NUREG-1930, Supplement 1

Safety Evaluation Report

Related to the License Renewal of Indian Point 

Nuclear Generating Unit Nos. 2 and 3

Supplement 1

Docket Nos. 50-247 and 50-286

Entergy Nuclear Operations, Inc.

United States Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

August 2011
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ABSTRACT

This document is a supplemental safety evaluation report (SSER) for the license renewal

application for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) as filed by 

Entergy Nuclear Operations, Inc., (Entergy or the applicant). By letter dated April 23, 2007, and 

as supplemented by letters dated May 3 and June 21, 2007, the applicant submitted the LRA in 

accordance with Title 10, Part 54, of the Code of Federal Regulations, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants.” Entergy requests renewal of the IP2 

and IP3 operating licenses (Facility Operating License Numbers DPR-26 and DPR-64, 

respectively) for a period of 20 years beyond the current expirations at midnight on 

September 28, 2013, for IP2, and at midnight on December 12, 2015, for IP3.

The NRC staff published NUREG-1930 “Safety Evaluation Report Related to the License 

Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3” in two volumes in

November 2009, which summarized the results of its safety review of the renewal application for

compliance with the requirements of Title 10, Part 54, of the Code of Federal Regulations, (10 

CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." 

This SSER documents the staff’s review of supplemental information provided by the applicant 

since the issuance of the SER. This information includes annual updates required by 10 CFR 

54.21(b), and updated information and commitments in response to staff requests for additional 

information. This document only discusses the changes to the SER.
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TABLE OF CONTENTS

ABSTRACT................................................................................................................................iii

SECTION 1 INTRODUCTION AND GENERAL DISCUSSION............................................... 1-1

1.1 Introduction................................................................................................................. 1-1

SECTION 2 STRUCTURES SYSTEMS AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW ....................................................................................................... 2-1

SECTION 3 AGING MANAGEMENT REVIEW RESULTS ..................................................... 3-1

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report ................................... 3-1

3.0.3 Aging Management Programs................................................................................ 3-1

3.0.3.1 AMPs Consistent with the GALL Report........................................................ 3-1

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions and/or Enhancements

................................................................................................................................ 3-13

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report ............... 3-14

3.0.5 Operating Experience for Aging Management Programs ..................................... 3-15

3.0.5.1 Summary of Technical Information in the Application .................................. 3-15

3.0.5.2 Staff Evaluation ........................................................................................... 3-16

3.0.5.3 UFSAR Supplement.................................................................................... 3-17

3.0.5.4 Conclusion .................................................................................................. 3-17

3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant Systems...... 3-17

3.1.2 Staff Evaluation.................................................................................................... 3-17

3.1.2.1 AMR Results Consistent with the GALL Report........................................... 3-17

3.1.2.2 AMR Results Consistent with the GALL Report for which Further Evaluation is 

Recommended......................................................................................................... 3-19

3.2 Aging Management of Engineered Safety Features Systems ................................... 3-23

3.2.2 Staff Evaluation................................................................................................... 3-23

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ... 3-23

3.3 Aging Management of Auxiliary Systems.................................................................. 3-23

3.3.2 Staff Evaluation................................................................................................... 3-23

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ... 3-24

SECTION 4 TIME LIMITED AGING ANALYSIS.................................................................... 4-1

4.3 Metal Fatigue Analyses............................................................................................... 4-1

4.3.3 Effects of Reactor Water Environment on Fatigue Life.......................................... 4-1

4.3.3.1 Summary of Techical Information in the Application ..................................... 4-1

4.3.3.2 Staff Evaluation ............................................................................................ 4-1

4.3.3.1 UFSAR Supplement..................................................................................... 4-3

4.3.3.4 Conclusion ................................................................................................... 4-3

SECTION 5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS ... 5-1

SECTION 6 CONCLUSION .................................................................................................. 6-1
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Appendices

Appendix A: List of Commitments .........................................................................................A-1

Appendix B: Chronology ........................................................................................................B-1
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ABBREVIATIONS 

vii

ACI American Concrete Institute

ADAMS Agencywide Documents Access and Management System

AMP aging management program

AMR aging management review

ASME American Society of Mechanical Engineers

AWWA American Water Works Association

CAP corrective action program

CASS cast austenitic stainless steel

CLB current licensing basis

CFR Code of Federal Regulations

CUF cumulative usage factor

EPRI Electric Power Research Institute

EQ environmental qualification

Fen environmental fatigue life correction factor

GALL Generic Aging Lessons Learned

GL Generic Letter

IPEC Indian Point Energy Center

IP2 and IP3 Indian Point Nuclear Generating Unit Nos. 2 and 3

ISI inservice inspection

kV kilovolts

LER licensee event report

LRA license renewal application

LWR light water reactor

MRP Materials Reliability Program

NRC Nuclear Regulatory Commission

OEP operating experience program

PEO period of extended operation

PVC polyvinyl chloride

PWSCC primary water stress corrosion cracking

QA Quality Assurance
ABBREVIATIONS 

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RAI request for additional information

RCPB reactor coolant pressure boundary

RIS Regulatory Information Summary

SCC stress corrosion cracking

SCs Structures and Components

SER safety evaluation report

SG steam generator

SGMP steam generator management program

SRP-LR Standard Review Plan for License Renewal Applications for Nuclear 

Power Plants

SSCs systems, structures and components

SSER supplemental safety evaluation report

UFSAR updated final safety analysis report

USAS United States of America Standard

V volts
1-1

SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

This document is a supplemental safety evaluation report (SSER) for the license renewal

application (LRA) for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) as filed 

by Entergy Nuclear Operations, Inc., (Entergy or the applicant). By letter dated April 23, 2007, 

and as supplemented by letters dated May 3 and June 21, 2007, the applicant submitted the 

LRA in accordance with Title 10, Part 54, of the Code of Federal Regulations, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants.” Entergy requests renewal of the IP2 

and IP3 operating licenses (Facility Operating License Numbers DPR-26 and DPR-64, 

respectively) for a period of 20 years beyond the current expirations at midnight on 

September 28, 2013, for IP2, and at midnight on December 12, 2015, for IP3.

The NRC staff published NUREG-1930 “Safety Evaluation Report Related to the License 

Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3” in two volumes in

November 2009, which summarized the results of its safety review of the renewal application for

compliance with the requirements of Title 10, Part 54, of the Code of Federal Regulations, (10 

CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." 

This SSER documents the staff’s review of supplemental information provided by the applicant 

since the issuance of the SER. This information includes annual updates required by 10 CFR 

54.21(b), and updated information and commitments in response to staff requests for additional 

information (RAIs). This SSER supplements portions of SER Sections 3, 4, 5, Appendix A, and 

Appendix B.
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SECTION 2

STRUCTURES SYSTEMS AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW

There are no changes or updates to this section of the safety evaluation report.
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SECTION 3

AGING MANAGEMENT REVIEW RESULTS

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report

3.0.3 Aging Management Programs

3.0.3.1 AMPs Consistent with the GALL Report

3.0.3.1.2 Buried Piping and Tanks Inspection Program

Summary of Technical Information in the Application. By letters dated March 28, July 14, and 

July 21, 2011, the applicant supplemented the LRA to include revisions to the Buried Piping and 

Tanks Inspection Program. The applicant revised the number of planned inspections of buried 

piping within the scope of license renewal from 45 (a non-specific mix of direct and indirect 

inspections) in the 10-year period prior to the period of extended operation to 31 direct 

inspections of steel piping, 3 direct inspections of stainless steel piping, and 17 indirect 

inspections in the 10-year period prior to the period of extended operation. The applicant also 

revised the number of inspections to be conducted in the period of extended operation from a 

non-specific total in the first 10 years of the period of extended operation based on the results of 

inspections to be completed prior to the period of extended operation to 28 direct inspections of 

steel piping and two direct inspections of stainless steel piping in each 10-year period of the 

period of extended operation. The applicant stated that until such time that an alternative 

inspection methodology is qualified and demonstrated to be effective, it will not use alternate 

inspection methods to inspect buried piping within the scope of license renewal for the stated 

minimum number of inspections. The staff noted that based on this response, the applicant will 

not use the guided wave method in lieu of excavated direct visual inspection of buried piping

within the scope of license renewal.

Staff Evaluation. In light of operating experience that has occurred coincident with and after the 

staff’s initial evaluation of the Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) 

license renewal application (LRA) and issuance of the SER, the staff reviewed the LRA and 

SER and determined that additional information was required to evaluate how the applicant is 

implementing changes to its program based on more recent industry experience. By letter 

dated February 10, 2011 the staff issued request for additional information (RAI) 3.0.3.1.2-1 

requesting that the applicant:

a) state how many buried piping segments are within the scope of license renewal for 

each material; how many are code and/or safety-related; and, how many with the 

potential to release materials detrimental to the environment, will be inspected

b) confirm which systems have cathodic protection, whether periodic NACE surveys are 

conducted, and the availability of the cathodic protection system

c) state why piping that is not cathodically protected will meet the minimum design wall 

thickness throughout the period of extended operation
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d) provide details on buried pipe inspections that have been conducted since July 2009 

that provide insights on the quality of backfill in the vicinity of buried pipes

e) state what alternative inspection methods will be used in lieu of direct visual inspection 

of buried pipe

f) state what systems have underground piping (i.e., piping and tanks that are below 

grade, contained in a vault or tunnel, in contact with air, and where access for 

inspection is restricted)

g) state what soil parameters will be included in soil corrosivity testing, how often, and in 

what locations sampling will be conducted; and how localized soil conditions will be 

factored into the number of inspections of buried piping with the scope of license 

renewal.

In its response dated March 28, 2011, the applicant stated that:

a) The following excavated direct visual inspections will be conducted on buried piping

within the scope of license renewal:

• at IP2, at least nine locations of code or safety-related steel piping and 11

locations of steel piping containing hazardous materials will be inspected in the 

10-year period prior to the period of extended operation,

• at IP3, at least eight locations of code or safety-related steel piping, three 

locations of steel piping containing hazardous materials, and three locations of 

stainless steel piping containing hazardous materials will be inspected in the 

10-year period prior to the period of extended operation,

• in summary, prior to the period of extended operation, there will be 31 

inspections of steel piping and three inspections of stainless steel piping

• at IP2, at least six locations of code or safety-related steel piping and eight 

locations of steel piping containing hazardous materials will be inspected each 

10-year period during the period of extended operation,

• at IP3, at least six locations of code or safety-related steel piping, eight locations 

of steel piping containing hazardous materials, and two locations of stainless 

steel piping containing hazardous materials will be inspected each 10-year period 

during the period of extended operation,

• In summary, during each 10-year period during the period of extended operation, 

there will be 28 inspections of steel piping and two inspections of stainless steel 

piping,

• with the exception of ten inspections that have already been conducted, each 

excavated direct visual examination inspection will consist of a minimum of 10

linear feet of pipe for the full circumference. The 10 inspections conducted to 
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date ranged from five feet to more than ten feet with an average of eight linear 

feet,

• the non safety-related security generator buried propane tank and steel piping 

will be age managed by monitoring the level of the propane in the tank; however, 

opportunistic inspections of the tank will be performed.

b) The buried city water piping in the vicinity of the Algonquin gas pipelines is the only 

buried piping within the scope of license renewal that is cathodically protected. Annual 

NACE surveys are conducted. Cathodic protection availability since installation in 

November 2009 has exceeded 98 percent.

c) The applicant stated that there is reasonable assurance that buried piping within the 

scope of license renewal will continue to meet its design function without cathodic

protection because: (1) recent inspections have found the piping’s coating to be in good 

condition, (2) soil resistivity measurements have shown the soil to be non-aggressive, 

(3) risk ranking of inspection locations has been and will be used to identify those areas 

most susceptible to corrosion, (4) further soil samples will be obtained with the number 

of inspections being increased if the soil is corrosive, and (5) an adequate number of 

inspections have been conducted to date and are planned.

d) Two 10-foot sections of 16-inch pipe and an eight foot section of 10-inch city water 

piping were inspected in October 2009. Eight feet of fire protection piping was inspected 

in November 2009. The backfill did not contain rocks or foreign material that would 

damage external coatings. The coatings were found to be in good condition.

e) It has no plans to use volumetric inspection methods in lieu of direct visual examination 

of buried pipe. In the absence of a qualified method and until such time that one is 

demonstrated to be effective, it will not use alternate inspection methods.

f) It has no underground piping or tanks (i.e., piping and tanks below grade, contained in a 

vault or tunnel, in contact with air, where access for inspection is restricted) within the 

scope of license renewal.

g) Both soil resistivity and American Water Works Association (AWWA) C105 rating factors 

will be used to determine soil corrosivity. Soil parameters utilized in the AWWA C105 

rating are resistivity, pH, redox potential, sulfides, and moisture. If soil resistivity is less 

than 20,000 ohm-cm or the AWWA C105 rating exceeds 10, the soil will be considered 

corrosive. Soil samples will be taken prior to the period of extended operation and at 

least once every 10 years in the period of extended operation. Soil samples will be 

taken at a minimum of two locations near buried piping within the scope of license 

renewal to obtain representative soil conditions for each system. The number of 

inspections of steel code or safety-related piping will be increased from six to eight 

inspections and for steel piping containing hazardous materials from eight to 12 if the 

soil is corrosive.

The staff finds the applicant’s response to RAI 3.0.3.1.2-1, items (b), (c), (d), (e), (f), and (g) 

acceptable. Although the service water, containment isolation support, auxiliary feedwater, 
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plant drains, fuel oil, security diesel propane, and fire protection systems are not cathodically 

protected, the applicant’s response is acceptable in that:

• The applicant is risk informing its piping inspection locations to select those with the 

greatest potential for leakage.

• The applicant is sampling the soil for corrosivity prior to and during the period of 

extended operation, using standard industry methodologies to determine soil corrosivity, 

and will be increasing the number of inspections if the soil is corrosive.

• Steel piping is coated.

• Recent inspections found that the backfill did not contain rocks or foreign material that 

would damage external coatings and the coatings were found to be in good condition. 

The staff noted that foreign material in backfill caused sufficient damage of the 

condensate storage tank return line coating such that the line corroded and leaked, and 

in other instances inspections found coating damage; however, the applicant’s proposed 

number of inspections meet the current staff position for number of inspections for a 

plant with no cathodic protection and unacceptable backfill quality.

The staff finds that the applicant is conducting a sufficient number of inspections to establish a 

reasonable basis for the staff to conclude that the current licensing basis (CLB) function(s) of 

the buried systems within the scope of license renewal will be maintained throughout the period 

of extended operation. The staff noted that the applicant will not use alternative inspection 

methodologies unless they are qualified and demonstrated to be effective. The staff also noted 

that the applicant has no underground piping or tanks (i.e., piping and tanks below grade, 

contained in a vault or tunnel, in contact with air, where access for inspection is restricted) within 

the scope of license renewal.

The staff’s concern described in item (a) of RAI 3.0.3.1.2-1 was not resolved because the 

applicant proposed to manage the effects of aging for the buried propane piping and tanks by 

monitoring tank level. The license renewal function of these components is to provide a 

pressure boundary function for the tanks and piping to support a 10 CFR Part 50 Appendix R 

event. By letter dated June 15, 2011, the staff issued RAI 3.0.3.1.2-2 requesting that the 

applicant state the basis for why monitoring propane tank level ensures that the license renewal 

function of the tank and piping is met.

In its response dated July 14, 2011, the applicant stated that: there are two propane tanks and 

50 feet of piping that supply fuel to one engine that supports fire protection and 10 CFR Part 50 

Appendix R lighting requirements; the tanks and piping are not safety-related and do not contain 

hazardous materials; the piping and tanks are constructed of the same material, coated, and 

exposed to similar soil conditions as the other buried steel piping within the scope of license 

renewal which will have multiple direct visual inspections as described above; observation of 

tank levels allows personnel to initiate corrective actions to repair or replace a leaking tank; and

monitoring of propane tank level is similar to the recommendation in NUREG-1801, “Generic 

Aging Lessons Learned (GALL) Report,” Revision 2 which allows monitoring of jockey pump 

operation to age manage buried fire system piping within the scope of license renewal. 
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The staff finds the applicant’s response acceptable because the applicant’s 31 direct visual 

inspections of buried steel piping prior to the period of extended operation and 28 during each of 

the 10-year periods in the period of extended operation, coupled with the buried propane tanks 

and piping being constructed of similar material and exposed to a similar environment, will 

establish objective evidence of the condition of the buried propane piping and tanks. The staff’s 

concern described in RAI 3.0.3.1.2-2 is resolved.

Based on its review of the applicant’s response to RAI 3.0.3.1.2-1 and RAI 3.0.3.1.2-2, the staff 

finds that operating experience related to the applicant’s program demonstrates that it can 

adequately manage the detrimental effects of aging on systems, structures and components 

(SSCs) within the scope of the program, and implementation of the program will result in the 

applicant taking appropriate corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criteria in NUREG-1800, Revision 1, “Standard 

Review Plan for Review of License Renewal Applications for Nuclear Power Plants” (SRP-LR)

Section A.1.2.3.10 and, therefore, the staff finds it acceptable.

Operating Experience. There are no changes or updates to this section of the SER.

Updated Final Safety Analysis Report (UFSAR) Supplement. The staff noted that the applicant 

had not updated UFSAR Sections A.2.1.5 and A.3.1.5, as required by 10 CFR 54.21(d), to 

reflect the response to RAI 3.0.3.1.2-1 in regard to the number and frequency of piping 

inspections and soil testing. Therefore, by letter dated June 15, 2011, the staff issued RAI 

3.0.3.1.2-3 requesting that the applicant revise the UFSAR supplement to reflect the number 

and frequency of inspections and soil testing planned for all buried pipe within the scope of 

license renewal.

In its response dated July 14, 2011, and amended by letter dated July 27, 2011, the applicant 

revised LRA Sections A.2.1.5 and A.3.1.5 to reflect the number and frequency of piping 

inspections and soil testing.

The staff finds the applicant’s response acceptable because the UFSAR supplement 

establishes the number and frequency of piping inspections and soil testing licensing basis for 

the program. The staff’s concern described in RAI 3.0.3.1.2-3 is resolved.

Conclusion On the basis of its review of the applicant's response to RAIs 3.0.3.1.2-1, 

3.0.3.1.2-2, and 3.0.3.1.2-3, the staff finds that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.1.6 Non-EQ Inaccessible Medium-Voltage Cable Program

Summary of Technical Information in the Application. LRA Section B.1.23 as modified by letters 

dated March 28, 2011 and July 7, 2011, describes the Non-EQ (environmental qualification)

Inaccessible Medium-Voltage Cable Program as a new program that will be consistent with the 
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GALL Report aging management program (AMP) XI.E3, "Inaccessible Medium-Voltage Cables 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." 

The applicant stated that the Non-EQ Inaccessible Medium-Voltage Cable Program includes 

periodic inspections for water collection in cable manholes, and provides for the testing of

cables. In-scope medium-voltage cables (i.e., cables with operating voltage from 400 volts (V)

to 35 kilovolts (kV)) exposed to significant moisture will be tested at least every 6 years for an 

indication of the condition of the conductor insulation. The program inspects for water 

accumulation in manholes at least annually.

Staff Evaluation. The staff’s evaluation of the applicant’s Non-EQ Inaccessible Medium-Voltage 

Cable Program is documented in SER Section 3.0.3.1.6. Subsequent to issuance of the SER, 

the staff issued RAI 3.0.3.1.6-1 requesting that the applicant respond to the following to address 

recent industry operating experience with inaccessible low and medium voltage power cables:

1. Explain how Entergy Nuclear Operations, Inc., (Entergy) will manage the effects of aging 

on inaccessible low voltage power cables within the scope of license renewal and 

subject to aging management review, including consideration of recently identified 

industry operating experience and any plant-specific operating experience. The 

discussion should include assessment of the aging management program description, 

program elements (i.e., scope of program, parameters monitored/inspected, detection of 

aging effects, and corrective actions), and an UFSAR summary description to 

demonstrate reasonable assurance that the intended functions of inaccessible low 

voltage power cables subject to adverse localized environments will be maintained 

consistent with the current licensing basis through the period of extended operation.

2. Provide an evaluation showing that the proposed Non-EQ Inaccessible Medium-Voltage 

Cable Program test and inspection frequencies, including event-driven inspections, 

incorporate recent industry and plant-specific operating experience for both inaccessible 

low and medium voltage cables.

3. In Commitment 40, Entergy committed to evaluate plant-specific and industry operating 

experience prior to entering the period of extended operation. Explain how the proposed 

Non-EQ Inaccessible Medium-Voltage Cable Program will continue to ensure that future 

industry and plant-specific operating experience will be incorporated into the program 

such that inspection and test frequencies may be increased based on test and 

inspection results. 

By letters dated March 28, 2011, and July 7, 2011, the applicant provided a supplement to the 

license renewal application including the management of inaccessible low voltage power cables. 

The applicant stated that it will include low-voltage power cables (400V to 2kV) in the Non-EQ

Inaccessible Medium-Voltage Cable Program. In addition, the applicant stated that the Non-EQ

Inaccessible Medium-Voltage Cable Program will include provisions to increase cable testing 

and manhole inspections frequencies, including adjusting frequencies based on the results of 

testing and inspections. 

Specifically, the applicant stated that the Non-EQ Inaccessible Medium-Voltage Cable Program 

will be based on and consistent with GALL AMP. XI.E3, “Inaccessible Medium-Voltage Cables 
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Not Subject to 10 CFR 50.49 Environmental Qualification Requirements” with the following 

enhancements described in LRA Sections B.1.23, A.2.1.22 and A.3.1.22:

• The significant voltage exposure definition (applicable to medium voltage cable (2kV to 

35kV) subjected to system voltage for more than 25 percent of the time) is removed as a 

scope of program criterion. 

• The Non-EQ Inaccessible Medium-Voltage Cable Program is expanded to include 400V 

to 2kV in-scope inaccessible low voltage power cable.

• The performance of manhole inspections is increased to at least annually.

• The testing of inaccessible cables (400V to 35kV) for degradation of cable insulation will 

be performed at least once every six years.

• Event driven inspections (e.g. heavy rain or flooding), are incorporated into the Non-EQ 

Inaccessible Medium-Voltage Cable Program.

• Cable test results include reviews to determine the need for more frequent testing.

• Manhole inspection results are evaluated to determine the need for more frequent 

manhole inspections.

The applicant also provided more recent plant operating experience stating that the applicant’s

response to Generic Letter (GL) 2007-01 “Inaccessible or Underground Power Cable Failures 

that Disable Accident Mitigation Systems or Cause Plant Transients” described that IP3 had 

experienced two cable failures, and IP2 had experienced no failures based on the scoping 

criteria set forth in GL 2007-01. The applicant explained that both IP3 failures involved lowvoltage power cables but the failures were due to mechanical damage and not aging. The 

applicant also stated that a review of plant operating experience since the applicant’s response 

to GL 2007-01 identified one IP2 failure and no IP3 failures of low or medium voltage power 

cables within scope of the maintenance rule or license renewal. The applicant further stated 

that the cable failure identified for IP2 was caused during modification activities and was not 

aging related.

With the information provided by the applicant’s RAI response, the staff finds the applicant’s 

Non-EQ Inaccessible Medium-Voltage Cable Program acceptable with respect to inaccessible 

low voltage power cable because the applicant has included inaccessible low voltage power 

cables (400v to 2kV) within the scope of this program consistent with industry and plant-specific 

operating experience such that there is reasonable assurance that inaccessible low voltage 

power cables subject to significant moisture will be adequately managed during the period of 

extended operation. The applicant also revised cable testing frequencies to once every 6 years 

and manhole inspections to at least annually with added event-driven inspections for in-scope 

manholes. The applicant’s incorporation of increased testing and inspection frequencies and 

event driven inspections into the Non-EQ Inaccessible Medium-Voltage Cable Program is 

acceptable because the changes are also consistent with industry operating experience. The 

elimination of the significant voltage criterion definition (subjected to system voltage for more 

than 25 percent of the time) is also acceptable because this change expands the scope of the 
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program consistent with inaccessible medium voltage cable operating experience. The 

applicant also revised the Non-EQ Inaccessible Medium-Voltage Cable Program to provide 

more frequent inspection and test frequencies as necessary based on inspection and test 

results, and current staff recommendations. The staff’s concerns related to inaccessible power 

cables operating experience described in RAI 3.0.3.1.6-1 are resolved.

Operating Experience. There are no changes or updates to this section of the SER.

UFSAR Supplement. In LRA Sections A.2.1.22 and A.3.1.22, the applicant provided the 

UFSAR supplement for the Non-EQ Inaccessible Medium-Voltage Cable Program. By 

response to RAI 3.0.3.1.6-1 dated March 28, 2011 and supplemented by letters dated July 14, 

and July 27, 2011 the applicant revised the UFSAR supplements A.2.1.22 and A.3.1.22 to 

include inaccessible power cable (400V to 2kV) and to address operating experience for 

inaccessible power cable within the scope of license renewal. The March 28, 2011 letter 

included a revision to the UFSAR supplement for IP2 (LRA Section A.2.1.22) which stated that 

“In addition to the periodic manhole inspections, inspection of event-driven occurrences, such 

as heavy rain or flooding will be performed.” The July 14, 2011 letter contained an UFSAR 

supplement for IP3 (LRA Section A.3.1.22) which stated that “The inspection frequency for 

water collection is established and performed based on plant specific operating experience with 

cable wetting or submergence in manholes (i.e. the inspection is performed periodically based 

on water accumulation over time and event driven occurrences, such as heavy rain or flooding). 

The July 27, 2011 letter revised the IP2 UFSAR supplement to correspond with the IP3 UFSAR 

supplement provided in the July 14, 2011 letter. It was unclear to the staff if the revised UFSAR 

supplements included event driven inspections. Therefore, the staff held a teleconference with 

the applicant on August 3, 2011, to request clarification on the revised UFSAR supplements. 

The applicant indicated that the Non-EQ Inaccessible Medium-Voltage Cable Program, as 

described in the revised UFSAR supplements, would not include event driven inspections. The 

staff indicated on the teleconference that the program should be able to ensure that the cables 

were not submerged in the intervals between periodic inspections. Therefore, by letter dated 

August 9, 2011 the applicant revised the UFSAR supplements for IP2 and IP3 to state that 

event driven inspections will be performed. The staff reviewed these sections, including the 

applicant’s RAI response, and determines that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21 (d). The applicant 

committed to implement the Non-EQ Inaccessible Medium-Voltage Cable Program prior to the 

period of extended operation. The applicant further stated that this new program will be 

implemented consistent with LRA Section B.1.23 and the corresponding program described in 

GALL AMP XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements" (Commitment 15). 

By letter dated July 27, 2009, the applicant added a new commitment (Commitment 40) which

states that plant-specific and appropriate industry operating experience will be evaluated and

lessons learned will be used to establish appropriate monitoring and inspection frequencies to

assess aging effects for the new aging management programs prior to the period of extended 

operation. In RAI 3.0.3.1.6-1 the staff asked the applicant to explain how the proposed Non-EQ 

Inaccessible Medium-Voltage Cable Program will continue to ensure that future industry and 

plant-specific operating experience will be incorporated into the program such that inspection 

and test frequencies may be increased, as appropriate, based on test and inspection results. 

By RAI response dated March 28, 2011, the applicant stated that the revised Non-EQ 

Inaccessible Medium Voltage Cable Program specifies that cable inspection and test 
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frequencies will be adjusted as necessary based on the results of cable testing and manhole 

inspections. The applicant also stated that it will incorporate lessons learned from future 

industry and plant-specific operating experience, including plant-specific test and inspection 

results during implementation of the Non-EQ Inaccessible Medium Voltage Cable Program. 

The adjustment of inspection and test frequencies based on inspection and test results and 

lessons learned during the implementation of the applicant’s Non-EQ Inaccessible MediumVoltage Cable Program is consistent with staff recommendations. The staff’s concern related to 

the evaluation of plant-specific and industry operating experience during program 

implementation described in RAI 3.0.3.1.6-1 is resolved.

Conclusion. On the basis of its audit and review of the applicant's Non-EQ Inaccessible

Medium-Voltage Cable Program, the staff finds: (a) the applicant’s program is based on and 

consistent with GALL AMP XI.E3, (b) the program enhancements, including the incorporation of 

400 V to 2 kV power cables, are consistent with industry operating experience and current staff 

recommendations. The staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.1.10 One-Time Inspection – Small Bore Piping Program

Summary of Technical Information in the Application. The applicant provided additional 

information related to the One-Time Inspection – Small Bore Piping Program subsequent to the 

issuance of the SER. The additional information is discussed below in the “Staff Evaluation” 

section.

Staff Evaluation. The staff’s evaluation of the applicant’s proposed One-Time Inspection–Small 

Bore Piping Program (ASME Code Class 1) is documented in SER Section 3.0.3.1.10. The 

applicant provided additional information subsequent to the issuance of the SER. The staff’s 

evaluation of the additional information related to the One-Time Inspection – Small Bore Piping 

Program is discussed below in the following categories: (1) Volumetric Examination 

Methodology; (2) One-Time Inspection of Butt Welds at IP2, and Both Butt Welds and Socket 

Welds at IP3; (3) Destructive Examination as an Alternative; and (4) Socket Weld Periodic 

Inspection at IP2.

(1) Volumetric Examination Methodology

By letter dated July 26, 2010, the applicant provided supplemental information related to the 

One-Time Inspection – Small Bore Piping Program regarding the volumetric examination of 

small bore piping. The applicant stated that it will perform the examination in accordance with 

guidelines established in MRP-146, “Materials Reliability Program Management of Thermal 

Fatigue in Normally Stagnant Non-Isolable Reactor Coolant System Branch Lines,” June 2005. 

The staff noted that MRP-146 recommends examination of the base metal half an inch beyond 

the toe of the weld; however, the weld metal is not required as part of examination volume. It 

was not clear to the staff if the applicant’s inspections as part of the One-Time Inspection –

Small Bore Piping Program were to inspect the base metal only without inspecting the weld 

metal. The staff noted that if weld metal is not inspected, this proposed inspection methodology 

may not be adequate to manage age-related degradation of ASME Code Class 1 small-bore 
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piping, because industry operating experience has indicated numerous failures in small bore 

piping, predominantly in the form of cracking in the weld metal. The staff noted that many of 

these failures are documented in Licensee Event Reports (LERs). The staff’s concern is that 

cracking in the weld metal could occur and remain undetected if examination of the weld metal 

is not performed. By letter dated February 10, 2011, the staff issued RAI 3.0.3.1.10-1, Part 1 

and Part 2, requesting the applicant to justify that the examination volume is sufficient and 

capable of detecting cracking in the welds. 

In its response dated March 28, 2011, the applicant stated that volumetric examinations in 

accordance with MRP-146 will be performed to manage thermal fatigue. The applicant clarified 

that volumetric examinations of butt welds always include the weld metal and that it will also 

perform volumetric examinations on the weld metal for socket welds. 

The staff finds the applicant’s response and volumetric examination methodology acceptable 

because the applicant’s volumetric examination includes inspection of the weld metal for butt 

welds and socket welds. The staff’s concern described in RAI 3.0.3.1.10-1, Part 1 and 2, is 

resolved.

(2) One-Time Inspection of Butt Welds at IP2, and Both Butt Welds and Socket Welds at IP3

By letter dated July 26, 2010, the applicant provided its inspection sampling size related to the 

One-Time Inspection – Small Bore Piping Program, which states that, as part of the program, it 

had performed volumetric inspection on two socket welds at IP2, and on 21 socket welds at IP3. 

The staff noted that the applicant did not provide specific information regarding the small bore 

piping weld population or inspection sampling size for either butt welds or socket welds. This 

information is needed by the staff to evaluate the adequacy of the applicant’s inspection 

sampling for socket welds and butt welds and whether the applicant’s program is consistent with 

the staff’s inspection sampling guidance. By letter dated February 10, 2011, the staff issued 

RAI 3.0.3.1.10-2 requesting the applicant to provide the total population of ASME Code Class-1 

small-bore welds of each weld type (butt weld and socket weld) for each unit. In addition, the 

staff requested the applicant to provide the inspection sampling size for ASME Code Class 1 

small-bore piping. 

In its response dated March 28, 2011, the applicant provided the population for each weld type 

at each unit. Specifically, there are 195 butt welds and 433 socket welds at IP2; there are 96 

butt welds and 333 socket welds at IP3. In addition, the applicant provided the inspection 

sampling size consisting of examinations already completed and examinations to be completed 

as part of the One-Time Inspection – Small Bore Piping Program. Specifically, the program will 

include six butt welds (approximately 3 percent) at IP2 and four butt welds (approximately 4 

percent) and 20 socket welds (approximately 6 percent) at IP3. The applicant also stated that 

the inspection locations of small-bore piping welds are determined by risk-informed selection 

criteria which will include the most susceptible and risk-significant welds. In addition, the 

applicant stated that no evidence of cracking or leakage has been detected based on the 

examinations already completed as part of the One-Time Inspection – Small Bore Piping 

Program. The staff noted that both IP2 and IP3 have operated for more than 30 years without 

any plant-specific operating experience of butt weld failures at either unit and no socket weld 

failures at IP3. Therefore the staff finds that use of One-Time Inspection – Small Bore Piping 

Program is appropriate for IP2 in regards to butt welds, and is appropriate to IP3 in regards to 

both socket welds and butt welds.
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Based on the applicant’s plant-specific operating experience and operating history, the staff’s 

sampling guidance is three percent of the weld population, up to 10 welds, for each weld type at 

each unit. The staff finds the applicant’s response and inspection sampling size and 

methodology regarding the one-time inspection of butt welds at IP2, and both butt welds and 

socket welds at IP3 is acceptable. In this regard, the applicant’s One-Time Inspection – Small 

Bore Piping Program includes (a) volumetric inspection of at least three percent of the socket 

welds and butt welds in each unit, and (b) a methodology to select the most susceptible and 

risk-significant welds, consistent with the staff’s sampling guidance. Also, IP2 and IP3 have 

operated for more than 30 years with no plant-specific operating experience that indicates 

cracking or failures with regards to the components in scope of the One-Time Inspection –

Small Bore Piping Program, and no evidence of cracking or leakage has been detected based 

on the examinations already completed as part of the One-Time Inspection – Small Bore Piping 

Program. The staff’s evaluation of the applicant’s proposed inspection of socket welds at IP2 is 

further discussed below in category 4 (Socket Weld Periodic Inspection at IP2). The staff’s 

concern described in RAI 3.0.3.1.10-2 is resolved.

The staff noted that the applicant’s period of extended operation begins on September 28, 2013, 

for IP2, and on December 12, 2015, for IP3. The staff further noted that, as part of the OneTime Inspection - Small Bore Piping Program, IP3 has already completed all of its examinations 

during its current (fourth) 10-year inservice inspection (ISI) interval; IP2 has completed all but 

one of its examinations (an examination of one butt weld) during its current (fourth) 10-year ISI 

interval and will complete the remaining one (butt weld examination) prior to entering the period 

of extended operation. 

The staff finds the applicant’s implementation of these one-time inspections timely and 

acceptable because the applicant has already completed its proposed inspections, except an 

examination of one butt weld at IP2, without revealing any evidence of cracking or leakage and 

the remaining examination will be completed prior to the period of extended operation, 

consistent with the staff’s program implementation guidance.

(3) Destructive Examination as an Alternative

By letter dated March 28, 2011, the applicant indicated that, for socket weld examination, it 

proposes the option of performing destructive examination in lieu of volumetric examination on a 

two-for-one basis. Based on the staff’s sampling guidance, an applicant may take credit for 

each weld destructively examined as being equivalent to having volumetrically examined two 

welds because more information can be obtained from a destructive examination than from 

nondestructive examination; therefore, the staff finds the applicant’s option to perform 

destructive examination in lieu of volumetric examination on a two-for-one basis acceptable and 

consistent with the staff’s sampling guidance.

(4) Socket Weld Periodic Inspection at IP2

In its review of the supplemental information provided by the applicant by letter dated 

July 26, 2010, the staff noted cases of ASME Code Class 1 socket weld failures at IP2. The 

most recent case was a socket weld failure that resulted in reactor coolant system (RCS)

leakage, as documented in LER 2472010004 (ADAMS Accession No. ML1014501190). Based

on this plant-specific operating experience at IP2, the staff determined that the use of a one-
3-12

time inspection may not be appropriate, and that it may be necessary for the applicant to 

perform periodic inspection of socket welds to manage age-related degradation during the 

period of extended operation. By letter dated February 10, 2011, the staff issued RAI 

3.0.3.1.10-1, Part 3, requesting the applicant to provide justification that periodic inspection of 

ASME Code Class 1 small-bore socket welds at IP2 is not needed. 

In its response dated March 28, 2011, the applicant provided a discussion of its operating 

experience which states it has experienced five leaks during 38 years of operation at IP2. In 

addition, the applicant stated that it will perform periodic inspection of ASME Code Class 1 

socket welds at IP2. Specifically, it will volumetrically inspect at least 10 socket welds in 2012 

and at least 10 socket welds during each 10-year ISI interval. However, the basis for the 

inspection sampling size for the periodic inspection at IP2 was not clear to the staff. A robust 

inspection program for socket welds is warranted based on the operating experience at IP2, and 

the inspection sampling should be statistically significant so that cracking, if present, will be 

detected prior to leakage of the component. In the case of a focused inspection in which an 

applicant selects the most susceptible welds and the most risk-significant welds, the staff 

recommends inspection sampling of 10 percent, up to 25 welds, for each 10-year interval during 

the period of extended operation. Therefore, by letter dated June 15, 2011, the staff issued RAI 

3.0.3.1.10-3 requesting the applicant to justify the sampling adequacy of the periodic inspection 

for socket welds at IP2. 

In its response dated July 14, 2011, the applicant stated that it will perform periodic volumetric 

inspection of socket welds as part of its ISI Program. The staff’s evaluation of the applicant’s ISI 

Program is documented in Section 3.0.3.3.4 of the SER. The staff noted that the inspection 

sampling will consist of 25 socket welds during each of the ISI 10-year intervals, consistent with 

the staff’s inspection sampling guidance. In addition, since IP2 is currently in the third period of 

its fourth ISI 10-year interval, the applicant will perform volumetric examination of seven socket 

welds (i.e., 28 percent of the 25 welds needed for the interval) which is the prorated number of 

socket welds to be inspected for the remaining years in the current 10-year interval. The staff 

noted that the applicant will use a methodology to select the most susceptible and risksignificant welds to ensure a high probability of detecting cracking, if it exists. The staff also 

noted if cracking is detected during the inspection, there will be an extent of condition review to 

evaluate the inspection sampling size to ensure that it is adequate to identify cracking that could 

occur at other locations. 

The staff finds the applicant’s response acceptable because the applicant’s sampling 

methodology ensures that an adequate number of welds will be examined during each 10-year 

interval to ensure that aging, if present, will be adequately managed during the period of 

extended operation. The staff’s concern described in RAI 3.0.3.1.10-1, Part 3 and RAI

3.0.3.1.10-3 is resolved.

Based on its review, the staff determined that the applicant’s proposed aging management of 

ASME Code Class 1 small bore piping is adequate because the program includes a sufficient 

number of welds to be inspected, an adequate selection methodology that focuses on 

susceptibility, welds and risk-significance, and the program will also be implemented in a 

reasonable timeframe. 

Operating Experience. There are no changes or updates to this section of the SER.
3-13

UFSAR Supplement. There are no changes or updates to this section of the SER.

Conclusion. There are no changes or updates to this section of the SER.

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions and/or Enhancements

3.0.3.2.10 Masonry Wall Program

Summary of Technical Information in the Application. The applicant provided additional 

information related to the Masonry Wall Program subsequent to the issuance of the SER. The 

additional information is discussed below in the “Staff Evaluation” section.

Staff Evaluation. The staff’s evaluation of the applicant’s proposed Masonry Wall Program is 

documented in Section 3.0.3.2.10 of the SER.

Subsequent to issuance of the SER, the staff identified a need for additional information 

regarding the frequency of inspections for masonry walls within the scope of license renewal. 

By letter dated February 10, 2011, the staff issued RAI 3.0.3.2.10-1 requesting the applicant to 

provide the inspection interval for masonry walls.

By letter dated March 28, 2011, the applicant responded and stated that the inspection interval 

for masonry walls within the scope of license renewal is every 5 years. The staff reviewed the 

applicant’s response and found it acceptable because the applicant is conducting inspections 

consistent with the frequency described in the GALL Report.

Operating Experience. There are no changes or updates to this section of the SER.

UFSAR Supplement. There are no changes or updates to this section of the SER.

Conclusion. There are no changes or updates to this section of the SER.

3.0.3.2.15 Structures Monitoring Program

Summary of Technical Information in the Application. The applicant provided additional 

information related to the Structures Monitoring Program subsequent to the issuance of the 

SER. The additional information is discussed below in the “Staff Evaluation” section.

Staff Evaluation. The staff’s evaluation of the applicant’s proposed Structures Monitoring 

Program is documented in Section 3.0.3.2.15 of the SER. Subsequently, the staff requested

additional information regarding the Structures Monitoring Program acceptance criteria. The 

staff’s evaluation of the additional information submitted by the applicant related to the 

Structures Monitoring Program is discussed below.

GALL AMP XI.S6, “Structures Monitoring Program,” states that American Concrete Institute 

(ACI) 349.3R is an acceptable basis for selection of parameters monitored, detection of aging 

effects, and acceptance criteria. The LRA states that the applicant’s program incorporates 

inspection guidance based on recommendations contained in ACI 349.3R; however, the LRA 

does not clearly state that acceptance criteria align with those in ACI 349.3R. By letter dated 
3-14

February 10, 2011, the staff issued RAI 3.0.3.2.15-1 requesting the applicant provide 

quantitative acceptance criteria that align with ACI 349.3R, or provide technical justification for 

any differences.

By letter dated March 28, 2011, the applicant responded and stated that its Structures 

Monitoring Program has a responsible engineer with the appropriate education and experience 

to identify and evaluate existing conditions using appropriate standards, including ACI 

standards. The applicant further stated that the program will be enhanced to include more 

detailed guidance on quantitative acceptance criteria of ACI 349.3R, “Evaluation of Existing 

Nuclear Safety-Related Concrete Structures.” The applicant committed to implementing this 

enhancement prior to the period of extended operation (Commitment 25). 

The staff reviewed the applicant’s response and found it acceptable because the applicant has 

committed to enhance its Structures Monitoring Program to include acceptance criteria aligned 

with the quantitative criteria recommended in ACI 349.3R, and therefore, with the 

recommendations in the GALL Report. The applicant has committed to implement this 

enhancement prior to the period of extended operation.

Operating Experience. There are no changes or updates to this section of the SER.

UFSAR Supplement. In LRA Section A.2.1.35, the applicant provided the UFSAR supplement 

for the Structures Monitoring Program. In a letter dated March 28, 2011, the applicant 

supplemented the application and revised Commitment No. 25 to enhance the acceptance 

criteria of the program. The staff has determined that the information in the UFSAR supplement 

is an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. There are no changes or updates to this section of the SER.

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report

3.0.3.3.1 Boral Surveillance Program

Summary of Technical Information in the Application. The applicant provided additional 

information related to the Boral Surveillance Program subsequent to the issuance of the SER. 

The additional information is discussed below in the “Staff Evaluation” section.

Staff Evaluation. The staff’s evaluation of the applicant’s Boral Surveillance Program is 

documented in Section 3.0.3.3.1 of the SER. Subsequent to the issuance of the SER, the staff 

identified a need for additional information as to whether the Boral Surveillance Program will 

perform inspection and testing activities with sufficient frequency to ensure that aging of Boral 

neutron-absorbing panels will be adequately managed. By letter dated June 15, 2011, the staff 

issued RAI B.1.4-1 requesting that the applicant state the frequency of inspection and testing 

activities, provide justification if the frequency is less than once every 10 years, and revise the 

UFSAR supplement to include the inspection and testing interval.

In its response dated July 14, 2011, the applicant stated that inspection and testing activities are 

based on plant-specific operating experience and will occur at least once every 10 years during 

the period of extended operation. The applicant revised the UFSAR supplement to reflect the 

minimum 10-year frequency. The staff finds the applicant’s response acceptable because the 
3-15

applicant’s inspection and testing of Boral coupons are informed by operating experience and 

will be performed at least once every 10 years, which is sufficient to ensure that Boral 

degradation will be detected prior to loss of intended function. The staff’s concern described in 

RAI B.1.4-1 is resolved.

UFSAR Supplement. There are no changes or updates to this section of the SER.

Conclusion. There are no changes or updates to this section of the SER.

3.0.3.3.4 Inservice Inspection Program

Summary of Technical Information in the Application. There are no changes or updates to this 

section of the SER.

Safety Evaluation. There are no changes or updates to this section of the SER.

Operating Experience. There are no changes or updates to this section of the SER.

UFSAR Supplement. In LRA Section A.2.1.17, the applicant provided the UFSAR supplement 

for the Inservice Inspection Program. By letter dated July 14, 2011, the applicant revised LRA 

Section A.2.1.17 to include the following,

IPEC will perform twenty-five volumetric weld metal inspections of small-bore 

Class 1 socket welds during each 10-year ISI interval scheduled as specified by 

IWB-2412 of the ASME Section XI Code. In lieu of volumetric examinations, 

destructive examinations may be performed, where one destructive examination 

may be substituted for two volumetric examinations.

The applicant committed (Commitment 46) to perform 25 volumetric weld metal inspections of 

small bore Class 1 socket welds in each 10-year ISI interval during the period of extended 

operation.

The staff reviewed LRA Section A.2.1.17 as amended by letter dated July 14, 2011, and 

concludes that this section of the UFSAR supplement provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. There are no changes or updates to this section of the SER.

3.0.5 Operating Experience for Aging Management Programs

3.0.5.1 Summary of Technical Information in the Application

LRA Section B.0.4 describes the consideration of operating experience for AMPs. The LRA 

states that the applicant reviewed past operating experience to prepare the application. This 

review included operating experience from such sources as corrective actions; reports of recent 

inspections, examinations, tests, and sample results; input from program owners; and 

applicable self-assessments, quality assurance (QA) audits, peer evaluations, and NRC 

reviews. The LRA also states that site procedures require reviews of site and relevant industry 

operating experience as the site continues operation through the period of extended operation.
3-16

3.0.5.2 Staff Evaluation

Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of 

aging on structures and components (SCs) subject to an aging management review (AMR) will 

be adequately managed so that their intended functions will be maintained consistent with the 

CLB for the period of extended operation. SRP-LR, Revision 1, Section A.1.2.3 describes 10 

elements of an acceptable AMP including element 10, “Operating Experience.”

The staff reviewed LRA Section B.0.4 to determine whether the applicant will implement 

adequate programmatic activities for the continual review of both plant-specific and industry 

operating experience to identify areas where AMPs should be enhanced or new AMPs 

developed. While LRA Section B.0.4 states that operating experience will be reviewed in the 

future, it does not fully describe the details of how the applicant will use future operating 

experience to ensure that the AMPs will remain effective for managing the aging effects during 

the period of extended operation. Also, it is not clear as to which AMPs will be updated based 

on future operating experience or whether new AMPs will be developed, as necessary. By letter 

dated June 15, 2011, the staff issued RAI B.0.4-1 requesting that the applicant describe in detail 

the programmatic activities that will be used to continually identify aging issues, evaluate them, 

and, as necessary, enhance the AMPs or develop new AMPs.

In its response dated July 14, 2011, the applicant provided further information to describe how it 

will use its existing programs to monitor, on an ongoing basis, plant-specific and industry 

operating experience and how the evaluations completed under these programs will ensure that 

the AMPs will be effective in managing the aging effects for which they are credited. The 

applicant stated that it will use two programs: the operating experience program (OEP) and the 

corrective action program (CAP). The applicant indicated that the OEP will monitor sources of 

industry operating experience whereas the CAP will monitor sources of plant-specific operating 

experience. Some examples of industry sources are NRC generic communications and Institute 

of Nuclear Power Operations event reports, and some plant-specific sources are the results of 

inspections performed under plant programs and system health reports. The applicant stated 

that items are first screened under the OEP to determine the potential impact to the plants, and

are entered into the CAP when the item concerns degraded equipment. The applicant 

explained that degraded equipment includes degradation due to the effects of aging. 

Evaluations under the CAP consider whether the frequency of future inspections needs 

adjustment, whether new or different inspections are needed, and whether inspections include 

adequate depth and breadth of component, material, and environment combinations. The 

applicant stated that corrective actions can include enhancement of existing AMPs or 

development of new AMPs. Finally, the applicant stated that both the OEP and the CAP are 

administratively controlled.

The staff finds the applicant’s response acceptable because the programmatic activities it 

described are adequate to monitor and evaluate plant-specific and industry operating 

experience on a continual basis. In addition, these programs provide for the enhancement of 

AMPs or the development of new AMPs, when necessary, to ensure that the effects of aging will 

be adequately managed. The staff’s concern described in RAI B.0.4-1 is resolved.

The staff determines that the applicant has met the intent of the “operating experience” program 

element with respect to the future consideration of operating experience. 
3-17

3.0.5.3 UFSAR Supplement

The staff reviewed the UFSAR supplements in LRA Appendix A to determine whether the 

applicant provided an adequate summary description of the ongoing operating experience 

review activities. As the staff found no such description, it also requested in RAI B.0.4-1 that the 

applicant provide a description of these activities for the UFSAR supplement required by 

10 CFR 54.21(d).

In its response dated July 14, 2011, the applicant did not amend the UFSAR supplements to 

include a description of the programmatic activities for the ongoing review of operating 

experience. As such, on July 21, 2011, staff held a teleconference with the applicant to discuss 

the need for such a description in the UFSAR supplements. On July 27, 2011, the applicant 

submitted a supplemental response to RAI B.0.4-1, in which it provided the following description 

in both UFSAR supplements:

The Operating Experience Program (OEP) and the Corrective Action Program 

(CAP) help to assure continued effectiveness of aging management programs 

through evaluations of operating experience. The OEP implements the 

requirements of NRC NUREG-0737, “Clarification of TMI Action Plan 

Requirements,” Section l.C.5 and evaluates site, Enterqy fleet, and industry 

operating experience for impact on IPEC. The CAP implements the 

requirements of 10 CFR 50, Appendix B, Criterion XVI and is used to evaluate 

and effect appropriate actions in response to operating experience relevant to 

IPEC that indicates a condition adverse to quality or a non-conformance.

The staff reviewed this description against the acceptance criteria in SRP-LR Sections 3.1.2.4, 

3.2.2.4, 3.3.2.4, 3.4.2.4, 3.5.2.4, and 3.6.2.4. In accordance with the acceptance criteria in 

these sections, the staff determines that the summary description is sufficiently comprehensive 

such that later changes can be controlled by 10 CFR 50.59. As such, the staff determines that 

the information in the UFSAR supplements is an adequate summary description of the ongoing 

operating experience review activities, as required by 10 CFR 54.21(d).

3.0.5.4 Conclusion

On the basis of its review of the applicant’s programmatic activities for the ongoing review of 

operating experience, the staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR supplement for these activities and concludes that it provides an 

adequate summary description, as required by 10 CFR 54.21(d).

3.1 Aging Management of Reactor Vessel, Internals and Reactor Coolant Systems

3.1.2 Staff Evaluation 

3.1.2.1 AMR Results Consistent with the GALL Report 
3-18

LRA Table 3.1.1, item number 82, states that SG primary side divider plates are composed of 

nickel alloy. LRA Table 3.1.1, item number 81, addresses cracking due to primary water stress 

corrosion cracking (PWSCC) for the nickel alloy or nickel-alloy clad SG divider plate exposed to 

reactor coolant. The applicant credited the Water Chemistry Control – Primary and Secondary

Program to manage cracking due to PWSCC in nickel-alloy SG divider plates exposed to 

reactor coolant, consistent with the GALL Report.

The staff noted that, from foreign operating experience in steam generators with similar design 

to that of the applicant’s SGs, cracking due to PWSCC has been identified in SG divider plate 

assemblies fabricated from Alloy 600, even with proper primary water chemistry. The staff 

noted specifically, that cracks have been detected in the stub runner, very close to the 

tubesheet/stub runner weld and with depths of almost a quarter of the divider plate’s thickness. 

Therefore, the staff determined that the Water Chemistry – Primary and Secondary Program 

might not be effective in managing cracking due to PWSCC in SG divider plate assemblies 

fabricated from Alloy 600 and its associated weld metals.

The staff noted that, although these SG divider plate assembly cracks might not have a 

significant safety impact in and of themselves, these cracks could affect adjacent items that are 

part of the reactor coolant pressure boundary, such as the tubesheet and the channel head, if 

they propagate to the boundary with these items. The staff further noted that for the tubesheet, 

PWSCC cracks in the divider plate assemblies fabricated from Alloy 600 and its associated weld 

metals could propagate to the tubesheet cladding, with possible consequences to the integrity of 

the tube-to-tubesheet welds. Furthermore, for the channel head, the PWSCC cracks in the 

divider plate assemblies could propagate to the SG triple point (i.e. the point where the divider 

plate and tube sheet meet with the shell) and potentially affect the pressure boundary of the SG 

channel head.

The staff reviewed the applicant’s UFSAR and noted that IP2 UFSAR Section 4.2.2.3 and 

Table 4.2-1, and IP3 UFSAR Section 4.2.2 and Table 4.2-1 describe the construction materials 

for the IP2 replacement Model 44F steam generators and for the IP3 replacement Model 44F 

steam generators, respectively. However, there was no information about the construction 

materials of the divider plate assemblies for the SGs at both units.

By letter dated February 10, 2011, the staff issued RAI 3.1.2.2.13-1 requesting that the 

applicant (1) discuss the materials of construction for the IP2 and IP3 SG divider plate 

assemblies, including the welds within these assemblies, to the channel head and to the 

tubesheet, (2) if any constitutive/weld material of the SG divider plate assemblies is susceptible 

to cracking (e.g., Alloy 600 or its associated weld materials), describe an inspection program 

(examination technique and frequency) to ensure that there are no cracks propagating into other 

items which are part of the reactor coolant pressure boundary (e.g., tubesheet and channel 

head) that could challenge the integrity of those adjacent items.

In its response dated March 28, 2011, the applicant described that for IP2 and IP3, the divider 

plates are Inconel 600 (ASME-SB-168) and that it is conservatively assumed that the weld 

materials are the associated Alloy 600 weld materials. The applicant further clarified that IP2 

original Westinghouse Model 44 steam generators were replaced with Model 44F steam 

generators in 2000 and that IP3 original Westinghouse Model 44 steam generators were 

replaced with Model 44F steam generators in 1989. The applicant also described the 

evaluation and conclusion from the Electric Power Research Institute (EPRI) about the safety 
3-19

concern of a cracked divider plate in a Westinghouse Model F SG. In addition, the applicant 

described that the industry plans to study the potential for divider plate crack growth and to 

develop a resolution to the concern through the EPRI Steam Generator Management Program 

(SGMP) Engineering and Regulatory Technical Advisory Group, which is expected to be 

completed by 2013. However, recognizing that the EPRI SGMP resolution of this issue is under 

development, the applicant stated that it would inspect all its SGs to assess the condition of the 

divider plate assembly.

The applicant’s RAI response dated March 28, 2011, was subsequently revised by letters dated 

July 14 and July 27, 2011, which considered information discussed in conference calls held on 

June 9 and July 25, 2011. In the letter of July 27, 2011, the applicant committed 

(Commitment 41) to the following:

IPEC will perform an inspection of steam generators for both units to assess the 

condition of the divider plate assembly. The examination technique used will be 

capable of detecting PWSCC in the steam generator divider plate assemblies. 

The IP2 steam generator divider plate inspections will be completed within the 

first ten years of the period of extended operation (PEO), i.e. prior to 

September 28, 2023. The IP3 steam generator divider plate inspections will be 

completed within the first refueling outage following the beginning of the PEO.

Based on its review, the staff finds the applicant‘s response to RAI 3.1.2.2.13-1 and associated 

Commitment 41 acceptable because the applicant will assess the condition of the divider plate 

assembly in each SG at both units by inspection during the period of extended operation, in a 

time period consistent with the detection of potential PWSCC cracks, with appropriate 

examination techniques. The staff’s concern described in RAI 3.1.2.2.13-1 is resolved.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended

By letter dated June 14, 2010, the applicant provided LRA amendment number 9, which

included the Reactor Vessel Internals Program and revisions to the related LRA Sections. The 

LRA amendment described the Reactor Vessel Internals Program as a new, plant-specific aging 

management program. The Reactor Vessel Internals Program and associated LRA revisions 

were based on the Electric Power Reactor Institute (EPRI) report, “Materials Reliability Program: 

Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227, Rev. 0),” 

which was submitted to the NRC by letter dated January 12, 2009 (ADAMS Accession No. 

ML090160204). The staff completed its review of MRP-227, Rev. 0, and issued its SER on that 

report on June 22, 2011 (ADAMS Accession No. ML111600498). Subsequent to issuing its 

SER on MRP-227, Rev. 0, the staff issued Regulatory Information Summary (RIS) 2011-07, 

“License Renewal Submittal Information for Pressurized Water Reactor Internals Aging 

Management.” As stated therein, RIS 2011-07 “provides information to licensees with respect 

to how to meet their existing license renewal commitments related to reactor vessel internals 

aging management programs, and on acceptable changes to existing license renewal 
3-20

commitments in order to account for recent issue of the staff’s final Safety Evaluation (SE) on 

MRP-227, Rev. 0, and the forthcoming issue of the approved version of MRP-227.”

RIS 2011-07 identifies categories for plants in varying stages of license renewal. Category “C” 

is described as being applicable to plants that have an LRA currently under review which 

applies to IP2 and IP3. RIS 2011-07 states, for applicants in Category C, that “Applicants will 

be expected to revise their commitment for aging management of PWR vessel internals such 

that the submittal information identified in the SE for MRP-227 would be submitted to the NRC 

for review and approval not later than two years after issuance of the renewed license and not 

later than two years before the plant enters the period of extended operation, whichever comes 

first.” The applicant’s current licenses expire on September 28, 2013 for IP2 and December 12, 

2015 for IP3.

By letter dated August 22, 2011, the applicant stated that it would further supplement its LRA by 

September 28, 2011, to include an inspection plan for reactor vessel internals, which is 

consistent with its previous commitment (Commitment 30). In addition, the applicant stated that 

following the issuance of the approved version of MRP-227 (MRP-227-A), it will review the 

inspection plan to determine any need for revision, and will modify the inspection plan to include 

the necessary revisions, if any. The submission of the Reactor Vessel Internals Program, along 

with applicant’s stated intention of supplying an inspection plan by September 28, 2011, and its

plan to revise its program, as necessary, to address the staff’s evaluation of MRP-227, is 

consistent with the applicant’s previous commitment and the recent guidance provided in RIS 

2011-07. Therefore, the staff’s conclusions regarding the applicant’s AMRs for reactor vessel 

internals, as documented in SER Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, and 

3.2.2.17, remain valid.

3.1.2.2.16 Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion 

Cracking

SER Section 3.1.2.2.16 discussed (1) cracking due to stress corrosion cracking (SCC) in 

stainless steel control rod drive head penetration components and on the primary coolant side 

of steel steam generator heads clad with stainless steel, and (2) cracking due to SCC that could 

occur on stainless steel pressurizer spray heads and cracking due to PWSCC that could occur 

on nickel alloy pressurizer spray heads. This SSER supplements the discussion in SER Section 

3.1.2.2.16(1) which appears on pages 3-286 through 3-289 of the SER. SER Section 

3.1.2.2.16(2) is unchanged by this SSER.

(1) Subsequent to the issuance of the SER, the staff requested additional information 

related to the aging management of SG tube-to-tubesheet welds made or clad with 

nickel alloy. The following is the staff’s evaluation of the additional information.

LRA Table 3.1.1, item number 3.1.1-35, states that the corresponding GALL Report line 

item applies to once-through steam generators (SGs) and was used as a comparison for 

the SG tubesheets at the applicant’s site. The applicant further stated that for the steel 

with nickel alloy clad steam generator tubesheets, cracking is managed by the Water 

Chemistry Control – Primary and Secondary and Steam Generator Integrity Programs.

SRP-LR Section 3.1.2.2.16 identifies that cracking due to PWSCC could occur on the 

primary coolant side of PWR steel SG tube-to-tubesheet welds made or clad with nickel 
3-21

alloy. The GALL Report recommends ASME Section XI ISI Program and control of 

water chemistry to manage cracking due to PWSCC and recommends no further aging 

management review for PWSCC of nickel alloy if the applicant complies with applicable 

NRC Orders and provides a commitment in the FSAR supplement to implement 

applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. 

Item IV.D2-4 in the GALL Report addresses cracking due to PWSCC, and is applicable 

only to once-through SGs, but not to recirculating SGs.

The staff noted that ASME Code, Section XI, does not require any inspection of the 

tube-to-tubesheet welds, and that no specific NRC Orders or bulletins address 

inspection requirements for these welds. The staff’s concern is that, if the tubesheet 

cladding is Alloy 600 or the associated Alloy 600 weld materials, the region of the 

autogenous tube-to-tubesheet weld may have insufficient chromium content to prevent 

initiation of PWSCC, even when the SG tubes are made from Alloy 690TT. 

Consequently, a crack initiated in this region, close to a tube, may propagate into or 

through the weld, causing a failure of the weld and of the reactor coolant pressure 

boundary (RCPB). This could occur in once-through SGs, as well as in recirculating 

SGs such as those used at both of the applicant’s units. Therefore, unless the NRC has 

approved a redefinition of the RCPB in which the autogenous tube-to-tubesheet weld is 

no longer included, or the tubesheet cladding and welds are not susceptible to PWSCC, 

the staff considers that the effectiveness of the Water Chemistry Control – Primary and 

Secondary Program should be verified to ensure PWSCC cracking is not occurring. 

Moreover, it was not clear to the staff how the Steam Generator Integrity Program is able 

to manage PWSCC of the tubesheet cladding, including the tube-to-tubesheet welds.

LRA Section 2.3.1.4 describes the IP2 replacement Westinghouse Model 44F SG tubes 

as being fabricated from Alloy 600TT, and the IP3 replacement Westinghouse Model 

44F SG tubes as being fabricated from Alloy 690TT. The applicant also described the 

tubesheet surfaces in contact with reactor coolant as clad with Inconel, and stated that 

the tube-to-tubesheet joints are welded for both units’ SGs.

By letter dated February 10, 2011, the staff issued RAI 3.1.2.2.16-1 requesting that the 

applicant, for the IP2 SGs, (1) clarify whether the tube-to-tubesheet welds are included 

in the RCPB or alternate repair criteria have been permanently approved, and (2) if the 

SGs do not have permanently approved alternate repair criteria, justify how the Steam 

Generator Integrity Program is capable of managing PWSCC in tube-to-tubesheet 

welds, or provide a plant-specific AMP that will complement the Water Chemistry Control 

– Primary and Secondary Program, in order to verify its effectiveness and ensure that 

cracking due to PWSCC is not occurring in tube-to-tubesheet welds. For the IP3 SGs, 

the staff requested that the applicant justify how the Steam Generator Integrity Program 

is capable of managing PWSCC in tube-to-tubesheet welds, or provide either a plantspecific AMP that will complement the Water Chemistry Control – Primary and 

Secondary Program, in order to verify its effectiveness and ensure that cracking due to 

PWSCC is not occurring in tube-to-tubesheet welds, or a rationale for why such a 

program is not needed.

In its response dated March 28, 2011, the applicant clarified that in the IP2 SGs, the 

tube-to-tubesheet welds are included in the RCPB and no tubesheet region alternate 

repair criterion is employed. The applicant further stated that, for each unit, it would 
3-22

address the potential failure of the steam generator reactor coolant pressure boundary 

due to PWSCC cracking of tube-to-tubesheet welds via one of two options, an analysis 

or an inspection. The applicant further stated that an approved analytical evaluation 

would obviate the need to develop a plant-specific AMP to verify effectiveness of the 

Water Chemistry Control – Primary and Secondary program.

The applicant’s RAI response dated March 28, 2011, was subsequently revised by 

letters dated July 14, July 27, and August 9, 2011, which considered, among other 

things, information discussed in conference calls held on June 9, and July 25, 2011. In 

the August 9, 2011 letter, the applicant committed (Commitment 42) to the following:

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 steam generator tube-totubesheet welds in order to establish a technical basis for either 

determining that the tubesheet cladding and welds are not susceptible to 

PWSCC, or redefining the pressure boundary in which the tube-totubesheet weld is no longer included and, therefore, is not required for 

reactor coolant pressure boundary function. The redefinition of the 

reactor coolant pressure boundary must be approved by the NRC as part 

of a license amendment request.

Option 2 (Inspection)

IPEC will perform a one-time inspection of a representative number of 

tube-to-tubesheet welds in each steam generator to determine if PWSCC 

cracking is present. If weld cracking is identified:

a. The condition will be resolved through repair or engineering 

evaluation to justify continued service, as appropriate, and

b. An ongoing monitoring program will be established to perform routine 

tube-to tubesheet weld inspections for the remaining life of the steam 

generators.

Moreover, for IP2, the applicant stated that the tube-to-tubesheet welds have been in 

service for approximately eleven years since it replaced the IP2 SGs in 2000. 

Considering this limited service time, the applicant further stated that, if Option 1 were 

not implemented, it would implement Option 2 that includes tube-to-tubesheet weld 

inspections for PWSCC. The applicant further stated that these inspections would be 

performed between March 2020 and March 2024, such that the SGs will have been in 

service between 20 and 24 years. For IP3, the applicant stated that the tube-totubesheet welds have been in service for approximately 22 years since it replaced the 

IP3 SGs in 1989. The applicant further stated that, if Option 1 were not implemented, it 

would implement Option 2 which includes tube-to-tubesheet weld inspections for 

PWSCC. The applicant further stated that these inspections would be performed prior to 
3-23

the end of the first refueling outage following the beginning of the period of extended 

operation.

Based on its review, the staff finds the applicant‘s response to RAI 3.1.2.2.16-1 and 

associated Commitment 42 acceptable because the applicant will manage the aging 

effect of cracking due to PWSCC in the SG tube-to-tubesheet welds either by 

demonstrating that those welds are no longer included in the SG reactor coolant 

pressure boundary function or are not susceptible to PWSCC, or by implementing a 

one-time inspection on a representative number of tube-to-tubesheet welds of each 

steam generator to determine if PWSCC is present, in a time period consistent with the 

detection of potential PWSCC cracks. The staff finds that the timing of this inspection for 

each unit is acceptable because at the time of the inspections, the respective SGs will 

have been in operation for between 20 and 24 years, and between 22 and 28 years, for 

IP2 and IP3, respectively, and it is unlikely that significant detrimental PWSCC cracking 

will have initiated at this time period. The staff also noted that if aging effects are 

identified by the inspections, the applicant will take corrective actions including an 

evaluation of the degradation and the implementation of routine inspections of the tubeto-tubesheet welds for the remaining life of the SGs. The staff’s concern described in 

RAI 3.1.2.2.16-1 is resolved.

3.2 Aging Management of Engineered Safety Features Systems

3.2.2 Staff Evaluation

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

3.2A.2.3.5 Containment Penetrations-Summary of Aging Management ReviewLRA Table 3.2.2-5-IP2

SER Section 3.2A.2.3.5 presented the staff’s review of AMR items in LRA Table 3.2.2-5-IP2. In 

addition to the AMR results documented in the SER for LRA Table 3.2.2-5-IP2, by letter dated 

July 26, 2010, the applicant proposed no aging effect for stainless steel filter housings exposed 

to indoor air externally. This line item is similar to Item VF-12 in the GALL Report, which is for 

stainless steel piping, piping components, and piping elements in an external environment of 

air—indoor uncontrolled. Because the LRA item is similar to the GALL Report item for that 

material and environment, the staff finds that the exposure of stainless steel material to plant 

indoor air will not result in aging that will be of concern during the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, aging effect requiring management and AMP combinations not 

addressed in the GALL Report. The staff finds that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3 Aging Management of Auxiliary Systems

3.3.2 Staff Evaluation
3-24

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

3.3B.2.3.19 Chlorination System, Nonsafety-Related Components Potentially Affecting Safety 

Functions – Summary of Aging Management Review – LRA Table 3.3.2-19-5-IP3

SER Section 3.3B.2.3.19 presented the staff’s review of AMR items in LRA Table 

3.2.2-19-5-IP2. In addition to the AMR results documented in the SER for LRA Table 3.3.2-19-

5-IP3, by letter dated July 26, 2010, the applicant proposed no aging effect for plastic piping 

exposed to indoor air externally and treated water internally. The staff noted that the applicant’s 

LRA was submitted using GALL Report Revision 1 which did not address this component, 

material and environment combination. The staff also noted that GALL Report Revision 2 

addresses polyvinyl chloride (PVC) pipe exposed to the air-indoor environment and 

condensation. No aging effects for PVC in these environments would be expected based on 

GALL items AP-268, SP-152, and SP-153 which state in part that generally low operating 

temperatures and historical good chemical resistance data for PVC components, combined with 

a lack of historic negative operating experience, indicate that PVC is not likely to experience any 

degradation from the nonaggressive indoor air and condensation. The staff noted that the 

internal environment would include chlorine during chemical injection periods. The staff also 

noted that the Environmental Technical Specifications and UFSAR state a range of chlorine

from 13.5 percent to 15 percent. The staff further noted that the “Chemical Resistance of 

Plastics and Elastomers,” Third Edition, by the Plastic Design Library Staff, William Andrew 

Publishing, Interactive Table, states that PVC material exposed to sodium hypochlorite solutions 

up to 20 percent are acceptable with no effect. Therefore the staff finds the applicant’s AMR 

results as appropriate.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, aging effect requiring management and AMP combinations not 

addressed in the GALL Report. The staff finds that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).
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4-1

SECTION 4

TIME LIMITED AGING ANALYSIS

4.3 Metal Fatigue Analyses

4.3.3 Effects of Reactor Water Environment on Fatigue Life

4.3.3.1 Summary of Technical Information in the Application

The applicant provided additional information related to the Metal Fatigue Analyses subsequent 

to the issuance of the Safety Evaluation Report (SER). The additional information is discussed 

below in Supplemental SER Section 4.3.3.2 “Staff Evaluation.”

4.3.3.2 Staff Evaluation

The staff’s evaluation of the applicant’s environmentally-assisted fatigue evaluations are 

documented in Section 4.3.3.2 of the SER. Subsequently, based on recent staff review it was 

noted that the applicant’s plant-specific configuration may contain locations that require an 

analysis to determine the effects of reactor water environment on component fatigue life, other 

than those generic locations identified in NUREG/CR-6260 “Application of NUREG/CR-5999 

Interim Fatigue Curves to Selected Nuclear Power Plant Components,” February 1995. The 

staff’s evaluation of the additional information submitted by the applicant in relation to 

environmentally-assisted fatigue is discussed below.

By letter dated February 10, 2010, the staff issued request for additional information (RAI) RCS3 requesting the applicant to confirm and justify that the locations selected for environmentally 

assisted fatigue analyses, consistent with NUREG/CR-6260, are the most limiting for the plant. 

Furthermore, if these locations are not the most limiting for the plant, the applicant was 

requested to clarify the locations that require an environmentally-assisted fatigue analysis and 

the actions that will be taken for these additional locations.

In its response dated March 28, 2010, the applicant committed (Commitment 43) to implement,

prior to entering the period of extended operation, the following:

IPEC (Indian Point Energy Center) will review design basis ASME (American 

Society of Mechanical Engineers) Code Class 1 fatigue evaluations to determine 

whether the NUREG/CR-6260 locations that have been evaluated for the effects 

of reactor coolant environment on fatigue usage are the limiting locations for the 

IP2 and IP3 (Indian Point Nuclear Generating Unit Nos. 2 and 3) configuration. If 

more limiting locations are identified, the most limiting location will be evaluated 

for the effects of the reactor coolant environment on fatigue usage.

IPEC will use the NUREG/CR6909 methodology in the evaluation of the limiting 

locations consisting of nickel alloy, if any. 
4-2

The staff finds that the use of NUREG/CR-6909, "Effect of LWR (light water reactor) Coolant 

Environments on the Fatigue Life of Reactor Materials," for nickel alloy materials is acceptable 

because it incorporates the most recent fatigue data for determining the environmental fatigue 

life correction (Fen) factor for nickel alloys.

Based on its review, the staff finds the applicant’s response to RAI RCS-3 and Commitment 43 

acceptable because (1) the applicant will review its design basis ASME Code Class 1 fatigue 

evaluations to determine whether the NUREG/CR-6260 locations are the limiting components 

for the applicant’s design, (2) if more limiting locations are identified, the applicant will perform 

environmentally assisted fatigue analyses for the most limiting location, (3) the applicant will use 

the methodology consistent with NUREG/CR-6909 in the evaluation if the limiting location 

identified consists of nickel alloy, (4) the applicant will complete this review prior to entering the 

period of extended operation, and (5) Commitment 43 is consistent with the recommendations 

in “Standard Review Plan for Review of License Renewal Applications for Nuclear Power 

Plants” (SRP-LR) Sections 4.3.2.2 and 4.3.3.2, and NUREG-1801, “Generic Aging Lessons 

Learned (GALL) Report,” aging management program (AMP) X.M1, to consider environmental 

effects for the NUREG/CR-6260 locations, at a minimum. The staff’s concern in RAI RCS-3 is 

resolved.

Separate from the staff’s license renewal reviews, but as part of its review of the AP1000 design 

certification application, the NRC staff identified specific concerns with the use of the NB-3600 

option for the computer program WESTEMSTM. These concerns are described in the staff’s 

safety evaluation and audit reports related to the AP1000 review (ADAMS Accession 

Nos. ML103430502 and ML110250634, respectively). Based on this documented concern, the 

applicant submitted a letter dated March 28, 2011, in which it provided two commitments 

regarding its use of the computer program WESTEMSTM for license renewal. 

First, the applicant committed (Commitment 44) to include a written explanation and justification 

of any user intervention in future evaluations using the WESTEMSTM “Design CUF (cumulative 

usage factor)” module. The applicant stated that this commitment will be implemented prior to 

the end of the current licensing term, which is September 2013 for IP2 and December 2015 for 

IP3. The staff finds the applicant’s implementation schedule reasonable because the applicant 

is ensuring that a written explanation and justification of any user intervention, in future 

calculations using the WESTEMSTM “Design CUF” module, will be documented. The staff noted 

that the implementation schedule also allows the applicant sufficient time to document and 

implement necessary procedures.

Based on its review, the staff finds the applicant’s Commitment 44 acceptable because it 

ensures that the records of any calculations performed with WESTEMSTM “Design CUF” module 

will contain sufficient information to document and justify any assumptions and engineering 

judgment used to calculate the CUF value, and that the basis for the conclusions in the fatigue 

calculations are auditable and retrievable.

Second, in its letter of March 28, 2011, the applicant also provided Commitment 45, which 

states that it will not use the NB-3600 option of the WESTEMSTM program in future fatigue 

design calculations until the issues identified in NRC’s review of the NB-3600 option of the 

program have been resolved. Further, this commitment will be implemented prior to the end of 
4-3

the current licensing term. The staff finds the applicant’s implementation schedule reasonable 

because the applicant is ensuring that the NB-3600 option of the WESTEMSTM program will not 

be used for design calculations. The staff noted that the implementation schedule also allows 

the applicant sufficient time to document and implement necessary procedures to prevent the 

use of the NB-3600 option of the WESTEMSTM program. The staff noted that the applicant’s 

current decision to not use this option of the WESTEMSTM program is acceptable in view of the 

staff’s identification of an issue regarding whether the NB-3600 option performs fatigue 

calculations consistent with ASME Code Section III, Subsection NB, Subarticle NB-3600.

Based on its review, the staff finds the applicant’s Commitment 45 acceptable because the 

applicant committed not to use the NB-3600 option of the WESTEMSTM program in future 

design calculations until the NRC-identified issue is resolved.

4.3.3.3 UFSAR Supplement

There are no changes or updates to this section of the SER.

4.3.3.4 Conclusion

There are no changes or updates to this section of the SER.
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5-1

SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS

The staff has provided the Advisory Committee on Reactor Safeguards with a copy of this 

supplemental safety evaluation report.
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6-1

SECTION 6

CONCLUSION

The staff concludes that the additional information provided by Entergy Nuclear Operations, 

Inc., does not alter the conclusions stated in the SER and that the requirements of 

10 CFR 54.29(a) have been met.
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A-1

APPENDIX A

IP LICENSE RENEWAL COMMITMENTS

During the review of the Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3), license renewal application (LRA) by the 

staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff), Entergy Nuclear Operations, Inc. (Entergy or the applicant) made 

commitments related to aging management programs (AMPs) to manage the aging effects for certain structures and components

during the period of extended operation. The following table lists these commitments along with the applicant’s stated implementation 

schedules and sources for each commitment. This list supersedes the list published in Appendix A of NUREG-1930.

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

1 Enhance the Above Ground Steel Tanks Program for IP2 and 

IP3 to perform thickness measurements of the bottom surfaces 

of the condensate storage tanks, city water tank, and fire water 

tanks once during the first ten years of the period of extended 

operation.

Enhance the Above Ground Steel Tanks Program for IP2 and 

IP3 to require trending of thickness measurements when 

material loss is detected.

A.2.1.1

A.3.1.1

B.1.1

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

2 Enhance the Bolting Integrity Program for IP2 and IP3 to clarify 

that actual yield strength is used in selecting materials for low 

susceptibility to SCC and clarify the prohibition on use of 

lubricants containing MoS2 for bolting.

The Bolting Integrity Program manages loss of preload and loss 

of material for all external bolting. 

A.2.1.2

A.3.1.2

B.1.2

Audit Items 201, 241, 

270

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153
A-2

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

3 Implement the Buried Piping and Tanks Inspection Program for 

IP2 and IP3 as described in LRA Section B.1.6.

This new program will be implemented consistent with the 

corresponding program described in NUREG-1801, Section 

XI.M34, Buried Piping and Tanks Inspection.

Include in the Buried Piping and Tanks Inspection Program 

described in LRA Section B.1.6 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. 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 demonstrated 

effectiveness.

A.2.1.5

A.3.1.5

B.1.6

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

NL-09-106

NL-09-111

NL-11-101

4 Enhance the Diesel Fuel Monitoring Program to include cleaning 

and inspection of the IP2 GT-1 gas turbine fuel oil storage tanks, 

IP2 and IP3 EDG fuel oil day tanks, IP2 SBO/Appendix R diesel 

generator fuel oil day tank, and IP3 Appendix R fuel oil storage

tank and day tank once every ten years. 

A.2.1.8

A.3.1.8

B.1.9

Audit Items 128, 129, 

132, 491, 492, 510

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

NL-08-057
A-3

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

4 (continued) Enhance the Diesel Fuel Monitoring Program to include 

quarterly sampling and analysis of the IP2 SBO/Appendix R 

diesel generator fuel oil day tank, IP2 security diesel fuel oil 

storage 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 
A-4

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

4 (continued) 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.

5 Enhance the External Surfaces Monitoring Program for IP2 and 

IP3 to include periodic inspections of systems in scope and 

subject to aging management review for license renewal in 

accordance with 10 CFR 54.4(a)(1) and (a)(3). 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).

A.2.1.10

A.3.1.10

B.1.11

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

6 Enhance the Fatigue Monitoring Program for IP2 to monitor 

steady state cycles and feedwater cycles or perform an 

evaluation to determine monitoring is not required. Review the 

number of allowed events and resolve discrepancies between 

reference documents and monitoring procedures.

Enhance the Fatigue Monitoring Program for IP3 to include all 

the transients identified. Assure all fatigue analysis transients 

are included with the lowest limiting numbers. Update the 

number of design transients accumulated to date.

A.2.1.11

A.3.1.11

B.1.12

Audit Item 164

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153
A-5

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

7 Enhance the Fire Protection Program to inspect external 

surfaces of the IP3 RCP oil collection systems for loss of 

material each refueling cycle.

Enhance the Fire Protection Program to explicitly state that the 

IP2 and IP3 diesel fire pump engine sub-systems (including the 

fuel supply line) shall be 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.

A.2.1.12

A.3.1.12

B.1.13

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039
A-6

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

8 Enhance the Fire Water Program to include inspection of IP2 

and IP3 hose reels for evidence of corrosion. Acceptance 

criteria will be revised to verify no unacceptable signs of 

degradation.

Enhance the Fire Water Program to replace all or test a sample 

of IP2 and IP3 sprinkler heads required for 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 the IP3 foam based fire suppression tanks. Acceptance 

criteria will be enhanced to verify no significant corrosion.

A.2.1.13

A.3.1.13

B.1.14

Audit Items 105, 106

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

NL-08-014
A-7

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

9 Enhance the Flux Thimble Tube Inspection Program for IP2 and 

IP3 to implement comparisons to wear rates identified in WCAP12866. Include provisions to compare data to the previous 

performances and perform evaluations regarding change to test 

frequency and scope.

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.

A.2.1.15

A.3.1.15

B.1.16

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

10 Enhance the Heat Exchanger Monitoring Program for IP2 and 

IP3 to include the following heat exchangers in the scope of the 

program.

• Safety injection pump lube oil heat exchangers

• RHR heat exchangers

• RHR pump seal coolers

• Non-regenerative heat exchangers

A.2.1.16

A.3.1.16

B.1.17

Audit Item 52

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

NL-09-018
A-8

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

10 (continued) • Charging pump seal water heat exchangers

• Charging pump fluid drive coolers

• Charging pump crankcase oil coolers

• Spent fuel pit heat exchangers

• Secondary system steam generator sample coolers

• Waste gas compressor heat exchangers

• 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 nondestructive 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, fouling, or scaling.
A-9

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

11 Deleted Not applicable Not applicable NL-09-056

NL-11-101

12 Enhance the Masonry Wall Program for IP2 and IP3 to specify 

that the IP1 intake structure is included in the program. A.2.1.18

A.3.1.18

B.1.19

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039
A-10

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

13 Enhance the Metal-Enclosed Bus Inspection Program to add IP2 

480V bus associated with substation A to the scope of the bus 

inspected.

Enhance the Metal-Enclosed Bus Inspection Program for IP2 

and IP3 to visually inspect the external surface of MEB

enclosure assemblies for loss of material at 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.

A.2.1.19

A.3.1.19

B.1.20

Audit Item 124, 133, 

519

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

NL-08-057
A-11

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

14 Implement the Non-EQ Bolted Cable Connections Program for 

IP2 and IP3 as described in LRA Section B.1.22. A.2.1.21

A.3.1.21

B.1.22

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

15 Implement the Non-EQ Inaccessible Medium-Voltage Cable 

Program for IP2 and IP3 as described in LRA Section B.1.23.

This new program will be implemented consistent with the 

corresponding described in NUREG-1801, Section XI.E3, 

Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements.

A.2.1.22

A.3.1.22

B.1.23

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

NL-11-032

NL-11-096

NL-11-101

16 Implement the Non-EQ Instrumentation Circuits Test Review 

Program for IP2 and IP3 as described in LRA Section B.1.24.

This new program will be implemented consistent with the 

corresponding described in NUREG-1801, Section XI.E2, 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in 

Instrumentation Circuits.

A.2.1.23

A.3.1.23

B.1.24

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

17 Implement the Non-EQ Insulated Cables and Connections 

Program for IP2 and IP3 as described in LRA Section B.1.25.

This new program will be implemented consistent with the 

corresponding described in NUREG-1801, Section XI.E1, 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements.

A.2.1.24

A.3.1.24

B.1.25

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153
A-12

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

18 Enhance the Oil Analysis Program for IP2 to sample and 

analyze lubricating oil used in the SBO/Appendix R diesel 

generator consistent with the oil analysis for other site diesel 

generators.

Enhance the Oil Analysis Program for IP2 and IP3 to sample 

and analyze generator seal oil and turbine 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.

A.2.1.25

A.3.1.25

B.1.26

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-11-101

19 Implement the One-Time Inspection Program for IP2 and IP3 as 

described in LRA Section B.1.27.

This new program will be implemented consistent with the 

corresponding program described in NUREG-1801, Section 

XI.M32, One-Time Inspection.

A.2.1.26

A.3.1.26

B.1.27

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153
A-13

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

20 Implement the One-Time Inspection – Small Bore Piping 

Program for IP2 and IP3 as described in LRA Section B.1.28.

This new program will be implemented consistent with the 

corresponding program described in NUREG-1801, Section 

XI.M35, One-Time Inspection of ASME Code Class I Small-Bore 

Piping.

A.2.1.27

A.3.1.27

B.1.28

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

21 Enhance the Periodic Surveillance and Preventive Maintenance 

Program for IP2 and IP3 as necessary to assure that the effects 

of aging will be managed such that applicable components will 

continue to perform their intended functions consistent with the 

current licensing basis through the period of extended operation.

A.2.1.28

A.3.1.28

B.1.29

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

22 Enhance the Reactor Vessel Surveillance Program for IP2 and 

IP3 revising the specimen capsule withdrawal schedules to draw 

and test a standby capsule to cover the peak reactor vessel 

fluence expected through the end of the period of extended 

operation.

Enhance the Reactor Vessel Surveillance Program for IP2 and 

IP3 to require that tested and untested specimens from all 

capsules pulled from the reactor vessel are maintained in 

storage.

A.2.1.31

A.3.1.31

B.1.32

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

23 Implement the Selective Leaching Program for IP2 and IP3 as 

described in LRA Section B.1.33.

This new program will be implemented consistent with the 

corresponding program described in NUREG-1801, Section 

XI.M33, Selective Leaching of Materials.

A.2.1.32

A.3.1.32

B.1.33

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153
A-14

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

24 Enhance the Steam Generator Integrity Program for IP2 and IP3 

to require that the results of the condition monitoring 

assessment are compared to the operational assessment 

performed for the prior operating cycle with differences 

evaluated.

A.2.1.34

A.3.1.34

B.1.35

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

25 Enhance the Structures Monitoring Program to explicitly specify 

that the following structures are included in the program.

• Appendix R diesel generator foundation (IP3)

• Appendix R diesel generator fuel oil tank vault (IP3)

• Appendix R diesel generator switchgear and enclosure (IP3)

• city water storage tank foundation

• condensate storage tanks foundation (IP3)

• containment access facility and annex (IP3)

• discharge canal (IP2/3)

• emergency lighting poles and foundations (IP2/3)

• fire pumphouse (IP2)

• fire protection pumphouse (IP3)

• fire water storage tank foundations (IP2/3) 

• gas turbine 1 fuel storage tank foundation

• maintenance and outage building-elevated passageway 

(IP2)

• new station security building (IP2)

• nuclear service building (IP1)

• primary water storage tank foundation (IP3)

• refueling water storage tank foundation (IP3)

• security access and office building (IP3)

• service water pipe chase (IP2/3)

A.2.1.35

A.3.1.35

B.1.36

Audit Items 86, 87, 88, 

417, 358, 360

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

NL-08-057

NL-08-127

NL-11-032

NL-11-101
A-15

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

25 (continued) • service water valve pit (IP3)

• superheater stack 

• transformer/switchyard support structures (IP2)

• 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.

• cable trays and supports

• concrete portion of reactor vessel supports

• conduits and supports

• cranes, rails and girders

• equipment pads and foundations

• fire proofing (pyrocrete)

• HVAC duct supports

• jib cranes

• manholes and duct banks

• manways, hatches and hatch covers

• monorails

• new fuel storage racks

• 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 
A-16

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

25 (continued) 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 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 and IP3 to 

perform an engineering evaluation of 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 and IP3 to 

perform inspection of the degraded areas of the water control 

structure once per 3 years rather than the normal frequency of 

once per 5 years during the PEO.
A-17

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

25 (continued) Enhance the Structures Monitoring Program to include more 

detailed quantitative acceptance criteria 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.

26 Implement the Thermal Aging Embrittlement of Cast Austenitic 

Stainless Steel (CASS) Program for IP2 and IP3 as described in 

LRA Section B.1.37.

This new program will be implemented consistent with the 

corresponding program described in NUREG-1801, Section 

XI.M12, Thermal Aging Embrittlement of Cast Austenitic 

Stainless Steel (CASS) Program.

A.2.1.36

A.3.1.36

B.1.37

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153

27 Implement the Thermal Aging and Neutron Irradiation 

Embrittlement of Cast Austenitic Stainless Steel (CASS) 

Program for IP2 and IP3 as described in LRA Section B.1.38.

This new program will be implemented consistent with the 

corresponding program described in NUREG-1801, Section 

XI.M13, Thermal Aging and Neutron Embrittlement of Cast 

Austenitic Stainless Steel (CASS).

A.2.1.37

A.3.1.37

B.1.38

Audit Item 173

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-07-153
A-18

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

28 Enhance the Water Chemistry Control – Closed Cooling Water 

Program to maintain water chemistry of the IP2 

SBO/Appendix R diesel generator cooling system per EPRI 

guidelines.

Enhance the Water Chemistry Control – Closed Cooling Water 

Program to maintain the IP2 and IP3 security generator and fire 

protection diesel cooling water pH and glycol within limits 

specified by EPRI guidelines.

A.2.1.39

A.3.1.39

B.1.40

Audit Item 509

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039

NL-08-057

29 Enhance the Water Chemistry Control – Primary and Secondary 

Program for IP2 to test sulfates monthly in the RWST with a limit 

of <150 ppb.

A.2.1.40

B.1.41

IP2: September 28, 

2013

NL-07-039

30 For aging management of the reactor vessel internals, IPEC will 

(1) participate in the industry programs for investigating and 

managing aging effects on reactor internals; (2) evaluate and 

implement the results of the industry programs as applicable to 

the reactor internals; and (3) upon completion of these 

programs, but not less than 24 months before entering the 

period of extended operation, submit an inspection plan for 

reactor internals to the NRC for review and approval.

A.2.1.41

A.3.1.41

B.1.41

IP2: September 28, 

2011

IP3: December 12, 

2013

NL-07-039

31 Additional P-T curves will be submitted as required per 10 CFR 

50, Appendix G prior to the period of extended operation as part 

of the Reactor Vessel Surveillance Program.

A.2.2.1.2

A.3.2.1.2

4.2.3

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-07-039
A-19

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

32 As required by 10 CFR 50.61(b)(4), IP3 will submit a plantspecific safety analysis for plate B2803-3 to the NRC three years 

prior to reaching the RTPTS screening criterion. Alternatively, the 

site may choose to implement the revised PTS rule when 

approved.

A.3.2.1.4

4.2.5

IP3: December 12, 

2015

NL-07-039

NL-08-127

33 At least 2 years prior to entering the period of extended 

operation, for the locations identified in LRA Table 4.3-13 (IP2) 

and LRA Table 4.3-14 (IP3), under the Fatigue Monitoring 

Program, IP2 and IP3 will implement one or more of the 

following:

(1) Consistent with the Fatigue Monitoring Program, Detection of 

Aging Effects, update the fatigue usage calculations using 

refined fatigue analyses to determine valid CUFs less than 1.0 

when accounting 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.

A.2.2.3.3

A.3.2.2.3

4.3.3

Audit Item 146

IP2: September 28, 

2011

IP3: December 12, 

2013

Complete

NL-07-039

NL-07-153

NL-08-021

NL-10-082
A-20

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

33 (continued)

4. An analysis using an NRC-approved version of the 

ASME code or NRC-approved alternative (e.g., NRCapproved 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.

34 IP2 SBO/Appendix R diesel generator will be installed and 

operational by April 30, 2008. This committed change to the 

facility meets the requirements of 10 CFR 50.59(c)(1) and, 

therefore, a license amendment pursuant to 10 CFR 50.90 is not 

required.

2.1.1.3.5 April 30, 2008

Complete

NL-07-078

NL-08-074

NL-11-101

35 Perform a one-time inspection of representative sample area of 

IP2 containment liner affected by the 1973 event behind the 

insulation, prior to entering the period of extended operation, to 

assure liner degradation is not occurring in this area.

Perform a one-time inspection of representative sample area of 

the IP3 containment steel liner at the juncture with the concrete 

floor slab, prior to entering the period of extended operation, to 

assure liner degradation is not occurring in this area.

Any degradation will be evaluated for updating of the

containment liner analyses as needed.

Audit Item 27 IP2: September 28, 

2013

IP3: December 12, 

2015

NL-08-127

NL-09-018

NL-11-101
A-21

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

36 Perform a one-time inspection and evaluation of a sample of 

potentially affected IP2 refueling cavity 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 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 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.

Audit Item 359 IP2: September 28, 

2013

NL-08-127

NL-09-056

NL-09-079

NL-11-101

37 Enhance the Containment Inservice Inspection (CII-IWL) 

Program to include inspections of the containment using 

enhanced characterization of degradation (i.e., quantifying the 

dimensions of noted indications through the use of optical aids) 

during the period of extended operation. The enhancement 

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.

Audit Item 361 IP2: September 28, 

2013

IP3: December 12, 

2015

NL-08-127
A-22

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

38 For Reactor Vessel Fluence, should future core loading patterns 

invalidate the basis for the projected values of RTPTS or CVUSE, 

updated calculations will be provided to the NRC.

4.2.1 IP2: September 28, 

2013

IP3: December 12, 

2015

NL-08-143

39 Deleted Not applicable Not applicable NL-09-079

40 Evaluate plant specific and appropriate industry operating 

experience and incorporate lessons learned in establishing 

appropriate monitoring and inspection frequencies to assess 

aging effects for the new aging management programs. 

Documentation of the operating experience evaluated for each 

new program will be available on site for NRC review prior to the 

period of extended operation.

B.1.6

B.1.22

B.1.23

B.1.24

B.1.25

B.1.27

B.1.28

B.1.33

B.1.37

B.1.38

IP2: September 28, 

2013

IP3: December 12, 

2015

NL-09-106
A-23

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

41 IPEC will inspect steam generators for both units to assess the 

condition of the divider plate assembly. The examination 

technique used will be capable of detecting PWSCC in the 

steam generator divider plate assembly. The IP2 steam 

generator divider plate inspections will be completed within the 

first ten years of the period of extended operation (PEO). The 

IP3 steam generator divider plate inspections will be completed 

within the first refueling outage following the beginning of the 

PEO.

N/A IP2: After the

beginning of the

PEO and prior to

September 28,

2023

IP3: Prior to the 

end of the first 

refueling outage 

following the 

beginning of the 

PEO

NL-11-032

NL-11-074

NL-11-090

NL-11-101

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 steam 

generator tube-to-tubesheet welds in order to establish a 

technical basis for either determining that the tubesheet cladding 

and welds are not susceptible to PWSCC, or redefining the 

pressure boundary in which the tube-to-tubesheet weld is no 

longer included and, therefore, is not required for reactor coolant 

pressure boundary function. The redefinition of the reactor 

coolant pressure boundary must be approved by the NRC as a 

license amendment request.

N/A Option 1: 

IP2: Prior to March 

2024

IP3: Prior to the

end of the first

refueling outage

following the

beginning of the

PEO. check these

against august 9 

letter.

Option 2:

IP2: Between 

March 2020 and 

March 2024

NL-11-032

NL-11-074

NL-11-090

NL-11-096
A-24

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

42 (cont.)

Option 2 (Inspection)

IPEC will perform a one-time inspection of a representative 

number of tube-to-tubesheet welds in each steam generator to 

determine if PWSCC cracking is present. If weld cracking is 

identified:

a. The condition will be resolved through repair or 

engineering evaluation to justify continued service, as 

appropriate, and

b. An ongoing monitoring program will be established to 

perform routine tube-to-tubesheet weld inspections for 

the remaining life of the steam generators.

IP3: Prior to the 

end of the first 

refueling outages

following the 

beginning of the 

PEO.

43 IPEC will review design basis ASME Code Class 1 fatigue 

evaluations to determine whether the NUREG/CR-6260 

locations that have been evaluated for the effects of the reactor 

coolant environment on fatigue usage are the limiting locations 

for the IP2 and IP3 configurations. If more limiting locations are 

identified, the most limiting location will be evaluated 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.

4.3.3 IP2: Prior to 

September 28, 

2013

IP3: Prior to 

December 12, 

2015

NL-11-032

NL-11-101
A-25

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS

Item Number Commitment UFSAR

Supplement Section/

LRA Section

Applicant’s 

Implementation 

Schedule

Source

44 IPEC will include written explanation and justification of any user 

intervention in future evaluations using the WESTEMS “Design 

CUF” module.

N/A IP2:

Prior to

September 28,

2013

IP3: Prior to

December 12,

2015

NL-11-032

NL-11-101

45 IPEC will not use the NB-3600 option of the WESTEMS program 

in future design calculations until the issues identified during the 

NRC review of the program have been resolved.

N/A IP2:

Prior to

September 28,

2013

IP3: Prior to

December 12,

2015

NL-11-032

NL-11-101

46 Include in the IP2 ISI Program that IPEC will perform twenty-five 

volumetric weld metal inspections of socket welds during each 

10-year ISI interval 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.

N/A IP2: Prior to 

September 28, 

2013

NL-11-032

NL-11-074
B-1

APPENDIX B

CHRONOLOGY

This appendix lists chronologically the licensing correspondence between the staff of the U.S.

Nuclear Regulatory Commission (NRC) (the staff) and Entergy Nuclear Operations, Inc. 

(Entergy or the applicant). This appendix also lists other correspondence concerning the staff’s 

review of the Indian Point Nuclear Generating Unit Nos. 2 and 3 license renewal application 

(LRA) (Docket Nos. 50-247 and 50-286) issued since the publication of NUREG-1930 in

November 2009.

CHRONOLOGY

Date Subject

7/14/2010 Letter from Entergy Nuclear Operations, Inc. to NRC, Indian Point, Units 2 & 3 -

Amendment 9 to License Renewal Application, Reactor Vessel Internals Program,

(ADAMS Accession No. ML102010102)

7/26/2010 Letter from Entergy Nuclear Operations, Inc. to NRC, Indian Point, Units 2 & 3, 

Amendment 10 to License Renewal Application, (ADAMS Accession No. 

ML102150347)

8/9/2010 Letter from Entergy Nuclear Operations, Inc. to NRC, Indian Point Nuclear 

Generating, Units 2 and 3 - License Renewal Application - Completion of 

Commitment #33 Regarding the Fatigue Monitoring Program, (ADAMS Accession 

No. ML102300504)

2/10/2011 01/06/2011 & 01/12/2011-Summary of Telephone Conference Calls Between the 

NRC and Entergy Nuclear Operations Inc., Concerning Draft Requests for 

Additional Information (ADAMS Accession No. ML110180529)

2/10/2011 Letter from NRC to Entergy Nuclear Operations, Inc., Request for Additional 

Information for the Review of the Indian Point Nuclear generating Units Numbers 

2 and 3, License Renewal Application, (ADAMS Accession No. ML110190809)

4/19/2011 Letter from NRC to Entergy Nuclear Operations, Inc., Safety Project Manager 

Change For The License Renewal Project For Indian Point Nuclear Generating 

Unit Numbers 2 And 3, (ADAMS Accession No. ML11090A078)

3/28/2011 Letter from Entergy Nuclear Operations, Inc. to NRC, Indian Point, Units 2 & 3, 

Response to Request for Additional Information on Aging Management Programs, 

(ADAMS Accession No. ML110960360)

5/9/2011 01/12/11 Summary of Telephone Conference Call Between NRC and Entergy 

Nuclear Operations, Inc., Concerning the Final SEIS for the Proposed License

Renewal of Indian Point, Units 2 and 3, (ADAMS Accession No. ML11102A006)

6/15/2011 Letter from NRC to Entergy Nuclear Operations, Inc, Request For Additional 

Information For The Review Of The Indian Point Nuclear Generating Unit Nos. 2 

and 3, License Renewal Application, (ADAMS Accession No. ML11139A447)

7/14/2011 Letter from Nuclear Operations, Inc, to NRC, Indian Point Units 2 & 3, Response 

to Request for Additional Information Aging Management Programs, (ADAMS 

Accession No. ML11201A160)
B-2

CHRONOLOGY

Date Subject

7/18/2011 06/09/2011-Summary of Conference Call Between the NRC and Entergy Nuclear 

Operations, Inc., Concerning Inspection of Small Bore Piping, Steam Generator 

Components, and the Non-EQ Inaccessible Medium-Voltage Cable Program,

(ADAMS Accession No. ML11178A335)

7/27/2011 Letter from Nuclear Operations, Inc, to NRC, Indian Point Units 2 & 3, Clarification

for Request for Additional Information Aging Management Programs, (ADAMS 

Accession No. ML11215A128)

8/9/2011 Letter from Nuclear Operations, Inc, to NRC, Indian Point Units 2 & 3, Clarification

for Request for Additional Information Aging Management Programs, (ADAMS 

Accession No. ML11229A803)

8/22/2011 Letter from Nuclear Operations, Inc, to NRC, Indian Point Units 2 & 3, Clarification

for Request for Additional Information Aging Management Programs ADAMS 

Accession No. ML11XXXXXXX)

8/30/11 7/21/2011-Summary of Conference Call Between the NRC and Entergy Nuclear 

Operations, Inc., Concerning Operating Experience at Indian Point Nuclear 

Generating Station, Units 2 and 3, (ADAMS Accession No. ML11215A056)

8/30/11 07/25/2011-Summary of Conference Call Between the NRC and Entergy Nuclear 

Operations, Inc., Concerning Steam Generator Aging Management and Metal 

Fatigue Analysis, (ADAMS Accession No. ML11215A088)

8/30/11 8/3/2011-Summary of Conference Call Between the NRC and Entergy Nuclear 

Operations, Inc., Concerning the Non-EQ Inaccessible Medium-Voltage Cable 

Program, (ADAMS Accession No. ML112270145)