information Regarding License Amendment Requests to Adopt TSTF-505, Revision 2, and 10 CFR 50.69, November 24, 2020. (ADAMS Accession No. ML20329A433).

60. ASME/ANS RA-Sb-2013, "Addenda to ASME/ANS RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," American Society of Mechanical Engineers, New York, NY, September 2013.

U.S. Nuclear Regulatory Commission RA-23-0279 ATTACHMENT 1 LIST OF CATEGORIZATION PREREQUISITES

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U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 Duke Energy will establish procedure(s) prior to the use of the categorization process on a plant system. The procedure(s) will contain the elements/steps listed below.

x Integrated Decision-Making Panel (IDP) member qualification requirements.

x Qualitative assessment of system functions. System functions are qualitatively categorized as preliminary High Safety Significant (HSS) or Low Safety Significant (LSS) based on the seven criteria in Section 9 of NEI 00-04 (see Section 3.1 of the enclosure for this license amendment request). Any component supporting an HSS function is categorized as preliminary HSS. Components supporting, an LSS function are categorized as preliminary LSS.

x Component safety significance assessment. Safety significance of active components is assessed through a combination of Probabilistic Risk Assessment (PRA) and non-PRA methods, covering all hazards. Safety significance of passive components is assessed using a methodology for passive components.

x Assessment of defense-in-depth (DID) and safety margin. Safety-related components that are categorized as preliminary LSS are evaluated for their role in providing DID and safety margin and, if appropriate, upgraded to HSS.

x Review by the IDP. The categorization results are presented to the IDP for review and approval. The IDP reviews the categorization results and makes the final determination on the safety significance of system functions and components.

x Risk sensitivity study. For PRA-modeled components, an overall risk sensitivity study is used to confirm that the population of preliminary LSS components results in acceptably small increases to core damage frequency (CDF) and large early release frequency (LERF) and meets the acceptance guidelines of Regulatory Guide 1.174.

x Periodic reviews are performed to ensure continued categorization validity and acceptable performance for those SSCs that have been categorized.

x Documentation requirements per Section 3.1.1 of the enclosure.

U.S. Nuclear Regulatory Commission RA-23-0279 ATTACHMENT 2 DESCRIPTION OF PRA MODELS USED IN CATEGORIZATION

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U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 Unit 1 CDF & LERF Baseline CDF Baseline LERF Source Contribution Source Contribution Internal Events Internal Events 3.14E-06 3.96E-07 PRA PRA Internal Internal 4.86E-06 5.89E-07 Flooding PRA Flooding PRA Fire PRA 3.37E-05 Fire PRA 5.12E-06 High Winds High Winds 3.02E-06 1.12E-07 PRA PRA Total CDF 4.47E-05 Total LERF 6.22E-06 Unit 2 CDF & LERF Baseline CDF Baseline LERF Source Contribution Source Contribution Internal Events Internal Events 3.16E-06 4.20E-07 PRA PRA Internal Internal 6.38E-06 6.17E-07 Flooding PRA Flooding PRA Fire PRA 4.06E-05 Fire PRA 5.01E-06 High Winds High Winds 3.13E-06 1.08E-07 PRA PRA Total CDF 5.33E-05 Total LERF 6.16E-06

U.S. Nuclear Regulatory Commission Page 2 RA-23-0279 ATTACHMENT 3 DISPOSITION AND RESOLUTION OF OPEN PEER REVIEW FINDINGS AND SELF-ASSESSMENT OPEN ITEMS

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U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 The McGuire Nuclear Station (MNS), Units 1 and 2 Internal Events, Internal Flood, Fire, and High Winds PRA models have zero open finding level Facts and Observations (F&Os). As such, Attachment 3 is not applicable to MNS.

U.S. Nuclear Regulatory Commission RA-23-0279 ATTACHMENT 4 EXTERNAL HAZARDS SCREENING

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U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the IPEEE (Reference 1), an assessment of aircraft impact risk was performed with the total crash probability listed as 1.3E-08/yr.

The assessment was updated using recent air traffic data using the guidance provided in NUREG 0800 Section 3.5.1.6 (Reference 2). The primary change that has occurred since the conduct of the IPEEE analyses is the increase in air traffic, particularly commercial air traffic that uses the Charlotte-Douglas International Airport Aircraft Impact Y PS4 (CLT).

The analysis resulted in an updated value of the annual probability of an aircraft crash onto the MNS site of 3.2E-8, which is a factor of 3 below the risk criteria specified in the SRP for probability of aircraft accidents that could result in releases that exceed 10 CFR 100 limits of less than 1E-7 per year. Additionally, the crash frequency is much less than the CDF screening criteria of 1E-6 per year (PS4).

Based on this review, the Aircraft Impact hazard is considered to be negligible.

Per the IPEEE (Reference 1), there are no mountains in the vicinity of McGuire from which a significant avalanche could Avalanche Y C3 be generated.

Based on this review, the Avalanche hazard is considered to be negligible.

This hazard is slow to develop and can Biological Events Y C5 be identified via monitoring and

U.S. Nuclear Regulatory Commission Page 2 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 managed via standard maintenance process. Actions committed to and completed by MNS in response to Generic Letter 89-13 provide on-going control of biological hazards. These include performance of periodic maintenance work orders to inspect the intake structures, perform flow balance/testing, periodic flushing, and heat exchanger cleaning.

Based on this review, the Biological Events hazard is considered to be negligible.

Per the IPEEE (Reference 1), McGuire is located more than 150 miles from the nearest coastal area. However, to protect the lake edge from erosion, the yard areas subjected to waves are protected by riprap underlain by a thick Coastal Erosion Y C1 subgrade of filter material. Therefore, lake edge erosion will not be a significant problem.

Based on this review, the Coastal Erosion hazard is considered to be negligible.

Drought is a slowly developing hazard allowing time for orderly plant reductions, including shutdowns.

Drought Y C1 Based on this review, the Drought hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 3 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the Flood Hazard Reevaluation Report (FHRR - Reference 4), external flooding mechanisms exceeding the Current Design Basis (CDB) that could pose a potential challenge to MNS key safety functions were:

• Local Intense Precipitation (LIP)

• Flooding in Streams and Rivers (referred to as Flooding in Reservoirs in MNS FHRR)

• Failure of Dams

• Probable Maximum Storm Surge and Seiche/Wind Wave Runup To mitigate worst case flood scenarios for mechanisms other than LIP C1 (henceforth referred to as Combined External Flood Y Effects (CE) flooding), permanent C5 concrete protective barriers on the north embankment were installed to raise the flood protection levels at the site to 779 ft. This prevents water from the CE flood encroaching on the Auxiliary Building (AB) and site grade. This modification is permanent, passive protection that does not require any human actions to keep the site dry.

There is 0.46 ft of available physical margin (APM) present with the barriers installed.

The LIP flood causing mechanism produces a maximum water surface elevation of 761.1 ft (1.1 ft of standing water for 2.5 hrs) around the AB which

U.S. Nuclear Regulatory Commission Page 4 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 houses all SSCs related to maintaining key safety functions. For this LIP flood mechanism, site procedures require installation of temporary, engineered flood barriers at several locations around the AB.

The site begins preparations to install the flood barriers approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before the arrival of the storm.

The barriers are engineered for rapid deployment and ample recovery time is available should troubleshooting or reinstallation be required. The barriers are rated to protect AB doors from 30 (2.5 ft) of water and only 0.6 ft of water has been postulated due to a LIP event.

With the barriers in place, all SSCs related to KSFs are maintained free from flood waters throughout the event with adequate available physical margin.

The flood protection door barriers will be categorized as high safety significant (HSS) should categorization of the system be completed.

Based on this review, the External Flood hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 5 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 The McGuire High Winds PRA model Extreme Winds addresses risk from extreme winds and N/A N/A tornadoes.

and Tornadoes Per the IPEEE (Reference 1), accident data involving surface vehicles or aircraft would include the effects of fog.

Per the UFSAR Section 2.3.2.3 (Reference 5), consideration has been given to possible environmental effects associated with heat dissipation from Fog Y C1 the cooling pond (Lake Norman, vicinity of McGuire Nuclear Station). A review of the literature and operating experience to date would suggest that effects of fogging and icing are minimal for the properly designed cooling pond.

Based on this review, the Fog hazard is considered to be negligible.

Per the IPEEE (Reference 1), bush and local forest fires are handled by the local fire department. Such fires are not considered to have any impact on the Forest Fire Y C1 station because the site is cleared and the fire cannot propagate to station buildings or equipment.

U.S. Nuclear Regulatory Commission Page 6 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the UFSAR Section 2.2.3 (Reference 5), the only potential fire hazard in the plant vicinity is a brush fire. The plant fire protection system is adequate to prevent any possible damage from a fire due to this origin.

Based on this review, the Forest Fire hazard is considered to be negligible.

Per the IPEEE (Reference 1), both the Reactor Building and the Auxiliary Building are designed for a combination Frost Y C1 of snow, ice, and rain.

Based on this review, the Frost hazard is considered to be negligible.

Per the IPEEE (Reference 1), both the Reactor Building and the Auxiliary Building are designed for a combination of snow, ice, and rain.

C1 In addition, the principal effects of such Hail Y events would be to cause a loss of off-C4 site power, which is addressed for weather-related LOOP scenarios in the FPIE PRA model for McGuire.

Based on this review, the Hail hazard is considered to be negligible.

Per the IPEEE (Reference 1), the effect of high summer temperatures at C1 High Summer McGuire is insignificant because there Y

Temperature are upstream dams that provide water C4 level control on Lake Norman.

U.S. Nuclear Regulatory Commission Page 7 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Technical Specification Surveillance Requirement (SR) 3.7.8.2 verifies that the Nuclear Service Water System is available to cool the CCW System to at least its maximum design temperature with the maximum accident or normal design heat loads for 30 days following a Design Basis Accident. The SR verifies that the average water temperature of the Standby Nuclear Service Water Pond is 82°F at an elevation of 722 ft (level must be 739.5 ft per SR 3.7.8.1) else the plant be shut down.

The SR is modified by a Note that states the Surveillance is only required to be performed during the months of July, August, and September. During other months, the ambient temperature is below the surveillance limit.

In addition, the principal effects of such events would be to cause a loss of off-site power, which is addressed for weather-related LOOP scenarios in the FPIE PRA model for McGuire.

Based on this review, the High Summer Temperature hazard is considered to be negligible.

Per the IPEEE (Reference 1), McGuire is located more than 150 miles from the High Tide Y C4 nearest coastal area.

U.S. Nuclear Regulatory Commission Page 8 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the High Tide hazard is considered to be negligible.

See Extreme Winds or Tornados and External Flood / Intense Precipitation.

External Flood effects from hurricanes Hurricane are accounted for in the Combined Y C4 (Tropical Cyclone) Effects (CE) hazard analysis.

Based on this review, the Hurricane (Tropical Cyclone) hazard is considered to be negligible.

Per the IPEEE (Reference 1), Both the Reactor Building and the Auxiliary Building are designed for ice.

Per UFSAR (Reference 5) Section 2.4.7, ice flooding is not applicable to C1 the site area.

Ice Cover Y C4 In addition, the principal effects of such events would be to cause a loss of off-site power, which is addressed for weather-related LOOP scenarios in the FPIE PRA model for McGuire.

Based on this review, the Ice Cover hazard is considered to be negligible.

Per the IPEEE (Reference 1), there are no military or industrial facilities within a Industrial or C1 5-mile radius of the plant.

Military Facility Y Accident C3 Per UFSAR Section 2.2 (Reference 5),

military and transportation facilities are nearly non-existent and only a few

U.S. Nuclear Regulatory Commission Page 9 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 industrial facilities are located in the vicinity of McGuire. The few facilities that do exist have no effect on the McGuire Nuclear Station nor will McGuire Nuclear Station have any effect on the existing facilities.

Based on this review, the Industrial or Military Facility Accident hazard is considered to be negligible.

The McGuire Internal Events and Internal Flood N/A N/A Internal Flood PRA model addresses risk from internal flood events.

Internal Fire N/A N/A The McGuire Internal Fire PRA model addresses risk from internal fires.

Per the IPEEE (Reference 1), landslides are considered an insignificant hazard at McGuire. The Standby Nuclear Service Water Pond (SNSWP) dam is the only natural or man made slope which, upon Landslide Y C1 failure, would prevent safe shutdown of the plant. Therefore, the SNSWP was statically designed for stability under all loading conditions Based on this review, the Landslide hazard is considered to be negligible.

Per the IPEEE (Reference 1), the most probable effect of lightning is the loss of off-site power due to a strike in the Lightning Y C4 switchyard. These occurrences are accounted for in the loss of off-site power initiating event frequency.

U.S. Nuclear Regulatory Commission Page 10 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the Lightning hazard is considered to be negligible.

Per the IPEEE (Reference 1), the effect of low lake level, or low river water level at McGuire is insignificant because there are upstream dams that provide water level control on Lake Norman.

Due to normal regulation of lake level Low Lake or River and the extended time available before Y C1 Water Level minimum water level, sufficient time would be available to respond to this hazard.

Based on this review, the Low Lake or River Water Level hazard is considered to be negligible.

Per the IPEEE (Reference 1), the Reactor Building and the Auxiliary Building are designed for a combination of snow and ice. These hazards are commensurate with low winter C1 temperatures.

Low Winter Y

Temperature In addition, low winter temperatures C4 causing failure of instruments are included in the plant trip frequency data.

Based on this review, the Low Winter Temperature hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 11 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the IPEEE (Reference 1), this event has significantly lower frequency than other events with similar uncertainties.

The frequency of a meteor or satellite strike is judged to be so low as to make Meteorite/Satellite Y PS4 the risk impact from such events Strikes insignificant.

Based on this review, the Meteorite/Satellite Strikes hazard is considered to be negligible.

Per the IPEEE (Reference 1), gas pipeline maps of the area around the McGuire plant site were reviewed and indicated that there were no changes to the original PRA screening information as contained in the FSAR.

Per the FSAR Section 2.2.3 (Reference 5), there are two gas pipelines: one 36-inch diameter and one 42-inch diameter located one mile south of the plant. The Pipeline Accident Y C3 consequences a rupture of the 42-inch gas pipeline rupture was evaluated.

The evaluation included the potential effects of the gas at the plant, an unconfined in-air explosion, and surface blast at the point of rupture.

The evaluation found the effects of gas at the plant were well below the flammability threshold. The unconfined in-air explosion and surface blast effects only resulted in a worst-case

U.S. Nuclear Regulatory Commission Page 12 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 overpressure of 1.3 to 1.8 psi at the plant, which is considered minor.

Based on this review, the Pipeline Accident hazard is considered to be negligible.

This hazard is discussed under External Flooding.

Precipitation, See External Flood.

Y C1 Intense Based on this review, the Intense Precipitation hazard is considered to be negligible.

Per the IPEEE (Reference 1), potential hazards from the storage of toxic material on-site is minimal.

The FSAR Section 2.1.4 (Reference 5) states that no large quantities of caustic or flammable material will be stored on site.

Release of MNS updated its Toxic Gas evaluation Chemicals from Y C1 in July 2022 (Reference 6) to evaluate Onsite Storage onsite and offsite chemical hazards in accordance with Regulatory Guide 1.78, Rev. 1 (Reference 7).

The evaluation considered potential onsite and offsite stationary and mobile hazardous chemical sources that could pose a threat to control room habitability upon release within 5 miles of MNS.

U.S. Nuclear Regulatory Commission Page 13 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 The evaluation concluded that there are no toxic gas hazardous chemical threats to control room habitability.

Based on this review, the Release of Chemicals from Onsite Storage hazard is considered to be negligible.

Per the IPEEE (Reference 1), no present means exist to divert or reroute the river flow through the dams other than insignificant amounts of water used for municipal supply.

Per UFSAR Section 2.4.9 (Reference 5), there are five reservoirs on the Catawba River upstream of Cowans Ford Dam, all of which have operating hydroelectric power plants located on River Diversion Y C1 them. Since Duke owns and controls the levels of each reservoir above the site of McGuire Nuclear Station, any upstream diversion or rerouting of the source of cooling water is very unlikely to happen. No present means exist to divert or reroute other than minor amounts used for municipal water supply.

Based on this review, the River Diversion hazard is considered to be negligible.

Per the IPEEE (Reference 1), McGuire Sandstorm Y C1 is located more than 150 miles from the nearest area with a large sand deposit.

U.S. Nuclear Regulatory Commission Page 14 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 The likelihood of occurrence is insignificant.

Based on this review, the Sandstorm hazard is considered to be negligible.

Per FSAR Section 2.4.5.2 (Reference 5), Lake Norman, immediately north of the plant, is a relatively new inland lake with no history of surge or seiche Flood.

Seiche Y C1 The Seiche hazard is accounted for in the Combined Effects (CE) hazard analysis for External Flood.

Based on this review, the Seiche hazard is considered to be negligible.

MNS is an EPRI Tier 2 Plant as defined Seismic Activity N/A N/A by Reference 8. See Section 3.2.3 of this LAR.

Per the IPEEE (Reference 1), both the Reactor Building and the Auxiliary Snow Y C1 Building are designed for snow.

Based on this review, the Snow hazard is considered to be negligible.

Per FSAR Section 2.5 (Reference 5),

extensive investigations on soil and rock samples found that subsurface conditions of the site have no adverse Soil Shrink-Swell Y C1 impact on the design, construction, or operation of the station.

Based on this review, the Soil Shrink-Swell hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 15 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 The Storm Surge hazard is accounted for in the Combined Effects (CE) hazard Storm Surge Y C1 analysis for External Flood.

Based on this review, the Storm Surge hazard is considered to be negligible.

Per the IPEEE (Reference 1), leaks from containers of chlorine (used for drinking water purification and sanitary waste treatment) and other potential toxic gas sources were evaluated which found that it is unlikely that leaks from these containers would result in dangerous concentrations in the Control Room.

MNS updated its Toxic Gas evaluation in July 2022 (Reference 6) to evaluate onsite and offsite chemical hazards in accordance with Regulatory Guide 1.78, Toxic Gas Y C1 Rev. 1 (Reference 7).

The evaluation considered potential onsite and offsite stationary and mobile hazardous chemical sources that could pose a threat to control room habitability upon release within 5 miles of MNS.

The evaluation concluded that there are no toxic gas hazardous chemical threats to control room habitability.

See also Release of Chemicals from Onsite Storage.

Based on this review, the Toxic Gas hazard is considered to be negligible.

U.S. Nuclear Regulatory Commission Page 16 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Per the IPEEE (Reference 1), there are no industries within 5 miles of McGuire which transport or store products harmful to the station.

Per FSAR Section 2.2.2 (Reference 5),

the major transportation corridors within 5 miles of the site N.C. 16, located approximately three miles west of the site and I-77 located approximately five miles east of the site. N.C. 73, located approximately 0.4 miles south of the site, is primarily used by local residents, commuters, and for recreational access to Lake Norman. There are no Transportation manufacturers or suppliers of hazardous Y C3 Accidents materials within 10 miles of the site.

The shipment of hazardous materials is regulated by the U.S. Department of Transportation (USDOT). Based on the USDOT regulations and the proximity of alternate major high-speed highways bypassing the site, the probability of MNS being affected by shipment of hazardous materials is insignificant.

See also Toxic Gas.

Based on this review, the Transportation Accidents hazard is considered to be negligible.

Per the IPEEE (Reference 1), McGuire Tsunami Y C3 is located more than 150 miles from the nearest coastal area at an elevation of

U.S. Nuclear Regulatory Commission Page 17 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 760 ft. mean sea level. Therefore, tsunami effects are insignificant.

See also External Flood.

Based on this review, the Tsunami hazard is considered to be negligible.

Per the IPEEE (Reference 1), the majority of the structures at MNS are located either along or within close proximity to the longitudinal centerlines of the respective turbines. Calculations on turbine missiles prepared for MNS indicate that the contribution to plant risk from the turbines would be insignificant.

FSAR Sections 3.5.2.2 and 10.2.3 describe how the orientation of the turbine and the fact that all Category 1 structures, with the exception of the Turbine-Generated New Fuel Storage Vault exposed to this Y C4 Missiles hazard, are designed to withstand low-trajectory turbine missiles and meet Regulatory Guide 1.115, Rev. 1 (Reference 10). This provides additional assurance that safety-related structures and components will not be affected in the extremely unlikely event a turbine missile is generated.

FSAR Section 10.2.3 also notes that the low-pressure turbine rotors have been replaced with FI (Fully Integral) rotors which further reduce the probability of turbine missile generation.

U.S. Nuclear Regulatory Commission Page 18 RA-23-0279 Screening Result1,3 External Hazard Screened? Screening Comment (Y/N) Criterion2 Based on this review, the Turbine-Generated Missiles hazard is considered to be negligible.

Per the IPEEE (Reference 1), no active volcanoes exist within the vicinity of McGuire.

Volcanic Activity Y C3 Based on this review, the Volcanic Activity hazard is considered to be negligible.

The Waves hazard is accounted for in the Combined Effects (CE) hazard Waves Y C1 analysis for External Flood.

Based on this review, the Waves hazard is considered to be negligible.

1 The list of hazards and their potential impacts considered those items listed in Tables D-1 and D-2 in Appendix D of RG 1.200, Rev. 3 (Reference 12).

2 See Attachment 5 for descriptions of the screening criteria.

3 A separate list of references is provided for Attachment 4. References

1. Duke Power letter to NRC, McGuire Nuclear Station, Units 1 and 2, Individual Plant Examination of External Events (IPEEE) Submittal, letter dated June 1, 1994 (ADAMS Accession No. ML9406140331).

2. NUREG-0800, "Standard Review Plan (SRP) for the Review of Safety Analysis Reports for Nuclear Power Plants," Section 3.5.1.6, "Aircraft Hazards," Revision 4, March 2010.

3. [Not used]

U.S. Nuclear Regulatory Commission Page 19 RA-23-0279

4. Duke Energy Letter to the NRC, Flood Hazard Reevaluation Report, Response to NRC Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f)

Regarding Recommendations 2.1, 2.3 and 9.3 of Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, Dated March 12, 2012," (ADAMS Accession No. ML14083A415), dated March 12, 2014.

5. McGuire Nuclear Station Updated Final Safety Analysis Report (UFSAR), April 2020 (ADAMS Accession No. ML20282A521).

6. Calculation MCC-1211.00-00-0141, " Control Room Habitability Toxic Gas Review," Rev. 4, July 2022.

7. Regulatory Guide (RG) 1.78, "Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release," Revision 1, (ADAMS Accession No. ML013100014), December 2001.

8. Electric Power Research Institute (EPRI) 3002017583, Alternative Approaches for Addressing Seismic Risk in 10 CFR 50.69 Risk-Informed Categorization, February 2020 (ADAMS Accession No. ML21082A170).

9. Generic Letter 88-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f), Supplement 4," USNRC, June 1991.

10. RG 1.115, "Protection Against Low Trajectory Turbine Missiles," U.S. Nuclear Regulatory Commission, Revision 1, July 1977 (ADAMS Accession No. ML003739456).

11. Duke Energy Letter to NRC, "Seismic Hazard and Screening Report (CEUS Sites),

Response to NRC 10 CFR 50.54(f) Request for Information Pursuant to Title 10 of the Code of Federal Regulations Section CFR 50.54(f) regarding Recommendations 2.1, 2.3 and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident,"

(ADAMS Accession No. ML14098A421), dated March 20, 2014.

12. RG 1.200, "Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 3, December 2020 (ADAMS Accession No. ML20238B871).

U.S. Nuclear Regulatory Commission Page 20 RA-23-0279 ATTACHMENT 5 PROGRESSIVE SCREENING APPROACH FOR ADDRESSING EXTERNAL HAZARDS

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U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 Event Analysis Criterion Source Comments NUREG/CR-2300 C1. Event damage potential and ASME/ANS is < events for which plant is Standard RA-Sa-designed.

2009 C2. Event has lower mean NUREG/CR-2300 frequency and no worse and ASME/ANS Initial Preliminary consequences than other Standard RA-Sa-Screening events analyzed. 2009 NUREG/CR-2300 C3. Event cannot occur and ASME/ANS close enough to the plant to Standard RA-Sa-affect it.

2009 NUREG/CR-2300 Not used to C4. Event is included in the and ASME/ANS screen. Used only definition of another event. Standard RA-Sa- to include within 2009 another event.

C5. Event develops slowly, allowing adequate time to ASME/ANS eliminate or mitigate the Standard threat.

PS1. Design basis hazard ASME/ANS cannot cause a core damage Standard RA-Sa-accident. 2009 PS2. Design basis for the NUREG-1407 and event meets the criteria in ASME/ANS the NRC 1975 Standard Standard RA-Sa-Progressive Review Plan (SRP). 2009 Screening PS3. Design basis event NUREG-1407 as mean frequency is < 1E-5/y modified in and the mean conditional ASME/ANS core damage probability is < Standard RA-Sa-0.1. 2009 NUREG-1407 and PS4. Bounding mean CDF is ASME/ANS

< 1E-6/y. Standard RA-Sa-2009

U.S. Nuclear Regulatory Commission Page 2 RA-23-0279 Event Analysis Criterion Source Comments Screening not successful. NUREG-1407 and PRA needs to meet ASME/ANS Detailed PRA requirements in the Standard RA-Sa-ASME/ANS PRA Standard. 2009

U.S. Nuclear Regulatory Commission RA-23-0279 ATTACHMENT 6 DISPOSITION OF KEY ASSUMPTIONS/SOURCES OF UNCERTAINTY

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U.S. Nuclear Regulatory Commission Page 1 RA-23-0279 Assumption/ Uncertainty Discussion Disposition Safety Injection (NI) pump miniflow Not modeling the NI pump miniflow line may A sensitivity was performed increasing the NI lines are assumed not necessary for underestimate the risk in sequences in which pump failure rate to a large bounding value to pump start success reactor pressure is above the pump shutoff represent inclusion of the miniflow line head. This situation could occur during a components. Importance measures were small LOCA, for which the charging pumps evaluated across all initiators and scenarios.

initially operate. Loss of the NI pump No basic events increased from LSS in the miniflow could potentially damage the NI base case to HSS in the sensitivity case.

pump. If subsequently the charging pumps were to fail, all high-pressure injection would As such, this sensitivity study shows 10 CFR be lost. This failure scenario requires at least 50.69 categorization is not sensitive to this two failures (charging pumps and NI pump uncertainty.

miniflow, randomly or hazard-induced).

U.S. Nuclear Regulatory Commission RA-23-0279 ATTACHMENT 7 MARKUP OF MCGUIRE, UNITS 1 AND 2 RENEWED FACILITY OPERATING LICENSES

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U.S. Nuclear Regulatory Commission RA-23-0279 A revised markup of the MNS, Units 1 and 2 Facility Operating Licenses to reflect the proposed change for 10 CFR 50.69 is provided as Attachment 4 of Duke Energy letter RA-23-0279.





























































































U.S. Nuclear Regulatory Commission RA-23-0279 Attachment 4 ATTACHMENT 4 MARK-UP OF MCGUIRE, UNITS 1 AND 2 RENEWED FACILITY OPERATING LICENSES

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Add 2 new rows to Appendix B table.

First new row: add "10 CFR 50.69 License Condition INSERT" Second new row: add "TSTF-505 License Condition INSERT"

Add 2 new rows to Appendix B table.

First new row: add "10 CFR 50.69 License Condition INSERT" Second new row: add "TSTF-505 License Condition INSERT"

10CFR50.69LicenseConditionINSERT

[XXX] Duke Energy is approved to implement 10 CFR 50.69 Upon implementation using the processes for categorization of Risk- of Amendment No.

Informed Safety Class (RISC)-1, RISC-2, RISC3, and [XXX]

RISC-4 structures, systems, and components (SSCs) using: Probabilistic Risk Assessment (PRA) models to evaluate risk associated with internal events, including internal flooding, internal fire, and high winds; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2, Class 3, and non-class SSCs and their associated supports; the results of non-PRA evaluations that are based on the IPEEE Screening Assessment for External Hazards updated using the external hazard screening significance process identified in the ASME/ANS PRA Standard RA-Sa-2009 for other external hazards except seismic, and the alternative seismic approach described in Duke Energys submittal letter RA 0090 dated February 17, 2023; as specified in License Amendment No. [XXX] dated [DATE].

Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from a seismic margins approach to a seismic probabilistic risk assessment approach).





































TSTF505LicenseConditionINSERT

[XXX] For the Risk-Informed Completion Time (RICT) Upon implementation calculations within the Risk-Informed Completion Time of Amendment No.

Program, a singular approach for the high winds [XXX]

external hazard will be specified and utilized for a given RICT. Either a high winds penalty or a high winds probabilistic risk assessment (PRA) will be utilized in the RICT Program calculations. A high winds PRA and high winds penalty shall not be used simultaneously to determine RICTs within the RICT Program.