View source for NL-12-174, Official Exhibit - ENT000597-00-BD01 - NL-12-174, Letter from Fred Dacimo, Vice President, IPEC, to NRC Document Control Desk, Additional Clarification of Underground Piping Information Provided in Letter NL-12-149 Regarding the .

{{Adams
| number = ML13039A452
| issue date = 11/29/2012
| title = Official Exhibit - ENT000597-00-BD01 - NL-12-174, Letter from Fred Dacimo, Vice President, IPEC, to NRC Document Control Desk, Additional Clarification of Underground Piping Information Provided in Letter NL-12-149 Regarding the .
| author name = Dacimo F
| author affiliation = Entergy Nuclear Northeast
| addressee name = 
| addressee affiliation = NRC/ASLBP, NRC/Document Control Desk
| docket = 05000286, 05000247
| license number = DPR-026, DPR-064
| contact person = SECY RAS
| case reference number = RAS 23852, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01, NL-12-174
| document type = Legal-Exhibit
| page count = 29
}}

=Text=
{{#Wiki_filter:United States Nuclear Regulatory Commission Official Hearing Exhibit Entergy Nuclear Operations, Inc.
In the Matter of:
(Indian Point Nuclear Generating Units 2 and 3)
ASLBP #: 07-858-03-LR-BD01 Docket #: 05000247 l 05000286 Exhibit #: ENT000597-00-BD01                  Identified: 12/10/2012 Admitted: 1/15/2013                          Withdrawn:
ENT000597 Rejected:                                       Stricken:
Other:
Submitted: December 6, 2012 Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-2055 Fred Dacimo Vice President Operations License Renewal NL-12-174 November 29, 2012 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

==SUBJECT:==
Additional Clarification of Underground Piping Information Provided in Letter NL-12-149 Regarding the License Renewal Application Indian Point Nuclear Generating Unit Nos. 2 & 3 Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64

==REFERENCE:==
(1) Entergy letter (NL-12-149), Clarification of Underground Piping Information Provided in Letter NL-11-032 Regarding the License Renewal Application, dated October 18, 2012

==Dear Sir or Madam:==

Reference 1 provided information on underground piping (piping below grade in air with restricted access) in the IPEC Unit 2 and Unit 3 fuel oil systems, and in the IPEC Unit 3 service water and city water systems. In this letter it was stated that The above piping will be periodically inspected under the Buried Piping and Tanks Inspection Program at a frequency that meets or exceeds NUREG-1801 Section XI.M41 guidance for underground piping which will ensure the effects of aging are adequately managed. The NUREG-1801 recommendation for an inspection frequency of at least once every ten years is provided for piping with preventive measures consisting of coatings in accordance with XI.M41 Table 2b or approved alternative.
The underground piping at IPEC is not provided with such coatings. Therefore, Entergy is making the following commitment to perform inspections at a frequency of at least once every two years.
Commitment 48 Entergy will visually inspect IPEC underground piping within the scope of license renewal and subject to aging management review prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation. This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

ATTACHMENT 1 TO NL-12-174 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev. 19 ENTERGY NUCLEAR OPERATIONS, INC.
INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

Attachment 1 NL-12-174 Page 1 of 21 List of Regulatory Commitments Rev. 19 The following table identifies those actions committed to by Entergy in this document.
Changes are shown as strikethroughs for deletions and underlines for additions.
#                           COMMITMENT                         IMPLEMENTATION     SOURCE      RELATED SCHEDULE                  LRA SECTION
                                                                                            / AUDIT ITEM IP2:              NL-07-039     A.2.1.1 1   Enhance the Aboveground Steel Tanks Program for September 28,                   A.3.1.1 IP2 and IP3 to perform thickness measurements of 2013                             B.1.1 the bottom surfaces of the condensate storage tanks, city water tank, and fire water tanks once during the IP3:
first ten years of the period of extended operation.
December 12, Enhance the Aboveground Steel Tanks Program for            2015 IP2 and IP3 to require trending of thickness measurements when material loss is detected.
IP2:              NL-07-039     A.2.1.2 2   Enhance the Bolting Integrity Program for IP2 and IP3 September 28,                   A.3.1.2 to clarify that actual yield strength is used in selecting 2013                             B.1.2 materials for low susceptibility to SCC and clarify the prohibition on use of lubricants containing MoS2 for IP3:              NL-07-153 Audit Items bolting.
December 12,                   201, 241, The Bolting Integrity Program manages loss of              2015                              270 preload and loss of material for all external bolting.

Attachment 1 NL-12-174 Page 2 of 21
#                        COMMITMENT                        IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                     / AUDIT ITEM IP2:           NL-07-039     A.2.1.5 3 Implement the Buried Piping and Tanks Inspection September 28,                A.3.1.5 Program for IP2 and IP3 as described in LRA Section 2013                          B.1.6 B.1.6.
NL-07-153   Audit Item This new program will be implemented consistent with IP3:                               173 the corresponding program described in NUREG-            December 12, 1801 Section XI.M34, Buried Piping and Tanks             2015 Inspection.
Include in the Buried Piping and Tanks Inspection                       NL-09-106 Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that                     NL-09-111 includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. Classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Determine corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Establish inspection priority and frequency for periodic inspections of the in-scope piping and tanks based on the results of the risk assessment. Perform inspections using inspection techniques with NL-11-101 demonstrated effectiveness.

Attachment 1 NL-12-174 Page 3 of 21
#                        COMMITMENT                        IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                     / AUDIT ITEM IP2:           NL-07-039     A.2.1.8 4 Enhance the Diesel Fuel Monitoring Program to September 28,                A.3.1.8 include cleaning and inspection of the IP2 GT-1 gas 2013                          B.1.9 turbine fuel oil storage tanks, IP2 and IP3 EDG fuel oil NL-07-153 Audit items day tanks, IP2 SBO/Appendix R diesel generator fuel IP3:                        128, 129, oil day tank, and IP3 Appendix R fuel oil storage tank December 12,                  132, and day tank once every ten years.
2015           NL-08-057 491, 492, Enhance the Diesel Fuel Monitoring Program to                                           510 include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 10mg/l. Water and sediment acceptance criterion will be less than or equal to 0.05%.
Enhance the Diesel Fuel Monitoring Program to include thickness measurement of the bottom of the following tanks once every ten years. IP2: EDG fuel oil storage tanks, EDG fuel oil day tanks, SBO/Appendix R diesel generator fuel oil day tank, GT-1 gas turbine fuel oil storage tanks, and diesel fire pump fuel oil storage tank; IP3: EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank.
Enhance the Diesel Fuel Monitoring Program to change the analysis for water and particulates to a quarterly frequency for the following tanks. IP2: GT-1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank; IP3: Appendix R fuel oil day tank and diesel fire pump fuel oil storage tank.
Enhance the Diesel Fuel Monitoring Program to specify acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of the program.
Enhance the Diesel Fuel Monitoring Program to direct samples be taken and include direction to remove water when detected.
Revise applicable procedures to direct sampling of the onsite portable fuel oil contents prior to transferring the contents to the storage tanks.
Enhance the Diesel Fuel Monitoring Program to direct the addition of chemicals including biocide when the presence of biological activity is confirmed.

Attachment 1 NL-12-174 Page 4 of 21
#                        COMMITMENT                         IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                      / AUDIT ITEM IP2:           NL-07-039    A.2.1.10 5 Enhance the External Surfaces Monitoring Program September 28,               A.3.1.10 for IP2 and IP3 to include periodic inspections of 2013                         B.1.11 systems in scope and subject to aging management review for license renewal in accordance with 10 CFR IP3:
54.4(a)(1) and (a)(3). Inspections shall include areas December 12, surrounding the subject systems to identify hazards to 2015 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).
IP2:           NL-07-039    A.2.1.11 6 Enhance the Fatigue Monitoring Program for IP2 to September 28,               A.3.1.11 monitor steady state cycles and feedwater cycles or 2013                         B.1.12, perform an evaluation to determine monitoring is not NL-07-153   Audit Item required. Review the number of allowed events and 164 resolve discrepancies between reference documents and monitoring procedures.
Enhance the Fatigue Monitoring Program for IP3 to         IP3:
include all the transients identified. Assure all fatigue December 12, analysis transients are included with the lowest          2015 limiting numbers. Update the number of design transients accumulated to date.

Attachment 1 NL-12-174 Page 5 of 21
#                        COMMITMENT                         IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                      / AUDIT ITEM IP2:           NL-07-039    A.2.1.12 7 Enhance the Fire Protection Program to inspect September 28,               A.3.1.12 external surfaces of the IP3 RCP oil collection 2013                         B.1.13 systems for loss of material each refueling cycle.
Enhance the Fire Protection Program to explicitly         IP3:
state that the IP2 and IP3 diesel fire pump engine        December 12, sub-systems (including the fuel supply line) shall be     2015 observed while the pump is running. Acceptance criteria will be revised to verify that the diesel engine does not exhibit signs of degradation while running; such as fuel oil, lube oil, coolant, or exhaust gas leakage.
Enhance the Fire Protection Program to specify that the IP2 and IP3 diesel fire pump engine carbon steel exhaust components are inspected for evidence of corrosion and cracking at least once each operating cycle.
Enhance the Fire Protection Program for IP3 to visually inspect the cable spreading room, 480V switchgear room, and EDG room CO2 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

Attachment 1 NL-12-174 Page 6 of 21
#                        COMMITMENT                       IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                    / AUDIT ITEM IP2:           NL-07-039    A.2.1.13 8 Enhance the Fire Water Program to include inspection September 28,               A.3.1.13 of IP2 and IP3 hose reels for evidence of corrosion.
2013                         B.1.14 Acceptance criteria will be revised to verify no NL-07-153 Audit Items unacceptable signs of degradation.
IP3:                        105, 106 Enhance the Fire Water Program to replace all or test December 12,     NL-08-014 a sample of IP2 and IP3 sprinkler heads required for 2015 10 CFR 50.48 using guidance of NFPA 25 (2002 edition), Section 5.3.1.1.1 before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.
Enhance the Fire Water Program to perform wall thickness evaluations of IP2 and IP3 fire protection piping on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. 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.
Enhance the Fire Water Program to inspect the internal surface of foam based fire suppression tanks.
Acceptance criteria will be enhanced to verify no significant corrosion.

Attachment 1 NL-12-174 Page 7 of 21
#                        COMMITMENT                     IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                  / AUDIT ITEM IP2:           NL-07-039    A.2.1.15 9 Enhance the Flux Thimble Tube Inspection Program September 28,               A.3.1.15 for IP2 and IP3 to implement comparisons to wear 2013                         B.1.16 rates identified in WCAP-12866. Include provisions to compare data to the previous performances and IP3:
perform evaluations regarding change to test December 12, frequency and scope.
2015 Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to specify the acceptance criteria as outlined in WCAP-12866 or other plant-specific values based on evaluation of previous test results.
Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to direct evaluation and performance of corrective actions based on tubes that exceed or are projected to exceed the acceptance criteria. Also stipulate that flux thimble tubes that cannot be inspected over the tube length and cannot be shown by analysis to be satisfactory for continued service, must be removed from service to ensure the integrity of the reactor coolant system pressure boundary.

Attachment 1 NL-12-174 Page 8 of 21
 #                       COMMITMENT                        IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                     / AUDIT ITEM IP2:           NL-07-039    A.2.1.16 10 Enhance the Heat Exchanger Monitoring Program for September 28,               A.3.1.16 IP2 and IP3 to include the following heat exchangers 2013                         B.1.17, in the scope of the program.
NL-07-153   Audit Item x  Safety injection pump lube oil heat exchangers IP3:                            52 December 12, x  RHR heat exchangers 2015 x  RHR pump seal coolers x  Non-regenerative heat exchangers x  Charging pump seal water heat exchangers x  Charging pump fluid drive coolers x  Charging pump crankcase oil coolers x  Spent fuel pit heat exchangers x  Secondary system steam generator sample coolers x  Waste gas compressor heat exchangers x  SBO/Appendix R diesel jacket water heat exchanger (IP2 only)
Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to perform visual inspection on heat exchangers where non-destructive examination, such as eddy current inspection, is not possible due to heat exchanger design limitations.
Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include consideration of material-environment combinations when determining sample population of heat exchangers.
Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to establish minimum tube wall thickness for the new heat exchangers identified in the scope of the program. Establish acceptance criteria for heat exchangers visually inspected to include no indication of tube erosion, vibration wear, corrosion, pitting,                   NL-09-018 fouling, or scaling.
NL-09-056 11 Deleted NL-11-101

Attachment 1 NL-12-174 Page 9 of 21
 #                       COMMITMENT                         IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                      / AUDIT ITEM IP2:           NL-07-039    A.2.1.18 12 Enhance the Masonry Wall Program for IP2 and IP3 September 28,               A.3.1.18 to specify that the IP1 intake structure is included in 2013                         B.1.19 the program.
IP3:
December 12, 2015 Enhance the Metal-Enclosed Bus Inspection Program IP2:                  NL-07-039    A.2.1.19 13 to add IP2 480V bus associated with substation A to September 28,                    A.3.1.19 the scope of bus inspected.                              2013                         B.1.20 NL-07-153 Audit Items Enhance the Metal-Enclosed Bus Inspection Program IP3:                                 124, for IP2 and IP3 to visually inspect the external surface December 12,   NL-08-057 133, 519 of MEB enclosure assemblies for loss of material at      2015 least once every 10 years. The first inspection will occur prior to the period of extended operation and the acceptance criterion will be no significant loss of material.
Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for MEB internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct.
Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections at least once every five years if performed visually or at least once every ten years using quantitative measurements such as thermography or contact resistance measurements. The first inspection will occur prior to the period of extended operation.
The plant will process a change to applicable site procedure to remove the reference to re-torquing connections for phase bus maintenance and bolted connection maintenance.
IP2:           NL-07-039    A.2.1.21 14 Implement the Non-EQ Bolted Cable Connections September 28,               A.3.1.21 Program for IP2 and IP3 as described in LRA Section 2013                         B.1.22 B.1.22.
IP3:
December 12, 2015

Attachment 1 NL-12-174 Page 10 of 21
 #                      COMMITMENT                      IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                  / AUDIT ITEM IP2:           NL-07-039    A.2.1.22 15 Implement the Non-EQ Inaccessible Medium-Voltage September 28,               A.3.1.22 Cable Program for IP2 and IP3 as described in LRA 2013                         B.1.23 Section B.1.23.
NL-07-153   Audit item This new program will be implemented consistent with IP3:                          173 the corresponding program described in NUREG-        December 12,   NL-11-032 1801 Section XI.E3, Inaccessible Medium-Voltage      2015 Cables Not Subject To 10 CFR 50.49 Environmental                    NL-11-096 Qualification Requirements.
NL-11-101 IP2:           NL-07-039    A.2.1.23 16 Implement the Non-EQ Instrumentation Circuits Test September 28,               A.3.1.23 Review Program for IP2 and IP3 as described in LRA 2013                         B.1.24 Section B.1.24.
NL-07-153   Audit item This new program will be implemented consistent with IP3:                          173 the corresponding program described in NUREG-        December 12, 1801 Section XI.E2, Electrical Cables and            2015 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.
IP2:           NL-07-039    A.2.1.24 17 Implement the Non-EQ Insulated Cables and September 28,               A.3.1.24 Connections Program for IP2 and IP3 as described in 2013                         B.1.25 LRA Section B.1.25.
NL-07-153   Audit item This new program will be implemented consistent with IP3:                          173 the corresponding program described in NUREG-        December 12, 1801 Section XI.E1, Electrical Cables and            2015 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

Attachment 1 NL-12-174 Page 11 of 21
 #                        COMMITMENT                       IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                     / AUDIT ITEM IP2:           NL-07-039    A.2.1.25 18 Enhance the Oil Analysis Program for IP2 to sample September 28,               A.3.1.25 and analyze lubricating oil used in the SBO/Appendix 2013           NL-11-101     B.1.26 R diesel generator consistent with the oil analysis for other site diesel generators.
IP3:
Enhance the Oil Analysis Program for IP2 and IP3 to     December 12, sample and analyze generator seal oil and turbine       2015 hydraulic control oil.
Enhance the Oil Analysis Program for IP2 and IP3 to formalize preliminary oil screening for water and particulates and laboratory analyses including defined acceptance criteria for all components included in the scope of this program. The program will specify corrective actions in the event acceptance criteria are not met.
Enhance the Oil Analysis Program for IP2 and IP3 to formalize trending of preliminary oil screening results as well as data provided from independent laboratories.
IP2:           NL-07-039    A.2.1.26 19 Implement the One-Time Inspection Program for IP2 September 28,               A.3.1.26 and IP3 as described in LRA Section B.1.27.
2013                         B.1.27 This new program will be implemented consistent with                   NL-07-153   Audit item the corresponding program described in NUREG-           IP3:                          173 1801, Section XI.M32, One-Time Inspection.              December 12, 2015 IP2:           NL-07-039    A.2.1.27 20 Implement the One-Time Inspection - Small Bore September 28,               A.3.1.27 Piping Program for IP2 and IP3 as described in LRA 2013                         B.1.28 Section B.1.28.
NL-07-153   Audit item This new program will be implemented consistent with IP3:                             173 the corresponding program described in NUREG-           December 12, 1801, Section XI.M35, One-Time Inspection of ASME 2015 Code Class I Small-Bore Piping.
IP2:           NL-07-039    A.2.1.28 21 Enhance the Periodic Surveillance and Preventive September 28,               A.3.1.28 Maintenance Program for IP2 and IP3 as necessary 2013                         B.1.29 to assure that the effects of aging will be managed such that applicable components will continue to IP3:
perform their intended functions consistent with the December 12, current licensing basis through the period of extended 2015 operation.

Attachment 1 NL-12-174 Page 12 of 21
 #                        COMMITMENT                        IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                      / AUDIT ITEM IP2:           NL-07-039    A.2.1.31 22 Enhance the Reactor Vessel Surveillance Program for September 28,               A.3.1.31 IP2 and IP3 revising the specimen capsule withdrawal 2013                         B.1.32 schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected IP3:
through the end of the period of extended operation.
December 12, Enhance the Reactor Vessel Surveillance Program for 2015 IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in storage.
IP2:           NL-07-039    A.2.1.32 23 Implement the Selective Leaching Program for IP2 September 28,               A.3.1.32 and IP3 as described in LRA Section B.1.33.
2013                         B.1.33 This new program will be implemented consistent with                    NL-07-153   Audit item the corresponding program described in NUREG-            IP3:                           173 1801, Section XI.M33 Selective Leaching of Materials. December 12, 2015 IP2:           NL-07-039    A.2.1.34 24 Enhance the Steam Generator Integrity Program for September 28,               A.3.1.34 IP2 and IP3 to require that the results of the condition 2013                         B.1.35 monitoring assessment are compared to the operational assessment performed for the prior IP3:
operating cycle with differences evaluated.
December 12, 2015 Enhance the Structures Monitoring Program to             IP2:           NL-07-039    A.2.1.35 25 explicitly specify that the following structures are     September 28,               A.3.1.35 included in the program.                                 2013                         B.1.36 x Appendix R diesel generator foundation (IP3)                          NL-07-153 x Appendix R diesel generator fuel oil tank vault        IP3:                       Audit items (IP3)                                                December 12,               86, 87, 88, x Appendix R diesel generator switchgear and             2015           NL-08-057       417 enclosure (IP3) x city water storage tank foundation x condensate storage tanks foundation (IP3) x containment access facility and annex (IP3) x discharge canal (IP2/3) x emergency lighting poles and foundations (IP2/3) x fire pumphouse (IP2) x fire protection pumphouse (IP3) x fire water storage tank foundations (IP2/3) x gas turbine 1 fuel storage tank foundation x maintenance and outage building-elevated passageway (IP2)

Attachment 1 NL-12-174 Page 13 of 21
#                        COMMITMENT                       IMPLEMENTATION SOURCE     RELATED SCHEDULE             LRA SECTION
                                                                                  / AUDIT ITEM x   new station security building (IP2) x   nuclear service building (IP1) x   primary water storage tank foundation (IP3) x   refueling water storage tank foundation (IP3) x   security access and office building (IP3) x   service water pipe chase (IP2/3) x   service water valve pit (IP3) x   superheater stack x   transformer/switchyard support structures (IP2) x   waste holdup tank pits (IP2/3)
Enhance the Structures Monitoring Program for IP2 and IP3 to clarify that in addition to structural steel and concrete, the following commodities (including their anchorages) are inspected for each structure as applicable.
x   cable trays and supports x   concrete portion of reactor vessel supports x   conduits and supports x   cranes, rails and girders x   equipment pads and foundations x   fire proofing (pyrocrete) x   HVAC duct supports x   jib cranes x   manholes and duct banks x   manways, hatches and hatch covers x   monorails x   new fuel storage racks x   sumps, sump screens, strainers and flow barriers Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and IP3 will also inspect inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete degradation is occurring.
Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspections of elastomers (seals, gaskets, seismic joint filler, and roof elastomers) to

Attachment 1 NL-12-174 Page 14 of 21
 #                        COMMITMENT                         IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                       / AUDIT ITEM identify cracking and change in material properties and for inspection of aluminum vents and louvers to identify loss of material.
Enhance the Structures Monitoring Program for IP2                       NL-08-127   Audit Item and IP3 to perform an engineering evaluation of                                         360 groundwater samples to assess aggressiveness of groundwater to concrete on a periodic basis (at least once every five years). IPEC will obtain samples from at least 5 wells that are representative of the ground water surrounding below-grade site structures and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides.
Additionally, to assess potential indications of spent fuel pool leakage, IPEC will sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least once every 3 months.
Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support platform of the IP3 intake structure at least once every 5 years.
Enhance the Structures Monitoring Program for IP2                                   Audit Item and IP3 to perform inspection of the degraded areas                                     358 of the water control structure once per 3 years rather than the normal frequency of once per 5 years during the PEO.
Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria                   NL-11-032 for inspections of concrete structures in accordance with ACI 349.3R, Evaluation of Existing Nuclear Safety-Related Concrete Structures prior to the period of extended operation.                                            NL-11-101 IP2:           NL-07-039    A.2.1.36 26  Implement the Thermal Aging Embrittlement of Cast September 28,               A.3.1.36 Austenitic Stainless Steel (CASS) Program for IP2 2013                         B.1.37 and IP3 as described in LRA Section B.1.37.
NL-07-153   Audit item This new program will be implemented consistent with IP3:                              173 the corresponding program described in NUREG-            December 12, 1801, Section XI.M12, Thermal Aging Embrittlement 2015 of Cast Austenitic Stainless Steel (CASS) Program.

Attachment 1 NL-12-174 Page 15 of 21
 #                        COMMITMENT                       IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                     / AUDIT ITEM IP2:           NL-07-039    A.2.1.37 27 Implement the Thermal Aging and Neutron Irradiation September 28,               A.3.1.37 Embrittlement of Cast Austenitic Stainless Steel 2013                         B.1.38 (CASS) Program for IP2 and IP3 as described in LRA NL-07-153   Audit item Section B.1.38.
IP3:                           173 This new program will be implemented consistent with December 12, the corresponding program described in NUREG-           2015 1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.
IP2:           NL-07-039    A.2.1.39 28 Enhance the Water Chemistry Control - Closed September 28,               A.3.1.39 Cooling Water Program to maintain water chemistry of 2013                         B.1.40 the IP2 SBO/Appendix R diesel generator cooling NL-08-057   Audit item system per EPRI guidelines.
IP3:                           509 Enhance the Water Chemistry Control - Closed            December 12, Cooling Water Program to maintain the IP2 and IP3       2015 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines.
IP2:           NL-07-039    A.2.1.40 29 Enhance the Water Chemistry Control - Primary and September 28,                B.1.41 Secondary Program for IP2 to test sulfates monthly in 2013 the RWST with a limit of <150 ppb.
IP2:           NL-07-039    A.2.1.41 30 For aging management of the reactor vessel internals, September 28,               A.3.1.41 IPEC will (1) participate in the industry programs for 2011 investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of IP3:
the industry programs as applicable to the reactor December 12, internals; and (3) upon completion of these programs, 2013 but not less than 24 months before entering the period of extended operation, submit an inspection plan for Complete   NL-11-107 reactor internals to the NRC for review and approval.
IP2:           NL-07-039    A.2.2.1.2 31 Additional P-T curves will be submitted as required September 28,               A.3.2.1.2 per 10 CFR 50, Appendix G prior to the period of 2013                          4.2.3 extended operation as part of the Reactor Vessel Surveillance Program.
IP3:
December 12, 2015 As required by 10 CFR 50.61(b)(4), IP3 will submit a IP3:              NL-07-039    A.3.2.1.4 32 plant-specific safety analysis for plate B2803-3 to the December 12,                  4.2.5 NRC three years prior to reaching the RTPTS             2015           NL-08-127 screening criterion. Alternatively, the site may choose to implement the revised PTS rule when approved.

Attachment 1 NL-12-174 Page 16 of 21
 #                          COMMITMENT                            IMPLEMENTATION    SOURCE      RELATED SCHEDULE                 LRA SECTION
                                                                                              / AUDIT ITEM IP2:             NL-07-039    A.2.2.2.3 33 At least 2 years prior to entering the period of September 28,                 A.3.2.2.3 extended operation, for the locations identified in LRA 2011                            4.3.3 Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), under NL-07-153   Audit item the Fatigue Monitoring Program, IP2 and IP3 will IP3:                             146 implement one or more of the following:
December 12,     NL-08-021 (1) Consistent with the Fatigue Monitoring Program,            2013 Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting                 Complete     NL-10-082 for the effects of reactor water environment. This includes applying the appropriate Fen factors to valid CUFs determined in accordance with one of the following:
: 1. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue analysis valid for the period of extended operation, use the existing CUF.
: 2. Additional plant-specific locations with a valid CUF may be evaluated. In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component.
: 3. Representative CUF values from other plants, adjusted to or enveloping the IPEC plant specific external loads may be used if demonstrated applicable to IPEC.
: 4. An analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case) may be performed to determine a valid CUF.
(2) Consistent with the Fatigue Monitoring Program, Corrective Actions, repair or replace the affected locations before exceeding a CUF of 1.0.
April 30, 2008 NL-07-078    2.1.1.3.5 34 IP2 SBO / Appendix R diesel generator will be installed and operational by April 30, 2008. This Complete     NL-08-074 committed change to the facility meets the requirements of 10 CFR 50.59(c)(1) and, therefore, a NL-11-101 license amendment pursuant to 10 CFR 50.90 is not required.

Attachment 1 NL-12-174 Page 17 of 21
 #                        COMMITMENT                         IMPLEMENTATION  SOURCE      RELATED SCHEDULE               LRA SECTION
                                                                                       / AUDIT ITEM IP2:           NL-08-127   Audit Item 35 Perform a one-time inspection of representative September 28,                  27 sample area of IP2 containment liner affected by the 2013 1973 event behind the insulation, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area.
NL-11-101 Perform a one-time inspection of representative           IP3:
sample area of the IP3 containment steel liner at the     December 12, juncture with the concrete floor slab, prior to entering  2015 the period of extended operation, to assure liner degradation is not occurring in this area.
Any degradation will be evaluated for updating of the                    NL-09-018 containment liner analyses as needed.
IP2:           NL-08-127   Audit Item 36 Perform a one-time inspection and evaluation of a September 28,  NL-11-101      359 sample of potentially affected IP2 refueling cavity 2013 concrete prior to the period of extended operation.
The sample will be obtained by core boring the refueling cavity wall in an area that is susceptible to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel.
Additional core bore samples will be taken, if the                       NL-09-056 leakage is not stopped, prior to the end of the first ten years of the period of extended operation.
A sample of leakage fluid will be analyzed to                            NL-09-079 determine the composition of the fluid. If additional core samples are taken prior to the end of the first ten years of the period of extended operation, a sample of leakage fluid will be analyzed.
IP2:           NL-08-127   Audit Item 37 Enhance the Containment Inservice Inspection (CII-September 28,                 361 IWL) Program to include inspections of the 2013 containment using enhanced characterization of degradation (i.e., quantifying the dimensions of noted IP3:
indications through the use of optical aids) during the December 12, period of extended operation. The enhancement 2015 includes obtaining critical dimensional data of degradation where possible through direct measurement or the use of scaling technologies for photographs, and the use of consistent vantage points for visual inspections.

Attachment 1 NL-12-174 Page 18 of 21
 #                       COMMITMENT                         IMPLEMENTATION    SOURCE      RELATED SCHEDULE                LRA SECTION
                                                                                        / AUDIT ITEM IP2:             NL-08-143      4.2.1 38 For Reactor Vessel Fluence, should future core September 28, loading patterns invalidate the basis for the projected 2013 values of RTpts or CVUSE, updated calculations will be provided to the NRC.
IP3:
December 12, 2015 NL-09-079 39 Deleted IP2:             NL-09-106      B.1.6 40 Evaluate plant specific and appropriate industry September 28,                  B.1.22 operating experience and incorporate lessons learned 2013                           B.1.23 in establishing appropriate monitoring and inspection B.1.24 frequencies to assess aging effects for the new aging IP3:                           B.1.25 management programs. Documentation of the December 12,                   B.1.27 operating experience evaluated for each new program 2015                           B.1.28 will be available on site for NRC review prior to the B.1.33 period of extended operation.
B.1.37 B.1.38 IP2:             NL-11-032       N/A 41 IPEC will inspect steam generators for both units to After the assess the condition of the divider plate assembly.
beginning of the The examination technique used will be capable of PEO and prior to detecting PWSCC in the steam generator divider plate September 28, assembly. The IP2 steam generator divider plate 2023             NL-11-074 inspections will be completed within the first ten years of the period of extended operation (PEO). The IP3 IP3:             NL-11-090 steam generator divider plate inspections will be Prior to the end completed within the first refueling outage following of the first     NL-11-101 the beginning of the PEO.
refueling outage following the beginning of the PEO.

Attachment 1 NL-12-174 Page 19 of 21
 #                        COMMITMENT                       IMPLEMENTATION     SOURCE      RELATED SCHEDULE                 LRA SECTION
                                                                                        / AUDIT ITEM NL-11-032      N/A 42 IPEC will develop a plan for each unit to address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options.
Option 1 (Analysis)
IPEC will perform an analytical evaluation of the IP2:              NL-11-074 steam generator tube-to-tubesheet welds in order to establish a technical basis for either determining that Prior to March the tubesheet cladding and welds are not susceptible    2024              NL-11-090 to PWSCC, or redefining the pressure boundary in        IP3: Prior to the end of the first  NL-11-096 which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor    refueling outage coolant pressure boundary function. The redefinition    following the beginning of the of the reactor coolant pressure boundary must be approved by the NRC as a license amendment              PEO.
request.
Option 2 (Inspection)                                   IP2:
Between March IPEC will perform a one-time inspection of a            2020 and March representative number of tube-to-tubesheet welds in     2024 each steam generator to determine if PWSCC cracking is present. If weld cracking is identified:    IP3: Prior to the
: a. The condition will be resolved through repair    end of the first or engineering evaluation to justify continued  refueling outage service, as appropriate, and                    following the beginning of the
: b. An ongoing monitoring program will be            PEO.
established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators.

Attachment 1 NL-12-174 Page 20 of 21
 #                        COMMITMENT                        IMPLEMENTATION  SOURCE      RELATED SCHEDULE              LRA SECTION
                                                                                      / AUDIT ITEM IP2:           NL-11-032      4.3.3 43 IPEC will review design basis ASME Code Class 1 Prior to fatigue evaluations to determine whether the September 28, NUREG/CR-6260 locations that have been evaluated 2013 for the effects of the reactor coolant environment on NL-11-101 fatigue usage are the limiting locations for the IP2 and IP3: Prior to IP3 configurations. If more limiting locations are December 12, identified, the most limiting location will be evaluated 2015 for the effects of the reactor coolant environment on fatigue usage.
IPEC will use the NUREG/CR-6909 methodology in the evaluation of the limiting locations consisting of nickel alloy, if any.
IP2:           NL-11-032       N/A 44 IPEC will include written explanation and justification Prior to of any user intervention in future evaluations using the September 28,  NL-11-101 WESTEMS Design CUF module.
2013 IP3: Prior to December 12, 2015 IP2:           NL-11-032       N/A 45 IPEC will not use the NB-3600 option of the Prior to WESTEMS program in future design calculations until September 28,  NL-11-101 the issues identified during the NRC review of the 2013 program have been resolved.
IP3: Prior to December 12, 2015 IP2:           NL-11-032       N/A 46 Include in the IP2 ISI Program that IPEC will perform Prior to twenty-five volumetric weld metal inspections of September 28,  NL-11-074 socket welds during each 10-year ISI interval 2013 scheduled as specified by IWB-2412 of the ASME Section XI Code during the period of extended operation.
In lieu of volumetric examinations, destructive examinations may be performed, where one destructive examination may be substituted for two volumetric examinations.

Attachment 1 NL-12-174 Page 21 of 21
 #                        COMMITMENT                       IMPLEMENTATION  SOURCE      RELATED SCHEDULE              LRA SECTION
                                                                                     / AUDIT ITEM IP2:           NL-12-089      N/A 47 IPEC will perform and submit analyses that Prior to demonstrate that the lower support column bodies will September 28, maintain their functionality during the period of 2013 extended operation considering the possible loss of fracture toughness due to thermal and irradiation IP3: Prior to embrittlement. The analyses will be consistent with December 12, the IP2/IP3 licensing basis.
2015 Entergy will visually inspect IPEC underground piping   IP2:           NL-12-174      N/A 48 within the scope of license renewal and subject to      Prior to aging management review prior to the period of          September 28, extended operation and then on a frequency of at        2013 least once every two years during the period of extended operation. This inspection frequency will be   IP3: Prior to maintained unless the piping is subsequently coated     December 12, in accordance with the preventive actions specified in  2015 NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

ATTACHMENT 2 TO NL-12-174 CHANGES TO THE INDIAN POINT LRA UPDATED FINAL SAFETY ANALYSIS REPORT SUPPLEMENT (APPENDIX A)
AND AGING MANAGEMENT PROGRAMS AND ACTIVITIES (APPENDIX B)
ENTERGY NUCLEAR OPERATIONS, INC.
INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

Attachment 2 NL-12-174 Page 1 of 4 INDIAN POINT NUCLEAR GENERATING UNIT NO. 2 CHANGES TO THE INDIAN POINT LRA UPDATED FINAL SAFETY ANALYSIS REPORT SUPPLEMENT (APPENDIX A)
The LRA is revised as described below (underline - added)
A.2.1.5      Buried Piping and Tanks Inspection Program The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried and underground carbon steel, gray cast iron, and stainless steel components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.
IP2 will perform 20 direct visual inspections of buried piping during the 10 year period prior the PEO. IP2 will perform 14 direct visual inspections during each 10-year period of the PEO. Soil samples will be taken prior to the PEO and at least once every 10 years in the PEO. Soil will be tested at a minimum of two locations at least three feet below the surface near in-scope piping to determine representative soil conditions for each system. If test results indicate the soil is corrosive then the number of piping inspections will be increased to 20 during each 10-year period of the PEO.
The Buried Piping and Tanks Inspection Program will be implemented prior to the period of extended operation. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection with the following modification.
The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. The program will classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Corrosion risk will be determined through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Inspection priority and frequency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.
Inspections will be performed using qualified inspection techniques with demonstrated effectiveness. Inspections will begin prior to the period of extended operation. Underground piping within the scope of license renewal and subject to aging management review will be visually inspected prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation. This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

Attachment 2 NL-12-174 Page 2 of 4 INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 CHANGES TO THE INDIAN POINT LRA UPDATED FINAL SAFETY ANALYSIS REPORT SUPPLEMENT (APPENDIX A)
The LRA is revised as described below (underline - added)
A.3.1.5      Buried Piping and Tanks Inspection Program The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried and underground carbon steel, gray cast iron, copper alloy and stainless steel components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.
IP3 will perform 14 direct visual inspections of buried piping during the 10 year period prior the PEO. IP3 will perform 16 direct visual inspections during each 10-year period of the PEO. Soil samples will be taken prior to the PEO and at least once every 10 years into the PEO. Soil will be tested at a minimum of two locations at least three feet below the surface near in-scope piping to determine representative soil conditions for each system. If test results indicate the soil is corrosive then the number of piping inspections will be increased to 22 during each 10-year period of the PEO.
The Buried Piping and Tanks Inspection Program will be implemented prior to the period of extended operation. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection with the following modification.
The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. The program will classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Corrosion risk will be determined through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Inspection priority and frequency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.
Inspections will be performed using qualified inspection techniques with demonstrated effectiveness, Inspections will begin prior to the period of extended operation. Underground piping within the scope of license renewal and subject to aging management review will be visually inspected prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation. This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

Attachment 2 NL-12-174 Page 3 of 4 INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 CHANGES TO THE INDIAN POINT LRA AGING MANAGEMENT PROGRAMS AND ACTIVITIES (APPENDIX B)
The LRA is revised as described below (underline - added)
B.1.6      BURIED PIPING AND TANKS INSPECTION Program Description The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried and underground carbon steel, gray cast iron, copper alloy and stainless steel components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement. The program applies to buried components in the following systems.
* Safety injection
* Service water
* Fire protection
* Fuel oil
* Security generator
* City water
* Plant drains
* Auxiliary feedwater
* Containment isolation support
* River water service (IP1)
* Circulating Water System (IP2)
Of these systems, only the safety injection system contains radioactive fluids during normal operations. The safety injection system buried components are stainless steel. Stainless steel is used in the safety injection system for its corrosion resistance. This program also applies to underground components in the IP3 service water and city water systems and the IP2 and IP3 fuel oil systems.
The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping tank or tank leakage and of conditions affecting the risk for corrosion. The program will classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard dosed by fluid contained in the piping and the impact of leakage on reliable plant operation. Corrosion

Attachment 2 NL-12-174 Page 4 of 4 risk will be determined through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Inspection priority and frequency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.
Inspections will be performed using qualified inspection techniques with demonstrated effectiveness. Inspections will begin prior to the period of extended operation.
Prior to entering the period of extended operation, plant operating experience will be reviewed and multiple inspections will be completed within the past ten years. Additional periodic inspections will be performed within the first ten years of the period of extended operation.
Underground piping within the scope of license renewal and subject to aging management review will be visually inspected prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation. This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).
The program will be implemented prior to the period of extended operation.}}