Plant License Renewal (ANO-1)- February 22, 2001

                Official Transcript of Proceedings


Title:                    Advisory Committee on Reactor Safeguards
                               Plant License Renewal Subcommittee

Docket Number:  (not applicable)

Location:                 Rockville, Maryland

Date:                     Thursday, February 22, 2001

Work Order No.: NRC-081                               Pages 1-177

                   NEAL R. GROSS AND CO., INC.
                 Court Reporters and Transcribers
                  1323 Rhode Island Avenue, N.W.
                     Washington, D.C.  20005
                          (202) 234-4433.                         UNITED STATES OF AMERICA
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                                 + + + + +
                       ARKANSAS NUCLEAR ONE, UNIT 1
                        LICENSE RENEWAL APPLICATION
                                 + + + + +
                             FEBRUARY 22, 2001
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                            ROCKVILLE, MARYLAND
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                 The Subcommittee met at the Nuclear Regulatory
           Commission, Two White Flint North, Room T2B3, 11545
           Rockville Pike, at 8:30 a.m., Mario V. Bonaca,
           Subcommittee Chairman, presiding.
           MARIO V. BONACA, Chairman
           THOMAS S. KRESS
           WILLIAM J. SHACK
           ROBERT E. UHRIG
           NRC STAFF:
           H. ASHER
           R. AULUDE
           LEE BANIC
           W. BATEMAN
           W. BURTON
           JIM DAVIS
           T. EATON
           BARRY ELLIOT
           J. FAIR
           Z. BART FU
           CHRIS GRIMES
           M. HARTZMAN
           STEVE HOFFMAN
           A. KEIM
           THOMAS KENYON
           C. LAURON
           ANDREA LEE
           S.K. MITRA
           A. PAL
           K. PARCZESKI
           ROBERT J. PRATO
           J.H. RAVAL.           NRC STAFF: (CONT.)
           J. RAJAN
           CHANG-YANG LI
           Y.C. (RENEE) LI
           OTHERS PRESENT:
           RAYMOND BAKER, Southern Nuclear
           RICK BUCKLEY, Entergy
           RICHARD HARRIS, Entergy
           NATALIE MOSHER, Entergy
           JEFF RICHARDSON, Entergy
           MARK RINCKEL, Framatome
           CHARLES WILLBANKS, Scientech
           GARY YOUNG, Entergy.                                 I-N-D-E-X
           I.    Opening Remarks. . . . . . . . . . . . . . . 5
           II.   Staff Introduction . . . . . . . . . . . . . 6
           III.  Overview of SER Related to ANO-1 License . . 7
           IV.   Entergy Operations, Inc., Presentation . . .42
           V.    SER Chap 2.0 - Scoping and Screening of. . .73
                 Structures and Components Subject to an
                 Aging Management Review
           VI.   SER Chap. 3.3.1 - Common Aging . . . . . . .92
           VII.  SER Chap. 3.3.2 - Reactor Coolant System . .95
           VIII. SER Chap. 3.3.3 - Engineered Safety. . . . 108
           IX.   SER Chap. 3.3.4 - Auxiliary Systems. . . . 113
           X.    SER Chap. 3.3.5 - Steam and Power. . . . . 123
                 Conversion Systems
           XI.   SER Chap. 3.3.6 - Structures and . . . . . 128
           XII.  SER Chap. 3.3.7 - Electrical Components. . 136
           XIII. SER Chap. 4.0 - Time Limited Aging . . . . 148
           XIV.  Overview of the License Renewal. . . . . . 158
                 Environmental Review Process
                 Subcommittee Discussion. . . . . . . . . . 170.                           P-R-O-C-E-E-D-I-N-G-S
                                                    (8:30 a.m.)
                       DR. BONACA:  The meeting will now come to
           order.  This is a meeting of the ACRS Subcommittee on
           Plant License Renewal.  I am Mario Bonaca, Chairman of
           the Subcommittee.  ACRS members in attendance are
           George Apostolakis, Thomas Kress, William Shack, and
           Robert Uhrig.
                       The purpose of this meeting is to discuss
           the license renewal application for the Arkansas
           Nuclear One, Unit 1, and the associated NRC staff's
           draft Safety Evaluation Report.  The Subcommittee will
           gather information, analyze relevant issues and facts,
           and formulate proposed positions and actions, as
           appropriate, for the liberation by the full Committee. 
           Sam Duraiswamy is the Cognizant ACRS Staff Engineer
           for this meeting.
                       The rules for participation in today's
           meeting have been announced as part of the notice of
           this meeting, previously published in the Federal
           Register on January 29, 2001.  A transcript of the
           meeting is being kept and will be made available as
           stated in the Federal Register Notice.  It is
           requested that the speakers first identify themselves
           and speak with sufficient clarity and volume so that
           they can be readily heard.
                       We have received no written comments or
           requests for time to make oral statements from members
           of the public regarding today's meeting.  We will now
           proceed with the meeting and I call upon Mr. Chris
           Grimes, of the NRR, to begin.
                       MR. GRIMES:  Thank you, Dr. Bonaca.  I am
           Chris Grimes, Chief of the License Renewal and
           Standardization Branch, and we're here today to
           present the results of this staff's safety evaluation
           with open items for the review of the license renewal
           application for Arkansas Nuclear One, Unit 1.
                       As you may recall, this is a B&W unit, and
           our review followed very closely the Oconee license
           renewal application.  And in order to make this most
           useful for you, the staff's presentation has been
           organized to highlight differences and uniqueness of
           this review over other license renewal reviews that
           we've presented to you, in order to focus on what was
           special about Arkansas Nuclear One in terms of the
           conduct of this staff's review.
                       I would like to introduce Robert Prato,
           who is the license renewal project manager for the
           ANO-1 license renewal review.  And he'll go over the
           license renewal application and the main part of the
           presentation.  And then we have other staff members
           who will cover other topics in our agenda today.
                       As the Subcommittee, or the full
           Committee, I can't recall now which, as you requested,
           we've also arranged to present a brief overview of the
           environmental review, in order to familiarize you with
           the parallel activity that the staff had ongoing
           related to the review of the environmental report and
           the preparation of the supplement to the generic
           environmental impact statement.  And that's arranged
           later in the agenda.
                       Unless there are any questions that you
           have for me, I'll turn it over to Bob Prato, and we'll
           get started with the presentation.
                       DR. BONACA:  We can start.
                       MR. PRATO:  Thank you.  Good morning. 
           Again, my name is Bob Prato.  I'm the -- should I go
           ahead?  I'm the Project Manager for Arkansas Nuclear
           One License Renewal Application.  On slide two is a
           listing of the topics, and the presenters of those
                       Now, I'll begin with the overview.  On
           slide -- we'll start on slide three if we could,
           please.  Unit description:  ANO-1 is a two-unit site
           consisting of a Babcock and Wilcox pressurized water
           reactor and a combustion engineering pressurized water
           reactor located in Pope County in central Arkansas on
           Lake Dardanelle.
                       Lake Dardanelle is a man-made lake.  It
           was constructed around 1960, in the very early '60s. 
           On February 1, 2000, the applicant, Entergy
           Incorporated, submitted a license renewal application
           for ANO-1, Arkansas Nuclear One, Unit 1, the 2,568
           megawatt thermal Babcock and Wilcox pressurized water
                       Unit 1 construction began in 1968 and went
           commercial in 1974.  The current facility operating
           license expires in May of 2014.  This facility is
           similar to ONS in the interpless design aspects. 
           Comparing ANO-1 site with the Oconee nuclear facility,
           Oconee nuclear site is a three-unit site.
                       It has a stand by shut down facility,
           which is not only a difference between Oconee and ANO,
           but it's unique to the industry.  And Oconee uses a
           keowee hydroelectric dam to provide emergency power,
           which again, is unique to that site.
                       The difference between ANO-1 and Oconee is
           ANO-1 has an emergency cooling pond as an alternate
           ultimate heat sink.  With respect to the applications,
           you need to understand that Oconee submitted its
           application prior -- or developed this application
           prior to issuance of the standard review plan.
                       As a result, their outline was
           considerably different than was anticipated in the
           standard review plan.  The outline for the Oconee SER
           application was -- Chapter 1 was the introduction. 
           Chapter 2 was scoping.  Chapter 3 was aging effects. 
           Chapter 4 was age of management programs.  And Chapter
           5 was time limited aging analysis.
                       The ANO-1 application was more consistent
           with the SRP, where we had Chapter 1 was the
           introduction.  Chapter 2 was scoping, and Chapter 3
           was the aging management review, which is combined
           Chapter 3 and 4 putting in the Oconee application. 
           Chapter 4 was also a TLA.
                       As far as the safety evaluation reports,
           the SER was out in time for the staff to develop the
           SER for Oconee consistent with the SRP.  And
           therefore, both applications are very similar.  There
           is a couple of extra chapters in the Oconee
                       I believe it's Chapter 2 is -- I'm sorry 
           -- Chapter 2 is aging effects from mechanical systems,
           and I believe Chapter 3 is containment.  They
           separated out containment from the rest of the
           structures.  The ANO application, a safety evaluation,
           starts with an introduction, goes to scoping, goes to
           aging management review, and goes to time limit aging
                       There is a unique feature about the ANO
           application, the Chapter 3, is what they call the
           mechanical tools.  This chapter is what they use to
           develop the aging effects for mechanical components. 
           This -- understanding that this is a separate focus of
           the applicants will help us later on in presentation.
                       What we did to try and provide you a
           comparison of the two applications was we took the
           open items from Oconee and ANO, and we identified the
           differences in the application for those items.  So
           we're going to begin with scoping.
                       ANO-1 safety-related criteria is based on
           the more current definition consistent with 10 CFR
           54.4(a)(1) and (a)(2).  That is that the safety-
           related criteria is based on the safety-related
           criteria and a non-safety-related criteria for scoping
           for license renewal.
                       Oconee's safety-related criteria was
           considerably different.  Their definition was based on
           very deficient products, and that caused some contrast
           between what the staff was used to and the rule
           itself.  And we spent quite a bit of time trying to
           rectify the differences in ensuring that the scope was
           complete for Oconee.
                       We did not have that difficulty for ANO. 
           We'll begin the presentation on the scoping
           methodology here a little bit later.  ANO-1 spent fuel
           pool cooling was not included within the scope of
           license renewal.  This was consistent with the Oconee
           conclusion that the -- Oconee's recirculating cooling
           water system was not required because the spent fuel
           pools are similar designs.  Neither one were required
           for being within the scope of license renewal.
                       ANO-1 chilled water was not excluded from
                       DR. BONACA:  Excuse me.
                       MR. PRATO:  Yes, sir.
                       DR. BONACA:  But Oconee had an emergency
           make-up to the pool that is a part of the aging
           management programs.  And I believe, also, Arkansas
           has an emergency make-up capability, right, to serve
           this water.
                       MR. PRATO:  Yes, sir.  And both of them
           are required to keep their fuel full, and rather than
           requiring emergency cooling, it's just required to
           keep the materials in the fuel -- spent fuel pool
                       DR. BONACA:  Yes.  And you tell us also
           about the liner, because there is a one --
                       MR. PRATO:  We will cover that a little
           bit later as well when we get down into the specifics.
                       DR. BONACA:  Yes.  Was the Oconee
           application -- did it include the liner as part of the
           components under -- in the scoping?
                       MR. PRATO:  Yes, sir.
                       DR. BONACA:  Okay.
                       MR. PRATO:  Yes, sir.
                       DR. BONACA:  Do you also want to discuss
           the boron flux issue?
                       MR. PRATO:  Yes, we will.  We will.  We
           will get to that as well.
                       ANO-1 passive long-lived skidman equipment
           were not excluded from an aging management review and
           the license renewal application.  ANO-1 structural
           sealant, water stops and expansion joints were not
           excluded from an aging management review as well in
           the license renewal application.
                       DR. BONACA:  The chilled water system. 
           You didn't -- I interrupted you at that point.
                       MR. PRATO:  Yes, sir.
                       DR. BONACA:  Did you have any comment on
           that one?  You have a bullet here.
                       MR. PRATO:  I thought I added that.  It
           was included within the scope of the license renewal
           in the application.  You'll find out as we go through
           this presentation that ANO took considerable advantage
           of the lessons learned from Oconee.
                       And a lot of what issues were raised
           during Oconee, the great majority of them were
           resolved right in the application.  And that's really
           the theme that we're trying to bring out here, is a
           lot of what we identified early on for Oconee was
                       DR. BONACA:  Among the comparisons here,
           I would like to talk about also the reactor vessel
           level measurement system.
                       MR. PRATO:  Okay.  I'm not sure we were
           prepared to go into detail on that, but if you'd like
                       DR. BONACA:  Well, I would like to hear
           about that.  I understand it's been excluded from the
           scope --
                       MR. PRATO:  Yes.
                       DR. BONACA:  -- of the application.  And
           I can't remember if we excluded it for Oconee too.  It
           probably was excluded.
                       MR. PRATO:  It's just one of the measuring
           devices.  I don't believe that all of them were
           excluded.  They have --
                       DR. BONACA:  When you go through the
           scoping, it will be interesting to understand the
           logic for excluding the reactor vessel level
           measurement system.
                       MR. PRATO:  Okay.  And we'll try to
           prepare for that.  I'll go back.  I believe that
           presentation is probably scheduled for after lunch.
                       DR. BONACA:  Okay.
                       MR. PRATO:  The applicant is going to be
           here as well, and you may be able to get the details
           if you need, as well, from them.
                       DR. BONACA:  Good.
                       MR. PRATO:  Structural sealants, water
           stops and expansion joints were included.  Electric
           cables were not excluded from this scope.  They were
           included and required an aging management review for
           Arkansas Nuclear One.
                       Initially, in the application there were
           some contradicting statements with respect to Lake
           Dardanelle and the Turbine Building, and as to whether
           or not they were included within the scope.  Those
           were straightened out in the RAI process, and it was
           straightened out prior to issuing the SER.
                       ANO-1 ventilation sealants were also
           included within the scope, and an aging management
           review was performed on those.  ANO fire detector
           cables were also included.  ANO aging effects
           discussed and accepted by the staff were consistent --
           were consistently applied throughout the application.
                       This is where that Appendix C came into
           play.  Because they had tools and they applied those
           tools consistently across all their systems, they
           didn't have the problems that arose in the Oconee
           application with applying aging effects consistently
           across the different systems.
                       ANO-1 buried pipe were included within a
           scope, and an aging management review was performed in
           the license renewal application.  And ANO-1 committed
           to 10 CFR Part 50, Appendix B, for corrective actions,
           confirmation, processes, and document control
           activities were both safety-related and non-safety-
                       Oconee had only committed it for safety-
           related, and they applied different techniques to
           resolve those for non-safety-related.  ONS just
           committed to Appendix B for all components within the
           scope of license renewal.
                       MR. GRIMES:  Excuse me, Bob, are you on
           slide six?
                       MR. PRATO:  Yes, I am.
                       MR. GRIMES:  Is slide six up?  Thank you.
                       MR. PRATO:  The last two items on that
           page are the two items that are open items for ANO-1
           with respect to scoping.  The staff identified in the
           FSAR that one of the full control offices was required
           to control the injection of sodium hydroxide for pH
                       The applicant included that orifice within
           the scope of license renewal, but solely for pressure
           boundary.  And the staff requested that they justify
           excluding it for full control.  The other item, which
           is the item that right now is the center of our focus
           for proceeding with the -- final safety evaluation --
           is the fire protection system.
                       ANO-1 was built prior to 1968.  They were
           not subject to all of Appendix R, just the three
           subsections they were back fitted to.  They, at that
           time, they were not submitting specific components for
           fire protection.  They were doing it in general terms. 
           The staff were reviewing them in general terms.
                       There was some confusion as to whether or
           not they were ever within the applicant's CLB.  In the
           mid-'80s, they did a design basis reconstitution to
           convert their safety-related definition from Fischen
           product barriers to event medication.  And when they
           went through that process, they identified all the
           components on site.
                       And then they made a determination whether
           it was safety related, whether it was required for
           fire protection, ATWS, et cetera.  When they were done
           with that evaluation, they had what is known as the
           ref list, which is the fire protection list.
                       And there were a number of components that
           were not included on that list that the staff feels
           should be included.  And we're in the process of
           evaluating whether or not those components need to be
           added to their current licensing basis.  If it is
           decided that it needs to be added, they are going to
           be required to submit an aging management review on
           those components.
                       The components in question is the fire
           protection jockey pump.  The carbon dioxide system,
           fire hydrants, the water supply to the low level rad
           waste building fire protection system, and the piping
           to the manual hose stations -- are they components
           that are within question.
                       There will be a staff meeting on that. 
           Right now, we're trying to figure out a final date for
           that meeting.  It's going to be a public meeting. 
           It's currently scheduled for the 7th.  There are some
           scheduling conflicts, and we're trying to work those
           out as well.
                       MR. SHACK:  Does this report sort of
           follow the NEI suggested format?  That is, is this
           close to a template for what we expect future license
           renewal applications to look like?
                       MR. PRATO:  Their application did
           basically follow the NEI template.  They did something
           unique.  They incorporated a lot of tables.  And the
           staff had mixed feelings about that.  Having the
           tables were really helpful.  It had a lot of compact
           information that sat in front of you and it helped you
           do your evaluation a lot quicker.
                       However, it being in table form, did raise
           some questions on the details.  And we had
           approximately 250 REIs as a result of the application
           review, which is less than our predecessors.  However,
           if you take a look at them, about 90, 95 percent were
           questions on details that the information really was
           contained in the tables, but it wasn't clear.
                       The staff is not discouraging the use of
           the tables.  We're trying to get a balance between the
           tables and the detailed information that we need
           writing the application.
                       DR. BONACA:  I didn't see any, you know,
           extensive reference to the GALL2 report.  Was it just
           because of timing, the GALL2 came after the
           application was essentially submitted, or was it just
           because the GALL would be mostly referenced by the
                       MR. PRATO:  The GALL hadn't been issued
           during the development stage.  They followed a lot of
           it, and the staff requested a lot of information.  And
           the applicant made a lot of adjustments to be more
           consistent with GALL.
                       DR. BONACA:  Okay.  So they played the
           role, although maybe less a role just because of the
                       MR. PRATO:  I believe it played a role for
           the applicant as well as the staff.
                       DR. BONACA:  Okay.
                       DR. SHACK:  Well, the B&W topical reports
           also had a tremendous impact, just to cover huge
           chunks of stuff --
                       MR. PRATO:  And that's another difference
           between Oconee and ANO.  A couple of the topical
           reports were not issued when ANO were developing their
           application.  And that generated a lot of open items. 
           And a lot of those open items were just not applicable
           to Arkansas because they had incorporated the
           requirements in those topical reports.
                       DR. SHACK:  One other general comment,
           just as you're coming up on the aging management
           review, I didn't see really do a -- I didn't see
           nearly as many one-time inspections.  Is that correct,
           or am I just -- that there's not a call out as one-
           time inspections as there were for Calvert Cliffs or
                       MR. PRATO:  There were a couple one-time
           inspections, but I think you're right, because I've
           worked both on Calvert and Oconee's.
                       DR. SHACK:  Plus, there were like 30 of
           them or something.
                       MR. PRATO:  Yes, yes, sir.  And a lot of
           those were as a result of open items, and it was a
           resolution to a lot of the open items.  I'm not sure
           why there aren't as many as at ANO, but I believe the
           reason is is because they were aware of the fact that
           they were open items.
                       And instead of trying to address the
           resolution of the open items, I believe the applicant
           tried to address the issue itself.  And as a result,
           some of those one-time inspections just materialized.
                       DR. BONACA:  But you performed a
           comparison with the previous applications to make sure
           that of one of the reasons a one-time inspection is
           because there is a different commitment that fulfills
           the need anyway.
                       MR. PRATO:  We did not do a specific
           evaluation to verify that itself.  I think we did --
           and I think a large part of that is because we had
           different reviewers.  Again, another unique about
           Arkansas is that a lot of the review is done by
                       We had staff personnel overseeing it,
           making sure it was complete, making sure that it was
           consistent, that we weren't recreating the will, if
           you will, for Arkansas.  But I think as -- because we
           got different reviews involved, there wasn't that
                       Another thing is I don't think the staff
           wholesale accepts one-time inspections.  We, in
           general, request them to justify the use of that if
           that's what they want to use.  It has to make sense,
           and it's the applicant's responsibility to provide a
           justification for that.
                       DR. BONACA:  But as you go forth, I mean
           I imagine that although you have different reviewers,
           you will want to capture lessons learned from
           individual -- this, by the way, is one of the reasons
           why we have a presentation that we discuss with Mr.
           Grimes, which includes some comparison.
                       Because we are trying ourselves, as a
           committee, to gain from previous experience.
                       MR. PRATO:  Don't misunderstand me. 
           There's a big effort and a lot of focus on lessons
           learned between plants.  And not only with the staff
           itself, but with the industry.
                       The industry meets quite often internally
           to themselves, and talk about what they've learned and
           where the problems are, and why is it a problem here
           and it wasn't in another place, and what is a good
           solution for it?  And a lot of that work is going into
           GALL, I believe.
                       MR. GRIMES:  As a matter of fact, I wanted
           to point out that I think that you say fewer one-time
           inspections here, primarily, because some of the
           uncertainty associated with the treatment of potential
           aging effects in Calvert Cliffs and Oconee has been
           resolved in the work on GALL, that has either
           determined where there is no need to verify the
           existence of an aging effect, or the effectiveness of
           a program.
                       And I think also my sense was, as we were
           going through the review of the Arkansas safety
           evaluation, I got the sense that Entergy put more
           reliance on existing programs and periodic inspections
           to determine the existence of aging effects, where
           Calvert Cliffs and Oconee look more to the one-time
           inspection to check for the existence of aging
                       DR. SHACK:  I notice they even opted for
           a periodic pressurizer cladding inspection, whereas
           you accepted a one-time inspection and a topical
           report, which struck me as a considerable improvement.
                       MR. PRATO:  Yes, well -- and we thought
           so, too.
                       DR. BONACA:  Yes, at some point, Appendix
           B on the application has at least seven -- I believe
           seven new problems.  Among those are a couple of one-
           time inspections.  And at some point, we will get an
           overview of those programs?
                       MR. PRATO:  Not as a separate
           presentation.  But if you'd like, I'll be glad to
           propose one.
                       DR. BONACA:  No, you don't have to, but as
           long as we get it sometime today from the licensee or
           from you.
                       MR. PRATO:  Okay.  We'll do what we can.
                       DR. BONACA:  Well, I mean, some of them
           I'm sure you're going to go through, because --
                       MR. PRATO:  Absolutely.
                       DR. BONACA:  So there might be a couple
           extra, but I would like to review them a little bit to
                       MR. PRATO:  There are a number of them
           that are common aging management programs, which we're
           going to cover that as a separate entity as well.  So
           you'll get most of them.  We weren't prepared to do
           those by themselves, and I'm not sure if the applicant
           is prepared to do that.
                       But if there are any --
                       DR. BONACA:  Well, we just have a few
           questions.  I'm sure you are cognizant enough to
           provide some answers.
                       MR. PRATO:  Yes, sir.  As for aging
           management, the plant differences ANO-1 did not
           exclude the heat transfer as an applicable intended
           function for heat exchangers.  And they use
           performance monitoring consistent with generic letter
           8913 to manage the following itself -- 8913 is the
           service water generic letter.
                       ANO-1 performed an aging management review
           of all the piping in the service -- all the piping
           within the scope of this service water system
           regardless of the materials.  Oconee limited their
           initial evaluation just to carbon steel piping.
                       ANO-1 did not perform an aging management
           review of the tendon galleries in the license renewal
           application, which is consistent with the previous two
           applicants.  They weren't required to do that.
                       Continuing with the aging management
           review, this is specific to the reactant coolant
           system aging effects.  ANO-1 pressurizer spray head
           was not included within the scope of license renewal,
           because it's not required by the current licensing
           basis.  They don't use it for design basis events
           accident analysis.
                       ANO-1 addressed void swelling in its
           license renewal application as an applicable aging
           effect for the reactor vessel.  And manage the related
           aging using the reactor vessel internal aging
           management program consistent with the topical report
           BAW-2248 and the Oconee lessons learned.
                       Next slide is on reactive coolant systems
           aging management programs.  ANO-1 heater bundle
           penetration welds are designed differently than
           Oconee's heather bundle penetration welds.  ANO-1
           heater bundles are all stainless steel and consist of
           a stainless steel heater sheet weld directly to a
           stainless steel diaphragm plate.
                       Oconee Unit One contained alloy 600 heater
           sheets.  And the design was a heater sheet to sleeve,
           plate weld to a heater sleeve, to a bundle diaphragm
           plate weld.  ANO-1, in this license renewal
           application, committed to examine heater bundles upon
           removal consistent with the lessons learned from
                       DR. BONACA:  Now, in the application,
           however, it states that if Oconee performs the
           inspection and doesn't find anything, then they would
           not perform an inspection in Arkansas.  But in the
           SER, I didn't see the exclusions.  So is there some
           agreement that you reached through some
                       MR. PRATO:  Yes, I don't believe there's
           an open item on that issue at all.  The agreement was
           that when they replace it, they're going to inspect
           it.  There's not going to be any specific inspection,
           unless when Oconee does its inspection, they find a
                       Is that correct?
                       MR. YOUNG:  Gary Young with Entergy. 
           We're going to follow the Oconee work and they're
           going to follow our work.  So what we're going to do
           is compare notes.  If we do our heater bundle first,
           then the results from that will be factored into the
           Oconee program.
                       And if they do their heater bundle first,
           then we'll factor that result into our program. 
           Though, it's really more of a B&W program to look at,
           you know, both units together.  That's why it's stated
           the way it is.  And the staff, if they have any
           problems with that --
                       DR. BONACA:  Okay.  Yes, because the
           application is clear on that issue, but the SER did
           not -- assuming the SER says that Arkansas would
           perform in any event, an inspection of the heater
           bundle, which in turn, it means that it may not, in
           case Oconee does it first.
                       MR. PRATO:  Right.
                       DR. BONACA:  And I think it's fine.
                       MR. PRATO:  If the Oconee comes out, you
           know, with no problems whatsoever, and there's no
           benefit from doing a subsequent inspection in
           Arkansas, that's what that section was all about.
                       DR. BONACA:  And that was part of the B&W
                       MR. PRATO:  Yes.
                       DR. BONACA:  That kind of --
                       MR. PRATO:  Dr. Bonaca, I have a note
           here, and we will go through the SER again and in our
           revision and in our final version, we'll make sure
           that's made clear.
                       DR. BONACA:  Okay.
                       MR. PRATO:  ANO-1, in its license renewal
           application, included cracking as an applicable aging
           effect for reactor vessel internal non-bolted items. 
           And the identification of limiting components when
           considering irradiation embrittlement in its reactor
           vessel internal's aging management program.  This is
           consistent with topical report BAW-2248 and the Oconee
           lessons learned.
                       DR. BONACA:  Now, Arkansas-1 experienced
           thermal shields and cobarold bolt cracking, right, as
           experienced in the past.
                       MR. YOUNG:  Yes, that's right.
                       MR. RINCKEL:  This is Mark Rinckel from
           Framatome, and that's correct.
                       DR. BONACA:  And so as part of the
           internal inspections, it would be also -- probably you
           have a periodic inspection of those components.
                       MR. RINCKEL:  They are in the reactor
           vessel internal as aging management program.  Yes,
           that's correct.
                       DR. BONACA:  And that program involves a
           one-time inspection, right?
                       MR. RINCKEL:  It could be one or it could
           be more.
                       DR. BONACA:  But now, if I remember, that
           inspection is also tied to an Oconee inspection.
                       MR. RINCKEL:  That is correct, yes, and
           the application.
                       DR. BONACA:  Okay.  Which means if Oconee
           performs the inspection first, then you may not
           perform the inspection for Arkansas?
                       MR. RINCKEL:  It's possible.  I think it's
           in the application we are committing to doing some
           type of inspection, but I -- you know, I think there
           will be lessons learned from the Oconee inspections
           because they'll be first.
                       DR. BONACA:  Yes, the reason why I'm
           asking that question is, since you've experienced
           already the cracking of the bolts, in both the thermal
           shields and the wiring, why would you consider the
           experience from Oconee applicable to our -- or, let me
           just put it the other way, which is why would you
           consider Arkansas to be -- you know, I mean, you have
           experienced the problem.
                       Wouldn't you want to see -- don't you have
           already the inspections to look at those --
                       MR. RINCKEL:  We do, not necessarily
           biometric inspections.  But if you remember back in
           the original issue, they thought it was stress erosion
           cracking, and a lot of it with the fabrication, you
           know, overtorquing and so forth.
                       And so they've replaced those.  And now
           what the issue is, is possibly a radiation assisted
           stress erosion cracking, which is more of an aging
           phenomena as opposed to a fabrication type issue, so
           it's kind of something different now with regard to
           aging, even though it's the same component.
                       DR. BONACA:  Okay.  But you are tracking
           the issue?
                       MR. RINCKEL:  Yes.
                       MR. PRATO:  Next page, we're going to
           continue with reactant coolant system.  ANO-1 included
           IASCC as an applicable aging effect for baffle bolts
           in its license renewal application consistent with
           topical report BAW-2248 and Oconee lessons learned.
                       ANO-1 evaluated reactor vessel internal
           cast components.  In this license renewal application,
           for reduction of fracture toughness by thermal
           embrittlement and a radiation embrittlement consistent
           with the EPRI technical report 106092.
                       This is also consistent with the topical
           report 2248 and the Oconee's lessons learned.  ANO-1
           included vent valve bodies and retainer rings in its
           reactor vessel internal's age and management program
           and its application.
                       DR. SHACK:  Just let me get back to the --
           the cast stainless was a sort of a extended topic of
           discussion for Calvert Cliffs and Oconee.  And this
           one -- it just -- I mean, it did go smoothly, right? 
           I mean, they incorporated acceptable plans from the
           lessons learned, basically, from line one, or was this
           another exchange before we iterated to a successful
                       MR. PRATO:  I believe it went so smoothly
           at ANO because they followed the topical report.  Is
           that correct --
                       MR. YOUNG:  Yes, Bob.  They -- and we also
           followed the lessons learned from Oconee.  We just
           basically incorporated what the staff determined to be
           acceptable.  And you have to remember the CASS
           includes the retical and pump casing, valve bodies,
           and those we follow the same solution that Oconee did.
                       And then the rad vessel internal's CASS,
           you had not only thermal embrittlement, but
           irradiation embrittlement.  And we address those by
           putting them in our rad vessel internalization
           management program, which is consistent with Oconee.
                       MR. PRATO:  And the last item, ANO-1
           identified cracking and loss of material of letdown
           cooler tubing, and loss of material for external
           ferritic surfaces due to boric acid wastage as
           applicable aging effects in the license renewal
           application, which is consistent with the lessons
           learned for Oconee.
                       That completes the RCS aging management
           review.  We'll go on with the rest of the system's
           aging management review.  ANO-1 did not consider
           vibration loading as an applicable aging effect for
           the HVAC system in its license renewal application
           consistent with the staff's determination that caused
           similar concerns on Oconee.
                       ANO-1 included an acceptable scope for the
           aging management review of the reactant cooling pump
           motor oil collection system inspection program.  There
           was some questions as to whether or not Oconee
           included the entire -- enough of the system based on
           lessons learned from Oconee.  ANO included the
           appropriate evaluation boundaries for the system.
                       DR. BONACA:  If I remember, for Oconee,
           the only inspection was for corrosion due to water
           intrusion in the --
                       MR. PRATO:  Wet system.
                       DR. BONACA:  -- in the drain, for the
           drain in the tanks, collection tanks.  And now, so the
           Arkansas has included in the piping of the system and
           any other component?
                       MR. YOUNG:  Yes, we included the oil
           collection pans and the piping that went down to the
           drain tank, the whole system.
                       MR. PRATO:  ANO-1 spent fuel concrete
           thermal exposure is limited to less than 150 degrees
           Fahrenheit, which is contrary to the Oconee.  They
           experienced temperature of up to 183 degrees, and
           being less than 150 degrees is less than the threshold
           for potential cracking and changes in properties of
           the concrete.
                       And the applicant addressed this directly
           in the application.  ANO-1 considered results of
           inspections and instances of reporting unusual event
           in this demonstration of aging management programs in
           the license renewal application.  In general, part of
           the demonstration was operating history.
                       The staff had a number of questions as to
           whether or not they considered operating history, and
           in a couple of cases, the applicant had to go back and
           take a look at it.  But in general, they did include
           operating history, both industry and on-site history
           for demonstration.
                       ANO-1 primary and secondary shield wall is
           reinforced concrete without any tendons, and
           therefore, monitoring of applicable forces is not
           needed.  And there was a question with Oconee's
           monitoring of tendon forces in the secondary shield
                       ANO-1 consistently considered applicable
           aging effects with cable trays and conduits located
           inside and outside of containment.
                       DR. SHACK:  Want to flip your slide?
                       MR. PRATO:  Oh, I'm sorry.  The last two
           items there on this page common to both ANO and
           Oconee, ANO meets -- and these are two of the -- two
           of the six open items.  ANO-1 needs to provide
           additional summary description for a number of their
           selected program descriptions in the FSAR supplement.
                       And a second item is ANO-1 needs to
           identify an aging management program for buried
           medium-voltage cables exposed to ground water that are
           within the scope of license renewal and subject to an
           aging management review.  This was an issue both for
           Oconee and ANO, and the applicant is developing a
           program similar to what ANO resolution -- I'm sorry,
           similar to the resolution for Oconee.
                       DR. UHRIG:  Are these primarily load
           carrying cables, or are these there for emergencies?
                       MR. PRATO:  It's load carrying.
                       DR. UHRIG:  Load carrying.
                       MR. PRATO:  Yes, sir.
                       DR. UHRIG:  So they would have heating?
                       MR. PRATO:  Right.  That's part of the
           problem, that along with moisture causes a number of
           aging effects to occur.  Slide 13.  Time limit aging
           analysis.  ANO-1 did provide a discussion on the
           cumulative effects of fatigue for the containment
           liner plate and penetration in the application.
                       ANO-1 provided an adequate TLAA for the
           reactive coolant system to address environmentally
           assisted fatigue concerns for operation beyond 40
           years in the application.  ANO-1 committed to 10 CFR
           Part 50, Appendix B, for all -- for corrective actions
           for all components within the scope of license
           renewal, including Section 11.4 evaluations.
                       ANO-1 addressed the reduction of fracture
           toughness related to susceptibility of the reactor
           vessel internal -- internals under loss of coolant and
           seismic loadings.  And its reactive vessel internals
           aging management program consistent with the topical
           report BAW-2248 and Oconee lessons learned.
                       ANO-1 addressed the applicability of flow
           of growth in accordance with the ASME boiler pressure
           code Section 11 ISI requirements in the application
           consistent with topical report BAW-2248 and Oconee
           lessons learned.
                       The last two items are ANO open items. 
           These are the last two of the six open items that
           exist right now in the safety evaluation.  The first
           one has come to both Oconee and ANO.  ANO did not
           demonstrate the adequacy of the existing pre-stress
           forces in the containment tendons by providing the
           trend lines for the containment post-tensioning system
           for the period of extended operation.
                       There were some questions as to how they
           described their program in the application.  They used
           the same aging management program that they used in
           Chapter 3 for managing the aging of those tendons. 
           The staff wanted something more for the time limit
           aging analysis, more trending, more than was required
           by the code itself and the applicants in the process
           of developing that.
                       And the last item is the boraflex
           monitoring program.  The ANO monitoring program is
           similar to Oconee's monitoring program.  However,
           sometime between the time they submitted their
           application and during the staff review, they
           collected additional data.  They plotted that data,
           and they found out that the boraflex is not going to
           last much more than five years.
                       Therefore, they had to do something under
           Part 50.  Because they felt that it became a Part 50
           issue, they turned around and told the staff instead
           of sending additional description, as the staff
           requested in the REI, they turned around and said,
           "Look, we have this problem.  We have to fix it prior
           to entering into the period of extended operation. 
           Therefore, we don't consider it a TLAA anymore."
                       Initially, the staff accepted that.  But
           as we thought about it more and more, it was a
           difficult concept for us to accept that we were going
           to give them a license for 60 years without knowing
           whether or not they have sufficient boraflex to
           maintain the shut down margin.
                       We spoke with OGC.  OGC said it's not --
           if you look at the definition for TLAA, there's one
           item that says as defined by the current licensing
           term.  They said that does not necessarily need to be
           interpreted as 40 years.  In other words, if it was a
           TLAA in the initial application for initial licensing,
           we can still consider it a TLAA in the license renewal
                       So the applicant is working out a
           resolution.  The resolution is targeted for late 2002. 
           What we're going to do is we're going to insist that
           they maintain their boraflex monitoring program until
           the resolution is not only developed, reviewed, and
           approved by the staff, but implemented as well.
                       That completes the overview.  Next item of
           topic is scoping of systems.
                       DR. SHACK:  I think it's -- when you say
           they handled the environmentally assisted fatigue in
           the application, that means basically, it came in in
           an acceptable form, and you weren't negotiating back
           and forth the way you were with Oconee and Calvert
                       MR. PRATO:  That is correct.  After
           resolving Oconee and Calvert Cliffs satisfactorily,
           the information was out there.  And they took
           advantage of that, and they took the lessons learned,
           and they submitted.  That's not to say the staff
           didn't have any RAIs on this subject.
                       If I remember correctly, we had a number
           of RAIs, but they responded satisfactorily.
                       MR. YOUNG:  Bob, in that regard -- this is
           Gary Young again with Entergy.  We did have a number
           of conversations with John Fair, and we had originally
           proposed what we felt was a complete solution to the
           environmentally assisted fatigue involving in-service
                       But we couldn't come to terms on the
           interval for the inspection, the ten year interval. 
           So we wound up, through their RAI process, revising
           our commitment to deal with whatever comes out of the
           changes that may occur with the definition of flaw
           growth tolerances for environmentally assisted
                       And also open the possibility that we
           might go back and do analysis once the methodology is
           established for doing analysis for environmentally
           assisted fatigue.  So there was an adjustment made,
           but it was through the RAI process.
                       MR. PRATO:  Are there any more questions
           for me?
                       MR. GRIMES:  Actually, before you go on to
           the next topic, Dr. Bonaca, I would like to emphasize
           that in describing these differences between Oconee
           and Arkansas, I don't want to leave the impression
           that we were Oconee bashing in some fashion.
                       Bob referred frequently to deficiencies in
           the Oconee application, and given that they were
           flying blind as one of the first two license renewal
           applicants.  I still think it was remarkable that we
           only had, I believe, it was 48 or 49 open items on
                       And the purpose of Bob's presentation was
           to explain how Arkansas was issued with six open
           items.  So we got from 48 open items to six open
           items.  And I think that if you went through and
           counted the number of times Bob referred to,
           consistent with lessons learned from Oconee, the
           Arkansas application did reflect a lot of the
           experience from Oconee and also incorporated the
           resolution of a number of the Oconee open items.
                       And that was the vast majority of the
           reasons for the difference between the number of open
           items.  You also heard reference to a number of B&W
           programs that were resolved and a staff evaluation was
           issued at about the same time that the Oconee safety
           evaluation was issued.  And so we took advantage of
                       And then there were a handful of
           circumstances where Bob explained that there were
           plant unique features, plant unique environment. 
           There were only a few cases where unit differences
           between the Oconee site and Arkansas site accounted
           for the basis for the differences.
                       So those are the categories of differences
           that we described.  You also will observe that there
           were -- there are a handful of these open items that
           will probably always be open items.  The content of
           the FSAR supplement is always going to have to have a
           finishing touch to it.  And there are going to be open
           items in the scoping area where there -- we're trying
           to pin down the precise nature of the current
           licensing basis.
                       So you can expect that future license
           renewal safety evaluations are going to have open
           items that look like that, but they're going to vary
           from plant to plant based on the differences in the
           current licensing basis.
                       DR. BONACA:  Thank you.  I must say at
           least I didn't get the impression that there was any
           bashing of Oconee.  I mean, I recognize the fact that
           Oconee was the second -- one of the first.  Anyway,
           the first two coming through the gate.  And they had
           to really start from scratch.
                       I mean, so clearly, there were many more
           open issues.  I think what we're seeing here for
           Arkansas is encouraging.  However, the lessons learned
           are being clearly implemented and used.  And the
           issues are closed before they are opened.  That's
           good.  Okay, thank you.
                       MR. PRATO:  Okay.  Next presentation will
           be on scoping.  Greg Galletti will make that
           presentation.  The next presentation is supposed to be
           Entergy.  I apologize.
                       DR. BONACA:  Yes, okay.
                       MR. PRATO:  We're just getting a little
           ahead of ourselves.
                       MR. YOUNG:  My name is Gary Young, and I'm
           with Entergy.  I'm the Project Lead for the license
           renewal project.  And one thing I'd like to make you
           aware of is about 22 years ago, I was part of the ACRS
           staff.  I worked as an ACRS fellow for one year, and
           then as an ACRS Staff Engineer for one year.
                       And that was in 1979, 1980, and 1981 time
           frame.  So I'm glad to be back, and especially in the
           context of presenting license renewal as the subject. 
           So that's a very nice subject to be talking about with
           the ACRS.
                       To my right is Natalie Mosher, who is our
           Lead Licensing Engineer for the license renewal
           project.  She's been doing all of the interfacing and
           coordinating with the NRC staff as we've gone through
           this process.  I've also got several members of our
           staff here.
                       Reza Arabli is from our structural group. 
           Jeff Richardson worked on our electrical portion of
           our application.  Mark Rinckel, who spoke earlier with
           FDI, helped us a lot with the Class 1 and the
           mechanical portion of the work.
                       Rick Buckley was our Environmental Lead
           and did a lot of work in that area.  And Richard
           Harris, who worked on our SAMA portion of our
           environmental application.  So we brought all these
           people here to help address any questions you might
           have and help facilitate your review process.
                       DR. BONACA:  I'll have a number of
           questions about specific components in scope.  I don't
           want to interrupt your presentation.  So you tell me
           when is the best time for me to ask questions.
                       MR. YOUNG:  At any time.  At any time. 
           Yes, I'd rather you ask at the point that the question
           comes up, and then we'll try to address it right then.
                       We'd like to than the ACRS for the
           opportunity to come here, and to go through this part
           of the process.  We're anxious to answer your
           questions and to help you facilitate your review. 
           We'd also like to thank the NRC staff, because we --
           this process, although it's been somewhat grueling to
           go through all the questions and the RAIs, and the
           site visits, and the meetings, we think that the end
           product justifies all the work that we've had to put
           into it.
                       And we know the staff has put an awful lot
           of work into it, too, because getting down to just six
           open items was -- I mean, we'd like to take all of the
           credit for that, but we don't deserve all the credit. 
           The NRC staff did a lot of work in order to get the
           list down to just the six open items.
                       Okay.  Next slide.  Now, Bob covered a lot
           of this, so I'll skip through a good portion of this
           and try to move on.  Again, we're located in
           Russellville, Arkansas.  We are similar to Oconee, a
           B&W 177 fuel assembly plant, a 2,568 megawatts
           thermal.  Our current license expires May of 2014, and
           with license renewal, we will have the option to
           operate until 2034.
                       And again, one issue that we always like
           to make clear, is that by getting this renewed license
           doesn't mean we will operate for 60 years because
           economic factors will dictate how long we operate even
           if we go beyond 40 years.
                       But by getting this license, it gives us
           that option that if economic factors are good, then we
           can continue to operate.  Now, you know, two is not
           included in this application or this review.  It's a
           combustion engineering unit, and so, we're going to
           have to submit a separate application for ANO-2.  And
           we plan to do that by September of 2003.
                       The ANO-1 effort, too, is going to set the
           platform for all the subsequent Entergy applications. 
           And we have a number of other plants that we plan to
           pursue license renewal on.  So we'll use this as our
           template, and the lessons that we learn from this. 
           And we have learned a lot of lessons going through
           this process.  We plan to apply to the other units,
           and then hope to come in with even cleaner
           applications in the future.
                       Next slide.  And again, as mentioned
           earlier, we did follow Oconee, and we tried to apply
           as many lessons learned as we could.  The timing of
           our application was very good relative to the
           resolution of a lot of the issues on Oconee, and the
           completion of some of the topical reports.
                       Those were completed at a point where we
           could take advantage of them in our application.  And
           as mentioned earlier, there's a lot of credit to be
           given to that for reducing the number of open items.
                       We did participate with the B&W owners
           group in developing generic aging management reports,
           which were the topical reports we talked about
           earlier.  But in addition, we developed, or
           participated in the development, of mechanical and
           structural guideline documents to help actually do the
           aging management review.
                       And those things are sometimes referred to
           as mechanical tools and structural tools.  We took
           full advantage of those, and that's part of what is
           described in Appendix C of our application.  Also, we
           looked at the RAIs that had come out on Oconee, and
           tried to incorporate as much of that as we could.
                       I certainly cant' say that we incorporated
           all of the RAI resolutions from Oconee, but we did try
           to incorporate the ones that we felt were the more
           significant ones.  And then also, we got few back from
           the NRC prior to submitting our application on what
           kind of format they would like to see.
                       And this was what became known as the
           standard format for license renewal application.  It
           was published a few months before we were to turn in
           our application.  So again, we took advantage of that,
           and formatted our application to the standard format
           that was draft at that time.
                       In addition, we had some conversations in
           meetings with the staff to discuss some of the
           details, and got some direction there.  In fact, some
           of the tables that you see in our application were
           worked out with the NRC staff ahead of time.  Now,
           again, it was the first time that we tried to use
           those kind of tables.
                       There were some problems with them as far
           as, maybe, level of detail.  But again, I think we've
           learned some lessons from that and we can apply them
           on the next applications.  In addition, we worked with
           NEI to obtain industry input.  During the final stages
           of our application, we actually had a peer review of
           the draft application with several other utilities
           through the NEI License Renewal Task Force.  And we
           get a lot of benefit from that by getting the
           perspective of other utilities on our application. 
           Next slide.
                       This slide shows the hierarchy of the
           documentation that exists to support the application
           itself.  The application is the top box on this slide,
           and then all of the other documentation below that
           represents on-site engineering reports that were
           create to support the license renewal project.
                       The first grouping of documents is what we
           call the Class 1 mechanical.  These are the ASME Class
           1 or the RCS related components.  In this grouping, we
           had eight reports that were created, eight on-site
           engineering reports.  And these benefited from the
           generic topicals that were done by the B&W owners
                       And four of those had received prior NRC
           approval so that we could actually reference those in
           our application.  And that was on the reactor vessel,
           reactor vessel internals, the pressurizer, and the RCS
                       The second grouping of documents is the
           non-Class 1 mechanical.  There were 25 system reports
           generated, and these were on systems such as the high-
           pressure ejection system, and the emergency feed water
           and main steam.  For this grouping of documents, we
           used the mechanical tools to guide us through the
           evaluation process.
                       And those mechanical tools, at the time,
           were B&W report.  They've now been transferred to EPRI
           and they're being published as an EPRI document so
           that the whole industry can use those and reference
                       In the structural area, we had seven
           reports that were broken into major structures on-site
           and commodities.  For example, we had one report on
           the reactor building, one on the OTS building, and one
           on the intake structure.  And for these reports, we
           used the structural tools, which at that time were
           also B&W document, which has also been transferred to
           EPRI and is now an industry document.
                       And then the electrical area, we had ten
           engineering reports on the cables, connectors,
           terminal blocks, et cetera.  And these were generated
           using the Sandia Spaces approach, which is also a more
           or less an industry document that we -- that the whole
           industry can use to do their review on electrical
           equipment the same way.
                       Then we had separate reports on the
           environmental issue, TLAA's, our program's document,
           and an EQ.  We separated EQ out, simply because of the
           volume of work that was required to go through a
           reevaluation on our EQ components.
                       Region 4 has just recently been at
           Arkansas on site, performing a review of these
           engineering reports as part of this review process. 
           And they're having an exit meeting on the results of
           that on, I believe, it's March the 9th.  So we think
           that went fairly well.
                       We haven't got the full results from that
           inspection yet, but it seemed to go quite well as they
           went through and reviewed the details of these
                       DR. BONACA:  In the phase of scoping, you
           know, the documentation shows that you were pretty
           much helped by the fact that you have -- you included
           all the supports in the system, and those include a
           lot of support systems that somebody else could not
           call them until later, actually.
                       MR. YOUNG:  Yes.
                       DR. BONACA:  So you have a pretty
           comprehensive scope.  You all do list in the
           application the -- your design basis events that you
           considered as the basis, I guess, as the source of
           this information.  Since you have a pretty extensive
           definition, you know, not the minimum requirement
           definition of safety-related, I was kind of surprised
           a little bit regarding the reactor vessel level
           measurement system.  And I can see how you don't have
           any specific design basis event that would reference
           that and become, therefore, excluded.  On the other
           hand, I mean, that's a true -- the only function of
           the system is to provide a safety function of some
           type, which is under certain conditions to measure
                       What was the logic for excluding it that
           you presented that was then accepted by the NRC?
                       MR. YOUNG:  Okay.  The reactor vessel
           level instrumentation was added as a post-TMI
           modification.  During the development of our emergency
           operating procedures, which is where that component
           comes into play -- first of all, in the safety
           analysis, we take no credit for vessel level
                       It's not something that we include in any
           of our safety analysis as credit.  On top of that, in
           our emergency operating procedures, they're based on
           maintaining a sub-cooling margin in the core.  And
           that is the safety source of information.  And as long
           as we can maintain the sub-cooling margin, then we
           don't get into any vessel level problems.
                       As the staff went through and reviewed the
           Entergy staff in developing all of these emergency
           procedures, they realized that the vessel level
           monitoring system is a good piece of information for
           the operators to have, but they don't take action on
           that information.  They take action solely on the sub-
           cooling margin in keeping the core cool.
                       DR. BONACA:  But once you lose sub-cool
           margin --
                       MR. YOUNG:  Again, that piece of
           information is available to the operators, but they
           take action based on losing sub-cooling margin, not
           based on vessel level.
                       DR. BONACA:  Okay.  Now, what's the
           consequences of not including that system?  Does it
           mean that --
                       MR. YOUNG:  Really, a lot of -- one of the
           things I think is important to understand is by not
           having it in the scope, license renewal doesn't change
           how it's treated.  It's still treated as a full
           quality requirements PBX type inspections,
           surveillances.  It has specifications on if it's out
           of service, how long you can continue to operate, or
           what you do if it goes out of service.
                       There's a number of requirements that
           still exist because of the post-TMI commitments, and
           those have not changed.  And they will continue
           through the extended term.
                       DR. BONACA:  Yes, that goes to the
           commitments issues.  What I mean is that, on the other
           hand, you could change commitments regarding the
           system and not have a linkage to the commitments of
           the license renewal.  I mean --
                       MR. YOUNG:  Yes, all of that, though,
           would have to go through a 5059 review process.  And
           depending on the outcome of that, you know, possibly
           having NRC staff approval before we can make any
           changes to it.
                       DR. BONACA:  Okay.
                       MR. YOUNG:  Another factor that would
           probably be important to point out here is that we did
           include the pressure boundary portions of the vessel
           level monitoring system, since that is in the scope of
           license renewal.
                       DR. BONACA:  Yes, I saw that.
                       MR. YOUNG:  And most of the other
           instrumentation would have been excluded anyway
           because it would have been an active component.  So I
           doubt that even including it would have changed very
           much on how we would have handled the aging management
           review.  Because most of it is just electrical thermal
           couples and so forth, inside the reactor vessel.
                       DR. BONACA:  Okay.  But certainly, I mean,
           right now you may have some guidelines that says that
           if it fails, you have some commitment on how long you
           can stay with the system failed.
                       MR. YOUNG:  Yes.
                       DR. BONACA:  And, you know, you can change
                       MR. YOUNG:  Well, those, I believe, are
           tech specs.  So we would have to go through NRC review
           and approval to change that.  They're not -- they're
           not just commitments.  They're actually in our tech
                       DR. BONACA:  All right.  Thank you.
                       MR. YOUNG:  Okay.  On the -- again, on the
           scoping, I think we've talked about most of this.  The
           first, we used NEI 95-10 as our guidance document for
           doing the scoping review.  And the guidance documents
           that were available from the NRC in the form of the
           rule and the draft and the review plan.
                       Safety-related definition we have -- was
           mentioned earlier as component level Q-list, and also
           a summary level Q-list that's in the SAR.  And those
           were the basis for determining what equipment was in
           the scope of A-1, which is the safety-related
                       A-2, which is the non-safety-related
           components that can prevent a safety-related function
           from being performed.  At Arkansas, most everything
           that would really fall in this category, we had
           already classified as Q, or safety related.  The
           history on that was simply that at the time that we
           were building the plant and licensing it, was that if
           you had a support system that was needed -- for
           example, a cooling water system to a pump.
                       And that cooling water system was needed
           to make that pump operable, we'd call that Q, safety
           related.  We didn't call it non-Q that could affect
           safety related.  So we had very little equipment that
           fell into the A-2 category.  We did have some, because
           it is an older plant, and there were a few things like
           seismic category two over one, that fell in this
                       But the majority of equipment was actually
           falling in the category of A-1 for us.  Next slide. 
           The A-3 category, which is sometimes referred to as
           the regulated events category, included the fire
           protection, environmental qualification, pressurized
           thermal shock, anticipated transits without scram and
           station blackout.
                       We simply used the design documentation
           for those events to come up with a listing of what was
           in scope.  And as was mentioned earlier, fire
           protection is one that we still have an open item on. 
           We're working through that.  You know, we have what we
           defined as the scope of our fire protection equipment.
                       And the -- I think it was four or five
           sets of components are being evaluated right now with
           the staff on whether or not they should have been
           included.  And we're going to have meetings on that in
           another week or two.
                       Okay.  On the next slide, going into the
           screening process, after we had scoped -- we scoped at
           the system level, the system and structure level.  And
           then we went in to do screening to identify the
           passive long-lived components that were within those
           structures and systems, that had a function that
           required an aging management review.
                       And this was, I guess, the second major
           step in the process before you got into aging.  And
           this again, was using the guidelines of NEI 95-10. 
           Next slide.  The -- once we got into the scoping and
           screening work, again, we split it up into mechanical,
           electrical, and structural, and did those pretty much
           in parallel with separate activities.
                       All of this work, of course, was done on
           a plant specific basis.  But for the Class 1
           mechanical equipment, we did have the benefit of the
           generic B&W topical reports to use, and that was a
           tremendous benefit, because when we started into the
           site specific, we could basically take those topical
           reports and simply deal with the site specific
                       So most of our actual on-site effort was
           in the areas of the non-Class 1 and the electrical and
           structural.  We didn't have any generic or topical
           type reports that we could rely upon.  I think that's
           all we have on that slide.  Next slide.
                       Okay.  The aging effects.  Again, the
           mechanical review was done on a system basis.  We went
           system by system, and did and evaluation for the Class
           1.  Again, we used the topical reports.  For the non-
           Class 1, we used the mechanical tools to help us go
           through that review process.
                       On the electrical side, we used what's
           called the spaces approach, which is based on the
           Sandia aging management guidelines.  And then on
           structural, we used a commodity and a building
           approach.  We looked at major buildings, but then
           within those buildings, we took commodities basically,
           steel and concrete, and just did an aging review on
           those commodities.
                       And based on that, we identified the aging
           effects that required management.  Okay.  Next slide. 
           After we had identified the aging effects that
           required management, then we'd identify the aging
           management programs.  And as was mentioned earlier, we
           had -- well, first of all, we had about 30 major
           groupings of programs that we've identified.
                       Now, there's probably about over 100
           actual specific programs, but we grouped them, such as
           our preventive maintenance program, which has a lot of
           individual preventive maintenance activities that we
           credited.  We just put it in the category -- one
           category called preventive maintenance.  Same thing
           with our chemistry.
                       But in the aging management programs, we
           have a group called the new programs, and then a group
           called the existing and modified programs.  And there
           were seven major categories for new programs that
           didn't exist before.
                       And I've listed a few of them here, our
           buried piping inspection program, our electrical
           component inspection, certain pressurizer
           examinations, reactor vessel internals aging
           management, which was a B&W topical issue, and our
           Smithfield fuel monitoring programs.
                       DR. BONACA:  I have a number of questions
           on these programs.  And is it a good time to ask?
                       MR. YOUNG:  Yes.
                       DR. BONACA:  On the buried pipe inspection
           program, you know, when I go back to Appendix B, and
           I'm looking at what it says, it says that the program
           consists of, you know, whenever you have an
           opportunity to expose one of these pipes because of
           maintenance or a design change, you will look at the
                       MR. YOUNG:  Right, right.
                       DR. BONACA:  And how different is this
           program from what you do right now?
                       MR. YOUNG:  The main difference is that
           right now, when we expose the piping, it's really up
           to the individual work group doing the activity to do
           an inspection, so what we want to do is formalize that
           and give them criteria so that when they uncover one
           of these pipes, they know what to look for, what sort
           of things we were concerned about.
                       We went back in history and looked at the
           times when we have exposed buried piping, and we found
           that in most cases, they did do an inspection beyond
           just the location they were either doing a repair on
           or doing instruction.  But there was no requirement
           for them to do that.
                       So we felt like that because of the review
           that came out of the license renewal, that we should
           formalize that into a set of activities or inspection
           criteria, that then they would document those results,
           and we could watch for trends.  So that's the main
                       DR. BONACA:  The other question is just on
           the top of your head, what's the frequency of, you
           know -- I mean, how many times in the past 30 years
           you had an opportunity to --
                       MR. YOUNG:  Yes, we've got about 26 years
           of operation now, something like that.  And we didn't
           go all the way back to the beginning, but we found
           that in the last ten years or so, we've had about, I
           think, two or three situation where we've had to dig
           up piping for various reasons.
                       So we're thinking that, in general, it's
           about once every five years.  Sometimes more,
           sometimes less.
                       DR. BONACA:  Okay, thanks.  Second
           question I had was on the heat exchanger monitoring
           I thought you have core problems, which I'm looking at
           performance.  I think it's --
                       MR. YOUNG:  We do.  That's a little
           confusing, the title of that program is a little
           confusing, because what we have is our service order
           integrity program, which is an existing program.  And
           it looks at service water heat exchangers.
                       But what we found in doing our review,
           there were some heat exchangers that were not covered
           by the service water integrity program.  And in fact,
           the issue that we're dealing with on the heat
           exchanger program is actually a cracking or loss of
           integrity, primarily from a seismic viewpoint.  So
           that gets into things like doing some sort of non-
           destructive testing, like maybe 80 current, or
           something like that.
                       So those -- it's a very limited set of
           heat exchangers that fall under what we call this heat
           exchanger program, because the majority of the heat
           exchangers on site are already covered by the service
           water integrity program.  So they work hand in hand. 
           We gave it that title, and we found out later that
           even the staff questioned us on that, is why are there
           so few heat exchangers in your heat exchanger
           monitoring program?
                       The reason is we have what we call the
           service water integrity program that covers most of
                       DR. BONACA:  Yes.  The third question I
           have, probably you already answered, I mean, you're
           not augmented, because you already have extensive
           pressurizer examinations --
                       MR. YOUNG:  Yes.
                       DR. BONACA:  -- to perform as part of the
           ISI, right?
                       MR. YOUNG:  Right, right.  These were some
           new commitments on very special locations.  And so we
           went ahead and called it a new program, just to kind
           of, you know, add to the visibility of it.  We, in
           fact, could have put it over into the category of an
           existing ISI program that was just augmented.
                       But we felt like it was worth making this
           one more visible in our report.
                       DR. BONACA:  Okay.
                       MR. GRIMES:  Dr. Bonaca, if I could add,
           this is Chris Grimes.  And I think that there is still
           a certain degree of controversy over the clad
           integrity inspections, and the need for them, and the
           conduct of them.  So, you know, Arkansas has called it
           out.  They have proposed to do more than we've been
           able to negotiate on a generic basis.
                       But that will continue to be an area where
           I think there's ongoing dialogue with the industry.
                       DR. BONACA:  Thank you.  On the -- let's
           see -- on the reactor vessel internal aging management
           program, the application did not specify at all the
           time when you would perform the one-time inspection. 
           But the SER states specifically, I can't remember now,
           it refers to some kind of periodic time when it will
           be done?
                       MR. YOUNG:  Yes.
                       DR. BONACA:  What's the commitment there?
                       MR. YOUNG:  Okay.  I might turn this over
           to Mark Rinckel.  He's the one that has helped us
           develop that program.  Mark?
                       MR. RINCKEL:  Yes, this is Mark Rinckel. 
           I think the commitment came through the RAI reposes to
           do one inspection towards the end of the fifth
           interval.  So that would be, you know, towards 45 to
           50 years.  But also, realizing that Oconee will have
           already inspected probably Oconee Unit 1.  And we're
           going to certainly incorporate lessons learned.
                       Now, there is, you know, a question as to
           whether or not we will have to inspect Unit 1 and O-1,
           once Oconee has, but, you know, we are -- made a
           commitment to do an inspection towards the end of the
           fifth interval.
                       DR. BONACA:  So that the fifth interval?
                       MR. RINCKEL:  Yes, the fifth interval is
           between years 40 and 50.  So it's towards -- I believe
           it's towards the end of the fifth interval is when we
           made the commitment.  Now, I'm going by memory here,
           so --
                       DR. BONACA:  I couldn't understand, in
           fact, what I was referring to.  I only know that
           clearly they were specified, although it was not
           specified in the application.
                       MR. YOUNG:  Yes, at the time we wrote the
           application, I think they were still developing some
           of these details in the reactor vessel internals
           program, and we coordinated with Oconee in coming up
           with this inspection.  Because obviously, this really
           is a generic B&W inspection effort.
                       So whatever we find, we feed to the other
           plants.  Whatever they find, they feed to us.  So we
           tried to coordinate our commitment on when we would do
           an inspection so that we wouldn't wind up doing two
           inspections at the same time.  We would sequence them
           with Oconee.
                       DR. BONACA:  Once you have all these
           agreements in place, will you amend the application
           for your own purpose, I mean, to include these
                       MR. GRIMES:  If I could answer that.  It
           is our expectation that by drawing a conclusion on the
           proposals and the commitments that have been made, and
           then are codified in changes in the FSAR, we would
           expect that after issuance of a renewed license, that
           commitments could be changed in accordance with 50.59
           and 50.71 E.
                       And that -- and much like the vessel
           surveillance program this internals program relies on
           a sharing of information that we would expect would
           feed the different B&W plants, and cause them to
           reflect on whether or not they need to make changes in
           these programs.  And whether or not they trip the
           threshold of 50.59 that would warrant a license
                       MR. YOUNG:  And we do plan to document
           that inspection frequency in the SAR supplement that
           will be, you know, issued with the new license.  So it
           will be documented.
                       DR. BONACA:  I just wanted to point out,
           at this stage, a reader like myself who come in cold 
                       MR. YOUNG:  Yes.
                       DR. BONACA:  I went through the
           application first, and I found a lot of open issues,
           vague -- not vague, but simply they were specified
           for, in this case, it will be one inspection.
                       Then I go to the SER and I find there is
           a timing of the inspection stated, and everything
           else.  So it seems as if something has been negotiated
           in between that is not reflected in the application
                       MR. YOUNG:  Yes, we don't plan to amend
           the application, but in the commitment itself would be
           contained in the SAR supplement.
                       DR. BONACA:  In the supplement?
                       MR. YOUNG:  Right.
                       MR. PRATO:  A lot of this was discussed on
           the RAI process.  It's documented in the RAIs and
           their responses.
                       MR. YOUNG:  Yes, right.
                       MR. GRIMES:  Yes, Dr. Bonaca, this is
           Chris Grimes.  Now, I would like to emphasize that
           we're at that stage in the review where we expect to
           have more dialogue with the applicant in order to
           resolve the open items.  And then, before we draw a
           final conclusion on it, a renewed license, we'd
           present the resolution of the open issues along with
           any clarifications to the safety evaluation, and it
           would feel warranted.
                       And then those would be reflected in
           changes to the SAR supplement where appropriate.  But
           the whole record will consist of the application along
           with all the correspondence since the application was
           submitted, in support of the final safety -- the
           safety evaluation, the FSAR supplement, and those will
           be the two case in terms of having a consistent
           explanation of the treatment of these issues.
                       DR. BONACA:  One last question I had on
           the problems was -- well, on the spent fuel pool
           monitoring, I think already we talked about that.  But
           I had a question regarding the mineralizers heat
           exchangers in part of the scope?
                       MR. YOUNG:  No.
                       DR. BONACA:  They're not?  Because they're
           not included in the cooling pool?
                       MR. YOUNG:  Right.
                       DR. BONACA:  Just the emergency addition
           from the service water.
                       MR. YOUNG:  Yes, right.
                       DR. BONACA:  And the last question I had
           was, when I was reading about the program of wall
           thinning inspections, specifically the major portion
           of the description, you know, regarding application,
           Arkansas claims that visual inspections have been
           effective in maintaining the integrity of the walls.
                       When I look at the SER, the SER states
           that ultrasonic testing will be neutralized in wall
                       MR. YOUNG:  Yes.
                       DR. BONACA:  Again, there is a disconnect,
           and I don't understand.
                       MR. YOUNG:  I believe that we got an RAI
           on that, and that was actually an error in our
           application.  We meant to say that in service
           inspections, instead of visual inspection, and it does
           include volumetric inspection.
                       DR. BONACA:  So you will go to --
                       MR. YOUNG:  Yes.
                       DR. BONACA:  Okay, thank you.  I think
           that's pretty much it.  Thanks.
                       MR. YOUNG:  Okay, this next slide is just
           a summary listing of the 22 existing programs that we
           had.  And of course, these are some of the major
           programs that all plants have, a Section 11 program,
           chemistry program, preventive maintenance program, and
           so on.
                       One of the things we did find that
           literally, probably 95 percent of all of the
           components and equipment, that need an aging
           management program, already have one.  And the new
           programs are really covering a limited set of
           components.  So most everything we need, we already
           had in place.
                       DR. SHACK:  Your risk informed ISI, you
           referred to as a -- translate that for me.  Is that
           every risk informed, or the Westinghouse?
                       MR. RINCKEL:  That is, as Mark -- it's the
           EPRI, EPRI method.  And I think they'll get into that
           later, but those application numbers from form ISI,
           and essentially resolve the small buried piping issue,
           which is a good precedent for future applications.
                       MR. YOUNG:  Right.  Okay.  The next slide
           here is on the time limited aging analysis, and here
           I've just listed some examples of the TLAAs that we
           had and evaluated.  This was done separately from the
           rest of the review process.  Our list of TLAAs was
           very similar to Oconee's, and of course, similar to
           other utilities.  I think we're all coming up with
           very similar lists on our TLAAs.
                       And we've already talked a little bit
           about the boraflex issue.  That was something that we
           thought was going to last for the full 60 years, but
           as we got into the review, we got some test results
           back showing that it would not.  So we're working with
           the staff now to deal with that as far as getting our
           license renewed.
                       Next slide.  Yes, that's the end of the
           discussion on the application on aging management. 
           Now I'm going to move into the environmental report. 
           In the environmental report, again, we --
                       DR. BONACA:  How long do you think you'll
           need for this portion here?
                       MR. YOUNG:  About five minutes.
                       DR. BONACA:  Well, let's go through it,
           and then we'll take a break so we are on schedule.
                       MR. YOUNG:  And the reason I say that, the
           environmental review is going extremely well.  We've
           really had no problems in that area.  Again, we used
           NEI and NRC guidance documents.  We incorporated
           lessons learned, primarily from Oconee.  We looked at
           what they had done, and tried to adjust our
           environmental report accordingly.
                       We did a new insignificant information
           review to confirm the adequacy of the category one
           conclusions that were in the generic environmental
           impact statement that the NRC staff credits for
           license renewal.
                       Next slide.  The environmental impacts in
           all areas were identified as small, which is I guess,
           an EPA definition meaning that there are no
           significant impacts.  There were no unique plant
           characteristics that would effect the environment
           based on license renewal.  And we had no threatened
           and endangered species present on site.
                       In the area of SAMA, Severe Accident
           Mitigation Alternatives, we identified 169
           alternatives to be considered.  This was based on the
           Calvert Cliffs and Oconee work that had been done
           previously.  Eighty of those were screened out as
           either being not applicable or already having been
           implemented at ANO.
                       And then 89 were subject to benefit cost
           evaluation.  Of those 89, we only found one that was
           actually cost beneficial.  It dealt with a training
           program -- or -- yes, a training item that dealt with
           the operator switchover when they're going from the
           water storage tank to the sump during ECCS
           recirculation mode.
                       That was the only on that turned out to be
           cost beneficial.  As we looked into it further, we
           determined that the training program had been
           appropriately modified, and there was no further
           action required there.
                       No SAMAs were identified that were age
           related, including the one that was cost beneficial. 
           Tom Kenyon, our NRC Project Manager on that, has done
           a very good job, I think, of going through and doing
           the review.  We had a couple of public meetings. 
           Those went quite well.
                       And we're now, I think, in the final
           stages of getting the supplemental environmental
           impact statement issued and published.  And then the
           last slide, just a quick conclusion, again we utilized
           a number of the lessons learned from Oconee and the
           industry to get to where we are.
                       We appreciate that support that we got
           from the previous applications, and from the NRC's
           previous reviews.  We were able to reduce the number
           of RAIs during the review process, as was mentioned
           earlier.  I think Oconee had over 350 and we had
           pretty close to 250.
                       Of course, we'd like to get that number
           down even further and later applications, but still
           that was quite an accomplishment.  And we also reduced
           the number of open items down to six, with taking
           benefit from those lessons learned.  In our opinion,
           the license renewal process is stable and predictable. 
           We, as well as the other utilities that we're working
           with on the NEI group, are building our applications
           off of each previous application.
                       So I think you'll see that the
           applications, for example, Turkey Point, that has come
           in fairly recently, used a lot of lessons learned from
           our application as well as Oconee.  And hopefully,
           they'll come through with a lot of the issues we're
           dealing with, and our RAIs will already have been
           dealt with in their application.  So that's all I had.
                       DR. BONACA:  Thank you.  Any additional
           questions from the members?  I thank you for your
           presentation.  I think we will hear about the
           specifics in this scoping methodology, and design
           basis events, and open items after the break.  So
           let's take a break now until 10:15.
                       (Whereupon, the foregoing matter went off
                       the record at 9:59 a.m. and went back on
                       the record at 10:16 a.m.)
                       DR. BONACA:  Let's resume the meeting, and
           we now can proceed to the next presentation on the
                       MR. GALLETTI:  Good morning.  My name is
           Greg Galletti.  I'm an operations engineer with
           Nuclear Reactor Regulation, Division of Inspection
           Performance Management.  I'm in the Equipment Quality
           and Performance Branch, and our Branch had the
           responsibility for the screening and the scoping
           methodology review for the license renewal
                       What I wanted to go over today was quickly
           give you an overview of the methodology review that we
           performed, that was both done in-house and as an on-
           site audit.  And then get into some of the findings
           from that review, our conclusions from that review and
           then we'll switch over and discuss a little bit about
           the plant differences between the Oconee and the ANO
                       With respect to the scoping methodology,
           the staff's mandate was to review the license review
           application to ensure that the information provided in
           the application was consistent with the 54.4
           regulations.  In order to do that, the staff
           implemented a two-tiered approached, one being the in-
           house review of certain design documentation. 
           Specifically, what we looked at was the license
           renewal application information and some of the
           supporting information that was provided by the
                       Some of that supporting information we had
           already in-house, for instance, the updated final
           safety analysis report, which we used quite heavily;
           the B&W ATOG, which is their emergency procedures
           guideline documentation, which the licensees have used
           to generate their own site-specific EOPs.  And we had
           the benefit of using the applicant's summary report
           from their IPE.
                       The basis for our doing the desktop review
           was, as I mentioned, first, to ensure that their
           application documentation was consistent with the
           regulations, that it encompassed all of those aspects
           of 10 CFR 54.4 that were required.  And then,
           secondarily, the supporting documentation provided the
           staff some additional insights as to how the applicant
           had implemented their procedures and processes to
           ensure that their final product was consistent with
           their LRA application.
                       In addition, some of the background
           documentation, like the updated final safety analysis
           report and the EPGs, provided the staff some better
           understanding of the design basis, certain design
           basis events that the licensee basically was
           responsible for reviewing, and gave the staff some
           additional understanding of some of the CLB issues.
                       In addition to the desktop review, we had
           the opportunity to do an on-site audit, and that was
           performed by three staff members over a period of
           about three days, and that was done on-site at the
           engineering facilities of the licensee, the applicant. 
           The purpose of the on-site audit was initially to
           verify that the documentation provided in the LRA, in
           terms of the process used to generate the scoping
           methodology, was consistent with the actual
           application in the field; that is, that what they
           described in the LRA was consistent with the actual
           application of the engineering procedures and the
           process that they -- the implementation process the
           licensee used at their own facility.
                       Secondarily, what the on-site audit
           provided us is an opportunity to look at some products
           from their LRA implementation process to ensure that
           there was consistency in those products; that is, the
           different reviewers, different engineers that were
           involved in the review basically had the same level of
           detail, same analysis approach, same processes used to
           generate their final reports.
                       And thirdly, the on-site audit provided us
           an opportunity to look more specifically at the
           implementation guidance of the licensee.  Their
           engineering reports, that Gary had mentioned earlier,
           we got to look at some of the detail associated with
           those reports, and we got to look at their actual
           implementing procedures; that is, what specific
           guidance, if you will, and operating procedure, if you
           will, for this purpose, specific guidance that the
           engineers had at their disposal that governed what
           sort of information they looked at, how they
           approached the process of developing the LRA, the
           scoping methodology and the results.
                       DR. BONACA:  This on-site visit was three
           days, you said?
                       MR. GALLETTI:  Yes, sir.
                       DR. BONACA:  Okay.  Because in the
           application and also in the NCR there is a lot of
           statements regarding the fact that the applicant
           stated that or has stated that.  So that was the
           extent of the verification process.
                       MR. GALLETTI:  The initial verification
           process, which was done in-house, which was to review
           the LRA and make it very clear what the applicant
           provided to us.
                       DR. BONACA:  Okay.
                       MR. GALLETTI:  In addition, the on-site
           audit provided what I would characterize as a
           verification and validation process for the staff. 
           That is, we were able to verify that the process used
           by the applicant matched very well with the
           description that was provided in the LRA.
                       And in terms of verification -- or in
           terms of validation, again, we got to see the end
           results.  We got to look at the specific design
           documentation that the applicant used.  We got to
           understand the scope of that design documentation, and
           that was quite important, because what we wanted to
           set out to do was establish that the licensee had done
           a credible job of reviewing their CLB and ensuring
           that they went, certainly, just beyond like accident
           analysis or just design basis events.
                       DR. BONACA:  One statement regarding the
           involvement of the staff was that you took some
           systems or some components that were not included in
           the scope by the application, and they were
           borderline.  And for those, you verified that in fact
           the contention of the applicant was correct.
                       MR. PRATO:  This is Bob Prato.  That's
           part of the scoping inspection.
                       DR. BONACA:  Yes.
                       MR. PRATO:  What Greg is talking about is
           the methodology review.
                       DR. BONACA:  Okay.
                       MR. PRATO:  We actually spent an
           additional -- there was seven us I believe.  And we
           actually did a verification that what they actually
           included within the scope of license renewal was
           consistent with the methodology, the application and
           the SER.
                       DR. BONACA:  Okay.  So there were two
           visits then to the site.
                       MR. GALLETTI:  Right, right.
                       MR. PRATO:  When we do that scoping
           methodology, we do it in really two stages.  The first
           stage is we pick a number of systems that we feel are
           important, that can be important, that were not
           included within the scope of the license renewal, and
           we verify that those systems do not meet the criteria. 
           And once we do that verification, we have a
           comfortable feeling that they've included all the
           systems within the scope, and then we go into the
           screening and the actual scoping activities.
                       DR. BONACA:  All right.  Two visits there,
           and this was meant.
                       MR. GALLETTI:  Correct, yes.  The purpose
           of our audit was to ensure that the methodology that's
           been outlined --
                       DR. BONACA:  I understand.
                       MR. GALLETTI:  -- in the engineering
           documents is consistent with the regulations.
                       Basically, one of the things that we did
           in the on-site audit was to review some of the design
           documentation as the results of the LRA application. 
           In essence, we looked at what's called the upper level
           documents.  These ULDs are essentially a library of
           documents that cover systems, structures, events, if
           you will, design basis events, as well as additional
           topics.  And by looking at those ULDs, as well as
           looking at what Gary brought up before, the Q list
           development process, the staff was able to come up
           with reasonable assurances that the process
           implemented by the applicant was consistent with 54.4.
                       If I could go on to the specific findings,
           as a result of our in-house review, as well as our on-
           site audit, we did find that the applicant's approach
           was consistent with 54.4 in terms of defining what
           safety-related equipment was consistent with A-1,
           understanding their consideration for non-safety-
           related equipment.
                       And what's been brought up already is the
           fact that many things we would characterize as non-
           safety whereby the virtue of the licensees desire are
           already safety related.  And those things above and
           beyond that, such as the seismic two over one or some
           internal flooding types of systems and components were
           brought into play as a result of the review.
                       And, finally, we did verify that the
           regulated events, if you will, the ATWS, the station
           blackout, those sorts of events were well analyzed by
           the applicant.  There is sufficient design
           documentation available to us to ensure that they had
           done a credible job of reviewing those events and
           scoping in the proper equipment components and
           structures necessary.
                       What we found is that their scoping
           process was very well defined in their engineering
           reports, and that the implementation of those
           processes was very consistent.  The audit also
           provided confirmation that the process implementation
           was consistent with the descriptions provided in the
           LRA and also consistent with the specific engineering
           procedures that the licensee had been developed for
           that purpose.
                       In conclusion, the staff made a safety
           finding that the applicant's methodology and
           implementation was sufficient to develop and we
           believe maintain the scope of the license renewal
           application over the period of extended operation.
                       If I could, I'd like to -- if there's no
           specific questions on those areas --
                       DR. BONACA:  Well, I have two questions on
           scoping that you and you with the applicant may
           answer, if I could ask them now.
                       MR. GALLETTI:  Certainly.
                       DR. BONACA:  Because we're going to be
           getting into section three, which is more of the aging
           management problems, right?
                       On scoping, I have just a few questions. 
           One is, I was looking at page 217 of the SER where it
           talks about the fact that Arkansas included components
           not addressed in the B&W 2243(a).  And I was -- one
           thing I was aware of is that some of the B&W plant
           experienced letdown system pressure breakdown,
           orifices failures.  Are those included in the scope?
                       MR. YOUNG:  The orifices are included from
           the viewpoint of pressure boundary, but they don't --
           I don't believe those particular orifices perform a
           safety function, so they weren't in there for flow
           control or anything like that.  But they were in there
           for pressure boundaries, so they were included.
                       DR. BONACA:  Pressure boundary.  So they
           are for pressure boundary.
                       MR. YOUNG:  Yes.
                       DR. BONACA:  Okay.  Thank you.  The other
           question I had was -- maybe this is just a confusion
           on my part -- in the section that speaks about the
           steam generator, there is a reference to the fact that
           the auxiliary feed water in the piping is not in
           scope.  But then when I look at the SER, and
           specifically it talks about the emergency feed water
           system, it seems to be in scope, the piping.  And I am
           confused.  I mean do you have two different systems,
           an emergency feed water system and an auxiliary feed
           water system or is it the same system and then these
                       MR. RINCKEL:  This is Mark Rinckel.  I
           believe that was an error in the original application. 
           There was an RAI on that.  That piping is in the
           scope.  I've got a picture of it here if you want to
           see it.  But it's the riser piping that goes from the
           header into the generator.
                       DR. BONACA:  If I could see that?
                       MR. RINCKEL:  Sure.  Oh, wait, let me make
           sure I brought it.
                       DR. BONACA:  So you don't have two
           systems.  Because also I found at times it's referred
           to as auxiliary feed water system; at times it's an
           emergency feed water system.  I think the application
           is auxiliary, and the SER is emergency.  So I thought
           maybe they're two different systems.  I wanted to
                       MR. RINCKEL:  I apologize, I didn't bring
           the picture of the generator.
                       DR. BONACA:  All right.
                       MR. RINCKEL:  But what it is is there is
           a main feed water header, there's two of them, and
           there's riser piping that goes up and attaches to the
           shell of the generator.  And all of that's in scope. 
           And emergency feed water has a similar application,
           but I think it goes almost all the way around, it's a
           header, and there's riser piping that goes up and
           attaches to it.  All of that is in scope.
                       DR. BONACA:  Okay.
                       MR. RINCKEL:  And what was in the
           application was an error.  That was clarified in RAI
                       DR. BONACA:  All right.  Is the mechanical
           seal package of the reactor coolant pumps in scope?
                       MR. YOUNG:  Sorry, what?
                       DR. BONACA:  The mechanical seal package
           in scope for the RCPs?
                       MR. YOUNG:  No.  The seals are replaced
           based on --
                       DR. BONACA:  Because you have periodic
                       MR. YOUNG:  Right.  So they don't have a
           long life.
                       DR. BONACA:  All right.  One question I
           had was regarding the reactor vessel head leakage
           monitoring piping, which was excluded, and the staff
           accepted that on the basis that Arkansas estimates
           that the leak flow would be within the capacity of the
           makeup system.  Could you explain to me what estimates
                       MR. YOUNG:  Well, first of all, the head
           leak-off path is after the first o-ring in the reactor
           vessel head, and it does have an orifice in it, or a
           small opening that goes into the piping.  So what we
           did is we did a review on what would happen if that
           was orifice was exposed to the full RCS pressure and
           how much flow we would get out and could we handle it
           with our makeup capacity?  And we found that we could. 
           But in reality the path to get there is so torturous
           that the flow would actually be much lower than that.
                       DR. BONACA:  Okay.  But still you
           performed the calculation.
                       MR. YOUNG:  Yes.
                       DR. BONACA:  All right.  So it wasn't just
           a judgment.
                       MR. YOUNG:  Oh, no; you're right.  Right,
           we did some analysis on it.
                       DR. BONACA:  Yes, I was just questioning
           the word "estimates."
                       On the emergency room drains there was a
           request for additional information, and then you said
           that there is a drain there that is a 10-inch drain,
           I believe, that will allow you to prevent flooding. 
           What prevents the drain to be clogged, I mean, and to
           have the flooding?
                       MR. YOUNG:  The drain that was being
           referred to there is actually a pipe.  I think 10
           inches, is that what --
                       DR. BONACA:  Yes.
                       MR. YOUNG:  It's a fairly big pipe.  It's
           actually a hole in the wall.
                       DR. BONACA:  It's a 10-inch pipe, yes.
                       MR. YOUNG:  It's an exterior wall, and
           it's just a straight pipe right through the wall, so
           there was no aging mechanism or anything that could
           come into play.
                       DR. BONACA:  So it's not a question of
           aging.  It's a question of -- no, I understand.
                       And I had one more question.  It was of
           the auxiliary building hitting a ventilation.  They
           have a function of maintaining 60 degrees during
           winter.  Now, I don't know, maybe you never get below
           60 degrees in America, but the question I had was do
           you have -- are the heating components in scope?
                       MR. YOUNG:  I believe the way that's
           handled, pressure boundary components are in scope. 
           So any portions of the system that had pressure
           boundary would be.  I don't believe we had -- you're
           talking about electrical heating elements?
                       DR. BONACA:  Yes.  Because the 60 degrees
           contingent is to prevent components from freezing.
                       MR. YOUNG:  Right.  The electrical
           equipment, like heating elements and so forth, are
           considered active, because they have to be energized
           in order to perform their function.  So they were
           excluded upon that basis.
                       DR. BONACA:  Okay.  I agree with that. 
           Okay, thank you.
                       MR. GALLETTI:  Okay, if I could, I'd like
           to switch to a quick discussion of the differences
           between the Oconee review and the ANO review with
           regard to the scoping methodology, specifically
           looking at the design basis events, which I understand
           from previous discussion was a topic of concern.
                       With respect to ANO, clearly, as part of
           their scoping methodology, they looked specifically at
           their Chapter 14 accident analysis events.  But far in
           addition to that, as part of their Q list development
           process and as part of this ULD development process
           that we discussed earlier, the applicant went far
           beyond Chapter 14, clearly looked at all of the FSAR
           as it related to the events, and then went beyond that
           still to consider the current licensing basis.
                       And if you look at that supporting
           documentation, the ULDs and the Q list development
           process, when we went through that as part of the on-
           site audit, we were able to take a look specifically
           at the types of information that the licensee had
           employed for those reviews.
                       In doing so, we confirmed that they had
           looked at operational experiences, they had looked at
           commitments they had made to the NRC regulations, they
           had looked at exemptions that were made to the
           license.  So they really encompassed all of their CLB,
           as far as the definition was concerned, in those
           reviews.  And it was a major difference between the
           two right off the bat.
                       The second difference which was brought up
           had to do with the definition of safety-related.  For
           the Oconee review, they relied on, basically, three
           barriers to the release as their definition.  For ANO,
           as was brought up, they relied on basically the 54.4
           A-1 definition -- A-2?  And A-2 definition for what
           constitutes safety-related.
                       So in that respect, we were aligned from
           the very beginning with ANO-1 in terms of coming to a
           formal and agreeable definition.
                       DR. BONACA:  Now, the difference in
           definition between the Oconee application and the
           Arkansas, did it lead to significant differences in
           the equipment that is in scope?
                       MR. GALLETTI:  I don't believe it really
           led to a change in the equipment versus led to an
           understanding of if the requirement was that you look
           at these three criterion, instead of doing that you
           looked at these criterion, what was the nexus?  How
           could the staff make a safety finding that in fact by
           using these other criteria, that you were using the
           same approach or was going to have the same effect.
                       DR. BONACA:  I don't want to reopen the
           issue of Oconee.  We know that was a difficult scoping
           process.  But as we go forth, for similar plans, I
           would expect that once we make a determination that
           certain components had to be scoped, that logic should
           extend to sister plants.  And I'm not saying that
           they'll identical these plants, but they're very
                       MR. GRIMES:  Dr. Bonaca, this is Chris
           Grimes.  I think Greg has struck on it more from the
           standpoint of our ability to understand the current
           licensing basis and the associated intended functions
           that are relied on is going to be easier when there's
           a process and a methodology associated with
           maintaining that Q list that is as comprehensive as
           the one that Entergy employs at Arkansas.
                       Our struggle at Oconee was more from the
           standpoint of understanding their licensing basis. 
           With the resultant set of components, we would expect
           to see only minor differences in plant licensing
           basis.  So it really gets to our ability to understand
           and have reasonable assurance in the scoping process
           that is benefitted by a process that maintains the
           licensing basis with such clarity.
                       MR. GALLETTI:  And I guess to close out
           this discussion, the final change, or difference,
           between the two applicants was that with the Oconee
           review, initially they looked at their accident
           analysis design basis events and then included natural
           phenomenon and external events.  And one of the areas
           of concern or issue was the anticipated operational
           occurrences and defining what those are and scoping
           those in.  And there was a lot of discussion between
           the staff and the licensee on doing that.
                       With respect to Arkansas, we didn't see
           the same issue arise, again, as a result of their Q
           list development process and their ULD development
           process.  Those anticipated operational occurrences
           were in fact considered during those review programs.
                       In conclusion, there were two open items
           as a result of the scoping methodology.  The first is
           the applicant needs to provide a technical
           justification for not including in-line flow orifice
           flow control intended function to ensure proper sodium
           hydroxide injection rate for pH control.
                       The second open item we currently have is
           to have the applicant provide a technical
           justification for not including fire protection jockey
           pump, carbon dioxide systems, fire hydrants, the water
           supply to the low-level rad waste building fire
           protection system and the piping to the manual hose
           station as being within the scope of license renewal
           and subject to an AMR.  I believe both of these issues
           have been previously brought up today.
                       DR. BONACA:  As part of this open item is
           the question also about fire water storage tank.  Is
           there a fire water storage tank or is the source of
           water --
                       MR. YOUNG:  The source of water is our
           service water system, the lake, so it's an infinite
                       DR. BONACA:  Okay.  Thank you.
                       MR. GALLETTI:  That concludes my
           presentation.  Thank you.
                       DR. BONACA:  Thank you.  Any other
           questions for Mr. Galletti?
                       MR. PRATO:  Next presentation will be
           "Common Aging Management Programs," by Meena Khanna.
                       MS. KHANNA:  Good morning.  My name's
           Meena Khanna.  I'll be talking about common aging
           management programs, and I guess I'll go ahead and
                       A common aging management program, as you
           already may know, is a program that covers and manages
           the applicable aging effects of two or more systems'
           inner structures.  Entergy identified 12 common aging
           management programs in their ANO-1 LRA, and these
           include the Chemistry Control program, the QA program,
           structures and system walkdowns, the Heat Exchange
           Monitoring program, buried pipe inspection, Wall
           Thinning Inspection program, Boric Acid Corrosion
           Prevention program, flow accelerate corrosion
           prevention, leakage detection and reactor building,
           oil analysis, Reactor Building Leak Rate Testing
           program and the ASME ISI program.
                       The staff and the contractors evaluate the
           Aging management program against the following
           elements, as discussed in the standard review plan. 
           These include scope, preventive actions, parameters
           monitored, protection of aging effects, monitoring and
           trending, acceptance criteria, corrective actions,
           confirmation process, admin controls and operating
                       Now, there's three of those that are
           covered under the Corrective Actions program, as was
           stated in the LRA.  For ANO-1, the elements involved
           corrective actions, confirmation process and admin
           controls are all discussed in the Corrective Actions
           program, so we don't address those elements in the SE
           under those.
                       Okay.  For open items, there were no
           significant open items.  However, there are a few
           minor FSAR supplements that will be needed to be done
           by Entergy.  They're listed in the SE.  We don't have
           to go into those, because they're not really
           important.  They're just basically summaries that need
           to be beefed up in the FSAR supplement.
                       Okay.  Plant differences.  If you compare
           the ANO-1 LRA to the Oconee, basically, with respect
           to the common aging management programs, Entergy's
           description of the aging management programs were
           written very closely to those for Oconee.  And we
           noted a few differences.  If you compared the elements
           to those of the SRP, there are some differences;
           however, we were still able to do a parallel review. 
           So, basically, you know, we didn't have a problem in
           reviewing those programs.
                       ANO-1 applied many of the lessons learned
           in determining their aging management programs.  That
           was the difference with Oconee.  And, finally, the
           aging management programs for ANO-1 were very similar
           to those for Oconee.  There were only a few
           deviations, and those were due to site-specific
           differences or limitations, such as the Buried Pipe
           Inspection program.
                       DR. BONACA:  Okay.  Of this common aging
           management programs, some of them are the new
           programs, right, like the Buried Pipe Inspection
           program --
                       MS. KHANNA:  Right, exactly.
                       DR. BONACA:  -- Heat Exchange and
           Monitoring program.  And some of them are existing
                       MS. KHANNA:  Exactly.
                       DR. BONACA:  Okay.  Now, okay, we have
           some questions about the new programs.  And you use
           the ten elements of the SRP.
                       MS. KHANNA:  Right.  We look at the SE. 
           That's how we actually evaluate them against those ten
                       DR. BONACA:  That's right.
                       MS. KHANNA:  A couple of them were a
           little different the way they were written up, but you
           could still get the same information if you read the
                       DR. BONACA:  Okay.  For example, the Flow
           Accelerated Corrosion Prevention program, that's a
           standard programs or existing program --
                       MS. KHANNA:  Right.
                       DR. BONACA:  -- that's being used.  In
           fact, those, in the evaluation, it's referring to
           standards that are in place already.
                       Okay.  Any questions for members regarding
           this?  Thank you.
                       MR. PRATO:  "Reactor Coolant System,"
           Andrea Lee.
                       MR. LEE:  Good morning.  My name is Andrea
           Lee, and I work in the Materials and Chemical
           Engineering Branch.  I was the technical monitor for
           the contract to review the RCS and also the lead
                       And in terms of an overview, there were
           several topical reports for the RCS system.  There was
           one for the reactor vessel, for reactor vessel
           internals, for piping and also for the pressurizer. 
           And there were several applicant action items in each
           of those reports, which license renewal applicants
           have to respond to.
                       Most of the applicant items were addressed
           in the initial application, but through the request
           for additional information process, we got expanded
           information and additional clarifications, which
           allowed us to draft the safety evaluation report with
           no open items.
                       In terms of differences in Oconee and some
           of the other applications, one difference was the
           Alloy 600 and Alloy 82/182.  The applicant is
           monitoring the locations that are most susceptible to
           cracking during the period of extended operation.  And
           the method used to identify these locations was a
           susceptibility model.  That model is similar to a
           model that was accepted for the CRDMs, and that was
           based on an EPRI model.
                       And just as a summary, the model that was
           used, there was a reference Alloy 600 item that was
           picked.  And that item was the pressurizer
           instrumentation nozzle, and that is a nozzle that was
           found leaking in 1999 -- or excuse me, 1990.  Once
           that item was selected, there is a relative time to
           crack initiation that was calculated for the item.  So
           to extend that to the other locations, a
           susceptibility factor was calculated.
                       And throughout the process there was a
           comparison of material parameters and other items,
           such as chemistry, in order to extend that reference
           to the subject component, Alloy 600 component that was
           being compared.  Once that process was done, there was
           a susceptibility factor calculated for the new item. 
           And in terms of the items that were determined to be
           most susceptible, they were all piping components in
           the pressurizer.
                       Another difference was the way small bore
           piping was handled.  And just as background, small
           bore piping, as you probably know, is piping that's
           less than four inches nominal pipe size.  And also as
           background for the ASME code, any piping that's
           between one inch and four inches, there's no
           requirement for volumetric examination.  There's just
           a surface.  And for any piping less than one inch,
           there's no volumetric or surface requirement.
                       So in light of that, and the final safety
           evaluation for the piping topical, the staff suggested
           that all applicants do a one-time inspection.  And ANO
           was unique in that they implemented a risk-informed
           process.  And through that process, they picked the
           most susceptible locations.  And from that, they're
           going to do an ongoing program.  And this was already
           approved for the current license.
                       So it was just extended into, and the
           materials and the parameters were looked at for the
           period of extended operation.  So because of that
           extension, it negated the need to have a one-time
           inspection.  This is an ongoing program, which is an
           improvement than just doing the one-time inspection.
                       And the --
                       DR. BONACA:  If I remember now, the
           previous applications we had one-time inspection in a
           susceptible location.
                       MR. LEE:  Yes.
                       DR. BONACA:  Right?  So this is now a
           periodic inspection.
                       MR. LEE:  Well, for the -- if I'm not
           mistaken, for the other applications it was one-time
           inspection for a susceptible location.
                       DR. BONACA:  Yes, that's right.
                       MR. LEE:  And just as a matter of
           interest, the susceptible locations were the
           pressurizer spray line, make-up and purification
           lines, letdown lines, and cold leg section drain
           lines.  And these are all one and a half- or two and
           a half-inch lines.
                       And during the course of the request for
           additional information process, we got very detailed
           in asking, "Well, this is a good procedure for between
           one and four.  Is this extended to less than one?" 
           And throughout the process, it's the same materials
           and the same kind of considerations, so that was
           rolled into the evaluation for all of small bore
           piping.  So we didn't have to keep making the
           distinction between less than one and between one and
                       DR. BONACA:  Okay.
                       MR. LEE:  And that's all that I prepared,
           unless you have any more questions.
                       DR. BONACA:  Now, there are no Class I
           piping fabricated from CASS-1 at Arkansas-1; is that
                       MR. LEE:  Pardon me?
                       DR. BONACA:  There are no Class I piping
           fabricated from CASS component?
                       MR. LEE:  No.
                       DR. BONACA:  In Arkansas.  Now, the SER
           refers to five leaks associated with RCS small bore
           piping --
                       MR. LEE:  Yes.
                       DR. BONACA:  -- which have been identified
           in the past?  And there's a comment that says that the
           applicant states that all leaks and cracks were caused
           by vibration of fatigue due to design problems.  And
           how far back in time -- oh, yes, I can see that.  As
           late as 1998, however, it occurred.
                       MR. YOUNG:  Yes.  Right.  What we found
           was all of those leaks that occurred before, when we
           did our root cause evaluation, identified some sort of
           a vibrational problem or a support problem or a change
           in the way we operated the plant.  And the solution in
           all those cases was to do a design change to correct
           the problem that caused the cracking.
                       DR. BONACA:  Okay.
                       DR. SHACK:  I guess I had one question. 
           I'm a little surprised to find that everybody believes
           Alloy 600 is the more limiting component over the
           Alloy 82/182, and so that when you look at the most
           susceptible Alloy 600, you've bounded the 82/182.  And
           I just wondered if any rethinking of that since the
           summer incident?
                       MR. LEE:  That may be a better question
           for --
                       MR. RINCKEL:  Yes.  This is Mark Rinckel. 
           The program that -- Alloy 600 program that Arkansas
           has relies upon the B&W Owners Group program.  And it
           includes all the Alloy 600 items and all of the Alloy
           82/182 weld locations.  Up until this point, it was
           pretty much expected that the base metal would be the
           more limiting item.  Recent events may change that.
                       DR. SHACK:  Certainly in my laboratory
           tests I wouldn't believe that.
                       MR. RINCKEL:  Well, it was because of the
           stresses and the way it was fabricated, at least our
           components and what we had seen before.  You know, the
           nozzle that cracked at Arkansas was the base metal; it
           wasn't the weld.  And so for the B&W design
           components, that's what we had seen.
                       But this is a living program, and they're
           going to have to go back and see how this new
           information affects the ranking.  And the ranking was
           done for ANO, as well as Oconee.  Oconee used a
           similar type ranking process, and identified the top
           five locations amongst the three.  But the program
           will evolve, you know, as they get more operating data
           and so forth.
                       DR. SHACK:  Yes.  It's hard to look at one
           without looking at the other.
                       MR. RINCKEL:  Yes.  So to answer your
           question, every weld and every Alloy 600 item is
           catalogued and is in the program.  It's how it's
           treated, you know, will evolve and will change.  And
           it may result in focusing on different locations for
                       MR. ELLIOT:  Barry Elliot, Materials and
           Chemical Engineering Branch of NRR.  As far as a weld,
           82/182 welds, that's a current problem.  We're
           evaluating -- the industry is a proposing a program
           right now to evaluate the entire -- all welds in the
           reactor coolant pressure boundary that are 82/182. 
           And whatever program we come up with for those welds
           will carry forward into the license renewal term.
                       DR. SHACK:  I guess I had one other
           comment too, and that was in the SER, there was a --
           they were evaluating the program for thermal fatigue,
           and they were taking credit for the primary water
           chemistry.  Now, I'll yield to nobody in my dedication
           to good primary water chemistry, just how much it buys
           you in terms of thermal fatigue, I'm a little
                       MR. ELLIOT:  We agree.  And that's why we
           have the Small Bore Piping program.
                       DR. SHACK:  Well, but if you read the SER,
           it's a preventive factor for thermal fatigue.
                       MR. ELLIOT:  Yes.  And that's why we have
           inspections, to find that out.
                       PARTICIPANT:  I don't believe that's the
           only aging management program.
                       DR. SHACK:  No.  It was just under one of
           the ten element assessments.  I agreed that it
           certainly does -- you wouldn't want bad water
           chemistry on top of thermal cycling.  Good water
           chemistry isn't going to save you from thermal
                       MR. GRIMES:  When we go back -- this is
           Chris Grimes -- when we go back and address the open
           items in the final safety evaluation, we'll check to
           make sure we haven't overstated water chemistry.
                       DR. BONACA:  Now, my understanding is that
           for this presentation it includes the reactor vessel
           and pressurizer, right?
                       MR. LEE:  Yes.
                       DR. BONACA:  Not the TLAA portions. 
           They'll be later.
                       MR. LEE:  That will be later.
                       DR. BONACA:  And I guess for this
           component, it's pretty much B&W document supply.
                       MR. LEE:  Yes.  The only component that
           did not have a topical was the pump.  There may have
           been another one, but from my recollection, the
           reactor coolant pump did not have a topical.
                       DR. BONACA:  Okay.  And there is a
           specific description here of the programs to manage
                       MR. LEE:  Yes.
                       MR. RINCKEL:  This is Mark Rinckel.  The
           other component that did not receive or have a topical
           report was the steam generator, the OTSG.  And, again,
           the review of that was very similar to Oconee, since
           they have the same OTSG.
                       DR. BONACA:  Any comments on that, Bill. 
           You had some comments yesterday.
                       DR. SHACK:  I looked at that again.  I
           have no idea -- what is the status of the steam
           generators at ANO-1?  Do they show degradation?  Are
           there plans to replace them or they're still marching
                       MR. YOUNG:  They're still marching along
           fairly well, but we are in the early stages of doing
           an evaluation for possible replacement because of the
           industry experience and the Oconee experience.  So I
           think at this point it would be safe to say we don't
           expect them to last the full 40 years, but they
           haven't started degrading to the point that we have to
           make any definite plans for replacement.  We're just
           doing some preliminary plans at this moment.
                       DR. BONACA:  Okay.  Thank you.  Any other
           questions for Ms. Lee?  No, so thanks a lot.
                       MR. LEE:  Thank you.
                       DR. APOSTOLAKIS:  Speaking of risk-
           informed stuff, what is the core damage frequency at
           ANO Unit 1 from the IPE?
                       MR. HARRIS:  For the IPE, it was 3.47 E --
                       DR. BONACA:  Please introduce yourself.
                       MR. HARRIS:  This is Richard Harris at
           Entergy.  For the IPE, I believe the core damage
           frequency was around 3.67 E minus 5.  I may be off a
           little bit, but it was a net in that area.
                       DR. APOSTOLAKIS:  You say from the IPE. 
           I mean have you done anything to it afterwards?
                       MR. HARRIS:  Yes.  We have done a couple
           of revisions to --
                       DR. APOSTOLAKIS:  And what is it now?
                       MR. HARRIS:  The current core damage
           frequency is around 5.6 E minus 6.
                       DR. APOSTOLAKIS:  Went down by, wow,
           almost --
                       MR. HARRIS:  There are some specific
           reasons that for.  One of the dominant contributors to
           risk in the IPE was the station blackout sequences
           lost that power.  Since that time, we've put in a SBO
           diesel, which took us from around 3.6 down to about
           1.90 minus 5.  And then our small break LOCAs became
           a pretty dominant contributor after that revision. 
           We've since gone to new reg 57.50.  We're initiating
           the frequencies.  And that's not the small break LOCA
           frequencies.  Our contributor's down significantly. 
           And there's some other changes included in that, and
           those are addressed in the environmental report, but
           those are the main things that took the core damage
           frequency down.
                       DR. BONACA:  And this is only internal
           events, correct?
                       MR. HARRIS:  Yes.
                       DR. BONACA:  And you've done the IPEEE as
                       MR. HARRIS:  Well, we have done IPEEE.  We
           did a vulnerability assessment for fire and a seismic
           margins method for that portion.  We haven't
           calculated a core damage frequency for our fire
                       DR. BONACA:  But you will?
                       MR. HARRIS:  Well, at this point, we'll
           see where we're going with that.  The intent of the
           IPEEE effort was to identify vulnerabilities and
           weaknesses in your operation system, et cetera.  And
           we've done that.  And we've met the intent of IPEEE. 
           But there was no requirement to generate a core damage
           frequency in that effort.  And although we did use our
           PSA models and fire methodology to do screening, we
           didn't calculate an absolute core damage frequency for
                       DR. BONACA:  Well, I guess that's not a
           question to you, but I'm really curious now how one
           can find vulnerabilities without calculating the core
           damage frequency.
                       MR. HARRIS:  Well, you can -- what you can
           do, or what we did, and I think most of the industry
           did, was we did a screening analysis.  By removing
           those components within the zone that would be
           affected by a fire in that zone, you can then quantify
           and determine what your CDF is.  And if it's below 1E
           minus 7, it screens, you're done.  If it's above 1E
           minus 7, then you go in and you look and say, "Well,
           is this -- does this really fail or does this really
           impact this equipment?  What are the circumstances?" 
           And you work on it until it either screens or it
           doesn't screen.
                       And once it gets -- if it screens, you
           stop.  If it doesn't screen, then you work on it a
           little bit more until you get to a point where you
           feel comfortable that you've adequately assessed that
           zone.  Then you go to the next zone and you do the
           same thing.  But you're not really trying to determine
           an absolute core damage frequency for each and every
           zone.  You're simply doing a screening analysis.
                       DR. BONACA:  Okay.
                       MR. PRATO:  The next presentation is on
           "Engineering Safety Features," by Bart Fu.
                       MR. FU:  Again, my name is Bart Fu.  I'm
           with EMCB NRR.  I'm also the tech monitor for the ESF
           section during ANO's license renewal process.
                       Just a brief overview of ESF system.  They
           consist of ECCS actuation part of it.  That's the
           LPI/HPI.  And core flood.  Then it also includes
           reactor building spray, reactor building cooling,
           purging, isolation.  There are a few more:  sodium
           hydroxide system, hydrogen control system.  So they're
           designed, again, for the engineered safeguard purpose
           in case of a LOCA, in case of -- well, during shutdown
           you use them to cool the core.
                       Most of the components are made of
           stainless steel and carbon steels.  In a few systems,
           we've seen 90/10 carbon nickel and also inc alloy 800. 
           And they're exposed to air, ambient air, water and
           borated water.  Those are the environments.
                       Aging effects identified.  Major aging
           effects are pretty much a loss of materials, cracking
           and fouling.  Aging management programs.  I believe
           Meena discussed the common again management programs
           a little earlier.  For a few of the systems, they have
           specific aging management programs just for the
           specific aging effects identified in the process.
                       We don't have any open items.  There is
           one item that was added to the supplemented FSAR. 
           That items calls for a one-time inspection of the
           piping in the sodium hydroxide system.  But all issues
           are resolved at this point.
                       I was told to focus on the plant
           differences.  Really, as you all are aware of, they're
           sister plants with Oconee, and even the process is
           pretty much similar.  The way I've seen, you know,
           they've got, I think, a little bit more streamlined in
           their process.  The few differences that I know of,
           one is the hydrogen control system.  It was identified
           and reviewed as part of the auxiliary system in the
           Oconee's process but as an ESF system, part of the
           ESF.  In ANO's process, under the same -- it should be
           listed the same system.
                       Under this hydrogen control system, no
           aging effects were identified for the Oconee's review
           process, but at ANO, fouling was identified as an
           aging effect.  That was the only difference for this
           system.  And it's actually fouling at the external
           surface for the EP changers.  They're exposed to a gas
           air environment.
                       The other difference, halide impurities. 
           The concern was raised during the process, and we
           talked to the plant engineers about the -- we called
           it a little bit too high of impurities in the sodium
           hydroxide system -- or sodium hydroxide.  And we
           addressed this issue.  And it resolved the item I
           mentioned that was added to the supplemented FSAR that
           calls for a one-time inspection of the system.
                       DR. SHACK:  I mean there was some
           difference in the specification for the purchase of
           the sodium hydroxide that would let you expect more
           halide here?
                       MR. FU:  I'm not sure about Oconee, but at
           ANO that was the case, yes, because they may have
           purchased sodium hydroxide from different sources. 
           But when I reviewed the Oconee's SER, this concern
           wasn't raised.  So it could be the sources, but I'm
           not so sure.
                       DR. SHACK:  What temperature is that
           system?  I mean that stuff sits around at room
           temperature, basically?
                       MR. FU:  Right.  Ambient air.  So we're
           talking about 90-some.
                       DR. SHACK:  Oh, so it's -- yes.
                       DR. BONACA:  Much of this piping is
           exposed to boron, right?
                       MR. FU:  Boron streaming.
                       DR. BONACA:  I'm sorry?  Many of the
           systems are exposed to boron.
                       MR. FU:  Right.  Or to water or boron.
                       DR. BONACA:  Yes.  So I guess -- so this
           must be controlled by some kind of -- oh, yes, boric
           acid, corrosion --
                       MR. FU:  Right.
                       DR. BONACA:  -- carbon.  Is this problem
           looking at piping inside and outside only or just
           simply focusing on the internal corrosion of piping?
                       MR. YOUNG:  Are you referring to the Boric
           Acid Corrosion Prevention program?
                       DR. BONACA:  Yes, yes.
                       MR. YOUNG:  It's external piping carbon
           steel and components.  So the program is basically a
           walkdown inspection looking for boric acid crystals. 
           And then if we find them, we trace them back to the
           source and see if it has contacted any carbon steel
           components.  And if so, corrective action is taken.
                       DR. BONACA:  Okay.  Now, this piping
           typically sits there standby with boric acid diluted
           in the water.  And what prevents internal corrosion,
           I guess, is lining of the piping?
                       MR. YOUNG:  All of the piping that has
           borated water in it is stainless steel.  There is no
           carbon steel, right.  The only time we get boric acid
           on carbon steel is if it leaks out and gets on another
           piping system that is carbon.  But all internal
           surfaces are stainless that have borated water.
                       DR. BONACA:  So mostly you're looking at
           joints, you're looking at --
                       MR. YOUNG:  Yes.  Flanges --
                       DR. BONACA:  Flanges.
                       MR. YOUNG:  -- and valve packing and
           things like that.
                       MR. FU:  And just to add to your point,
           when there's a leak, you see on the external surface
           of carbon steel, and then they have maintenance rules
           and other programs to catch it.
                       DR. BONACA:  Yes.  And so -- I mean this
           is a standard program, but you come back and there are
           no changes to it for the extended period of operation.
                       MR. YOUNG:  That's correct.  That's
           correct.  It's the existing program.
                       DR. BONACA:  Okay.  Thank you.
                       MR. PRATO:  Any additional questions? 
           Thank you.
                       The next presentation will be on
           "Auxiliary Systems," by Merrilee Banic.
                       MS. BANIC:  Good morning.  My name is Lee
           Banic, and it's a pleasure to be here to present our
           safety evaluation of the 13 auxiliary systems.  As the
           lead technical monitor for the contract on the
           auxiliary systems for the Materials and Chemical
           Engineering Branch, I'll be making the presentation. 
           Assisting me is Renee Lee, the technical monitor for
           the contract for the Mechanical Engineering Branch and
           Jim Davis of the Materials and Chemical Engineering
           Branch.  Our contractor, Idaho National Labs,
           performed the review.
                       The ANO-1 auxiliary systems consists of
           the following 13 systems:  spent fuel, fire
           protection, emergency diesel generator, auxiliary
           building sump and reactor building drains, alternate
           AC diesel generator, halon fuel oil, instrument air,
           chilled water, service water, penetration room
           ventilation, auxiliary building heating and
           ventilation and control room ventilation.
                       We reviewed the application to determine
           whether the effects of aging on the system components
           were adequately managed.  There were many kinds of
           components.  They include pumps, piping, valves,
           drains, screens, tanks, cylinders, fans and filters,
           among others.
                       The environments were water, meaning
           borated, treated and well water, external buried,
           external ambient, internal ambient and fuel oil.  The
           aging effects were cracking, loss of material, loss of
           mechanical closure integrity and fouling.
                       Of the programs we reviewed, most were
           existing programs proven by operating experience and
           common to the industry.  Many apply to more than one
           system.  The programs are:  reactor building leak rate
           testing, maintenance rule, Oil Analysis program,
           preventive maintenance, buried pipe inspection, ASME
           section 11, ISI inspections and augmented inspection,
           chemistry monitoring programs, primary, secondary and
           auxiliary systems, Boric Acid Corrosion Inspection
           program, spent fuel pool level monitoring, service
           water, Chemical Control program, fire suppression
           water supply system and sprinkler system surveillance,
           fire water piping thickness evaluation, control room
           halon fire system inspection, emergency diesel
           generator testing and inspections, reactor coolant
           pump oil collection system, alternate AC and AC diesel
           generator testing and inspection, Diesel Fuel
           Monitoring program, instrument air quality, wall
           thinning inspection, Heat Exchange and Monitoring
           program, Service Water Integrity program and testing
           of the penetration room and control room ventilation
                       We had no open items.  We found that ANO
           has shown that the effects of aging on the auxiliary
           systems will be adequately managed so that there is
           reasonable assurance that the systems will perform
           their intended functions in accordance with the
           current licensing basis for the period of extended
                       For items that are unique or different
           from Oconee, we had the Buried Pipe Inspection
           program.  This is a new program.  ANO's program is
           consistent with programs acceptable according to the
           Generic Aging Lessons Learned Report.
                       DR. BONACA:  Okay.  I had a question
           regarding the alternate AC generator.  The starting
           receivers, are they in scope?  That wasn't clear if
           they were in scope.
                       MR. YOUNG:  Yes.
                       DR. BONACA:  They are in scope.
                       MR. YOUNG:  Yes.  Everything associated
           with the, we call them the station blackout diesels,
           or the alternate AC diesels, were in scope.
                       DR. BONACA:  Part of the pressure
                       MR. YOUNG:  Yes.
                       DR. BONACA:  The other question I had was
           instrument air.  Now, the passive components or
           elements of the compressors, are they in scope?
                       MR. YOUNG:  No, not the compressors.  The
           only portion of the instrument air that was in scope
           were the portions that connected directly to a safety
           system or were part of a reactor building isolation
           system.  But the actual instrument air system itself
           is not safety grade.
                       DR. BONACA:  So you don't have any passive
           component that you had to look at.  I mean you're
           looking at it as an active component.
                       MR. YOUNG:  Well, the passive equipment
           that we looked at were pressure boundary on the tubing
           and the piping and certain valves that we credit to
           ensure that we don't have a loss of air on those
           systems that require air.  The compressors themselves
           are not -- we don't depend on them.  We have air
           accumulators for those systems that have a safety
           function that requires an air supply.
                       DR. BONACA:  Okay.
                       MR. YOUNG:  Yes.
                       DR. BONACA:  All right.  Okay.  Thanks. 
           On the -- one thing I noticed in many of these
           programs, some of them make reference to preventive
           maintenance as a program that supports it; some of
           them don't.  And yet it seems to me that preventive
           maintenance is part of those components too.  It's
           just an oversight or --
                       MR. YOUNG:  No.  You're right.  Preventive
           maintenance is a part of every system in the plant. 
           But what we did is on those systems that required some
           sort of aging management program, we looked to see if
           we had a preventive maintenance activity that we could
           credit for that.
                       DR. BONACA:  I see.
                       MR. YOUNG:  So the ones you see in the
           document there are those that we specifically credited
           for an aging management review.
                       DR. BONACA:  Because they do perform an
           aging management role.
                       MR. YOUNG:  Right.
                       DR. BONACA:  All right.
                       MR. GRIMES:  Dr. Bonaca, this is Chris
           Grimes.  And I'd like to add that Safety Evaluation
           explicitly considered in each of the programs whether
           or not we felt there was a need to credit some form of
           preventive maintenance.
                       DR. BONACA:  All right.  So I understand
           now.  We really have a benefit from it that you can
           claim for the aging purposes.  Otherwise you don't
           reference that.
                       MR. GRIMES:  Yes.  The important part is
           whether or not we felt that was a need to credit a
           preventive maintenance activity specifically for the
           purpose of managing the aging effect.
                       DR. BONACA:  On the control room, this is
           part of the system, yes.  Are the door seals and other
           penetrations in scope?
                       MR. YOUNG:  Yes.  All of the pressure
           boundary for the control room was in scope.
                       DR. BONACA:  Okay.  And I had a question
           here.  I think we discussed it before, the buried
           piping for the extent on the environment.  My question
           was more like you've had experience with it, because
           you already set it on a frequency of once almost every
           five years.  Did you have any problems you identified
           through these inspections in the past?
                       MR. YOUNG:  As far as aging problems?
                       DR. BONACA:  Yes.
                       MR. YOUNG:  The problems that we've found
           in the past have primarily been associated with some
           sort of an event.
                       DR. BONACA:  Okay.
                       MR. YOUNG:  For example, we had an acid
           leak that was routed through some abandoned piping and
           got down into some buried piping and ate away the
           coating and the pipe until a leak occurred.
                       DR. BONACA:  Yes.
                       MR. YOUNG:  And so as we went down to
           repair that, we inspected the piping in the area
           seeing if the acid had exposed any other piping.
                       DR. BONACA:  Outside of those kind of
           failures that you have seen because of root cause --
           I mean here you have a cause that --
                       MR. YOUNG:  Yes.
                       DR. BONACA:  -- have you had any
           experience of failures of buried piping that you did
           not expect?
                       MR. YOUNG:  No, no.  We haven't found any
           instances where the -- all of this piping is coated
           with a tar-type coating.
                       DR. BONACA:  Right.
                       MR. YOUNG:  And the only time we've had
           problems so far has been when that coating was damaged
           for some reason, such as the acid leak.  So as long as
           the coating is in tact, we haven't seen any problems.
                       DR. BONACA:  Okay.  Thank you.
                       MR. PRATO:  This is Bob Prato.  During the
           inspection, the aging management review inspection, we
           thoroughly reviewed the Buried Pipe Inspection
           program.  We looked at all the operating history, and
           we have an extensive write-up in the inspection
           report, which should be issued in about 30 days.
                       DR. BONACA:  Okay.  Oh, yes, on the
           Emergency Diesel Generator Testing and Inspection
           program, it's interesting that, you know, the
           frequency of tests and visual exams are managed by
           plant procedures.  Now, question, just for learning
           purposes, you know, if you make a change to those
           procedures at some point in the future, for example,
           by stepping down the frequency of the inspections or
           tests, okay, how does that tie up to be accident of
           the aging management commitments?
                       MR. YOUNG:  In the diesel, the emergency
           diesel case specifically, what we found was that the
           current inspection intervals, which are normally a
           major inspection every 18 months and then some more
           minor inspections during the surveillance period,
           which may be quarterly or monthly, was far more
           frequent than what's required for aging management. 
           So we went ahead and committed to those programs
           simply because they're existing programs.
                       But if we were only looking for aging
           effects, we would have much longer intervals than
           what's required for the active function of the system. 
           So we're crediting something that is looking for
           active failures, but we're also finding it would see
           any evidence of corrosion during those inspections.
                       DR. BONACA:  Yes.  In some cases, that may
           not be the case, however.  You may have instances
           where -- I'm trying to understand now, you have
           commitments in the FSAR addendum, and I understand
           that.  But you must have a configuration management
           program of some type that ties commitments you made
           for existing programs tied to aging, to the LRA, so
           that you can flag it through that.
                       MR. YOUNG:  Right.  The way that will work
           is we will have the commitment in the SAR that
           changes, the SAR supplement that comes out with the
           new license.  And then that will tag those specific
           procedures as being associated with a SAR commitment. 
           And then any changes that we would want to make will
           have to go through the full 50.59 review process to
           determine if we -- that we're meeting our commitments.
                       DR. BONACA:  Yes.  Okay, thank you.  I
           don't have any other questions of this issue.  Thank
           you.  Any other questions?
                       MR. PRATO:  Next presentation is "Steam
           and Power Conversion System," by George Georgiev.
                       MR. GRIMES:  This is Chris Grimes.  While
           George is getting settled in his chair up there, I'd
           like to mention that we're embarking on an effort here
           to get about three hours ahead of your schedule.  And
           so for your planning purposes, I think we now have all
           of the staff representatives to cover the afternoon
           materials.  And so we're going to continue to try and
           march through and cover the safety evaluation topics
           hopefully before lunch.
                       DR. BONACA:  Now, there is a presentation
           scheduled also, "The License Renewal Environmental
           Review Process."
                       MR. GRIMES:  Yes.  We can get Mr. Kenyon
           here.  He's not here.  He was here.  But we can bring
           Mr. Kenyon in if you want to cover that before lunch.
                       DR. BONACA:  Anyway, let's -- why don't we
           just proceed about half an hour and see where we're
           going at that point.  And then we'll make some
           decision of how long this meeting will last.
                       Okay.  So now we are down to "Steam and
           Power Conversion Systems."
                       MR. GEORGIEV:  Yes, good morning.  My name
           is George Georgiev, and I was the technical monitor
           for the steam and power conversion system, and ARGON
           National Laboratory did the actual review.
                       The steam and power conversion system
           includes four subsystems:  Main steam, main treated
           water, emergency feed water and the condensate storage
           and transfer system.
                       The materials for those subsystems are
           mainly carbon, steel.  It does include some stainless
           steel, bronze and copper.  The environment in which
           these systems operate is mostly treated water, which
           is a high purity water and steam, and the external
           environment is ambient, inside building environment in
           the reactor building turbine and the auxiliary
                       There are 11 aging management programs
           identified in the application.  As example, some of
           them are Flow Accelerated Corrosion Prevention
           program, ASME Section 11, inspection -- Wall Thinning
           Inspection program, maintenance rule and some others.
                       The components for those systems are
           standard piping components:  piping, valves, pumps,
           feedings, there are some coolants and heat exchanges. 
           And it's nothing unusual.
                       The aging effects that the application
           identified with these systems is general corrosion,
           selective leaching involving CASS and peeling and
           stress corrosion.  Again, those are expected
           degradation effects for these type of materials and
                       We did not identify any open items.  And
           as far as plan differences and Oconee and Arkansas one
           very minor.  Like, for instance, in the materials
           area, in the Oconee application, there was copper
           nickel for tubes used here.  They have something else. 
           They do have copper tubes in some of their coolers. 
           As far as the aging management programs in this plant,
           there are 11 aging management programs and Oconee's,
           there were only four aging management programs
           identified to control aging effects.
                       And that's basically it.  That concludes
           our presentation.
                       DR. SHACK:  When I read the report, I was
           sort of interested in the flow-assisted corrosion,
           that they had done 900 inspections and replaced 125
           components.  That seemed to me a larger number.  But
           I assume all that was really in the secondary system,
           by and large.
                       They're relying on check works, which, as
           I understand it, would monitor sort of the most
           susceptible regions, and then you would do an
           analytical thing to sort of assure yourself that
           you're okay.  Are they actually directly making 
           ultrasonic measurements on any part of the feed water
           system or the main steam or those would all rank low
           in the susceptibility and so they're monitoring
           something else directly?
                       MR. GEORGIEV:  I believe that the latter
           is the case in the system, including the steam and
           power conversions and the lower side.  However, they
           do have a Wall Thinning program, which is separate for
           the steam and power conversion system.  They take
           measurements of the management and compare, you know,
           how it is to what it was before.
                       DR. SHACK:  So there are direct wall
           thinning measurements then, for example, in the feed
           water system?
                       MR. GEORGIEV:  That's right, yes, there
           is.  But it's more in conjunction with the wall
           thinning problem.  See, in this plant, they have
           subdivided.  They have 11 programs, and Oconee, they
           have four.  And part of the reason, I believe, was
           explained earlier.
                       They went back to their procedures, their
           way of doing business.  And whatever they can use
           within these programs and procedures that could be
           used to do an aging management, they use it.  And in
           doing that, I guess, they ended up with 11 programs. 
           They also have more of Section 11 type of inspection
           in this steam and power conversion than Oconee had. 
           And maybe I should let them explain better why they
           set it up the way they set it, but that's how it is. 
           The staff believes it's --
                       DR. SHACK:  Yes.  Somehow I had
           interpreted the wall thinning as some sort of --
           you're looking for general corrosion, but I wouldn't
           have thought that you were doing that on systems that
           you were monitoring for flow-assisted corrosion.
                       MR. YOUNG:  That's correct.  The Flow
           Accelerated Corrosion program deals with those systems
           that have that potential effect, and we do do
           ultrasonic inspections in certain locations to measure
           the actual loss of material and then to trend it to
           see if we have a situation where we need to replace
           the piping or just continue to monitor it.
                       Then there were some other piping systems
           that were identified in this review that could be
           subject to wall thinning for reasons other than flow
           accelerated corrosion.  That's the Wall Thinning
           program that was referred to.  So it does not include
           any systems that have flow accelerated corrosion
           problems, because that's covered under that program,
           under the FAC program.
                       DR. SHACK:  So, again, coming back to my
           question then, is any part of the feed water system
           directly monitored under the DFAC program or it's one
           of the less susceptible ones, and so you're looking at
           something else as the lead component?
                       MR. YOUNG:  I'm not familiar enough with
           that program to say which one is the lead.  I know we
           do a lot of ultrasonic inspections during an outage,
           but I can't tell you specifically which system is
           included in that at this point.  We can try to get an
           answer for you, though.
                       DR. SHACK:  It just seemed to me on sort
           of a risk-informed perspective, I'd worry a lot more
           about losing that feed water system than I would many
           of the other pipes that you're probably directly
                       MR. YOUNG:  Well, I know that the way the
           program was set up, we're looking for those areas that
           are the most susceptible to FAC, and it has to do more
           with geometry and the way the system --
                       DR. SHACK:  Right, rather than risk.
                       MR. YOUNG:  Right.  Yes.  In fact, I don't
           think risk even comes to play on the FAC program.
                       MR. FU:  Are you satisfied, sir?
                       DR. SHACK:  Yes.
                       DR. BONACA:  Any other questions?  None,
           so thank you.
                       MR. FU:  Thank you.
                       MR. PRATO:  Next presentation is going to
           be on "Structures and Structural Components," by David
                       MR. JENG:  Good morning.  I am David Jeng. 
           I'm a member of the Mechanical Engineering Branch in
           Division Engineering.  And being there was for us to
           perform the review of the structure sections.  And I
           participated in the review after the submittal.
                       I'm here to provide you an overview of the
           structures and structure components review.  The
           applicant adopted so-called commodity grouping
           approach in which they put together some materials and
           environment items in different buildings as one
           commodity group in just the aging management.
                       So among the commodity groups, they have
           presented to us the steel structure -- concrete,
           prestress concrete, threaded fasteners, fiber, and as
           an embankment elastomas integral.  These are the
           sibling categories.  They categorized, and each of
           them they addressed their aging effect, their
           environment, and how they propose to manage -- they
           are proposing aging management programs.
                       The materials.  Among the key materials
           are structure steel, carbonized steel, standard steel,
           concrete precision wires, fire protection material
           like receiving for the penetrations, elastomas,
           neoprenes, careful material and PVC water stopped.
                       With regard to the environment, I think
           that, yes, so-called protected environment,
           unprotected environment, high humidity, high
           temperature, environments and high radiation
           environment and also some roll water, baronated water,
           or boric acid concentration and concrete environment. 
           These are the key environments which we have
                       Income of aging effects.  The major aging
           effects are the loss of material, cracking and also
           the change of material properties.  And also, in the
           case of prestress concrete component, we have a loss
           of prestress due to reaction and cracks of the
           preceding wires.
                       And we have not identified any open items. 
           As regard to any difference between the Oconee and the
           ANO plant, there are a few minor differences.  In the
           case of Oconee, they used Keowee dams and the
           hydraulic unit to provide power.  ANO, we did not have
           that kind of need.  Also, Oconee had the so-called
           safe-shutdown facility, which is sort of unique, as
           compared to ANO-1 situation.
                       And in the case of ANO-1, they have
           adopted so-called emergency cooling pond, which is the
           major supplier of water for emergency situations.  And
           they had to perform annual inspection to make sure the
           pond is maintained.  And what they do is they do an
           inspection to check the pond water and make sure the
           volume is there.  So this is sort of unique in the
           case of ANO-1 compared to Oconee.
                       And there are other differences, such as
           the trash racks in the infrastructure, which in the
           case of ANO-1 was not within the AMR domain.  And in
           the case of the Oconee, the turbine building -- they
           are part of the turbine building susceptibility, so
           they had to address that portion.  And this is the
           difference between the two plants.
                       So these are the key differences between
           the two sister plants.  And my presentation concludes
           at this point.
                       MR. GRIMES:  Actually, I think they're
           first cousin plants, but --
                       MR. JENG:  First cousin plants.
                       DR. BONACA:  Now, under the structural
           steel portion, there's always a reference to an aging
           effect being loss of material for the reactor building
           liner plate.  I just have a question regarding the
           steel liner of the containment.  Are there concerns
           with any corrosion of steel liner outside of the steel
           liner plate that has been addressed?
                       MR. JENG:  In so far as the particular
           issue, in the section of the steel liner operating
           floor, unless there's some expansion allowances, in
           the past history many plants did encounter some
           difficulties, corrosion, due to seepage of the waters. 
           But staff has paid attention in this area.  In past
           LRA evaluations, we asked applicant to talk about
           their previous experience.  In the case of ANO-1, I
           think they have not encountered this situation which
           we're concerned.  So they are maintaining a good shape
           of these interfaces.
                       DR. BONACA:  So you have a program to look
           at it?  I mean are you walking down, typically, those
                       MR. YOUNG:  Yes.  All of the reactor
           building liner drills are subject to a visual
           inspection on a certain frequency.  And then we if see
           any sort of signs of degradation that could indicate
           that there may be problems with the buried part of the
           liner, or the embedded part of the liner, then we
           would have to come up with some evaluations of
           programs to deal with that.  But we haven't had any
                       DR. BONACA:  Because the steel liner goes
           into the concrete --
                       MR. YOUNG:  Yes.
                       DR. BONACA:  -- and that ties into the
           liner plate.
                       MR. YOUNG:  The base.
                       DR. BONACA:  So there is a portion which
           is not visually accessible.
                       MR. YOUNG:  Yes.  Right.  But if we don't
           see any signs of any problems at the surface, where
           the water or whatever might get into it, then right
           now that's our program to determine that there
           shouldn't be any problems further down.
                       DR. BONACA:  Okay.  Regarding the
           concrete, I was looking at page 232.  There was a
           request on the part of the NRC regarding aging effects
           in an accessible area.  And the response from Arkansas
           was that the concrete used in those inaccessible areas
           was a high cement contained, low water cement ratio
           and proper curing.  And that's the reason why the
           applicant stated that we don't have to have an aging
           management program, and the staff accepted that.
                       I was kind of -- I mean that kind of claim
           could be made about any component which is not
           accessible.  And I'm not an expert in concrete
           structures, just I wanted to understand how you got
           the confidence that in fact because of these
           assertions, you don't need to look at these
           inaccessible structures.
                       MR. JENG:  Okay.  In the issue, really,
           most concern the situation where in a containment it's
           the basement level.  The liner is about two feet deep
           of concrete.  And the concern was if there was some
           significant cracks on this two-foot concrete and the
           water may seep in to become the agent for causing
           degradation of the liner underneath that.
                       The staff originally pulls the requirement
           that applicant should have an aging management
           program.  But soon the interaction and discussion
           under the context of the LAR report discussion, most
           of the staff and the applicant comes to a conclusion
           that if you are ever to conclude it's of high quality,
           low probability --
                       DR. BONACA:  I see.
                       MR. JENG:  For this reason -- on top of
           that, they had the maintenance program to perform the
           regular inspection, as required by the program.  And
           this, too, we come to the conclusion that --
                       DR. BONACA:  Okay.  I understand.  And you
           have solid records that shows that you have high
           cement contained to low water cement ratio and proper
                       PARTICIPANT:  Yes, we do.
                       MR. YOUNG:  Yes.  We went back to our
           construction records to document that.
                       DR. BONACA:  Again, on the effects of
           aging on the building, I guess, in the tendon gallery,
           there's a statement that says, "The applicant states
           that they have not observed abnormal levels of
           humidity during four contaminants in the tendon access
           gallery."  And then there's a statement that says,
           "Corrosion was identified in components during a ten-
           year and 15-year in service tendon inspections.  But
           this loss of material did not adversely effect the
           intended function of these components.
                       Now, I can agree that you had not enough
           corrosion to affect the function.  What does it give
           you the comfort that we don't need to look at it in
           the future?
                       MR. JENG:  We do look at it in the future,
           according to the tendon program.  Yes, it is power. 
           It's on the side of the anchor of the tendon --
                       DR. BONACA:  Yes, that's right.
                       MR. JENG:  -- which is part of their
           regular movement.  So it's to be looked at --
                       DR. BONACA:  Oh, so it's back to the
           program already.  The inspection and of course there
           will be corrective action if he gets to the point.
                       MR. JENG:  Yes.
                       DR. BONACA:  Now, you still have an issue
           of criteria for corrective action on the tendons that
           you have an open item on, right?  I thought there was
           an open item.
                       MR. JENG:  That's only --
                       PARTICIPANT:  On TLAA, sir.
                       DR. BONACA:  Okay.  All right.  Thank you. 
           I have no further questions on this.
                       MR. JENG:  Thank you.
                       MR. PRATO:  Last presentation on the aging
           management review will be by Duc Nguyen on the
           electrical systems.
                       MR. NGUYEN:  Good morning.  My name is Duc
           Nguyen, and I am a technical monitor in the electrical
           system performed by the INEL, Idaho National
           Engineering and Environmental Lab.
                       Today, I'm going to present the aging
           management program for the electrical system.  The
           applicant yielded commodity component to identify the
           long-lived passive electric component.  That required
           the aging management review.  And you know most
           electrical components are active, and therefore only
           three commodity time will identify.
                       The first one is the connector, terminal
           block and the cable.  The environmental -- this can
           affect the aging of this component, including the
           radiation environment and the potential humidity
           environment and chemical environment.
                       Also, cable and connector also subject to
           the frequent manipulation.  When you disconnect and
           connect them more than once, many times, it can create
           a problem, especially to have a very low voltage
           current, low voltage implementation cable and
           connector.  That can create a problem.  That is
           sensitive to small variation.
                       Talking about the aging effect, the aging
           effect of the connector it would include the potential
           aging.  Aging mechanism will be the corrosion of
           metal, electrical tresses, water, humidity effect,
           mechanical tresses and thermal radiation, aging of the
           organic components.  However, the corrosion is not
           expected because the connector usually in the -- not
           so bad on dry condition, not in the humidity
           condition.  So it's not supposed to have any corrosion
                       And mechanical tress is not significant,
           because, you know, connector does not provide any
           mechanical support.  So the mechanical tress is not
           the problem.  And electrical tresses.  Usually,
           connector can handle lots of current, so electrical
           trussing not a problem.  I had the applicant identify
           the number of splices that can have the moisture and
           the temperature effect.  And to manage that, they do
           the Component Inspection program to manage that.
                       Also, the applicant also identified
           connector that is subject to frequent manipulation,
           like the multi-pin connector screw terminal and the
           battery terminal post.  The effect of frequent
           manipulation can create wear, loose fitting, cracking,
           and this can be detected by visual inspection.  So
           they do the good maintenance practice.  That means
           when you disconnect or connect something, they use a
           good maintenance to check the resistance of that
                       And connector that are the terminating
           impeding sensor circuit also has been identified by
           the applicant.  Oxidization and corrosion of the
           connector pin could interfere with the operation of
           these circuits.  And in order to ensure this does not
           happen, Electrical Component Inspection program will
           be established to periodically inspect this connector.
                       And about a terminal block, the only thing
           that can affect the aging of the terminal block is the
           frequent manipulation.  But the applicant identified
           that, you know, the procedure will call for lifting of
           the lead from the terminal block for testing purpose. 
           This will be to control the aging effect of frequent
                       And the last one is the cable.  Cable can
           have potential aging mechanism due to corrosion of the
           conductor electrical tresses.  Water and humidity
           affect terminal degradation, aging and mechanical
           tresses.  About corrosion of the conductor, I think
           it's not a problem, because, you know, conduction
           usually covered by insulator.  So corrosion of the
           conductor is not a problem.
                       Electrical tresses can be a problem,
           because the omit hitting can be significant for the
           cable.  That I wrote in they're continually open with
           a high current, relative to that and past the limit. 
           However, most of this component, you know, only ruling
           the normal operation, this component had very low
           current.  Only during the action condition then they
           can create a high current.  But it doesn't happen very
                       Another concern is exposed to the wet
           environment can be significant aging effect for the
           medium or high voltage cable, especially the medium
           cable that you have buried in the conduced.  This can
           have significant effect.
                       Chemical attack of the organic material
           also can be potential effect of this cable.  Radiation
           tests are not significant because this is not a cable. 
           So the radiation tests for this is less than one to
           the eight rad, so it's not a problem.  To manage this
           aging effect, the applicant does the Component
           Inspection program.  They use the Inspection program
           to manage the aging effect of this component.
                       Right now I would like to talk about an
           open item that we have.  We have the concern about the
           unacceptable cable, because in the Component
           Inspection program, there's only visual inspection. 
           And there's only visual inspection with acceptable
           cable, not unacceptable.  And they view the acceptable
           cable to compare to with unacceptable, and we think
           that's no comparable, because you cannot do visual
           inspection for inaccessible cable.  And we have a
           concern with that one.  So that one is an open item
           right now.
                       DR. BONACA:  The concern is that the
           environment may be --
                       MR. NGUYEN:  Different from the
                       DR. BONACA:  -- different from what they
           should assess.
                       MR. NGUYEN:  Yes, yes.  Especially water
           tree, you know, moisture intrusion, and it can crack
           the insulation of the cable.
                       DR. BONACA:  This is a separate issue from
           GSI 168.
                       MR. NGUYEN:  Yes, different.
                       DR. BONACA:  Yes.  And Arkansas has
           committed to essentially meet the requirements of GSI
           168 once that is resolved?
                       MR. NGUYEN:  That, let me ask Arkansas. 
           Maybe they can answer that question.
                       DR. BONACA:  For medium voltage cables,
           irrespective of accessible even.  The concern which
           has been raised through GSI 168 is the ability of
           maintaining, for example, the environmental capability
           once they are heated and in wet condition for a long
           time.  I mean because there has been testing that has
           shown that under LOCA conditions, for example, they
           would fail in a gross fashion.  Has this issue been
           addressed here?
                       MR. GRIMES:  I'm going to attempt to
           explain that the resolution of GSI 168, as I
           understand it at this point, is being treated on a
           manufacturer basis; that is, that the testing results
           raise some question about the qualification techniques
           by -- manufacturer now escapes me.  But we're pursuing
           those results primarily from the standpoint of
           reflecting on the lessons learned from the testing. 
           But otherwise, I believe that when GSI 168 is
           ultimately concluded, and my recollection is it hasn't
           been concluded yet, that it's still in a process of
           trying to draw the generic insights.
                       But we still rely on compliance with EQ
           rule as an acceptable way to establish a qualified
           life.  And the process by which one maintains
           qualified life to reflect on testing insights and
           whether or not the qualification basis needs to be
           revisited at any point, either in the current term or
           the extended period of operation.
                       DR. BONACA:  The reason I asked that
           question is that, first, the issue of GSI 168 is
           pretty high on the agenda of this Committee of the
           ACRS.  And second, for Oconee, if I remember, we had
           an implicit discussion in the SER regarding the in
           fact medium voltage cables.
                       MR. GRIMES:  Non-EQ medium voltage cables.
                       DR. BONACA:  And the need for walkdowns of
           those components.  Yes, I agree with you, that the EQ
           program requirements are sufficient to --
                       MR. NGUYEN:  Wait, wait.  This one is not
           EQ.  We talk about the non-EQ cable.  GSI 168, I think
           they talk about EQ cable, so that's a different issue
           here.  We're talking about here a non-EQ medium
                       MR. PRATO:  Cables found outside, exposed
           to the environment, buried.
                       MR. NGUYEN:  Yes, buried.
                       MR. PRATO:  And could be exposed to
                       DR. BONACA:  Sure.  And I can see this,
           and you're asking for a program.
                       MR. GRIMES:  If I could suggest, this is
           equivalent to the open item that we had on Calvert and
           Oconee and are still pursuing in generic aging lessons
           learned in terms of establishing some consistent basis
           for concluding that on the treatment of the potential
           for moisture intrusion on medium voltage buried
                       DR. BONACA:  Yes.  Well, the reason why I
           raised that issue was only because of the
           characterization of buried cable.  I thought that the
           open issue for Oconee was all medium voltage cable.
                       MR. GRIMES:  No.  It was inaccessible,
           whether the inaccessibility comes through being buried
           or being hidden in a conduit.  But the issue is
           referred to both ways, as buried or inaccessible.  But
           essentially it's the same issue.
                       DR. SHACK:  But didn't Oconee have a
           program to look for sort of warm temperature --
                       DR. BONACA:  That's right.
                       DR. SHACK:  -- or radiated conditions on
           the medium --
                       DR. BONACA:  Absolutely.
                       DR. SHACK:  It was non-EQ, but it was a
           general kind of --
                       DR. BONACA:  They offered the program, and
           the program essentially was addressing all cables. 
           They had pictures of cable they had identified in
           locations where clearly it was accessible, because I
           took pictures of it, and it was showing the damage of
           high heat and water intrusion on the jacket of cable.
                       DR. SHACK:  That's what I recall.  They
           looked at the cabling and then they looked where the
           cabling would be in a high temperature, high radiation
           area, and then they would do inspections there.
                       DR. BONACA:  Right.
                       MR. NGUYEN:  We talk about inaccessible
           cable, and I believe at Oconee they committed to test
           everything for this kind of cable.  Look at the
           manhole to see if the water collects so they can make
           a comparison to see how the inaccessible cable -- but
           they commit to do the test.
                       DR. BONACA:  They committed to do
           walkdowns and inspect and repair the cable that showed
           clear degradation.  That's all they did.
                       MR. GRIMES:  But my recollection is Dr.
           Shack is correct, that it's not simply water intrusion
           by itself that causes a concern about potential
           degradation of the cable insulation.  It's the
           condition of buried cables or inaccessible cables that
           also are exposed to other stressors that might cause
           -- that would provide a basis for you to infer from
           conditions of accessible cables the point at which
           buried cables would become in jeopardy and would need
           to be explicitly checked.  And that was the nature of
           the program.
                       MR. YOUNG:  If I may here, as far as the
           Arkansas situation, we have committed to an Electrical
           Component Inspection program that's similar to Oconee
           for the accessible cables in high temperatures and so
           on.  So we are on the same path with them there.  This
           open item dealt with those limited set of cables that
           were buried or inaccessible, and we are working on
           writing a resolution on those that will also match the
           Oconee resolution which is to do some sort of testing
           on these cables that may be exposed to that kind of
                       DR. SHACK:  Is this testing a leakage
           current thing or something?
                       MR. YOUNG:  It's somewhat undefined at
           this point, and -- yes, Jeff, go ahead.
                       MR. RICHARDSON:  Yes.  This is Jeff
           Richardson with Entergy.  Right now, the way the
           electrical component -- our response to this
           particular issue is being formed.  The test is non-
           specific.  There are several different tests that have
           been proposed, including power factor type testing. 
           We're not going specifically.  It will be condition
           driven based on the cable and the situation.  But the
           test --
                       DR. SHACK:  But you'll do testing of some
                       MR. RICHARDSON:  Yes.  The plan at this
           point, or the direction we're taking at this point is
           to follow Oconee's lead into the medium voltage
           inaccessible cables that are within the scope.  Where
           appropriate, where they're exposed to either extended
           periods of being exposed to water and also in
           conjunction with thermal stresses such as high system
           voltage, greater than 25 percent system voltage for a
           period of time, then those would be subjected to some
           form of testing to be determined as appropriate for
           those conditions.
                       DR. BONACA:  So there is a commitment you
           said, and that's going to be in the FSAR.
                       MR. YOUNG:  Yes.  We've already got a
           commitment to the visual inspection portion of it. 
           And in response to this open item, we'll make a
           commitment for the varied cable portion.
                       DR. BONACA:  Let me just make an
           announcement outside of schedule here.  I've been told
           the Agency will close at 12 noon, which is now. 
           Because, I guess, of weather conditions, they're
           sending people away.  I would like to propose the
           following here:  We don't have much left on the
           agenda, and I think we can condense the overview on
           the license renewal and environmental review process. 
           So I would like to do is to continue.  Just take five
           minute break right now and then continue this meeting
           for next half an hour.  That should be allowing to go
           to discussion, and then end the meeting.  I think we
           can do that.
                       MR. GRIMES:  Dr. Bonaca, the staff is
           ready, willing and able.  We want to march through the
           time limit at aging analysis.  I sent a runner to try
           and track down Mr. Kenyon so that we can try and get
           through the environmental review as well.
                       DR. BONACA:  Well, let's try to do that.
                       MR. GRIMES:  Okay.
                       (Whereupon, the foregoing matter went off
                       the record at 12:00 p.m. and went back on
                       the record at 12:08 p.m.)
                       DR. BONACA:  We want to review the TLA. 
           I believe that's the next step of the agenda.
                       MR. ELLIOT:  My name is -- my assistant
           here is not here.  My name is Barry Elliot.  I'm with
           the Materials and Chemical Engineering Branch of NRR.
                       There are ten TLA issues that cover
           mechanical areas, materials areas, corrosion areas. 
           So it covers a broad spectrum of Division of
           Engineering functions.  People who have reviewed these
           area functions are Hanz Asher, Carol Lauron, John
           Fair, Cliff Munson, Amar Pal, Mark Hartzman, Andrea
           Lee and Jay Rajan.
                       The first TLA is reactor vessel neutron
           embrittlement.  There are two regulations that are
           reviewed with respect to this issue.  They are the PTS
           rule, which is 10 CFR 50.61 and Appendix G of the
           regulations, which establishes upper-shelf energy
                       In this case, the applicant did a plant-
           specific PTS evaluation.  And as far as the upper-
           shelf energy, it would be a plant-specific upper-shelf
           energy evaluation.  And it turns out that as far as
           the upper-shelf energy, all the forgings would be
           above 50-foot pounds at end of license, end of renewal
           license.  However, the welds would not -- and an
           Appendix K analysis was done to show that it had
           adequate safety margins.  These methodologies are the
           same as those used by Oconee, the only difference
           being the plant-specific variability.
                       The next issue is metal fatigue.  The
           applicant evaluated the impact and environmental
           effects on the reactor coolant pressure boundary
           components.  And the evaluation indicated that the
           surge line and the high pressure injection make-up
           nozzle and safe ends may exceed a cumulated usage
           factor of one during the period of extended operation. 
           As a result, the applicant proposes a program which
           will include one or more of the following options: 
           refinement of the fatigue analysis, repair,
           replacement and management of the effects of fatigue
           by a program that would be approved by the staff.
                       Essentially, this is very similar to what
           Oconee did.  The difference is that Oconee is counting
           the cycles and may have to perform corrective action
           similar to ANO-1.  ANO-1 already extrapolated a number
           of transients in 60 years and has identified the
           potential locations with usage factors that may exceed
                       DR. SHACK:  But they also do a monitoring
           program, don't they, so they'll be able to actually --
                       PARTICIPANT:  Count.
                       DR. SHACK:  Yes, count.
                       MR. ELLIOT:  Yes, they do that.
                       MR. FAIR:  This is John Fair with the
           staff.  They haven't proposed to do this by a
           monitoring program similar to Oconee, but they do have
           a cyclic -- they do keep track of cyclic transients. 
           But they don't propose to use the program to manage
           the effect.  So they did an up-front calculation,
           whereas Oconee is going to monitor cycles.
                       MR. ELLIOT:  The next issue is
           environmental qualification.  The applicant evaluated
           environmental impact of extended operation on all
           long-life, passive and active electrical components
           within the scope of the rule.  And the components
           either had analysis that remained valid for the period
           of extended operation, had analysis that projected to
           the end of the period of extended operation or had a
           program to reanalyze or replace components prior to
           exceeding the qualified life of the component.  This
           is very similar to the program for Oconee.
                       Next issue is concrete reactor building
           tendon prestress.  The applicant indicates concrete
           reactor building tendon prestress that we've managed
           during the period of extended operation, using ASME
           code, Section 11 In-Service Inspection program.  This
           is an open issue for us, because although this is
           similar to Oconee, in the case of Oconee, they have
           addressed the program in sufficient detail and given
           us sufficient characteristics to approve the program. 
           In the case of ANO-1, they have not, and they must
           address the attributes and characteristics that are in
           this overhead.  And then we'll be able to resolve this
                       The reactor building liner plate fatigue
           analysis.  The applicant had demonstrated that the
           original fatigue analysis is valid for the extended
           period of operation.  In this case, the methodologies
           used by Oconee and ANO-1 are the same.  Individual
           plant-specific transients may be slightly different.
                       Next issue, aging of Boraflex and spent
           fuel pools.  Boraflex is a neutron absorber.  It is
           used to maintain subcriticality margin in the spent
           fuel during storage or transfer of fuel.  Tech specs
           require applicants to maintain the subcriticality
           margin.  The applicant has determined that the
           Boraflex has degraded more rapidly than expected and
           will not last through the current 40 years.  They've
           done an analysis, and that's the results.
                       As a result, in order to satisfy the
           license renewal rule, they're going to have to propose
           a program to monitor the aging of the Boraflex.  This
           is an open issue at the moment for ANO-1.  They have
           to propose a program.  Oconee has already a defined
           program, and that's the difference.
                       Next issue, as far as reactor vessel
           underclad cracking, the issue here is that when B&W
           fabricated the vessels, the course grade forgings had
           cracks in them during fabrication, intergranule
           separations during the cladding operation.  We're
           talking about defects on the order of a tenth of an
           inch.  This was evaluated in the first 40 years, and
           in the next 60 years the evaluation goes to higher
           neutron fluences and also more fatigue crack growth.
                       The analysis was a fraction mechanic
           analysis, and it was determined to be acceptable by
           the staff for the 60-year license.  Both Oconee and
           ANO referenced the B&W topical report, which contained
           analysis applicable to both Oconee and ANO-1.
                       Next issue is the reactor vessel
           instrumentation nozzle.  The applicant has evaluated
           the impact of flow-induced vibration on reactor vessel
           instrumentation nozzles.  Analyses have been projected
           to the end of the period of extended operation.  The
           flow-induced vibration stresses are below the
           extrapolated fatigue limit.  Oconee and ANO-1 used the
           same methodology in evaluation of flow-induced
           vibration -- well, ANO-1 used the same methodology as
           used in Oconee reactor vessel internals.
                       DR. SHACK:  Do they do this because
           they've actually had a flow-induced vibration problem
           or is this just part of their basic design?
                       MR. FAIR:  This is John Fair again.  This
           is part of the basic design on this.  They just
           extrapolate out the originally designed for -- what is
           it, 12 cycles or something like that?  And they
           extrapolate it out in order of magnitude, very
           conservative extrapolation.
                       MR. RINCKEL:  This is Mark Rinckel with
           Framatome.  There were problems with the original end
           core modern system design.  There were three-quarter-
           inch on 60 pipe that went at the bottom of the vessel. 
           Those cracked off at Oconee at one, and then they
           built them up and repaired them all.  And then this
           fatigue analysis that John's referring to was with
           regard to the new design.
                       DR. SHACK:  So you basically just beefed
           the up enough --
                       MR. RINCKEL:  We beefed up, yes.
                       DR. SHACK:  -- so the stresses are very
                       MR. RINCKEL:  Yes.  They were not designed
           proper to begin with, and that was corrected.
                       MR. ELLIOT:  The next issue is a leak
           before break.  The applicant did a -- there was a
           leak-before-break analysis done in the first 40 years. 
           The applicant has evaluated the impact of fatigue
           crack growth and thermal aging on leak-before-break
           analysis of the reactor coolant system, main coolant
           and piping.  The floor growth analysis remains valid
           for the period of extended operation.  And the flaw
           stability analysis used lower bound casts, fostering
           a stainless steel fracture toughness properties for
           the reactor coolant pump nozzles in adjacent welds.
                       And the adjacent wells will have adequate
           fresh stuff at the end of the period of extended
           operation.  That's the result of the analysis.  Oconee
           and ANO-1 used the same basic approach.
                       The last issue is the reactor coolant pump
           motor flywheels.
                       DR. SHACK:  Excuse me, that must be a
           postulated flaw assumption, right?
                       MR. ELLIOT:  Yes, it is a postulated flaw.
                       DR. SHACK:  What's the postulated flaw?
                       MR. ELLIOT:  It's a leak before break. 
           You have to have a leakage size.
                       DR. SHACK:  Oh, okay, okay.
                       MR. ELLIOT:  It's criteria.  There's
           leakage-size flaw, and then there's a stability flaw. 
           There's two size flaws, and that depends on the
           leakage and the size of the pipe and everything.  So
           there's not one flaw; it's a through-wall flaw.
                       DR. SHACK:  It's a through-wall flaw.
                       MR. ELLIOT:  It depends on the size of the
           pipe and --
                       DR. SHACK:  They're not just counting to
           go through the wall.  They're actually looking at the
           through-wall flaw and making sure it's stable.
                       MR. ELLIOT:  Right.  That's for the
           stability analysis.  For the fatigue analysis, it
           starts with a small flaw.
                       And then the final issue is the reactor
           coolant pump motor flywheels.  The applicant has
           evaluated the impact of fatigue on the growth of
           cracks in the reactor coolant pump flywheel bore
           keyways.  This is another postulated flaw.  There is
           no flaw there.  And the analysis is projected --
           growth remains acceptable for the period of extended
           operation.  There is nothing unique about this
           analysis.  This is standard fatigue crack growth
                       Any questions?
                       DR. SHACK:  Is that in a standard design
           procedure for all coolant pumps with keyways?  Do they
           have to do this?
                       MR. ELLIOT:  No.  There is a different
           here, now that I think about it, a little different. 
           They did the analysis -- in the case of Oconee, they
           proposed a program.  Instead of doing the analysis to
           the reactor pumps, they do inspections, periodic
           inspections.  So you have this alternative.  You can
           either do analysis or you can do inspections.  And at
           ANO-1 they chose the analysis, and Oconee chose the
           inspections.  And this is a continuation of each of
           their licensing bases.  The ANO-1 licensing basis was
           the fatigue study, and the Oconee licensing basis was
           the inspection program.
                       DR. BONACA:  Okay.  One last question I
           have is regarding the Boraflex.  So the expectation is
           that there will be a solution needed prior to entering
           the 20 additional years of life.
                       MR. PRATO:  In reality -- this is Bob
           Prato -- in reality, they had submitted a program that
           was consistent with Oconee.  We asked for some
           additional description in our RAIs, and that's when
           they found the data would -- that the Boraflex would
           not last the current licensing term.
                       DR. BONACA:  All right.
                       MR. PRATO:  They did not respond to our
           description.  They said it's no longer TLAA.  Staff
           took exception.  So, basically, what they're going to
           provide is that same program they had initially with
           the additional information we requested in our RAI. 
           And from the staff's perspective, that should resolve
           the issue.
                       DR. BONACA:  Okay.  Thank you.
                       MR. ELLIOT:  Thank you.
                       MR. PRATO:  That concludes the safety
           inspection review.  Tom Kenyon, for the environmental
           evaluation review, will give his presentation at this
                       DR. BONACA:  And the plan we have right
           now is to have a brief overview of this environmental
           review process, maybe ten minutes or so.  Then I would
           like to just have a brief discussion among the members
           here, and then a decision on how we're going to
           address this at the full committee next week.
                       MR. GRIMES:  Yes, sir.  Dr. Bonaca, this
           is Chris Grimes.  I would like to introduce Tom
           Kenyon, who's the Environmental Project Manager for
           Arkansas.  I would like to remind you that the staff
           made presentations to the Committee about the
           regulatory guide and the standard review plan for the
           environmental process.  Tom's going to just basically
           run through the main features of the review process
           and our NEPA obligations.  And he should be able to do
           that in about ten minutes.
                       DR. BONACA:  Okay.
                       MR. KENYON:  I'll try.  My name is Tom
           Kenyon.  I'm an Environmental Project Manager with the
           Generic Issues Environmental, Financial and Rulemaking
           Branch.  I've been asked to make a presentation
           regarding the environmental review process that we
           undertake under the license renewal reviews.
                       I plan to talk a little bit about the
           statutory requirements.  We'll focus on the National
           Environmental Policy Act.  I'll be talking about the
           review process that we go through and give you an idea
           of the schedule.  My goal is to just kind of put into
           perspective the environmental protection activities
           that we undergo for license renewal purposes.  And the
           presentation is for information only.  We're not
           asking for a letter in this area.  Of course, you
           always have the option, if you want to, to provide
           your views.
                       DR. BONACA:  We don't intend to write a
           letter on this now.
                       MR. KENYON:  Thank you.  Some of you may
           recall that Barry Saltman had made a presentation like
           this a couple years ago, and I think it's safe to say
           right now that not a whole lot has changed, other than
           we've implemented the process, we've completed the
           review on two plants, Calvert Cliffs and Oconee, and
           we're undergoing a review right now of three
           additional plants.
                       As you well know, the NRC is governed by
           the Atomic Energy Act and the Energy Reorganization
           Act of '74.  There are a number of other statutes that
           define our mission in terms of the environmental
           protection mission as well, but I'm going to focus on
           the National Environmental Policy Act.
                       This slide gives you -- it's a slide of
           all of the -- the entire license review process.  The
           top path shows the path that you're used to working
           in.  The Part 54 review includes the inspection
           activities, it includes the safety review that Mr.
           Prato is involved in, and of course, it includes the
           ACRS' review as well.  Now, the bottom path is the
           path that we follow as part of our Part 51 review. 
           And I'm going to go into more detail about each one of
           these steps as we go through this presentation.
                       Now, I'm going to give you a bit of
           background on the National Environmental Policy Act. 
           It was enacted in 1969, and it requires all federal
           agencies to use a systematic approach to consider the
           environmental impacts of certain decisionmaking
           proceedings.  It's a disclosure tool that involves the
           public and involves the process in which we gather
           information, we document the findings that we have and
           then we invite public participation to evaluate it.
                       The NEPA process results in a number of
           different documents, but the one that we're going to
           focus on is the Environmental Impact Statement, which
           describes the results of our detailed review, that is
           the environmental impacts for major federal actions
           that have the potential to significantly affect the
           quality of the human environment.  And the NRC has
           already determined that NEPA -- I'm sorry, that
           license renewal is just such a major federal action.
                       Now, to implement NEPA, the staff has its
           regulations in Part 51.  And the regulation describes
           the process that we undertake, it outlines the
           contents of the Environmental Impact Statements, and
           it also defines the objective of our review.  And I'm
           going to have to read this, because it's a big
           unwieldy.  Our objective is "To determine whether the
           adverse environmental impacts of license renewal are
           not so great that preserving the option of license
           renewal for energy planning decision-makers would be
                       Now, that's a quote from the regulations. 
           It's Part 51.95.  I prefer to just think of it as
           we're trying to determine whether or not the
           additional 20 years of operation is acceptable from an
           environmental standpoint.
                       Now, if I could go back to the previous
           slide for a second.  Early on when it was decided --
           when we were developing the license renewal process
           back in the '80s and '90s, it was recognized that the
           original Environmental Impact Statements that were
           developed to support the construction permits and the
           operating licenses about 20 or more years ago would
           have to be updated to reflect the additional 20 years. 
           And so the NRC undertook a rulemaking effort to modify
           Part 51 and to have it reflect the license renewal
                       As part of the rulemaking effort, the
           staff developed a generic Environmental Impact
           Statement, known as the GEIS, which took a systematic
           look at the thousands of hours of operation of the
           nuclear power plants to help us identify where our
           potential environmental impacts could occur.  In
           addition, the staff developed regulatory guidance, the
           Environmental Standard Review plan, and a regulatory
                       Now, the GEIS was used, as I said earlier,
           as a supporting document for the Part 51 rulemaking,
           but it's also an integral part of our review process,
           and so I wanted to go in a little bit of detail as to
           what's enclosed in that document.  The GEIS was
           published as NUREG-1437 and was issued in 1996. 
           During the development, the staff met with the states,
           the Presidential Council on Environmental Quality. 
           They met with the Environmental Protection Agency and
           other groups, and they had a series of public
           workshops to develop the final GEIS.
                       And suffice it to say that during this
           period the staff was trying to identify what
           environmental impacts needed to be reviewed in license
           renewal.  And we identified a total of 92 issues. 
           When the staff evaluated those issues, they found that
           some -- noticed that some of those were generic in
           nature; that is that they are common to all plants or
           a class of plants regardless of where they're sited. 
           And so the NRC wanted to kind of categorize them
           differently, and so we came up with this Category 1,
           Category 2 scheme, Category 1 being, of course,
           generic issues, and Category 2 requiring plant-
           specific review.
                       Now, I did not mean that we do not look --
           well, I'm trying to figure out what I can skip
           through.  An example of Category 1 issue is a the off-
           site radiological impacts.  And the staff took a look
           to see if whether or not it was likely that there
           would be an increase in off-site radiological impacts
           due to the increased operation.  So they did a
           historical review and determined that the public --
           and determined that the doses to the public have been
           maintained below those allowed by the regulations.
                       And staff has not been able to see any
           reason why the doses would increase due to the
           extended operation, provided that the control programs
           and the monitoring programs are maintained and
           implemented acceptably.  So because the expected
           radiological impacts apply to all plants in a similar
           manner and that the impact is considered small at all
           the plants, the staff concluded that this could be
           addressed on a generic basis.
                       Now, that does not mean that we do not
           need to look at this issue anymore.  What it means is
           that we look only to see if there's significant new
           information that would cause us to change the
           conclusions that we made five years ago.  As you can
           see, there are 69 issues that were resolved in this
           manner, considered generic issues, and the remainder
           of the 23 issues that were identified need to be
           addressed on a plant-specific basis.
                       Now, when the staff completed the GEIS in
           '96, we evaluated it to determine their impact
           significance, in terms of whether or not their
           environmental impacts are likely to be small, moderate
           or large.  And what we determined was that the generic
           issues, the Category 1 issues, all had a small impact
           on the environment, and that the impacts of Category
           2 issues could range across the full gamut, from small
           to large, depending on the particular site and the
           particular issue.  I guess I don't know need to show
           that slide.
                       Now, this slide shows a little more detail
           about the NEPA process.  There are certain steps that
           we have to follow, and these steps are consistent for
           all Environmental Impact Statements that are prepared
           by federal agencies for any major federal action.  The
           first step is the notice of intent.  It lets the
           public know that we're going to prepare for an
           Environmental Impact Statement.  It is issued in the
           Federal Register shortly after the acceptance review
           is completed.
                       To prepare for our reviews, we've
           assembled a team of NRC staff with backgrounds in a
           specific technical and scientific disciplines that is
           needed to do these reviews.  We have people with
           backgrounds in biology, ichthyology, zoology.  There
           some people with human health backgrounds.  And they
           have generalists like me, project managers who
           coordinate the reviews.
                       In addition, to supplement the expertise
           of the staff, we've engaged the assistance of various
           national laboratories to ensure that we have a well-
           rounded knowledge base to do these reviews.  For every
           review, we put a team together of about 20 people.
                       The next step is the scoping process,
           during which we tried to narrow down the scope of the
           Environmental Impact Statement for the plant that
           we're looking at.  And we solicit public input.  The
           scoping process runs for about a minimum of 30 days
           and could be as long as -- what we've been doing,
           because we have to gain some experience, we've been
           allowing for a 60-day comment period.  About midway
           into the comment period, we have two public meetings
           near the site where we describe what we do, and we try
           to solicit public input.  We also perform a site
           visit, and we obtain information from the applicant
           during the site visit and from federal, state and
           local authorities.
                       Now, during this time, we seek information
           to define the scope of the plant-specific
           Environmental Impact Statement and determine what
           needs to be studied in detail and what is not
           appropriate to address.  We start with the potential
           list of 92 issues that came from the GEIS, and then we
           try to determine which ones are applicable and which
           are not.
                       In addition, we require the applicant to
           submit an evaluation and to let us know whether or not
           they're aware of any new, significant information that
           could affect our conclusions on Category 1 issues. 
           And during the scoping phase, of course, we take a
           look and see what the members of the public have to
           say and other federal, state and local authorities. 
           And if something new and significant information does
           arise, then we review it on a plant-specific basis. 
           And if not, we adopt the generic conclusions from the
           GEIS, and we incorporate those conclusions into our
           plant-specific review.
                       Category 2 issues, of course, we look at
           at the plant, and we obtain information during our
           site audits.  And finally, we also try to find out if
           there's any new issues that we hadn't considered in
           the GEIS five years ago.  And if a significant new
           issue does come up, then we would review that as if it
           were a Category 2 issue.
                       The most important thing about this slide
           that I wanted to point out was that -- I'm sorry.
                       MR. GRIMES:  Tom, if I could suggest, if
           you'd go to 15, because you basically covered what the
           process steps are, and just flash 15 and 16 for the
           areas review.
                       MR. KENYON:  And then finish up.
                       MR. GRIMES:  Yes.
                       MR. KENYON:  Okay.  This gives you an idea
           of the ecological issues.  The next slide shows you
           the kind of issues we look at in terms of social
           economics and environmental justice.
                       DR. APOSTOLAKIS:  How do you do social
                       MR. KENYON:  Well, we have a sociologist,
           and we go out and we interview a number of different
           people, like the local businessmen; we talk to local
           charities; we try to get a flavor for what would be
           the impact of the plant not being there, in terms of
           what it would do to their tax base, that sort of
           thing.  It's kind of a different kind of review.
                       When you're talking to the people who run
           the charities, you know, when they think of the plant
           leaving, in some cases there would be a significant
           impact; in other cases, these people that they take
           care of are probably not likely to be working at the
           plant to start with.  Okay?
                       DR. APOSTOLAKIS:  Okay.
                       MR. KENYON:  I'll just breeze through this
           real quickly.  There are issues that are not
           considered in the environmental review, such as the
           need -- this is by regulation.  The other important
           thing I wanted to point out is that we don't look at
           the safety-related issues.  That's left up to Mr.
           Prato, and we don't get involved in his review.
                       DR. APOSTOLAKIS:  So let me understand
           this.  A coal fire plant is not licensed by the
           federal government; is that true?  Are they licensed
           by the federal government?
                       MR. KENYON:  I don't know that they're
           licensed by the federal government, but there's a
           number of environmental statutes that they have to
           meet, and they're covered by the Environmental
           Protection Agency.
                       MR. GRIMES:  We have to be careful with
           our choice of terms, because I would contend that
           there's an EPA permit requirement that is not like our
           licensing process, but it is a federally imposed
           restriction.  Hydroelectric facilities are licensed by
           FERC in a process that looks very much like ours.
                       DR. APOSTOLAKIS:  So, ultimately,
           everybody does an Environmental Impact Statement.
                       MR. GRIMES:  Yes.  Ultimately, everybody
           does an Environmental Impact Statement but with a
           particular focus.
                       MR. KENYON:  And that concludes my
           presentation, unless you have any other questions.  I
           did provide you with the document of the last
           Environmental Impact Statement that we produced on
           Oconee just to give you an idea of what we do.
                       DR. BONACA:  Thank you; appreciate it.
                       MR. GRIMES:  I'd also like to add that Tom
           made a point that during the process that they go
           through, they reach out to the public in order to find
           out what the public's interests are.  But the
           environmental review does not address safety-related
           issues.  So if safety issues are brought to them, they
           refer them to the safety review, and Mr. Prato checks
           to make sure that they're being covered as part of our
           review process.  But we don't necessarily tailor a
           safety evaluation to address the public's interest in
           issues like waste or so forth.  But we do keep the two
           trains separate during the review process.
                       DR. BONACA:  Thank you for the
           presentation.  And I would like to thank also the
           applicants and Framatome's support for the
           presentations; very informative for the application
           that was -- well, I'll comment on that.  And also the
           staff for the presentations we received.
                       And I would like to go around the table
           and ask the two surviving members of the Subcommittee
           here if they have any additional insights to whatever
           they provided me before regarding the presentations.
                       I would like to just make a few comments. 
           One is that I spent quite a bit of time reviewing the
           application as well as the SER, and I thought that the
           application was effective.  I thought the SER was
           complete and effective.  I thought that definitely
           there were a lot of lessons learned that were used to
           make this application and the review more complete. 
           I think that it was easy to trace the issues.
                       And I also appreciate the staff's
           willingness to make this presentation on a comparison
           basis.  It was helpful for us, because I mean we spent
           quite a bit of time on Oconee, and it was a profit for
           us to benefit from the experience in our review of
           Arkansas, and that took place.
                       I felt that the scoping process was
           thorough and part was helped by very effective quality
           listing that already Arkansas seemed to have.  That
           was quite helpful.  We didn't go through the pain and
           suffering that we had in previous applications.  That
           was good.  I thought that it was pleasing to see that
           there wasn't too much of a focusing on legalistic
           narrow limits in the extent in which management
           programs were implemented.
                       There was some expansion to give proper
           consideration to important items, and that was
           important.  And because of that, I feel that there are
           very few open items.  That's one of the reasons.  And
           I don't think those items are contentious.  The way I
           see it there is no measure of contention there.  So I
           don't see any show stoppers from a perspective of the
           review of the staff, as well as a review of the CRS.
                       What I would recommend is that we do not
           have an interim report.  And I would like to have your
           thoughts, Chris, regarding this.
                       MR. GRIMES:  My view is we don't need one. 
           I think that we've benefitted from your review, and
           the level of detail that you've gone into is evident,
           and the feedback is helpful, and we're going to
           reflect on ways that we can improve the safety
           evaluation just based on the exchange that we'd had. 
           But unless you have any particular views on the
           issues, we don't need an interim report in order to
           proceed, and we'll plan on coming back to the
           Subcommittee again to report on the resolution of the
           open items and --
                       DR. BONACA:  And we will plan to write a
           letter at that time.
                       MR. GRIMES:  Correct.
                       DR. BONACA:  We will write just one
           letter.  That was part of our plan, in fact, when we
           go to a second and third review of a similar type
           plan, unless there are major issues to which we can
           contribute observations, then we'd have simply a final
           report, which we plan to have on this plant.
                       What I would propose, then, is that I'll
           report these conclusions to the full committee next
           week.  That will take probably 15 to 20 minutes, maybe
           half an hour at the most.  And I would request that
           the staff supports me maybe with a couple of people
           there present in case there are any specific questions
           from the members of the full committee.  And that's
           what I would like to do.
                       So for that presentation we do not need
           applicants present, right, at this stage.  We will
           plan to have you come at the final -- when we receive
           the final SER with the closed open items.  And then we
           will have a full presentation in front of the
           Committee at the time, and then we'll write a full
                       So if there are no disagreements, that's
           pretty much what we're trying to do.  We will somewhat
           change the schedule --
                       DR. APOSTOLAKIS:  How much time are we
           scheduled for?
                       DR. BONACA:  We're scheduled for an hour
           and a half, George.
                       DR. APOSTOLAKIS:  But we will take only
           half an hour?
                       DR. BONACA:  About half an hour, yes. 
           We'll take a half an hour and --
                       DR. APOSTOLAKIS:  We'll do something else.
                       DR. BONACA:  Oh, yes.  We've got a lot
           things to do.
                       DR. APOSTOLAKIS:  We can finish the safety
                       DR. BONACA:  No.  With that, I'm pleased
           to see that even our review was facilitated by the
           lessons learned.  So with that, if there are no
           further comments --
                       MR. GRIMES:  Dr. Bonaca, I have a couple
           of questions, though, that I'd like to pose before you
           adjourn.  The first is I'd like to ask -- you
           mentioned during the course of the presentation
           several times that you had some questions:  The
           question on the reactor vessel level measurement
           device --
                       DR. BONACA:  Yes.
                       MR. GRIMES:  -- the nature of the seven
           new programs, the clarity of the SER as it relates to
           the B&W integrated internal's activities.  Dr. Shack
           asked about impurities in the sodium hydroxide and FAC
           on the feed water.  And I wanted to know whether or
           not there were any of those questions that you'd like
           us to pursue further and get back to you?
                       DR. BONACA:  Not for my part, no.  I was
           satisfied that it was more like I needed
           clarification.  In many cases -- in my case, it was
           the point I made that the application said something
           and the SER contained resolutions of issues that were
           not reflected in the application.
                       MR. GRIMES:  I understand.  And as I said,
           that was useful for us, and we'll reflect on that when
           we close the open items to see if we can improve the
           clarity of the SER in those areas.
                       The other question I had is the style of
           this presentation was largely built off of Oconee, but
           I would expect that when we bring Hatch to the
           Subcommittee at the end of March that we do something
           that largely focuses on BWR uniqueness and perhaps the
           particular issues that we felt were challenging
           because of the boiling water reactor.  So in that
           sense, we would have a presentation that would be
           organized in much the same way, allow about the same
           order and level of detail, and highlight unique BWR
           challenges rather than differences from previous
                       DR. BONACA:  I agree with that.  That
           seems to be a positive approach.  The thing that I
           would like to make sure, of course we have not
           reviewed the BWR/VIP documents; we're reviewing them
                       MR. GRIMES:  We have a separate meeting
           scheduled for the VIP, the day before.
                       DR. BONACA:  That's right.  I was
           referring to the full committee meeting we have the
           week after that.  So if I understand it, the SER for
           Hatch will be very much based on -- okay, but we're
           saying we're going to deal with them separately.
                       MR. GRIMES:  Right.  We would attempt to
           try and cover as much of the VIP during the first
           meeting as possible so that the focus of the second
           meeting would largely be the same kind of format as
           today -- scoping -- our methodology, scoping, aging
           management programs in each of the areas.  And then
           wherever VIP occurs, we'd refer away from that and
           concentrate on the other aspects of the Hatch review
           that were unique and challenging from an aging
           management perspective.
                       DR. BONACA:  And I agree with that. 
           Actually, that would be helpful for another reason,
           that although we think of these plants very
           differently, but in many of the support system we find
           similarities.  And to the extent to which you can
           capture the experience we have for those similarities,
           that helps.  I mean, clearly, emergency systems and
           the steam -- well, not completely, but many portions
           would be singular.
                       Any other questions?
                       MR. GRIMES:  That's everything I need. 
           Thank you.
                       DR. BONACA:  Questions or comments from
                       DR. SHACK:  I like the format of the
           license renewal report.  I thought it was rather
           helpful to get through it.  It was easier reading than
           the first two that we went through.  For the SER, how
           about a list of the initialese up front.  For those of
           us that ULDs don't slip off our tongue, and when I
           come back in two weeks I forget what a ULD is again.
                       MR. GRIMES:  Acronyms up front, right
           behind the executive summary.
                       DR. BONACA:  If there are no further
           comments, I'll adjourn the meeting.  Thank you very
                 (Whereupon, the Subcommittee meeting was
           concluded at 12:49 p.m.)


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