CNL-13-104, Response to NRC Request for Additional Information Regarding the Review of License Renewal Application, Sets 11 (B.1.40-4a, B.1.25.1a), 13 (B.1.41-4a),14 (3.5.1-57, 3.5.1-87)

Response to NRC Request for Additional Information Regarding the Review of License Renewal Application, Sets 11 (B.1.40-4a, B.1.25.1a), 13 (B.1.41-4a),14 (3.5.1-57, 3.5.1-87)

ML13296A017
Person / Time
Site:	Sequoyah
Issue date:	10/21/2013
From:	Shea J W Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CNL-13-104, TAC MF0481, TAC MF0482
Download: ML13296A017 (45)

Text

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402 CNL-13-104 October 21, 2013 10 CFR Part 54 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Sequoyah Nuclear Plant, Units 1 and 2 Facility Operating License Nos. DPR-77 and DPR-79 NRC Docket Nos. 50-327 and 50-328

Subject:

Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units I and 2, License Renewal Application, Sets 11 (B.1.40-4a, B.1.25.1a), 13 (B.1.41-4a), 14 (3.5.1-57, 3.5.1-87) (TAC Nos. MF0481 and MF0482)

References:

1. Letter to NRC, "Sequoyah Nuclear Plant, Units 1 and 2 License Renewal," dated January 7, 2013 (ADAMS Accession No. ML13024A004)

2. NRC Letter to TVA, "Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application

-Set 11," dated August 22, 2013 (ADAMS Accession No. ML1 3224'A1 26)3. NRC Letter to TVA, "Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application

-Set 13," dated September 16, 2013 (ADAMS Accession No.ML13256A007)

4. NRC Letter to TVA, "Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application

-Set 14," dated September 26, 2013 (ADAMS Accession No.ML13263A338)

By letter dated January 7, 2013 (Reference 1), Tennessee Valley Authority (TVA) submitted an application to the Nuclear Regulatory Commission (NRC) to renew the operating licenses for the Sequoyah Nuclear Plant (SQN), Units 1 and 2. The request would extend the licenses for an additional 20 years beyond the current expiration date.Printed on recycled paper # ý, ? (

U.S. Nuclear Regulatory Commission Page 2 October 21, 2013 By Reference 2, NRC forwarded a request for additional information (RAI) labeled Set 11, which included Requests for Additional Information (RAI) B.1.40-4a and B.1.25.1a with a required response due date no later than October 21, 2013. Enclosure 1 provides the TVA responses for RAIs B.1.40-4a and B.1.25.1 a.By Reference 3, the NRC forwarded an RAI labeled Set 13 that included RAI B.1.41-4a with a required response due date no later than October 16, 2013. However in a telecom, Mr.Richard Plasse, NRC Project Manager for the SQN License Renewal, gave verbal extension until November 15, 2013. Enclosure 1 provides the TVA response for RAI B.1.41-4a.

By Reference 4, the NRC forwarded an RAI labeled Set 14 that included RAI 3.5.1-57 and 3.5.1-87 with a required response due date no later than October 28, 2013. Enclosure I provides the TVA responses for RAI 3.5.1-57 and 3.5.1-87.Enclosure 2 is an updated list of the regulatory commitments for license renewal.Consistent with the standards set forth in 10 CFR 50.92(c), TVA has determined that the additional information, as provided in this letter, does not affect the no significant hazards considerations associated with the proposed application previously provided in Reference 1.Please address any questions regarding this submittal to Henry Lee at (423) 843-4104.I declare under penalty of perjury that the foregoing is true and correct. Executed on this 2 1 st day of October 2013.Respec y, J W./ SheaNuclear Licensing

Enclosures:

1. TVA Responses to NRC Request for Additional Information:

Sets 11 (B. 1.40-4a, B.1.25.1a), 13 (B.1.41-4a), and 14 (3.5.1-57, -87)2. Regulatory Commitment List, Revision 10 cc (Enclosures):

NRC Regional Administrator-Region II NRC Senior Resident Inspector

-Sequoyah Nuclear Plant ENCLOSURE1 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal TVA Responses to NRC Request for Additional Information:

11 (B.1.40-4a, B.1.25.1a), 13 (B.1.41-4a), 14 (3.5.1-57, 3.5.1-87)Set 11: RAI B.1.40-4a

Background:

Based on the response dated July 1, 2013, the technical evaluation of the groundwater in-leakage concluded that 1) the condition would not affect the intended function of the structure elements, and 2) the technical evaluation of the crack concluded that the structural capability of the turbine building north wall was not unacceptably impaired and that the wall would continue to perform its design function.The response stated that minor groundwater in-leakage has been observed and documented in several Category I structures since 1996. Inspections of the turbine building (as listed in the LRA), a non-Category 1 structure, noted in-leakage in the basement floor slab at elevation 662.5' and significant in-leakage for the north and south perimeter walls above floor elevation 662.5' and floor elevation 685'. The response also stated that the turbine building is the most significant of the structures within the scope of the Structures Monitoring Program due to the constant moisture in-leakage over large areas of the structure.

Although leak repairs have been initiated, the staff observed conditions during the audit walkdowns that may need further evaluation to demonstrate that the effects of aging will be adequately managed during the period of extended operation.

The staff is concerned that the continued constant exposure to groundwater in-leakage may affect the integrity of the reinforced concrete during the period of extended operation.

Issue: 1. The technical basis, supporting the evaluation that concluded the groundwater in-leakage into the turbine building would not affect the intended function of the structure, was not provided.2. The technical basis, supporting the evaluation that concluded the structural capacity of the turbine building north wall was not unacceptably impaired, was not provided.3. Considering the history of constant groundwater in-leakage, in the absence of a plan to further evaluate the condition of the below-grade concrete, the staff is concerned that the periodic visual inspections, performed under the proposed Structures Monitoring Program, may not provide sufficient information, regarding the integrity of the concrete and reinforcing steel, for monitoring and trending of the structure during the period of extended operation.

E-1 -1 of 25 Request: 1. Provide additional information regarding the technical evaluation that was performed, which concluded the groundwater in-leakage would not affect the intended function of the turbine building.

Include the following details in the response: a. Completion date for the technical evaluation and if/when it was re-evaluated

b. Description of activities performed (e.g. visual inspection, testing, structural analyses, chemical analyses)c. Description of the qualitative or quantitative acceptance criteria used d. Discussion of results obtained supporting the conclusion reached e. Corrective actions taken, if any f. Structural drawing(s) detailing the below grade-concrete in the area considered to have the most significant in-leakage, indicating floor elevations, water table elevation, concrete wall and floor slab thickness, rebar details. Indicate on the drawing the approximate locations of groundwater in-leakage.

2. Provide additional information regarding the technical evaluation of the large diagonal crack on the north wall of the turbine building, which concluded that the structural capacity of the turbine building north wall was not unacceptably impaired.

Include the following details in the response: a. Width of the crack at its widest point b. History of crack growth c. Discussion about the source of rust colored stains on the wall and flowing out of the crack d. Description of activities performed (e.g. visual inspection, testing, structural analyses, chemical analyses)e. Discussion of results obtained supporting the conclusion reached f. Corrective actions taken, if any g. Sketch detailing the location and dimensions of the crack, and areas of spalling.3. In the absence of a plan to mitigate the groundwater in-leakage, explain how the proposed Structures Monitoring Program will adequately manage the potential increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide; cracking due to expansion from reaction with aggregates; and cracking, loss of bond, and loss of material due to corrosion of embedded steel. Include any plans for testing and/or inspections that may demonstrate the effects of aging will be adequately managed during the period of extended operation.

E-1 -2 of25 TVA Resoonse to RAI B.1.40-4a 1. The intended function of the turbine building (TB) is to provide physical support, shelter, and protection for safety-related (SR) and non safety-related (NSR) systems, structures, and components whose failure could prevent satisfactory accomplishment of function(s) identified for 10 CFR 54.4(a)(1) and to provide physical support, shelter, and protection for systems, structures, and components relied upon in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulation for station blackout (10 CFR 50.63). There are SR components in the TB/control building mezzanine area that are supported by the main structural steel in the TB foundation and the auxiliary building wall/foundation.

Additional SR components in the TB are near the main feed pumps on Elevation 706.0' supported by the TB main structural steel and TB foundation.

The condenser pit walls are inside the TB perimeter between Elevations 662.75' and 685.0' as shown in Figure 1. The crack in the TB north wall is in the north wall of the condenser pit at approximately Elevation 668.0' west of column line E and north of column line T3 (see Figure 1 and Figure 4). The area in question is remote from any SR component in the TB. There is no structural connection between the area in question and the structural support for SR components.

The additional information regarding the technical evaluation that concluded the groundwater inleakage would not affect the intended function of the TB is included in the responses to the following requested details.a. The TB water inleakage, which is through the condenser pit walls and slabs, was documented in the Sequoyah Nuclear Plant (SQN) corrective action program (CAP) in early 1993. The engineering evaluation of the documented condition concluded that the structural integrity of the affected structural elements of the TB would not be adversely affected.

The intended function of the TB has not been affected.

The water inleakage was subsequently evaluated during the SQN maintenance rule (Structures Monitoring Program (SMP)) baseline inspections in 1996 with reevaluation in 2002, 2007, and 2010. The evaluation applied to the water inleakage through the below-grade walls of the TB which include the condenser pit walls between Elevations 662.75' and 681.0' (See Figure 1).E-1 -3 of 25 0 TURBINE BLDG PLAN EL 662.75' & 685.0'Figure 1 E 4of25

b. Visual inspections were performed followed by engineering evaluation of the inspection findings, as documented in the SCG1S596, Maintenance Rule Structures Inspection and in the SQN correction action program (CAP)documents.

Please review the responses to Request 1.c and 1.d below. They provide the bases of the engineering evaluation.

c. Based on the configuration of the wall and the location of cracks, a qualitative assessment determined that the loadings on the wall were not sufficient to require a detailed analysis to determine the functional impact of the observed cracks. This assessment was based on the fact that the wall is poured directly against the vertical portion of the excavated bedrock and is integral with the fill concrete poured directly on the bedrock that supports the structural slab at Elevation 683.0' as shown in Figure 2. The wall is tied into the 24-inch thick structural slabs at both the top and bottom and all horizontal construction joints require PVC water seals. The wall is not a load bearing wall because it does not support any walls above. Furthermore, the wall is lightly loaded structurally from the portion of the structural slab and fill slab directly above the wall and the attached mechanical and electrical systems (e.g., a few cable tray supports and conduits).

Reinforcement is provided for the wall in the near face only to control cracks from temperature and shrinkage stresses.

A 24-inch fill slab was poured over the upper and lower structural slab to allow for placement of embedded piping. For all of the above reasons, if minor deterioration of the rebar was present at locations of water inleakage, it is not considered significant enough to affect the structural integrity of the wall. See response to Request 2.C for additional information.

The primary water inleakage occurs at the upper slab juncture (See Figure 2).This location is not in the structural connection joint between the wall and the structural slab, but is instead at the non-structural interface of the fill slab on top of the structural slab. As such, no rebar is affected by this water inleakage at the wall to structural slab interface.

E 5of25 0 0 EL. 6.8,5.0 FILL SLAB EL. 63.0 -7/ (N235-2) Location of pdmary EL. '.L,.-7.'- inleakaae S, STRUCTURAL SLAB (OUTL[NE 41N225-2P (REIr"4F.

41N226-3)FILL COJNCRETE~-

04]N206-ID W'- ALL X (OUTLCNE 41]NHE'5-Z)(REINF. 4IN226-3)BEDROCK-F[LL SLAB 4123-2 EL. 66Z.75\7- / EL. 6 .5/ E L .65 5.5 STRUCTURAL SLAB (OUTLINE 41N225-2)(REINF. 4tN22c-i)

BE O C 0 BEDROCK CROSS SECTION (LOOKING EASTýFigure 2 d. See response to Request 1 .c.e. SQN determined that the crack represented a non-structural, water inleakage issue only. Therefore, corrective actions taken to address the water inleakage were to seal the crack and redirect any future potential water inleakage away from plant equipment that might be susceptible to water damage.f. The primary water inleakage occurs at the construction joint at Elevation 683.0'.Other locations are at construction joints at Elevations 681.0' and 671.0' and at localized shrinkage cracks. The groundwater level at SQN in the vicinity of the TB varies between approximately Elevation 680.0' and 690.0' as measured in monitored observation wells.Based on the following points, the north, south and east walls of the condenser pit (See Figure 1) are considered non-structural (non-load bearing).* Figures 1, 2 and 3 in this response show details and sections of the concrete and applicable notes regarding the slabs and walls. The drawings allow the E-1 -6 of 25 use of concrete with a compressive strength of 2000 psi when the wall is poured integral with the fill concrete poured directly on the bedrock behind the wall and specifies the use of concrete with a compressive strength of 3000 psi when the wall is less than 3-feet thick. The wall has reinforcing bars for limiting cracking due to temperature and shrinkage.

The near face of the wall has No. 6 reinforcing bars horizontally at 12 inches on center and No. 6 reinforcing bars vertically at 9 inches on center. The far face of the wall has no reinforcing as shown in Figure 3.4 8A 60 ConosS71 I;: 64.,.2:sa/4 V1671,0-K 12 inches oc 6,4 139 inches oc A71 650. 92. 17 6_[ C 60. S" dsA46 ee 84-8 41 N226-4 Figure 3 Drawing 41 N206-1 indicates that the fill concrete and/or bedrock behind the wall extend up to Elevation 681.0' which is the same elevation as the top of the wall.The structural slab at Elevation 683.0' is poured directly onto and supported by the fill concrete as shown in Figure 2. The fill slab at Elevation 685.0' is poured directly onto and supported entirely by the structural slab located at Elevation 683.0'.E-1 -7 of 25 Therefore, the wall is not considered to carry any substantial loads, except for that the portion of the structural slab and fill slab directly above the wall and the attached mechanical and electrical systems (e.g., a few cable tray supports and conduits).

2. The additional information regarding the technical evaluation of the large diagonal crack on the north wall of the TB, which concluded that the structural capacity of the TB north wall was not unacceptably impaired, is included in the responses to the following requested details. The subject crack is in the north wall of the condenser pit of the TB.a. As shown in Figure 4, the width of the crack at its widest point is less than 1/1 6-inch except at one isolated location where the crack opens up to a 11/2-inch wide by 6-inch long spall. Based on the appearance of the spall and the location of drain tubes and abandoned injection ports, the spall appears to be the result of previous attempts to inject epoxy material to stop the water inleakage.

7-441 WALL CRACK OPEN GAP APPROX 6" L x lr2" W x I' D (APPEARS TO BE RESULT OF AN ATTEMPTED LEAK REPAIR)TB WALL CRACK (GAP< 1116")WDRAINI-TUBES !II ',,__ _ _ _,_ T/FLOOR f TRENCH DRAIN EL. 662'-9" __,_ ,, I ENLARGED TB WALL CRACK DETAIL VIEW LOOKING NORTH Figure 4 E-1 -8 of 25

b. Based on available SQN documentation, the crack has not significantly changed, other than the spalling noted in Response 2.a, since it was initially documented in the SQN SMP baseline inspections in 1996. Because externally applied loads are low on this wall, the crack was most likely developed as a result of concrete shrinkage soon after initial construction.

The spalling most likely occurred during the attempts to seal the inleakage cracks.c. While some rebar could possibly be rusting from the water inleakage, the rust colored stains are likely due to the leaching of epoxy crack injection nozzle materials used to seal the cracks and joints. The reinforcing steel provided in the wall is placed in the near face only with the primary purpose of controlling cracking of the concrete due to temperature and shrinkage stresses.

The concrete condenser pit walls are basically a concrete liner wall poured against bedrock. These walls offer no structural support to the TB. If minor deterioration of the rebar is present at locations of water inleakage, it is not considered significant enough to affect the structural integrity of the wall.d. Visual inspections were performed followed by engineering evaluation of the inspection findings, as documented in the SCG1 S596, Maintenance Rule Structures Inspection and in the SQN CAP documents.

Please review the response to Request 2.e below. It provides the bases of the engineering evaluation.

e. The water inleakage in the TB was documented in the SQN CAP in early 1993.The engineering evaluation of the condition concluded that the structural integrity of the affected structural elements would not be adversely affected.

The water inleakage was subsequently evaluated during the SQN SMP baseline inspections in 1996 with reevaluation in 2002, 2007, and 2010. See response to Request 1.C and 2.C for additional information.

CAP documents have been initiated over the years concerning water inleakage in the TB condenser pit. As a result, engineering evaluations were performed on the subject crack and the overall condition of the TB condenser pit walls. In 2005, a functional evaluation assessed the possibility of rebar corrosion.

The functional evaluation noted that "The condenser pit concrete wall is poured integral with fill concrete which is placed on bedrock. The reinforcing provided is in the near face only and is primarily in place to control cracks from temperature and shrinkage.

Therefore, if there is any minor deterioration of the rebar it would not be considered significant and will not affect the structural integrity of the wall." This evaluation also referenced a previous engineering evaluation for inleakage through the walls of the condenser pit, and stated that "No significant structural deterioration has been observed since 1993." f. SQN determined that the crack represented a non-structural, water inleakage issue. Corrective actions were made to seal the crack with epoxy.g. See Figure 4 above.E 9of25

3. As noted previously, the north wall of the TB condenser pit is a non-structural (non-load bearing) feature of the TB. Although the deficiencies noted in the wall do not impair the wall's ability to perform its license renewal intended function, the wall will continue to be routinely monitored under the SMP.To assess that the concrete walls and floor slabs are not degrading from the inleakage of water, SQN will perform testing of the water inleakage for minerals and iron content to determine if the concrete or reinforcing steel are being affected.

Additionally, SQN will obtain and test core samples of the TB condenser pit north wall to determine its in-situ strength capacity and compare to the design strength requirements.

The results of tests and SMP inspections will be used to determine the need for future corrective measures including, but not limited to, more frequent inspections, sampling and analysis of the water for minerals and iron, and evaluation of the affected area using evaluation criteria and acceptance criteria of ACI 349.3R.Commitment

1. 31.M has been revised with additions underlined.

1. SQN will map and trend the crack in the condenser pit north wall.2. SQN will test water in leakage samples from the turbine building condenser pit walls and floor slab for minerals and iron content to assess the effect of the water inleakage on the concrete and the reinforcing steel.3. SQN will test concrete core samples removed from the turbine building condenser pit north wall with a minimum of one core sample in the area of the crack. The core samples will be tested for compressive strength and modulus of elasticity and subjected to petrographic examination.

4. The results of tests and SMP inspections will be used to determine further corrective actions, if necessary.

5. Commitment

1. 31.M will be implemented before the PEO for SQN Unit 1 and Unit 2.E 10of25 Set 11: RAI B.1.25.la

Background:

In a letter dated May 31, 2013, the staff issued RAI B. 1.25-1 requesting additional information on the corrective actions taken to prevent in-scope inaccessible power cable exposure to significant moisture including manhole, sump pump, and cable support structure inspection and, maintenance.

The staff also requested the applicant to include a summary discussion of the complete schedule for inaccessible cable corrective actions. The staff further requested the applicant describe inaccessible power cable testing (e.g., test frequency, and applicable tests)performed that demonstrates that in-scope inaccessible power cables will continue to perform their intended function consistent with the CLB.In response to the staffs RAI, in a letter dated July 1, 2013, the applicant stated that as documented in the SQN corrective action program, there have been multiple instances of water in manholes at SQN. In 2012, a report was initiated in the correction action program to document the trend of high levels of water in manholes that the work control process is not resolving in a timely manner. In response to the identified issues with untimely removal of water from manholes, the preventive maintenance (PM) task instructions were revised to require water removal, if found, from the manholes before the PM task could be closed.SQN experience since revising the PM instruction has been that the water, if any, has been removed within a week of initiating the PM activity.

The applicant also stated that as a result of operating experience (OE) with water in the manholes, a team of TVA personnel was established in early 2013 to resolve the dewatering issues with safety-related manholes.

The team is scheduling activities which will repair or replace sump pumps and discharge piping as necessary to improve dewatering performance.

In addition, TVA stated it is issuing a modification to enhance the ability to remove water from manholes without having to remove the heavy missile shield manhole covers. The applicant further stated that a cable support structure inspection is performed at least once every five years as part of the SQN structures monitoring program (SMP). Finally, the applicant stated that the inspections described in NUREG-1801, Section Xl. E3 will be implemented as part of the new SQN Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program described in LRA Section B. 1.25 prior to entering the PEO. During the PEO, the periodic inspections of manholes including cable support structures will be completed at least once every year (annually).

Issue: The applicant's program for inaccessible cables may allow unacceptable water levels to remain in the manhole for an extended period before corrective action to remove the water is completed.

The staff noted that because of the difficulty in removal of the manhole covers, there has been limited manhole inspection and maintenance of the sump pumps to ensure sump pumps were operable and capable of preventing cable submergence.

In addition, based on OE with water in manholes, the staff is concerned that the current five year inspection frequency for manhole structures including cable supports may not be adequate.The applicant's RAI response did not describe the corrective actions to be taken for manhole inspection and maintenance of sump pumps to prevent exposure of cables to significant E-1 -11 of 25 moisture.

The staff is concerned that the applicant's manhole inspections and corrective actions may not be adequate to prevent in-scope inaccessible power cables from being subjected to significant moisture.

The staff could not determine based on current OE if the applicant's non-EQ Inaccessible Power Cable aging management program will ensure that in-scope inaccessible power cables will continue to perform their intended function during the period of PEO.Request: 1. Describe corrective actions (e.g., inspection, preventive maintenance) have been taken to ensure the operation of sump pumps to prevent exposure of in-scope inaccessible power cables to significant moisture.

Include a discussion of the completion schedule to implement the corrective actions.2. Provide a technical justification for the current 5 year inspection frequency for in-scope manhole cable support structures given plant specific OE with water in the manholes and GALL Report AMP XI.E3 guidance.

Include a discussion on how the interval for water collection and inspection of manhole structures including cable supports is established and adjusted for plant specific and industry operating experience.

3. For in-scope inaccessible power cables subjected to submergence (significant moisture), how is the condition and operability of these cables determined?

Describe the tests and inspections performed as part of the corrective action to ensure that these cables remain capable of performing their intended function consistent with the current licensing basis.TVA Response to RAI B.1.25-1a 1. Corrective actions (e.g., inspection, preventive maintenance) that have been taken and are planned to minimize exposure of in-scope inaccessible power cables to significant moisture include improvements in water management processes, resolution of sump pump deficiencies, and re-grading the ground surface in the vicinity of one manhole. Following are details regarding each of these corrective actions.SQN procedures for managing water levels in manholes with SR cables have been revised to require that any water found above two inches is evacuated prior to closing the manhole water monitoring preventive maintenance (PM). As-found water levels are recorded and discrepancies are documented in TVA's CAP. If water levels indicate inadequate dewatering system performance, corrective actions are planned and prioritized in accordance with plant maintenance procedures to restore the proper functioning of the dewatering system.Sump pump deficiencies that have historically resulted in submergence of SR power cables have been addressed through repairs to sump pumps and associated piping. The success of these corrective actions is demonstrated through the results of recent water level inspections.

During the period of March through July of 2013, the inspections identified no SR cable submergence.

In the most recent water level inspections, water was detected in only seven of the 38 inspected SR manholes/handholes.

In each case where water was detected, the water elevation was 12 inches or more below the SR cables in the manholes/handholes.

These results demonstrate reasonable assurance that SQN water E 12of25 management features and processes can minimize the exposure of inaccessible power cables to significant moisture.

To provide additional assurance, further actions to correct sump pump and discharge piping deficiencies associated with accumulation of water in these seven manholes/handholes are scheduled for correction and/or mitigation by September 2015. (See Commitment

1. 18.A)Historically, a significant amount of surface water has run into manhole 31 during heavy rains. This condition will be corrected by re-grading the ground surface in the vicinity of the manhole to redirect the runoff away from the manhole. The re-grading is scheduled for completion by September 2014. (See Commitment

1. 18.A)Following water management process improvements and resolution of several long standing sump pump deficiencies, operating experience (OE) has demonstrated that SQN manhole and handhole dewatering processes and features provide reasonable assurance of minimizing the exposure of SR cables to significant moisture.

Prior to the period of extended operation (PEO), the program described in LRA Section B.1.25 will be implemented which will include these same water management processes for the NSR cables manholes that are in the scope of license renewal and subject to aging management review. (See Commitment

1. 18.A)2. The response to RAI B.1.25-1 (TVA letter to NRC, dated July 1, 2013, page E1-52, ADAMS No. ML1 3190A276) stated that the cable support structure inspection is performed at least once every five years as part of the SQN SMP. This response was intended to reflect the SMP following its enhancement prior to the PEO. An enhancement is specified in Section B.1.40 of the SQN LRA to revise the SMP procedures to include inspections of manholes at least once every five years. Under the current SMP, manhole inspections have not been routinely performed due to access limitations.

Historically, few structural inspections of SR manholes have been performed due to accessibility limitations.

In these structural inspections, carbon steel cable tray supports that have been submerged, show indication of some damaged coating and minor surface corrosion.

Typical carbon steel tray supports are robust cantilevers fabricated from 1/4-inch wall structural tube steel sections.

Engineering review indicates no structural concern with the minor surface corrosion of the carbon steel supports identified in the opportunistic inspections.

The results of these inspections indicate that the once per five year frequency as stated in the enhanced SMP is acceptable.

Prior to the PEO, the Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program described in LRA Section B.1.25 will specify visual inspection of the cable supports in these manholes at least once per year (annually), which is consistent with the program described in NUREG-1801,Section XI.E3. The frequencies for water accumulation inspections and inspection of manhole structures including cable supports are evaluated and adjusted, as necessary, based on plant-specific and industry OE. Specifically, the SQN inspections for water accumulation are performed on one-month intervals based on historical inspection results. While manhole structures have not been periodically inspected, SQN OE indicates that the frequency of once per year under the new Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program will be acceptable during the PEO. (See Commitment

1. 1 8.A)E 13of25

3. The program description in NUREG-1801 Section XI.E3 indicates that inspecting for water in manholes and draining water, as needed, are not sufficient to ensure that water is not trapped elsewhere in the raceways.

Therefore, the Section XI.E3 program recommends periodic testing to indicate the condition of the conductor insulation.

Consistent with this recommendation, SQN currently performs diagnostic testing of inaccessible 6.9 KV SR cables at least once every five years or once every three refueling outages. In accordance with license renewal commitments, TVA will implement the program described in LRA Section B.1.25 prior to the PEO. Program implementation entails providing diagnostic testing at least once every six years for all inaccessible power cables that are in the scope of license renewal and subject to aging management review.The diagnostic testing of medium-voltage cables includes measurements of dissipation factor (also known as tan delta) taken when energized with a very low frequency (VLF)alternating current, sinusoidal waveform.

VLF tan delta testing has been shown to be effective in detecting cable insulation degradation resulting from long-term water submergence.

Tan delta changes are trended to detect cable insulation degradation.

If moderate insulation degradation is detected, the cable is tested each refueling outage. If significant insulation degradation is detected, the cable is replaced.

VLF tan delta testing is followed by withstand testing, also at VLF. The two methods ensure that cable insulation degradation is revealed, whether global or local prior to cable failure. Consistent with the recommendations of NUREG-1801 Section XI.E3, these methods demonstrate acceptable condition of tested inaccessible power cables subjected to submergence (significant moisture).

The most recent tan delta cable testing in the 2011 to 2012 timeframe indicated no degradation of inaccessible 6.9 KV SR cables.TVA performs the established diagnostic testing activities on inaccessible SR medium-voltage cables at SQN. Prior to the PEO, the license renewal commitment for the Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program will establish diagnostic testing activities on all inaccessible power cables in.the 400 V to 35kV range that are in the scope of license renewal and subject to aging management review. (See Commitment

1. 18.A)As an additional corrective action, TVA plans to add to the monthly manhole inspection procedures the maximum allowable water level to preclude SR cable submergence in the manhole. If the inspection identifies submergence of inaccessible power cable for more than a few days, the condition will be documented and evaluated in the SQN CAP. The evaluation will consider results of the most recent diagnostic testing, insulation type, submergence level, voltage level, energization cycle (usage), and various other inputs to determine whether the cables remain capable of performing their intended current licensing basis function. (See Commitment

1. 18.A)E-1 -14of25 Commitment

1. 18.A will be revised with additions underlined.

1. Repair the manhole sump pump and discharqe piping deficiencies associated with the accumulation of water in seven manholes/handholes that are scheduled for correction and/or mitigation by September 2015. (HH3, HH2B, HH52B, HH55A2, MH7B, MH10A and MH32B as identified on October 1, 2013)2. Grade the ground surface around Manhole 31 to direct runoff away from the manhole.The re-grading is scheduled for completion by September 2014.3. Prior to the PEO, the license renewal commitment for the Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program will establish diagnostic testing activities on all inaccessible power cables in the 400 V to 35kV range that are in the scope of license renewal and subject to aging management review.4. Revise the manhole inspection procedures to specify the maximum allowable water level to preclude cable submergence in the manhole. If the inspection identifies submergence of inaccessible power cable for more than a few days, the condition will be documented and evaluated in the SQN corrective action program. The evaluation will consider results of the most recent diagnostic testing, insulation type, submergence level, voltage level, energization cycle (usage), and various other inputs to determine whether the cables remain capable of performing their intended current licensing basis function.E 15of25 Set 13: RAI B.1.41-4a

Background:

In its August 9, 2013, letter, the applicant responded to RAI B. 1.41-4 which addressed plant specific flaw tolerance evaluation of cast austenitic stainless steel (CASS) components with a ferrite content greater than 25 percent. In its response, the applicant stated that a probabilistic fracture mechanics method will be used in flaw tolerance evaluation for CASS piping components with a ferrite content greater than 25 percent. The applicant also stated that its flaw tolerance evaluation will use the percent probabilities of various levels of material fracture toughness.

The applicant further stated that the flaw tolerance evaluation will calculate the maximum allowable flaw depths for a specific (very low) probability of failure based on crack tip stability, or instability, of the assumed flaws in the elastic-plastic fracture mechanics (EPFM)analysis.Issue: GALL Report AMP Xl. M12 recommends plant-specific flaw tolerance evaluation for CASS components with a ferrite content greater than 25 percent as one of the options for aging management.

However, GALL Report AMP X1. M12 recommends deterministic principles (as described in ASME Code Section Xl, IWB-3640) for flaw tolerance evaluation of CASS components with a ferrite content up to 25 percent. In addition, GALL Report AMP XI.M12 does not include technical evaluation of probabilistic fracture mechanics methods for aging management.

By contrast, the applicant's response to RAI B. 1.41-4a indicates that its program may use probabilistic flaw tolerance evaluation for aging management of CASS components with a ferrite content greater than 25 percent. Therefore, the applicant should submit its probabilistic flaw tolerance evaluation for staff's review to demonstrate the adequacy of the evaluation.

The staff also noted that the revised updated final safety analysis report (UFSAR) supplement for the applicant's program (as described in the August 9, 2013, response) addresses flaw tolerance evaluation for detected flaws, which is not relevant to the flaw tolerance evaluation for postulated flaws. The staff further needs to clarify how the applicant will confirm that CASS components, for which flaw tolerance evaluation is performed, do not have a flaw greater than the maximum allowable flaw size of applicant's evaluation.

Request: Submit applicant's probabilistic flaw tolerance evaluation to demonstrate that the evaluation is adequate for aging management.

In addition, identify any NRC-approved methods and associated safety evaluations that are used for the applicant's flaw tolerance evaluation.

Clarify why the revised UFSAR supplement refers to detected flaws rather than postulated flaws in relation to the flaw tolerance evaluation.

Describe how the applicant will confirm that CASS components, for which flaw tolerance evaluation is performed, do not have a flaw greater than the maximum allowable flaw size of applicant's evaluation (Please note that this request is for all CASS components in the scope of the applicant's program regardless of whether the ferrite content is greater than 25 percent).E 16 of 25 TVA Response to RAI B.1.41-4a 1. The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program is a new program that manages the aging effects of cracking and reduction in fracture toughness in CASS components.

The program consists of a determination of the susceptibility of CASS piping, piping components, and piping elements, including the pressurizer spray head and regenerative heat exchanger shell and channel head, to thermal aging embrittlement.

Susceptibility is determined based on casting method, molybdenum content, and percent delta ferrite. For potentially susceptible components, aging management is accomplished through qualified visual inspections, such as enhanced visual examination, qualified ultrasonic testing methodology, or component-specific flaw tolerance evaluation in accordance with ASME Section Xl Code, 2001 Edition 2003 addendum.Specifically, for the CASS materials with delta ferrite < 20%, estimated using the Hull equivalent factors described in NUREG/CR-4513, Revision 1, the method given in ASME Code, Section Xl, IWB-3640 will be used. This Code method would permit flaws detected inservice to be evaluated as flux welds using the flaw evaluation procedures in Article C-6000. For CASS materials with estimated delta ferrite > 20% that have been determined susceptible to thermal aging, a flaw tolerance analysis per GALL XI.M12 may be necessary.

Such flaw tolerance analyses will apply ASME Code approaches for flaw tolerance of CASS that have been accepted and approved by the time that flaw tolerance must be demonstrated.

The GALL XI.M12 guidance, in this case for CASS components with delta ferrite exceeding 20%, recommends deterministic flaw tolerance evaluation methods. Therefore, the first option for the susceptible CASS components will be the application of deterministic flaw tolerance evaluation methods.However, deterministic methods combined with ASME Code Section Xl safety factors may lead to maximum allowable flaw sizes that are considered undetectable using ultrasonic examination (UT) techniques.

While no alternate method has been approved by regulatory authorities, considerable industry activity is underway that may produce a reasonable alternative.

This ongoing activity has produced a draft ASME Section Xl Code Case intended to demonstrate flaw tolerance of CASS components in the fully aged condition with estimated delta ferrite > 20%. While the Code Case is not yet approved, the technical approach has been used by a number of utilities for aging management of CASS, and a technical basis that explains the approach for calculating maximum allowable flaw sizes will soon be published by EPRI and made available to the ASME Code committees for their deliberation.

The industry continues to work with the ASME Code bodies and maintain technical communications with regulatory staff in order to provide the necessary information and application data to justify the alternate approach.Such an alternate flaw tolerance evaluation approach will be especially important for CASS components with high delta ferrite, where the existing ASME Code Section Xl, IWB-3640, requirements and the GALL XI.M12 guidance do not apply. For those components with delta ferrite content > 25%, additional analyses will be performed using plant-specific materials data and best available fracture toughness curves.E 17of25

3. Volumetric inspections will be used to confirm the absence of flaws greater than the maximum allowable flaw depths from the flaw tolerance analyses.

Industry efforts are continuing for demonstration of ultrasonic inspection capabilities on CASS components.

In the absence of successful completion of an industry performance demonstration program on applicable CASS components, the best available inspection methods will be employed for these inspections.

Possible methods for performing ultrasonic examination of CASS piping are described in ASME Code Case N-824.The changes to LRA Sections A.1.41 and B.1.41 follow with additions underlined and deletions lined thorough."A.1.41 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program manages the aging effects of cracking and reduction in fracture toughness in cast austenitic stainless steel (CASS) components.

The program consists of a determination of the susceptibility of CASS piping, piping components, and piping elements and the pressurizer spray head and regenerative heat exchanger shell and channel head to thermal aging embrittlement based on Hull's equivalent factor, as described in NUREG/CR-4513, Revision 1. For potentially susceptible components, aging management is accomplished through qualified visual inspections, such as enhanced visual examination, qualified ultrasonic testing methodology, or component-specific flaw tolerance evaluation in accordance with ASME Section Xl code, 2001 Edition 2003 addendum.

Applicable industry standards and guidance documents are used to delineate the program. A flaw tolerance e'-aluatioR for flaws-, detected in CASS components-wi4th >25% ferrite will bhe perfo~rmed us6ing a probabilis6tic fracture mechanic (PF=M) appracah aRd plant specific data. For CASS materials with estimated delta ferrite> 20% that have been determined susceptible to thermal aging, a flaw tolerance analyses may be performed using ASME Code approaches for flaw tolerance of CASS that have been accepted and approved by the time that flaw tolerance must be demonstrated.

For those CASS components with delta ferrite content > 25%, additional analysis will be performed using plant-specific materials data and best available fracture toughness curves.This program will be implemented prior to the period of extended operation.

B.1.41 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)Program Description The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program is a new program that manages the aging effects of cracking and reduction in fracture toughness in CASS components.

The program consists of a determination of the susceptibility of CASS piping, piping components, and piping elements and the pressurizer spray head and regenerative heat exchanger shell and channel head to thermal aging embrittlement based on Hull's equivalent factor, as described in NUREG/CR-4513, Revision 1. For potentially susceptible components, aging management is accomplished through qualified visual inspections, such as enhanced visual examination, qualified ultrasonic testing methodology, or component-specific flaw E 18of25 tolerance evaluation in accordance with ASME Section XI code, 2001 Edition 2003 addendum.

Applicable industry standards and guidance documents are used to delineate the program. A flaw evaluation for flaws detected in CASS componentS With >225% ferFrite will be pe~fermed uring a probabilistic-frac-ture mechanics (PF=M) approach and plant specific dt. For CASS materials with estimated delta ferrite> 20% that have been determined susceptible to thermal aqin.q, a flaw tolerance analyses may be performed using ASME Code approaches for flaw tolerance of CASS that have been accepted and approved by the time that flaw tolerance must be demonstrated.

For those CASS components with delta ferrite content > 25%, additional analysis will be performed using plant-specific materials data and best available fracture toughness curves.This program will be implemented prior to the period of extended operation." E 19of25 Set 14: RAI 3.5.1-57

Background:

LRA Table 3.5.1, item 3.5.1-57 addresses constant and variable load spring hangers; guides;stops exposed to air-indoor, uncontrolled or air-outdoor environments, which will be managed for aging effects of loss of mechanical function due to corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads. The LRA states that this item is not applicable because loss of mechanical function due to distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads is not an aging effect requiring management because such failures typically result from inadequate designs rather than aging effects.The staff notes that LRA Section B. 1.17, "lnservice Inspection

-IWF (ISI-IWF)

Program" states"[v]isual examinations are conducted to determine the general mechanical and structural condition or degradation of component supports such as verification of clearances, settings, physical displacements, loose or missing parts, debris, corrosion, wear, erosion, or the loss of integrity at welded or bolted connections." Issue: The GALL Report, identifies loss of mechanical function in Class 1 piping and components (such as constant and variable load spring hangers, guides, stops, sliding surfaces, and vibration isolators) fabricated from steel or other materials, as an aging effect that can occur through the combined influence of a number of aging mechanisms.

Such aging mechanisms are not limited to loss of material due to corrosion, but also include distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads, or elastomer hardening.

The loss of mechanical function due to distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads is not solely the result of inadequate design or events. As stated above, the GALL report identifies loss of mechanical function for Class I piping and components due to distortion, dirt, overload, fatigue due to vibratory and cyclic thermal loads as an aging effect to be managed.Request: Provide the staff with sufficient technical basis for concluding loss of mechanical function due to distortion, dirt, overloads, and fatigue due to vibratory and cyclic thermal loads is not an aging effect requiring management, or provide an AMP to manage this aging effect.TVA Response to RAI 3.5.1-57 TVA has reassessed and concluded that loss of mechanical function due to distortion, dirt, overloads, and fatigue due to vibratory and cyclic thermal loads is an aging effect requiring management For constant and variable load spring hangers, guides and stops, the ISI-IWF Program includes inspections capable of detecting loss of mechanical function due to distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads.The changes to LRA Table 3.5.1 Item 3.5.1-57 and Table 3.5.2-4 follow with additions underlined and deletions lined through.E 20 of 25 Table 3.5.1: Structures and Component Supports Aging Item Aging Effect/ Management Further Evaluation Number Component Mechanism Programs Recommended Discussion Safety-Related and Other Structures, and Component Supports 3.5.1-57 Constant and Loss of mechanical ISI (IWF) No Consistent with NUREG-1801.

The variable load spring function due to SI-I WF Program includes inspections hangers; guides; corrosion, distortion, capable of detecting loss of stops dirt, overload, mechanical function due to distortion, atigue due to dirt, overload, and fatigue due to vibratory and cyclic vibratory and cyclic thermal loads.--4 thermal loads " .... "" "÷. ..R9 naagmet Sucnh fail0urec6 typically resuft from inadequate deino co-ul of.hici....l f c.. ti o , is addressed ,nor Item 3.5.1! 1 related to, GOMPGnent 6upport members.E-1 -21 of 25 Table 3.5.2-4 Bulk Commodities Summary of Aging Management Evaluation Table 3.5.2-4: Bulk Commodities Structure and/or Aging Effect Aging Component or Intended Requiring Management NUREG-1801 Table I Commodity Function Material Environment Management Program Item .Item Notes Supports for ASME SRE, SSR Carbon steel Air- indoor Loss of ISI-IWF III.B1.1.T-28 3.5.1-57 Class 1, 2 and 3 uncontrolled or mechanical III.B1.2.T-28 jiping and Air-outdoor function components (Constant and variable load spring han ers: guides: stops)Supports for ASME SRE, SSR Galvanized Air- indoor Loss of ISI-IWF 111.B1.1.T-28 3.5.1-57 A Class 1, 2 and 3 steel uncontrolled or mechanical III.B1.2.T-28 piping and Air-outdoor function components (Constant and variable load prinq hangers: uides; stops)E 22 of 25 Set 14: RAI 3.5.1-87

Background:

LRA Table 3.5.1, item 3.5.1-87, states "[v]ibration, flexing of the joint, cyclic shear loads, thermal cycles and other causes can cause partial self-loosening of a fastener.

These causes of loosening are minor contributors in structural steel and steel component threaded connections and are eliminated by initial preload bolt torquing.

The LRA further states: "SQN uses site procedures and manufacturer recommendations to provide guidance for proper torquing of nuts and bolts used in structural applications.....

Therefore, loss of preload due to self-loosening is not an aging effect requiring management for structural steel and steel component threaded fasteners within the scope of license renewal." Issue: The ASME Section X1, Subsection

/WF Program described in the GALL Report, program element, "parameters monitored or inspected, " states "Structural bolts are monitored for corrosion and loss of integrity of bolted connections due to self-loosening and material conditions that can affect structural integrity. " Based on this, the staff's position is that the potential loss of preload due to self-loosening from vibration, flexing of the joint, cyclic shear loads, thermal cycles and other causes is an aging effect requiring management.

Request: Provide sufficient technical basis for concluding loss of preload due to self-loosening is not an aging effect requiring management, or identify an AMPs to manage this aging effect.TVA Response to RAI 3.5.1-87 TVA has reassessed and concluded that loss of preload due to self-loosening is an aging effect requiring management.

The ISI-IWF Program manages loss of preload due to self-loosening of structural bolting.The changes to LRA Table 3.5.1 Item 3.5.1-87 and Table 3.5.2-4 follow with additions underlined and deletions lined through.E 23 of 25 Table 3.5.1: Structures and Component Supports Item Aging Effect/ Aging Management Further Evaluation Number Component

] Mechanism Programs Recommended Discussion Safety-Related and Other Structures; and Component Supports 3.5.1-87 Structural bolting Loss of preload due ISI (IWF) No Vibration, flexing of the joint, cYclic shear to self-loosening lads, theFrmnal cycles and otherc9auses can cause partial self loosening of a fastener.

These c-auses- Of loosening are minor contributorsgi struc-tu r;;l steel ;and steel componenAt threa;d-ed cnecin and- ere eliminated by initial pFrelead belt torquing.

SQN uses site procedu--reRs-an manuifactref r recommendat~ions to provide guidance for proper torguing ot nutsAnd bolts usepd in structurali applications.

Additionally, SQN site operating experience has not shown self l9oosRing Of u in SQN. Therefore, loss of preload due to Self loosing is, not an aging effect requiing anaement for s-tructuWral steel.and steel component threaded fasteners Atfhin the scope Of lcense reneAl.;I Consistent with NUREG-1801.

The ISI-IWF Program manages loss of preload due to self-loosening.

E 24 of 25 Table 3.5.2-4 Bulk Commodities Summary of Aging Management Evaluation Table 3.5.2-4: Bulk Commodities Structure and/or Aging Effect Aging Component or Intended Requiring Management NUREG-1801 Table I Commodity Function Material Environment Management Program Item Item Notes Hi-gh strength SNS, SRE, Carbon steel Air- indoor Loss of preload ISI-IWF III.B1.1.TP-229 3.5.1-87 A structural bolting SSR stainless steel uncontrolled or 111.813.2.TP-229 (Supports for ASME Air with borated Class 1, 2, and 3 water leakage piping and components)

Structural bolting SNS, SRE, Carbon steel Air -indoor Loss of preload ISI-IWF 111.131.TP-229 3.5.1-87 A SSR uncontrolled or 111.1323TP-229 Galvand Air -outdoor or Air with borated Stainless steel water leakage E 25 of 25 ENCLOSURE2 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Regulatory Commitment List, Revision 10 Commitments 18.A and 31.M have been revised with additions underlined.

LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE /AUDIT ITEM Implement the Aboveground Metallic Tanks Program as described 3QN1: Prior to 09/17/20 B.1.1 in LRA Section B.1.1 3QN2: Prior to 09/15/21 2 A. Revise Bolting Integrity Program procedures to ensure the 3QN1: Prior to 09/17/20 B.1.2 actual yield strength of replacement or newly procured bolts will be 3QN2: Prior to 09/15/21 less than 150 ksi B. Revise Bolting Integrity Program procedures to include the additional guidance and recommendations of EPRI NP-5769 for replacement of ASME pressure-retaining bolts and the guidance provided in EPRI TR-104213 for the replacement of other pressure-retaining bolts.C. Revise Bolting Integrity Program procedures to specify a corrosion inspection and a check-off for the transfer tube isolation valve flange bolts.D. Revise Bolting Integrity Program procedures to visually inspect a representative sample of normally submerged ERCW system bolts at least once every 5 years. (See Set 10 (30-day), Enclosure 1, B. 1.2-2a)3 A. Implement the Buried and Underground Piping and Tanks SQNI: Prior to 09/17/20 B. 1.4 Inspection Program as described in LRA Section B.1.4. SQN2: Prior to 09/15/21 B. Cathodic protection will be provided based on the guidance of NUREG-1801, section XI.M41, as modified by LR-ISG-2011-03.

E lof18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM 4 A. Revise Compressed Air Monitoring Program procedures to SQN1: Prior to 09/17/20 B.1.5 include the standby diesel generator (DG) starting air subsystem.

SQN2: Prior to 09/15/21 B. Revise Compressed Air Monitoring Program procedures to include maintaining moisture and other contaminants below specified limits in the standby DG starting air subsystem.

C. Revise Compressed Air Monitoring Program procedures to apply a consideration of the guidance of ASME OM-S/G-1998, Part 17;EPRI NP-7079; and EPRI TR-108147 to the limits specified for the air system contaminants D. Revise Compressed Air Monitoring Program procedures to maintain moisture, particulate size, and particulate quantity below acceptable limits in the standby DG starting air subsystem to mitigate loss of material.E. Revise Compressed Air Monitoring Program procedures to include periodic and opportunistic visual inspections of surface conditions consistent with frequencies described in ASME O/M-SG-1998, Part 17 of accessible internal surfaces such as compressors, dryers, after-coolers, and filter boxes of the following compressed air systems:* Diesel starting air subsystem* Auxiliary controlled air subsystem* Nonsafety-related controlled air subsystem F. Revise Compressed Air Monitoring Program procedures to monitor and trend moisture content in the standby DG starting air subsystem.

G. Revise Compressed Air Monitoring Program procedures to include consideration of the guidance for acceptance criteria in ASME OM-S/G-1998, Part 17, EPRI NP-7079; and EPRI TR-108147.

E 2of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE IAUDIT ITEM 5 A. Revise Diesel Fuel Monitoring Program procedures to monitor 3QN1: Prior to 09/17/20 B.1.8 and trend sediment and particulates in the standby DG day tanks. SQN2: Prior to 09/15/21 B. Revise Diesel Fuel Monitoring Program procedures to monitor and trend levels of microbiological organisms in the seven-day storage tanks.C. Revise Diesel Fuel Monitoring Program procedures to include a ten-year periodic cleaning and internal visual inspection of the standby DG diesel fuel oil day tanks and high pressure fire protection (HPFP) diesel fuel oil storage tank. These cleanings and internal inspections will be performed at least once during the ten-year period prior to the period of extended operation and at succeeding ten-year intervals.

If visual inspection is not possible, a volumetric inspection will be performed.

D. Revise Diesel Fuel Monitoring Program procedures to include a volumetric examination of affected areas of the diesel fuel oil tanks, if evidence of degradation is observed during visual inspection.

The scope of this enhancement includes the standby DG seven-day fuel oil storage tanks, standby DG fuel oil day tanks, and HPFP diesel fuel oil storage tank and is applicable to the inspections performed during the ten-year period prior to the period of extended operation and succeeding ten-year intervals.

6 A. Revise External Surfaces Monitoring Program procedures to SQN1: Priorto 09/17/20 B.1.10 clarify that periodic inspections of systems in scope and subject to SQN2: Prior to 09/15/21 aging management review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3) will be performed.

Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2).

B. Revise External Surfaces Monitoring Program procedures to include instructions to look for the following related to metallic components: " Corrosion and material wastage (loss of material)." Leakage from or onto external surfaces loss of material)." Worn, flaking, or oxide-coated surfaces (loss of material)." Corrosion stains on thermal insulation (loss of material)." Protective coating degradation (cracking, flaking, and blistering).

• Leakage for detection of cracks on the external surfaces of stainless steel components exposed to an air environment containing halides.C. Revise External Surfaces Monitoring Program procedures to include instructions for monitoring aging effects for flexible polymeric components, including manual or physical manipulations of the material, with a sample size for manipulation of at least ten E 3of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM (6) percent of the available surface area. The inspection parameters for polymers shall include the following:

• Surface cracking, crazing, scuffing, dimensional changes (e.g., ballooning and necking) -).* Discoloration.

• Exposure of internal reinforcement for reinforced elastomers (loss of material).

• Hardening as evidenced by loss of suppleness during manipulation where the component and material can be manipulated.

D. Revise External Surfaces Monitoring Program procedures to ensure surfaces that are insulated will be inspected when the external surface is exposed (i.e., during maintenance) at such intervals that would ensure that the components' intended function is maintained.

E. Revise External Surfaces Monitoring Program procedures to include acceptance criteria.

Examples include the following:

• Stainless steel should have a clean shiny surface with no discoloration.

• Other metals should not have any abnormal surface indications.

• Flexible polymers should have a uniform surface texture and color with no cracks and no unanticipated dimensional change, no abnormal surface with the material in an as-new condition with respect to hardness, flexibility, physical dimensions, and color.* Rigid polymers should have no erosion, cracking, checking or chalks.E 4of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE / AUDIT ITEM 7 A. Revise Fatigue Monitoring Program procedures to monitor and SQNI: Prior to 09/17/20 B.1.11 track critical thermal and pressure transients for components that SQN2: Prior to 09/15/21 have been identified to have a fatigue Time Limited Aging Analysis.B. Fatigue usage calculations that consider the effects of the reactor water environment will be developed for a set of sample reactor coolant system (RCS) components.

This sample set will include the locations identified in NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant pressure boundary if they are found to be more limiting than those considered in NUREG/CR-6260. In addition, fatigue usage calculations for reactor vessel internals (lower core plate and control rod drive (CRD) guide tube pins) will be evaluated for the effects of the reactor water environment.

Fen factors will be determined as described in Section 4.3.3.C. Fatigue usage factors for the RCS pressure boundary components will be adjusted as necessary-to incorporate the effects of the Cold Overpressure Mitigation System (COMS) event (i.e., low temperature overpressurization event) and the effects of structural weld overlays.D. Revise Fatigue Monitoring Program procedures to provide updates of the fatigue usage calculations and cycle-based fatigue waiver evaluations on an as-needed basis if an allowable cycle limit is approached, or in a case where a transient definition has been changed, unanticipated new thermal events are discovered, or the geometry of components have been modified.E. Revise Fatigue Monitoring Program procedures to track the tensioning cycles for the reactor coolant pump hydraulic studs.8 A. Revise Fire Protection Program procedures to include an SQN1: Prior to 09/17/20 B.1.12 inspection of fire barrier walls, ceilings, and floors for any signs of SQN2: Prior to 09/15/21 degradation such as cracking, spalling, or loss of material caused by freeze thaw, chemical attack, or reaction with aggregates.

B. Revise Fire Protection Program procedures to provide acceptance criteria of no significant indications of concrete cracking, spalling, and loss of material of fire barrier walls, ceilings, and floors and in other fire barrier materials.

9 A. Revise Fire Water System Program procedures to include periodic SQN1: Prior to 09/17/20 B.1.13 visual inspection of fire water system internals for evidence of SQN2: Prior to 09/15/21 corrosion and loss of wall thickness.

B. Revise Fire Water System Program procedures to include one of the following options:* Wall thickness evaluations of fire protection piping using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material will be performed prior to the period of E 5of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM (9) extended operation and periodically thereafter.

Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.A visual inspection of the internal surface of fire protection piping will be performed upon each entry into the system for routine or corrective maintenance.

These inspections will be capable of evaluating (1) wall thickness to ensure against catastrophic failure and (2) the inner diameter of the piping as it applies to the design flow of the fire protection system. Maintenance history shall be used to demonstrate that such inspections have been performed on a representative number of locations prior to the period of extended operation.

A representative number is 20%of the population (defined as locations having the same material, environment, and aging effect combination) with a maximum of 25 locations.

Additional inspections will be performed as needed to obtain this representative sample prior to the period of extended operation and periodically during the period of extended operation based on the findings from the inspections performed prior to the period of extended operation.

C. Revise Fire Water System Program procedures to ensure a representative sample of sprinkler heads will be tested or replaced before the end of the 50-year sprinkler head service life and at ten-year intervals thereafter during the extended period of operation.

NFPA-25 defines a representative sample of sprinklers to consist of a minimum of not less than four sprinklers or one percent of the number of sprinklers per individual sprinkler sample, whichever is greater. If the option to replace the sprinklers is chosen, all sprinkler heads that have been in service for 50 years will be replaced.D. Revise the Fire Water System Program full flow testing to be in accordance with full flow testing standards of NFPA-25 (2011).E. Revise Fire Water System Program procedures to include acceptance criteria for periodic visual inspection of fire water system internals for corrosion, minimum wall thickness, and the absence of biofouling in the sprinkler system that could cause corrosion in the sprinklers.

F. Prior to the PEO, SQN will select an inspection method (or methods) that will provide suitable indication of piping wall thickness for a representative sample of buried piping locations to supplement the existing inspection locations for high pressure fire protection system 26 and essential raw cooling water system 67.10 A. Revise Flow Accelerated Corrosion (FAC) Program procedures SQN1: Priorto 09/17/20 B.1.14 to implement NSAC-202L guidance for examination of components SQN2: Prior to 09/15/21 upstream of piping surfaces where significant wear is detected.E 6of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM (10) B. Revise FAC Program procedures to implement the guidance in LR-ISG-2012-01, which will include a susceptibility review based on internal operating experience, external operating experience, EPRI TR-1 011231, Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant Piping, and NUREG/CR-6031, Cavitation Guide for Control Valves.11 Revise Flux Thimble Tube Inspection Program procedures to SQNI: Prior to 09117/20 B.1.15 include a requirement to address if the predictive trending projects SQN2: Prior to 09/15/21 that a tube will exceed 80% wall wear prior to the next planned inspection, then initiate a Service Request (SR) to define actions (i.e., plugging, repositioning, replacement, evaluations, etc.) required to ensure that the projected wall wear does not exceed 80%. If any tube is found to be >80% through wall wear, then initiate a Service Request (SR) to evaluate the predictive methodology used and modify as required to define corrective actions (i.e., plugging, I repositioning, replacement, etc).12 A. Revise Inservice Inspection-IWF Program procedures to clarify SQN1: Priorto 09/17/20 B.1.17 that detection of aging effects will include monitoring anchor bolts for SQN2: Prior to 09/15/21 loss of material, loose or missing nuts, and cracking of concrete around the anchor bolts.B. Revise ISI -IWF Program procedures to include the following corrective action guidance.When a component support is found with minor age-related degradation, but still is evaluated as "acceptable for continued service" as defined in IWF-3400, the program owner may choose to repair the degraded component.

If the component is repaired, the program owner will substitute a randomly selected component that is more representative of the general population for subsequent inspections.

13 Inspection of Overhead Heavy Load and Light Load (Related to SQN1: Prior to 09/17/20 B.1.18 Refueling)

Handling Systems: SQN2: Prior to 09/15/21 A. Revise program procedures to specify the inspection scope will include monitoring of rails in the rail system for wear; monitoring structural components of the bridge, trolley and hoists for the aging effect of deformation, cracking, and loss of material due to corrosion; and monitoring structural connections/bolting for loose or missing bolts, nuts, pins or rivets and any other conditions indicative of loss of bolting integrity.

B. Revise program procedures to include the inspection and inspection frequency requirements of ASME B30.2.C. Revise program procedures to clarify that the acceptance criteria will include requirements for evaluation in accordance with ASME B30.2 of significant loss of material for structural components and structural bolts and significant wear of rail in the rail system.E 7of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE /AUDIT ITEM (13) D. Revise program procedures to clarify that the acceptance criteria and maintenance and repair activities use the guidance provided in ASME B30.2 14 Implement the Internal Surfaces in Miscellaneous Piping and SQN1: Prior to 09/17/20 B.1.19 Ducting Components Program as described in LRA Section B.1.19. SQN2: Prior to 09/15/21 15 Implement the Metal Enclosed Bus Inspection Program as SQN1: Prior to 09/17/20 B.1.21 described in LRA Section B.1.21. SQN2: Prior to 09/15/21 16 A. Revise Neutron Absorbing Material Monitoring Program SQN1: Prior to 09/17/20 B.1.22 procedures to perform blackness testing of the Boral coupons within SQN2: Prior to 09/15/21 the ten years prior to the period of extended operation and at least every ten years thereafter based on initial testing to determine possible changes in boron-10 areal density.B. Revise Neutron Absorbing Material Monitoring Program procedures to relate physical measurements of Boral coupons to the need to perform additional testing.C. Revise Neutron Absorbing Material Monitoring Program procedures to perform trending of coupon testing results to determine the rate of degradation and to take action as needed to maintain the intended function of the Boral.17 Implement the Non-EQ Cable Connections Program as described QNI: Prior to 09/17/20 B.1.24 in LRA Section B.1.24 QN2: Prior to 09/15/21 18 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) QN1: Prior to 09/17/20 B.1.25 Program as described in LRA Section B.1.25 QN2: Prior to 09/15/21 A. TVA response to RAI B.1.25.1a 1. Repair the manhole sump pump and discharge piping 18.A.1: Sept 2015 deficiencies associated with the accumulation of water in seven manholes/handholes that are scheduled for correction and/or mitigation by September 2015. (HH3, HH2B, HH52B, HH55A2.MH7B, MH10A and MH32B as identified on October 1, 2013) 18.A2 & 4: Sept 2014 2. Grade the ground surface around Manhole 31 to direct runoff away from the manhole. The re-grading is scheduled for completion by September 2014.3. Prior to the PEO, the license renewal commitment for the Non-EQ 18.A.3: Inaccessible Power Cables (400 V to 35 kV) Program will QN1: Prior to 09/17/20 establish diagnostic testing activities on all inaccessible power SQN2: Prior to 09/15/21 cables in the 400 V to 35kV range that are in the scope of license renewal and subiect to aging management review.4. Revise the manhole inspection procedures to specify the maximum allowable water level to preclude cable submergence in the manhole. If the inspection identifies submergence of inaccessible power cable for more than a few days, the condition will be documented and evaluated in the SQN corrective action proqram. The evaluation will consider results of the most recent E 8of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM (18) diaignostic testing., insulation type, submergence level, voltage level, energization cycle (usage), and various other inputs to determine whether the cables remain capable of performing their intended current licensing basis function.19 Implement the Non-EQ Instrumentation Circuits Test Review QN1: Prior to 09/17/20 B.1.26 Program as described in LRA Section B.1.26. QN2: Prior to 09/15/21 20 Implement the Non-EQ Insulated Cables and Connections QN1: Prior to 09/17/20 B.1.27 Program as described in LRA Section B.1.27 QN2: Prior to 09/15/21 21 A. Revise Oil Analysis Program procedures to monitor and SQN1: Prior to 09/17/20 B.1.28 maintain contaminants in the 161-kV oil filled cable system within SQN2: Prior to 09/15/21 acceptable limits through periodic sampling in accordance with industry standards, manufacturer's recommendations and plant-specific operating experience.

B. Revise Oil Analysis Program procedures to trend oil contaminant levels and initiate a problem evaluation report if contaminants exceed alert levels or limits in the 161-kV oil-filled cable system.22 Implement the One-Time Inspection Program as described in LRA SQN1: Prior to 09/17/20 B.1.29 Section B.1.29. SQN2: Prior to 09/15/21 23 Implement the One-Time Inspection

-Small Bore Piping Program SQN1: Prior to 09/17/20 B.1.30 as described in LRA Section B.1.30 SQN2: Prior to 09/15/21 24 Revise Periodic Surveillance and Preventive Maintenance SQN1: Prior to 09/17/20 B.1.31 Program procedures as necessary to include all activities described SQN2: Prior to 09/15/21 in the table provided in the LRA Section B.1.31 program description.

25 A. Revise Protective Coating Program procedures to clarify that SQNI: Prior to 09/17/20 B.1.32 detection of aging effects will include inspection of coatings near SQN2: Prior to 09/15/21 sumps or screens associated with the emergency core cooling system.B. Revise Protective Coating Program procedures to clarify that instruments and equipment needed for inspection may include, but not be limited to, flashlights, spotlights, marker pen, mirror, measuring tape, magnifier, binoculars, camera with or without wide-angle lens, and self-sealing polyethylene sample bags.C. Revise Protective Coating Program procedures to clarify that the last two performance monitoring reports pertaining to the coating systems will be reviewed prior to the inspection or monitoring I process.E 9of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE IAUDIT ITEM 26 A. Revise Reactor Head Closure Studs Program procedures to SQNI: Prior to 09/17/20 B.1.33 ensure that replacement studs are fabricated from bolting material SQN2: Prior to 09/15/21 with actual measured yield strength less than 150 ksi.B. Revise Reactor Head Closure Studs Program procedures to exclude the use of molybdenum disulfide (MoS 2) on the reactor vessel closure studs and to refer to Reg. Guide 1.65, Revi.27 A. Revise Reactor Vessel Internals Program procedures to take SQNI: Prior to 09/17/20 B.1.34 physical measurements of the Type 304 stainless steel hold-down springs in Unit 1 at each refueling outage to ensure preload is SQN2: Not Applicable adequate for continued operation.

B. Revise Reactor Vessel Internals Program procedures to include preload acceptance criteria for the Type 304 stainless steel hold-down springs in Unit 1.28 A. Revise Reactor Vessel Surveillance Program procedures to SQNI: Prior to 09/17/20 B.1.35 consider the area outside the beltline such as nozzles, penetrations SQN2: Prior to 09/15/21 and discontinuities to determine if more restrictive pressure-temperature limits are required than would be determined by just considering the reactor vessel beltline materials.

B. Revise Reactor Vessel Surveillance Program procedures to incorporate an NRC-approved schedule for capsule withdrawals to meet ASTM-E185-82 requirements, including the possibility of operation beyond 60 years (refer to the TVA Letter to NRC,"Sequoyah Reactor Pressure Vessel Surveillance Capsule Withdrawal Schedule Revision Due to License Renewal Amendment," dated January 10, 2013, ML13032A251.)

C. Revise Reactor Vessel Surveillance Program procedures to withdraw and test a standby capsule to cover the peak fluence expected at the end of the period of extended operation.

29 Implement the Selective Leaching Program as described in LRA SQNI: Prior to 09/17/20 B.1.37 Section B.1.37. SQN2: Prior to 09/15/21 30 Revise Steam Generator Integrity Program procedures to ensure SQNI: Prior to 09/17/20 B.1.39 that corrosion resistant materials are used for replacement steam SQN2: Prior to 09/15/21 generator tube plugs.31 A. Revise Structures Monitoring Program procedures to include the following in-scope structures:

• Carbon dioxide building" Condensate storage tanks' (CSTs) foundations and pipe trench" East steam valve room Units 1 & 2" Essential raw cooling water (ERCW) pumping station* High pressure fire protection (HPFP) pump house and water storage tanks' foundations" Radiation monitoring station (or particulate iodine and noble gas SQNI: Prior to 09/17/20 SQN2: Prior to 09/15/21 B.1.40 E 10 of 18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM (31) station) Units 1 & 2" Service building* Skimmer wall (Cell No. 12)" Transformer and switchyard support structures and foundations B, Revise Structures Monitoring Program procedures to specify the following list of in-scope structures are included in the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program (Section B.1.36):* Condenser cooling water (CCW) pumping station (also known as intake pumping station) and retaining walls* CCW pumping station intake channel* ERCW discharge box* ERCW protective dike* ERCW pumping station and access cells* Skimmer wall, skimmer wall Dike A and underwater dam C. Revise Structures Monitoring Program procedures to include the following in-scope structural components and commodities:

• Anchor bolts* Anchorage/embedments (e.g., plates, channels, unistrut, angles, other structural shapes)* Beams, columns and base plates (steel)* Beams, columns, floor slabs and interior walls (concrete)

• Beams, columns, floor slabs and interior walls (reactor cavity and primary shield walls; pressurizer and reactor coolant pump compartments; refueling canal, steam generator compartments; crane wall and missile shield slabs and barriers)* Building concrete at locations of expansion and grouted anchors;grout pads for support base plates" Cable tray* Cable tunnel* Canal gate bulkhead" Compressible joints and seals* Concrete cover for the rock walls of approach channel* Concrete shield blocks* Conduit* Control rod drive missile shield" Control room ceiling support system* Curbs* Discharge box and foundation

• Doors (including air locks and bulkhead doors)* Duct banks* Earthen embankment

• Equipment pads/foundations

• Explosion bolts (E. G. Smith aluminum bolts)" Exterior above and below grade; foundation (concrete)" Exterior concrete slabs (missile barrier) and concrete caps* Exterior walls: above and below grade (concrete)

• Foundations:

building, electrical components, switchyard, transformers, circuit breakers, tanks, etc.E 11of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE AUDIT ITEM (31) o Ice baskets" Ice baskets lattice support frames* Ice condenser support floor (concrete)

• Insulation (fiberglass, calcium silicate)* Intermediate deck and top deck of ice condenser* Kick plates and curbs (steel -inside steel containment vessel)* Lower inlet doors (inside steel containment vessel)" Lower support structure structural steel: beams, columns, plates (inside steel containment vessel)* Manholes and handholes* Manways, hatches, manhole covers, and hatch covers (concrete)

• Manways, hatches, manhole covers, and hatch covers (steel)* Masonry walls* Metal siding* Miscellaneous steel (decking, grating, handrails, ladders, platforms, enclosure plates, stairs, vents and louvers, framing steel, etc.)* Missile barriers/shields (concrete)

• Missile barriers/shields (steel)* Monorails* Penetration seals* Penetration seals (steel end caps)* Penetration sleeves (mechanical and electrical not penetrating primary containment boundary)Personnel access doors, equipment access floor hatch and escape hatches* Piles* Pipe tunnel* Precast bulkheads* Pressure relief or blowout panels" Racks, panels, cabinets and enclosures for electrical equipment and instrumentation" Riprap* Rock embankment

• Roof or floor decking* Roof membranes* Roof slabs* RWST rainwater diversion skirt* RWST storage basin* Seals and gaskets (doors, manways and hatches)* Seismic/expansion joint" Shield building concrete foundation, wall, tension ring beam and dome: interior, exterior above and below grade* Steel liner plate" Steel sheet piles* Structural bolting* Sumps (concrete)

• Sumps (steel)E 12 of 18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM (31)

• Sump liners (steel)* Sump screens" Support members; welds; bolted connections; support anchorages to building structure (e.g., non-ASME piping and components supports, conduit supports, cable tray supports, HVAC duct supports, instrument tubing supports, tube track supports, pipe whip restraints, jet impingement shields, masonry walls, racks, panels, cabinets and enclosures for electrical equipment and instrumentation)" Support pedestals (concrete)

• Transmission, angle and pull-off towers* Trash racks* Trash racks associated structural support framing* Traveling screen casing and associated structural support framing* Trenches (concrete)" Tube track" Turning vanes" Vibration isolators D. Revise Structures Monitoring Program procedures to include periodic sampling and chemical analysis of ground water chemistry for pH, chlorides, and sulfates on a frequency of at least every five years.E. Revise Masonry Wall Program procedures to specify masonry walls located in the following in-scope structures are in the scope of the Masonry Wall Program:* Auxiliary building* Reactor building Units 1 & 2* Control bay* ERCW pumping station* HPFP pump house* Turbine building F. Revise Structures Monitoring Program procedures to include the following parameters to be monitored or inspected:

• Requirements for concrete structures based on ACI 349-3R and ASCE 11 and include monitoring the surface condition for loss of material, loss of bond, increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation.

• Loose or missing nuts for structural bolting.* Monitoring gaps between the structural steel supports and masonry walls that could potentially affect wall qualification.

G. Revise Structures Monitoring Program procedures to include the following components to be monitored for the associated parameters:

• Anchors/fasteners (nuts and bolts) will be monitored for loose or missing. nuts and/or bolts, and cracking of concrete around the anchor bolts.* Elastomeric vibration isolators and structural sealants will be E 13 of 18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE / AUDIT ITEM (31) monitored for cracking, loss of material, loss of sealing, and change in material properties (e.g., hardening).

Monitor the surface condition of insulation (fiberglass, calcium silicate) to identify exposure to moisture that can cause loss of insulation effectiveness.

H. Revise Structures Monitoring Program procedures to include the following for detection of aging effects:* Inspection of structural bolting for loose or missing nuts.* Inspection of anchor bolts for loose or missing nuts and/or bolts, and cracking of concrete around the anchor bolts.* Inspection of elastomeric material for cracking, loss of material, loss of sealing, and change in material properties (e.g., hardening), and supplement inspection by feel or touch to detect hardening if the intended function of the elastomeric material is suspect. Include instructions to augment the visual examination of elastomeric material with physical manipulation of at least ten percent of available surface area.* Opportunistic inspections when normally inaccessible areas (e.g., high radiation areas, below grade concrete walls or foundations, buried or submerged structures) become accessible due to required plant activities.

Additionally, inspections will be performed of inaccessible areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant degradation is occurring.

• Inspection of submerged structures at least once every five years.Inspections of water control structures should be conducted under the direction of qualified personnel experienced in the investigation, design, construction, and operation of these types of facilities.

• Inspections of water control structures shall be performed on an interval not to exceed five years.* Perform special inspections of water control structures immediately (within 30 days) following the occurrence of significant natural phenomena, such as large floods, earthquakes, hurricanes, tornadoes, and intense local rainfalls.

• Insulation (fiberglass, calcium silicate) will be monitored for loss of material and change in material properties due to potential exposure to moisture that can cause loss of insulation effectiveness.

I. Revise Structures Monitoring Program procedures to prescribe quantitative acceptance criteria is based on the quantitative acceptance criteria of ACI 349.3R and information provided in industry codes, standards, and guidelines including ACI 318, ANSI/ASCE 11 and relevant AISC specifications.

Industry and plant-specific operating experience will also be considered in the development of the acceptance criteria.E 14 of 18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE /AUDIT ITEM (31) J. Revise Structures Monitoring Program procedures to clarify that detection of aging effects will include the following.

Qualifications of personnel conducting the inspections or testing and evaluation of structures and structural components meet the guidance in Chapter 7 of ACI 349.3R.K. Revise Structures Monitoring Program procedures to include the following acceptance criteria for insulation (calcium silicate and fiberglass)

• No moisture or surface irregularities that indicate exposure to moisture.L. Revise Structures Monitoring Program procedures to include the following preventive actions.Specify protected storage requirements for high-strength fastener components (specifically ASTM A325 and A490 bolting).Storage of these fastener components shall include: 1. Maintaining fastener components in closed containers to protect from dirt and corrosion;

2. Storage of the closed containers in a protected shelter;3. Removal of fastener components from protected storage only as necessary; and 4. Prompt return of any unused fastener components to protected storage.M. TVA Response to RAI B.1.40-4a (Turbine Building wall crack)1. SQN will map and trend the crack in the condenser pit north wall.2. SQN will test water inleakaqe samples from the turbine building condenser pit walls and floor slab for minerals and iron content to assess the effect of the water inleakage on the concrete and the reinforcing steel.3. SQN will test concrete core samples removed from the turbine building condenser pit north wall with a minimum of one core sample in the area of the crack. The core samples will be tested for compressive strength and modulus of elasticity and subiected to petrographic examination.

4. The results of the tests and SMP inspections will be used to determine further corrective actions, if necessary.

5. Commitment

1. 31.M will be implemented before the PEO for SQN Units 1 and 2.32 Implement the Thermal Aging Embrittlement of Cast Austenitic QN1: Prior to 09/17/20 B.1.41 Stainless Steel (CASS) as described in LRA Section B.1.41 QN2: Prior to 09/15/21 33 A. Revise Water Chemistry Control -Closed Treated Water QN1: Prior to 09/17/20 B. 1.42 Systems Program procedures to provide a corrosion inhibitor for the QN2: Prior to 09/15/21 following chilled water subsystems in accordance with industry guidelines and vendor recommendations:

• Auxiliary building cooling* Incore Chiller 1A, 1B, 2A, & 2B* 6.9 kV Shutdown Board Room A & B E 15of18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE /_AUDIT ITEM (33)(33)B. Revise Water Chemistry Control -Closed Treated Water Systems Program procedures to conduct inspections whenever a boundary is opened for the following systems:* Standby diesel generator jacket water subsystem* Component cooling system* Glycol cooling loop system* High pressure fire protection diesel jacket water system* Chilled water portion of miscellaneous HVAC systems (i.e., auxiliary building, Incore Chiller 1A, 1B, 2A, & 2B, and 6.9 kV Shutdown Board Room A & B)C. Revise Water Chemistry Control-Closed Treated Water Systems Program procedures to state these inspections will be conducted in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection and personnel qualification procedures that are capable of detecting corrosion or cracking.D. Revise Water Chemistry Control -Closed Treated Water Systems Program procedures to perform sampling and analysis of the glycol cooling system per industry standards and in no case greater than quarterly unless justified with an additional analysis.E. Revise Water Chemistry Control -Closed Treated Water Systems Program procedures to inspect a representative sample of piping and components at a frequency of once every ten years for the following systems: " Standby diesel generator jacket water subsystem" Component cooling system* Glycol cooling loop system" High pressure fire protection diesel jacket water system" Chilled water portion of miscellaneous HVAC systems (i.e., auxiliary building, Incore Chiller 1A, 1 B, 2A, & 2B, and 6.9 kV Shutdown Board Room A & B)F. Components inspected will be those with the highest likelihood of corrosion or cracking.

A representative sample is 20% of the population (defined as components having the same material, environment, and aging effect combination) with a maximum of 25 components.

These inspections will be in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection and personnel qualification procedures that ensure the capability of detecting corrosion or cracking.34 Revise Containment Leak Rate Program procedures to require SQN1: Prior to 09/17/20 B.1.7 venting the SCV bottom liner plate weld leak test channels to the SQN2: Prior to 09/15/21 containment atmosphere prior to the CILRT and resealing the vent path after the CILRT to prevent moisture intrusion during plant operation.

E 16 of 18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE IAUDIT ITEM 35 Modify the configuration of the SQN Unit 1 test connection access SQN1: Prior to 09/17/20 B. 1.6 boxes to prevent moisture intrusion to the leak test channels.

Prior to installing this modification, TVA will perform remote visual SQN2: Not Applicable examinations inside the leak test channels by inserting a borescope video probe through the test connection tubing.36 Revise Inservice Inspection Program procedures to include a SQN1: Prior to 09/17/20 B.1.16 supplemental inspection of Class 1 CASS piping components that SQN2: Prior to 09/15/21 do not meet the materials selection criteria of NUREG-0313, Revision 2 with regard to ferrite and carbon content. An inspection techniques qualified by ASME or EPRI will be used to monitor cracking.Inspections will be conducted on a sampling basis. The extent of sampling will be based on the established method of inspection and industry operating experience and practices when the program is implemented, and will include components determined to be limiting from the standpoint of applied stress, operating time and environmental considerations.

I E 17 of 18 LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE / AUDIT ITEM 37 TVA will implement the Operating Experience for the AMPs in accordance with the TVA response to the RAI B.0.4-1 on July 29, 2013 letter to the NRC. (See Set 7.30day RAI B.0.4-1 Response, ML13213A027);

and Oct 16, 2013 2013 letter to the NRC. (See Set 13.30day RAIs B.O.4-la and A.l-la Response)* Revise OE Program Procedure to include current and future revisions to NUREG-1 801, "Generic Aging Lessons Learned (GALL) Report," as a source of industry OE, and unanticipated age-related degradation or impacts to aging management activities as a screening attribute.

• Revise the CAP Procedure to provide a screening process of corrective action documents for aging management items, the assignment of aging corrective actions to appropriate AMP owners, and consideration of the aging management trend code." Revise AMP procedures as needed to provide for review and evaluation by AMP owners of data from inspections, tests, analyses or AMP OEs." Revise the OE Program Procedure to provide guidance for reporting plant-specific OE on unanticipated age-related degradation or impact to aging management activities to the TVA fleet and/or INPO.* Revise the OE, CAP, Initial and Continuing Engineering Support Personnel Training to address age-related topics, the unanticipated degradation or impacts to the aging management activities; including periodic refresher/update training and provisions to accommodate the turnover of plant personnel, and recent AMP-related OE from INPO, the NRC, Scientech, and nuclear industry-initiated guidance documents and standards."" A comprehensive and holistic AMP training topic list will be developed before the date the SQN renewed operating license is scheduled to be issued." TVA AMP OE Process, AMP adverse trending & evaluation in CAP, AMP Initial and Refresher Training will be fully implemented by the date the SQN renewed operating license is scheduled to be issued.No later than the scheduled issue date of:he renewed operating icenses for SQN Units 1& 2.'Currently February 2015)B.0.4 The above table identifies the 37 SQN NRC LR commitments.

Any other statements in this letter are provided for information purposes and are not considered to be regulatory commitments.

E 18 of 18