ML13039A200

Enclosures 1 & 2 to L-MT-12-114 - Responses to the Gap Analysis and Marked Up Page Changes to EPU Documentation Based on the Gap Analysis Results, Part 1 of 3

ML13039A200
Person / Time
Site:	Monticello
Issue date:	01/21/2013
From:	Xcel Energy, Northern States Power Co
To:	Office of Nuclear Reactor Regulation
References
L-MT-12-114, TAC MD9990
Download: ML13039A200 (126)

Text

L-MT-12-114 Enclosure 1 ENCLOSURE 1 RESPONSES TO THE GAP ANALYSIS Introduction On November 20, 2012, Northern States Power -Minnesota (NSPM) presented to the NRC the results of a Gap Analysis performed to verify the adequacy of the extended power uprate (EPU) documentation.

Due to the delay in review of the Monticello Nuclear Generating Plant (MNGP) EPU License Amendment Request (LAR), the NRC was concerned that various aspects of the NRC review were no longer applicable.

Through the Gap Analysis, NSPM demonstrated that various technical items required revision and some design and licensing bases information had changed, but overall the body of EPU documentation was correct with the exception of the issues identified for correction.

As part of that discussion, NSPM provided the NRC with a table of items that had changed in the EPU documentation.

This table was discussed and NRC provided their comments on the documentation needed to close the items.This enclosure contains a brief synopsis of each item discussed in the Gap Analysis, the information the NRC needed to close the gap (from the November 20, 2012 meeting with NRC), and the NSPM response to the identified gap.Page 1 of 80 L-MT-12-114 Enclosure 1 Contents Provided below are responses to the following items from the Gap Analysis: Item 1 -Grid Stability Assessment Item 2 -Battery Capacity Changes Item 3 -Changes to Setpoint Calculations Item 4 -Steam Dryer Noise Filtering and Noise Reduction Item 5 -Reactor Water Cleanup Impact on Reactor Water Quality Item 6 -Noble Metals Modification Item 7 -Unnecessary Abnormal Operating Procedure (AOP) Change Item 8 -Emergency Core Cooling System (ECCS) Pump Flow Rates Item 9 -Residual Heat Removal and Core Spray Pump Rooms Post-Loss of Coolant Accident (LOCA) Heatup Item 10 -Final Feedwater Temperature Change Item 11 -Piping Components Requiring Further Analysis Item 12 -Technical Support Center (TSC) Dose Calculation Item 13 -Risk Assessment Item 14 -Computer Code Changes Item 15 -Turbine Bypass Valve Capacity Item 16 -Reactor Head Spray Nozzle Fatigue Assessment Item 17 -Emergency Operating Procedure Flow Chart for ATWS Item 18 -Main Steam Line Thermowells Item 19 -EPU Modifications List Changes Item 20 -Annulus Pressure (AP) Loads Item 21 -Emergency Core Cooling System (ECCS) Analysis Confirmation Item 22 -Confirmation that Oscillation Power Range Monitor (OPRM) Testing is Completed Item 23 -Fatigue Monitoring Program Item 24 -Motor Operated Valve (MOV) Program Changes Item 25 -Shroud Screening Criteria Flaw Evaluation and Recirculation Line Break (RLB) Loads Item 26 -High Energy Line Break (HELB) Analysis Reconstitution Item 27 -Equipment Qualification Program Reconstitution Item 28 -Effects of Loss of Stator Water Cooling Analysis Page 2 of 80 L-MT-12-114 Enclosure 1 ITEM I -GRID STABILITY ASSESSMENT NRC REQUESTED INFORMATION:

Change MNGP substation figure to show new grid connections.

Send the figure and identify that Midwest Independent System Operator (MISO) has reconfirmed their original study is satisfactory based on CAPX2020.

NRC would like to see the MISO letter. State the effect on grid stability.

Include results of latest stability review -just reference the consultant's review.NSPM RESPONSE: Since submittal of the original stability study in L-MT-08-052 (Reference 1-1), Enclosure 14, an additional 345 KV line has been added to the MNGP substation which increased the number of transmission lines from 5 to 6 connecting to this substation.

This included an upgrade of the 345 KV bus from a ring bus to a breaker-and-one-half system (USAR Section 8.2.1).The power increase related to the EPU project was originally planned in two phases in 2009 and 2011. EPU is currently planned to be implemented following the 2013 outage.Midwest Independent Transmission System Operator, Inc. (MISO) has approved the full power increase in a signed Interconnection Agreement (IA) as executed in MISO Projects (G725 13MWe and G929 60.8MWe) on October 6, 2009.The Large Generator Interconnection Agreement (LGIA) did not identify the need for any additional interconnection, or system protection facilities, or require any distribution, generator, or network upgrades.On February 22, 2011, Xcel notified MISO ISO that the Commercial Operation Date (COD) for Monticello Projects G725 and G929 has been extended from May, 2011 to August 2013. This change notification was not considered a material change in accordance with Midwest ISO electric tariff and a LGIA restudy was not required.The evaluation, analysis, and IA in support of the MISO upgrades are documented in the following approved engineering evaluations:

By email dated September 24, 2012 from Vikram Godbole of MISO to various individuals, MISO reported the results of a restudy evaluation of projects with permanent Generator Interconnection Agreements (GIAs). The study included: 1. Stability Analysis 2. Network Resource Interconnection Service (NRIS) analysis 3. Project summary results.The MNGP EPU is covered by GIA G929. No adverse impacts were identified for this study.See Enclosure 2 for a markup of L-MT-08-052, Enclosure 14 reflecting these changes.Page 3 of 80 L-MT-12-114 Enclosure 1 See Enclosure 3 for latest version of NH-1 78635 -USAR Section 15 figure and the email from Vikram Godbole of MISO.References 1-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML091410120)

Page 4 of 80 L-MT-12-114 Enclosure 1 ITEM 2 -BATTERY CAPACITY CHANGES NRC REQUESTED INFORMATION:

Ongoing plant changes to battery loading including finalization of 13.8 KV design has changed the battery capacity values.Update battery load final margin results to NRC. Include a discussion about any changes to safety related (SR) loads such as emergency diesel generator (EDG).Identify which loads have changed and why, confirm that aging margin and temperature factors are included.NSPM RESPONSE: NSPM letters L-MT-08-039 and L-MT-09-043 (References 2-1 and 2-2) provided preliminary information regarding MNGP battery capacity and loading based on the planned changes associated with EPU. NSPM is providing final MNGP battery capacity values and analyses based on operation at EPU conditions.

Load changes within the Safety Related Direct Current (DC) Onsite Power System remain bounded by the capacity of the existing station batteries.

Cell sizing evaluations for revised system configurations confirm positive capacity margin remains for the analyzed scenarios following implementation of plant changes during the EPU outage.The final cell sizing margin for the safety related batteries is summarized in Table 2-1 below.Table 2-1 Final Battery Cell Sizing Margins Essential Battery CLTP EPU Capacity Margin Capacity Margin 125 VDC Division I 15.83% 9.29%250 VDC Division I 23.63% 20.64%125 VDC Division II 26.58% 8.11%250 VDC Division II 2.04% 22.81%Cell sizing evaluations performed for post-EPU conditions do not modify Aging Factors or Temperature Correction Factors used in the Current Licensed Thermal Power (CLTP) analyses.

For Safety Related 125 VDC and 250 VDC station batteries, the minimum electrolyte temperature is taken as 60F and a corresponding 1.11 Temperature Correction Factor is used following the guidance of IEEE Std. 485-1997,"IEEE Recommended Practice for Sizing Lead-Acid Batteries for Stationary Applications." A 1.11 Aging Factor is used corresponding to 90% manufacturer's rated capacity in agreement with the acceptance criterion of Monticello Technical Specifications Surveillance Requirement SR 3.8.6.6.No Safety Related 250 VDC load changes were implemented under EPU, although the High Pressure Coolant Injection (HPCI) Station Blackout (SBO) operating sequence was revised (Reference 2-3, Enclosure 5, Sections 2.3.4 and 2.3.5) for EPU conditions.

Page 5 of 80 L-MT-12-114 Enclosure 1 Improvements in 250 VDC Division II battery margin are not due to EPU changes, but rather load timing changes implemented under a separate battery capacity margin management modification.

Minor load changes were incorporated in the Safety Related 125 VDC calculations for new equipment associated with the replacement Generator Step Up transformer, replacement 1 R transformer, replacement 2R transformer, Main Generator Rewind and the new 13.8 kV non-safety related switchgear.

NRC REQUESTED INFORMATION:

Staff requests a detailed discussion of the changes to electrical equipment loading and capacities since the last submittal, including emergency diesel generators.

NSPM RESPONSE: Modifications to the 1 R and 2R offsite power transformers were in the conceptual stage when Reference 2-1 was submitted to the NRC. These designs have been finalized with new equipment ratings listed below. As discussed in Reference 2-1, the existing non-safety related #11 and #12 buses will be replaced with new buses rated for operation at 13.8kV. Table 2-2 identifies the new AC electrical equipment provided for EPU. Table 2-2 also includes the new motor loads operating on the new buses.Table 2 -2 EPU Replaced Equipment Ratings Comparison Equipment CLTP EPU Rating Rating 1 R Transformer 22.400/29.867/37.333 MVA 40.5/54 MVA OA/FA/FA @ 65C Rise ONAN/ONAF

@ 65C Rise 115kV-4.16kV-4.16kV 115kV-13.8kV-4.16kV 2R Transformer 56 MVA 40.5/54 MVA FOA @ 65C Rise ONAN/ONAF

@ 65C Rise 34.5kV-4.16kV-4.16kV 34.5kV-13.8kV-4.16kV Non-Safety Related 2000 A Continuous 2000 A Continuous Switchgear

1. 11 4.76 kV 15 kV Non-Safety Related 2000 A Continuous 2000 A Continuous Switchgear

1. 12 4.76 kV 15 kV Feedwater Pump 6000 HP 8000 HP#11 and #12 4000 V 13200 V Condensate Pump 1750 HP 2400 HP#11 and #12 4000 V 13200 V Reactor Recirculation MG 4000 HP 4000 HP Set Drive Motor 4000 V 13200 V#11 and #12 Page 6 of 80 L-MT-12-114 Enclosure 1 Table 2-3 provides a comparison of the full steady state and largest accident loading.Table 2-3 AC Electrical Loading for Steady State and Accident Conditions Loading Condition Steady State Loading Percent of 1R or 2R EPU EPU Conditions Transformer ONAF* Rating Full Plant Load 36.9 MVA 68.3%LOCA Load 39.1 MVA 72.4%*ONAF is the ANSI/lEE Standard C57.12.00 defined 4 digit code describing the cooling attributes of a transformer.

There are no EPU changes to the ratings for safety-related loads. No increase in flow or pressure is required for any AC-powered Emergency Core Cooling System (ECCS)equipment for EPU. The EDG design basis loading is not affected by EPU (Reference 2-3, Enclosure 5, Section 2.3.3.)See Enclosure 2 for a markup of L-MT-08-039 and L-MT-08-043 reflecting the discussed changes.References 2-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate (USNRC TAC MD8398): Acceptance Review Supplemental Information," L-MT-08-039, dated May 28, 2008. (ADAMS Accession No. ML081490639) 2-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate (USNRC TAC MD8398): Acceptance Review Supplemental Information Package 6," L-MT-08-043, dated June 12, 2008.(ADAMS Accession No. ML081640435) 2-3 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML091410120)

Page 7 of 80 L-MT-12-114 Enclosure 1 ITEM 3 -CHANGES TO SETPOINT CALCULATIONS NRC REQUESTED INFORMATION:

Calculations provided to the NRC have changed.Briefly discuss previously provided calculations that have changed..

Describe the changes and conclusion that there are no technical changes. Specifically state that the values computed in the calculations and reported to NRC did not change.NSPM RESPONSE: NSPM letter L-MT-09-026 (Reference 3-1), Enclosure 1, provided a response to NRC RAI EICB RAI No. 1. In this response NSPM provided the following calculations:

CA-95-073 R4 -Reactor low water level Scram setpoint CA-95-075 R1 -MSL High flow trip setpoint CA-96-054 R5 -Turbine Stop Valve Closure/Generator Load Reject Scram Bypass NSPM's response to EICB RAI No. 1 in L-MT-09-026 indicates that the calculation revisions were performed to "support recent plant modifications and to improve the quality of the calculation by adding more detail...

These revisions have not changed the EPU values shown in Table 2.4-1." Note: Table 2.4-1 is a reference to the original EPU LAR analysis provided in L-MT-08-052 (Reference 3-2), Enclosure

5. These calculations were provided as part of the process of documenting changes to MNGP operating parameters resulting from changes from CLTP operation to EPU operations.

These calculations were revised after Reference 3-1 was submitted to the NRC.However, there were no changes to the EPU values reported in Reference 3-1. Only administrative changes to the calculations have occurred.

These administrative changes do not change or affect any setpoint values previously reported to the NRC.There are no proposed changes to EPU documentation resulting from this response.References 3-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Instrumentation

& Controls Branch Request for Additional Information (RAI dated March 11, 2009, and April 6, 2009, and Fire Protection Branch RAIs dated March 12, 2009 (TAC No. MD9990)," L-MT-09-026, dated May 13, 2009. (ADAMS Accession No. ML0832301 11)3-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML091410120)

Page 8 of 80 L-MT-12-114 Enclosure 1 ITEM 4 -STEAM DRYER NOISE FILTERING AND NOISE REDUCTION NRC REQUESTED INFORMATION:

Specific submittals contain information that has been superseded by the Replacement Steam Dryer (RSD). Update to supersede outdated information.

NSPM RESPONSE: In letter L-MT-09-043 (Reference 4-1) in response to NRC RAI EMCB-SD RAI No. 5, NSPM provided information to the NRC discussing the noise reduction techniques that were applied to the steam dryer data collected in support of qualification of the MNGP steam dryer at EPU conditions.

Subsequently, NSPM replaced the original MNGP steam dryer with a replacement steam dryer. Therefore, the information provided in response to EMCB-SD RAI No. 5 is no longer applicable to the MNGP EPU LAR. This information has now been superseded by information provided in L-MT-12-056 (Reference 4-2), Enclosure 2.In letter L-MT-09-043 (Reference 4-1) in response to NRC RAIs EMCB-SD RAI No. 6 and No. 7, NSPM provided information to the NRC discussing the noise filtering techniques that were applied to the steam dryer data collected in support of qualification of the MNGP steam dryer at EPU conditions.

Subsequently, NSPM replaced the original MNGP steam dryer with a replacement steam dryer. Therefore, the information provided in response to EMCB-SD RAIs No. 6 and No. 7 is no longer applicable to the MNGP EPU LAR. This information has now been superseded by information provided in L-MT-12-056 (Reference 4-2), Enclosure 2.See Enclosure 2 for a markup of the RAI responses reflecting these changes.References 4-1 Letter from T J O'Connor (NSPM) to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Mechanical and Civil Engineering Review Branch(EMCB)

Requests for Additional Information (RAIs) dated March 20, 2009, and June 26, 2009 (TAC No. MD9990)," L-MT-09-043, dated August 12, 2009. (ADAMS Accession No. ML092260436) 4-2 Letter from M A Schimmel (NSPM) to Document Control Desk (NRC), "Monticello Extended Power Uprate: Replacement Steam Dryer -Second Set of Responses to Requests for Additional Information (TAC MD9990)," L-MT-12-056, dated July 19, 2012. (ADAMS Accession No. ML12207A541)

Page 9 of 80 L-MT-12-114 Enclosure 1 ITEM 5 -REACTOR WATER CLEANUP IMPACT ON REACTOR WATER QUALITY NRC REQUESTED INFORMATION:

MNGP did not take any credit for increasing Reactor Water Cleanup (RWCU) capacity for assessment of impact on water quality. A modification has been completed to maintain RWCU flow capacity as a constant percent of feedwater (FW) flow. Summarize the changes in the analysis and demonstrate that what was submitted is conservative or the change is negligible.

NSPM RESPONSE: Current EPU Documentation In L-MT-08-052 (Reference 5-1), NSPM assessed impact on reactor water quality based on the installed RWCU pump capacity in 2008. This is demonstrated by the following from L-MT-08-052, Enclosure 5, Section 2.1.7: "RWCU flow is usually selected to be in the range of 0. 8% to 1.0% of FW flow based on operational history. The existing RWCU flow slightly exceeds this range (1.08%of FW flow). The RWCU flow analyzed for EPU is within this range... " The remaining portion of Section 2.1.7 demonstrated the adequacy of the proposed RWCU flow reduction impact on typical reactor water iron and conductivity changes.Previous operating experience had shown that the FW iron input to the reactor increases for EPU as a result of the increased FW flow. It was anticipated to raise the typical reactor water iron concentration from < 1.7 ppb to < 2.0 ppb. However, this change was considered insignificant, and did not affect RWCU performance.

The effects of EPU on the RWCU system functional capability was reviewed, and the system can perform adequately at EPU rated thermal power (RTP) with the original reduced RWCU system flow. Using the original RWCU system flow at EPU RTP results in a slight increase in the calculated reactor water conductivity (from 0.1 pS/cm to 0.115 pS/cm) because of the increase in FW flow. The current reactor water conductivity limits are unchanged for EPU and the actual conductivity remains within these limits.Reference 5-1, Enclosure 5, also states,"Table 2.1-4 indicates that the changes in RWCU system operating conditions are small and are acceptable.

The system flow rate is unchanged.

..Revision to EPU Documentation A modification has been developed to maintain-RWCU flow capacity as a constant percent of FW flow. The RWCU System parameters shown in the L-MT-08-052, Enclosure 5, Table 2.1-4 will change as a result of the modification that increased RWCU flow rate from 160 gpm nominal to 180 gpm nominal. The increased flow through the RWCU system represents less than a 0.001% change in both the Reactor Recirculation System and FW systems. This flow rate increase is considered to have a negligible effect on each system for temperature, enthalpy, and flow rate considerations Page 10 of 80 L-MT-12-114 Enclosure 1 for interfacing systems. The changes to Table 2.1-4 (provided in Enclosure

2) also include changes due to the as-built determination that feedwater temperature is about 5 0 F higher than shown on the original heat balance shown in L-MT-08-052, Enclosure 5, Figure 1-2. See item 10 for more details regarding final feedwater temperature changes.In addition, the values shown in the L-MT-08-052, Enclosure 5, Table 2.1-5 were also based on an assumed 15% reduction in RWCU capacity as compared to feedwater flow rate (the 2008 pump capacity).

Since the RWCU system has been upgraded to allow a flow increase from 160 gpm to 180 gpm, (12.5% increase), the system capacity as compared to FW flow returns to the original system specification requirement, equivalent to 1% of the feedwater flow rate.This capacity increase reduces the estimated EPU values shown for conductivity and iron for EPU in the L-MT-08-052, Enclosure 5, Table 2.1-5. The increase in system flow capacity returns the Estimated EPU Value to values comparable to the CLTP values.Similarly, the Projected EPU Margin indicated on L-MT-08-052, Enclosure 5, Table 2.1-5 will increase.The L-MT-08-052, Enclosure 5, Table 2.1-5 values were not recalculated and remain conservative with respect to actual operating conditions and the Operating Guideline/Limit provided in the table. No changes to L-MT-08-052, Enclosure 5, Table 2.1-5 are provided.See Enclosure 2 for a markup of the L-MT-08-052, Enclosure 5, Section 2.1.7, including Table 2.1-4, reflecting these changes.References 5-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML091410120)

Page 11 of 80 L-MT-12-114 Enclosure 1 ITEM 6 -NOBLE METALS MODIFICATION NRC REQUESTED INFORMATION:

Dose rates for steam areas discussed in the EPU LAR are based on use of Hydrogen Water Chemistry (HWC). NRC noted that in the draft Safety Evaluation (SE) no mention is made of HWC, but it needs to. NRC would like to change the SE in this area and qualitatively update to include Noble chemistry changes that NSPM discussed.

Discuss changing solubility of hydrogen (H 2) effect on 40CFR190 at EPU conditions that results in increased dose. This should be discussed independently of Noble chemistry.

NSPM RESPONSE: NSPM is planning to install a NobleChem modification at the MNGP in mid-2013.

The use of noble metal chemistry will allow a reduction in H 2 use while maintaining the ability to mitigate the potential for intergranular stress corrosion cracking (IGSCC) and irradiation assisted stress corrosion cracking (IASCC). The NobleChem modification is not currently installed; therefore, the EPU dose analyses provided in the EPU documentation remain valid. The following evaluation supports the premise that assessments performed in the EPU documentation are conservative and still bounding once NobleChem is installed.

Dose rates for steam areas discussed in the EPU LAR are based on use of Hydrogen Water Chemistry (HWC). L-MT-08-052 (Reference 6-1), Enclosure 5, Section 2.1.4, Reactor Coolant Pressure Boundary Materials, states that "to mitigate the potential for IGSCC and IASCC, Monticello utilizes hydrogen water chemistry." For the assumed HWC regime, the gas injection rates for H 2 and oxygen (02) would increase proportionally with power level to maintain dissolved gas concentrations constant.

System capacity would support the required flow increase with H 2 flow rate increasing from 36 scfm at 1775 MWt to 41 scfm at 2004 MWt.L-MT-08-052, Enclosure 5, Section 2.10.1, Normal Operational Radiation Levels, provides a discussion on dose impact for operation at EPU conditions assuming full HWC injection (without NobleChem).

This discussion was augmented by RAI responses provided in NSPM letter L-MT-09-042 (Reference 6-2). Each of the responses in Reference 6-2 had some relevance to EPU doses resulting from use of HWC.H 2 injection rates for use of HWC result in operation with a normal feedwater H 2 concentration of approximately 1.6 ppm. Under NobleChem the H 2 concentration will be reduced to a normal range of 0.25 ppm to 0.40 ppm. This equates to a H 2 injection rate of approximately 8 scfm. Reducing the H 2 concentration will reduce the steam line radiation levels due to a reduction in the amount of nitrogen-16 (N-16) being removed from the reactor. Typical radiation level changes are indicated by the Main Steam Line Radiation Monitor (MSLRM). MSLRM data correlated to H 2 concentration is shown in Table 6-1 for various HWC injection rates.Page 12 of 80 L-MT-12-114 Enclosure 1 Table 6-1 Dose Rates vs HWC Injection Rates Reactor HWC "A" Power Injection MSLRM FW H2 (MWt) Rate (scfm) (mr/hr) (pp) Date/Time 1763 0.0 499 0.00 3/29/12 0900 -1100 1774 8.0 517 0.34 8/8/12 1510- 1600 1774 18.9 1725 0.80 1/29/12 0700 -1100 1774 37.1 2584 1.58 11/28/12 0100 -0200 The expected radiation level under NobleChem is approximately 517 mr/hr based on an estimated 8 cfm H 2 injection rate yielding a 0.34 ppm hydrogen concentration (between 0.25 and 0.40 ppm). This is 20% of the normal value of 2584 mr/hr with a feedwater hydrogen concentration of 1.58 ppm typical of operation with HWC at CLTP conditions.

This indicates that NobleChem will reduce radiation from N-16 by a factor of approximately 5.This factor of 5 reduction can be used to provide a rule of thumb impact on dose rates.Once NobleChem is implemented the dose reductions will impact the responses provided in L-MT-09-042 NRC RAI No. la, lb and 2a by reducing the dose rates by a factor of 5.Reference 6-1, Enclosure 5, Section 2.10.1, stated for off-site doses that the maximum dose rates at plant boundaries are expected to remain below the 10 CFR 20.1302 maximum dose rate of 2 mrem/hr. Addition of NobleChem would not affect this conclusion and, as demonstrated above, would reduce the off-site maximum dose rate.Since the NobleChem modification is not currently installed, the EPU analyses provided in L-MT-08-052, Enclosure 5, and L-MT-09-042 are still correct and provide bounding results. The purpose of this evaluation is to indicate that these dose estimates will be very conservative when NobleChem transition is completed for MNGP.40 CFR 190 Assessment The response to Reference 6-2, Enclosure 1, RAI No. 2(b) covers the impact on 40 CFR 190. The expected dose related to sky shine was stated in Reference 6-1 as less than 6 mrem/yr for Monticello.

These results were subsequently corrected by later correspondence provided in L-MT-09-042 (Reference 6-2), Enclosure 1, RAI No. 2(b) to 10 mrem/yr. These results remain conservative as these values would also be reduced by the impact of NobleChem as discussed below.In Reference 6-2, Enclosure 1, RAI No. 2(b) the impact of sky shine was estimated by comparing the maximum difference between inner and outer ring thermoluminescent detector (TLD) locations provided in Table 1A and scaling this factor by an estimated Page 13 of 80 L-MT-12-114 Enclosure 1 increase in worst case sky shine of 34.4%. The maximum contribution from sky shine was predicted to be 9.1 mrem/yr.Reference 6-2, Enclosure 1, RAI No. 2(b) Table 1A has been updated to provide data up to 2012. The new data does not change the previous results. Applying the impact of NobleChem would reduce the 9.1 mrem/yr predicted sky shine dose by a factor of up to 5 (i.e. reducing the resultant sky shine dose rate to approximately 1.9 mrem/yr).Other Changes During this review NSPM identified that additional data could be added to update the NRC with the latest available data regarding dose rates recorded at MNGP and at the Inner and Outer Ring locations.

Enclosure 2 contains updates to Tables 1, 1A (discussed above) and 2 as presented in L-MT-09-042 (Reference 6-2) NRC RAI No.2(b) to include available data after 2006.Reference 6-2, Enclosure 1, RAI No. 2(b) Table 1, has been updated to provide data up to 2012. The average dose per year has not increased with the additional data, therefore, the conclusions made from this data has not changed.Reference 6-2, Enclosure 1, RAI No. 2(b) Table 2 was updated to provide available data up to 2011. The average dose per year with the additional data is still well below the 10 CFR 50 Appendix I and 10 CFR 20 limits, therefore, the conclusions made from this data has not changed.See Enclosure 2 for a markup of the L-MT-09-042, NRC RAI No. 2(b), reflecting all the changes discussed in this section.References 6-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML091410120) 6-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC)," Monticello Extended Power Uprate: Response to NRC Reactor Inspection Branch Request for Additional Information (RAI) dated March 20, 2009 (TAC No. MD9990)," L-MT-09-042, dated June 16, 2009. (ADAMS Accession No.ML091671787)

Page 14 of 80 L-MT-12-114 Enclosure 1 ITEM 7 -UNNECESSARY ABNORMAL OPERATING PROCEDURE (AOP) CHANGE NRC REQUESTED INFORMATION:

Turbine Backpressure limit in AOPs was indicated as a planned change. Update to remove reference to changing AOP. Provide a brief basis for change from L-MT-08-052, Enclosure 5.NSPM RESPONSE: L-MT-08-052 (Reference 7-1), Enclosure 5, Section 2.11.1, stated: "The following are the AOP procedural changes:* Turbine backpressure limits have changed as a result of modifications to the low-pressure turbines.

These requirements will be incorporated into the Decreasing Condenser Vacuum AOP. The new turbine backpressure limits are slightly less restrictive at full EPU conditions, are slightly more restrictive at intermediate power conditions and are unchanged at low power conditions." After completion of the low-pressure turbine design, the turbine backpressure limits were changed such that no significant change in required trip margins existed. It was therefore determined that no change was warranted and this change will not be made.See Enclosure 2 for a markup of the L-MT-08-052, Enclosure 5, Section 2.11.1 reflecting this change.References 7-1 Letter from T J O'Connor (NSPM) to Document Control Desk (NRC), "Monticello Extended Power Uprate: Updates to Docketed Information (TAC MD9990)," L-MT-10-072, dated December 21, 2010. (ADAMS Accession No. MLI103570026)

Page 15 of 80 L-MT-12-114 Enclosure 1 ITEM 8 -EMERGENCY CORE COOLING SYSTEM (ECCS) PUMP FLOW RATES NRC REQUESTED INFORMATION:

Pump flow rate assumptions used in the net positive suction head required (NPSHr) analysis changed as a result of the resolution of the Containment Accident Pressure (CAP) issue. Update EPU documentation to indicate that RAI responses contain information that should be superseded.

NSPM RESPONSE: In letters L-MT-09-048 and L-MT-09-073 (References 8-1 and 8-2) NSPM provided responses to NRC RAIs concerning ECCS pump flow rates crediting the use of CAP.Subsequently in letters L-MT-12-082 and L-MT-1 2-107 (References 8-3 and 8-4), NSPM provided revised analyses for ECCS pump flow rates crediting the use of CAP, while applying the guidance of SECY 11-0014. These revised analyses supersede portions of the responses provided in Reference 8-1 and 8-2.See Enclosure 2 for markups to L-MT-09-048, RAIs 12 and 29; and markups to L-MT-09-073 RAIs 5 and 6, based on the revised analyses provided in L-MT-12-082 and L-MT-12-107.

References 8-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Containment and Ventilation Review Branch (SCVB) Request for Additional Information (RAI) dated March 19, 2009, and March 26,2009 (TAC No. MD9990) ", L-MT-09-048, dated July 13, 2009. (ADAMS Accession No. ML092170404) 8-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Containment and Ventilation Review Branch (SCVB) Requests for Additional Information (RAIs) dated July 2, 2009 and July 14, 2009(TAC MD9990)," L-MT-09-073, dated August 21, 2009.(ADAMS Accession No. ML092430088) 8-3 Letter from M A Schimmel (NSPM) to Document Control Desk (NRC), "Monticello Extended Power Uprate and Maximum Extended Load Line Limit Analysis Plus License Amendment Requests:

Supplement to Address SECY 11-0014 Use of Containment Accident Pressure (TAC Nos. MD9990 and ME3145) (TAC MD9990)," L-MT-12-082, dated September 28, 2012. (ADAMS Accession No.ML12276A057)

Page 16 of 80 L-MT-12-114 Enclosure 1 8-4 Letter from M A Schimmel (NSPM) to Document Control Desk (NRC), "Monticello Extended Power Uprate and Maximum Extended Load Line Limit Analysis Plus License Amendment Requests:

Supplement to Address SECY 11-0014 Use of Containment Accident Pressure, Sections 6.6.4 and 6.6.7 (TAC Nos. MD9990 and ME3145) (TAC MD9990)," L-MT-12-107, dated November 30, 2012.(ADAMS Accession No. ML12276A057)

Page 17 of 80 L-MT-12-114 Enclosure 1 ITEM 9 -RESIDUAL HEAT REMOVAL AND CORE SPRAY PUMP ROOMS POST-LOSS OF COOLANT ACCIDENT (LOCA) HEATUP NRC REQUESTED INFORMATION:

Original responses were based on engineering judgment and said that building heatup would be -< 1.8 0 F. Formal calculations exist now that have changed the value. Summarize changes in reactor building (RB) heatup calculation and include why they were needed and why they are conservative.

Confirm that method is the same and indicate why change has occurred.

Indicate whether pipe support modifications will be necessary.

Indicate that GOTHIC was used and what version. State that there is no change in methodology.

NSPM RESPONSE: NSPM reported in letters L-MT-08-052 (Reference 9-1), Enclosure 5, Section 2.7.5 and L-MT-09-048 (Reference 9-2), NRC (SCVB) RAI No. 34 that the Residual Heat Removal (RHR) and Core Spray (CS) pump room temperatures would change based on EPU conditions.

Specifically, NSPM reported that the RHR and CS pump room temperatures were determined to increase up to 1.8 0 F following a LOCA at EPU conditions.

This 1.8 0 F increase was determined using engineering judgment based on heat load increases in the rooms.Subsequently, a formal calculation for the building heatup resulting from the LOCA scenario at EPU conditions has been finalized.

This calculation concluded that an increase of 2.9°F for RHR and CS pump room temperatures would occur following a LOCA at EPU conditions.

GOTHIC 7.2a was used for the modeling software which in combination with enhanced Reactor Building conductors, volumes, and surface areas updated for EPU, provides a more accurate analysis of the LOCA event than previous modeling versions.

No methodology changes were made. The 2.9 0 F temperature increase for the RHR and CS pump rooms has been evaluated and determined to be acceptable.

No modifications in the RHR and CS pump rooms are required due to the higher LOCA temperatures at EPU conditions.

See Enclosure 2 for a markup of the EPU documentation reflecting these changes.References 9-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML091410120)

Page 18 of 80 L-MT-12-114 Enclosure 1 9-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Containment and Ventilation Review Branch (SCVB) Request for Additional Information (RAI) dated March 19, 2009, and March 26,2009 (TAC No. MD9990)", L-MT-09-048, dated July 13, 2009. (ADAMS Accession No. ML092170404)

Page 19 of 80 L-MT-12-114 Enclosure 1 ITEM 10 -FINAL FEEDWATER TEMPERATURE CHANGE NRC REQUESTED INFORMATION:

Change in final as-built feedwater temperature.

Temperature change for full EPU conditions is approximately 5 0 F higher than originally analyzed.

This affects the feedwater (FW) piping design limit. NSPM needs to describe how this change has been assessed.

Provide more information from GE on how it was evaluated.

Indicate what events/transients have been looked at (including other non-limiting reload events such as Loss of FW heating).

Indicate that the containment response remains bounding.

Need to demonstrate how we came to conclusion that it is negligible.

NSPM RESPONSE: Following the 2011 Refueling Outage, the newly installed feedwater (FW) heater performance exceeded expectations with a higher than predicted FW temperature exiting the 15A and 15B heaters. The issue was entered into and evaluated in the MNGP corrective action program.NSPM evaluated the increased FW temperature impact on design bases accident -loss of coolant accident (DBA-LOCA) and the high energy line break (HELB) analyses performed for the EPU project.A feedwater temperature of 400.8 0 F was used to develop revised reactor heat balances to account for EPU power level, MELLLA+ flow rate, and using an extrapolation from CLTP power level. From this effort, revised EPU and MELLLA+ heat balances were obtained.

For piping analysis purposes, 402.8 0 F was used for conservatism.

Consideration for Transient Analysis GEH performed a study and determined that the impact of the FW temperature change on anticipated operational occurrences (AOOs) was negligible.

GEH further concluded that sufficient margin remains in the peak dome pressure safety limit and ASME upset condition limit when accounting for this small FW temperature change.Consideration of DBA-LOCA Containment Response: The incremental heat added to containment as a result of the FW temperature change was determined to be less than 0.97 MBTU, which is conservative for both the short-term and long-term DBA-LOCA analyses.

This was compared to the conservatively determined total FW input plus the metallic heat BTU of approximately 55.5 MBTU. The FW enthalpy delta was determined to be insignificant.

There was sufficient conservatism (approximately 8 MBTU) identified in the analysis to account for the small change in FW temperature.

This evaluation demonstrates that the assumed heat added to containment (as a result of the incremental change in FW temperature) is significantly bounded by the analysis of record. Therefore, the impact of having a slightly higher feedwater temperature is bounded by the assumptions and conservatisms used in the analysis.Page 20 of 80 L-MT-12-114 Enclosure 1 Considerations for HELB: The systems communicating with the feedwater piping were evaluated for potential HELB impacts of this increased feedwater temperature.

FW HELB breaks were not impacted significantly since the temperature change is small when compared to the large volume of relatively cold water drawn from the condenser.

The evaluation determined that three FW HELB cracks were impacted and one Reactor Water Cleanup (RWCU) break was impacted.The three cracks releasing FW are of sufficient duration (> 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) that the increase in temperature/enthalpy does have some impact on volume temperatures.

The RWCU break impacted the evaluation of a RWCU HELB in the Steam Chase. These changes have been included in related calculations in order to provide configuration and design control. Further discussion concerning final HELB analysis results are provided in Item 26.Conclusions Analyses to account for change in FW temperature have been performed that demonstrate that changes do occur in certain HELB results. However, the revised FW temperature had only minor impact on Reactor Building maximum temperatures, pressures, or flood levels. The changes to HELB profiles resulting from the final feedwater temperature changes are included in the response to Item 26.Some of the Environmental Qualification (EQ) temperature profiles durations are altered, and this documentation is currently being revised to incorporate this change.See item 27 for further discussion concerning EQ changes.There are no proposed changes to EPU documentation resulting from this response.Page 21 of 80 L-MT-12-114 Enclosure 1 ITEM 11 -PIPING COMPONENTS REQUIRING FURTHER ANALYSIS NRC REQUESTED INFORMATION:

L-MT-08-052, Enclosure 5, Table 2.2-2d indicated six areas where further piping analysis was required.

The analyses for these six areas are completed.

Provide a complete summary of the feedwater (FW) piping evaluation completed.

Demonstrate that results are within code allowables.

Look at discussion in L-MT-09-044 and L-MT-1 1-044 and confirm these results. Provide pipe support stress tables similar to L-MT-09-044, Enclosure 1, pgs 27 and 28.NSPM RESPONSE: NSPM letter L-MT-08-052 (Reference 11-1), Enclosure 5, Section 2.2.2.1 including Table 2.2-2d indicated that certain piping analyses remained to be completed.

This was accurate as of the initial EPU LAR submittal.

However, these analyses have now been completed and thus L-MT-08-052, Enclosure 5, Section 2.2.2.1 and Table 2.2-2d can be revised to reflect these changes.In addition, L-MT-09-044 (Reference 11-2), Enclosure 1, EMCB RAI No. 17a provided Main Steam System piping evaluation results. A portion of these results have changed.Specifically, the Main Steam line piping outside Containment results have changed and are updated below.Torus Attached Piping, RHR (BOP Condensate Service Water Lines), Cross Around Piping, CARV Discharge Piping Reference 11-1, Table 2.2-2d indicated that these piping analyses along with Main Steam and Feedwater/Condensate remained to be completed.

The Torus Attached Piping, RHR (BOP Condensate Service Water Lines), Cross Around Piping, CARV Discharge Piping analyses are now completed and all the results are within the code allowables.

The Main Steam and Feedwater/Condensate lines are discussed separately below.Main Steam System NSPM confirmed the Main Steam line piping inside Containment analysis results provided to the NRC in Reference 11-2, EMCB RAI No. 17a are correct and have not changed. Therefore, no changes to this response are necessary.

In this same response NSPM provided Main Steam line piping outside Containment analysis results to the NRC. NSPM has determined that these values have changed.The revised values are provided below.Page 22 of 80 L-MT-12-114 Enclosure 1 Table 11-1 -Main Steam Loading Results Maximum Flued Head Anchor Loads Maximum Pipe Stresses (Outside Containment)

Load Combination Service Node Stress Allowable Interaction Level (psi) (psi) Ratio P+DW A TURD 7650 15000 0.51 TH Range A TURB 16618 22500 0.74 P+DW+TSV B TURC 12288 18000 0.68 P + DW + OBE* B X7A 14289 18000 0.79 DW+SRSS(TSV, D X7A 21026 26325 0.80 SSE)*HELB TH N/A TURB 16618 18000 0.92 HELB N/A TURD 3263 1 30000 1.09**DW+TH+OBE*Excluding seismic category II pipe between Stop Valves and Turbine**Indicates a HELB at this location, this load combination is used only to evaluate the need to assume a HELB and is not required to have an Interaction Ratio <1 to meet USAR requirements.

Maximum Turbine Loads Load Service Mx Allowable Interaction Mz Allowable Interaction Combination I Level (ft-lb) (ft-lb) Ratio J (ft-lb) (ft-lb) Ratio DW B 3714 413000 0.090 1848 722000 0.256 3 86 DW + TH B 2846 413000 0.689 1631 722000 0.226 1 03 55 Note: Loads from all turbine nodes were combined Page 23 of 80 L-MT-12-114 Enclosure 1 Feedwater System Previously NSPM reported that the FW/Condensate system piping evaluations were not complete.

These evaluations are now complete.

Below are the results of the FW/Condensate piping evaluations.

Table 11-2 -Feedwater/Condensate Loading Results FW/Condensate Maximum Pipe Stresses (Maximum Interaction Ratios): Node Load Combination Stress si Allowable (psi) Interaction Ratio OlON P + DW 8,637 15,000 0.58 Q12N I TH 18,119 22,500 0.81 PN25 P + DW + SSE896 14,602 22.863 0.639 Reactor Feed Pump Nozzles Stress Analysis*:

Load Case Max Equivalent Stress Allowable Safety Stress (psi) (psi) Factor P-2A Suction (DW+TH) [ 8,118 20,855 2.6 P-2A Discharge (DW+TH) ]9,014 20,855 2.3 P-2B Suction (DW+TH) 8,203 20,855 2.5 P-2B Discharge (DW+TH) 8,774 20,855 2.4[P-2A Suction (DW+TH+UBC) 18,136 20,855 2.6 IP-2A Discharge (DW+TH+UBC) 9,376 1 20,855 2.2[P-2B Suction (DW+TH+UBC) 8,247 20,855 2.5 P-2B Discharge (DW+TH+UBC) 8,844 20,855 2.4*The analysis presented here does not include the latest analysis of the stresses on the nozzles. The latest analysis of the stresses increased the stress by a maximum of <1.1%, which resulted in it being deemed unnecessary to re-analyze as the safety factors of>2.2 will bound these minor increases in stresses, as a minimum safety factor of 1.5 is required for normal (static) operating conditions per ASME BPVC See. II, Part D-C, Table lA values at 315'F.Maximum Support Load: I Support # I Node I Description I Force (lb) Allowable (lb) I Interaction Ratio I FWH-90 1401NI F (IRmax 946 953 0.993!!See Enclosure 2 for a markup of the EPU documentation reflecting the completed piping analyses and the changes identified above for the Main Steam and Feedwater Systems.Page 24 of 80 L-MT-12-114 Enclosure 1 Temperature Pressure Changes As part of the reanalysis of piping for EPU pressures and temperatures changed due to EPU conditions.

The EPU Design Pressure and Temperature columns contain the values used in the EPU design analyses performed for the subject piping. These changes are provided in the following table: Table 11-3 -Design Pressure and Temperature Comparison of CLTP and EPU The Crossaround Piping Line No. EPU Design From -to Pressure Psig EPU Design Temperature OF CLTP Press*/Temp E6A from crossaround 269 4 To E-15A heater (08-211)E6B from crossaround 269 4 To E-15B heater (09-105)The Extraction Steam Lines to 13 and 14 heaters 10 10 220/396 220/396 Line No.From -to EPU Design Pressure Psig EPU Design Temperature OF CLTP Press*/Temp E8A-20"-HA Condenser

-E-13A heater (08-128)E8B-20"-HA Condenser

-E-13B heater (08-128)E7A-10"-HA Turbine -E14A (08-128)E7B-10"-HA Turbine -E14B (08-128)100 100 170 170 329 329 363 363 68/315 68/315 117/348 117/348 Page 25 of 80 L-MT-12-114 Enclosure 1 Condenser Drains Line No.From -to EPU Design Pressure Psig EPU Design Temperature OF CLTP Press*/Temp CD9-6" 269 T-6A- CD5 CD10-6" 269 CD9-condenser CD5-6"-HCD 269 CD5 -condenser CD5-6" 269 T-6B -E-14A CD11-6" 269 T-6D -CD6 CD12-6" 269 CD11- condenser CD6-6"-HCD 269 CD6 -condenser CD6-6" 269 T-6C -E-14B Relief Valve and Vent Piping 410 410 410 410 410 410 410 410 212/392 100/392 212/392 100/392 212/392 100/392 100/392 212/392 RV2/12-6" (12 heaters)RV3/13-6" (13 heaters)RV4/14-6" (14 heaters)RV5/15-4" (15 heaters)V2A-8"/6" (1 2A vent)V2B-8"/6" (128 vent)VIA-8"/6" (11 A vent)V1 B-8"/6" (11 B vent)50 92 158 269 261 333 370 410 261 261 192 192 vacuum/243 vacuum/310 vacuum/344 vacuum/390 50 50 50 50 15/245 15/245 15/245 15/245 Page 26 of 80 L-MT-12-114 Enclosure 1 Condensate Piping Line No. EPU Design EPU Design CLTP From-To Pressure Temperature Press*/Temp Psig OF C1A/C1B Condenser-Pump Vacuum 145 Vacuum/135 CIA/Cl B-16" Pump-Air Ejector 450 145 434/135 C2A/C2B Air Ejector-Steam 450 145 434/135 Packing Exhauster C2-12"-GB 450 145 434/135 Air Ejector Bypass Steam Packing Exhauster 434/135-11 Drain Coolers C4A/C4B 11 Drain Cooler- 450 158 434/144 11 FW Heater C4A/C4B 11 FW Heater-12 Drain Cooler 450 182 434/175 C4A/C4B 12 Drain Cooler -450 199 434/193 12 FW Heater C4A/C4B 12 FW Heater-13 FW Heater 450 250 434/238 C4A/C4B 13 FW Heater-FW Pump 450 321 434/310 Page 27 of 80 L-MT-12-114 Enclosure 1 Feedwater Piping Line No.From-To FW3 and FW4 FW Pump Recirc lines EPU Design Pressure Psig 1550 EPU Design Temperature OF 323 CLTP Press*/Temp 1550/313 FW2A/FW2B FW Pump-14 FW Heater FW2A/FW2B 14 FW Heater-15 FW Heater FW2A/FW2B 15 FW Heater-MO-1614 & MO-1615 1550 1550 1550 323 357 1550/313 1550/345 1550/400 1250/400 410 410 FW2A/FW2B MO-1614 & MO-1615-2 nd check valve from vessel 1250 Heater Drains Piping Line No.From-To EPU Design Pressure Psig EPU Design Temperature OF CLTP Press*/Temp HD1, HD11.HP Heater- CV-1 019& CV-1 058 HD1, HD11 CV-1019 & 1058-14 Heaters HD1, HD11 HD1 & HD11-CV-1020 & 1059 HD1, HD11 CV-1020 &CV1 059-Condenser

1. 28 & #19 269 371 269 371 215/349 110/349 215/349-/349 269 371 269 371 Page 28 of 80 L-MT-12-114 Enclosure 1 Line No. EPU Design EPU Design CLTP From-To Pressure Temperature Press*/Temp Psig OF HD2, HD12 149 337 110/318 14 Heaters-CV-1017 & 1056 HD2, HD12 149 337 63/318 CV-1017 & 1056-13 Heaters HD2, HD12 149 337 110/318 HD2 &12-CV-1018 & 1057 HD2, HD12 149 337 -/318 CV-1018 & 1057-Condenser

1. 12 & 10 HD3, HD13 87 263 64/248 13 Heaters-CV-1015 & 1054 HD3, HD13 87 263 12/248 CV-1015 & 1054-12 Heaters HD3, HD13 87 263 64/248 HD3 &13-CV-1016 & 1055 HD3, HD13 87 263 -/248 CV-1016 & 1055-Condenser

1. 13 & 19 HD4, HD14 19 258 12/243 12 Heaters-T-52 A & B HD5, HD15 19 258 12/243 T-52A & B-12 Drain Coolers Page 29 of 80 L-MT-12-114 Enclosure 1 Line No. EPU Design EPU Design CLTP From-To Pressure Temperature Press*/Temp Psig OF HD6, HD16 19 193 12/185 Drain Coolers-CV-1013 & 1052 HD6, HD16 19 193 -/185 CV-1013 & 1052-11 Heaters HD6, HD16 19 193 12/185 HD6, HD16-CV-1014 &1053 HD6, HD16 19 193 -/185 CV-1014 &1053-Condenser

1. 11 & #7 HD7, HD17 -6.3 185 -7/180 11 Heaters-11 Drain Coolers HD8, HD18 -6.3 185 -7/180 HD7 & HD17-Condenser

1. 7 HD9, HD19 -6.3 155 -7/138 11 Heaters-Condenser

1. 5* Pressure values indicated with a "-" were determined to be less than 50 psig.The changes identified in Item 11 are included in the markups provided in Enclosure 2.Changes are identified under Items 11 and 26.References 11-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML091410120)

Page 30 of 80 L-MT-12-114 Enclosure 1 11-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " Monticello Extended Power Uprate: Response to NRC Mechanical and Civil Engineering Review Branch (EMCB) Requests for Additional Information (RAIs) dated March 28, 2009 (TAC MD9990)," L-MT-09-044, dated August 21, 2009. (ADAMS Accession No. ML092390332)

Page 31 of 80 L-MT-12-114 Enclosure 1 ITEM 12 -TECHNICAL SUPPORT CENTER (TSC) DOSE CALCULATION NRC REQUESTED INFORMATION:

L-MT-08-036, Enclosure 6 provided a vendor calculation for TSC Internal Dose. This calculation was subsequently revised. Provide a discussion of revised calculation, including a table of changes. Indicate which events are/are not affected and why that determination was made. Report the results and indicate calculation within acceptable limits.NSPM RESPONSE: Reference 12-2, Enclosure 6 contained calculation ALION-CAL-M NGP-4370-03,"MNGP EPU -TSC Internal Dose, Revision 0." This calculation was subsequently revised to Revision 1. The results of the calculation revision change were reported to the NRC in Reference 12-1. However, the update did not recognize that L-MT-08-036 (Reference 12-2),, Enclosure 6 was impacted by this change.The change affects the TSC post-LOCA dose. A complete description of the reason for the change is provided in Reference 12-1, Enclosure 4, including updated excerpts from the EPU documentation (including dose tables) that show the corrected TSC dose. The dose tables also include the NRC acceptance criteria and demonstrate that the revised TSC post-LOCA dose is well within the NRC acceptance criteria.See Enclosure 2 for a markup of Reference 12-2 indicating that the provided calculation is no longer applicable.

References 12-1 Letter from T J O'Connor (NSPM) to Document Control Desk (NRC), "Monticello Extended Power Uprate: Updates to Docketed Information (TAC MD9990)," L-MT-10-072, dated December 21, 2010. (ADAMS Accession No. ML103570026) 12-2 Letter from T J O'Connor (NSPM) to Document Control Desk (NRC), "Monticello Extended Power Uprate (USNRC TAC MD8398): Acceptance Review Supplement Regarding Radiological Analysis," L-MT-08-036, dated May 20, 2008. (ADAMS Accession No. ML081430494)

Page 32 of 80 L-MT-12-114 Enclosure 1 ITEM 13 -RISK ASSESSMENT NRC REQUESTED INFORMATION:

Ongoing changesto model, site design and operation have impacted previously reported results. Describe any changes to Operations or Design that affect the PRA analysis.

Indicate that enhancements have been identified that would have a small change on the baseline CDF. A description in a qualitative manner is acceptable since this is not a risk informed application.

Discuss any HEP/HRA changes. See SRP 19.2, Appendix D for criteria.

Indicate that enhancements and proposed changes would not significantly affect delta CDF/LERF.Conclude that ACDF and ALERF have not changed, or conclude that the change is still very small. Indicate that the model will be revised in the future to include all enhancements and EPU changes..NSPM RESPONSE: NSPM letter L-MT-08-052 (Reference 13-1), Enclosure 15 provided a risk evaluation of operation of the MNGP at EPU conditions.

This assessment was performed in March 2008. The following Gap assessment shows that while a number of changes have occurred at the MNGP that impact the PRA analysis, the results of these changes do not have a significant impact on the change in risk attributable to the EPU as compared to the March 2008 assessment and related analysis.

Therefore, no additional changes to L-MT-08-052, Enclosure 15 are proposed at this time.Although the current Probabilistic Risk Assessment (PRA) model of record is the same base model used to perform the EPU Risk Assessment (Identification of Risk Implications Due to Extended Power Uprate at Monticello, March, 2008, Enclosure 15 to L-MT-08-052), two general areas are considered in the following Gap Assessment to address changes since the 2008 timeframe when the EPU Risk Assessment was performed.

First, plant modifications that have been (or will be) implemented subsequent to the EPU risk assessment (but prior to EPU implementation), including EPU modifications that have been refined since 2008, are considered for their potential impact on the EPU Risk Assessment.

No significant changes to the Human Error Probability/Human Reliability Analysis (HEP/HRA) insights from the March 2008 submittal result from these plant modifications.

Second, several adjustments have been made over the past several years to the current PRA model, that are intended to bring the PRA into conformance with the ASME/ANS PRA standard endorsed by the NRC in Regulatory Guide 1.200. These adjustments are not associated with implementation of EPU. This revised PRA model is scheduled to become the new model of record in the first half of 2013.Plant Modifications Plant modifications on equipment that have potential to impact PRA model results that were not included in the original EPU Risk Assessment:

Page 33 of 80 L-MT-12-114 Enclosure 1" Condensate Pump Replacement-This modification replaces both Condensate Pumps with higher capacity pumps and motors, generally leading to a risk reduction, but two features have potential for a small negative impact on risk. The pump motor oil will be cooled by Service Water (SW), and higher pump capacity can lead to higher potential flood rates. The SW dependency impact is minimized by the fact that Feedwater pumps are already dependent on SW. The internal flooding impact is offset by the enhanced High Energy Line Break (HELB) flood barrier that protects the Division 1 4 KV equipment.

This change impacts the base risk level, but the differential risk due to EPU would not be impacted.* Division 1 4KV Switchgear Room HELB Barrier Improvement

-Enhanced flooding protection to the lower 4 KV switchgear is being installed to accommodate HELB concerns.

A flooding barrier up to 7 feet high is being installed.

As the lower 4 KV equipment is one of the critical areas that drive base internal flooding risk at Monticello, this modification will significantly offset negative impacts from increased design flow in systems accommodating EPU. This change reduces the base risk level, but the differential risk due to EPU would be minimal." Feedwater Regulating Valve Replacement

-New Feedwater Regulating valves will have virtually the same dependencies and failure modes as the existing valves.New valve positioners for these valves will incorporate digital technology with some possible additional failure modes, but will eliminate some existing failure modes.Overall impact on risk is neutral.* Service Water Pump Replacement

-All three SW pumps have been replaced with higher capacity pumps. Pump #11 power supply has been switched from load center LC-103 to LC-107. Increased risk from higher potential flooding rates is offset by improved flooding barrier for the lower 4 kV room, and enhanced system capability.

The new power source to Pump #11 can be maintained under Loss of Offsite Power (LOOP) conditions using the #13 Diesel Generator.

Overall impact on risk is neutral." Instrument Air System Upgrade -All three air compressors have been replaced by much higher capacity compressors.

Two smaller air dryers have been replaced by three reliable and high capacity dryers. Power supplies to the compressors were changed to provide back up from alternate power sources. Service water has been eliminated as a potential failure mechanism to compressors.

The compressors are relocated to an area that is not susceptible to internal flooding.

Higher reliability of the Instrument Air system has a positive impact on overall risk. Thus, the change reduces the base risk level, but the differential risk due to EPU would be minimal.* Condensate Demineralizer Replacement

-Higher capacity demineralizers have been installed to accommodate EPU conditions.

Demineralizer outlet valve failure mode has changed from fail-closed to fail-as-is.

This change improves condensate system reliability under loss of instrument air events. Increase in potential flood rates due to larger pipe diameters and associated air operated valves (AOVs) in the demineralizer system is offset by improved flood protection of the lower 4 KV Page 34 of 80 L-MT-12-114 Enclosure 1 switchgear equipment.

This change reduces the base risk level, but the differential risk due to EPU would be minimal.0 CAPX2020 Subyard Improvements

-Significant enhancements to the 345 KV offsite power grid have been incorporated.

One additional offsite power source is provided from the new Quarry power line. The new 345 KV ring bus now remains intact following a plant trip as opposed to breaking the ring bus upon tripping the main generator for the old configuration.

This results in more reliable offsite power sources, particularly following a plant transient.

The net impact on overall risk is positive.

This change reduces the base risk level, but the differential risk due to EPU would be neutral.0 Feedwater Pump Replacement

-New higher capacity feedwater pumps will be installed to provide the enhanced flow required for EPU conditions.

The power source to the pump motors will be shifted to the new 13.8 kV supplies.

This system upgrade will result in no significant change in base risk or differential risk due to EPU.* 13.8 KV Switchgear Installation

-A new power supply for the FW pumps, Condensate pumps and Recirculation pump motor-generator (MG) set drive motors will be placed in service. The new configuration is very similar to the existing power supplies, except for the increased 13.8 KV voltage. Buses 11 and 12 will be relocated to the old hot machine shop building.

Overall impact on base risk or differential risk from the EPU due to this modification is neutral.* Hotwell Level Increase -Main condenser hotwell level will be increased slightly to provide additional net positive suction head (NPSH) for the new Condensate pumps.The slight addition in makeup water inventory will enhance the ability to cool the reactor, but also will increase flood source inventory.

This potential additional source of floodwater will be offset by the enhanced flood barrier protecting the lower 4 KV switchgear room. Risk impact is not significantly affected by this modification.

• Maximum Extended Load Line Limit Analysis Plus (MELLLA+)

-MELLLA+ will modify the power-flow map to allow operation along a higher rod line. A post-EPU/MELLLA+

Reactor Recirculation pump trip or runback will not reduce power as much as the current condition.

There will be a slight impact on reactor power level following Anticipated Transient Without Scram (ATWS). An evaluation of Attachment 6 (Monticello MELLLA+ Risk Assessment) of L-MT-10-003 (MELLLA+License Amendment Request) was performed to determine if changes subsequent to the submittal could alter the fundamental conclusion of the assessment.

This evaluation concluded that although the baseline CDF/LERF is expected to increase from upgrading the PRA model of record, the outcome will not result in a shift outside of Region III (Very Small Changes) acceptance guidelines from Regulatory Guide 1.174 (An Approach for Using PRA in Risk-Informed Decisions on Plant Specific Changes to the Licensing Basis).0 Main Turbine/Generator Upgrades -The Turbine/Generator upgrades have no effect on structures, systems and components (SSCs) that have potential'to Page 35 of 80 L-MT-12-114 Enclosure 1 significantly impact critical safety functions modeled in the PRA. Therefore the baseline or differential risk results are not impacted by these modifications.

• 1 R/2R Auxiliary Transformer Replacements

-New transformers will be installed to accommodate the new 13.8 KV loads. In addition to the increase in design capacity, these new transformers will be less dependent on AC power for cooling under post transient conditions.

This results in a net reduction in baseline risk.* Main Generator Output Transformer Replacement

-The newly installed Main Generator Output Transformer has no effect on SSCs that have potential to significantly impact critical safety functions modeled in the PRA. Therefore, this modification has no impact on baseline risk or differential risk from the EPU.PRA Model Enhancements Future PRA model enhancements to conform to the ASME/ANS Standard have been considered for their potential impact on PRA EPU assessment results as described below:* Potential Condensate Demineralizer flooding due to spurious AOV operation

-In the process of designing the new condensate demineralizer system, it was discovered that single AOV failures in the system could result in overfilling the Backwash Receiving tank and subsequent flooding of the 911' elevation of the Turbine Building.

The modification to protect the lower 4 KV room from flooding as discussed above, significantly reduces the risk associated with this flooding potential.

Although this vulnerability has always existed for MNGP, it will impact the internal flooding baseline results of the PRA. This change impacts the base risk level, but the differential risk due to EPU would not be impacted.* Control Rod Drive Hydraulic (CRDH) system success criteria changes -Success criteria crediting early injection success for the CRDH system will be modified in the next revision of the PRA model. This change in CRDH success criteria is a result of new insights obtained by detailed hydraulic modeling of the CRDH system that were performed as part of the Reg. Guide 1.200 model upgrade.Long term (late in the event) CRDH success criteria are not impacted by this new insight. Importance of the CRDH system as an early injection source is limited due to its limited flow capacity.

This model improvement would be appropriate regardless of the impact from EPU, yet the timing where CRDH becomes a credible early injection source will change slightly following EPU implementation.

This change impacts the base risk level, but the differential risk due to EPU would not be significantly impacted." Diesel Fire Pump and CRDH ventilation dependencies

-Recent insights have revealed that long term use of the Diesel Fire Pump with room ventilation failure would be challenged by the fact that personnel accessibility to the room to make up fuel oil to the day tank is complicated by high room temperatures.

Similar insights have shown that loss of room ventilation to the CRDH pump room may make flow Page 36 of 80 L-MT-12-114 Enclosure 1 enhancement valve manipulations in the room prohibitive if not performed soon after the ventilation system loss. Although these insights were not incorporated in the model used for the EPU assessment, the issues are the same for both pre- and post-EPU conditions.

This small change impacts the base risk level, but the differential risk due to EPU would not be impacted." Modular Accident Analysis Program (MAAP) Parameter File corrections related to Drywell Coolers -An error was identified in the parameters used to define Drywell Cooler sizing and performance.

A number of the thermal-hydraulic calculations using the MAAP code had to be re-run for the future PRA. Since the EPU risk assessment was performed prior to discovery of this issue, the overall impact of this issue on the EPU risk assessment has been evaluated and documented in a report. This report determined the following about the discrepant suppression pool pressure and temperature calculations: "In addition, the SPIT and SPIP point in time values mentioned in the Comment column of Table E-1 of the MNGP EPU risk assessment report for this case are not reflective of the MNGP containment response; however, these particular parameter values are commentary and not specifically used directly in any calculation." While a number of the MAAP simulations in this report are impacted by this modeling issue, NSPM has determined that this issue has no impact on the numerical risk results or conclusions of the MNGP EPU risk assessment.

• Fire Water/Condensate Service Water (CSW) success criteria changes -The pump and system flow characteristics for the Fire Water and CSW systems have been recently updated to more accurately reflect the expected injection flow rates into the reactor vessel following depressurization.

These new data revealed that flow from these alternate injection systems is less than that credited in the current PRA model. These new insights have resulted in a lengthened period of time between the initiating event and the time when these systems should be credited as capable of making up for decay heat losses. Although this refined information will result in an increase in overall base CDF/LERF, the same increase would apply to both pre- and post-EPU conditions, and therefore, would not result in a significant differential change to the risk of EPU.* Safety Relief Valve (SRV) Depressurization success criteria changes -The EPU risk assessment was based on a model that credited early Fire Water and CSW system injection following depressurization with two SRVs. Future revisions of the PRA model will use a more restrictive definition of core damage (peak fuel temperature of 1800OF versus 22001F) based on the recommendations in the ASME PRA standard.

The more restrictive definition of core damage, combined with updated pump flow characteristics for Fire and CSW systems mentioned above, will remove those systems from being credited as successful early injection systems.Although this success criteria change will result in an increase in overall base CDF/LERF, the same increase would apply to both pre- and post-EPU conditions, Page 37 of 80 L-MT-12-114 Enclosure 1 and therefore, will not result in a significant change to the EPU assessment results in terms of change in risk due to operating at a higher power level.Best estimate Battery Capacity Calculation

-A thorough battery analysis has been performed subsequent to the EPU risk assessment, which provides best estimate battery duration following a Station Blackout (SBO) event. This analysis shows that High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) can function well beyond the 4-hour design battery duration upon loss of all AC power. Incorporation of this insight into the PRA model results in a reduction in SBO risk and the baseline values for CDF and LERF. The impact on the EPU risk assessment would be minor since the battery analysis results would apply equally to the pre-EPU and post-EPU models.Conclusion:

Plant changes that have been implemented subsequent to the EPU risk assessment and plant modifications designed to support the EPU that have not yet been completed (but are planned to be installed prior to EPU implementation) do not have a significant impact on the change in risk attributable to the power uprate as compared to the March 2008 assessment and related analysis.

Additionally, PRA insights gained over the past several years while pursuing a major model update to conform to the ASME/ANS standard, although currently anticipated to result in a net increase in overall baseline CDF/LERF, do not result in a significant change in the delta between baseline risk and EPU risk.The overall estimated impact attributable to the EPU is low, and remains within the "very small" category (i.e., Region III of the Regulatory Guide 1.174 Guidelines) for CDF and LERF. The next PRA model revision, which is currently in later stages of development, will incorporate all of the above changes with the exception of the new 13.8 KV switchgear configuration.

This electrical modification will have virtually no impact on the model results. Final design of the (yet to be installed) 13.8 KV system was not complete as of the "freeze date" applied to the current model upgrade initiative.

There are no proposed changes to EPU documentation resulting from this response.References 13-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML091410120)

Page 38 of 80 L-MT-12-114 Enclosure 1 ITEM 14 -COMPUTER CODE CHANGES NRC REQUESTED INFORMATION:

L-MT-08-052, Enclosure 5, Table 1-1 indicates that GOTHIC Version 7.1 was used to perform the High Energy Line Break (HELB)Subcompartment Evaluation.

NSPM used later codes including GOTHIC Version 7.2a and Version 7.2b to perform HELB evaluations.

Identify GOTHIC 7.2a and 7.2b as computer codes used in EPU.NSPM RESPONSE: L-MT-08-052 (Reference 14-1), Enclosure 5, Table 1-1 indicates that GOTHIC Version 7.1 was used to perform the High Energy Line Break (HELB) Subcompartment Evaluation.

NSPM used later codes including GOTHIC Version 7.2a to perform HELB evaluations and 7.2b for Containment Accident Pressure calculations.

GOTHIC version 7.2a was used for HELB reconstitution analysis including some subcompartment analyses.

The results of these analyses were benchmarked to RELAP4/Mod5 previously approved code of record. See item 26 for details.GOTHIC version 7.2b was used for Containment Accident Pressure (CAP) analyses, and for the reactor heat balance evaluations associated with the multiple spurious operations analyses for Appendix R. In the CAP submittal (L-MT-12-082, Reference 14-2) the results of the GOTHIC 7.2b analyses are benchmarked against SHEX and Monte Carlo results.See Enclosure 2 for a markup of L-MT-08-052, Enclosure 5, Table 1-1 reflecting these changes.References 14-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML0832301 11)14-2 Letter from M A Schimmel (NSPM) to Document Control Desk (NRC), "Monticello Extended Power Uprate and Maximum Extended Load Line Limit Analysis Plus License Amendment Requests:

Supplement to Address SECY 11-0014 Use of Containment Accident Pressure (TAC Nos. MD9990 and ME3145) (TAC MD9990)," L-MT-12-082, dated September 28, 2012. (ADAMS Accession No.ML12276A057)

Page 39 of 80 L-MT-12-114 Enclosure 1 ITEM 15 -TURBINE BYPASS VALVE CAPACITY NRC REQUESTED INFORMATION:

L-MT-10-002, Enclosure 2 changed the Turbine Bypass Valve Capacity value from 11.6% to 11.5% of the Nuclear Steam Supply. The submittal did not identify that this change also applied to other documents, and identify those documents as needing correction.

Update only to supersede outdated information.

Include statement that confirms all affected analyses were performed at correct value. No changes to analysis outcomes for anticipated operations occurrences (AOOs).NSPM RESPONSE: The transient analysis completed for the EPU was reported to the NRC in L-MT-08-052 (Reference 15-1), Enclosure 5, section 2.5.4.3 and in L-MT-09-049 (Reference 15-2), response to RAI 2.8.3 -11. Both documents reported a turbine bypass valve capacity of 11.6%. A change in turbine bypass valve capacity from 11.6% to 11.5% was reported to the NRC under letter L-MT-10-002 (Reference 15-3). This letter stated: "TS Bases B 3.3.1.1 refers to bypass capacity in terms of "% of the THERMAL POWER," while B 3.7.7 (Main Turbine Bypass System) to bypass capacity in terms of "% ... rated steam flow." For consistency, it was decided that those statements (which refer to the same capability) should read the same. The only measurable and calculated value is steam flow, which is the applicable parameter used in the safety analyses, and thus, "% of rated steam flow" is the more appropriate term to be used in the TS Bases. Therefore, the TS Bases turbine bypass value statements are changed from "THERMAL POWER" to "of rated steam flow," and the latest calculated value (11.5%) supersedes the 11.6% in the original TS Bases markups." Turbine bypass valve capacity is not used as an input for containment analysis or for the ECCS analysis.

This value is used in the evaluation of plant transients.

The evaluation of plant transients is performed on a cyclic basis for MNGP and has been completed for EPU core design using a value of 11.5% for the evaluation of transients for Cycle 26 and beyond. Cycle 26 started operation in 2011. The results of this transient evaluation are available in the MNGP cycle 26 supplemental reload licensing report (SRLR) that includes MELLLA+ conditions and evaluations provided as Enclosure 3 to L-MT-12-054 (Reference 15-4).See Enclosure 2 for a markup of L-MT-08-052, Enclosure 5, reflecting these changes.References 15-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML0832301 11)Page 40 of 80 L-MT-12-114 Enclosure 1 15-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " Monticello Extended Power Uprate: Response to NRC Reactor Systems Review Branch and Nuclear Code and Performance Review Branch Request for Additional Information (RAI) dated March 23, 2009 and Nuclear Code and Performance Review Branch Request for Additional Information dated April 27, 2009 (TAC No.MD9990)," L-MT-09-049, dated July 23, 2009. (ADAMS Accession No.ML092090219) 15-3 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "

Subject:

Monticello Extended Power Uprate: Updates to Enclosures 1, 3, 5 and 7 of L-MT-08-052, and Enclosure 3 of L-MT-09-047, (TAC MD9990)," L-MT-10-002, dated January 25, 2010. (ADAMS Accession No. ML100270020) 15-4 Letter from M A Schimmel (NSPM), to Document Control Desk (NRC), "

Subject:

Supplement to Maximum Extended Load Line Limit Analysis Plus License Amendment Request (TAC ME3145)," L-MT-12-054, dated June 27, 2012.(ADAMS Accession No. ML12192A1 04)Page 41 of 80 L-MT-12-114 Enclosure 1 ITEM 16 -REACTOR HEAD SPRAY NOZZLE FATIGUE ASSESSMENT NRC REQUESTED INFORMATION:

L-MT-08-052, Enclosure 5, Section 2.2.3, including Table 2.2-3, indicates that the Reactor Head Spray Nozzle piping exists.However, this piping has been removed and the nozzle is now permanently blank flanged. Provide corrected information.

NSPM RESPONSE: NSPM letter L-MT-08-052 (Reference 16-1), Enclosure 5, Section 2.2.3, including Table 2.2-3, indicates that Reactor Head Spray Nozzle piping exists. However, other locations in the EPU documentation contain reference only to the Reactor Head Spray nozzle (Reference 16-1, Enclosure 5, pgs 2-42 and 2-44; Reference 16-2, Enclosure 1, pgs 1, 2 and 4). Further, NSPM stated in Reference 16-3, Enclosure 1, RAI response No. 14 that the Reactor Head Spray line (piping) and valves have been removed.For clarification, the Reactor Head Spray piping has been removed from the plant and the remaining Reactor Head Spray nozzle is blank flanged off. References to Reactor Head Spray piping or Reactor Head Spray Nozzle piping are incorrect and are being deleted.See Enclosure 2 for a markup of L-MT-08-052, Enclosure 5, reflecting these changes.References 16-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML0832301 11)16.2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate (USNRC TAC MD8398): Acceptance Review Supplemental Information Package 6", L-MT-08-043, dated June 12, 2008.(ADAMS Accession No. MIL081640435) 16-3 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Containment and Ventilation Review Branch (SCVB) Request for Additional Information (RAI) dated March 19, 2009, and March 26,2009 (TAC No. MD9990)", L-MT-09-048, dated July 13, 2009. (ADAMS Accession No. ML092170404)

Page 42 of 80 L-MT-12-114 Enclosure 1 ITEM 17 -EMERGENCY OPERATING PROCEDURE FLOW CHART FOR ATWS NRC REQUESTED INFORMATION:

EOP Flow Chart for ATWS -Copy of C.5-2007, Rev. 15 was sent to NRC (Reference 17-1, Enclosure 1). C.5-2007 is now at Rev. 17.Briefly describe the change made and that this is a newly implemented change with no impact on event response.

Separate MELLLA+ from EPU in this discussion as both need to be addressed separately.

NRC will verify that safety evaluations (SEs) are compatible.

NSPM RESPONSE: In NSPM letter L-MT-09-049 (Reference 17-1), Enclosure 1; in response to NRC SRXB RAI 2.8.3-3, NSPM submitted EOP flow chart C.5-2007, Failure to Scram, Revision 15 to the NRC. Since that submittal, the flow chart has been revised and is now at revision 17.This change is in response to concerns regarding response to a high power ATWS with loss of the main condenser.

The changes place some of the non-time critical power leg steps into a separate procedure to allow the operators to rely on a single procedure and expedite getting to the time critical operator action (TCOA) of injecting standby liquid control (SBLC) in 124 seconds. The step to run back recirculation flow and then trip the recirculation pumps has been moved to a separate procedure.

No steps were eliminated, only moved to a separate procedure.

See Enclosure 2 for a markup of L-MT-09-049 reflecting these changes.A revised copy of C.5-2007 is provided in Enclosure 3.References 17-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " Monticello Extended Power Uprate: Response to NRC Reactor Systems Review Branch and Nuclear Code and Performance Review Branch Request for Additional Information (RAI) dated March 23, 2009 and Nuclear Code and Performance Review Branch Request for Additional Information dated April 27, 2009 (TAC No.MD9990)," L-MT-09-049, dated July 23, 2009. (ADAMS Accession No.ML092090219)

Page 43 of 80 L-MT-12-114 Enclosure 1 ITEM 18 -MAIN STEAM THERMOWELLS NRC REQUESTED INFORMATION:

L-MT-09-044 (Reference 18-1), RAI 28 response discussed a modification to remove or shorten the Main Steam (MS) thermowells in 2011 refueling outage to reduce the ratio of the vortex shedding frequency to the natural frequency of the MS thermowells to the CLTP value to minimize the potential of the system jumping into resonance.

Please confirm the status of this modification.

NSPM RESPONSE: NSPM will be performing a modification in the upcoming 2013 refueling outage to remove the existing MS thermowells and install plugs in their place.See Enclosure 2 for a markup of L-MT-09-044 reflecting these changes.References 18-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Mechanical and Civil Engineering Review Branch (EMCB) Requests for Additional Information (RAIs) dated March 28, 2009 (TAC MD9990)," L-MT-09-044, dated August 21, 2009. (ADAMS Accession No. ML092390332)

Page 44 of 80 L-MT-12-114 Enclosure 1 ITEM 19 -EPU MODIFICATIONS LIST CHANGES NRC REQUESTED INFORMATION:

Some modifications described in L-MT-08-052, Enclosure 8 have been eliminated from consideration as not required to support EPU.One new modification has been added. Provide updated information.

NSPM RESPONSE: NSPM letter L-MT-08-052 (Reference 19-1), Enclosure 8 provided planned modifications to implement the EPU at MNGP. Some information in this table is incorrect and requires revision.

In addition, letter L-MT-08-052, Enclosure 5, Section 2.5.4.4, also provided information related to planned modifications to implement the EPU at MNGP. Some information in this section is incorrect and requires revision.NSPM has identified three planned modifications that are included in the above reference correspondence that are no longer planned for the EPU implementation.

The three modifications are: 0 Reactor Feed Pump Discharge Check Valve Replacement

• Generator Hydrogen Coolers Replacement

• #11 Drain Cooler Replacement/Reanalysis The bases for not performing these modifications are as follows:* Reactor Feed Pump (RFP) Discharge Check Valve Replacement

-The existing 14" RFP discharge check valves were going to be replaced with 16" check valves when the RFP discharge piping was replaced with 16" piping. It was subsequently determined that the 14" RFP discharge piping does not need to be replaced.

Since the RFP discharge piping will stay 14", the valves are no longer being replaced.* Generator Hydrogen Coolers Replacement

-NSPM determined that the replacement of the Hydrogen Coolers is not required due to existing procedural guidance for monitoring hydrogen cold gas temperatures which provides adequate alarm margins and operator actions. Currently, operators monitor generator hydrogen temperature during operator rounds by procedure and annunciator.

The maximum operating H2 cold gas temperature at 45 psig of H2 pressure is 46°C (114 0 F) with a 5 0 C margin to the high cold gas alarm setpoint of 51'C (123°F).In addition, NSPM evaluated hydrogen cooler performance at EPU conditions with a service water temperature of 90 0 F. The evaluation concluded that the maximum expected generator cold gas temperature at EPU conditions with a service water temperature of 90OF is 47.9°C. Therefore, there is a 3°C margin to the alarm setpoint of 51 °C where operator action to reduce generator power would be required.* #11 Drain Cooler Replacement/Reanalysis

-Calculations determined that the #11 feedwater heater drain coolers, E-DC-1 1A and E-DC-1 1 B, can pass the higher required EPU flows. This is based on the assumption that the 14" diameter pipe Page 45 of 80 L-MT-12-114 Enclosure 1 segments between the coolers and condenser, as well as the associated condenser penetrations, are increased to 16" in diameter.

Portions of these heater drain lines were modified to increase their diameter to 16" during the 2011 refuel outage. The remaining portions of the piping modifications will occur during the 2013 refuel outage. Monitoring of the drain cooler's condition will continue to be performed under the plant's life cycle management (LCM) process.NSPM also identified one new modification required to support EPU conditions.

This modification is based on the discussion provided in Item 9, which identified a change to the Post-LOCA heatup of the RHR and CS rooms (see Item 9 for details).Pipe Support SR-530 modification

-NSPM reviewed the Post-LOCA torus room temperature and determined that it increases to about 180 0 F. Based on these results, piping and components in the torus and surrounding areas were reviewed for effects of this change. NSPM determined that these results affected the Residual Heat Removal Service Water (RHRSW) discharge pipe from the RHR heat exchangers and the RHR heat exchanger supports.Based on the revised Post-LOCA temperature increase, NSPM reanalyzed the piping, supports, grouted penetrations and equipment nozzles for compliance with the ANSI B31.1, AISC & ACI code acceptance criteria, and manufacturers' allowable stresses.

The analysis revealed increased applied loads to pipe supports SR-530.However, pipe support SR-530 was determined to require modification to remain within code allowables under the new loading.Pipe Support SR-530 supports line SW6-16"-JF.

It is located in the "B" RHR room at approximate elevation 929'. This line transports service water from the Reactor Building Closed Cooling Water (RBCCW) heat exchangers to the SW discharge.

The modification consists of replacing the support pipe clamp, strut, and structural attachment.

An engineering change has been initiated to issue the updated piping calculations and to document the modification of support SR-530 for Extended Power Uprate (EPU) conditions.

In addition, the titles of Tables 8-2 and 8-3 were modified to remove reference to the planned implementation of the modifications.

The planned dates and refueling outages are not pertinent information and do not reflect the final implementation of the modifications.

See Enclosure 2 for a markup of the EPU documentation reflecting these changes.Page 46 of 80 L-MT-12-114 Enclosure 1 References 19-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML0832301 11)Page 47 of 80 L-MT-12-114 Enclosure 1 ITEM 20 -ANNULUS PRESSURE (AP) LOADS NRC REQUESTED INFORMATION:

Determine if the EPU documentation includes coverage of Annulus Pressure (AP) loads. Add to EPU LAR documentation if necessary.

NSPM RESPONSE: GE Hitachi Nuclear Energy (GEH) has investigated a concern related to the impact of various plant improvements with regard to changes in the evaluation of AP loads and the subsequent impact of changes in AP loads on the performance of the Bio-Shield Wall (BSW) doors during events where the AP loads were postulated to increase.While reviewing the AP loads analysis for another plant, it was found that off-rated conditions, which generate higher total mass release than the design power and core flow point, result in higher peak pressure differential on the BSW door. These loads have been evaluated at MNGP. A modification was completed in order to remove the bricks in the bioshield to prevent the potential for higher energy missiles during the off-rated conditions.

In addition, NSPM verified that the design differential pressure capability of the bioshield doors bounds the expected LOCA during the evaluated off-normal conditions.

Although not part of the design basis, the Minimum Pump Flow Point on the MELLLA line (1210.4 MWt/43.3%

Core Flow) is also evaluated.

The energy release at this point is calculated to be 17.4% greater than the release at the original basis of 1670 MWt/100% Core Flow resulting in an annulus pressure of 42.3 psid. This is the limiting differential pressure analyzed.

This differential pressure (dp) bounds the 40 psid value calculated for both current licensed thermal power (1775 MWt) and extended power uprate (2004 MWt). The BSW doors are designed for a dp of 54 psi. Therefore the BSW doors have adequate margin for expected dp loads.There are no proposed changes to EPU documentation resulting from this response.Page 48 of 80 L-MT-12-114 Enclosure 1 ITEM 21 -EMERGENCY CORE COOLING SYSTEM (ECCS) ANALYSIS CONFIRMATION NRC REQUESTED INFORMATION:

Need to confirm that the EPU 10CFR 50.46 ECCS analysis includes all the latest GEH reported changes to the Appendix K analysis.

Add to EPU LAR documentation if necessary.

NSPM RESPONSE: GEH has confirmed to NSPM that the EPU ECCS-LOCA analysis includes all relevant 10 CFR 50.46 notifications, with the exception of the 10 CFR 50.46 Notification Letter 2012-01.Notification 2012-01, which is related to implementation of the GEH PRIME thermal-mechanical model, is not considered an Evaluation Model Error, but rather a Change.No fault is implied or inferred with current analyses and analyses pending NRC review.No operation out of compliance to Acceptance Criteria with the GESTR-based model is reported.

Rather, it is seen as an evolution of the model and the reported change in Peak Clad Temperature (PCT) is an estimated impact if the PRIME thermal-mechanical model is used instead of the GESTR-based model. It is considered "implemented" in that the GEH Evaluation Model will henceforth be performed using PRIME.The impact for Monticello of the PRIME implementation is assessed as 45°F, as reported in the GEH 10 CFR 50.46 Notification Letter 2012-01 dated November 29, 2012. Given the EPU Large Break PCT (LBPCT) of 2140 OF, this impact will present no violation to the 2200°F limit. As it is under the 50OF significance threshold, and confirming resolution of all prior Notification Letters in the analysis as it stands, no reporting requirement would be seen as necessary for the EPU ECCS-LOCA basis in response to Notification 2012-01.There are no proposed changes to EPU documentation resulting from this response.Page 49 of 80 L-MT-12-114 Enclosure 1 ITEM 22 -CONFIRMATION THAT OSCILLATION POWER RANGE MONITOR (OPRM) TESTING IS COMPLETED NRC REQUESTED INFORMATION:

Statements in the EPU LAR describe pre-operational testing of the OPRMs and the results of that testing and that MNGP was permitted 90 days of testing before declaring OPRMs operable.

NSPM please clarify the accuracy of this language, or supersede it.NSPM RESPONSE: NSPM letter L-MT-09-049 (Reference 22-1), Enclosure 1, RAI SRXB RAI No. 2.8.3-4 provided a response to the NRC request concerning an update on OPRM-based Long Term Stability Solution (LTSS) Option III implementation at MNGP. The NSPM response in part stated: "The OPRM-based Option Ill LTS equipment was installed in the plant as part of the PRNMS modification at MNGP. Both OPRM trip outputs will be disabled during the OPRM monitoring and evaluation period. The period extends from the startup following PRNM system installation to 90 days of steady-state operation after reaching full power. The monitoring period is described in Section 5.1.2 of Enclosure I of the MNGP PRNM licensing amendment request dated February 6, 2008 and in NSPM letter dated November 6, 2008. It is currently scheduled to be armed on August 31, 2009." The OPRM-based Option III LTSS equipment is installed and was turned over to plant Operations in September 2009. The monitoring and evaluation period is complete.See Enclosure 2 for a markup of L-MT-09-049 reflecting these changes.References 22-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " Monticello Extended Power Uprate: Response to NRC Reactor Systems Review Branch and Nuclear Code and Performance Review Branch Request for Additional Information (RAI) dated March 23, 2009 and Nuclear Code and Performance Review Branch Request for Additional Information dated April 27, 2009 (TAC No.MD9990)," L-MT-09-049, dated July 23, 2009. (ADAMS Accession No.ML092090219)

Page 50 of 80 L-MT-12-114 Enclosure 1 ITEM 23 -FATIGUE MONITORING PROGRAM NRC REQUESTED INFORMATION:

EPRI Fatigue Monitoring Program is using the Green's Function, which is not satisfactory to NRC. Nine Mile Point had a license condition for this issue. NSPM please assess if any changes to the Fatigue Monitoring program are necessary and document that to NRC. If NSPM is going to use stress based program, NSPM will need to include a description of the six components.

NSPM RESPONSE: RIS 2008-30 describes a concern regarding the methodology used by some licensees to demonstrate the ability of nuclear power plant components to withstand the cyclic loads associated with plant transient operations for the period of extended operation.

This particular analysis methodology (called FatiguePro) involves the use of the Green's (or influence)

Function to calculate the fatigue usage during plant transient operations such as startups and shutdowns.

Specifically, RIS-2008-30 expresses concerns about whether the use of a single stress component (as opposed to the standard six stress components required by ASME Code) as an input to Green's Function used in the software is sufficiently conservative with regard to determining fatigue accumulation.

RIS-2008-30 was evaluated in January 2009 for impact on the Monticello Fatigue Monitoring Program. Monticello does not currently use FatiguePro or any other fatigue monitoring software that uses the simplified approach of a single stress component as input to the Green's Function for determining fatigue usage. Monticello performs manual cycle counting in accordance with ASME Code,Section III requirements and all thermal transient calculations used in monitoring fatigue accumulation are derived from the six stress components as required by the ASME Code.The most recent fatigue monitoring program update was performed with the support of Structural Integrity Associates (SIA). SIA confirmed that the FatiguePro software was not used during the update of the Monticello Fatigue Monitoring Program and the software that was used during the update did not use the simplified approach for input to the Green's Function.There are no proposed changes to EPU documentation resulting from this response.Page 51 of 80 L-MT-12-114 Enclosure 1 ITEM 24 -MOTOR OPERATED VALVE (MOV) PROGRAM CHANGES NRC REQUESTED INFORMATION:

Changes to HELB environmental profiles, changes to valve component performance assessments and implementation of new calculations associated with an MOV program update has resulted in need to adjust 10 MOV switches versus the one switch previously reported.

After EPU submittal to the NRC, NSPM performed a comprehensive evaluation and design basis reconstitution of the MNGP GL 89-10 MOV program. The HELB and EPU dependencies and programmatic improvements resulted in increased maximum expected differential pressures (MEDP) for certain valve stroke scenarios.

This included new thrust requirements and modified torque switch settings above thrust setting to maintain margin. Identify the MOVs that changed. State the functional performance requirements for the MOVs. Identify how they meet GL 89-10 and GL 95-06 and any ASME OM code requirements.

Provide a background of the change to the analysis that led to the change in the number of MOVs. Discuss how this impacts the IST 1Oyr interval testing of the MOVs.NSPM RESPONSE: In NSPM letter L-MT-08-039 (Reference 24-1), Enclosure 2, NSPM provided responses to RAIs 1, 2 and 3 that included discussion concerning the MNGP Motor Operated Valve (MOV) program and details concerning changes required to the MOV program to accommodate EPU conditions.

Since this submittal, changes have occurred to the MNGP MOV program that require NSPM to update the NRC regarding the MOV program and the impact on EPU documentation.

The following discussion provides the bases for the changes to the MOV discussion in EPU documentation.

NSPM performed a comprehensive reconstitution of the MNGP MOV program since submittal of the EPU LAR (Reference 24-2). The HELB and EPU dependencies and programmatic improvements resulted in increased MEDP for certain valve stroke scenarios.

This included new thrust requirements and modified torque switch settings above the current thrust setting to maintain margin.The reconstitution consisted of:* Development of revised MOV functional analyses (system calculations) for differential pressures, temperatures, and flows with regard to system condition changes pursuant to the EPU, HELB and original system requirements.

• Revision of the MOV functional analyses to document the results satisfactorily for CLTP conditions.

• Updating of the valve coefficient of friction (COF) analysis.* Updating of voltage (effects of RHR / CS Pump Motor Starting Transients on MOV Performance) and environmental temperature (MOV Environmental Temperatures) analysis.Page 52 of 80 L-MT-12-114 Enclosure 1 Updating of the analysis to include the most recent diagnostic test data and test equipment accuracies.

The function performance requirements did not change from those described in the L-MT-08-052, Enclosure

5. Only the valves requiring switch setting adjustments changed based on the reconstitution effort. Based on this reconstitution effort Table 24-1 identifies MOVs that require switch adjustments to fully comply with the EPU performance requirements:

Table 24-1 -MOVs Requiring Switch Adjustment to Support EPU Valve Name MO-2009 12 RHR Torus Cooling Injection Valve MO-2014 11 LPCI Inboard Injection Valve MO-2015 12 LPCI Inboard Injection Valve MO-2020 11 Containment Spray Outboard Valve MO-2021 12 Containment Spray Outboard Valve MO-2023 12 Containment Spray Inboard Valve MO-2034 HPCI Steam Line Isolation Valve MO-2035 HPCI Steam Line Isolation Valve MO-2061 HPCI Torus Suction Inboard Isolation Valve MO-2062 HPCI Torus Suction Isolation Valve The switch adjustments are scheduled for completion in the 2013 refueling outage.Once the switch adjustments are completed, the valves listed above will be fully capable of performing their post-EPU safety functions, including meeting the requirements of GL 89-10 and GL 96-05.The reconstitution determined that all affected valves have positive periodic verification (PV) margin and all valves are within their respective PV testing intervals as defined by GL 89-10 / GL 96-05 requirements.

Additionally, because the valves meet the PV requirements of GL 96-05, they also meet the requirements of the ASME OM code case (i.e., OMN-1 code case relies on the periodic verification testing program set-up by the MNGP GL 89-10 / 96-05 testing program).Finally, the MNGP IST program establishes (under ASME OMN-1 Code Case) a test interval for a given MOV based on risk and margin up to a maximum of 10 years between tests. The test interval requirements of the MNGP IST program are not impacted by the changes from the reconstitution of the MNGP MOV program.See Enclosure 2 for a markup of L-MT-08-52 and L-MT-08-039 reflecting these changes.Page 53 of 80 L-MT-12-114 Enclosure 1 References 24-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " Monticello Extended Power Uprate (USNRC TAC MD8398): Acceptance Review Supplemental Information," L-MT-08-039, dated May 28, 2008. (ADAMS Accession No. ML081490639) 24-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML0832301 11)Page 54 of 80 L-MT-12-114 Enclosure 1 ITEM 25 -SHROUD SCREENING CRITERIA FLAW EVALUATION AND RECIRCULATION LINE BREAK (RLB) LOADS NRC REQUESTED INFORMATION:

GEH issued Safety Communication SC-09-03 in 2009 concerning Shroud Screening criteria flaw evaluation and Recirculation Line Break (RLB) loads. Make a statement concerning the results of the NSPM review of that SC and identify the scope of any corrective actions (if necessary) that are being taken.NSPM RESPONSE: GEH Safety Communication 09-03 determined that faulted shroud loading conditions did not consider RLB loads in screening for several plants. NSPM entered this communication into the MNGP corrective action program and requested GEH review the MNGP faulted shroud loading evaluation.

GEH determined that the MNGP shroud loading evaluation did not include RLB loads.NSPM corrected this condition by having GEH provide revised faulted shroud loading values including RLB loads. The loads evaluated were applicable to EPU conditions.

NSPM then updated the shroud inspection criteria evaluation for the MNGP with the new faulted shroud loading values and determined there was no effect on the inspection interval for the shroud as a result of the additional RLB loads.There are no proposed changes to EPU documentation resulting from this response.Page 55 of 80 L-MT-12-114 Enclosure 1 ITEM 26 -HIGH ENERGY LINE BREAK (HELB) ANALYSIS RECONSTITUTION NRC REQUESTED INFORMATION:

NSPM identified the following changes to the HELB Analysis: 1. Environmental profiles changed due to final resolution of various corrective actions discussed in L-MT-08-052, Enclosure

5.2. Completion

of detailed design of modifications

3. Changes in GOTHIC software versions 4. Final assessment of cracks for new feedwater piping design is not yet complete.NRC requested that NSPM discuss changes to HELB, provide tables of changed profiles, temperatures, flood levels, etc. NSPM should state that licensee has not changed the method for determining break locations.

NSPM should state that the program maintains compliance with the Giambusso letter and IEB 79-01 B. NSPM should reference the discussion in L-MT-10-025.

Complete discussion regarding jet impingement and pipe whip. NSPM should state that there are no new break locations or if new break locations why are they acceptable.

NSPM RESPONSE: Changes to the HELB model and Code Since November 2008, the MNGP HELB program performed a reconstitution to provide greater accuracy in calculations representing conditions in the Reactor and Turbine buildings following a HELB event. This reconstitution resulted in enhancements to the GOTHIC model which incorporated better modeling practices and more accurate break/crack characteristics.

As a result of an internal audit of the model, several changes were made to the program. It should be noted that the enhancements were applied to the model, and as such, changes were applied once the HELB conditions were reanalyzed.

The enhancements are: 1. Adjust the liquid drop size to the GOTHIC manual recommended size of 0.0039 inches.2. Adjust the wall and floor HTC (heat transfer coefficient) to better account for transition from vapor to liquid heat transfer.3. Adjust the boundary condition pressure to more closely match the break pressure where there was a substantial difference.

The updated HELB calculations did not incorporate any changes in pipe break methodology.

Most changes involved a re-analysis of breaks using more conservative assumptions of mass and energy release with more accurate plant conditions.

The liquid break calculation inputs were updated to consider: 1. Double-ended break flow to include flow from both ends of postulated breaks.Page 56 of 80 L-MT-12-114 Enclosure 1 2. System depletion to include mass and energy that exists in system piping and pressure vessels.3. A conservative change in the assumption for isolation valve stroke time from ASME Section XI Limiting Stroke Time to the value listed as the maximum valve operating time in the USAR.4. A conservative change for flow reduction assumptions with valve closure. CLTP analysis assumed flow was reduced proportional to isolation valve percent closed position.

The EPU analysis assumed 100% break flow until isolation valve was fully closed.5. The liquid mass from fire protection sprinkler systems postulated to actuate from HELB events was included.6. Upgrade computer code from GOTHIC version 4.0 to GOTHIC version 7.1 or later versions.Steam breaks also have been updated to consider the above conditions.

The only scenarios not accounting for all of the above were steam breaks isolated by steam isolation valve closure. These analyses assume the break flow reduces proportionally with the valve as it closes. The break flow decreases throughout the valve closure time.The initial analyses performed to support the EPU LAR submittal used GOTHIC version 7.1 as the evaluation tool. For the reconstitution of HELB performed after the LAR submittal, version 7.2a was used. Both versions of GOTHIC (7.1 and 7.2a) have been benchmarked in calculations in accordance with NSPM requirements.

These benchmark calculations determined that both versions of GOTHIC are acceptable for use. Both versions are supported by the software developer, and meet the requirements for use in evaluation of safety related activities as they are included in the MNGP Software Quality Assurance (SQA) Program.Because no fundamental change to HELB methodology occurred, the program remains in compliance with the Giambusso Letter and IEB 79-01 B, as implemented in the MNGP design and licensing bases. Therefore, a 10 CFR 50.59 evaluation was not required for the reconstitution effort, and MNGP remains compliant with the statements regarding applicability of 10 CFR 50.59 provided in NRC correspondence L-MT-10-025, dated April 6, 2010.The following tables, Tables 26-1 and 26-2 are provided to update the HELB temperatures, pressures and flood levels.Page 57 of 80 L-MT-12-114 Enclosure 1 Updated temperatures, pressures and flood levels (Note: underlined values represent CLTP to EPU increases):

Turbine Building: (Note: Turbine Building volumes were consolidated from 44 volumes to 37 to more accurately represent areas that had been partitioned in the model but did not have a physical door or wall separating the volumes. CLTP columns with an

• indicate that the effects of the consolidation no longer permit a direct comparison of these volumes)Table 26-1 -Turbine Building HELB Results [ PU Analys Rsults EQ CLTP values from EQ Part B Part B Turbine Building Maximum MaxmuMximum Volume Volume Description Presur Temperatur Level Pressure Temperature Flooding_____) (degF) (ft) psia deg F ft 1 Motor Control Center B-33A & B, and B-12 1.2 2126 15.3 212.2 5.58 2 Turbine Building Southeast Corner near MCC B-33 3 15.27 212.2 2.61 3 Lube Oil Reservoir and Reactor Feed Pump Area1 212.3 3 15.13 212.3 2.25 4 Lube Oil Storage Tank Room 214.8 105.6 0 14.75 104.6 0 5 Turbine Building Corridor Northeast 911' El 1.24 3 14.82 204.1 2.85 6 Water Box Scavenging System Area 1 1 3 14.8 188.2 3.02 7 Turbine Building Sump & MCC B-31 Area 3 14.71 106.03 0 8 4 KV and Load Center Division A 0 14.71 106.6 0 9 Hallway outside Air Ejector Room Entrance Door 15 14.5 15.3 * * *10 Hydrogen Seal Oil Unit and Condensate Pump Area North 1 187.3 3 15.01 139.9 0.13 11 Hydrogen Seal Oil Unit and Condensate Pump Area South 1525 19 13 * * *12 Mechanical Vacuum Pump Area 1.26 189.4 6 14.73 203.7 0.05 13 Condensate Backwash -Receiving Tank Area ..27 184 614.73 120.9 0.03 14 Air Ejector Room 154 2 29 15.26 284.95 1.44 15 Turbine Basement Condenser Area i1.58 211.9 5 15.79 247.15 1.12 16 Pipe Tunnel to Intake 9.1 14.76 115.14 0 17 Intake EntryArea 14.75 104.9 0 18 Intake Structure Pump Room 1 0U 14.75 104.58 0 19 Circ Water Pump Area 192. 14.76 104.6 0 20 Turbine Building 931'El East 120.1 0 14.71 171.4 0.23 21 FW Pipe & Cable Tray Penetration Room I094 0 14.84 149.8 0.01 22 Turbine Building 931' El East Vent Chase 211 15.08 211.3 0.04 23 Auxiliary Boiler Room 14.7 10. 0 14.7 104 0 Page 58 of 80 L-MT-12-114 Enclosure 1 Thhl~ 2R~1 -Tiirhin~ Riiilrlinn HEI B Rc~.ilt~3011 E~nfl.lId~

Annkinlin D*.mH.Tabe 2 -1* -T b .-L R u 9U0 n.a.Mew...

..ew EQ CLTP values from EQ Part B Part B Turbine Building M Max Volume Description Pressure Temperature Level Pressure Temperature Flooding__(po) (deg F) (f0t psia deg F ft 24 East Electrical Equipment Room and 13 EDG 14.7 104.3 0 14.7 104 0 25 Hot Machine Shop 14.94 107.9 0 14.7 104 0 26 Turbine Building Corridor Southeast Corner 931' El 15.12 178.4 0 14.85 187.9 0.06 27 Turbine Building Corridor Northwest and Hallway to No. 11 15.14 174.1 0 14.8 105 0 D.G. Entry 931' El 28 No. 11 Diesel Generator Room Entry Area 14.7 10.6 0 14.7 104 0 29 No. 11 Diesel Generator Room 14,7 0 14.7 104 0 30 No. 12 Diesel Generator Room 14.7 0 14.7 104 0 31 4KV and Load Center Division B 14.84 131.2 0 14.71 115.78 0 32 Stator Water Cooling Area 14.84 129-5 0 14.71 118.34 0 33 Valve Operating Gallery and Condensate Demin Panels Area 15.21 0 15 186.3 0.01 34 Turbine Building Railroad Car Shelter 15.16 203.4 14.98 195.92 0.04 35 Cable Chase 941' El 124.4 0 14.71 123.58 0 36 Turbine Building Northwest Stairway from 941' to 951' El 15.18 200. 0 14.71 104.1 0 37 Turbine Deck 951' to 1004' El 15.16 248.2 0.2 15.08 231.5 0.35 Page 59 of 80 L-MT-12-114 Enclosure 1 Reactor Building: (Note: LOCA GOTHIC results included for EQ peaks)Table 26-2 -Reactor Building HELB Results EPU HELB/LOCA Analvsis Results EQ Maximum Maximum Maximum CLTP values from EQ part B Part B Reactor Building Volume Leve Temp. Pressure Flooding Temp. Pressure Volume Description F I ft deg F psia 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 RHR and Core Spray Pump Room, Division I RHR and Core Spray Pump Room, Division I Stairway RHR and Core Spray Pump Room, Division II RHR and Core Spray Pump Room, Division II Stairway RCIC Room Reactor Bldg Elevation 896' Equipment and Floor Drain Tank CRD Pump Room HPCI Room Suppression Pool Area -Northeast Suppression Pool Area -Southeast Suppression Pool Area -Southwest Suppression Pool Area -Northwest East Shutdown Cooling Room B.1.9 CRD Hydraulic Control Unit Area -East 935' Elevation TIP Room Steam Chase TIP Drive Room CRD Hydraulic Control Unit Area & HVAC Areas- NW 935' El CST Pump Transfer DW Equip Hatch Entrance Areas -SW 935'West Shutdown Cooling Room 21 1/3B B.1.14 PIPE Chase 974'Pipe Chase 974'MCC and Standby Liquid Control System Area -East 962' El Contaminated Tool Storage -East 962' El MG Set Airlock 962' North of Reactor Shield Wall Reactor Recirculation Pumps MG Set Room 116.7 14.96 0.05 142.97 14.86 0 124.3 14.9 0.01 142.97 14.85 0.6 146.7 14 0.05 143.8 14.98 0 143.9 14.95 0 144.4 14.97.6 288.9 15.08 0.05 256 15.15 0.7 28 15.81 3.95 263.6 15.63 0.6 293.7 15.01 4.38 240.4 15.19 0 0 272.6 16.05 0. 20. 57 0.01 187.6 15.59 0.6 2 0 159.9 15.59 0. 0.9 1.9 0 158.7 15.59 0. 2 1 0.01 193 15.59 0 174 14.82 0.24 127.3 14.88 0 185.7 14.82 0.27 153.3 14.83 0.1 211.8 15.03 0.05 209.6 15.3 5.8 3109 20.88 6.68 311.3 21.16 0 2 0 222.4 15.14 0 22 14.92 0.68 208.1 15.11 0.1 291 14. 0.53 175.9 15.13 S 148 0 112.5 15.14 0 18.5 14.81 0 112.2 14.87 0 3 14.8 0 170.4 14.84 0 17. 4.82 0 143.7 14.87 0 04 14.7 0 104 14.7 0 1 1 14.82 145.8 14.85 0 118 14.71 0 109.1 14.89 Page 60 of 80 L-MT-12-114 Enclosure 1 I able 2.6-2 -Rem o~r BuildIing flr-Lo Results EIU I1ELB/LOCA Aflas IS KsuIts EQ Maximum Maximum Maximum CLTP values from EQ part B Part B Reactor Building Volume Level Temp. Pressure Flooding Temp. Pressure Volume Description ft d.gF Psia .ft deg F psia 27 Cooling Water Pump and Chiller Area -West 962' El 0 245.8 14.86 0.01 203.6 14.99 28 RWCU Pump Room B and Hallway 1 212.2 14.88 0.38 216.7 15.85 29 RWCU Pump Room A 1 212.5 14.94 0.3 214.6 15.85 30 RWCU Heat Exchanger Area 1 221.1 17.59 0.27 220.5 17.2 31 RWCU Area Behind Hx Exchanger 1j 1. 17.58 0.27 188.3 17.19 32 RWCU Isolation Valve Room 218.6 143 0.19 164.1 15.85 33 MCC and Instrument Rack C-55 Area 0 14.88 0 128.3 14.99 34 CGCS-A Recombiner Area 0 J1§ 14.81 0.005 168.3 14.83 35 Cooling Water Heat Exchanger and CGCS-B Recombiner Area 0 207.4 14.81 0.02 207.8 14.84 36 Standby Gas Treatment System B -Train Room 0 1 14.84 0 142.4 14.88 37 Standby Gas Treatment System Fan Room 0 178.8 14.84 0 112.8 14.88 38 Standby Gas Treatment System Airlock 0 100.3 14.7 0 100 14.7 39 Standby Gas Treatment System A -Train Area 0 129.5 14.85 0.01 215.3 14.87 40 Reactor Plenum Room 0 128.4 14.83 0 126.2 14.84 41 Reactor Recirculation MG Set Fan Room 0 117. 14.7 0 106.9 14.88 42 Corridor Outside Main Exhaust Plenum 0 207.2 14.81 0.01 204.7 14.85 43 Skimmer Surge Tank and Fuel Pool Pumps Area 0 123.6 14.8 0.01 128.3 14.83 44 Snubber Rebuild and Decontamination Area 0 128.8 14.8 0.01 160.8 14.82 45 Northeast Stairway 1001' El 0 2D6 14.8 0.01 169.7 14.85 46 Contaminated Equipment Storage Area 0 116.1 14.79 0.02 219.2 14.86 47 Northwest Stairway 1001' El 0 168.3 14.81 0 101.5 14.84 48 Refueling Floor 1027' El 0 1.39.7 1 !478 0.01 131.1 14.8 Page 61 of 80 L-MT-12-114 Enclosure 1 Pipe Whip and Jet Impingement:

Pipe whip and jet impingement loads resulting from high energy pipe breaks are directly proportional to system pressure.

Because EPU conditions do not result in an increase in the pressure considered in the high-energy piping evaluations, there is no increased pipe whip or jet impingement loads on HELB targets or pipe whip restraints.

Installation of new condensate and feedwater pumps with associated piping modifications include an evaluation of HELB target impact as part of the planned modification.

Pipe whip and jet impingement analyses are pending for the Condensate pump, Feedwater pump and piping replacement modifications.

New Break Locations:

EPU modification to the feedwater system resulted in one new limiting (for flooding)postulated 14" line crack at the inlet to the 14 feedwater heater. The results of this evaluation indicated slightly higher temperatures near the end of some Turbine Building bounding temperature profiles; however, there was no resultant impact to EQ equipment.

The new crack did not result in any new jet impingement or pipe whip targets. Peak profile temperatures increased in volumes that did not contain EQ equipment.

No mild volumes changed to harsh with this additional HELB analysis.Changes to EPU documentation The following locations contained information related to HELB in the EPU documentation:

L-MT-08-052, Enclosure 5, Sections 2.2.1.2, 2.2.2.1and associated tables are marked up to indicate the changes identified in this review.L-MT-08-052, Enclosure 17 -Provided a section entitled "NSPM Revised Response to NRC Electrical Engineering Branch (EEEB) Review Item documented in L-MT-08-042." Included within that response NSPM provided a document entitled "Monticello Extended Power Uprate Task Report T1004 -Environmental Qualification." Also. included were draft markups to EQ files. This information is superseded by the revised information provided in this item and the information provided in item 27. No further markup is provided.L-MT-09-044, EMCB RAIs 3(a), 5, 6(a), 6(b), 7, 8, 12(b), 13 including Table 1, 17(a) and 17(b) are marked up to indicate the changes identified in this review.L-MT-09-046, SBPB RAI 2.5-1 See Enclosure 2 for a markup of EPU documentation reflecting these changes.Page 62 of 80 L-MT-12-114 Enclosure 1 References 26-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "License Amendment Request: Extended Power Uprate (TAC MD9990)," L-MT-08-052, dated November 5, 2008. (ADAMS Accession No. ML0832301 11)26-2 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), " Monticello Extended Power Uprate: Response to NRC Mechanical and Civil Engineering Review Branch (EMCB) Requests for Additional Information (RAIs) dated March 28, 2009 (TAC MD9990)," L-MT-09-044, dated August 21, 2009. (ADAMS Accession No. ML092390332) 26-3 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Balance of Plant Review Branch (SBPB) Request for Additional Information (RAI) dated March 23, 2009 (TAC No.MD9990)," L-MT-09-046, dated June 12, 2009. (ADAMS Accession No.ML092390332)

Page 63 of 80 L-MT-12-114 Enclosure 1 ITEM 27 -EQUIPMENT QUALIFICATION PROGRAM RECONSTITUTION NRC REQUESTED INFORMATION:

EQ files were in draft form when presented in EPU LAR. Confirm EQ files complete to NRC. MNGP EQ program meets Division of Operating Reactors (DOR) Guidelines and USAR requirements.

Identify that the calculations, radiation levels and temperature changes have been reconstituted.

Identify what has changed (all changed values).NSPM RESPONSE: Environmental Qualification Extended Power Uprate Update The Environmental Qualification (EQ) Program has been reconstituted to incorporate the environmental conditions associated with increasing reactor thermal power from 1775 MWt to 2004 MWt. Revised environmental conditions were incorporated into document EQ-PART-B, Environmental Specifications.

All equipment within the EQ Program was evaluated to ensure that qualification would be maintained in accordance with 10 CFR 50.49 under these new conditions.

Changes to the EQ files and EQ-PART-B are complete.The EQ Program at MNGP was developed to the guidance and requirements contained in the DOR Guidelines and category II of NUREG-0588 for equipment that predates the issuance of 10 CFR 50.49 as delineated in 10 CFR 50.49 paragraph (k). The EQ Program maintains compliance with 10 CFR 50.49 with incorporation of EPU plant conditions.

Normal Ambient Temperature There is no impact of EPU conditions on normal plant temperature inputs to qualified life assessments.

Normal plant area ambient temperature will continue to be monitored by the EQ program in lieu of using the maximum design temperature for assessing qualified lifetimes.

Normal and Accident Radiation Evaluation Environmental Qualification radiation analyses are based on the total combined normal and accident doses. Under EPU, the normal plant doses are generally increased by 13% over CLTP doses while some steam line containing areas also experience increased doses during shut-down due to moisture carry-over issue related to EPU. The accident dose calculation determined increases ranging from 2.5% to 8.3% for EPU over CLTP conditions.

The normal and accident EPU radiological conditions have been incorporated into EQ-PART-B and the equipment specific qualification files.Qualification is maintained with the exception of two level transmitters in the Torus compartment, LT-7338A and LT-7338B.

These transmitters were replaced for compliance with the EQ program under EPU conditions.

Page 64 of 80 L-MT-12-114 Enclosure 1 The beta dose specified for the Drywell in the MNGP EQ Program is taken from the DOR Guidelines as an unshielded 200 Mrad dose which was developed for a 4,100 MWt reactor. Therefore, there is significant beta dose margin included in the beta dose as it applies to MNGP because there is no increase in the Drywell beta dose for EPU.Drywell Environmental Conditions The time-dependent Drywell EQ accident temperature profile is graphically compared for CLTP and EPU plant conditions in Figure 27-1.Figure 27-1 -Drvwell Pre/Post-EPU EQ Temperature Comparison Drywell Pre/Post-EPU EQ Temperature Comparison 350 2S0 I200 ISO I I 100 I.-- -,0---- 0 1.001+01 1.---- 02 --- I.E 1. ,* ... I I 1.OOE,0, 1.0OE-02 1.OOE,.O1 1.00E+O0 1.00(.401 1.00(0e02 1.00(4.03 1.00(004 1.00E40.O 1.001E+06 1.00E+07 1.001.,06 Time (seconds)-EPU Temperature

--CLTP Temperature The CLTP EQ Drywell accident temperature did not bound the peak EPU accident temperature in the short term (by 3 0 F within the first 600 seconds) and also at greater than a million seconds in the long term. Also, the EPU EQ Drywell accident pressure has increased to 58.8 psia vs. the CLTP accident pressure of 54.2 psia. These changes have been incorporated into EQ-PART-B, Environmental Specifications, as shown in Figure 27-2. All affected EQ components are now evaluated to these new accident conditions in their respective qualification files and remain qualified.

Page 65 of 80 L-MT-12-114 Enclosure 1 Figure 27-2 -Post-EPU Drywell Temperature and Pressure Profiles Drywell Temperature and Pressure Profiles 350 70 60 300// \ 50 0 20 T ii E0 /2/ 150 ___I 20 100 10 1.OE-3 1.OE-2 1,OE-1 1.OE+O 1.OE+1 1.OE+2 1.OE+3 1.OE+4 1.OE+5 1.OE+6 1.OE+7 1.OE+8 Time (Seconds)-Temperature

--Pressure Drywell flooding is not affected by EPU conditions and remains at the 922-foot elevation.

The maximum ECCS flow (from the four RHR and two CS pumps) is 25,560 gpm, which is bounded by the calculated flow through containment vents at 27,233 gpm.Reactor Buildinq Environmental Conditions The comparison of CLTP and EPU accident conditions for HELB has been submitted under Item 26. Non-EPU issues associated with the previous HELB models were reconstituted which led to revision of EQ parameters.

These issues were resolved during the EPU update and contributed to many of the large changes in calculated accident conditions.

Some decreases in post-accident submergence levels are attributed to model enhancements.

There are four volumes that are now considered a harsh temperature environment during a HELB with the new accident conditions.

These volumes are 13, 33, 37 and 47.Volumes 13 and 33 were already considered harsh environments.

The equipment in these volumes is now evaluated to the higher EPU accident temperatures in the qualification files and qualification is maintained.

Equipment contained in volume 37 supports the Standby Gas Treatment system, which is only required for design bases LOCA conditions.

LOCA does not create a harsh temperature environment during the Page 66 of 80 L-MT-12-114 Enclosure 1 time the Standby Gas Treatment equipment is required to function.

Volume 47 does not contain EQ end devices.The comparison of CLTP to EPU accident temperatures for post-LOCA heat up is shown in Table 27-1. Volume 16 is now considered a harsh environment during a DBA LOCA. However, this volume is already a harsh environment during a HELB accident.Table 27-1, Post-LOCA Temperature Comparison Reactor EPU CLTP Building Temperature Temperature Volume (OF) (OF)1 109.7 142.97 2 111.5 142.97 3 146.7 143.8 4 142.5 143.8 5 112.6 109.9 6 140.3 140.4 7 123.9 116.3 8 <125 <125 9 179.1 160.4 10 179.1 159.9 11 179.1 158.7 12 179 157.3 13 118.3 112.6 14 115.6 107.5 15 122.5 106.3 16 154.4 135.2 17 115.7 108.1 18 121.4 109.3 19 121.4 108.3 20 119.9 112.5 21 118.5 112.2 22 119.1 106.7 23 118.2 105.4 24 104 104 25 119.1 113.9 26 118.2 109.1 27 121.3 109.1 28 124.7 120 29 124.1 120.1 30 130.1 120.2 31 132.2 120.2 32 125.4 120.2 33 121.3 115.6 Page 67 of 80 L-MT-12-114 Enclosure 1 Reactor EPU CLTP Building Temperature Temperature Volume (OF) (OF)34 119.3 107.9 35 119.3 107.8 36 129.1 134.4 37 129.1 112.8 38 100 100 39 129.5 126.3 40 116.7 105.6 41 117.2 106.9 42 119.2 104.6 43 114.3 109.7 44 117.8 108.1 45 115.2 104 46 116.1 107.2 47 118.8 100 48 115.4 103.9 EQ equipment has been evaluated to the new conditions associated with EPU in each equipment specific qualification file in terms of pressure, temperature and flooding.However, the revised heat balance for an increased as-built FW temperature (see item 10) remains to be evaluated in terms of bounding EQ profile. Changes to the bounding profile are expected to be very minor (as discussed in Item 10), as the overall peak temperatures are not affected.

Final documentation will assure compliance with the EQ program. Qualification is maintained for all equipment (note: two level transmitters in the Torus compartment, LT-7338A and LT-7338B required replacement to maintain qualification).

Turbine Building Environmental Conditions The EPU HELB evaluation identified areas within the Turbine Building that changed from a mild to harsh environment.

EQ-PART-B volumes 7, 8, 9, 10, 11, 13, 16, 27, and 36 become harsh under EPU. Walkdowns of these volumes were performed to identify safety related equipment in these new harsh areas that may fall under the scope of the EQ program. No discrete equipment was identified; however, some safety-related cabling was discovered.

These cables already existed in the EQ Program. The new locations were incorporated into the EQ Program Master List and the cable files were updated to include turbine building conditions.

In addition to the cable identified above, there is a single Valcor solenoid valve in the EQ program located in Volume 21. The solenoid valve remains qualified for the postulated conditions in the TB under EPU.Page 68 of 80 L-MT-12-114 Enclosure 1 Previous NRC Submittals L-MT-08-052, Enclosure 17, provided a revised response to information submitted in L-MT-08-042.

The NRC requested that NSPM provide the full and completed EQ analysis.

The NRC said this should include any reanalysis, re-qualification, or replacement of equipment.

The licensee must also describe how the equipment was evaluated (e.g., calculations, assessments, etc.) and show how the equipment remains bounded (i.e., provide the original design parameters and the updated values including the supporting calculations).

At that time the "full EQ analysis" was not completed.

In order to support NRC review, NSPM submitted task report T1004 and draft markups to EQ files. The drafts of the final EQ file changes included expected changes in temperature, pressure, and submergence by volume for the reactor building were provided.As indicated above the full EQ analysis is now completed with only minor exceptions.

Therefore, NSPM is including in this response a comparison of CLTP vs EPU for the Reactor building.

Tables 27-2, 27-3, 27-4 and 27-5 provide comparisons for pressure, water level and temperature between the final EPU analysis and the EQ-Part-B results that represent CLTP conditions.

Therefore, statements in the task report T1004 and the draft markups to EQ files are no longer applicable.

This work is now complete and superseded by the data provided in Tables 27-2, 27-3, 27-4 and 27-5 below.Page 69 of 80 L-MT-12-114 Enclosure 1 27-2 Reactor Building HELB Peak Ambient Pressure Comparisons RB Volume EPU Pressure EQ-Part-B CLTP Delta (psia) Pressure (psia) (psia)1 14.96 14.86 0.1 2 14.95 14.85 0.1 3 14.96 14.98 -0.02 4 14.95 14.97 -0.02 5 15.06 15.15 -0.09 6 15.81 15.63 0.18 7 15.01 15.19 -0.18 8 16.22 16.05 0.17 9 15.79 15.59 0.2 10 15.79 15.59 0.2 11 15.79 15.59 0.2 12 15.79 15.59 0.2 13 14.82 14.88 -0.06 14 14.82 14.83 -0.01 15 15.03 15.3 -0.27 16 20.88 21.16 -0.28 17 15.02 15.14 -0.12 18 14.92 15.11 -0.19 19 14.9 15.13 -0.23 20 14.83 15.14 -0.31 21 14.81 14.87 -0.06 22 14.82 14.84 -0.02 23 14.82 14.87 -0.05 24 14.7 14.7 0 25 14.82 14.85 -0.03 26 14.71 14.89 -0.18 27 14.86 14.99 -0.13 28 14.86 15.85 -0.99 29 14.94 15.85 -0.91 30 17.59 17.2 0.39 31 17.58 17.19 0.39 32 17.43 15.85 1.58 33 14.86 14.99 -0.13 34 14.81 14.83 -0.02 35 14.81 14.84 -0.03 36 14.84 14.88 -0.04 37 14.84 14.88 -0.04 38 14.7 14.7 0 Page 70 of 80 L-MT-12-114 Enclosure 1 RB Volume EPU Pressure EQ-Part-B CLTP Delta (psia) Pressure (psia) (psia)39 14.85 14.87 -0.02 40 14.83 14.84 -0.01 41 14.7 14.88 -0.18 42 14.81 14.85 -0.04 43 14.8 14.83 -0.03 44 14.8 14.82 -0.02 45 14.8 14.85 -0.05 46 14.79 14.86 -0.07 47 14.81 14.84 -0.03 48 14.78 14.8 -0.02 Page 71 of 80 L-MT-12-114 Enclosure 1 27-3 Reactor Building HELB Water Level Comparisons RB Volume EPU Level EQ-Part-B Level, Delta (inches) CLTP (inches) (inches)1 7.2 0.6 6.6 2 0 0.12 -0.12 3 7.2 0.6 6.6 4 0 0 0.00 5 7.2 0.6 6.6 6 8.4 47.4 -39.00 7 7.2 52.56 -45.36 8 7.2 13.32 -6.12 9 7.2 0.12 7.08 10 7.2 0 7.2 11 7.2 0 7.2 12 7.2 0.12 7.08 13 0 2.88 -2.88 14 0 3.24 -3.24 15 1.2 0.6 0.6 16 69.6 80.16 -10.56 17 0 0 0.00 18 0 8.16 -8.16 19 1.2 6.36 -5.16 20 1.2 0 1.20 21 0 0 0.00 22 0 0 0.00 23 0 0 0.00 24 0 0 0.00 25 0 0 0.00 26 0 0 0.00 27 0 0.12 -0.12 28 14.4 4.56 9.84 29 14.4 3.6 10.80 30 12 3.24 8.76 31 12 3.24 8.76 32 14.4 2.28 12.12 33 0 0 0.00 34 0 0.06 -0.06 35 0 0.24 -0.24 36 0 0 0.00 37 0 0 0.00 38 0 0 0.00 Page 72 of 80 L-MT-12-114 Enclosure 1 RB Volume EPU Level EQ-Part-B Level, Delta (inches) CLTP (inches) (inches)39 0 0.12 -0.12 40 0 0 0.00 41 0 0 0.00 42 0 0.12 -0.12 43 0 0.12 -0.12 44 0 0.12 -0.12 45 0 0.12 -0.12 46 0 0.24 -0.24 47 0 0 0.00 48 0 0.12 -0.12 Page 73 of 80 L-MT-12-114 Enclosure 1 27-4 Reactor Building HELB Peak Temperature Comparison RB EPU EQ-Part- Delta (OF)Volume Temperature(° BTemperature, F) CLTP (-F)1 116.7 119.2 -2.5 2 124.3 138.1 -13.8 3 117.3 119.3 -2.0 4 143.9 144.4 -0.5 5 288.9 256 32.9 6 282 263.6 18.4 7 293.7 240.4 53.3 8 296.1 272.6 23.5 9 202.9 187.6 15.3 10 202.7 159.9 42.8 11 202.9 158.7 44.2 12 203.4 193 10.4 13 172.4 127.3 45.1 14 185.7 153.3 32.4 15 211.8 209.6 2.2 16 310.9 311.3 -0.4 17 273.4 222.4 51.0 18 272.8 208.1 64.7 19 269.1 175.9 93.2 20 209 112.5 53.8 21 118.5 112.2 6.3 22 193.1 170.4 22.7 23 175.4 143.7 31.7 24 104.4 104 0.4 25 191.1 145.8 45.3 26 118.2 109.1 9.1 27 245.8 203.6 42.2 28 212.2 216.7 -4.5 29 212.5 214.6 -2.1 30 221.1 220.5 0.6 31 215.7 188.3 27.4 32 218.6 164.1 54.5 33 243.7 128.3 115.4 34 198.2 168.3 29.9 35 207.4 207.8 -0.4 36 178.7 142.4 36.3 37 178.8 112.8 66.0 Page 74 of 80 L-MT-12-114 Enclosure 1 RB EPU EQ-Part- Delta (OF)Volume Temperature(*

BTemperature, F) CLTP (-F)38 100.3 100 0.3 39 129.5 215.3 -85.8 40 128.4 126.2 2.2 41 117.2 106.9 10.3 42 207.2 204.7 2.5 43 123.6 128.3 -4.7 44 128.8 160.8 -32.0 45 206 169.7 36.3 46 116.1 219.2 -103.1 47 168.3 101.5 66.8 48 140.5 (139.7) 131.1 9.4 Page 75 of 80 L-MT-12-114 Enclosure 1 27-5 Difference Between CLTP & EPU Reactor Bldg for Post-LOCA and SBA Volume Temperatures Volume HELB Volume Description EPU CLTP EPU (OF) (OF) Change (OF)1 RHR and Core Spray Pump Room, 109.7 142.97 -33.27 Division I 2 RHR and Core Spray Pump Room, 111.5 142.97 -31.47 Division I Stairway 3 RHR and Core Spray Pump Room, 146.7 143.8 2.9 Division II 4 RHR and Core Spray Pump Room, 142.5 143.8 -1.3 Division II Stairway 5 RCIC Room 112.6 109.9 2.7 6 Reactor Bldg Elevation 896' 140.3 140.4 -.01 Equipment and Floor Drain Tank 7 CRD Pump Room 123.9 116.3 7.6 8 HPCI Room <125 <125 0 9 Suppression Pool Area -Northeast 179.1 160.4 18.7 10 Suppression Pool Area -179.1 159.9 19.2 Southeast 11 Suppression Pool Area -179.1 158.7 20.4 Southwest 12 Suppression Pool Area -179 157.3 21.7 Northwest 13 East Shutdown Cooling Room 118.3 112.6 5.7 14 CRD Hydraulic Control UnitArea-115.6 107.5 8.1 East 935' Elevation 15 TIP Room 122.5 106.3 16.2 16 Steam Chase 154.4 135.2 19.2 17 TIP Drive Room 115.7 108.1 7.6 18 CRD Hydraulic Control Unit Area 121.4 109.3 12.1 and HVAC Areas -NW 935' El 19 CRD Hydraulic Control Unit Area 121.4 108.3 13.1 and HVAC Areas -SW 935' El.20 West Shutdown Cooling Room 119.9 112.5 7.4 21 PIPE Chase 974' 118.5 112.2 6.3 22 MCC and Standby Liquid Control 119.1 106.7 12.4 System Area -East 962' El 23 Contaminated Tool Storage -East 118.2 105.4 12.8 962' El 24 Recirc M/G Set Airlock 104 104 0 25 962' North of Reactor Shield Wall 119.1 113.9 5.2 Page 76 of 80 L-MT-12-114 Enclosure 1 Volume HELB Volume Description EPU CLTP EPU (OF) (OF) Change (°F)26 Reactor Recirculation Pumps MG 118.2 109.1 9.1 Set Room 27 Cooling Water Pump and Chiller 121.3 109.1 12.2 Area -West 962' El 28 RWCU Pump Room B and 124.7 120 4.7 Hallway 29 RWCU Pump Room A 124.1 120.1 4 30 RWCU Heat Exchanger Area 130.1 120.2 9.9 31 RWCU Area Behind Hx Exchanger 132.2 120.2 12 32 RWCU Isolation Valve Room 125.4 120.2 5.2 33 MCC and Instrument Rack C-55 121.3 115.6 5.7 Area 34 CGCS-A Recombiner Area 119.3 107.9 11.4 35 Cooling Water Heat Exchanger 119.3 107.8 11.5 and CGCS-B Recombiner Area 36 Standby Gas Treatment System B 129.1 134.4 -5.3-Train Room 37 Standby Gas Treatment System 129.1 112.8 16.3 Fan Room 38 Standby Gas Treatment System 100 100 0 Airlock 39 Standby Gas Treatment System A 129.5 126.3 3.2-Train Area 40 Reactor Plenum Room 116.7 105.6 11.1 41 Reactor Recirculation MG Set Fan 117.2 106.9 10.3 Room 42 Corridor Outside Main Exhaust 119.2 104.6 14.6 Plenum 43 Skimmer Surge Tank and Fuel 114.3 109.7 4.6 Pool Pumps Area 44 Snubber Rebuild and 117.8 108.1 9.7 Decontamination Area 45 Northeast Stairway 1001' El 115.2 104 11.2 46 Contaminated Equipment Storage 116.1 107.2 8.9 Area 47 Northwest Stairway 1001' El 118.8 100 18.8 48 Refueling Floor 1028' El 115.4 103.9 11.5 Page 77 of 80 L-MT-12-114 Enclosure 1 Updated T1004 Recommendations Item 1, Radiation Doses Qualification is maintained for EPU radiological conditions and documented in the equipment specific qualification files for the following items:* General Electric Fan Motors* Microswitch Limit Switches Rosemount Model 1153 Series A transmitters in the Torus compartment at functional locations LT-7338A/B were replaced due to the increased radiological conditions.

Item 2, Turbine Building Areas Reclassified as EQ Harsh The associated EQ Files have been updated to ensure the cables routed through the newly created harsh Turbine Building areas under EPU are addressed.

Item 3, Post-LOCA Heatup in RB New EPU post-LOCA heat up conditions have been incorporated in the EQ files. A corrective action remains associated with completing documentation of replacement intervals due to qualified life changes.Also, Rosemount level transmitters LT-7338A/B were replaced because they would not possess adequate life margin when accounting for the higher post-LOCA heat up conditions in the Torus compartment.

Item 4, ITT Royal Cable A thermal lag analysis has been performed to demonstrate cable temperatures will remain below qualification temperatures for RWCU line breaks.Item 5, EQ Supporting Documentation (Configuration Management Issues)EQ-Part-B has been revised for EPU conditions.

Update to RAI Response L-MT-09-045 Due to several changes in the calculated EPU conditions, MNGP's response to EEEB RAIs dated March 28, 2009, submitted in letter L-MT-09-045 (Reference 27-1), requires some minor revisions.

Revisions to this RAI response do not affect the conclusions made by the original submittal.

RAI No. 4 -The specific values that were discussed in this response associated with the submergence profiles have changed. These submergence values have been reduced. Therefore, the previous response is conservative and bounding.Page 78 of 80 L-MT-12-114 Enclosure 1 RAI No. 7 -The HELB profiles have changed since this response.

ITT Royal cable is evaluated to the new HELB profiles in the equipment specific qualification file and in the thermal lag calculation.

The cables remain qualified for EPU conditions.

RAI No 13(c) -Pressure switches PS-4664 through PS-4672 have been replaced.Enclosure 2 contains the affected markups.References 27-1 Letter from T J O'Connor (NSPM), to Document Control Desk (NRC), "Monticello Extended Power Uprate: Response to NRC Electrical Engineering Review Branch (EEEB) Request for Additional Information (RAI) dated March 28, 2009, (TAC No. MD9990)," L-MT-09-045, dated May 26, 2009. (ADAMS Accession No. ML091470559)

Page 79 of 80 L-MT-12-114 Enclosure 1 ITEM 28 -EFFECTS OF LOSS OF STATOR WATER COOLING ANALYSIS NRC REQUESTED INFORMATION:

Generic issue from 10CFR21 notification regarding a slow transient resulting from a loss of stator cooling (LOSC). The NRC understands that this event could result in an operating limit maximum critical power ratio (OLMCPR) penalty change. Provide confirmation to NRC that this event is covered in the EPU analyses.NSPM RESPONSE: NSPM requested GEH perform an evaluation of the LOSC event for the MNGP. This evaluation focused on determining if the LOSC event is non-limiting with respect to the GEH reload licensing analysis basis for Monticello EPU Cycle 27. The analysis addressed all applicable thermal limits including rated power Operating Limit Minimum Critical Power Ratio (OLMCPR) limits, APRM Rod Block Technical Specification (ARTS)Improvement Program power dependent operating limits for off rated core flow and off rated core power conditions, and Linear Heat Generation Rate (LHGR) limits.The LOSC for Monticello is characterized by a turbine load runback, which results in a Turbine Control Valve closure. The turbine runback results in reduced steam flow capacity in the turbine pressure regulation system, which leads to a significant increase in reactor pressure.

The event is terminated by an automatic RPS actuation on high pressure or high flux.These analyses confirm that a LOSC event with Monticello's configuration is not limiting for OLMCPR, LHGRFAC, or MAPFAC on a cycle-independent basis. Additional cases were run to confirm this conclusion for the MELLLA+ and CLTP operating domains.The LOSC event is bounded for these plant operating conditions as well.The evaluation of the LOSC event for Monticello confirms that there is sufficient margin to the existing thermal limits. This conclusion remains applicable for future cycles for CLTP, EPU, and MELLLA+.No markup to the EPU documentation is required.Page 80 of 80 L-MT-12-114 Enclosure 2 ENCLOSURE 2 MARKED UP PAGE CHANGES TO EPU DOCUMENTATION BASED ON THE GAP ANALYSIS RESULTS Item 1 -Markup to L-MT-08-052, Enclosure 14 Item 2 -Markup to L-MT-08-039, Enclosure 4, RAIs 2, 3 and 4; and L-MT-08-043, Enclosure 2, RAI 2 Item 3 -No Markup required Item 4 -Markup to L-MT-09-043, Enclosure 3, EMCB-SD RAI Nos. 5, 6 and 7 Item 5 -Markup to L-MT-08-052, Enclosure 5, Section 2.1.7 including Table 2.1-4 Item 6 -Markup to L-MT-09-042, Enclosure 1, NRC RAI No. 2(b)Item 7 -Markup to L-MT-08-052, Enclosure 5, Section 2.11.1 Item 8 -Markup to L-MT-09-048, Enclosure 1, RAIs 12 and 29; and markup to L-MT-09-073, Enclosure 1, RAts 5 and 6 Item 9 -Markup to L-MT-08-052, Enclosure 5, Section 2.7.5 and L-MT-09-048, NRC (SCVB) RAI No. 34 Item 10 -No Markup required Item 11 -Markup to L-MT-08-052, Enclosure 5, Section 2.2.2.1 including Table 2.2-2d and L-MT-09-044, Enclosure 1, EMCB RAI No. 17 Item 12 -Markup to L-MT-08-036, Enclosure 6 Item 13 -No Markup required Item 14 -Markup to L-MT-08-052, Enclosure 5, Table 1-1 Item 1.5 -Markup to L-MT-08-052, Enclosure 5, section 2.5.4.3 and L-MT-09-049, Enclosure 1, RAI 2.8.3-11 Item 1.6 -Markup to L-MT-08-052, Enclosure 5, Section 2.2.3, including Table 2.2-3 Item 17 -Markup to L-MT-09-049, Enclosure 1, RAI SRXB RAI No. 2.8.3-3 Item 18 -Markup to L-MT-09-044, Enclosure 1, EMCB RAI No. 28 Item 19 -Markup to L-MT-08-052, Enclosure 5, Section 2.5.4.4 and markup to L-MT-08-052, Enclosure 8.Item 20 -No Markup required Item 21 -No Markup required Item 22 -Markup to L-MT-09-049, Enclosure 1, RAI SRXB RAI No. 2.8.3-4 Item 23 -No Markup required Item 24 -Markup to L-MT-08-039, Enclosure 2, RAls 1, 2 and 3, and markup to L-MT-08-052, Enclosure 5, Section 2.2.4 Item 25 -No Markup required Item 26 -Markup to L-MT-08-052, Enclosure 5, Section 2.2.1.2, Section 2.2.2.1 including Tables 2.2-1, 2.2-2a, 2.2-2b and 2.2-2c; L-MT-09-044, Enclosure 1, EMCB RAIs 3(a), 5, 6(a), 6(b), 7, 12(b), 13, 17(a) and 17(b); and L-MT-09-046, Enclosure 1, SBPB RAI 2.5-1 Item 27 -Markup to L-MT-09-045, Enclosure 1, RAIs No. 4, 7 and. 13(c)Item 28 -No Markup required 100 pages follow FItem 1I ENCLOSURE 14 Introduction Two System Impact Studies (SIS) (References 1 & 2) were performed by the Midwest Independent System Operator, Inc (MISO) to evaluate the impact of the Monticello Nuclear Generating Plant (MNGP) Extended Power Uprate (EPU) operation on transmission system reliability.

The Reference 1 study analyzed an Interconnection Request for 13 MWe to ...pprt an EPU Phase , powor ..n.roAc.;....

fo..,,~ng the 200.0. rc-fuc-A-l The Reference 2 study analyzed an Interconnection Request for 60.8 MWe t c .upport an EP, A cn.e.. Phase ..po .o .....r. increac followin.g the 2011 , ro ,.fuol outago. A summary and results of both Ir these studies is provided herein.Design Basis The design basis for the electrical power system is defined in the MNGP Updated Safety Analysis Report (USAR) Sections 1.2.6 and 8.1: "Sufficient normal and standby auxiliary sources of electrical power are provided to attain prompt shutdown and continued maintenance of the plant in a safe condition under all credible circumstances.

The capacity of the power sources is adequate to accomplish all required engineered safeguards functions under all postulated design basis accident conditions.""The plant electrical power system is designed to provide a diversity of dependable power sources which are physically isolated so that any one failure affecting one source of supply will not propagate to alternate sources. The plant auxiliary electrical power systems are designed to provide electrical and physical independence and adequate power supplies for startup, operation, shutdown, and for other plant requirements which are important to safety." The Nuclear Management Company, LLC (NMC) provided MNGP's docketed position on 10 CFR 50 Appendix A, General Design Criteria (GDC) 17 compliance in a letter (Reference

3) dated July 21, 2006, "Response to Generic Letter 2006-02, 'Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power.'" The following is an excerpt from this letter: "Generally, the NMC-operated plants were licensed to comply with the Atomic Energy Commission General Design Criteria as proposed on July 10, 1967 (AEC GDC) as described in the plant Final (Updated)

Safety Analysis Report. AEC GDC proposed Criterion 39, which provides guidance applicable to the design of the AC electrical power system supplies to the engineered safety features, states: "Alternate power systems shall be provided and designed with adequate independency, redundancy, capacity, and testability to permit the functioning required of the engineered safety features.

As a minimum, the onsite power system and the offsite power system shall each, independently, provide this capacity assuming a failure of a single active component in each power system.Page 1 of 8 Iltem 1I ENCLOSURE 14"Thus, many of the provisions of GDC Criterion 17 are not applicable to the NMC operated plants, the responses to the questions reflect that the plants are not committed to GDC Criterion 17, and the responses do not in any manner commit to or imply compliance with GDC Criterion 17 for the NMC-operated plants." Offsite Power System General Description Transmission Interconnections r--three I The plant electrical output is connected tthe grid via an on-site switchyard.

Existing transmission outlet facilities consist of two 345 KV, two 230 KV, and three 115 KV transmission lines as shown in USAR Section 15, Drawing NH-1 78635.three The 345 KV portion of the switchyard has positions for connecting the generator output,{twe transmission lines, a 345-230-13.8 KV autotransformer, a 345-13.8 KV transformer, a 345-34.5 KV transformer, and a 345-115-13.8 KV autotransformer.

The 345 KV bus and circuit breaker arrangement is based on ultimate d.eyelpment inmt a breaker-and-one-half system. TI ie p it iistallatiuio is a ing bus cc ,,,figurati,,.

One 345 KV transmission line is routed to connect into the 345 KV loop around the Twin Cities Metropolitan Area at the Elm Creek Substation.

The ether line connects to the 345 KV transmission system at the Sherburne CountynSubstatn.

• -----The third 345 KV transmission line connects to the Fsecond lQuarry Substation near St. Cloud, Minnesota.

I The 230 KV portion of the switchyard is provided to establish an interconnection with the transmission system of Great River Energy. An autotransformer connects the 345 KV and 230 KV busses.The 115 KV portion of the switchyard is connected to the 345 KV bus through an autotransformer.

The 115 KV bus is arranged in a ring bus configuration.

In addition to the autotransformer connection to the 115 KV bus, there are three transmission line connections.

One of the three transmission lines connects into the 115 KV transmission system at Lake Pulaski and at Dickinson Substation.

The second line connects at Hassan Substation.

The third 115 KV line connects to the Sherburne County substation.

The 13.8 KV portion of the switchyard is provided to establish reliable power sources to various plant equipment.

These include the plant auxiliary reserve transformer (1AR);discharge structure transformers (X7, X8); cooling tower fan transformers (X50, X60, X70, X80); transformer XP91, which powers the hydrogen water chemistry cryogenic system panel, and an alternate feed (through transformer

6) to the training center.Plant Auxiliary Power Supplies Three transformers are provided to supply the plant with offsite power from the substation.

All three sources can independently provide adequate power for the plant's safety-related loads. These transformers and their interconnections to the substation are as follows: Page 2 of 8 Item 1I ENCLOSURE 14 The primary station auxiliary transformer, 2R, is fed from 345 KV Bus No. 1 via 345 KV to 34.5 KV transformer 2RS, a cunt limiting racto.. and fuse assembly., and underground cabling from the substation to the area northwest of the turbine building where 2R transformer is located. The 2R transformer is of adequate size to provide the plant's full auxiliary load requirements.

The reserve transformer, 1 R, is fed from the 115 KV substation via an overhead line from the substation to the area northwest of the turbine building where 1 R transformer is located. The 1 R transformer is of adequate size to provide the plant's full auxiliary load requirements.

The reserve auxiliary transformer, 1AR, is located southwest of the reactor building and may be fed from two separate 13.8 KV sources in the substation.

One method of supplying the 1AR transformer is from the tertiary winding of the 10 transformer, the auto-transformer.

that interconnects the 345 KV and 115 KV systems. Power is routed from the te jjrjýJ isubstationinding of 10 transformer to 1AR via circuit breaker 1N2 and underground cqIifig from the 61buUbstation to 1AR transformer.

The alternate method of feeding 1AR is from T345 KV &ie Ne. via 345 KV to 13.8 KV transformer 1ARS, circuit breaker 1 N6, and underground cabling from the substation to 1AR. Circuit breakers 1N2 and 1N6 are interlocked to prevent having both breakers simultaneously in the closed position.

The 1AR transformer is sized to provide only the plant's essential 4160 Volt buses and connected loads.TRAncformcrc 214 and lAR aro concidered as a singlc offitc cou~rc when IAR ic, supplied from 346 KV Bus No. 1 A A- nmRou common6GF~fl_

RRodc failurocF-c-44-t MWhic coul d cAUso c~imultaneouc deenRgffiZatiGn of both tranzformcrc.

To miniimizo the petcntial for oommofln PAoed- f ailuro, thc normal aligwnmnt of of sitc cOurczc to tho plant is 2R tFranformzre suppl';ing plant load, 1 R trancformcr cncgizcd iA Fescrye, and IAIR tranzeformor oergliZcd 4fro 10 trancformcr

~ac a third dictinct oA ciWtoe corco.. to tho occcntial bursco.Transmission Line Reliability The ftek3 and 115 Ky) transmission line connections to the switchyard are all connected into the Xcel Energy interconnected transmission grid. The points of connection to the grid are arranged by routes and intra-right-of-way spacing to minimize multiple line outages while performing the requirement of delivering power to locations which best satisfy system growth needs. The 345 KV and 115 Ky lines, as well as the lines to which they interconnect, are designed and built to exceed the requirements of the National Electric Safety Code for heavy loading districts, Grade B construction.

Lightning performance design of the transmission lines is based on less than one outage per 100 miles per year. E -~The fhoe Xcel Energy transmission lines leave the Monticello substation through tl~ee-separate rights-of-way:

Sherburne County line corridor; St. Cloud line czrrideF; and a common corridor for the Elm Creek, Dickinson-Lake Pulaski, d Hassan lines. These rights-of-way are considered independent as they are greatqr than 1/4 mile apart at a distance of one mile from the plant. two St. Cloud corridor lines I(Liberty and Quarry);Page 3 of 8 Item 1I ENCLOSURE 14 Analysisriginally The power increase related to the EPU project is anned in twe-phas,6 one following the 29 euln uaeadteF-n~aefleigte21

_refueling outage. A request for interconnection rights of an additional 13 MWe was identified by MISO as Project G725. The 13 MNe is an increase above the current interconnection rights of 607.2 MWe and was requested to accommodate the first phase power increase following the 2009 refuel outage. A request for interconnection rights of an additional 60.8 MWe was identified by MISO as Project G929. The 60.8 MWe request will accommodate the electrical output expected at EPU reactor thermal power of 2004 MWth.A summary of each study is provided below.Proiect G725, 13 MWe Increase Request: Study Methodology and Assumptions:

Both projects (G725 and G929) are currently planned to be implemented following the 2013 refueling outage.A benchmark case computer model was developed for the study from the MAPP 2005 series models. This model was used for steady state power flow analysis focused on thermal loadings under both normal and N-1 contingency conditions.

The model included transmission system updates and prior-queued generation projects in the region that could have an impact on the MNGP generation increase.

Monticello output was set at 607 MWe net and additional generation near the Monticello unit that was not at maximum output or in service was set at maximum and put into service. This represents a summer peak condition expected at the time of the MNGP output increase.

A subsequent study case model was developed incorporating the MNGP requested 13 MWe increase in electrical output. The analysis was done for station load supplied from both the 345 KV substation and the 115 KV substation.

For the transient stability analysis, a computer model called the Northern MAPP stability package was used. Again, benchmark case and study case models were developed.

This is a summer off-peak model. Regional generation was added and adjusted for peak output.Corresponding load sinks were adjusted as appropriate.

The stability of the grid was then analyzed for regional single-line ground faults with breaker failure and 3-phase faults without breaker failure.The Interconnection Request for this project asked that the total MNGP electrical output be classified as Network Resource Interconnection Service (NRIS). In order to be classified as NRIS, the project request must pass a generator deliverability study. This study was included in the SIS.Page 4 of 8 Item 1I ENCLOSURE 14 verified for both the cases where house loads are supplied from the 345 kV bus or the 115 kV bus. Screening results using only the reactive capability of the generator showed no change to the conclusions.

For transient conditions no violations of stability criteria were identified.

The 345 kV & 115 kV substation bus voltages remain within acceptable values with and without additional reactive capability.

The deliverability analysis concluded that the full electrical output of the MNGP can be classified as NRIS; therefore non-injection constraints identified in the steady state analysis do not need to be mitigated under this project.The short circuit analysis concluded the interrupting capability of NSP 345 kV, 230 kV and 115 kV substation breakers at Monticello and adjacent substations are adequate for the increased generator output.Insert A Since submittal of the original stability study an additional 345 KV line has been added to the MNGP substation which increased the number of transmission lines from 5 to 6 connecting to this substation.

This included an upgrade of the 345 KV bus from a ring bus to a breaker-and-one-half system (see USAR Section 8.2.1).The power increase related to the Extended Power Uprate (EPU) project was originally planned in two phases in 2009 and 2011. Midwest Independent Transmission System Operator, Inc. (MISO) has approved the full power increase in a signed Interconnection Agreement (IA) as executed in MISO Projects (G725 13MWe and G929 60.8MWe) on October 6, 2009. EPU currently plans to implement both of these MISO projects following the 2013 outage.The Large Generator Interconnection Agreement did not identify the need for any additional interconnection, or system protection facilities, or require any distribution, generator, or network upgrades.On February 22, 2011, Xcel notified MISO ISO that the Commercial Operation Date (COD) for MNGP Projects G725 and G929 have been extended from May, 2011 to August 2013. This change notification was not considered a material change in accordance with Midwest ISO electric tariff and a LGIA restudy was not required.By email dated September 24, 2012 from Vikram Godbole of MISO to various individuals, MISO reported the results of a restudy evaluation of projects with permanent Generator Interconnection Agreements (GIAs). The study included: 1. Stability Analysis 2. NRIS analysis 3. Per project summary results.The MNGP EPU is covered by GIA G929. No adverse impacts were identified for this study.Page 7 of 8 Enclosure 4 The onsite buses are designed to provide acceptable voltage to the safety related loads under worst case grid voltage conditions.

The AC power requirements for the operation of safety related loads will not change under EPU.Monticello's AC Load Study program controls and maintains the databases and computer models used to evaluate and record electrical load study cases and calculations that are performed.

This program is used to assure that the distribution system voltage ranges meet the underlying electrical system design bases for plant conditions.

The following loading conditions are analyzed to ensure that the electrical system design bases are maintained:

A. Full plant load B. Emergency Core Cooling System (ECCS)/Loss of Coolant Accident (LOCA)plant load C. Minimum plant load The AC Load Study program has established the following electrical system design bases for determining acceptable distribution system voltages: 1. 120 VAC Instrument AC System Voltages: Maximum -132 VAC, Minimum -108 VAC (+/- 10% of rated 120 VAC)2. 480 VAC System Voltages: Maximum -506 VAC, Minimum -426 VAC (+/- 10% voltage at the terminals of 460 VAC)3. 4160 VAC System Voltage: Maximum -4400 VAC at the 4 kV motor terminals (110% of rated 4000 VAC), Minimum -3975 VAC A separate analysis verifies that the bases for degraded voltage relay setpoint remains valid under the EPU configuration and loading conditions.

This analysis will include the transformer and balance of plant (BOP) modifications planned for EPU. Plant procedures incorporate these limits.Non-safety Related AC System Loads At EPU eenditinc themc will be an inRo~aco in the non cafot, related eleetrical leads primarily due to inrezased eendcncatolfocdwatcr pumHp flow Fequ*rcmcnts.

The ipc of this inerease Fesults in sevcrol ohallenges.

The eapoity of the I R tFROrmr i merginal.

The tatot of a larger fecdwator pumpI inRecases the voltage drop toth 4..16 WV switohgcar rczulting in Fedueed margins to protectiye relaying sctpOintS.

Also, the fault oontributien fromR lrgor mROtOre reducoc the mnargOR to the fault ratingseof the swxitehgcaF and any increase in the capacity of the I R trancfermer Will eXaccrbatc the situation.

Conscquently, the configuration of the 1 R anid 2R courcoc and non safety onsitc dictribution system will be modified to increaco eapaeit' and improvc margins to equipment ratingse and protective relaying sctpoints.

The modificatione to the 1R and Page 2 of 10 Insert A Implementation of the Extended Power Uprate (EPU) at Monticello requires increasing the reactor feedwater flow. This requires additional pumping capacity for the condensate and feedwater systems, with an attendant increase in electrical power to the pumps. The additional power to support these increases is not within the capabilities of the existing 1 R and 2R Transformers and 4 kV Buses 11 and 12. The approach selected to supply the increased pumping load was to install a new 13.8 kV Distribution System and replace reserve transformer 1 R and auxiliary transformer 2R. Consistent with the existing plant design, new 13.8 kV Buses 11 and 12 will continue to supply the Reactor Feed Pump and Reactor Recirculation MG (RRMG) drive motors. The new voltage at these buses requires replacing the RRMG drive motors, although there is no change in motor hp. In addition to increasing their horsepower, the condensate pump motors are being relocated to new 13.8 kV Buses 11 and 12.

Item 2 I Enclosure 4 2R offitoW pGO eroumrcc Wre in the conceptual stage at this time and erc sehedulced far e intaflotion in the 2011 i utacgc.Offsite Power System Grid Voltages The offsite power system is designed to provide adequate power to site loads given that the steady state source 345 kV and 115 kV grid voltages are within the ranges specified by plant procedures.

The ranges are derived from the plant AC load studies. Operation within these ranges provides adequate voltage for operability of safety related equipment, provides for proper operation of various automatic voltage regulating equipment such as load tap changers, and will result in the avoidance of inadvertent bus transfers of the safety related buses due to degraded voltage when starting plant equipment.

This performance will be demonstrated by the AC load studies completed as part of the off-site source (1 R and 2R) modifications.

Modification Control for EPU The configuration changes noted above will be controlled by the Monticello Modification Process. This process requires compliance with site work instructions for the Fuse/Breaker Coordination Study and AC Electrical Load Study. Conformance to the Monticello licensing bases is controlled by required load studies for changes to the site AC electrical system. The AC load study is described in the Updated Safety Analysis Report USAR) and references the associated NRC review and approval correspondence.

AC load studies become formal plant calculations.

The AC load study assumptions and the EPU impact are noted below." Loads shed by ECCS load shedding are not included in the Offsite AC System loading determination for the Design Basis Accident (DBA) LOCA loads.EPU Impact: EPU does not involve any changes to load shedding circuits.* The AC load studies include minimum and maximum equipment voltages for steady state operation and motor starting.

It also includes, by reference, the degraded voltage setpoints.

EPU Imoact: The load study established voltage limits based on equipment design. These limits were established with NRC approval.

EPU does not change these limits. All of the new EPU AC motors will be designed to start and operate within the existing voltage limits or, if operated at a different voltage base, new limits will be established based on equipment design. EPU does not require any changes to the setpoints for the degraded bus voltage and loss of voltage logic." The Offsite AC System load application is based on ECCS load sequencing.

EPU Impact: EPU does not affect any of the timing associated with ECCS load sequencing.

Page 3 of 10 FItf m l Enclosure 4" The Demand and Diversity Factors for AC Load Studies are included in the AC load study.EPU Impact: EPU does not require any changes to this load application methodology.

• Steady state voltage profile studies are completed using the maximum (Weak System) switchyard impedance with the minimum specified distribution system voltage. Short circuit studies use the minimum (Strong System) switchyard impedance with the maximum distribution system voltage.EPU Impact: EPU does not change these conservative assumptions.

DC Onsite Power System (PUSAR Section 2.3.4)DC Onsite Power System changes remain bounded by battery capacity.

Revision of station DC battery calculation verified acceptable margin remains after EPU* Monticello 125 VDC Division I Battery has spare capacity of 16.83 percent under EPU conditions.

The CLTP analysis had a battery margin of 40.60 percent." Monticello 250 VDC Division I Battery has spare capacity of 20.64 percent under EPU conditions.

The CLTP analysis had a battery margin of 2313* Monticello 125 VDC Division II Battery has spare capacity of 26.8 percent under EPU conditions.

The CLTP analysis had a battery margin of 20.24 E26.58_ J -1o22.81J* Monticello 250 VDC Division II Battery has spare capa--of--

percent under EPU conditions.

The CLTP analysis had a battery margin of 2.04 percent prior to EPU.

in mlargin wc.c based eR hangr,, in the Station .ut (SBO) se'naria oumptiens ac providcd in Montiocllo EPU L'AR Enoelocur 5 (PUSAR Soetion 2.3.6)and use ef marce rcalistio asaumptiens on battery loading in the calculation.

The revised Load changes to the Safety Related DC Onsite Power System remain bounded by the capacity of the existing station batteries.

Approved revisions to station cell sizing calculations confirmed positive capacity margin remains for the analyzed scenarios following implementation of EPU.a'l'ulati-ns in^"ud^d a'l pending miOr .hange. to thc ealoulatione.

No changes are expected for 250 VDC battery loads. Potential loading changes to the 125 VDC systems are not expected to be significant based on 10 CFR 50.59 screening or evaluation of the proposed changes.Station Blackout and DC Loadingl (PUSAR Section 2.3.5)The design basis loading for the safety related DC systems is the loading profile that occurs during an SBO event. The DC System electrical design parameters at the end of the four hour design basis SBO load discharge remain within design.The DC battery calculations for EPU demonstrate that, given conservative assumptions for the timing and application of DC loads during this event, sufficient DC power is Page 4 of 10 Item 2 1 Enclosure 4 sufficient battery capacity exists to start and operate all connected DC loads for the worst case loading scenario.NRC Question 3) In Section 2.3 of the LAR (Specifically Sections 2.3.3 and 2.3.4), the licensee stated that some equipment may change.In order for EEEB to start its review, the licensee must provide assurance that all required plant modifications are accounted for In its EPU application.

NMC Response: The Monticello EPU LAR, Enclosure 8, "Planned Modifications for Monticello Extended Power Uprate," contains a comprehensive list of all modifications that are planned for EPU. As noted in Enclosure 8, some of the listed modifications have been completed, some are planned for installation in 2009, and some are planned for installation in 2011.These tables also include modifications that are not required for EPU, but are being planned as part of the life cycle management (LCM) program.Modifications that have already been completed were those required to obtain data for steam dryer analysis.

The remaining modifications are required to support full power operation at 2004 MWt. Completion of turbine modifications planned for 2009 will enable operation at power levels above CLTP. None of the planned modifications listed below are safety related except for the modification providing upgrades to EQ equipment.

Modifications associated with the Monticello EPU LAR Enclosure 5 (PUSAR), Section 2.3 are described below: PUSAR Section 2.3.1, Environmental Qualification of Electrical Equipment.

Modifications:

• HELB Update/EQ Update -The response to EEEB Question 1 will provide more detailed information.

Question 1 will be submitted at a later date as discussed with the NRC staff on May 23, 2008.PUSAR Section 2.3.2. Offsite Power Systems, Planned Modifications:

• 1AR Transformer Replacement

-replacement due to aging not EPU -Installed]

• Main Transformer and Isophase Duct -increased capacity <-- -Installed* Reactor Feed Pump Replacement

-new higher horsepower 13.8kV motor* Condensate Pump Upgrades -new higher horsepower 13.8kV motor* New 13.8kV Bus Installation

-replace existing 11 and 12 4kV buses with 13.8kV bus including replacement of the 1 R and 2R transformers

• Replace the Recirculation M-G Set Motors -new 13.8kV motor Increases in required condensate and feedwater pump capacity for EPU result in electrical loads for onsite non-safety related AC power systems that exceed the capacity of the existing system. The modifications listed above provide upgrades to Page 6 of 10 Iltem 2 1 Enclosure 4 plant non-safety related AC electrical distribution systems to correct this deficiency.

There are no changes required to safety related buses.The existing non-safety related #11 and #12 4kV buses will be replaced with a new bus rated at 13.8kV. This will require replacing all motors associated with the new bus to provide motors rated at 13.8kV. These modifications will insure compliance with design requirements as fined in the Technical Evaluation of PUSAR Section 2.3.2. " for operation The electrical modifications planned for upgrade of the Offsite Power Systems are required due to the upgrades to the onsite AC systems. Potential grid modifications will be identified, if required, as part of the Midwest Independent System Operator (MISO) grid stability study associated with approval of the interconnection application for generation needed to support 2004 MWt reactor power. These modifications will be provided to the NRC for review by a later submittal as described in Sections 1.0 and 2.0 of the Monticello EPU LAR Enclosure 1, "NMC Evaluation of Proposed Changes to Operating License and Technical Specifications for Extended Power Uprate." A separate license amendment request will be submitted to increase the power level to 2004 MWt.The MISO grid stability study for approval of the interconnection application for generation needed to support 1870 MWt did not identify any grid modifications as being required.

This study will be submitted to the NRC by June 30, 2008.PUSAR Section 2.3.3. Onsite AC Power System, Planned Modifications:

There are no modifications required for the alternating current (AC) onsite power system for those standby power sources, distribution systems, and auxiliary supporting systems provided to supply power to safety-related equipment.

EPU does not affect the timing associated with ECCS load sequencing and has no effect on Emergency Diesel Generators (EDG) transient performance.

There are no changes to the sequencing and timing of AC ECCS loads during a DBA LOCA. EPU has no effect on the functional requirements for the instrumentation and control subsystems of the safety-related EDG power systems and there are no changes to the instrumentation and control systems of the essential AC systems.The EDG design basis loading is not affected by EPU. The EDG continuous load rating of 2500 kW envelopes the initial and steady state loading for the EDG. In addition, EDG transient voltage and frequency performance is not affected since the EDG loading does not change. See PUSAR Section 2.8.5.6.2, Emergency Core Cooling System and Loss-of-Coolant Accidents, for the evaluation of ECCS loads.PUSAR Section 2.3.4. DC Onsite Power System, Planned Modifications:

There are no currently identified modifications to the DC Onsite Power Systems.The DC System may be modified to include changes for certain EPU modifications.

Page 7 of 10 Iltem 2 Enclosure 4 of the proposed EPU. As noted in the response to Question 2 above, some modifications are required for non-safety related onsite AC power systems.PUSAR Section 2.3.4. DC Onsite Power System DC Onsite Power System changes remain bounded by battery capacity.

Revision of station DC battery calculations verified acceptable margin remains after EP" Monticello 125 VDC Division I Battery has spare capacity of 16.8 percent under EPU conditions.

The CLTP analysis had a battery margin of 10.6 percent." Monticello 250 VDC Division I Battery has spare capacity of 20.64 percent under EPU conditions.

The CLTP analysis had a battery margin of 23.63 P t.* Monticello 125 VDC Division II Battery has spare capacity of 26 percent under EPU conditions.

The CLTP analysis had a battery margin of 29.24 percent..26.58 __l-" Monticello 250 VDC Division II Battery has spare c iof 8Under EPU conditions.

The CLTP analysis had a battery margin of 2.04 percent prior to EPU.kmpro':cments in mSrgin werc based on ohangoc in the SBBC onas i asmpin3 Pro~ided on PUSAR Sootion 2.3.5 and use of mor8e roalistie assumptions on beAttz!au, .!" fk ^ -i 1. ...*- ..... .0T .. ...r- -. .-.. i,., ^ 1 .^-A%- *.. k' .*to the caloulatnci..

No changes are expected for 250 VDC battery loads, jPotential loading changes to the 125 VDC systems are not expected to be signifi nt based on 10 CFR 50.59 screening or evaluation of the proposed changes.PUSAR Section 2.3.5. Station Blackout The evaluation states that the plant will continue to meet the requireme ts of 10 CFR 50.63 following implementation of the proposed EPU.Load changes on the Safety Related DC Onsite Power System remain bounded by the capacity of the existing station batteries.

Approved revisions to station cell sizina calculations confirmed Dositive caoacitv margin remains for the analyzed scenarios following implementation of EPU.Page 10 of 10 Iltem 2 Enclosure 2 NRC Question: 1. Provide the staff with the USAR section number that describes the AC load Study.NMC Response: The AC load study is described in Monticello USAR Section 8.10, "Adequacy of Station Electrical Distribution System Voltages." NRC Question: 2. The licensee will provide statements that the margins discussed in the acceptance review response for the batteries will be met during the development of the modifications.

C,-- he-:These are the finalI NMWC Response:

, In Refee^Rcn 2, Ene- ......, NMC epo,.. d the following with .. s.pot t. DC battery capacity margins at Current Licensed Thermal Power (CLTP) and Extended Power Uprate (EPU) conditions:

Table I -Battery Margin_ CLTP (% Batte M i I EPU (% Batterv Margin)125 VDC Division I Battery 15.831 9.29 250 VDC Division I Battery 23.63 20.64 125 VDC Division 11 Battery 2 v=-426.58 26.68 8.11 250 VDC Division 11 Battery 2.04 8-9 22.81 Expeeted EPU eleetrieal mediflcatiens that eewid impact DG leads arc rcplaczmcnets i kind IFr and trl leads on the 142 VO) system. The additieRal 126 VDl j eads due to these EPU moediflcations will no~t roducoe the ropo~tod 125 VOCG batto mnargin by mor~e than Five perccnt of the calculated capacity' Fcpeotd. For eXam~ple, the[PU medifieaticns will be controlled such that the rcmaining 125 VDC Diyicion 1 batteryist Iat .ast 10.83 perent.Additionally, no changes to the margin for the 250V DC battery loads will result from EPU modifications.

Page 1 of 7

[Item 4 I L-MT-09-043 Enclosure 3 Page 11 of 64 EMCB-SD RAI No. 5 CDI Report 07-25P discusses noise removal from the CLTP signal. The licensee is advised to note the staff's position that using noise removal from CLTP signals based on LP signals is only acceptable when the LP signals are not corrupted by background electrical interference (EIC) noise, otherwise the dryer stresses should be computed using original CLTP signals, not those reduced by the LP signals corrupted by EIC noise. The licensee is requested to provide a discussion of the LP noise that was subtracted from CLTP and clearly substantiates that the LP signal is affected or corrupted by EIC. NSPM may submit new data and stress analyses based on low power signals not corrupted by EIC noise, for the staffs consideration.

Response superseded by WCAP-1 7548 NSPM Response p-IProvided in L-MT-12-056, Enclosure 2.Te original CLTP and low power data were collected in May and April of 2007. At th timonticello did not record EIC data. Low power and EIC data were subsequ y collectei September and October 2008; however, the EIC data at CLTP c itions was judged usable because of the large frequency exclusion that woul e required at 60 Hz. Thus,f all analyses discussed, the 2007 CLTP did NOT e the 2008 CLTP EIC data rem d, whereas for a conservative result, the,8 Low Power data did have the 2008 Low er EIC data removed. Figures 5bo 5.4 plot the CLTP (EIC not removed) and low power ta (EIC removed).

Note t the low power signals are consistently lower at each strain e location than CLTP signals for the frequency range considered here.Comparisons between EIC and low po da ith EIC included) are shown in Figures 5.5 to 5.8. It may be seen th low o data are consistently higher than the EIC data, except at the excl ion frequencies (60, 0, 180 Hz) where the two signals (at each strain gag cation) are essentially the sa Further compariso , etween the CLTP data collected in 2007 an e CLTP data collected in 20 (again, with EIC not removed are shown in Fi ures .to 5.12. Both cinfe nf cinn e r= r mnr!in r[Note: No change has been made to blacked out information.

Information redacted to preserve integrity of proprietary information.

NOTE: RAI No. 5 contains graphs on the following pages that are not reproduced here which are also superseded by the response in WCAP-17548 provided in L-MT-12-056, Enclosure

2.

Iltem 4 I L-MT-09-043 Enclosure 3 Page 24 of 64 EMCB-SD RAI No. 6 There appears to be an inconsistency among the different NSPM reports regarding how the CLTP signals are reduced by the low power signals. On Page 16 of 24 of Enclosure 11 to L-MT-08-052, "Steam Dryer Dynamic Stress Evaluation", NSPM states that, "For consistency, the low power strain gage signals are filtered in the same manner as the CLTP data and are fed into the ACM model to obtain the monopole and dipole signals at the MSL inlets." In Report CDI 07-25P, "Acoustic and Low Frequency Hydrodynamic Loads at CLTP Power Level on Monticello Steam Dryer to 200 Hz", Rev. 4, November 2008, NSPM states that up to 80% of the low power strain gage signals was subtracted from those measured at CLTP. In a third report, CDI Report 07-26P, "Stress Assessment of Monticello Steam Dryer", Rev. 2, November 2008, Equation 8 indicates that the CLTP signal is reduced by up to 80% (not that up to 80% of the LF signal is subtracted from the CLTP signals).

Clearly, the wording in these three reports is contradictory.

NSPM is requested to resolve the discrepancies and explain clearly how the low power noise removal was implemented.

In addition, NSPM is requested to modify the above mentioned reports so that the procedure of low power noise removal is consistent among the three reports. Response superseded by WCAP-17548 provided in L-MT-12-056, Enclosure 2.NSPM Response T-he.equation, as defined in C.D.I. Report No.07-25P (the loads report) and C.D.I.Repo 07-26P (the stress report), is where PR(0O) is the CLTP signal Ps(co) co or Low Power P&0o), computed as a This interpretation is consis with the wording in both C. .reports. Page 16 of 24 of Enclosure 11 toLM 052 (supplied by NSPM) is in error.See also response to EMCB-SD- RAI 20, where it is shown itat noise s ction is not ired for stress ratios above 2.0 at EPU conditions.

L-MT-09-043 Enclosure 3 Page 25 of 64 EMCB-SD RAI No. 7 The proper filtering of the plant noise (low power signal) from the CLTP signal requires that the corresponding EIC signals are accounted for. That is, the low power and CLTP signals are modified by subtracting the corresponding EIC signals from them, and then the modified LP signal is filtered out from the modified CLTP signal. Such a procedure was considered acceptable during staffs review of previous EPU application that CDI was involved in. However for the Monticello steam dryer, as stated in CDI Report 07-25P, NSPM has decided not to modify the LP and CLTP signals by subtracting the corresponding EIC signals. The licensee is requested to justify that this approach of not using the EIC signal is conservative compared to the one used for the BFN Unit 1 steam dryer. ., .. , 4-, ., I ro.ile iupnrsUdU Uy VVT.t--, -I Encosue2 I provided in L-MT-12-056, Enclosure 2.1 NSPM Response TI 2008 low power and EIC data sets have been used with the 2007 CLTP data. FAC" data a oved from the 2008 low power data (the low power EIC data), b from the 2007 CL a (the CLTP EIC data). The result is conservativ Previously, when noise subtr was performed, as left in the CLTP signal but subtracted from low power. This app pr .d a conservative signal after noise subtraction, since the low power sign gin AAfter EIC sbtractionis everywhere less than or equal to the low signal without E traction.

Heca mle amplitude low power s was subtracted from the CLTP si Note th rrently no low power subtraction is performed, so this issue is n vant t e current stress analysis.EMCB-SD RAI No. 8 NSPM Response Note: No change has been made to blacked out information.

Information redacted to preserve integrity of proprietary information.

Item 57 NEDC-33322P, Revision 3 While Monticello is not generally licensed to the current GDC or the 1967 AEC proposed General Design Criteria, a comparison of the current GDC to the applicable AEC proposed General Design Criteria can usually be made. For the current GDC listed in the Regulatory Evaluation above, the Monticello comparative evaluation of the comparable 1967 AEC proposed General Design Criteria (referred to here as "draft GDC') is contained in Monticello USAR Appendix E: draft GDC-9, draft GDC-33, draft GDC-67, draft GDC-68. draft GDC-69, and draft GDC-70.The Reactor Water Cleanup System is described in Monticello USAR Section 10.2.3. "Reactor Cleanup Demineralizer System." In addition to the evaluations described in the Monticello USAR. Monticello's systems and components were evaluated for License Renewal. Systems and system component materials of construction, operating history, and programs used to manage aging effects were evaluated for plant license renewal and documented in the Monticello Nuclear Generating Plant License Renewal Safety Evaluation Report (SER), NUREG-1865, dated October 2006 (Reference 5).The license renewal evaluation associated with the Reactor Water Cleanup System is documented in NUREG-1865, Section 2.3.3.15.

Management of aging effects on the Reactor Water Cleanup System is documented in NUREG-1865, Section 3.3.2.3.15.

Technical Evaluation RWCU system operation at the EPU RTP level slightly decreases the temperature

(< I°F) within the RWCU system. This system is designed to remove solid and dissolved impurities fi'om recirculated reactor coolant, thereby reducing the concentration of radioactive and corrosive species in the reactor coolant. The system is capable of performing this function at the EPU RTP level.RWCU flow is usually selected to be in the range of 0.8% to 1.0% of FW flow based on operational history. fit; exising iVt'U fla slightl) exed thi niw (I .6"b of FW lluv4.The RWCU flow analyzed for EPU is within this range. Furthermore, the EPU review included evaluation of water chemistry, heat exchanger performance, pump performance.

flow control valve capability, and filter / demineralizer performance.

Performance of each was found to be within the design of RWCU system at the analyzed flow. The RWCU analysis concludes: " There is negligible heat load effect." A small increase (z-!5%) in filter / demineralizer backwash frequency occurs, but this is within the capacity of the Radwaste system.* The slight changes in operating system conditions result from a decrease in inlet temperature and increase in FW system operating pressure." The RWCU filter / demineralizer control valves may operate in a slightly more open position to compensate for the increased FW pressure.

These valves do not have position indication, preventing quantification of this change. However, there are two 2-13

,Item 5 I Table 2.1-4 shows that the changes in RWCU system operating conditions are comparable to current conditions.

The reactor water iron and conductivity parameters at Monticello are maintained well below the EPRI BWRVIP-1 30: BWR Chemistry Guidelines

-2004 Revision guidelines for these parameters.

h r .5 NEDC-33322P, Revision 3 valves and each valve is designed to provide a flow total RWCU flow is divided equally through each val*ate of 0 to 100 gpm. Typically e.No changes to instrumentation are required for EPI), and no setpoint changes are expected due to the negligible system process paramen er changes.Previous operating experience has shown that the FW iron inpu!as a result of the increased FW flow. This predicts an increase concentration from < 1.7 ppb to < 2.0 ppb. However, this chang does not affect RWCU.to the reactor increases for EPU in the typical reactor water iron is considered insignificant, and effects of EPU on the RWCU system functional capability have been reviewed, and sfrm adequately at EPU RTP with the original RWCU system flow. U the original R ,system flow at EPU RTP results in a slight increase in the calculd reactor water conductivi rom 0.100 4S/cm to 0.115 pS/cm) because of the increasei W flow. The current reactor water ductivity limits are unchanged for EPU and -actual conductivity remains within these Table 2.1-4 shows that the change i, RWCU system o-rating conditions are small. The system flow rate is unchanged.

The reactor water iron and conductivity par ter Monticello are maintained well below the EPRI BWRVIP-1 30: BWR Water Che stry Guidelin -2004 Revision guidelines for these parameters.

Table 2.1-5 shows t -cal values for these pa eters based on CLTP rive year monthly' averages.

The es .ated EPIJ values are included.

This estimated increase is proportional to the RW System flow capacity as a percentage o edwater flow at EPU conditions.

No it is assumed for passive removal mechanisms s as source term reduction.

Tab] -.1-5 shows that the estimated increase in these parameters is not significant a that icient operating margin to.the conservative limits remains under EPU conditions.

The increase in FW line pre ure has a slight effect on the system operating conditions.

The effect of this increase is inclu d in Section 2.6.1.3 Containment Isolation.

Conclusion NSPM has evaluated the cffc ts of the proposed EPU on the RWCU system. The evaluation indicates that the RWCU syst will continue to be acceptable following implementation of the proposed EPU and will con inue to meet the requirements of the current licensing basis.Therefore, the proposed EPU i acceptable with respect to the RWCU system.Table 2.1-5 assumes an increase, which is not anticipated, in these parameters and demonstrates that this is not significant and that sufficient operating margin to the conservative limits remains under EPU conditions.

2-14 NEDC-33322P, Revision 3 Table 2.1-4 RWCU System Parameter Comparison for EPU RWCU System Parameter CLTP EPU RWCU Inlet Temperature, °F 530.2 529.7 RWCU Inlet Pressure (RPV dome pressure.

1010 1010 neglecting head), psig RWCU Outlet Temperature, 'F 449.2 449.RWCU Outlet Pressure (at the feedwater line), psig 1045 1057 Design RWCU Flow. Ibm/hr 80,000 8 6 : Maximum RWCU Flow. Ibm/hr 85,000 0--]449.11-oF9 o -0'00-2-18 Iltem 6m6 L-MT-09-042 Enclosure 1 Page 5 of 11 Table 1: Ambient Gamma Radiation as Measured by Thermoluminescent Dosimetry, Average Quarterly Dose Rates, Inner vs. Outer Ring Locations Inner Ring Outer Ring Year Dose rate (mRem tr)1991 15.2 1 992 15.1 5.115.9 I-nsert A 1994 N,14.6 14 1995 14.4 13.6 1996 14,/" 13.5 1997 .3 12.8 1998 15 14.4 1999 .1 14.3 2000 1, 14.5 2001 14.3 13.7 2002 " 15.9 \_ 14.8 20p 15.6 15____2005 16 5.4 2005 ~15.6 l2 2006 16.5 15.6N, Average 15.5125 14.8125_ _

Fit- m -1 Insert A Inner Ring Outer Ring Year Dose rate (mRem/qtr) 1991 15.2 15.8 1992 15.1 15.1 1993 15.6 15.9 1994 14.6 14 1995 14.4 13.6 1996 14 13.5 1997 13.3 12.8 1998 15 14.4 1999 15.1 14.3 2000 15.1 14.5 2001 14.3 13.7 2002 15.9 14.8 2003 15.6 15 2004 16 15.4 2005 15.6 15.2 2006 16.5 15.6 2007 16.1 15.1 2008 15.2 14.6 2009 14.9 14.4 2010 14.7 14.3 2011 14.8 14.3 2012 15.7 15.3 Average 15.12 14.62 Iltem 6 1 L-MT-09-042 Enclosure 1 Page 6 of 11 Table 1A below compares the mean for all locations in both the inner and outer rings and the mean of the peak location in each ring for the last 11 years. The maximum difference between the inner and outer ring peak locations is 1.7 mrem/qtr.

If this is taken as skyshine, as done above, it represents a maximum of 6.8 mrem/yr at current conditions.

Scaling this by 34.4 percent results in a maximum projected upper bound for offsite dose due to skyshine of 9.1 mrem/yr.Adding this to the average exposure from Table 2 of I mrem/yr results in a total of approximately 10 mrem/yr maximum potential dose to any member of the public. This is well within the 40 CFR 190 limit of 25 mrem/yr.Table 1A Off Site Ambient Gamma Radiation as Measured by TLD at the Peak Inner and Outer Ring Locations Compared to the Mean of all Locations in Each Ring Inner Ring Mean Inner Ring Peak Outer Ring Mean Outer Ring Pepk" ar All Locations Location Mean All Locations Locatioq>a-1an (mr/qtr) (mr/qtr) (mr/qtr) f r/qtr)1997 ::',,3.3 14.1 12J-f14.8 1998 15.,, 16.4 .,-ý .4 15.9 1999 15.1 7.0 14.3 15.9 2000 15.1 "' -,J6.,,,'

14.5 16.2 2001 14.3 13.7 15.0 2002 15.9 -17.4 14ý8 16.2 2003 15.. 17.6 ".15. 0 16.2 2004 -I0~ 18.4 P--4 16.7 2005 jf 15.6 17.4 15.2 16.5 20p:ý16.5 18.6 15.6 17.0 16.1 18.1 15.1 ,,-,erage Mean 1 51.3 17.1 t 4. 16.1ý Iltem 6 Insert B Inner Ring Outer Ring Mean All Inner Ring Mean All Outer Ring Locations Peak Location Locations Peak Location Year (mr/qtr) Mean (mr/qtr) (mr/qtr) Mean (mr/qtr)1997 13.3 14.1 12.8 14.8 1998 15 16.4 14.4 15.9 1999 15.1 17 14.3 15.9 2000 15.1 16.9 14.5 16.2 2001 14.3 16 13.7 15 2002 15.9 17.4 14.8 16.2 2003 15.6 17.6 15 16.2 2004 16 18.4 15.4 16.7 2005 15.6 17.4 15.2 16.5 2006 16.5 18.6 15.6 17 2007 16.1 18.1 15.1 16.5 2008 15.2 17.5 14.6 16.2 2009 14.9 15.8 14.4 15.6 2010 14.7 15.9 14.3 15.6 2011 14.8 16.3 14.3 15.8 2012 15.7 17.8 15.3 16.9 Average Mean 15.24 16.95 14.61 16.06 Iltem 6 m L-MT-09-042 Enclosure I Page 7 of 11 Table 2: Offsite Radiation Dose Assessments from 2001 through 20064ýj Source: Annu Radioactive Effluent Release Reports for MNGP 10 CFR 50 Appendix I Limits 10 CFR 20 10 20 15 5 15 15 3 10 1 Gaseous Releases Liquid Releases , ýGaseous Releases Max Site Boundary Maximum Dose to Most Likely Exposed M.,`'o Max Dose to Individuals due to Gamma OMember of General Public (1) Activities Inside Site Boundary (1)leI Max Gamma Beta Body WhOrgan Bode Thyroid Organ IB Wole Body Ira Whod (Skin)mrad/vr mrad/vr mrem/vr mremrvr-,-6em/vr m?'4y, Yr mrem mrem mrem mrem mrem 2001 3.OOE-03 4.OOE-03 1.10E-02 6.00,- 7.OOE-03 1.E-2 J.61E-05 1.72E-04 1.20E-02 1.40E-02 1.50E-02 2002 1.OOE-03 2.00E-03 1.40E-02 ,50E-03 8.OOE-03 1.40E-02 0.0 0.OOE+00 1.40E-02 1.80E-02 1.60E-02 2003 2.20E-02 1.70E-02 4.7pg " 3.90E-02 7.30E-02 4.70E-02 2.45E-07 '-,655E-07 2.00E-02 3.OOE-02 3.OOE-02 2004 1.30E-02 1.OOE-02,,.70E-02 2.20E-02 3.70E-02 3.70E-02 1.94E-10 1.9 9.OOE-03 1.10E-02 9.OOE-03 2005 3.00E-03 3 -03 2.50E-02 1.60E-02 2.50E-02 2.50E-02 0.OOE+00 0.OOE+00 ý' E-02 1.60E-02 1.90E-02 2006 1 .00E; I .00E-03 1.40E-02 8.OOE-03 6.OOE-03 9.OOE-03 0.00E+00 0.OOE+00 8.00E--'0 8.OOE-03 1.OOE-02 Averages , .E-03 6.17E-03 2.47E-02 1.62E-02 2.60E-02 2.38E-02 2.72E-06 2.88E-05 1.30E-02 1.-2 1.65E-02 Note 1: Maximum doses are calculated using the GASPAR code to provide data from the airborne pathways combined with the maximum site boundary doses.'I nsert C Item 6 I Insert C 10 CFR 50 Appendix I Limits 10 CFR 20 10 20 15 5 15 15 3 100 Source. Gaseous Releases Liquid Releases Gaseous Releases Radioactive Max Site Boundary Maximum Dose to Most Ukely Max Dose to Individuals due to Effluent Gamma Exposed Member of General Max Offsite Dose Activities Inside Site Boundary Release Organ Public (1) (1) Max Reports for Whole Whole Whole Max MNGP Gamma Beta Body Skin Thyroid Body Organ Body Thyroid Organ (skin)mrad/yr mrad/yr mrem/yr mrem/yr mrem/yr mrem/yr mrem mrem mrem mrem mrem 2001 3.OOE-03 4.OOE-03 1.10E-02 6.OOE-03 7.OOE-03 1.10E-02 1.61E-05 1.72E-04 1.20E-02 1.40E-02 1.50E-02 2002 1.OOE-03 2.OOE-03 1.40E-02 6.OOE-03 8.OOE-03 1.40E-02 0.OOE+00 0.OOE+00 1.40E-02 1.80E-02 1.60E-02 2003 2.20E-02 1.70E-02 4.70E-02 3.90E-02 7.30E-02 4.70E-02 2.45E-07 5.55E-07 2.OOE-02 3.OOE-02 3.OOE-02 2004 1.30E-02 1.00E-02 3.70E-02 2.20E-02 3.70E-02 3.70E-02 1.94E-10 1.94E-10 9.OOE-03 1.1OE-02 9.OOE-03 2005 3.OOE-03 3.OOE-03 2.50E-02 1.60E-02 2.50E-02 2.50E-02 0.OOE+00 0.OOE+00 1.50E-02 1.60E-02 1.90E-02 2006 1.OOE-03 1.OOE-03 1.40E-02 8.OOE-03 6.OOE-03 9.OOE-03 0.OOE+00 0.OOE+00 8.OOE-03 8.OOE-03 1.00E-02 2007 9.OOE-04 1.00E-03 1.05E-02 7.00E-03 7.OOE-03 1.05E-02 2.90E-03 5.92E-03_

1.50E-02 2.30E-02 1.70E-02 2008 1.90E-02 1.80E-02 8.40E-02 3.60E-02 3.50E-02 8.40E-02 0.OOE+00 0.OOE+00 3.80E-02 6.40E-02 4.80E-02 2009 1.95E-02 2.07E-02 6.24E-02 3.62E-02 2.54E-02 6.24E-02 3.21E-10 3.21E-10 3.57E-02 5.02E-02 4.40E-02 2010 1.53E-02 2.12E-02 1.15E-01 4.46E-02 3.15E-02 1.15E-01 0.OOE+00 0.OOE+00 1.39E-02 1.78E-02 1.92E-02 2011 1.18E-02 1.24E-02 1.25E-01 3.59E-02 5.30E-02 1.25E-01 0.OOE+00 0.OOE+00 2.42E-02 3.1OE-02 3.00E-02 Averages 9.95E-03 1.00E-02 4.95E-02 2.33E-02 2.80E-02 4.91 E-02 2.65E-04 5.54E-04 1.86E-02 2.57E-02 2.34E-02 Note 1: Maximum doses are calculated using the GASPAR code to provide data from the airborne pathways combined with the maximum site boundary doses.

Item 7 1 NEDC-33322P, Revision 3 Technical Evaluation In accordance with RS-O01, Review Standard for Extended Power Uprates, Revision 0, December 2003 Section 2.11.1, five specific questions are identified associated with the human factors area. Each question has been included below with the applicable response.1. Changes in Emergency and Abnormal Operating Procedures Describe how the proposed EPU will change the plant emergency (EOP) and abnormal (AOP)operating procedures.

Response: The Monticello 10 CFR 50 Appendix B plant procedure program governs changes to the AOPs and EOPs. The procedure change program and operator training program (discussed in question 5) will assure that operator performance will not be adversely affected by the proposed EPU.The following describes the procedure changes that will be implemented prior to operation at up-rated conditions and/or installation of the associated modification.

The following are the AOP procedural changes:-inc backprcssure limits have changed as a result of modifications to the low- re anged at low power conditions.

• The Station Blackout (SBO) analysis was changed to include using the HPCi suction from the Condensate Storage Tanks (CST). The AOP will be revised to require the operator to align the [IPCe suction to the Condensate Storage Tanks from the main control room, prior to the three-hour point in the event. This action was previously performed by the operators within the EOPs and is not a new action." Installation of new non-safety related 13.8 kv electrical buses and switchgear will result in changes to the electrical failure AOPs.The following are the EOP procedural changes: " The EPU will result in additional heat being added to the suppression pool during certain accident scenarios.

The Heat Capacity Temperature Limit (HCTL) curve in the EOPs will be revised to reflect the increase in decay heat loading on the suppression pool." The Pressure Suppression Pressure curve in the EOPs will be revised to reflect the increase in reactor power and increase in decay heat loading.2. Changes to Operator Actions Sensitive to Power Uprate Describe any new operator actions needed as a result of the proposed EPU. Describe changes to any current operator actions related to emergency or abnormal operating procedures that will occur as a result of the proposed EPU. (SRP Section 18.0) (i.e., Identify and describe operator actions that will involve additional response time or will have reduced time available.

Your 2-348 Item 87 L-MT-09-048 Enclosure 1 Page 16 of 50 NRC RAI No. 12 PUSAR Section 2.6.5, please define the various pump flows for RHR and CS pumps used in the DBA LOCA, Appendix R, SBO, ATWS, SBA analysis, i.e., whether these are pump runnout flow, rated flow or design flow. Please verify if these flows are consistent with the current analysis in the USAR and with operating procedures.

If these are not the same, provide a tabulation of the EPU values, the current analysis values used for analyzing these events, and the operating procedure values and provide justification for the differences.

How do these pump flows compare with flows used in the DBA LOCA analysis for long term suppression pool temperature response in PUSAR Section 2.6.1.1.1.

NSPM Response PUSAR Section 2.6.5 includes a discussion of long-term suppression pool temperature response that applies to both design basis accident profiles done to maximize containment response and to those profiles done to minimize containment response for the evaluation of ECCS pump NPSH. DBA LOCA evaluations assume pump runout capabilities for the first 10 minutes of the event sequences.

Other events such as SBO, ATWS and Appendix R have these pumps started by operator action at the design flow rates specified below. For DBA LOCA sequences it is assumed that at 10 minutes operator actions will establish containment heat removal and throttle pumps in service to maintain these pumps within NPSH limits as required by the Emergency Operating Procedures (EOPs).In the first 600 seconds of the event flow rate assumptions vary between the DBA LOCA containment response and NPSH analysis.

For this period of time operating procedures maximize injection to the reactor. The flow rates assumed by analysis are shown below: Pump Flow <600 Seconds for Containment Analysis CLTP1' EPU 3 NPSHW RHR 1 pump -NA I pump- 4320 gpm 'A' Pump -4278 gpm 2 pumps -8000 gpm 2 pumps -8641 gpm 'B' Pump -4327 gpm 4 pumps -17,400 gpm 'C' Pump -4330 gpm'D' Pump -4347 gpm CS 4370 gpm per pump 4245 gpm per pump 'A' Pump -4M86 gpm E, I_ I_ I _ _ _ I'B' Pump -4204 gpm 14129 ]--- 105 I 1. The containment analysis assumptions for CLTP are shown in USAR Table 5.2-7. Table 5.2-7 shows that for the first 10 minutes 1 CS and 2 RHR pumps were running at nominal flow rates. The 4 pump case was used to evaluate containment response for NPSH only.2. The flow rates for the NPSH analysis are based on a hydraulic model that provides an evaluation of actual capability based on individual pump characteristic curves and system hydraulic resistance.

These values are the same for CLTP and EPU and were used to evaluate NPSH.3. The EPU containment analysis is an average of all pumps from the NPSH analysis.

Item 8 8 L-MT-09-048 Enclosure 1 Page 17 of 50 9 I Event I RHR Flow (gpm)A 1 CS Flow (gpm _, 4129 I CLTP I EPU I Procedure I CLTP [EPU I I DBA 4278 4278 As Needed 1 4285 42864" As Needed 1<600 seconds 4327 4327 4204 4204 < 4058 (RHR pumps 4330 4330 A, B, C, D 4347 4347 3388 CS pumps A and B) ..DBA >600 4000 4000 4000 / pump 3035 a036' 2.2 v seconds 3029 302-_SBA 3 NW -4320 As Needed 1 NA4 3020 As Needed'<600 seconds SBA NWA 4000 4000 /pump NA4 3020 28.>600 seconds ATWS 6 NA4 4000 / 4000 / pump NA4 3035 See Note pump Number 5.SBO NA4 4000 / 4000 / pump NA" 0' Not used pump 6 Appendix R 4000 4000 4000 3029 3029 2700-41008 1-5---RHR and CS will initiate with the injection valves fully open, i.e. in pump runout flow. Procedures allow the operators to inject as needed to achieve desired reactor water levels to establish adequate core cooling. NPSH limits are provided in EOPs which allow pump flow at analytical values shown or higher.Cautions against exceeding NPSH limits are provided in EOPs to insure pump reliability.

CS rated pump flow rate is 3020 gpm at 145 psig reactor pressure.

RHR pump design rated flow rate is 4000 gpm/pump in containment cooling mode. LA>3150 1 CS flow is required by EOPs to be >2800-gpm if at 2/3 core height to insure adequate core cooling.3 For the SBA prior to 600 seconds the event is bounded by the DBA LOCA since makeup requirements are substantially lower. The use of one RHR and one CS pump was assumed.4 SBA, ATWS and SBO were not evaluated as part of the CLTP license basis and therefore are shown as not applicable, NA, in table above.6 The EOPs for an ATWS event control water level in a band that insures acceptable power reduction.

CS is not a preferred injection source and other systems would be expected to be used to maintain vessel inventory, therefore the use of CS flow of 3035 gpm for NPSH evaluation is conservative.

RHR is identified as a preferred injection source; however the maximum flow requirement (16,000 gpm)would be associated with suppression pool cooling which is assumed above.6 RHR flow for suppression pool cooling does not start until restoration of power after 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. All pumps are started in torus cooling mode after 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.7 Core cooling is provided by HPCI for this event and therefore CS is not used.8 The analysis assumed a maximum CS flow of 3029 gpm, the discrepancy between the procedure and analysis is being addressed by CAP 01176349.9 The RHR pumps are assumed to provide 4000 gpm. The procedures control this flow rate. L-MT-12-048, Section 6.6.2 notes that actual pump flow can be 4178 gpm if the minimum flow valve fails open. Cautions against exceeding NPSH limits are provided in EOPs to insure pump reliability.

CS rated pump flow rate is 3020 gpm at 145 psig reactor pressure.

RHR pump design rated flow rate is 4000 gpm/pump in containment cooling mode.

L-MT-09-048 Enclosure 1 Page 37 of 50 NRC RAI No. 29 PUSAR Section 2.6.5, for the NPSH cases analyzed, DBA LOCA, Appendix R Fire, ATWS and SBA, it is stated that containment overpressure (COP) is required to meet the required pump NPSH. Please clarify whether the COP required is necessitated due to conservatism in the analysis, and whether it can be (or has been) shown that with a realistic analysis, COP is not needed.Additional information is provided in NSPM letters L-MT-12-082 NSPM Response Iand L-MT-12-107 that considers the conservatism required by NSECY 11-0014 (References 29-3 and 29-4).At MNGP only the DBA and Appendix R fire events were previously evaluate need for containment overpressure to satisfy NPSH requirements for the EC The most recent NRC approval of the use of containment overpressure at M was with approval of Amendment 139 (Reference

1) on June 2, 2004. The is the first review of the other events for containment overpressure needs.,d for the CS pumps.:nticello-PU project The m~aimum wct::cl prcccuro roquirod in tho tablc bolow i6 the preraUre abov atmozphi I przzzUrl needecd to support ECCS pump NPSH i.e., eelntainmznt evcrprcccurc.

!n all eaecoc atmocphori perocure wa6 dofinod As 11.2 pcoia. The containmonet ovorproccuro~

roquired ;A- b-RAcod- onR *ha u of A dete1rMdinitic..Event EP6U Maximum We't~vl Prcsswe Reguircd (.Ap~e"* R--Gese-Ner-24 Small Break Aeozktnt&r&

Design Besio Aeeident 6741-PRFO Caco No. I A4WG 2-94 PRFO9 Case Ne. 2 6G4GF Statien Blaokout 0-Iltem 8 L-MT-09-048 Enclosure I Page 38 of 50 The evaluation of ECCS pump NPSH for the DBA LOCA was performed under calculation CA-07-038, Rev. 0, "Determination of Containment Overpressure Required for Adequate NPSH for Low Pressure ECCS Pumps with Suction Strainer Debris Loading at EPU Conditions." This calculation was provided to the NRC as part of letter L-MT-09-004 (Reference

2) on December 18, 2008.Cases 5 and 6 of this calculation provided a statistical evaluation of the limiting design basis accident to determine if a more realistic approach would support that COP is not needed. The statistical design basis accident evaluation provided by these cases assumed the availability of only 1 division of power consistent with the deterministic design basis accident analysis approach.

These evaluations showed the need for 1.8 psig of containment overpressure with these assumptions.

Case 10 of the calculation did an evaluation assuming containment failure, i.e., no overpressure but realistically assumed the availability of both divisions of ECCS equipment.

In this case no containment overpressure is required.The remaining events were not evaluated statistically.

Reference:

29-1: Amendment 139 to Facility Operating License No. DPR-22 on June 2, 2004.29-2: NSPM letter L-MT-09-004 from Timothy O'Connor to U.S. NRC, "Response to NRC Containment

& Ventilation Branch Request for Additional Information (RAIs)dated December 18, 2008 (TAC No. MD9990)." 29-3: NSPM letter L-MT-12-082 from M A Schimmel to U.S. NRC, "Monticello Extended Power Uprate and Maximum Extended Load Line Limit Analysis Plus License Amendment Requests: Supplement to Address SECY 11-0014 Use of Containment Accident Pressure (TAC Nos.MD9990 and ME31145)," dated September 28, 2012.29-4: NSPM letter L-MT-12-107 from M A Schimmel to U.S. NRC, "Monticello Extended Power Uprate and Maximum Extended Load Line Limit Analysis Plus License Amendment Requests: Supplement to Address SECY 11-0014 Use of Containment Accident Pressure, Sections 6.6.4 and 6.6.7 (TAC Nos. MD9990 and ME31145)," dated November 30, 2012.

FIt em L-MT-09-073 Enclosure 1 Page 6 of 11 SCVB RAI No. 5 Please provide numerical values in the following table in the blank cells and verify the information in the filled-in cells: NSPM RESPONSE The information provided here is for the evaluation of NPSHr for the ECCS pumps.

Item 8-1 L-MT-09-073 Enclosure 1 Page 7 of 11 ATWS- CS 1 3035 23 PRFO CS 2 0 NA Case 1 RHR 1 4000 189.03 16.173 21.163 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 33.913 3, 22 RHR 2 4000 188.804 16.204 20.434 32.084 22 RHR 3 4000 22 RHR 4 4000 22 ATWS- CS 1 3035 23 PRFO CS2 0 NA Case 2 RHR 1 4000 191.33 17.263 22.493 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 34.503 3% 22 RHR 2 4000 191.04 17.204 22.414 34.444 22 RHR 3 4000 22 RHR 4 4000 22 ATWS LOOP CS 1 CS 2 RHR 1 RHR 2 RHR 3 RHR 4 3035 0 447-3 49.44,, 2494-!2388 6 hors F7.6 h-ou-ris 123.9 5S-Hreff 3%23 NA NA'23 NA4 223.5 NA'NIA APP R-SORV (Case 1)CS 1 CS2 RHR 1 RHR 2 RHR 3 RHR 4 0 \3029 0 0 4178 195 i.14 4 1f7.6 F24-1.2-3 128.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> 31.2.:2, APP R- CS 1 0 7 NA No SORV CS 2 3029 /23 (Case 2) RHR 1 0 RHR2 49W 194.7 4969 17. 1;,- 21.11 3- 3 %2-RHR 3 0 28.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> _ NA RHR 4 0 3.8NA Small CS 1 3929 Steam Line CS 2 0 NA Break RHR 1 0 a 0" 24-.44 0 i4 4 3 NA Short RHR 2 0 [~uded by DBA LOCA and not required by SECY 11-0014 NA Term RHR 3 4&2Q EI Item 8 L-MT-09-073 Enclosure 1 Page 8 of 11 (<600 RHR 4 0 NA seconds)Small CS 1 3G29 2Q Steam Line CS 2 0 NA Break RHR 1 0 2-7. 43O .. NA Long Term RHR 2 0 4 1 ....... 1 NA (>600 RHR 3 499 [Bounded by DBA LOCA and not required by SECY 11-0014 ]4 seconds) RHR 4 0I__ NA Station CS 1 0 NA Blackout CS 2 0 NA Event RHR 1 0 157.4@3 hrs 14.26@3 hrs 36.74@3 hrs NA (4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> RHR 2 0 for HPCI for HPCI 2 for HPCI 0 28.42 1% NA duration)

RHR 3 0 NA RHR 4 0 NA HPCI 3000 17 Station CS 1 0 NPsHreff3%

NA Blackout CS 2 0 NA (RHR used RHR 1 4000 41.27@4 hrs /22 after 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> RHR 2 4000 175.5@4 hrs 14.22 for RHR 086.2 3% 22 point) RHR 3 4000 22 RHR 4 4000 22 HPCI 0 NA Notes: IN ot U sed .,,_,,. I 411A '13A.......... .It .... I*.

• J---- '=IPL L I I --WaSFU run Y io onlyazy. +R no cPProcc1Ion p981 iGomporFiur FoquIFrc to cuIppon PlraM MROr :nc IR iimtn PUMPS oPheric ProeurcF Of 11.26 pc6im at *ho- And of4* thcporiod.

ThoDA LORCAI ropoc foA ~n drt ic Fmoro........-.......

............2. NPSHA for HPCI for the SBO event is based on use of atmospheric pressure only not the actual containment pressure that would exist at that point in the containment time history. HPCI is not required to start again after 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> for this event.3. Review of time histories resulted in slight differences in limiting data as compared to values shown in partial time histories provided in PUSAR Section 2.6.5, Tables 2.6-2 through 2.6-9. All time steps are reflected in Figures 2.6-1A through 2.6-8 showing complete time history results.4. Limiting time step provided in PUSAR Section 2.6.5 tables.5. Assumes suction strainer debris loading per PUSAR Section 2.6.5 L-MT-09-073 Enclosure 1 Page 9 of 11 SCVB RAI No. 6a Please provide the basis for each of the flows in the above table and why the flows are conservative for analyses using containment accident pressure.

This question has been changed to "provide a description of conservative assumptions in COP analysis" NSPM RESPONSE The basis for the DBA LOCA short term (runout) and long term (throttled) flows is the original NPSH calculation of record, which were developed during power rerate (MNGP's first EPU) for containment overpressure amounts that were subsequently approved by the NRC. These flows were derived from hydraulic models of the different phases of ECCS pump operation during a DBA LOCA. The flow values are consistent with ECCS pump design flows as described in the USAR and with periodic pump operational testing.For the DBA LOCA short term, the time to reactor vessel level recovery is less than 10 minutes such that the timing of the runout flows are conservative with respect to actual flows after level recovery.

The 10 minute time is the standard time period prior to crediting manual operator actions. The short term (runout) flow values were developed from FLO-SERIES hydraulic models with all ECCS pumps running.The steady state floWc for the PRA. OCAS and Appendi* R ovont arc eencistcnt with flows used for the CLT-P COP Analysis which wcrc used by NSPIV to establish the existing COP design bacis as approved by Lioonse Amendment 130. Please see the floW .The flow rates used for accidents and AOOs are shown in L-MT-09-073, SCVB[RAI No. 5 and are further discussed in L-MT-12-082, Enclosure Section 2.0.According to Section 6.2.3.2.1 of the MNGP USAR, each RHR pump is designed to deliver greater than or equal to 4000 gpm. This provides margin above the minimum required injection flow (3870 gpm) assumed for the plant safety analysis.

For the torus cooling mode, the design flow rate is 4000 gpm. A plant periodic surveillance testing demonstrates that each RHR Heat Exchanger is capable of passing the single RHR pump containment cooling requirement of 4000 gpm.According to ction 6.2.2.1 of the MNGP USAR, each CS pump is required to inject 2800 gpm with "-.g gpm allowance for leakage. Per section 6.2.2.2.1 of the USAR, the CS design flow capacity is 3020 gpm. At MNGP, each CS pump is equipped with a locked-open minimum flow line. The hydau.li mo., del , hew, d that the ..r.lting Gs .floW to proey:dc 2800 gpm was 3036 gpmn (235 gpmn minimum flow !*Re) durfing a DBA periodic plant surveillance testing confirms that the CS pumps can deliv flow rate of 80gpm. L-MT-12-082 provides additional information on CS and RHR pump capabilities.

It em 91 NEDC-33322P, Revision 3 52.9 0 F* Turbine Building -Feedwater and Condensate pump areas, andissociated switchgear The increase in temperature in the Reactor Building areas will be _48 as a result of minor heat load increases and is within the design temperatures for the areas. Modifications for the condensate and feedwater pumps/motors are necessary for full EPU operation, which will increase heat loads in the Turbine Building.

The ventilation systems in the condensate and feedwater pump areas, and associated switchgear, will be evaluated in more detail when the modification designs are confirmed and the ventilation systems will be modified for EPU to accommodate the increased heat loads to maintain these area temperatures within acceptable values if necessary.

Conclusion NSPM has evaluated the effects of the proposed EPU on the power dependent HVAC systems that serve the Turbine Building and Radwaste Building.

Several plant areas will have higher heat loads but HVAC system operation is not adversely affected.

The HVAC systems in the condensate and feedwater pump areas, and associated switchgear, will be evaluated in more detail and modified if necessary to support EPU operation as a result of the modifications to those systems for EPU. Therefore, the proposed EPU is acceptable with respect to I IVAC system operation in the Turbine Building, Reactor Building, and drywell.2.7.6 Engineered Safety Feature Ventilation System Reaulatory Evaluation The function of the engineered safety feature ventilation system (ESFVS) is to provide a suitable and controlled environment for ESF components following certain anticipated transients and DBAs.The NRC's acceptance criteria for the ESFVS are based on (1) GDC-4, insofar as it requires that SSCs important to safety be designed to accommodate the effects of and to be compatible with the environmental conditions associated with normal operation, maintenance, testing. and postulated accidents; (2) GDC-l 7, insofar as it requires onsite and offsite electric power systems be provided to permit functioning of SSCs important to safety; and (3) GDC-60, insofar as it requires that the plant design include means to control the release of radioactive effluents.

Specific NRC review criteria are contained in SRP Section 9.4.5.Monticello Current Licensing Basis The general design criteria listed in RS-001 are those currently specified in 10 CFR 50, Appendix A. The applicable Monticello principal design criteria predate these criteria.

The Monticello principal design criteria are listed in USAR Section 1.2, "Principal Design Criteria." In 1967, the Atomic Energy Commission (AEC) published for public comment a revised set of proposed General Design Criteria (Federal Register 32FR10213, July Ii, 1967). Although not explicitly licensed to the AEC proposed General Design Criteria published in 1967, Northern States Power Company (NSP), the predecessor to NSPM, performed a comparative evaluation of the design basis of the Monticello, Unit 1, with the AEC proposed General Design Criteria of 2-232 Item 9fl L-MT-09-048 Enclosure 1 Page 43 of 50 NRC RAI No. 34 PUSAR Section 2.7.5, under heading "Technical Evaluation", please describe how the increase in the area temperature of 1.8 OF or less is calculated.

Is this based on the EPU revised design heat load in that area while the currently designed HVAC system serving that area is operating?

N S- PMo- 13" -s--INSPM peprformed a calculation that determined that the maximum roM PMp Areas in the Reactor Building that will experience higher loads due to EPU are the Steam Tunnel, HPCI Room, and the RHR and Core Spray Pump Rooms. The Steam Tunnel (less than 1°F) and the RHR and Core Spray Pump Rooms (-1-8-42F) are expected to see a small increase in the calculated room temperature.

The HPCI is not expected to see an increase in the calculated room temperature.

The mnthod used to calculate these increases is given below.Steam Tunnel -The less than V 0 F increase is calculated as follows: Heat loads to the room considered in design calculations are from system piping (Main Steam and Feedwater).

EPU does not impose changes to the Main Steam temperature, therefore there are no changes to heat loads from the Main Steam System. For Feedwater, EPU results in a 12.6°F increase (383.7 0 F to 396.3 0 F) at 2004 MWt (LPU). Based on a reference temperature of 90°F this 12.6 0 F increase in pipe temperature represents a 4.3 percent increase [12.61(383.7-90)]

in the difference between the reference temperature and piping temperature.

From existing design calculations at a room temperature of 104°F and a pipe insulation temperature of 160°F, which are the worst case heat load conditions evaluated, the feedwater piping accounts for approximately 15 percent of the piping heat load. Given that room temperature is linearly proportional to heat load and the feedwater temperature increases

4.3 percent

and that the feedwater piping accounts for 15 percent of the total heat load, the feedwater increase results in a 0.7 percent increase (4.3 percent of 15 percent) in room temperature above the reference temperature.

Conservatively, taking a 1 percent increase and applying it to the difference between the maximum measured room temperature (121.8 0 F) and the reference temperature of 90'F, results in a EPU room temperature increase of 0.3°F [0.01*(121.8-90)].

In addition to the heat load increase, it was assumed that the cooling coil returns an increased air temperature to the room. Assuming a 10°F approach for the coiling coil and applying the same percentage increase results in an additional 0.1°F increase to the room. Therefore, the estimated total room temperature increase was determined to be 0.4 0 F.

Iltem 9 L-MT-09-048 Enclosure I Page 44 of 50 RHR & Core Spray Pump Rooms -The 4--. increase is calculated as follows: lectrical heat loads in the room remain unchanged.

Piping heat loads are from RHR/a Core Spray piping, with the majority of the piping containing torus water, with th toru water temperature following a LOCA increasing as a result of EPU. The toru temp ture used in existing design calculations is based on a maximum torus temper re of 191OF. The maximum EPU torus water temperature following OCA is 208°F. T 17 0 F increase was evaluated for its affect on the piping heat lo and the resulting ro temperature.

The RHR piping and heat exchanger surface are insulated.

E ing design calculations calculate the temperature of the " sulation surface and con ude that this temperature will quickly be exceeded b he room temperature and t refore the RHR piping does not play a significa role in the room heat load. The EP rus water temperature was used to repeat e calculations and the same conclusion) s reached for EPU operation.

The Core Spray piping is n tinsulated and thus pipe surfac mperature was assumed to be the torus water tempe ure. The contribution of thi iping to the overall heat load varies as the room and to s water temperature ch ge. Existing design calculation tabulate Core Spray ing heat loads as unction of room temperature and torus water temperature.

The max um Core Spra/piping load of 63,293 Btu/hr occurs at a room temperature of 115°F and e maximu orus water temperature of 191°F.Using the fixed electrical load (341,500 tu/hr) r suits in a maximum total heat load of 404,793 Btu/hr of which the piping accou s f 15.6 percent (63,293 / 404,793) of the overall load.Based on a reference temperature of 9 F the OF increase in pipe temperature represents a 16.8 percent increase [1 /(191-90)]

the difference between the reference temperature and piping t perature.

A 1 .8 percent increase in the maximum Core Spray piping hea oad results in an U piping load of 73,927 Btu/hr (1.168 x 63,293). Adding this t the Electrical Heat Loa (341,500 Btu/hr) results in a maximum EPU heat load of 5,447 Btu/hr.From above, the worst c e piping heat load accounts for 15. ercent of the total heat load. Given that room mperature is linearly proportional to he load, the torus temperature increas 16.8 percent, and that the core spray pipin accounts for 15.6 percent of the total eat load, the torus water temperature increase sults in a 2.7 percent increase 16.8 percent of 15.6 percent) in room temperature.

Existing desi n calculations calculate the maximum room temperature to b 143.8 0 F.Taking a 2 percent increase and applying it to the difference between the ximum measur room temperature (143.8 0 F) and the reference temperature of 90`F sults in a EPU oom temperature increase of 1.5 0 F [0.027*(143.8-90)].

In addition to the eat load/ 'crease it was assumed that the cooling coil returns an increased air temper re to e room. Assuming a 10°F approach for the cooling coil and applying the same Iltem 9 1 L-MT-09-048 Enclosure 1 Page 45 of 50 BUF6raenea inomnas es2eJts in an Amififitn~ii it.- L- ...I..0.27 0 F ces to the roani. Therefore,-

mu tutat ro~~m tcmDcrature increaa~ w~m ~

LU I .U I.........................

O The original response to this RAI indicated a 1.8 0 F increase was determined using engineering judgment based on heat load increases in the rooms. Since that response, a formal calculation for the building heatup resulting from the LOCA scenario at EPU conditions has been finalized.

This calculation concluded that an increase of 2.9*F for RHR and CS pump room temperatures following a LOCA at EPU conditions would occur.GOTHIC 7.2a was used for the modeling software which in combination with enhanced Reactor building conductors, volumes, and surface areas updated for EPU, provides a more accurate analysis of the LOCA event than previous modeling versions.

No methodology changes were made. The 2.9 0 F temperature increase for the RHR and CS pump rooms has been evaluated and determined to be acceptable.

No modifications in the RHR and CS pump rooms are required due to the higher LOCA temperatures at EPU conditions.

ilt-em 1-1 NEDC-33322P, Revision 3 2a and 2.2-2b). These piping systems have been evaluated using the process defined in Appendix K of ELTR I and found to meet the appropriate code criteria for the EPU conditions, based on the design margins between actual stresses and code limits in the existing design. The original construction code was USAS B31.1.0 -1967 Power Piping Code. The existing code of record for many systems is ANSI B31.1.0, 1977 Edition with Addenda up to and including Winter 1978 and ASME Boiler and Pressure Vessel Code -Section II, Division 1 1977 Edition through the Winter 1978 Addenda for torus attached piping. The existing code of record for other specific systems includes other versions of ANSI B31.1.0 and/or ASME Section 1i1, Division 1. The Codes of Record as referenced in the appropriate calculations, code allowable values, and analytical techniques were used and no new assumptions were introduced.

For those systems that do not require a detailed analysis, pipe routing and flexibility were evaluated and determined to be acceptable.

Pipe break criteria were evaluated in accordance with Monticello Design Criteria, which are based on the Giambusso letter, SRP 3.6.2 and Generic Letter 87-1 1. Where required, percentage increases were applied to the calculated stress levels at applicable piping system node points.The combination of stresses was evaluated to meet the requirement of pipe break criteria.

Based on these criteria, no new postulated pipe break locations were identified.

Pipe Supports Operation at the EPU conditions increases the pipe support loadings on some BOP piping systems due to increases in the temperature of the affected piping systems (see Tables 2.2-2a, 2.2-2b. and 2.2-2c).The pipe supports for the systems affected by EPU loading increases were reviewed to determine if there is sufficient margin to code acceptance criteria to accommodate the increased loadings.This review shows that, in most cases, support loads under EPU conditions are in compliance with the appropriate Code criteria.

Additional e will be0 L, & p M &O ... /ee.4he qupe~ will be mediii ripd 8!z~tina EPU eenditicns (see Table 2.2 2d) io enzurz ccde limnits arc Nt c.c:de.d.'_l\

Detailed analyses of EPU loading has been completed and the results/indicate that code limits are not exceeded.Main Steam and Associated Piping System Evaluation (Outside containment)

The MS piping system (outside containment) was evaluated for compliance with Monticello criteria, including the effects of EPU on piping stresses, piping supports, and the associated building structure, turbine nozzles, and valves.Because the MS piping pressures and temperatures outside containment are not affected by EPU, there was no effect on the analyses for these parameters.

The increase in MS flow results in increased forces from the turbine stop valve closure transient (TSVC). The turbine stop valve closure loads bound the MSIV valve loads because the MSIV closure time is significantly longer than the stop valve closure time. Due to the magnitude of the TSVC transient load increase, the transient event was reanalyzed.

The MS piping was then reanalyzed using this revised load definition.

The MS turbine stop valve closure transient analysis pipe stress and support results are provided in Table 2.2-2c.2-37 Item 1Ii NEDC-33322P, Revision 3 Pipe Stresses The results of the Main Steam system piping analysis indicate that piping load changes do not result in load limits being exceeded for the MS piping system outside containment except for a few small bore lines. Aadditional aic:tail.d ana...e. will be p...p.r..

andl.r !he piping %,ill be med~fled for these small befe lines prier tz EPU4 implemenwaizr.

ie ensure eede litmits aft not z,..eeded (S:e Table 2.2 2d). No new postulated pipe break locations were identified.

Peu r Detailed analyses of EPU loading has been completed and the results Pipe Supports "' indicate that code limits are not exceeded.The pipe supports and turbine nozzles for the MS piping system outside containment were evaluated for the increased loading and movements associated with the turbine stop valve closure transient at EPU conditions.

The evaluations demonstrate that the supports and turbine nozzles have adequate design margin to accommodate the increased loads and movements resulting from EPU except for a few supports.

Aidi:inal detailed an.lyss ..ill be prepa...anJ_'zr the suppert1 will kb mcadfied pri@ to 611W impk-m.ntatiztn le ....u.. eed1 limits are ...t emeeeded (See Table2.2 2d) Based on existing margins available for the outside containment MS piping supports, except for those supports that may require modification, it was concluded that EPU does not result in reactions on existing structures in excess of the current design capacity.

Structural capacity associated with modified supports will be evaluated prior to EPU implementation to ensure design capacity is not exceeded.Conclusion NSPM has evaluated the structural integrity of pressure-retaining components and their supports and has addressed the effects of the proposed EPU on these components and supports.

The evaluation indicates that pressure-retaining components and their supports will continue to meet the requirements of 10 CFR 50.55a and Monticello's current licensing basis following implementation of the proposed EPU. Therefore, the proposed EPU is acceptable with respect to the structural integrity of the pressure-retaining components and their supports.2.2.3 Reactor Pressure Vessel Internals and Core Supports Reaulatory Evaluation Reactor pressure vessel internals consist of all the structural and mechanical elements inside the reactor vessel, including core support structures.

The NRC's acceptance criteria are based on (1) 10 CFR 50.55a and GDC-l, insofar as they require that SSCs important to safety be designed, fabricated, erected, constructed, tested, and inspected to quality standards commensurate with the importance of the safety functions to be performed; (2) GDC-2, insofar as it requires that SSCs important to safety be designed to withstand the effects of earthquakes combined with the effects of normal or accident conditions; (3) GDC-4, insofar as it requires that SSCs important to safety be designed to accommodate the effects of and to be compatible with the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents; and (4) GDC-10, insofar as it requires that the reactor core be designed with appropriate margin to assure that specified acceptable fuel 2-38 Iltem 11 NEDC-33322P, Revision 3 Table 2.2-2d Piping Components Requiring Further ReconciliationSystem I Vi~m team (Outside Containment)'

2 Feedwa and Condensate (from condens valves dw of the HP Heaters), 3 Torus Attached 4 RHR (BOP Condensate Se ce Water Lin 5 Cross Around Piping 1,2 ite pump'to the MO to pending p p changes 6 CARV Discharge Piping *'Notes: 1. Walkdowns in H' iation Areas are required to complete calcula s.2. Scope of ross Around Piping Analysis is being determined upon turbine modi tion.3. ope of CARV Analysis is being determined based upon turbine modification.

Table 2.2-2d is no longer required as piping analyses have been completed.

The results from the piping analyses indicate that code limits are not exceeded.2-63 Iltem 11 ]L-MT-09-044 Enclosure 1 Page 26 of 46 EMCB RAI No. 17 Steam flow and feedwater flow will increase as a result of the CPPU implementation.

The load due to the TSV fast closure transient is used in the design of the MS piping system. Page 2-31 states that "Due to the magnitude of the TSVC transient load increase [at EPU], the transient event was reanalyzed.

The main steam piping was then reanalyzed using this revised load definition." a) Provide a quantitative summary of the MS and associated piping system evaluation (inside and outside containment), including pipe supports, that contains the increased loading associated with the TSV closure transient at EPU conditions, along with a comparison to the code allowable limits. For piping, include maximum stresses and data at critical locations (i.e. nozzles, penetrations, etc), including fatigue evaluation CUFs, where applicable.

For pipe supports, state the method of evaluation for EPU conditions and confirm that the supports on affected piping systems have been evaluated and shown to remain structurally adequate to perform their intended design functions.

For non-conforming piping and pipe supports, provide a summary of the modifications required to ensure that piping and pipe supports are structurally adequate to perform their intended design functions and the schedule for completion of these modifications.

b) For FW and condensate, please respond as in part (a) of this RAI.NSPM RESPONSE Response to Part a The Main Steam system piping analysis results, including TSV closure loads are summarized below. The piping system was evaluated (by re-analysis versus scaling)using requirements from the existing code of record. The supports in the Main Steam piping remain adequate to perform their intended design functions.

An updated status for PUSAR Table 2.2-2d is provided in response to RAI 12, Part b above. There are no non-conforming pipes or supports requiring modifications on the main steam system.

Item 11 L-MT-09-044 Enclosure 1 Page 27 of 46 Main Steam Inside Containment Maximum EPU Results (Highest Interaction Ratio): Maximum Pipe Stresses Load Service Combination Level Node Stress Allowable Ratio_ _ _i___i S/Allow P+DW B 161 7709 15000 0.51 TH Range B 203 22940 22998 1.00 P+DW+OBE B U08 17823 18000 0.99 DW+TSV+SRV+SSE D U08 31261 36000 0.87 Note: 1. High Energy Line Breaks locations are not postulated inside containment.

2. Due to the revised analysis of the turbine stop valve closure loads, comparison to pre-EPU values is not meaningful.

Maximum SRV Flange Loads Inlet Flane Service 1 Node Moment Allowable Ratio Load Condition LevelI ft-lb ft-lb M/Allow DW+TH B U07 14558 34083 0.427 DW + TH + Level B Dynamic B U07 39362 68167 0.577 DW + TH + Level D Dynamic D U07 65909 99750 0.661 Outlet Flange Service Node Moment Allowable Ratio Load Condition Level ft-lb ft-lb M/Allow DW+TH B U08 13663 31000 0.441 DW + TH + Level B Dynamic B U08 34907 62083 0.562 DW + TH + Level D Dynamic D U08 57547 91250 0.631 Maximum RPV Nozzle Loads RPV Nozzle N-3D Service Node Fx Fy Fz Mx My Mz Loads TLevel IIb lb lb ft-lb -ft-lbI ft-lb Maximum Loads B 101 6667 18555 4979 67422 18193 98764 Allowables B 101 19392 51712 19392 .258562 32320 258562 Maximum/Allowable B 101 0.344 0.359 0.257 1 0.261 0.563 0.382 Maximum Flue Head Anchor Loads Penetrations X7A, X7B1, X7C, X7D -Side Bolt Evaluation Service Node Tension Shear Tallow Sallow IR Load Condition Level I lb lb lb Ib T/Ta+S/Sa DW+TH+SSE+BREAK (X7D) I 2 106702 17509 157500 96250 0.859 DW+TH+SSE+BREAK (X7A) D 30 1 107227 16683 157500 96250 0.854 L-MT-09-044 Enclosure 1 Page 28 of 46 Maximum Support Loads MS Relief Valve Dischar e Line Support RV25A-H1 (spring hanger)Max Min Service Node Load Allowable IR Load Allowable IR Load Condition Level lb lb Max/Allow lb lb Allow/Min_1 RDW+TH+ I 1 7. RS(TS, RV OB) B 285 11341 1344 0.9 1121 780 10.671 Ilnsert A ftaln Steam Outside Containment EPIU Results (Highest Interaction Ratio): Maximum pe Stresses d* Service Node Stress Allowable Ratio Level psi psi S/Allow -P+DW B X7A 6877 15000 01.4 TH Range B TURB 19441 22500 -T6 P+DW+TSVB 268 12236 18000 0.68 DW+TSV+SRV+SSEl 268 13795 26 0.52 HELB DW+TH+OBE B TURB 1 27559 ,ý000 0.92 z'11Z Maximum Turbine Loads N. y Load Service Node Mx 8le Ratio Mz Allowable Ratio Combination Level ft-lb ft-lb MxIAllow ft-lb ft-lb Mz/Allow DW B

• 32 1 413000 78 171446 722000 0.237 DW+TH B

• 1321 413000 0.6ý 302310 1722000 0.419*Note: Loads from all turbine nod ere combined Maximum Support L s Main Steam Line 'DDort PS-16. Node 283 Max Service Load Allowable IR Load ,ndition Level Component lb lb Max/Allow+TH+SRSS(TSV,SRV,OBE)

B Anchor bolt 20026 20731 0.966 Response to Part b The maximum Feedwater system operating temperature is 397.7 0 F at EPU conditions for the Feedwater piping from the outboard containment isolation valve to the containment and inside containment.

This value is bounded by the original analysis temperature of 400 0 F. The design pressure for this portion of the Feedwater system is unchanged by EPU. Therefore this piping is unaffected by EPU relative to HELB postulation.

The current design basis for Feedwater piping analysis does not include fluid transient analysis.

The stress analyses for the Feedwater piping from the outboard Item 11 1 Insert A Maximum Flued Head Anchor Loads Penetrations X7A, X7B, X7C, X7D -Bolt Evaluation Maximum Pipe Stresses (Outside Containment)

Load Combination Service Node Stress Allowable Interaction Level (psi) (psi) Ratio P-+ DW A TURD 7650 15000 0.51 TH Range A TURB 16618 22500 0.74 P + DW + TSV B TURC 12288 18000 0.68 P + DW + OBE* B X7A 14289 18000 0.79 DW+SRSS(TSV, D X7A 21026 26325 0.80 SSE)*HELB TH N/A TURB 16618 18000 0.92 HELB N/A TURD 32631 30000 1.09**DW+TH+OBE I I I*Excluding seismic category II pipe between Stop Valves and Turbine**Indicates a HELB at this location Maximum Turbine Loads Load Service Mx Allowable Interaction Mz Allowable Interaction Combination Level (fi-lb) (ft-lb) Ratio (ft-lb) (fi-lb) Ratio DW B 37143 413000 0.090 184886 722000 0.256 DW + TH B 284603 413000 0.689 163155 722000 0.226 Note: Loads from all turbine nodes were combined Maximum Support Loads (Outside Containment)

Main Steam Line Support PS-16, Node 283