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Plant License Renewal (Hatch 1&2) - October 25, 2001


                Official Transcript of Proceedings

                  NUCLEAR REGULATORY COMMISSION



Title:                    Advisory Committee on Reactor Safeguards
                               Plant License Renewal Subcommittee
                               Edwin I. Hatch License Renewal Application



Docket Number:  (not applicable)



Location:                 Rockville, Maryland



Date:                     Thursday, October 25, 2001







Work Order No.: NRC-081                               Pages 1-160



                   NEAL R. GROSS AND CO., INC.
                 Court Reporters and Transcribers
                  1323 Rhode Island Avenue, N.W.
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                          (202) 234-4433                         UNITED STATES OF AMERICA
                       NUCLEAR REGULATORY COMMISSION
                                 + + + + +
                 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
                PLANT LICENSE RENEWAL SUBCOMMITTEE MEETING
                                 + + + + +
                EDWIN I. HATCH LICENSE RENEWAL APPLICATION
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                                 THURSDAY
                             OCTOBER 25, 2001
                                 + + + + +
                            ROCKVILLE, MARYLAND
                                + + + + + 
                 The Subcommittee Meeting was called to order at
           the Nuclear Regulatory Commission, Two White Flint
           North, Room 2B3, 11545 Rockville Pike, at 8:31 a.m.,
           Dr. Mario V. Bonaca, Chairman, presiding.
           PRESENT:
           DR. MARIO V. BONACA, Chairman
           DR. F. PETER FORD, Member
           DR. THOMAS S. KRESS, Member
           DR. WILLIAM J. SHACK, Member
           DR. JOHN BARTON, ACRS Consultant
           MR. NOEL F. DUDLEY, ACRS Staff Engineer
           
           STAFF PRESENT:
           WILLIAM BURTON, NRR
           JAMES DAVIS, NRR
           CHRIS GRIMES, NRR
           JOHN NAKOSKI, NRR
           GENE CARPENTER, NRR
           TANYA EATON, NRR
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
                                            I-N-D-E-X
                       AGENDA ITEM                         PAGE
           Opening Remarks by Subcommittee Chairman . . . . . 4
           Opening Remarks by Chris Grimes, NRR . . . . . . . 5
           Presentation by W. Burton on Safety. . . . . . . . 6
                 Evaluation Report, Closure of Open Items
           Presentation by W. Burton on Appeal. . . . . . . 108
                 Process
           Discussion by Subcommittee . . . . . . . . . . . 142
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
                                      P-R-O-C-E-E-D-I-N-G-S
                                                    (8:31 a.m.)
                       CHAIRMAN BONACA:  Good morning.   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 Plant License Renewal
           Subcommittee.  
                       The other ACRS Members and consultant in
           attendance are Peter Ford, Thomas Kress, William
           Shack, and John Barton.
                       The purpose of this meeting is for the
           subcommittee to review the Safety Evaluation Report
           related to the license renewal of Edwin Hatch Nuclear
           Plants, Units 1 and 2. 
                       The Subcommittee will gather information,
           analyze relevant issues and facts, and formulate the
           proposed positions and actions, as appropriate, for
           deliberation by the full committee.  Mr. Noel Dudley
           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 October 10th, 2001. 
                       A transcript of this meeting is being kept
           and will be made available as stated in the Federal
           Register Notice.  It is requested that 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.  At our March 28th, 2001 Subcommittee
           meeting, we reviewed the SER with open items.  
                       In a letter to Dr. William Travers,
           Executive Director for Operations, issued on April
           16th, 2001, the ACRS provided conclusions based on its
           review of the SER with open items.  
                       We will now proceed with the meeting, and
           I call upon Mr. William Burton of the Office of
           Nuclear Regulatory Regulations to begin.  Actually,
           Mr. Grimes, would you like to have an introductory
           statement?
                       MR. GRIMES:  Yes, Dr. Bonaca.  First of
           all, I would like to thank the ACRS for this
           opportunity for the staff to present the results of
           the staff's review and resolution of open items.
                       As you mentioned, Butch Burton, a senior
           project manager, who is in charge of the license
           renewal review for Hatch, is going to lead the staff's
           presentation.
                       I would also like to introduce John
           Nakoski, who is an acting section chief in the license
           renewal and standardization branch.  I have to leave
           shortly to attend to another function for the Division
           of Regulatory Improvement Programs.
                       But we are looking forward to the ACRS
           reactions and comments on the staff's resolution of
           the open items and the final safety evaluation report.
                       Mr. Nakoski is going to represent my
           interests to make sure that we clearly understand what
           issues or what comments the subcommittee would like
           for us to address more fully for the full committee on
           November 8th.  Thank you very much. 
                       And so with that introduction, I will turn
           the presentation over to Butch Burton.
                       MR. BURTON:  All right.  Thank you, Chris. 
           I am going to use the remote mike.  Is that going to
           be all right and can everybody hear okay?  Okay.  My
           name is Butch Burton, and I am the lead project
           manager for the staff's review of the Plant Hatch
           license renewal application.
                       I have with me some of the staff reviewers
           who performed the review.  Not all of them are here
           today.  So if you have some questions that would
           really be addressed by them, I am going to have to
           perhaps defer the question until the full committee
           meeting.
                       But most of the reviewers should be here
           today.  I also have the representatives of Southern
           Nuclear here to clarify any items that you may need to
           ask of them.
                       According to the agenda, this is actually
           going to be in two parts.  The first part as I
           understand it that you wanted to do was to go over the
           open items that did not go through the appeal process.
                       So the first part, I was just going to go
           through those and what the resolution of those open
           items were.  And then following the break, I was going
           to go through the open items that did go to appeal.
                       And it was my understanding that for each
           of those that you wanted to make sure that you
           understood exactly the basis for going to appeal, as
           well as the final resolution of each of those items,
           and so I will be going through that also.
                       Okay.  First, a little bit of background,
           and a lot of this is similar to what I provided during
           the previous meetings back in -- what, the March-April
           time frame.  
                       Southern Nuclear submitted its application
           in late February of last year.  As you know, Plant
           Hatch is a two unit site, located about 11 miles north
           of Baxley, Georgia.  They were requesting renewal of
           both of the licenses for both of the units.
                       And for Unit 1, an extension of 20 years
           so that it would move from 2014 to 2034; and for Unit
           2, from 2018 to 2038.  The initial SER was issued in
           early February of this year, and we just recently
           issued the final SER that I will be talking about
           earlier this morning on October 5th.
                       Just briefly, I wanted to put up the
           milestone schedule, and just let you know some of the
           activities that have gone on since the last ACRS
           meetings, which occurred April 5th.  
                       Since that time, or at that point we had
           not gotten or completed all the necessary responses
           for all of the open items.  So since that meeting, we
           have gotten all of the open items, and we have been
           working to resolve those, and they are all resolved at
           this point.
                       The staff also issued its final
           environmental impact statement in late May, and we
           also did the final optional inspection.  As you know,
           there are two inspections that are normally done, and
           then an optional final inspection, and we did do that.
                       And we got the associated inspection
           report, and as I said before, the staff issued its
           final SER on October 5th, and following that we got
           the regional administrator's letter basically saying
           that as a result of the inspections that were done
           there were no outstanding issues.
                       Now, we identified 18 open items during
           the staff's review.  Of those 18, 12 were resolved
           without going through the appeal process, and six were
           resolved as a result of going through the appeal
           process.  
                       The next couple of slides is just a
           laundry list of the open items that were resolved
           without appeal, and I am going to be going through
           each one of these.  Now, if you actually look at the
           next two slides, you will actually count -- rather
           than 12, you will actually count 13 items.  
                       The reason for that is that one of the
           open items, the very last one, 413-1, had two parts to
           it.  Part A was not appealed and Part B was.  So, I
           split it up along those lines.  So you actually see 13
           items on this list.
                       Okay.  The first open item was Open Item
           2.3.3.2-1, and it had to do with the screening of
           skid-mounted components.  The big issue at hand was
           should skid-mounted components be subject to an AMR.
                       These skid-mounted components were
           actually associated with the hydrogen recombiners, and
           the emergency diesel generators.  We had actually gone
           through this issue with Oconee earlier, and the final
           resolution was that we needed to clearly define the
           boundaries between these two components, which were
           considered active, and then the associated skid-
           mounted components.
                       And what we recognized was that there were
           some skid-mounted components that actually fit the
           criteria for being long-lived and passive, and as such
           they needed to be -- well, they were already brought
           into scope, but also needed to be subject to an AMR.
                       So after some discussion the final
           resolution was that there were some additional
           components that were brought within that were subject
           to an AMR.  As you can see with the recombiners, they
           were such things as blower casing, piping, reaction
           chamber, and some other things.
                       And similarly with the diesel, jacket
           water cooling, lube oil, and scavenging air.  And what
           I wanted to make sure that you all understand is that
           when we have these scoping issues, when we did decide
           that something needed to be brought within scope,
           and/or subject to an AMR, there was a whole cadre of
           aging management information that had to come with it.
                       And so in each of the scoping and
           screening open items, if they were resolved such that
           things had to be brought within scope, or be subject
           to AMR, all of the associated aging management
           information was brought with it, and the staff
           evaluated it.
                       CHAIRMAN BONACA:  I have a question on
           this.  One is that this was an open item as you
           mentioned before on Oconee, and is the guidance --
           well, I believe the guidance right now, for example,
           in the GALL report is pretty clear about what it
           should be.
                       So with other applications coming through,
           does it look like this is going to be again contested
           in some other applications, or is it pretty much of a
           clear understanding now of what the interpretation is?
                       MR. BURTON:  Well, if you look at the
           latest license renewal guidance, the SRP, and all of
           that, it is pretty clearly laid out.  Once of the
           issues as I go through this and I guess you will kind
           of find is that the timing of the Plant Hatch
           application versus some of the infrastructure work
           that the staff was doing, we kind of got caught in
           cross-purposes.
                       But as we reach resolution on some of
           those things, we were able to see if it was applicable
           to Hatch and be able to resolve it that way.  You will
           see that with some other items that had to do with
           some of the work that we had to do with GALL and
           things like that.  So that was part of it.
                       DR. BARTON:  I had the same question,
           because it seems to me that there is going to be
           generic issues that are going to come up, and another
           one I think is seismic two over one piping issues.
                       Now, is the staff going to have to go
           through every application and go through the same
           arguments?  Isn't there some way once a precedence has
           been set that the word gets out or something, and
           don't come back in and try to argue it, because it
           seems to me just a waste of resources to fight the
           same issues if the staff is going to say, hey, we are
           never going to accept seismic two over one.
                       And so everybody is going to come in with
           the same argument, and we are going to have the same
           response.  So, you know, let's get on with it. 
                       CHAIRMAN BONACA:  And another thing that
           I wanted to note in particular for seismic two over
           one is that the SER for Hatch contains a discussion
           that is very clarifying.  
                       I mean, the logic why an existing high
           energy line break, for example, analysis doesn't
           provide sufficient understanding of locations that you
           have to protect for.
                       So I think an important question is how is
           this information or this guidance being provided to
           the licensees.  Clearly, an update of GALL may be the
           way, but it is important to provide it in a way that
           open items on the same issues don't appear again.  
                       Unless, of course, it is an issue that is
           highly contested by the industry, and then in that
           case we will have to go through to a resolution.  
                       MR. BURTON:  I will say that in the
           specific case of seismic two over one with Hatch, I
           was going to speak not only about the resolution, but
           how that actually got played out.
                       (Brief Interruption.)
                       CHAIRMAN BONACA:  Let me ask another
           question about this.  Are there any other skid-mounted
           systems in the plant that one should look at?
                       MR. BURTON:  Not -- well, I guess --
                       CHAIRMAN BONACA:  Well, I am just saying
           that I would like to ask that question.
                       MR. BAKER:  Of the items related to
           license renewal, the only ones that came to mine --
                       MR. DUDLEY:  Excuse me, but could you
           introduce yourself for the record?
                       MR. BAKER:  Ray Baker with Southern
           Nuclear.  The hydrogen recombiners skid and the diesel
           generator skids represent two major examples of skid-
           mounted components that have an overall active nature
           associated with them, but which through the
           discussions that we had with the staff, we resolved
           how to break that down into the parts that required
           aging management.  There are no others that I am aware
           of.
                       CHAIRMAN BONACA:  Okay.
                       MR. BAKER:  And that would reach that
           level of the interest.
                       MR. BURTON:  And for your other question
           about in general how we deal with these items that
           come up, I think Mr. Grimes wanted to speak to that.
                       MR. GRIMES:  Thank you, Butch.  Yes, I
           would like to first emphasize that we were learning
           how to resolve some of these issues, and which
           includes renewal guidance.  
                       And parallel with the staff's review of
           Hatch and Turkey Point, and the practice that we have
           established in it is that I would intend to continue,
           as has been illustrated by the demonstration project,
           is that as we identify areas where there is still
           controversy or sensitivity.
                       That wherever we can clarify the staff's
           expectations, we would send proposed positions to NEI,
           and give the industry an opportunity to react to them
           on a generic basis, and then augment the improved
           renewal guidance either in the form of supplements to
           the standard review plan, expectations regarding the
           contents of the application, or changes in the style
           guides that we have established to try and articulate
           a consistent treatment of these issues.
                       You might recall that the industry
           identified five -- what they referred to as dialogue
           issues, and those were areas where the industry felt
           that there was still an opportunity for improvements
           in the process.
                       Most notably, environment effects of
           fatigue is an area where there is ongoing research
           activity, and ongoing industry initiatives, and
           ongoing staff review.  
                       And in those areas, as we find ways to
           clarify the expectations and minimize the extent of
           the struggle over finding the right answer on a plant
           specific basis, we would intend on capturing those.
                       I do think that the improved renewal
           guidance is probably achieved 95 to 98 percent of the
           resolution of controversy over how to do license
           renewal, aging management, scoping, and other aspects
           of the process.
                       But there will continue to be areas where
           we are trying to find the optimum solution.  There
           will continue to be areas where there will be
           challenges on a plant specific basis, and that just
           represents the nature of the emerging issues and
           adaptability that will be a part of the process, I
           think, on an ongoing basis.
                       MR. BURTON:  And I wanted to add to that,
           is that as we do our work with grappling with the
           emerging issues, there is always the timing issue
           where as things come up you have applications that are
           being reviewed at that time, and applications that
           have already been reviewed and approved.
                       So there is also the part of what we do as
           part of our process is as we resolve these things, we
           have got to see how do we communicate that resolution
           to the plants who are so far along that they didn't
           have an opportunity necessarily to incorporate it.  
                       And also for those who have already been
           or had their license renewed, part of the process that
           we follow is that we have to evaluate, well, how does
           that impact on them and what needs to be done.
                       And some of that as well we are going to
           bring out with some of the seismic two over ones.  So
           those are all issues that we as a staff are aware of,
           and we try to take into account as we resolve these
           things.
                       MR. GRIMES:  Okay.  The next open item was
           2.3.4.2-1, fire suppression in the radwaste building. 
           Our fire protection engineer, in her review, did a
           thorough review of the fire hazards analysis, and what
           some of the commitments were in there.  
                       And comparing that to what had been scoped
           in for license renewal, and we found that some of
           these fire suppression systems in the radwaste
           building according to the fire hazards analysis was
           necessary to protect charcoal filters, and some
           combustibles, in the dry waste storage area.
                       And also as a result of one of the
           inspections, we also found that there was some cabling
           that needed some protection.  So as a result of that,
           we said, well, we think that needs to be brought into
           scope and be subject to an AMR.  
                       And we did some walkdowns during the
           scoping inspection, I believe it was, and actually
           identified that portion of the system, and exactly
           what it was designed to protect.  
                       And in the end we did decide -- the
           applicant did decide to bring that into scope, and
           make it subject to an AMR.  And again all of the
           associated aging management information came along
           with it.
                       Now, I just happen to know in this
           particular case that as you know, what was done was
           once you identified components in scope and subject to
           an AMR, you commoditized it.  You broke it down into
           its material environment combination.
                       And I know that in this case the staff
           that was brought in to scope when it was commoditized,
           it didn't really result in anything new, in terms of
           aging effects or aging management programs, and things
           like that.
                       The next open item was open item 3.0-1. 
           This is a standard open item.  What it is, it is sort
           of a place holder for all of the work that we do with
           the FSAR supplement.  As we review the FSAR supplement
           information, we will find open items, whatever issues
           that need to be resolved.
                       This open item is sort of a catch all,
           that when we are satisfied that all of the issues in
           the supplement are correctly resolved, then we will
           close that out.
                       There is also a standard license condition
           associated with that.  Basically, the license
           condition says that the FSAR supplement, as it has
           been agreed to, needs to be incorporated into the FSAR
           at the next available FSAR update, and that is a
           standing license condition.
                       Another standard license condition states
           that in the supplement that there are a number of
           future activities that are committed to, and so we
           also have another standard license condition that says
           all of those activities have to be performed before
           the end of the current term, another standard license
           condition.
                       And that is two of the three license
           conditions that we actually have in this review, and
           I will speak to the third one later.
                       CHAIRMAN BONACA:  A number of the closure
           of open items result in new one-time inspections, or
           some modifications of existing programs, and in some
           cases actual changes in site procedures.
                       And in fact I have some questions on that,
           and I think you, John, had some questions on that. 
           But the question that I have is are these changes
           going to be reflected in the FSAR supplement, or how
           are these new commitments captured?
                       I mean, the reason to commitment to the
           licensee to update the application, and we discussed
           this before.  The application stands as is, and it
           doesn't have included an amendment to reflect these
           changes.  Are they going to just sit in the SER, or
           what are they going to go?
                       MR. BURTON:  That is a good question, and
           I guess in order to answer it, I am going to let
           Southern Nuclear talk a little bit about their
           commitment tracking process, and then how we as the
           staff actually as part of our inspection actually took
           a look at that.  
                       MR. BAKER:  This is Ray Baker again at
           Southern Nuclear.  One of the activities that we began
           early was to track the commitments that we were making
           as a part of the license renewal application review
           process.
                       And we had several stake points in that
           process, one of which was the issuance of the final
           SER to go through that document again, and identify
           any revised commitments or new commitments that had
           been made since the previous stake points, and we
           capture those in a database.
                       And for each of those commitments, we have
           performed an extensive review process of the existing
           site procedures, and we have identified the
           procedures, and the procedure steps, where
           enhancements will be made, or where we will credit
           those activities to satisfy those license renewal
           commitments that we have made.
                       And so we have that process in hand now so
           that once the license is issued, we will then go
           through a process of actually converting those draft
           procedures into the actual implemented site
           procedures.  
                       DR. BARTON:  I have one additional
           question.  You have got this in the commitment
           tracking system, and I know that people sometimes have
           problems with commitment tracking systems, and lose
           commitments, and lose track of commitments, et cetera,
           et cetera.
                       Have you also placed each one of these
           items in your corrective action system?
                       MR. BAKER:  We have a separate database
           besides the actual site commitments matrix, that we
           are in the interim managing these commitments until
           they are established in the site's commitment tracking
           system.
                       As far as a separate -- our site processes
           would not lend themselves to having them in a separate
           corrective actions kind of a database.
                       DR. BARTON:  So you have got more than one
           corrective action system at the site?
                       MR. BAKER:  There is a corrective actions
           process.
                       DR. BARTON:  A corrective actions process?
                       MR. BAKER:  Yes.  
                       DR. BARTON:  So it has got many systems or
           many fingers to this, and how you track actions?
                       MR. BAKER:  One of the things that you
           would do would be to identify conditions that require
           correction.  So that is a piece of it.  And another
           part would be the tracking and trending of those
           issues.  
                       And so you have some procedures that track
           and trend internally, and then you have other
           procedures where the tracking and trending would be
           performed perhaps at a departmental level, rather than
           at the procedural level.  Those are all a part of the
           corrective actions control for the site.  
                       DR. BARTON:  Okay.  It just seems to me
           that it more complex, and I have seen other plants
           where everything goes into one corrective action
           system.  So I only have to worry about tracking one
           place.
                       MR. BAKER:  There is one corrective
           actions system, yes, but it is made up of many parts,
           yes, sir.
                       MR. PIERCE:  I just wanted to add one
           other thing.  This is Chuck Pierce, and I am with
           Southern Nuclear as well.  To more specifically answer
           the question that you had asked earlier, Chairman
           Bonaca, the SER supplement, which is a part of what we
           send the NRC, was updated to reflect these new
           commitments, and what we have resolved with these open
           items.
                       So there was an update made to that
           document that will go into our FSAR.
                       CHAIRMAN BONACA:  And that will list, for
           example -- well, I don't expect a description, but it
           will list the programs that you are committed to?
                       MR. PIERCE:  Yes, and it includes the
           final resolution of the commitments made in the open
           items.
                       CHAIRMAN BONACA:  Okay.  So there is a
           place then.
                       MR. PIERCE:  Yes, sir.  
                       CHAIRMAN BONACA:  Because that is really
           generic to all this license renewal, and not
           specifically to Hatch.  I mean, I think it is
           important that somewhere we have what is that we have
           agreed to support license renewal.
                       And I think that it is up to the location
           that there has to be a place where we understand what
           the programs are going to be.  Some of them are
           modifications that can be lost in a SER.  So, all
           right.
                       MR. BURTON:  Now, having a better
           understanding of what they do, now let me talk a
           little bit about what the staff did in terms of its
           confirmation of all of that.  
                       As they said, what they tried to do was to
           capture all of the commitments, and all of the
           commitments are identified in the application in the
           SER.
                       And as they said, they capture all of
           those commitments in a commitment matrix.  So what we
           did -- and this was at the very first scoping
           inspection, we spent a fair amount of time that week
           understanding their system, and taking examples of
           commitments as they were incorporated in the matrix at
           that point, and seeing how they were tracking them
           down to the procedure level.
                       And in fact we found that they actually
           did a very good job in terms of tracking those
           commitments, and they actually had red-line strikeouts
           of the associated site procedures.  And all of that is
           documented in, I believe, the first scoping inspection
           report.  
                       And actually in that respect, they were
           actually ahead of some of the previous applicants, in
           terms of their development of that phase of the
           process.  
                       Now, it was not complete at that point,
           because obviously now that we have the final SER out,
           there are more commitments that have been made as a
           result of resolving the open items.
                       All of that was actually before we had
           resolved the open items, and so what their process
           does is that they are going to go back now once
           everything is resolved, and put to bed, and see what
           other commitments they have made, and put them in that
           tracking system, and run them down to the procedural
           level.
                       But after we took a look at the process,
           we were pretty comfortable that they were actually
           doing things right there, and we are actually better
           than some of the other applicants.
                       MR. NAKOSKI:  Butch, this is John Nakoski. 
           If I could just add that post-renewed license, that we
           do plan to have an inspection procedure that will
           specifically go and look at confirmation that the
           commitments made have been implemented and met prior
           to or about the time the existing license would have
           expired.  
                       MR. BURTON:  The next open item is 3.1.1-1
           had to do with the BWR water chemistry guidelines.  We
           had developed in the initial license renewal
           application, they talked about some of the water
           chemistry guidelines that they were going to use, and
           they committed to following EPRI 103515.
                       And in response to an RAI, they noted that
           this document was going to be revised to Rev. 2.  So
           the issue came up, well, we haven't seen that, and we
           are not sure what is in it.  So we are not sure that
           we are going to be comfortable if you move to that
           revision.
                       And that was the basis of the open item. 
           After some discussions, we realized that the applicant
           needs to have flexibility in their water chemistry
           program.  They have hydrogen water chemistry, and
           hydrogen water chemistry with Noble gas chemical
           addition.
                       And as a result of some of the operating
           experience, they need to have the flexibility to make
           whatever changes that they need to make.  But in
           response to the open item, because our concern was,
           well, how does Rev. 1 differ from Rev. 2, they also
           included some of that information.
                       And in fact when you look at Rev. 2, what
           it does is that it does in fact give someone who
           implements Rev. 2 a lot more flexibility if they are
           using hydrogen water chemistry.  They are allowed to
           relax some of the limits for chlorides and sulfates,
           and things like that.
                       So after -- again, after looking at all of
           that, and realizing that they really do need to have
           that flexibility, we said, okay, we are going to close
           this out and basically not ask them to stick
           necessarily to Rev. 1.
                       DR. FORD:  Can I ask a procedural
           question?  I agree entirely with our decision there,
           but since you haven't reviewed Rev. 2, how is that 
           -- if you have not reviewed Rev. 2, how can you just
           go along and agree with the application?
                       MR. BURTON:  Okay.  And let me be clear. 
           Right now what they are doing is associated with Rev.
           1.  Rev. 2 at the time -- and I don't know whether the
           -- or at what stage of completion that is in.  I don't
           know if any of you all know that.
                       But again -- and I guess to some extent
           that you may call that a judgment call, and part of it
           very much was, well, we need to understand the delta
           between the two. 
                       And once we understood it, it really was
           just a relaxation of some of the chlorides and
           phosphates if you are using hydrogen water chemistry,
           because it gives you a big benefit to do that.
                       We thought that was a good thing.  The
           other thing that it did was that it also relaxed some
           of the monitoring frequencies.  I think Rev. 1 says
           that you have to monitor for these things daily.
                       Rev. 2 says, well, you can relax that if
           you have got satisfactory trends in some of your
           conductivity, and things like that.  Oh, okay.  Did
           you want to add to that?
                       MR. DYLE:  This is Robin Dyle from
           Southern Nuclear, Dr. Ford.  One of the things that we
           did in this process was evaluate for the staff the
           differences between Revision 2 and Revision 1, and
           provide that to them.
                       So there was an assessment of Rev. 2.  I
           think it would be better characterized that they
           didn't do a generic review, and to say that it is
           applicable to the entire fleet.  
                       But they do understand that the
           differences.  The one thing between Rev. 1 and Rev. 2
           is that there is no change in the action statements,
           and the real requirements.  There was more guidance on
           how to monitor things that should be noted and kept up
           with when you are implementing HWC or Noble Metal. 
           But that has been reviewed as far as what the
           differences were and that was provided.
                       And the documents are available for
           generic review also, but it just has not been
           submitted that way yet.
                       MR. BURTON:  The next open item was 3.1.3-
           1 having to do with diesel fuel oil testing.  The open
           item was that we had a concern with degradation of the
           tank bottoms, and that we thought that it would be
           advisable to do a one-time inspection of the tank
           bottoms.
                       One Southern Nuclear informed us of was
           that recently they had actually done some excavation
           and actually had done just the kind of inspection that
           we were looking for on one of the four buried diesels.
                       I'm sorry, diesel fuel oil storage tanks. 
           They couldn't bury diesels.  Wouldn't that be
           something.  They are pretty large tanks as I am sure
           that you all know.  When they looked at the one, they
           did not find any significant wall thinning or any kind
           of degradation. 
                       And the thought was that these four tanks,
           and they are all made of the same material, and they
           are all in the same environment, and they have all
           been in the same environment for the same period of
           time. 
                       So the implication is that if we are not
           seeing any significant degradation in the one, that is
           probably true for the other three.  There was also --
           well, actually, when we went on the scoping
           inspection, as we did our walk around, we noted the
           diesel fire pumps.
                       They also have fuel oil storage tanks. 
           However, they are above ground, and easily accessible,
           and the same material, and a more benign environment. 
           So if we were going to see any kind of degradation, we
           would see it here before we saw it here.  So the
           conditions here really bounded these.
                       DR. BARTON:  I have a question.  The
           buried diesel oil fuel storage things, the tanks, the
           four tanks, steel construction, coated or uncoated?
                       MR. DYLE:  The exterior surface is coated.
                       DR. BARTON:  The exterior surface is
           coated, and you inspected one of four tanks?
                       MR. DYLE:  Yes.
                       DR. BARTON:  And ultrasonic showed that
           you had no loss of wall on the one tank?
                       MR. DYLE:  That's correct.
                       DR. BARTON:  Now, what assurance is there
           that -- well, maybe that tank has no deterioration or
           no damage to the external coating when it was
           installed.  
                       What assurance do you have that when the
           other three tanks were put in the ground that there
           was no damage done to the external coating, and you
           could have some corrosion going on in those tanks.
                       And that the condition, if you did inspect
           them, could be different than in the 1-A tank?
                       MR. DYLE:  I think that what you are
           postulating is exactly correct, and is the case for
           all construction.  That is always a possibility for
           buried components; that if there is some construction
           related issue that is unique to a specific location,
           it could damage that exterior coating, but we have not
           observed that.
                       DR. BARTON:  How do you know?  Have you
           looked at the external coating of those other three
           tanks or other four tanks?
                       MR. DYLE:  We have not observed any
           consequences, any results of that throughout the plant
           in general.  When you backfill, you backfill with
           clean backfill so that there is not a significant
           likelihood of there being damage to the exterior
           coating of those tanks.
                       But your premise is exactly correct, and
           no, we have not looked at those.  But the assurance
           that we are able to provide ourselves is that by
           examining that one, a 25 percent sample showed no
           damage.
                       DR. BARTON:  Well, I still think that
           there could be damage to the other ones that you don't
           even know exists.  I think the staff should require
           additional inspections before closing the site, or
           requiring additional inspections somewhere down the
           road.
                       You expected this one because you went in
           and had to do some cleaning or something, and if you
           had to do some cleaning of the other tanks somewhere
           down the road, maybe the requirement ought to be that
           you do an ultrasonic inspection of those tanks while
           you are doing the cleaning.
                       I think it is a crap shoot, you know.  You
           hit one out of four, fine.  That's 25 percent, but you
           don't know what the condition is of the other three
           tanks.
                       DR. FORD:  I have a related question
           actually.
                       MR. BURTON:  Okay.  Well, go ahead.
                       DR. FORD:  And it is somewhat related to
           John's.  I am pretty uncomfortable about the idea of
           one time inspections when it is applied to a time
           dependent degradation mechanism.
                       DR. BARTON:  Yeah, 60 years.
                       DR. FORD:  And especially corrosion, when
           if it is uniformly general corrosion, fine.  But if it
           is localized corrosion, and if you have a bad batch of
           oil, with some chloride in the water or whatever it
           might be, then it depends on when you do the
           inspection as to whether you are going to see any
           results.
                       MR. BURTON:  Okay.
                       DR. FORD:  And so it is related to that.
                       DR. BARTON:  Well, you can only do it from
           the inside of the tank, and when it comes from the
           outside of the tank --
                       DR. FORD:  Right.  I was going to speak to
           that.
                       MR. BURTON:  Well, let me speak to both. 
           One of the things that Southern Nuclear has is they
           have put in their procedures how to deal with buried
           components, and actually I will speak to that in a
           little while.
                       And that is one of the things that we
           looked at in our inspection, is how did those
           commitments get carried through to the procedural
           level.
                       And the protective coatings program is one
           of the aging management programs that they take credit
           for.  When you go to the implementing procedures at
           the site level.  
                       What they say is that any time that things
           are being excavated, there is a specific pointer in
           there to have their protective coatings people go in
           and take a look at the exterior of the status of the
           protective coating.
                       So the aging management program -- the
           implementing procedures for the aging management
           programs actually will get them to where they do that.
                       DR. BARTON:  Butch, most people have that
           in their programs.  But, you know, one, when you go
           and do that inspection, it is usually when you have a
           leak, and then you do the excavation, and then you fix
           the leak.
                       And then you look at adjacent piping, or
           tanks, or whatever, and areas of the tank adjacent to
           the leak, and you go patch that up also.  But that is
           a reactive program, and it is usually after you have
           a leak and you are chasing a leak.
                       Now, you want diesel fuel oil leaking? You
           know, that's where I am coming from, you know, before
           you go and chase the tank or the coating.  I know the
           procedure, and most people do have that same
           procedure, because how else are you going to inspect
           all the buried stuff.
                       And you inspect it when it is leaking, and
           you go after it, and you do an inspection of the
           coating, and you repair the coating.  Otherwise, no
           one is going to dig up everything on site and look at
           what was buried 20 years ago.  I mean, that is not
           practical.
                       DR. SHACK:  At the risk of beating this
           one to death, how detailed was the ultrasonic
           inspection?  I would expect a coating failure to lead
           to a localized corrosion.  I am not too worried about
           uniform corrosion of this tank.  That's not likely to
           be a problem.
                       DR. BARTON:  Right.
                       MR. BAKER:  There were 144 locations that
           were probed around the tank, and none of those showed
           any reduction in wall thickness.
                       CHAIRMAN BONACA:  Why did you perform this
           inspection?
                       MR. BAKER:  It was an opportunity.  The
           tank was opened and we knew that this was a question
           that was of interest, and so we took that as an
           opportunity to go take a look and see, just to
           convince ourselves.
                       In general, these one time inspections are
           where we don't expect an aging effect to exist to
           begin with, but we want to confirm the absence of that
           aging effect.
                       So in that respect, perhaps they are
           proactive because it is not inspecting on an
           expectation of there being a problem, but to confirm
           that perhaps there is not a problem.  And so that was
           the rationale for what we did here.
                       MR. BURTON:  And actually what Mr. Baker
           said, I think that is an important point.  I think
           from the beginning of license renewal that we tried to
           lay out the rules of engagement, I guess you would
           want to call it, as it concerns one-time inspections.
                       And as Mr. Baker said, we generally
           expected those kinds of inspections one time in
           situations where based on operating experience we
           really have not found any evidence of age related
           degradation.
                       But again just if -- well, just to make
           sure that we are assuming is correct, or I shouldn't
           say we, but assuming what they are assuming is
           correct, they will go and do that.
                       And many times that is associated with
           things that have to do with chemistry of some sort.
                       CHAIRMAN BONACA:  I don't understand. 
           What are the commitments that you have to -- I mean,
           the current licensing term, and there is no
           commitment?
                       MR. BURTON:  I'm sorry, but say that
           again?
                       CHAIRMAN BONACA:  I am trying to
           understand for the first 40 years of operation of the
           plant.
                       MR. BURTON:  Oh, for the current term.
                       CHAIRMAN BONACA:  There is no commitment
           to tracking aging degradation of that tank?
                       MR. BURTON:  I must admit that I am less
           familiar with what is currently done.  So I don't know
           if you all can speak to that.
                       MR. NAKOSKI:  Butch, this is John Nakoski,
           and let me just ask -- I guess I am going to ask you
           a question here out of turn maybe.  
                       MR. BURTON:  Go ahead.  I'm ready.

                       MR. NAKOSKI:  Are we taking any credit for
           corrective action if there were degradation of a
           buried component?  Is that part of an aging management
           program?
                       MR. BURTON:  Sure.
                       MR. NAKOSKI:  And where they would
           increase the scope of the --
                       MR. BURTON:  Yes.
                       MR. NAKOSKI:  Well, consider that as part
           of the corrective action program?
                       MR. BURTON:  Yes, absolutely.  I am glad
           that you said that.  If I didn't make it clear before,
           let me do it now.  The corrective action program --
           and this kind of speaks to your question also, but the
           corrective action program is an aging management
           program.
                       And what it is, is that when any kind of
           problem is identified across any of the systems, their
           guidance has to feed that into the corrective action
           program, which basically is at an Appendix B level. 
           And so they implement all of those actions.
                       DR. BARTON:  Is the commitment tracking
           system at the same level?
                       MR. BURTON:  In terms of the maintenance
           of the commitment tracking?
                       MR. BAKER:  I'm sorry, I was talking to
           Chuck.  I apologize.  Repeat the question.
                       MR. BURTON:  What I was talking about was
           the correction actions program, and I was explaining
           that it is a separate aging management program, and it
           applies across all of license renewal, all of the
           systems.
                       And the way that the process works is that
           any time any problems are found anywhere, it gets fed
           into the corrective actions process.  And what I was
           just saying was that that process is really at an
           Appendix B level.
                       MR. BAKER:  That's correct.
                       MR. BURTON:  Even for some things that are
           not Appendix B.
                       MR. BAKER:  That's correct.
                       DR. BARTON:  The question was is the
           commitment tracking system at the Appendix B level
           also, or just the corrective actions system?
                       MR. BAKER:  The corrective actions system
           is an Appendix B program.
                       DR. BARTON:  And the commitment tracking
           is part of that?
                       MR. BAKER:  The commitment tracking is
           more of a licensing process I would characterize.
                       DR. BARTON:  So it is really not --
                       MR. BAKER:  I don't believe that it is
           subject to QA.
                       DR. BARTON:  That's my problem.  You are
           using different systems to track things that --
                       MR. NAKOSKI:  This is John Nakoski again
           to try to maybe help answer Mr. Barton's question.  I
           think the point was made earlier that the commitments
           are captured in the FSAR.
                       Further, there is a license condition that
           requires -- if I understand right, Butch, and correct
           me if I am wrong.  But there is a license condition
           that requires that those commitments be met before
           entering the extended period of operation.  That is
           really where the FSAR controls the commitments. 
                       DR. BARTON:  These commitments that are in
           the FSAR?
                       MR. BURTON:  Oh, yes, all the commitments
           are ultimately going to be in the FSAR, and controlled
           from that point.
                       MR. NAKOSKI:  And like I said further, we
           will have an inspection procedure, post-renewed
           license, that will go and look at satisfying these
           commitments.  
                       MR. BURTON:  Okay.  Now, all of that is
           true, and I think that satisfies at least part of your
           question.  But it sounds like your concern is that the
           entity that they used to track the commitments, the
           actual commitment tracking system, which is not
           technically part of an aging management program, that
           it is buried in the corrective actions program.
                       And I guess what I need to do is I need to
           get some clarification about that and what the level
           of accountability is for that.  
                       CHAIRMAN BONACA:  It seems to me that --
           well, what we are saying is that the one time
           inspection would be adequate if we had not concern for
           a possible inspection phase issue that may have led to
           having coating chipped?
                       DR. BARTON:  Failure of the coating.
                       DR. FORD:  Or localized corrosion, which
           may occur the day after you have done an inspection.
                       MR. BURTON:  Right.  And of course I want
           to address your question, because I don't think that
           we really spoke to that.  The issue of degradation
           from the inside -- and actually you said it already.
                       I mean, part of the ongoing program
           currently, programs currently, is to sample.  So if
           there is any evidence of degradation, it is caught
           fairly early.  I am not sure what the frequency is,
           but there is guidance for that.
                       So if there is evidence of degradation,
           they jump on it right away, and it gets fed into the
           corrective actions program, and is dealt with.  
                       DR. BARTON:  Butch, my only point is that
           if you are going to go in the future, and if you are
           going to inspect other diesel fuel oil tanks for
           whatever reason -- you had a reason to inspect the 1-A
           tank.
                       But if you have any reason to go in and
           clean and inspect the other ones, do an ultrasonic
           inspection, or do an inspection and tests like you did
           on the 1-A tank somewhere down the road.  
                       That is what I am looking for to ensure
           that there is nothing going on in the other three
           tanks.  It is the same as if you have a buried pipe
           that has a leak.  
                       So you are going to excavate and you are
           going to go and repair it.  But you are going to also
           expose other pieces of this piping.  So you would go
           and look at that while you had the hole open, all
           right?
                       MR. BURTON:  Absolutely.
                       DR. BARTON:  And all I am saying is that
           if the opportunity presents itself in the future to do
           other fuel oil tank inspections, go do them, and right
           now you are letting them off the hook on a one-time
           sample of one tank.  That's my problem.
                       MR. BURTON:  Okay.  And I do understand. 
           I guess what I will ask Southern Nuclear to talk about
           is currently what their normal process is.  If they go
           in to do any work on a tank for whatever reason -- and
           I don't want to put words in your mouth, you know, if
           you speak to that.
                       But I think the normal -- I think even
           normally now that when you go in to do something --
                       DR. BARTON:  Why don't you ask them what
           they do.  Don't tell them what they do.
                       MR. BURTON:  You are absolutely right.  
                       DR. BARTON:  Yes, I'm good at that.
                       DR. FORD:  The internal corrosion, and to
           ask a question.  This standard that you have got not
           to exceed .1 percent of water, what data was that
           based on, and how much margin do you have if you have
           maintained that specification?  How much margin do you
           have?
                       MR. BURTON:  I don't know.  Jim, can you
           speak to that?
                       MR. DAVIS:  I am Jim Davis.  That is
           really more for damaging equipment than it is for
           damaging the tank.  You don't see any damage to a fuel
           oil tank because you have got water in it, because the
           oil keeps you from corroding.  You just don't see the
           damage.
                       DR. FORD:  Are the two liquids -- well,
           does the water just fall to the bottom?
                       MR. DAVIS:   Water falls to the bottom,
           yeah, but you still have a film of oil there, and you
           just don't see that damage.  I have seen air cushion
           vehicles operating in sea water in Vietnam, and the
           oil coming out of the gas turbine engines coated the
           steel bolts connected to aluminum.
                       And there was absolutely no corrosion, and
           I couldn't believe it, but there was no corrosion.
                       DR. BARTON:  Did you ever see a thousand
           gallon fuel oil tank on a boat that has got water in
           the fuel oil, and it gets holes in the bottom of the
           tank and leaks a thousand gallons of diesel fuel in
           the bilge?  I have.
                       MR. DAVIS:   Yes, I have seen that.
                       DR. BARTON:  Well, what is different here? 
           You are telling me that you have got oil protection
           coating, and you have got the water, and there is no
           corrosion.  Well, how come it corrodes in the boat,
           and it doesn't corrode in those tanks?
                       MR. DAVIS:  That's sea water, and -- 
                       DR. BARTON:  I have got sea water in the
           tank?
                       MR. DAVIS:   You can, yeah.  I mean, you
           are right in the ocean.
                       DR. BARTON:  Okay.
                       MR. DAVIS:   But really what I pushed for
           and what they actually do in a lot of these instances
           that I don't want to take credit for, is there are
           well-established methods for determining corrosion of
           these tanks, and you normally are more concerned about
           corrosion from the soil than you are from the
           interior.
                       DR. FORD:  Is it protected as well --
                       DR. BARTON:  No.
                       MR. DAVIS:   And if you own a gas station,
           there are certain things that you have to do that the
           nuclear industry doesn't do.  And I came from the oil
           and gas pipeline industry, and pipeline coatings.
                       And there are very simple techniques that
           you can use to determine how good your coatings are. 
           You know, if you coat a pipe for the Department of
           Transportation to transfer oil or gas, you have to
           cathodically protect it and coat it.
                       And you have to do a subpipe to soil
           potential survey every year, and that tells you
           exactly where you have any problems, but NEI refused
           to accept that.  And so we put in a provision that 
           -- and it's not just if you are having a leak. 
                       If you are going in there to make a
           change, or you are going in to modify a line when you
           look at the coatings, and we have a sub to that on all
           of the license renewal applications.
                       But you can do a coating conductance
           measurement, or something like that.  A lot of the
           utilities actually do that, but they don't want to
           take credit for it because they didn't purchase their
           rectifier safety related and that causes some
           problems.  So they are actually doing more than they
           are taking credit for.
                       DR. FORD:  I noticed that they say here
           that incidents of such leakages is very low.  But what
           would be the consequence?
                       MR. DAVIS:   Well, they are following EPA
           rules.  If they have a leak in a fuel oil tank, they
           have to clean it up, and that is very, very expensive.
                       DR. FORD:  Well, I was thinking more in
           terms of that, but also the safety of the plant.
                       CHAIRMAN BONACA:  Well, you have four
           tanks and probably the leakage would be small at the
           beginning.
                       DR. FORD:  So we are banging something to
           death.                
                       DR. KRESS:  Well, this is as to a safety
           issue.
                       DR. BARTON:  Well, I think you were about
           to ask the licensee what his inspection program would
           be?
                       MR. BURTON:  What is his normal practice,
           yes.  And I don't know if we have the people here to
           do that, but if you can talk a little bit about what
           is normally done when you go into the tanks and things
           like that, and the scope of any follow-up activities
           that would apply to other tanks.  If any of you all
           could speak to that.
                       MR. BAKER:  The ultrasonic examination
           that we did -- and again this is Ray Baker, but the
           ultrasonic examination would not be a routine thing. 
           And we took the opportunity to go ahead and do that.
                       And if a tank was being cleaned, certainly
           you would visually observe the condition.  You would
           note whether there was any localized corrosion on the
           interior.  And, of course, that just deals with the
           interior of the tank.
                       And as was said, you would not expect to
           see anything in there, because there is -- except
           perhaps the oil vapor space would be where you might
           be likely to see something if there was anything,
           because the rest of it would be coated with oil, and
           would be very resistant to attack.
                       The exterior surface would be observed by
           our excavation procedure.  If you excavated for any
           reason -- you were doing a plant modification and it
           required exposure of a part of a buried component,
           even though there was no leak or anything that had led
           you to that excavation, you would still bring in the
           coating specialist to check the condition of the
           coating.  That is excavation for any reason.
                       MR. BURTON:  And if you did find
           something, you have processes to deal with that, and
           to identify the possible scope of the problem.
                       MR. BAKER:  That's right.
                       MR. BURTON:  And things like that.
                       MR. BAKER:  Correct, and the corrective
           actions program is applied across all of our license
           renewal programs.  So it will assure then that if the
           individual program does not have built within it the
           tracking and trending, the corrective actions program
           assures that it gets tracked and corrected, and
           remediated.
                       DR. BARTON:  If I understand you
           correctly, if you had to go into another tank for
           cleaning somewhere down the road, you would do a
           visual of the interior of the tank.  That's what I
           thought I heard you say.
                       MR. BAKER:  That's correct.
                       DR. BARTON:  Why did you do an ultrasonic
           on the 1-A tank?  
                       MR. BAKER:  Because we knew that this was
           an issue that was being raised and we just wanted to
           satisfy ourselves and the staff that what we expected
           the result to be was in fact what we found. 
                       And that if we had found something
           different, then that piece of operating experience
           would have been factored into what we proposed as
           appropriate aging management programs.
                       DR. BARTON:  So based on that, you don't
           plan on doing anything for the next X number of years
           on any of these tanks?
                       MR. BAKER:  Unless operating experience
           were to show that there was something going on that we
           did not expect to see.  And as was indicated, we -- I
           think all licensees probably do more than they have
           committed to doing just to assure themselves that they
           do maintain that equipment.
                       So if we were to observe anything, the
           operating experience is a piece of the equation to
           factor in and do self-correction on these programs as
           we go through the period of extended operation.
                       We can't just ignore operating experience
           just because we now have the license for an extension. 
           We continue to see what is happening not only at our
           plant, but in the industry.
                       DR. KRESS:  If you had a leak, would you
           know about it?  Do you have liquid level measurements
           in those tanks?
                       MR. BAKER:  It would have to be a pretty
           significant leak to observe it right away I think. 
           But ultimately you would observe it, and as was said,
           that would be a pretty big deal.  You would be in
           trouble with the EPA, and there would be an expensive
           process. 
                       DR. BARTON:  It would be cheaper to do an
           ultrasonic if they ever opened another tank than to
           clean up if I had a leak.
                       MR. BAKER:  Yes.  And I am not saying that
           we would not do that apart from what is committed to,
           because I know in other areas of the plant we have
           some aggressive programs to do radiography in areas
           where we are looking to see if there is wall thinning. 
           So it is not something that we want to ignore.  You're
           right.
                       DR. BARTON:  Okay.  The reason that I am
           being a stickler on this is because I was at a plant
           that ended up with tanks leaking, all right?  And then
           after 30 something years, you know?
                       So here you are doing a one-time
           inspection for 60 years, and then you are saying
           everything is hunky-dory, and I am not going to do
           anything else, and that is what bothers me.  All
           right.  End of my spiel.
                       CHAIRMAN BONACA:  I have just one more
           question.  How do we treat this for -- if I remember
           for the other applications, they also had one time
           inspections.
                       MR. NAKOSKI:  That's true.  That's true.
                       MR. BURTON:  I want to -- and I think it
           will get to yours, too, because I don't want to let
           Dr. Barton's question go just yet, because I
           understand where you are coming from in terms of what
           it says in the application.  
                       It sounds like we do a one time
           inspection--
                       DR. BARTON:  Of one tank.
                       MR. BURTON:  -- of one tank, and the
           results were satisfactory, and we don't need to go on.
                       DR. BARTON:  And I won't do anything else
           unless I have a leak.
                       MR. BURTON:  Right.  I think -- and
           probably we need to clarify this in the SERs, is that
           -- and when Mr. Baker talked about operating
           experience, it is more than just even the operating
           experience at that particular plant.  
                       One of the things that -- and it is an
           ongoing think that is factored in, is that if there is
           any evidence that this commodity group shows evidence
           of leakage or any kind of degradation, the license
           renewal process factors that knowledge in, whether it
           is plant specific operating experience, or industry-
           wide operating experience.
                       And that is an ongoing thing that goes on
           now, and will continue to go on into the renewal term. 
           So your concern that we look at it this one time, and
           it is never looked at again, is really not what
           happens.
                       But if we need to clarify that in the SER,
           that probably would be beneficial to talk more about
           some of the more routine things that go on.
                       CHAIRMAN BONACA:  And also I think you
           might want to think about it in terms of -- and this
           is in preparation for the presentation for the full
           committee, but in terms of the specific definition of
           the rule, I would suspect that this is a support
           system and this failure could cause safety systems not
           to perform.
                       MR. BURTON:  The aging criteria.
                       CHAIRMAN BONACA:  And you went on to look
           at it in the context of what would it take to lose
           function, which means to empty the tank to the point
           where you are really losing inventory, because from
           the perspective of the rule, that is really it seems
           to me the objective you have.
                       DR. KRESS:  But the question is, is there
           a safety concern, and that would be one question.
                       CHAIRMAN BONACA:  And they would be going
           into that.  So I think that is clearly an issue that
           we raise, and want to talk about.
                       DR. KRESS:  If there is no safety concern,
           it just seems like it is up to the applicant to deal
           with it the way that he wants to. 
                       CHAIRMAN BONACA:  Correct.
                       MR. DAVIS:   This is Jim Davis again. 
           Under the current regulations, they require nothing.
                       CHAIRMAN BONACA:  Well, that's why before
           I was asking what is the regulation asking for under
           the current --
                       MR. DAVIS:   There is no requirement.
                       CHAIRMAN BONACA:  I was asking before what
           do the current regulations require for the current
           term, and the answer is --
                       MR. DAVIS:   That there is no requirement.
                       CHAIRMAN BONACA:  -- there is no
           requirement.  But I think the presumption is that you
           would leak oil at a rate that would not -- well, by
           the time that it manifests itself, you would still
           have sufficient inventory in the four tanks to run
           your four diesels for the commitment that you have in
           the FSAR.
                       MR. BAKER:  Dr. Bonaca, if I could
           clarify.  There are two sets of tanks that are of
           interest when you are dealing with the emergency
           diesel generators.  These are the bulk fuel oil
           storage tanks.
                       The day tanks, which are associated with
           the immediate operability of the diesel generators,
           are above ground and are separate tanks.  So these are
           just the bulk fuel oil storage.
                       CHAIRMAN BONACA:  Okay.
                       MR. BURTON:  Okay.  But we will be
           prepared to talk about that a little bit more next
           week.  The next open item was 3.1.11-1, having to do
           with stress corrosion cracking of high-strength bolts.
                       The issue was that we know that bolting
           that has a yield strength below 150 ksi is not really
           subject to stress corrosion cracking.  
                       DR. KRESS:  Why is that?  Does that have
           to do with residual stresses?
                       MR. DAVIS:  This is Jim Davis.  It is the
           microstructure of the material.  We know that
           materials that have a yield strength above 150 ksi can
           be subject to hydrogen embrittlement actually.  We
           call it stress corrosion, but they can crack just in
           moist air. 
                       DR. KRESS:  Because they have a very small
           micro structure?
                       MR. DAVIS:  Yes.  It is probably -- well,
           it is a strength issue, and it is related to the
           microstructure.  So the specifications say a minimum
           of 125 ksi yield, and what happened was that we saw
           yields in the neighborhood of 175, and made sure that
           they met the 125.
                       And after a lot of study, we found that
           anything below 150, really you don't see the cracking
           problems.
                       MR. BURTON:  It's great to have a
           materials guy around.  Thanks.
                       CHAIRMAN BONACA:  Well, with this issue --
           well, go ahead.
                       DR. FORD:  May I ask -- well, in this item
           you say an approved thread lubricant.  
                       MR. BURTON:  I'm sorry, what?
                       DR. FORD:  It says to be lubricated with
           an approved thread lubricant.  It is not molybdic
           sulfite by any chance?
                       MR. DAVIS:  No.  That has been found to
           cause cracking very definitely.  A lot of the cracking
           problems were related to the thread lubricant, with
           molybdic sulfite decomposed to hydrogen sulfite.  
                       DR. KRESS:  So the resolution is or
           experience has shown that these particular bolts had
           a cracking problem?
                       MR. BURTON:  Right.  These bolts are used
           across a number of different systems, and what we
           found was that when we asked them to go back and look
           at some of the procurement data to see what that high
           limit was, it wasn't in the documentation.
                       So what they did was that they went back
           and again looked at operating experience and found
           that stress corrosion cracking for these bolts, that
           they really had not seen it across the industry.
                       DR. KRESS:  And where do they use these
           bolts?  Are they around the head, or --
                       MR. DAVIS:  They are used everywhere. 
           There is about 40,000 of them in the plant.  They are
           used on pumps, valves.
                       DR. KRESS:  And in the primary system they
           are used?
                       MR. DAVIS:   They are used in the primary
           system, and in the primary system the only place that
           I am aware that they are used are in pumps and valves. 
           Everything else is welded.
                       CHAIRMAN BONACA:  Let me tell you what
           makes me a little bit uncomfortable about this.  Just
           a month ago, we looked at Turkey Point and the same
           issues.  And they say, oh, yeah, in fact we are
           concerned enough that in our procedures we have a
           limit of 150 ksi in our positions, and so when you
           tork these bolts, you don't go above that.
                       Now here we are a month later, and we see
           a different applicant that says, oh, there is no
           issue.  Well, I am left with the feeling that we don't
           know where this is coming from.  
                       MR. DAVIS:   They are two different issues
           actually.
                       CHAIRMAN BONACA:  Were they?
                       MR. DAVIS:  Yes.  The high strength steel
           issue is the yield strength can't be above 150 ksi,
           and for A286 bolts, which are a corrosion resistant
           fastener, if you tork those above 100 ksi, then you
           are going to have stress corrosion problems.  Those
           are two different issues.
                       CHAIRMAN BONACA:  So two different types
           of bolts.
                       MR. DAVIS:   Right.
                       CHAIRMAN BONACA:  Could you explain to me
           exactly the difference again?
                       MR. DAVIS:   Well, they had both issues at
           Turkey Point, and we raised -- or I raised both
           issues, and that is the high strength steel with the
           yield strength above 150, and what they did was they
           did a license event report review, and found that they
           had no operating history of any problems with those
           bolts.
                       With PWRs, there is another issue, and
           that is that when you do system pressure tests, you
           have to remove the insulation, and inspect the bolts,
           and there is a code case N616 that says -- ASME Code
           case that says if you have corrosion resistant
           fasteners, you don't have to remover the insulation.
                       And we impose some requirements on heat
           treatment and applied stress.  For 17 -- and stainless
           steel, you have to temper the temperature, or the age
           of the temperature above 1100F, and then you won't get
           into stress corrosion problems.
                       With A286, if you apply a preload above a
           hundred ksi, you are going to start seeing stress
           corrosion cracking.
                       CHAIRMAN BONACA:  So you think it is still
           appropriate after the discussion, that it is
           appropriate to have Turkey Point have their procedures
           stay below 150 ksi?
                       MR. DAVIS:  Yes, that's right, and they
           went back and looked at the certified material test
           reports to show that either they didn't have any above
           150, or that they had no experience with any cracking.
                       CHAIRMAN BONACA:  And I went back to the
           Turkey Point, and in the discussion I just could not
           pick out the difference, and maybe I should have. 
           Thank you.
                       DR. FORD:  But the point here is that the
           minimum yield -- this is for the specifications,
           procurement specifications, with a minimum yield
           stress of 105, and there is no upper limit stated.  So
           they were lucky.  They weren't above 150.
                       MR. DAVIS:  Well, actually, there have
           been some that are above 150.  They have been as high
           as 175.  When people start seeing cracking problems,
           the industry kind of modified that specification and
           they are asking -- well, most of the industry, and I
           won't say for everybody.  But they are saying that
           between 105 and 150 yield.
                       DR. FORD:  But for these applications,
           would it not be wise to impose it on the
           specification?
                       MR. DAVIS:  I think that they already know
           that.  
                       DR. FORD:  Well, there is a difference in
           knowing it and in fact demanding it I would expect.
                       MR. DAVIS:  We could do that, but that's
           not really the issue, because there is 40,000
           fasteners already installed in that plant, and if we
           did a back-fit analysis and remove the antibolts with
           a yield strength above 150, we couldn't satisfy the
           back-fit requirements under 50.109.
                       DR. FORD:  But if you go into license
           renewal in the future, this will occur, and it should
           be documented, and in the future you will not or
           should not.
                       MR. BURTON:  Well, I think that the
           industry is aware of the fact that if they maintain
           high strength steel fasteners with a yield strength
           above 150 that they can get into trouble.
                       But that is not the real problem, because
           they don't change these fasteners all that often. 
           They have got 40,000 fasteners in there, and they are
           not going to go back and change them.
                       And unless we do a back-fit analysis and
           show that there is a problem, then we can't justify
           that.  I am aware of two cases where there have been
           a problem in the nuclear industry, and that is at
           Dresden.
                       And they had closure studs that were
           overly hard, and they had two of them that cracked. 
           But there has been no other occurrences, but I still
           ask the question just to make sure
                       MR. BURTON:  Okay.  Thank you, Jim.  The
           next open item was 3.1.13-1.  This open item actually
           had three parts to it.  The first part -- and we have
           actually started to talk about this -- had to do with
           buried components.  
                       The license renewal application credited
           this for managing aging effects of buried components,
           but when you went to the actual write-up in the amp,
           it didn't really speak to the buried components.
                       And so as a result the applicant clarified
           that the protective coatings program, that amp, is
           really what does the managing.  But what happens is
           that again, going down to these site procedures, the
           site procedures invokes an inspection that is part of
           this program.  
                       And part of that inspection is to use
           protective coatings personnel to look at the buried
           components, and they use the protective coatings
           program to do that.
                       So there is a linkage between the two
           applications, but the staff was a little unclear as to
           what the linkage was.  So they clarified it.
                       CHAIRMAN BONACA:  And that was brought up
           by the clarification in fact now.  So is the
           commitment only in site procedures, or is it also a
           license renewal commitment?
                       MR. BURTON:  The commitment -- well, go
           ahead. 
                       MR. BAKER:  It is programmatic.  It is in
           the program, yes, sir.
                       CHAIRMAN BONACA:  In the program?
                       MR. BURTON:  Yes, sir.
                       CHAIRMAN BONACA:  All right.
                       DR. BARTON:  And the words in the SER say
           that you will place this in the instruction.  My
           question is have you already done it?
                       MR. BURTON:  Yes.
                       MR. BAKER:  On that particular one, the
           trigger to get the coatings specialist in when buried
           components are exposed is already in the site
           procedures.
                       DR. BARTON:  And they will be examined by
           a protective coating specialist?  That is already in
           the procedures?
                       MR. BAKER:  The trigger to do that is
           already in there, yes, sir.
                       MR. BURTON:  And we will make that change
           to say that it has been done.
                       DR. BARTON:  Good, because this looks like
           you are going to do it when you go to license
           extension.
                       MR. BURTON:  All right.  Now --
                       DR. BARTON:  Don't end up.  I have another
           question with this one.  There is a third part to
           this, Part C.  Are you going to break this up into
           three pieces, or are you going to be done with it?
                       MR. BURTON:  No, no, go ahead.  Ask your
           question.
                       DR. BARTON:  The staff proposed to close
           the site and based on the applicant stating the plan
           is to inspect portions of PSW piping that is
           surrounded by guard piping during an outage during
           February of 2002.
                       Now, I heard what John said, is that they
           are going to have tracking, and these guys are going
           to do this inspection, et cetera.  Are you prepared to
           make sure that any outage scope of this February 2nd
           thing, that this is already in there?
                       MR. BURTON:  Actually, let me put some
           context in there.  What happened was that when we went
           down for the scoping inspection, there were three
           issues associated with this, and we have jumped to the
           third issue.
                       DR. BARTON:  This is the third issue.
                       MR. BURTON:  So let me speak to that and
           then I will go back to the second one.  This has to do
           with the plant service water guard pipe.  What
           happened was that during the scoping inspection, one
           of our regional inspectors, going through some of the
           diagrams, saw this section of guard pipe, and it just
           wasn't discussed at all.
                       So the question came up should this
           component be in scope.  So Southern Nuclear went back
           and looked at it, and looked at the intended function. 
           There is absolutely no documentation anywhere of what
           this guide pipe is supposed to be for.
                       So they went through there and asked their
           eight questions for the scoping criteria, and found
           that it did not have an intended function, and so it
           was not put in scope.
                       The problem is that this guard pipe is
           actually welded.  It is in the diesel generator
           building.  I guess it is about a hundred-foot section
           or so, and it is welded at each end to the exterior of
           the plant service water piping, which is in scope.  
                       So what it does is that it creates an
           internal environment that we are not sure what it is. 
           So again common sense tells you when they welded it
           that it is probably just dry air in there, and that
           there probably isn't any aging effect associated with
           it, but we don't know that for sure.
                       So what they said they would do is that
           during the next outage, they would actually go in and
           put in a baroscope or something, and take a look in
           there, and see exactly what the environment is.
                       Again, we don't anticipate any adverse
           aging effects.  but if they go in and they do find it,
           again it gets fed into the corrective active program,
           and is dispositioned accordingly.
                       DR. BARTON:  My question is whether it is
           already in the outage scope, or is nailed in the
           outage scope for the February 202 outage, and has the
           NRC confirmed it is in the outage scope?  That is my
           question.
                       MR. BURTON:  Right now do you guys have it
           as part of your plans for the outage?
                       MR. BAKER:  We plan to do it.  I can't
           speak to whether it is in an outage scope of work
           activities, or whether NRC has confirmed that it is
           there.  But the engineer who is going to be doing that
           work is planning on doing that work.
                       DR. BARTON:  The reason that I asked the
           question is usually this close to an outage, your
           scope is frozen.
                       MR. BAKER:  That's right.
                       DR. BARTON:  And if it is not in there
           now, are you going to be able to get it in there, and
           has the NRC confirmed that it is in there.  That's my
           concern.  
                       You made a commitment to do it, and I want
           to know if it is in the outage scope, and it is
           approved in the outage scope, and the NRC is satisfied
           that it is in there.
                       MR. BAKER:  What we should so -- well, we
           can call back and ask.  I am certain that it is,
           because I was just talking with the individual this
           week about it again, and he said, yes, that is still
           on track, and we intend to do that.  So I will get
           confirmation on that before the day is over.
                       DR. BARTON:  Thank you.
                       MR. BURTON:  And let me just say from our
           end that given the circumstances, we weren't sure
           whether we needed to lock this in with a license
           commitment, or license condition and that sort of
           thing, because they are saying that they are going to
           do it in February, which is like the time frame when
           we are talking about issuing the renewed license,
           again it was another timing issue where things could
           be working at cross-purposes.
                       DR. BARTON:  I am just reading what they
           said, and I am asking did they do it, and are they
           sure it is in here, and are you guys satisfied.
                       MR. BURTON:  Right.  And I will say that
           on our end our resident inspector, he has it on his
           "to do" list togo and check that out when that is
           done.  So we expect that to be done in February, and
           we have the things in place to make sure that it is
           done.
                       DR. BARTON:  Thank you.
                       MR. BURTON:  Okay.  Now, let me back up to
           issue number two.  Now, I wasn't sure whether you were
           talking about a third part in the first issue or just
           the third issue.  But it is no problem.
                       We needed some clarification regarding the
           treatment of the RHR heat exchangers.  The activities
           in the PSW and RHR service water inspection program
           apply across a number of components, including heat
           exchangers.  
                       There is another aging management program,
           and I have an open item associated with that, but it
           is the RHR heat exchanger augmented inspection and
           testing program, which also speaks to activities
           associated with the RHR heat exchanger.
                       So the issue came up, well, which one does
           what.  So part of the resolution was that they
           clarified this program, and the plant service water
           and RHR service water really does more than just a
           visual inspection of surfaces.
                       Whereas, the RHR heat exchanger augmented
           inspection testing program is really the primary amp
           to deal with components in the RHR system, looking at
           internals and things like that.
                       So they just clarified the scope
           difference between the two.  Okay.  Let's see.  The
           next open item, the reactor vessel monitoring program. 
           This is another aging management program.  This
           program actually is sort of a compilation of three
           different things.
                       There are three parts to it.  There is a
           fatigue monitoring aspect, which actually is done
           through an aging management program called the
           component SLIC or transient limit program, CCTLP.  It
           is done through that, and there is also aspects to it
           that are TLAA.  
                       Another aspect of the program are code
           required augmented inspections and tests, and that is
           done through the ISI program, which is also one of the
           aging management programs that they credit.
                       The third has to do with surveillance
           materials testing, and that was the basis of the open
           item.  The issue here is that there is a BWR VIP 78
           for an integrated surveillance program, where they are
           trying to work the surveillances across the entire BWR
           fleet.  
                       The problem is that when they submitted
           the application the staff was in the process of
           reviewing this.  Now, the current status is that we
           finished the review, and I am going to turn to Gene
           just to be clear exactly about what the status is of
           VIP-78, and its associated implementing document, 86. 
           If you want to speak to that for a second.
                       MR. CARPENTER:  This is Gene Carpenter. 
           Basically, the staff has completed the review of the
           BWRVIP-78 and the VIP-86 document, which is the
           implementation plan.  
                       We are in the process of documenting that
           in a safety evaluation report, and that should be on
           the street within the next month or so.  
                       MR. BURTON:  Thanks.  So what we had was
           that we had the crediting of a document that hadn't
           gone through our review process yet.  So what we had
           was that we asked them either to commit to that, or if
           that doesn't go through, to commit to a plan specific
           material surveillance program.
                       And the open item came out that we need
           this to be clear that those will meet Part 54, and the
           10 attributes for the aging management programs.  So
           we needed to get that commitment.
                       We did get it, and they said we will do
           one or the other.  Either way, it will meet the
           requirements of Part 54, and the 10 attributes, and we
           locked them in with a license condition.  That is the
           third license condition.  The first two I already
           mentioned having to do with the FSAR supplement, and
           this was the third one.
                       DR. FORD:  I am a little bit unsure about
           the 78.  It was only applicable to the current
           licensing period, and they are going to put in a
           supplement due in 2002 for the extended period?
                       MR. CARPENTER:  That is correct.
                       DR. FORD:  What are the details of that? 
           Why is it limited to only the current licensing
           period? 
                       MR. CARPENTER:  As the VIPs of the
           document is presently written, it is for the current
           operating term.  The reason that it is not at present
           for the extended operating period is because the
           BWRVIP program takes credit for a variety of plants
           surveillance materials.  
                       When the program was initially implemented
           or put together by the BWRVIP, they still were not
           sure which licensee, which BWR licensees, were going
           to be going for a license renewal.
                       They are in the process at this time of
           finalizing which plants will be in the license renewal
           period, and they will be able to take advantage of.
                       This is going to be a somewhat fluid
           matrix, because as things change, they need to have
           something that is flexible enough, a program that is
           flexible enough that will allow for Plant X, Y, Z,
           which would be one that they would take credit for,
           does not for whatever reason go into the license
           renewal period.  
                       They need to be able to be flexible enough
           to move to another plant and to make adjustments for
           it.  So this is something that the staff and the
           BWRVIP are working together on to ensure --
                       DR. FORD:  And this relates to the number
           of capsule samples at various fluence levels, and
           instead of going into the expected fluence for a given
           plant in a license renewal period, or is it something
           to do with that?  I am trying to work out why you need
           all these other licensees to --
                       MR. CARPENTER:  Well, it is an integrated
           surveillance program, where you have one licensee
           pulling its capsules and several other licensees being
           able to take advantage of that study. 
                       DR. FORD:  So you are studying all the
           fluence levels?
                       MR. CARPENTER:  Correct.
                       DR. FORD:  Okay.  That is what I was
           getting at. 
                       MR. CARPENTER:  Yes.
                       DR. FORD:  Okay.  
                       MR. CARPENTER:  Robin, did you want to add
           something?
                       MR. DYLE:  Yes, Gene, thank you.  This is
           Robin Dyle of Southern Nuclear.  The VIP-78 document
           is the technical basis document for why an integrated
           surveillance program is appropriate, and how you would
           go through and screen for fluence materials and select
           the best capsules that would be representative for the
           fleet.
                       And that 86, as Gene correctly
           characterizes, is the implementation schedule.  We
           believed at the time that we put it together that all
           those plants would go for license renewal, and for one
           reason or another we are not ready to make that
           commitment.
                       And instead of sitting on the
           implementation schedule, we put one together for the
           current term, and submitted it, and then we will
           revise the implementation schedule.  The technical
           basis won't change.
                       We have to be able to predict fluence, and
           we have to be able to test a range of capsules that
           will give an overview of what the fleet behavior is
           for vessel embrittlement.  So that is the way the
           program is put together.
                       Just as a note, both Hatch units capsules
           were going to be pulled as part of the ISP anyway, and
           so it doesn't affect Hatch one way or the other.  That
           is where we currently are.  
                       MR. BURTON:  And that is an important
           point, and that's why they can make the commitment
           that if 78, for whatever reason, doesn't work out,
           they can do it themselves.  
                       CHAIRMAN BONACA:  Okay.  Good.  
                       MR. BURTON:  The next open item was
           3.1.18-1, having to do with fire protection.  There
           are actually two issues associated with this.  The
           first one had to do with the adequacy of system flow
           tests to be able to manage aging.  
                       This was another one of these issues that
           was being worked at cross-purposes generically, and
           what was finally determined was that we did not need
           to have system flow tests per se as part of the aging
           management program.
                       It is currently done already and will
           continue to be done in the extended term.  But what we
           do have is that we do have an aging management program
           called fire protection activities, which is primarily
           inspections.
                       And so the idea is that those inspections,
           as part of the aging management program, along with
           the ongoing flow tests, should together be adequate to
           manage aging for the fire protection components in the
           extended term.  
                       DR. KRESS:  Did you inspect just the
           heads?
                       MR. BURTON:  The extent of the inspection? 
           I don't think it was just the heads.  I think they
           look at the piping and all the way up and down.  I
           think they look at everything.  There are some issues
           with the heads which I am going to get to, but yeah.
                       DR. KRESS:  And what did the flow tests
           consist of?  Do they actually turn these on?
                       MR. BURTON:  Well, what it is -- well, I
           do actually have some notes about that.  What they
           have is what they call an inspectors connection, and
           which is at the furtherest end of the system.  And
           what they do is that they actually just run the flow
           all the way through.  
                       DR. KRESS:  Run it into a bucket or
           something and that tells you how much?
                       DR. BARTON:  Yes, I guess it is a bucket
           or something like that.
                       DR. KRESS:  So it is a measure of the flow
           rate?
                       MR. BURTON:  Right, and the existence of
           the flow, right.
                       MR. BAKER:  At the furtherest point of the
           branch connections, right.
                       MR. BURTON:  Right.
                       DR. KRESS:  So what that tells you is that
           when you turn the system on that you are going to get
           flow?
                       MR. BURTON:  You are going to get flow,
           right.  Now, the issue --
                       DR. KRESS:  And what does that tell you
           about aging; that was my question.
                       MR. BURTON:  Well, that was the question. 
           Does that really tell you anything about age related
           degradation, and the question was that it really
           didn't.  What you really have to rely on is actually
           doing the inspections to see what is actually going
           on.
                       But between that and the flow tests, you
           have kind of got everything covered.  But, yes, the
           actual age related degradation, what we are depending
           on and what is being credited for license renewal, are
           the inspections as part of the fire protection
           activities amp.
                       DR. KRESS:  So my question once again is
           how extensive is the inspection, and what all does it
           look at, and how often?
                       MR. BURTON:  And I can either speak to
           that, or -- oh, Tanya.  I'm sorry.  You did come back.
                       MS. EATON:  This is Tanya Eaton, NRR, and
           I was the fire protection engineer that reviewed the
           application.  And Jim just told me, as I was out, and
           he said that you all were asking questions about the
           inspectors flow test, and how that is performed.
                       I know that -- well, I don't know if Butch
           explained this, but usually the most remote connection
           from the water supply, and so what they do is -- and
           I know, for example, with ANO, their connection was on
           the roof of some building somewhere.
                       And it hydraulically is the most remote
           point from the water supply.  So when they flow that,
           they are able to look at the water to see if there is
           any type of corrosion products that are coming from it
           or anything.
                       I don't know that they tested it.  That is
           not an NFPA requirement.  Usually, they are just
           trying to ensure that they are getting flow through
           the system.  
                       DR. KRESS:  How often do they do that?
                       MS. EATON:  I think it is annual.  If you
           look in NFPA-13 requirements, every year they will do
           the inspectors flow test.
                       DR. FORD:  As I read this, it is saying
           that you could have a situation of the year 49, for
           instance, and you suddenly want to turn on the
           sprinkler systems, and you are hoping that nothing has
           occurred from a corrosion point of view.  And this is
           not the time to be assuming no corrosion is going to
           occur in 49 years.  
                       CHAIRMAN BONACA:  This is the second issue
           item.
                       MR. BURTON:  Yes, we are actually getting
           into the second issue. 
                       CHAIRMAN BONACA:  And that is an
           interesting one by the way, Issue Number 2.  I just
           don't understand -- you know, it seems to me that the
           earlier that you perform an inspection the better off
           you are.
                       Now, we understand that the licensee
           proposed to perform a one time inspection before 40
           years.  And the staff said no, and you have to go
           NFPA, and the NFPA requires a one time inspection of
           50 years. 
                       MS. EATON:  It is not one time.
                       DR. BARTON:  It is 50 years.
                       CHAIRMAN BONACA:  Fifty years, because it
           says 50 years, and then your intervals.  Well, at 60
           years, the plant is retired, at least for this
           license.
                       MS. EATON:  I can address that.  The time
           -- well, if you look at the NFPA requirement, it
           requires at 50 years of service life of the
           components, and if you look at what I think Hatch was
           doing in this case, at 40 year operating life, their
           suppression system -- I think the sprinklers were
           going to be something like 46 or 47 years old.
                       So at that point when they were testing,
           right before they go into renewal, the system was
           already going to be 47 years old.  And I think
           initially that they proposed to do this as a one-time
           inspection.
                       The NFPA 25 requirement is that you do it
           at 50 year service life, and then you do it at 10 year
           intervals thereafter, and that is what we were trying
           to have them do, which was not just to do the one
           inspection.
                       CHAIRMAN BONACA:  So at the end of 50
           years, you are telling me that 50 years will come
           actually after 3 or 4 years in the new licensing
           period.
                       MS. EATON:  Right.
                       CHAIRMAN BONACA:  You see, that is not
           clear in the SER at all.  The SER speaks of 50 years,
           and 50 years from the moment of the license, and you
           are telling me that actually you are starting the
           clock years before.  
                       MS. EATON:  When it is installed and
           operable, right.
                       CHAIRMAN BONACA:  So for the 50 year --
           all right.  I think it would be important to have some
           clarification in the SER just to specify that that 50
           years -- well, because when you read that, you are
           saying, well, you give up at 40 years of inspection,
           and then you are waiting 10 years longer.
                       And that way you would have two
           inspections than one at, say, 43 years, and the other
           one at 53.
                       MR. BURTON:  Right.
                       MS. EATON:  Right.
                       DR. FORD:  When they came up with this
           specification, this 50 year business or whatever the
           number, they are very large numbers.
                       MS. EATON:  Right.
                       DR. FORD:  What data is -- 
                       MS. EATON:  I think what NFPA looked at
           was that their program, NFPA-25 has programs for the
           inspection, testing, and maintenance of fire
           suppression teams, and that in most cases it was their
           understanding that if you follow those programs that
           at your 50, that's when you really need to begin
           checking for the type of failures that you might see
           due to corrosion.
                       And with most licensees, we found that
           they would commit to NFPA-13, which is the sprinkler
           code that requires them to install suppression
           systems, and then they will have maintenance procedure
           inspections that are in accordance with the NFPA
           requirements that they follow.  And that is all the
           information that I have.
                       DR. FORD:  It just seems an incredibly
           long time --
                       MR. BURTON:  Yes, it is a long time.
                       DR. FORD:  -- of being assured that no
           corrosion has occurred.  
                       MS. EATON:  Right.  The NFPA requirements
           are also the minimum requirements.  It is always up to
           whoever the authority having jurisdiction is, which in
           this case will be the NRC to say that we require
           beyond that for these types of applications.  
                       If we see that there is evidence out there
           that shows that there are problems being experienced
           in cases of less than 50 year time periods.   
                       DR. FORD:  Well, shouldn't the NRC be
           applying -- I mean, this thing was done for warehouse
           --
                       MS. EATON:  No, NFPA-25 is -- a lot of
           industries outside of nuclear use that as guidance for
           whatever their particular industry is.  And so in the
           case for the NRC, if we find that -- well, for nuclear
           energies, we think that they should look before 50
           years, and we would need evidence to support that from
           our perspective.
                       I know that there have been studies done
           in the fire protection section to look at corrosion
           and blockage due to corrosion, and those types of
           things.  And we were unable to find any cases or we
           looked through licensee event reports, inspection
           reports.
                       And there were two studies.  One was done
           in the '80s, and another in the '90s, and I don't have
           the numbers now.  But the conclusions reached were
           that the licensees were aware that this could be a
           problem.
                       They had programs in place to at it, and
           to manage it if it were a problem.  It is not just a
           license renewal issue.  That is more of a current
           licensing issue.
                       CHAIRMAN BONACA:  Are these wet pipes or
           dry pipes?
                       MS. EATON:  For NFPA-25?
                       CHAIRMAN BONACA:  Yes.
                       DR. FORD:  Carbon steel pipes.
                       MR. BAKER:  Let me clarify.  Dr. Bonaca,
           this is Ray Baker again.  The item that we are talking
           about here is an inspection of a -- it is actually a
           destructive examination of a closed-head sprinkler.
                       And that is a separate issue from all of
           the other more general fire protection activities,
           where you are concerning yourself with corrosion, and
           blockage, and these other things.  
                       The specific issue here relative to this
           50 years of service testing is to ensure that that
           closed head sprinkler will actually actuate, and that
           is the thing that NFPA-25 is addressing itself to with
           regard to this 50 year service test.
                       And just to clarify the distinction that
           we are not talking about corrosion and those kinds of
           things with regard to this sprinkler.
                       DR. FORD:  The stocking -- 
                       MR. DAVIS:   That is part of the assurance
           that we give ourselves with the system flow test at
           the furthest branch connection to ensure that
           throughout that entire time period we are not
           accumulating a corrosion problem that might lead to a
           flow blockage situation.
                       DR. KRESS:  It seems like the corrosion
           products would accumulate in the head.
                       DR. BARTON:  That's where they will go.
                       MR. BAKER:  Well, on these closed systems,
           there is not going to be any flow in those branch
           lines.
                       DR. KRESS:  Well, there is static all the
           time.
                       MR. BAKER:  Right.  Right.
                       DR. KRESS:  Stuff can't get down there.
                       DR. BARTON:  It has a lot of moist carbon
           steel, and it is a dry system or --
                       MR. BAKER:  No, it is a wet system.
                       DR. KRESS:  They have little pony puffs
           that they can't pull.
                       DR. BARTON:  So you have got air in there,
           and water, and you have got some corrosion in the
           pipe.
                       MS. EATON:  The NFPA requirement for 25
           does require that you test a sample of each type of
           sprinkler head that is in the plant.  So if they did
           find problems, then they would have to go back and
           replace those heads.
                       DR. KRESS:  You made a study of NFPA-25 to
           assure yourself that it would be applicable to
           nuclear, because the issues are protection of
           investment versus safety, and I think that NFPA
           doesn't look to you for safety does it?
                       MS. EATON:  They do.  I think the concept
           is that the sprinkler systems are designed similar. 
           In either case, you don't want to have failure,
           whether you are protecting life or equipment.  
                       And especially in the case where you have
           safety related equipment.  You don't want to have
           failures.
                       DR. KRESS:  Yes, but there is a difference
           whether you are protecting life or equipment.
                       DR. BARTON:  That's right.  There really
           is.
                       MS. EATON:  Right.  But the systems are
           designed the same, and I think that they apply them in
           general throughout if you look at the NFPA-25
           guidance.             
                       DR. KRESS:  But my question is, is that
           applicable to nuclear, where chances of an accident is
           not just limited to the site, and I would question the
           applicability of that to nuclear safety.
                       DR. BARTON:  That's a good point.  Is it
           Bloomingdale's, or is it Plant Hatch.
                       DR. KRESS:  Is it an insurance issue or is
           it something else.
                       DR. BARTON:  That's right.
                       MR. BURTON:  Okay.  We will go back and
           research that a little bit and get an answer for you.
                       DR. KRESS:  I appreciate it.  
                       MR. BURTON:  Thank you, Tanya.  
                       CHAIRMAN BONACA:  Let's finish these items
           here, and then we will take a break.
                       MR. DAVIS:  I would like to make a comment
           on the 50 year life.  In a former life, I used to make
           fire protection pipe as well.
                       MR. BURTON:  He did it all.
                       DR. BARTON:  No doubt about it.
                       MR. DAVIS:   Actually, what occurs is that
           most of these are static and they are always filled
           with water.  And when you consume -- it drops to an
           extremely low value, and there were lots and lots of
           studies -- and this is in the '70s that I did this
           one, and I am an old guy.  
                       But they really had some good studies and
           they projected the corrosion rate, and what they
           really recommend is that you don't really disturb the
           system too much, because when you put new oxide in
           there, it starts to corrosion over again.  
                       All these piping systems were designed to
           last 50 years, and still be within a margin of safety
           just for the thickness of the pipe.  
                       So they are just plain carbon, carbon
           steel pipe.  And they  last that long, and they did a
           lot of corrosion studies to show that they would last
           that long.  They have a lot of data.
                       CHAIRMAN BONACA:  I would expect also that
           if you had a lot of corrosion going on and tests that
           you performed once a year, it would show the clogging
           of the sprinkler heads at the end of the rods.
                       DR. KRESS:  Except that they don't check
           the sprinkler heads as I understand it.
                       DR. BARTON:  They normally just check
           flow.
                       CHAIRMAN BONACA:  Just the flow, and as I
           was saying, you would have a lot of junk coming out.
                       
                       DR. KRESS:  I don't think so, because I
           think they would tap in before you get to the heads. 
           You wouldn't find out anything about the heads.
                       CHAIRMAN BONACA:  No, I am talking about
           the corrosion of the piping.
                       DR. KRESS:  Well, you would find out
           whether they had crap in the water, yes.
                       MR. DAVIS:   And we have had plenty of
           discussions on this, and what we should do, and
           reflecting about maybe putting or changing it as well.
                       And should we make them if they are going
           to go into the pipe, look and see if there is any
           corrosion, and I really recommended against that, and
           I think the better approach would be to do some
           ultrasonic measurements, and not disturb the pipe,
           because you are really doing more damage by opening it
           up and looking at it, because you are reintroducing
           oxygen into it.
                       DR. KRESS:  And then you have a problem as
           to where to do the measuring.
                       MR. DAVIS:   Right.  And so that's what we
           are saying, and saying in GALL -- well, I am not sure
           that we have made the change, and that would be to do
           ultrasonic measurements for wall thickness and see if
           you are losing wall.  
                       DR. FORD:  Well, that all makes technical
           sense, but where does it appear in the formal
           paperwork?
                       MR. DAVIS:   I am not sure that we
           addressed it with Hatch, because it was only a couple
           of weeks ago that we had a really big meeting, and
           discussed this for GALL.  Maybe we need to take
           another look at that.
                       MR. BURTON:  Well, it is another example
           of where some of the ongoing work timing wise gets
           cross-purposes.  So as we resolve this issue, one of
           the things that we have to do is to go back and see,
           number one, how does it affect those folks who are
           going through license renewal right now, and how does
           it affect the people who are getting ready to come in
           and maybe far enough along in their application that
           they can't really get to it.  
                       And in which case obviously we would go
           through an RAI process to get our arms around it.  And
           then how does it affect folks who perhaps already got
           their license, and then you get into the whole back-
           fit issue and stuff.
                       But those are all things that as we get
           these emerging issues coming out, how do we address
           it, not only -- well, you know, once we have resolved
           it, how do we address it for applicants and licensees
           at different phrases.  
                       So I don't have an answer for you, but it
           is something that the staff is aware of, and that we
           try to do for each one of them.
                       Next, open item 3.1.28-1, RHR heat
           exchanger inspection and testing.  An issue came up
           with how do he provisions in the aging management
           program manage aging, or manage damage that may result
           from vibration, vibration-induced cracking.  
                       And we asked basically for a lot more
           information about their methods, and their
           frequencies, and all the things that you see there, in
           addition to there was a tube leak in '96, and we
           wanted to get a little bit more information about how
           that was looked at, and how it was ultimately
           dispositioned.
                       There were some issues with dents and
           things like that, and the augmented inspection and
           testing program, which I spoke about before, that is
           really the main aging management program that deals
           not just with the RHR heat exchangers, but all the
           components in RHR.  
                       But this one also includes activities that
           ultimately between the inspections and all that stuff
           will tell you whether or not there is some tube
           damage, and whether it is due to vibration or anything
           else.
                       So they provided that additional
           information to try and clarify that the actions are in
           fact adequate to detect that sort of thing.  And then
           like I said, they also gave us some additional
           information on the operating experience they had
           associated with the tube leak.
                       DR. BARTON:  Before you get off of that,
           look at the words in the SER.  You asked four specific
           questions, and the licensee responded, but they didn't
           fully answer your question, and yet you signed this
           thing off.
                       The first thing you asked for was to
           provide information on inspection methods,
           frequencies, acceptance criteria, about bases, et
           cetera, et cetera, and they tell you I am going to do
           any current testing every 10 years.  
                       MR. BURTON:  Right.
                       DR. BARTON:  Well, they didn't say
           anything about any acceptance criteria, associated
           bases.
                       MR. BURTON:  Okay.
                       DR. BARTON:  And then in Item C, you ask
           for inspection criteria, et cetera, et cetera, and
           they said, hey, we are going to do general visual
           inspections of the RHR heat exchanger every three
           operating cycles.
                       And if you are satisfied with that, that's
           fine, but I don't think they answered fully what you
           asked for -- A, B, C, and D.  They gave you partial
           answers.  So maybe you are happy, and maybe there is
           something that is not in the SER.  I don't know.
                       MR. BURTON:  You just hit the nail on the
           head.  Actually, some of the supporting information
           for the bases and stuff was actually in response to an
           RAI, and it didn't get transferred into the final SER.
                       And now that you have said that, it
           probably ought to be in there for clarification.  But
           let me give you the answers.
                       DR. BARTON:  Okay.
                       MR. BURTON:  For the leak testing and the
           RHR heat exchange of the tubes and tube sheets, what
           they said, and I think this is in the SER, that they
           do 10 percent of the operational tubes.
                       DR. BARTON:  Every 10 years, right.
                       MR. BURTON:  Every 10 years.  The basis
           were test results that they have done on three heat
           exchangers, where they found no damage.  And they also
           have a 5 percent margin, in terms of excess tube
           capacity, to take into account when they -- if they
           have to do any tube plugging.
                       And so that is what they used to provide
           assurance that they could catch anything between the
           intervals.
                       DR. BARTON:  All right.
                       MR. BURTON:  In terms of the general
           visual inspection that you talked about -- and again,
           for 10 years -- the basis was actually a Sandia Lab
           report that recommended --
                       DR. BARTON:  When you say every three
           operating cycles, are they on a 24 month cycle?
                       MR. BAKER:  We are going to 24 months.
                       DR. BARTON:  You are going to 24.
                       MR. BURTON:  Yes, every three operating
           cycles.
                       DR. BARTON:  Every three operating cycles. 
           Okay.
                       MR. BURTON:  And shell side every 10
           years, with bundle supports and some other things.  
           That was based on the Sandia Lab report, and again
           operating experience.  
                       You know, some satisfactory results from
           some previous inspections.  But you are right.  None
           of that got into the SER, and it probably needs to be
           included.
                       DR. BARTON:  Thank you. 
                       CHAIRMAN BONACA:  And you do have what you
           asked for?
                       MR. BURTON:  Yes.  Yes, in response to the
           RAIs.  
                       DR. BARTON:  Well, I just didn't see it,
           Butch, and it should be in here I guess.
                       MR. BURTON:  Well, I am going to make a
           note of that.
                       MR. BAKER:  Butch, I have that response
           here if you need it.
                       MR. BURTON:  Oh, okay.  So we will make
           sure that we get all of that to the SER.  Let's see. 
           Next.  Open Item 3.2.3.1.1-1, having to do with cast
           austenitic stainless steel components, CASS
           components.
                       The issue was that we know from the
           science that CASS or Cast Austenitic Stainless Steel
           components, can be susceptible to a loss of fracture
           toughness as a result of thermal and neutron
           embrittlement.
                       We also know that that will come about if
           there is evidence of cracking in the components.  If
           there is no cracking, then you won't see the effect of
           the thermal and neutron embrittlement on loss of
           fracture toughness.
                       So the staff said, okay, well, let's do a
           one time inspection to see if there are any cracks in
           the components.  We should ask for that.  We did some
           additional discussions about that, and in the end we
           determined that probably at this point a one time
           inspection probably isn't warranted and here is why.
                       First of all, when you look across the
           industry, in terms of operating experience, there
           really is no evidence of cracking in these CASS jet
           pump assemblies and fuel supports.  These are the
           components that were under question.
                       The other portion was that the assembly
           welds are already being inspected as part of VIP-41,
           and that these welds actually would show evidence of
           the aging effect before the CASS components in
           question.
                       So this is sort of the precursor to it. 
           Once you found it in the welds, then that would direct
           you through to the corrective actions process to
           perhaps look at this.
                       But this is where you would find it first. 
           So based on that, we said, well, it is probably not
           appropriate since we have not seen it, and we have a
           precursor for it, it is probably not reasonable to ask
           for it.
                       CHAIRMAN BONACA:  Well, you have
           inspections that would be a precursor to identify
           that?
                       MR. BURTON:  Right.
                       CHAIRMAN BONACA:  You do have inspections.
                       DR. FORD:  What is your basis for saying
           that, that the assembly welds should be from a timing
           component more susceptible in CASS.
                       MR. BURTON:  Okay.  We are going to talk
           a little bit more about the science, and I --
                       DR. FORD:  Well, it is not the science for
           science sake.  You are using that as a leader of the
           fleet.
                       MR. BURTON:  Yes.
                       DR. FORD:  And I am just questioning what
           --
                       MR. BURTON:  Well, I can have perhaps
           Robin speak to it or Barry.
                       MR. DYLE:  I can speak to it from the VIP
           perspective, and I am not sure who the staff evaluator
           was.  This is Robin Dyle.  Peter, one of the things
           that we looked at when we developed VIP-41 was that
           the material and those welds are more susceptible to
           IGSCC than the CASS material is.
                       And the inspection program requires all of
           that to be inspected, and to do examinations of the
           welds, and the wrought material, and that would be a
           precursor before we would have to worry about cracking
           in the CASS material itself, just by the general
           nature of IGSCC and the material properties.
                       And the only way that you are concerned
           about fracture toughness is once you have the
           cracking, and so the inspection program -- and about
           half the fleet has already done these the best that we
           can tell.
                       And if you are looking at the entire jet
           pump assembly in all 20 of them, based on how the
           wrought material and the welds are behaving, that
           would be a precursor before you would have to worry
           about these actual CASS austenitic abusers that are at
           the bottom.
                       That is the way that the program was put
           together.  The practical side of it is that when you
           go down with a camera, and you have got it calibrated
           to do an EVT-1 or a VT-1, knowing what the distance is
           in the aim, unless you are going to be looking at
           these things also jus while you are putting the camera
           in place to look so that there will be some -- I
           started to say collateral, but that's not the best
           term.  You want to avoid that term these days.
                       There will be some additional inspections
           that occur that we just actually have not taken credit
           for, but we know that it will happen.
                       And we are confident that what we would
           see in the wrought and the welds would be a precursor
           to anything being a problem with the CASS austenitic
           material.
                       Also, as we go forward with HWC and open
           metal, we can also do things to further minimize
           concerns.  
                       DR. FORD:  I guess my problem with this
           particular one was the statement that because we
           haven't seen cracks, you never expect to see a problem
           because the parent material being brittle.
                       And you are leaving aside the fact of how
           -- that if you are going to see a crack, then how did
           it get there to start with.  And there is no reason at
           all why you could not have some sub-critical crack
           that you have not yet seen.
                       And to say that in the year 2035 or 2040
           that these sort of flux levels, and therefore
           fluences, that you wouldn't see some sub-critical
           crack growth in the CASS material.
                       And that's why I was questioning that if
           you are going to use the assembly welds, that there
           are so many variables which control the initiation and
           growth of a crack in a weld --
                       MR. BURTON:  Well, this is hardly -- well,
           this is 10 to the 17th.
                       DR. FORD:  I agree with you, Bill.  
                       DR. KRESS:  This is mostly thermal don't
           you think?
                       DR. SHACK:  I think the embrittlement is
           probably neutron.  I mean, 10 to the 17th does a
           wonderful job in embriddling fahrenheit islands, but
           it is not going to produce IASCC in a non-submittal.
                       DR. FORD:  I agree with you.  I am just
           pushing the questioning, and the assumption that if
           you haven't seen a crack now, at this time in its
           life, it doesn't mean to say that you are not going to
           see it in 10 years.  I mean, our industry is bedeviled
           by that argument.
                       MR. CARPENTER:  Dr. Ford, this is Gene
           Carpenter, and --
                       CHAIRMAN BONACA:  Point A I think was
           pretty irrelevant to the answer to some degree, and I
           think Point B was the one, because we were looking for
           an inspection program.  Point B is where the whole
           issue is.  
                       I mean, how credible it is that as you
           inspect the welds, you will also see cracks in the
           CASS components.  I don't know, and that is a good
           question.
                       DR. SHACK:  You will never see the crack
           in a CASS component until it busts.  You are probably
           better off inspecting the welds.
                       CHAIRMAN BONACA:  Okay.  So you are saying
           that the welds are only a precursor.  Okay.  That's
           right.  You're right.  
                       DR. SHACK:  But I probably believe your
           argument about IGSCC susceptibility.  In Peach Bottom,
           where did the fatigue cracks occur?  Were they at the
           welds, or were they in the elbows?  So there is
           another mechanism potentially for cracking here
           besides IGSCC.
                       MR. DYLE:  Let me be careful -- this is
           Robin Dyle again.  Let me be careful on how I answer
           that since I don't work at Peach Bottom.  I think you
           are talking about the jet pump riser pipe cracking is?
                       DR. SHACK:  Yes.  I don't know.  All I
           know is that they had a peak problem, and I don't have
           any idea where it was.
                       MR. DYLE:  That was in the jet pump riser
           pipe and that is wrought material and it is down where
           the nozzle is inserted into the vessel, and it is that
           elbow.  And it was wrought, and so it was a
           combination of IGSCC and then fatigue.
                       These CASS materials are further
           downstream, where the defusers sits on the jet pump,
           and the jet pump defuser sits on the shroud support,
           and actually injects the water into the bottom end
           region.
                       But we have seen cracking in the jet pump
           assemblies and the wrought material, and at the weld
           locations.  Not to date in the CASS material.  So we
           do have the inspection program that looks at the whole
           assembly.
                       And I believe that the precursor would be
           more thorough inspections in that more susceptible
           material.  
                       MR. BURTON:  Okay.  Thank you, Robin.  Now
           -- oh, I'm sorry.  Gene.  
                       MR. CARPENTER:  I just wanted to reply to
           Dr. Ford's question.  Basically, you are right.  There
           are things that could occur in 10 years that we don't
           expect today.  
                       And to address that, we are trying at this
           time to put into place a research program to look at
           the effects of the radiation embriddlement, et cetera,
           on these CASS components.
                       And I can't tell you that it will be in
           place in Fiscal 2002, but it will be in place well
           before any of these plants go into the license renewal
           term.
                       DR. FORD:  Now, as well as the kinetics
           embriddlement, what about sub-critical crack growth?
                       MR. DYLE:  That is part of the program
           that we are talking about at this time with our
           research department, the Office of Research
           Department.
                       MR. BURTON:  And the truth is that we
           didn't want to include it in the SER at this point
           because it isn't a firm commitment on either side
           right now.  We expect that it is going to be done with
           budgets and things like that at the point that we were
           doing the SER.
                       There was no short commitment for that,
           and so we decided not to put it in, but as Gene said,
           we expect that to happen.
                       CHAIRMAN BONACA:  Well, you do have a
           discussion in the SER regarding that on page 135,
           right?
                       MR. BURTON:  Yes.  Yes.  Right.
                       CHAIRMAN BONACA:  Well, we are running
           late, and so for those items, we will just have
           confirmation.  You know, you asked for confirmation
           from the licensee and he gave it to you, and just try
           to go fast.
                       MR. BURTON:  For the remaining things?
                       CHAIRMAN BONACA:  No, no.  
                       MR. BURTON:  Oh, you are still on this
           one?  I'm sorry.
                       CHAIRMAN BONACA:  No, I am talking about
           on the future items that you are going to present us
           with, and which you are asking for a question to them,
           and they say yes, and that's what it is, try to go a
           little faster.
                       MR. BURTON:  A little faster.  Okay. 
           There is just a couple of more in this portion, and
           let me do this a little expeditiously.  Open Item
           3.6.3.2-1, two items regarding the primary
           containment.  
                       The first was that we were a little bit
           unclear as to what was being credited to manage aging
           in the TORUS, and what they did was that they provided
           us with a drawing that showed very clearly the aging
           management programs that were being credited, and
           there are a number of them.
                       Basically, and I have jotted it down
           because there is no way that I can remember it all,
           but what they did was they identified the programs to
           manage aging for the TORUS above the water line, and
           then there was another set of aging management
           programs below the water line, and in the splash zone.
                       Above the water line, they took credit for
           in-service inspections, primary containment leak
           testing, protective coatings, and the CCTLP, fatigue
           monitoring basically.
                       Below the water line in the splash zone,
           they took credit for water chemistry, and associated
           inspections.  So they did clarify that, because at
           first we weren't sure how it was being done, and in
           fact it is being done by a combination of aging
           management programs.
                       So that was the final resolution for Issue
           Number 1.  For Issue Number 2, this is another example
           when we asked this open item, this was being dealt
           with as part of GALL, and again timing wise, it was
           for kind of cross-purposes.  
                       But in the end this issue was clarified
           both in GALL, and Hatch's position is consistent with
           that, in that they are going to use performance based
           requirements and criteria to ensure that the
           penetration leakage and overall containment leakage
           doesn't exceed the tech specs limits.  That is
           consistent with GALL.
                       DR. BARTON:  Well, in the initial item on
           the TORUS water level, above and below water level
           inspection, as I read the applicant's response, they
           say they have taken credit for the protective coating
           program for TORUS penetrations above the water line?
                       MR. BURTON:  Yes.  
                       DR. BARTON:  I didn't get out of there
           what program is covering corrosion below the water
           line.
                       MR. BURTON:  Below the water line?  Okay.
                       DR. BARTON:  I couldn't find that.
                       MR. BURTON:  Okay.  It should be right
           there.  
                       MR. DYLE:  If you recall, one of the
           clarifications that I provided you is that the
           protective coatings also should have been applied in
           the SER wording to the penetrations below the water
           line. 
                       MR. BURTON:  Right.  That's right.
                       DR. BARTON:  Well, it is not in there now
           though.
                       MR. DYLE:  It was not in the SER, but it
           is --
                       MR. BURTON:  Yes, the protective coatings. 
           Right.  That's right, and he had already pointed that
           out and we will have to take a look at that.
                       DR. BARTON:  Okay.  That was my problem
           with it.
                       MR. BURTON:  Oh, just with the protective
           coatings?
                       DR. BARTON:  Well, to address what program
           covers below water line.  It is not answered there. 

           It is not in the current SER, unless I missed it.
                       MR. BURTON:  On page 3-196.
                       DR. BARTON:  Okay.  I was looking back
           here.
                       MR. BURTON:  That was kind of a summary of
           some of the stuff, but it is in the body.
                       DR. BARTON:  It is covered in the body?
                       MR. BURTON:  Yes.
                       DR. BARTON:  Okay.
                       MR. BURTON:  Okay.  So I did identify the
           aging management programs, and protective coatings was
           missed, and we are going to have to include that.  
                       DR. BARTON:  Okay.  
                       MR. BURTON:  This is the last one of the
           open items that did not go to appeal.  Open Item
           4.1.3-1 had two parts to it.  Part (a) did not go to
           appeal, and Part (b) did.  So I will be talking about
           Part (b) after the break.  
                       For Part (a), it had to do with fatigue
           analyses, and the issue was -- well, actually, there
           were a couple of questions.  For the vessel internals,
           how was the fatigue analysis found to be acceptable
           for the 60 years, for the extended term.
                       And Section 4 covers TLAAs, and as you
           know, disposition of TLAAs, there are three options. 
           Either you can show that the analyses are already good
           for the extended term, and you can project the
           analyses or the evaluation to cover the extended term,
           or you manage.
                       It turns out that they clarified that the
           fatigue analysis for the internals was projected over
           the 60 years, and found to remain below one, and
           therefore met the second requirement.
                       And for the second part of the question,
           were there any other coolant pressure boundary
           components that were subject to fatigue analysis, and
           if so, how was that disposition, and they said that
           the -- they clarified that they didn't identify any
           other reactor and pressure boundary components that
           that would apply to.
                       And that's it.  That was the last of the
           open items that we resolved without going through
           appeal.  Any questions on any of that?
                       CHAIRMAN BONACA:  If not, let's take a
           recess for 15 minutes.  Let's meet at a quarter-of-11,
           and we will review the appeal issues or items.
                       (Whereupon, at 10:30 a.m., the meeting was
           recessed and resumed at 10:45 a.m.)
                       CHAIRMAN BONACA:  Let's start the meeting
           again.  We have now a presentation on the appeal
           process, and then a discussion of the six items
           resolved by appeal.  
                       MR. BURTON:  Okay.  I am going to try and
           go through this fairly quickly.  But Southern Nuclear
           had mentioned that there were a couple of things from
           last session that they wanted to clarify, and if you
           wanted to go on and do that real quick, Chuck.
                       MR. PIERCE:  Yes, my name is Chuck Pierce. 
           One item had to do with whether the commitment
           tracking program at Plant Hatch was an Appendix B
           Program, and I would like to clarify that in fact it
           is an Appendix B program, rather than what I said
           earlier.  
                       It is audited by our QA organizations, and
           falls under Appendix B.  The other clarification had
           to do with whether the guard pipe inspection
           activities that we are planning in the outage
           schedule.
                       Two items here.  The action item tracking,
           Item 4 of this work, has been generated already.  So
           it is scheduled in that sense.  It falls below the
           level that you would see in the outage schedule or the
           work schedule, per se.  
                       But it is in fact scheduled by action item
           tracking, and then the maintenance work order will be
           generated as we get into the time to do that work.
                       MR. BURTON:  Okay.  Of course, Dr. Barton
           isn't here to hear that, but --
                       MR. PIERCE:  I did mention to Dr. Barton
           as he went by about the Appendix B item.
                       MR. BURTON:  Okay.  Moving right along
           here, I am going to go over the six open items that
           did go through appeal.  There were two appeal
           meetings, one on March 29th at the branch level; and
           a second appeal meeting on June 6th at the division
           level.
                       And what I want to do is just go through
           this chart very quickly to explain how the process
           works.  This is a relatively old chart, and I think
           some of this may have changed, but I think that the
           relevant part is still relevant.
                       Any time we have a disagreement -- what
           did I say?
                       CHAIRMAN BONACA:  Just keep going.
                       MR. BURTON:  All right.  When we have a
           disagreement, we take it and the first level of appeal
           is at the branch level, and we had several of the
           items that did that.  If we resolve them at the branch
           level, great, and we continue on with our business and
           close it out.
                       If we continue to have a disagreement, we
           then go to the division level, and that is the next
           level of appeal.  Again, if it is resolved, which it
           was in this case, and so we followed this branch, and
           resolved the comments.
                       And the resolution was established and
           implemented in the SER.  So that is the branch that we
           actually took.  If there continued to be a
           disagreement at the division level, we would go on and
           move to the office level and so on.
                       But for our work with Hatch, we followed
           this patch here, and of course we keep the license
           renewal steering committee informed of our progress in
           this.  So that is how the appeal process works. 
                       CHAIRMAN BONACA:  Is this process unique
           to the license renewal, or is it a process that is
           used in other areas?
                       MR. NAKOSKI:  This is John Nakoski with
           NRR.  I think this is a typically and fairly informal
           process that is used throughout any licensing activity
           or licensing action.  
                       Essentially, if the staff and the licensee
           can't agree, we apply ever increasing levels of
           management attention until we come to a final agency
           position that may be in alignment with what the
           licensee asks, or it may not.  
                       But having the burden of making a
           regulatory decision, once we have gotten our
           management to agree we established a regulatory
           position and move forward.  So I would say that this
           is an informal process that has been used typically
           throughout all licensing activities.
                       DR. KRESS:  Suppose the lower level staff
           that raised the issue in the first place continues to
           disagree with the resolution after he gets up to the
           higher level?  
                       MR. NAKOSKI:  The recourse is that the NRC
           -- well, we fully support the right of any individual
           on the staff to have a differing professional view or
           differing professional opinion, and we will take

           appropriate actions consistent with those programs.
                       DR. KRESS:  Okay.  Thank you.
                       MR. BURTON:  The first open item, Seismic
           2 over 1.  We have spoken a little bit about it in the
           previous session.  The issue is that structures,
           systems, and components that have been identified as
           seismic 2 over 1, should those be in scope and be
           subject to an AMR.
                       The specifics of what brought this to
           light had to do with some piping segments that were
           seismically supported, and as a result of being
           seismically supported, Southern Nuclear felt that the
           associated pipe segments didn't need to be brought
           into scope, because with them being seismically
           supported, they wouldn't fall during a seismic event.
                       And we asked them to consider that, and
           they considered it to be hypothetical, and the reason
           that it is hypothetical is that there has been no
           industry experience of piping, whether new or old
           piping, that has actually fallen during a seismic
           event.
                       The staff's position was that when you
           look at operating experience, we in fact have a lot of
           operating experience that shows that pipes have failed
           due to age related degradation mechanisms.
                       And that in that respect, failure of the
           piping is not hypothetical, and should be considered
           in the scope and be subject to an AMR.  There was a
           lot of discussion on this issue.
                       And where we are now is ultimately there
           were some additional components that were brought into
           scope, and subject to aging management, but as a
           result of the discussions, we realized that there is
           -- that this is a generic thing that needs to be --
           that resolution needs to be incorporated into some of
           our guidance documents.
                       And that's where we are now.  What we did
           in the short term is we developed -- we are developing
           the staff position, but for those plants that were
           right after Hatch, which are going through now --
           Catabawa, Peach Bottom, Maguire, and some of those --
           this is also an issue that needs to be captured.
                       So the first thing that we did was we
           developed a series of both scoping and aging
           management RAIs to begin to understand what they put
           in scope, and what they didn't, and why.  
                       And then once we understand what is in
           scope, exactly how is that to be managed.  So in the
           short term, we have developed and distributed RAIs so
           that we can do that with some of the applicants behind
           us.
                       We also have to look at it as we document
           the position and put it in the guidance documents. 
           Now we have to apply it to the folks who already have
           their license, and does it raise to a level -- you
           know, go through the whole back fit thing, and see
           whether it needs to be addressed there.
                       So we are trying to capture the whole
           thing with the Seismic 2 over 1, and what we are doing
           right now is we are actually working on the staff
           position.
                       Next, Open Item 2.3.3.2-2, aging
           management review for the housings of active
           components.  The issue was raised that for active
           components the actual housing for those should be
           subject to an AMR.
                       And it actually came into play for four
           specific systems; standby gas treatment, control
           building, outside structures, and reactor building
           HVAC.
                       Southern Nuclear's position was that what
           the staff was asking for was basically to do a piece
           parts review, and if you go to the rule and some of
           the supporting documentation, what it specifically
           calls out are valve housings and pump casings. 
                       It specifically calls those out as
           requiring an AMR, and Southern Nuclear's position was
           what needs to be done is already identified, and
           that's all we need to do.  
                       The staff's position was, no, we see the
           valve housings and pump casings as being examples of
           what needs to be done, and it needs to be expanded
           beyond that to cover other housings for active
           components where there may be a pressure boundary
           function, and things like that.
                       So that was the source of the conflict and
           why it went to appeal.  It went through the first
           level of appeal as I recall, and in the end the
           resolution was that the housings would be brought into
           scope and be -- well, it was already in scope, and be
           subject to an AMR.
                       And again the associated aging management
           information was brought with it.  But we did recognize
           that the issue of the housings, we need to somehow
           clarify that in our guidance documents that it is more
           than just the valve housings and the pump casings.
                       CHAIRMAN BONACA:  Because this is not the
           first time it comes up anyway.
                       MR. BURTON:  Right.  Exactly.
                       CHAIRMAN BONACA:  Now, let me understand
           one thing.  Here you say that it has to be developed
           into a guidance, and of course it will be some place
           for guidance, and there are guidance documents.
                       Now, the previous issue of Seismic 2 over
           1, you said you are developing a staff position.
                       MR. BURTON:  Right.
                       CHAIRMAN BONACA:  How would that position
           be conveyed?  Also in guidance documents I would
           imagine?
                       MR. BURTON:  Yes, that's right.  They
           would ultimately be in the guidance documents; in the
           SRP, and the Reg Guide, and --
                       CHAIRMAN BONACA:  Well, when you talk
           about backfitting to the previous applicants, but I
           thought this issue of 2 over 1 already was dealt with? 
           I mean, it came up before.
                       MR. BURTON:  Yes, and I probably
           mischaracterized that.  With previous applicants, it
           may have been dealt with in other ways.  For instance,
           I think with ANO, they had actually -- it actually had
           its own specific category. 
                       It was -- I can't remember what it was
           called.  So it may in fact have been dealt with with
           previous applicants, but the thing is that part of our
           process is that we have to just make sure that it is. 
           That is the main thing.
                       CHAIRMAN BONACA:  Okay.
                       MR. BURTON:  The next issue is 3.2.2.3-1,
           small bore piping.  The staff recognized that small
           bore piping could be subject to high cycle thermal
           fatigue due to either thermal stratification or
           turbulent penetration, or it could be susceptible to
           intergranular stress corrosion cracking.
                       So we needed to have that captured in an
           aging management program.  What Southern Nuclear did
           was that they looked at all of their small bore
           piping, and looked at it from both a susceptibility
           standpoint and a consequence standpoint.  
                       And after going through all the small bore
           piping, what they identified was about -- I don't
           know, about a 2 foot section of the --
                       MR. BAKER:  Four foot.
                       MR. BURTON:  Four foot -- of the enclosure
           for the electrochemical potential sensor.  The
           enclosure for that seemed to be something that should
           be within the scope of this aging management program;
           the treated water systems, piping and inspection
           program.
                       And what that does is it is a series of
           one-time inspections just to confirm again -- and as
           we spoke before, just to confirm that there is no
           adverse aging degradation.  
                       So the scope of this aging managing
           program was revised to include that portion of the
           piping.  
                       MR. BAKER:  Butch, could I clarify?
                       MR. BURTON:  Sure.
                       MR. BAKER:  That was always within the
           scope of the treated water.  We just clarified
           explicitly that it was in scope.
                       MR. BURTON:  Right. 
                       CHAIRMAN BONACA:  Well, what happens if
           you -- the expectation is that you have no cracking
           due to -- well, that is a one-time inspection, and you
           are really doing that for confirming that the effect
           is not taking place.
                       Should you find that, would these
           inspections be expanded to other components; that is,
           more piping, or not?
                       MR. BURTON:  Yes, and again, as we had
           said before, the corrective actions program captures
           any of those kinds of problems, and once it is fed
           into the corrective action program --be expanded 
                       CHAIRMAN BONACA:  So that will be a
           leading indicator?
                       MR. BURTON:  Right.
                       MR. BAKER:  One thing.  If you did start
           finding some of this cracking, you could actually look
           and see what type of a program you need to put in
           place to manage it.  
                       So the one time inspections would probably
           cease at that point, and you would come up with a
           program that managed the cracking for the compliments.
                       CHAIRMAN BONACA:  Well, you are talking if
           you need further inspections, or why not.
                       MR. BAKER:  Exactly.
                       MR. BURTON:  That's correct.  The next one
           was Open Item 3.6.3-1(b), reactor building controlled
           in-leakage.  At this point in time in the review, what
           Southern Nuclear was crediting was maintenance of
           individual penetrations to make sure that the
           degradation was not so bad that leakage would be a
           problem.
                       The staff's position was that that is fine
           for each individual penetration, but you haver to look
           at the cumulative effect, even though leakage for
           individual penetrations may be acceptable, and when
           you look at it on a global basis, we still may not be
           able to maintain the in-leakage limits.
                       So the staff's point of view is, well, we
           already do the draw-down test for the standby gas
           treatment system, and why don't we credit that as an
           overall gross indicator for the entire building that
           leakage is being maintained.
                       Because we recognize that even though it
           is okay at the individual component level, globally
           there might be a problem.  Southern Nuclear felt like
           that was overkill, and that basically if we adequately
           managed the penetrations that should take care of the
           wider in-leakage problem.
                       Again, they took it to appeal, and when
           all was said and done, they did decide that we will
           credit it.  We are doing it now anyway, and we are
           going to continue to do it in the license term, and we
           will go on and take credit for it.  So that's how that
           was done.
                       CHAIRMAN BONACA:  I just have a question
           here.  Given that you are performing the tests anyway,
           you must have had a reason for trying to have it
           included in the commitment for license renewal.  
                       MR. BAKER:  We believed that the test was
           really a very gross test and added nothing to any
           assurance relative to aging management.  The threshold
           for detectability of a leak was probably on the order
           of 2 square foot on one unit, and about 4 square foot
           on the other unit.  
                       So we felt that that was really not going
           to add anything of value.  I think the resolution of
           it was that in fact, yes, you are doing that test
           anyhow, and so there is really no regulatory burden,
           and we agreed.
                       And so we have agreed, and the resolution
           of it is that we will do the test.  It is a tech spec
           requirement as it is.
                       CHAIRMAN BONACA:  And is that the course? 
           I wasn't aware of that.  Okay.
                       MR. BURTON:  Actually, I think this is the
           last one.  Again, I mentioned to you that open item
           4.1.3-1 had two parts to it.  Part (a) wasn't
           appealed, and I discussed that earlier.  Part (b) was
           appealed.
                       This is the next to last one.  Pipe break
           criteria is a TLAA.  The issue was postulated pipe
           break locations meet the TLAA criteria, and should be
           evaluated as TLAA.  Southern Nuclear's position is
           that it did not meet the six criteria that were
           necessary for it to be a TLAA.
                       Whereas, the staff said, look, in our
           guidance documents it says very clearly that this is
           to be a TLAA.  The cumulative usage factor, which is
           tied up in the identification of break locations, it
           is a TLAA, and the associated break locations should
           be also.
                       So that was the basis of the open item. 
           Again, when all was said and done, the applicant did
           revise the application to identify or to address the
           postulated pipe breaks, and the locations are going to
           be monitored using this component SLIC or transient
           limit program, the CCTLP.  So that was the resolution
           on that.
                       The final was environmentally assisted
           fatigue, and I am sure that you all know more about
           this than --
                       DR. SHACK:  Could we just go back to that
           for a second?
                       MR. BURTON:  Oh, sure.
                       DR. SHACK:  On the pipe break, I thought
           the idea was that you would look at pipe break
           locations again in light of any aging mechanisms that
           would be going on.  Not just fatigue.  
                       MR. BURTON:  Yes, that's true.  Now, let
           me say up front that I cannot get into it to any deep
           extent.  Our reviewer is not here, and we will see
           what we can do to answer your question, but I may need
           to table it.  
                       MR. BAKER:  The pipe break locations that
           we are dealing with here specifically are those
           outlined and which provide or basically says that for
           a class one boundary, if you have pipe break, or you
           have locations that have a CUF greater than .1, it
           would be a 3-1 evaluations, and predicted values of
           greater than .1, you would specifically consider that
           a pipe break location and deal with it appropriately
           within the 3-1 space.
                       Now, that is the specific issue that is
           being dealt with here.  If we are not dealing with
           IGSCC, or any other fatigue issues -- and of course
           there is general fatigue.
                       DR. SHACK:  Suppose I had a carpet steel
           align that I would suspect could be susceptible to
           FAC.  Could I then postulate breaks due to FAC, or is
           it just fatigue still?
                       MR. BAKER:  We would deal with the fact
           issue separately, or as a separate --
                       DR. SHACK:  But that is in your fact
           control, and so there is no need to postulate, okay,
           I blew the fact control.
                       MR. BAKER:  Right.  
                       DR. SHACK:  And I have a burst anyway, and
           that is not addressed.
                       MR. BAKER:  Correct.
                       MR. DYLE:  Bill, this is Robin Dyle.  Just
           for one clarification.  This goes back a long time
           that says that when you are designing the pipe
           restraints how are you going to select the location to
           look at, and the staff determined in the branch
           technical position, that anyplace the CUF exceeded .1,
           and so it was originally a somewhat arbitrary
           location, and just identify where you would assess the
           pipe break location.
                       DR. SHACK:  It didn't apply when you
           thought the principal aging mechanism was fatigue.
                       MR. DYLE:  Right.
                       DR. SHACK:  And you have new aging
           mechanisms.
                       MR. DYLE:  Yes, and so the issue here was
           whether that should be treated as a TLAA or not, and
           not whether any of those locations was the only issue
           to be dealt with.  It was just whether it needed to be
           a TLAA or not.  
                       And the argument that we had put forth was
           that since it was a design parameter, and not really
           -- this evaluation didn't manage cracking, it was just
           an old design parameter.  That was our argument for
           why it wasn't a TLAA.
                       But the staff disagreed with that, and as
           Butch said, the staff member is no here to address
           that.
                       MR. BURTON:  Is that something that you
           perhaps want to discuss more about next week?
                       DR. SHACK:  Yes, that is a topic that
           interests me, is that why should I only postulate the
           break space and not the fatigue.
                       CHAIRMAN BONACA:  Yes, because that is
           really what it does, and it would monitor for fatigue.
                       MR. BURTON:  The last item was
           environmentally assisted fatigue, and as I said, you
           all have dealt with this ad nauseam I know.
                       DR. SHACK:  You always love it, ad
           nauseam. 
                       MR. BURTON:  We love it.  Thank you, sir,
           may I have another.  The issue was that the staff's
           position was that the applicant should assess the
           locations identified in this new reg, considering the
           applicable environmental fatigue correlations in these
           other two new regs.  
                       As you all know, environmentally assisted
           fatigue has a long and torturous history.  A lot of
           documentation.  The bottom line was that Southern
           Nuclear had data that was coming from Susquehanna, and
           was basically saying that this is applicable to Hatch.
                       Our staff reviewer had some questions
           about that, the applicability, and felt that it would
           be more prudent to actually have things in place to
           actually monitor and collect data at Hatch as regards
           the environmentally assisted fatigue as recommended in
           these documents, in terms of locations and fatigue
           factors.
                       In the end, after our discussion, the
           applicant did commit to evaluating the six locations,
           and it was actually incorporated into again the
           component SLC or transient limit program, aging
           management program.
                       So they have committed to actually
           collecting that data at those locations.  That was the
           last open item, and the last couple of things is that
           I wanted to again identify the three license
           conditions that we have with the review.
                       DR. SHACK:  Before you get into that can
           I bring up one more issue in the SER.
                       MR. BURTON:  Sure.
                       DR. SHACK:  It is on page 3-62, discussing
           FAC.  And it says basically that water chemistry
           control can be achieved by reducing the oxygen content
           in the water environment.  Such a water chemistry
           control program to mitigate the aging effects
           attributable to FAC is not implemented in the Plant
           Hatch units.
                       I would argue that typically one would
           mitigate FAC by adding oxygen, and not by reducing it,
           and I just had a question for Hatch.  Do they maintain
           such a remittable oxygen level?
                       MR. BAKER:  We have to have oxygen comply
           with the code.
                       DR. SHACK:  Is that in the BWR
           environmental -- well, the water chem specs.  What do
           you maintain, 20 PPD or 15 PPD?  And that is part of
           the EPRI water chem specs?
                       MR. DYLE:  The normal situation --
                       DR. SHACK:  But you ought to correct that
           statement in the SER.
                       MR. BURTON:  Okay.  Clarify that a little
           bit more.  All right.  Let me write this down just in
           case.
                       (Brief Pause.)
                       MR. BURTON:  Okay.  All right.  Just a
           summary of the three license conditions.  We already
           talked about them.  One is the standard license
           condition that says that the FSAR supplement should be
           incorporated into the FSAR at the next update of the
           FSAR.  
                       And that is required by 50.71(e); and the
           other one, the second standard license condition is
           that all the future actions that were identified in
           the FSAR supplement should be completed before the
           beginning of the extended term.
                       And finally the third one was what we
           talked about before, that they should inform the NRC
           regarding whether they are going to use the integrated
           surveillance program associated with BWRVIP-78, or if
           they are going to use a plant specific program, and
           identify those actions.
                       So we tied those three things to a license
           condition.  And then finally the bottom line
           conclusion after the staff's review is that the staff
           believes that the applicant has met all the
           requirements of license renewal as required by 54.29.
                       And specifically actions have been
           identified, and have been or will be taken, either
           present actions or future actions, such that there is
           reasonable assurance that the activities will continue
           to be conducted in accordance with the current
           licensing basis.
                       And again the guidance documents say,
           bottom line, what we are trying to do is to maintain
           the licensing basis in the same manner and to the same
           extent in the future, in the renewal term, as it is
           being maintained now.  
                       And we have reasonable assurance that they
           are taking the actions to do that.  Also, the
           applicable requirements of 10 CFR Part 51, which is
           the environmental piece of the review, have been
           satisfied.
                       And finally matters raised under 10 CFR
           2.758, which is hearings and all of that, have been
           addressed.  There were no hearings, no petitions to
           intervene, or any of that stuff.  
                       So we feel that as a result of the review
           that we have covered the safety review, and we have
           covered the environmental review, and there were no
           intervenors or other issues raised.
                       But that they have all been satisfied, and
           on that basis, we feel like that they can get their
           license.  As I said, we have also gotten the
           confirmation from the regions, in terms of some of the
           follow up inspections.  
                       We got some clarification for Dr. Barton
           about the level of quality for the commitments, for
           the commitment matrix.  So hopefully we are satisfied
           there.  So we recommend that they should get their
           license.
                       CHAIRMAN BONACA:  And since we are talking
           about an appeal process, I think I read somewhere or
           I read some comments maybe from NEI that the appeal
           process is not working as it should, or something like
           that.  Is everybody happy about the appeal process?
                       MR. NAKOSKI:  This is John Nakoski, and if
           I could just say something about that.  NEI has
           proposed or submitted a proposed appeal process just
           recently that we have not completed our review on.
                       We will work towards an appeal process
           that improves the fairness or perceived fairness on
           the part of NEI, and other stakeholders, and the
           efficiency of the process.  
                       And at this point, I don't think that
           there is a whole lot more that we can say about that.
                       CHAIRMAN BONACA:  Well, I think we were
           asking some questions on --
                       MR. BAKER:  Dr. Bonaca, one other quick
           item.  I just wanted to mention that the NRC has been
           or has encouraged through the working group or through
           the steering committee a lessons learned process. 
                       And as a result of that encouragement of
           lessons learned process, the industry as a whole has
           -- well, when we have identified things that we think
           could be improved, has made recommendations to the
           NRC, and the NRC has been very open about considering
           those recommendations, and this is just another one of
           those type items.
                       MR. BURTON:  And let me add that just as
           John had mentioned before, I think people have the
           impression that Hatch is the first one to go through
           the appeal process, and my understanding is that that
           is not true.
                       Some of the other applicants have, and it
           wasn't as formalized as what I just showed you.  So
           Hatch is the one who has really gone through the more
           formalized system, and it was our first testing of it.
                       And just like anything else, we found
           areas where it could be improved, and Southern Nuclear
           has transmitted some of their suggestions about that,
           but that, just like everything else in this whole
           license renewal effort, we have a whole lessons
           learned process, and how do we take those lessons
           learned and incorporate them, and try to do things
           better.
                       And again because this was the first -- it
           wasn't the first appeal process, but it was the first
           one that really went through the technical aspects as
           I tried to show you.  
                       CHAIRMAN BONACA:  My question was more
           directed at understanding the difference between an
           appeal, a formal appeal process, and the normal
           process that takes place in an engineering environment
           where you have levels of management that should be
           involved in decisions, but certainly should not bypass
           the technical people and the technical input.
                       And so I am sure that the appeal process
           is not a process designed to bypass technical
           insights.
                       MR. NAKOSKI:  This is John Nakoski again. 
           I agree with you that it is not the purpose of the
           appeal process to bypass the technical decisions by
           escalating it to higher levels of management.  
                       CHAIRMAN BONACA:  Which I would expect
           would happen anyway.  So that's why I was intrigued a
           little bit by the process itself.
                       MR. BURTON:  One of the things that we
           have tried to do with license renewal is to try and
           make it as visible and transparent as possible,
           because as you know, we have several pillars that we
           try to meet.
                       One has to do with public confidence in
           our processes and stuff like that.  So we feel like
           the more that we can clearly show how we do our
           business, then the better that is going to be able to
           instill confidence with our stakeholders.
                       So what you are saying is true.  I mean,
           even before you get on the diagram, there is a whole
           lot of interaction that has gone -- that is done at
           the reviewer level, and even at that level it involves
           a lot of section chief interaction, the first level
           supervisory action.
                       And if we just reach an impasse where our
           views are just diametrically opposed, and we just
           don't seem to be making any progress, then we have to
           get the first level of management -- and not just at
           the NRC, but also the applicant's management involved,
           too.
                       And at that first branch level, and it is
           not just the NRC who is making this decision.  It is
           also the applicant.
                       MR. NAKOSKI:  Butch, let me interrupt here
           at this point and say that this is not unique to
           license renewal.  This is essentially the same process
           that we would use anytime there is a disagreement
           between the staff and an applicant on a licensing
           action.
                       In license renewal, like Butch was saying,
           we want to make this -- we want to put this in front
           of the public, as this is the process that we use in
           this space so that you are aware of the activities and
           actions going on that may appear to be behind the
           scenes.
                       But we are being open and up front about
           it, and these discussions go on.  We are telling you
           that they go on, and this is the steps that you need
           to go through, the licensee or the applicant would go
           through, if they disagree with us.  
                       The bottom line is that we have the burden
           to make the regulatory decision, and we are going to
           provide the public with the information that we based
           our decisions on.
                       MR. BURTON:  And also I should clarify
           that what it says on that diagram, it says
           stakeholders.  There are more stakeholders than just
           as and the applicant, and the process allows for any
           stakeholder who has an issue or a question that they
           feel needs to be brought up.  We have a process to do
           that.  And again all to instill public confidence.
                       MR. NAKOSKI:  And I guess I would add
           fairness.
                       MR. BURTON:  Right.
                       CHAIRMAN BONACA:  Some of these
           resolutions -- for example, seismic 2 over 1, the
           discussion in the SER as I said during this meeting is
           quite -- is defined.  It provides a lot of information
           about the reasons why.  So that's good.
                       In some of the cases, you know, it is more
           that the applicant decided to just go along with it,
           for example, and do the test, and it doesn't mean that
           they are going to be happy about what the resolution
           is.  And they simply said fine.
                       Is there any additional work being done on
           these issues on a generic basis or not, or is it a
           closed item?  I guess where I am going is that when I
           look at seismic 2 over 1, you have a very convincing
           explanation of why aging will bring potentially some
           fractures in locations that are not really covered by
           a normal break analysis and so on and so forth, and
           that makes sense.  So you have a solid technical basis
           to argue from, and I think the issue can be put to
           rest.
                       MR. NAKOSKI:  Mario, I think I would
           answer that in a generic sense.  We would look at the
           resolution of these open items for generic
           implications moving forward, and take the lessons
           learned from that review and apply them to future
           applicants.
                       If in the case of the standby gas
           treatment system draw down test, we made a
           determination that it was generically applicable, we
           would look at incorporating that into generic
           guidance.   
                       And I am not presupposing the position,
           but I am just stating a premise.  If we determined
           that it was generically applicable, we would
           incorporate that into generic guidance that we have
           developed.
                       MR. BURTON:  And also to understand that
           there is -- that operating experience plays a big part
           in this whole thing.  In the case of the end-leakage,
           and what we were saying is that you are maintaining
           the individual penetrations, but we are not sure
           whether that is enough on a global perspective.
                       Operating experience as we go along, as
           they implement management of the penetrations, and do
           the confirmatory draw down test, we may in fact see --
           well, that is kind of a bad example, because you have
           got to do it anyway.  
                       But operating experience in general, and
           let me try to be more general about it, if we find
           that something really isn't having a real benefit and
           it is an unnecessary regulatory burden and all that
           stuff, now this goes beyond license renewal.  
                       You always have the normal 50.59 process
           to try and provide justification, but we probably
           don't need to do this anymore.  
                       CHAIRMAN BONACA:  Are any of these issues
           still open with NEI?  I know that you are looking at
           a number of generic issues with NEI.
                       DR. BARTON:  Well, one that I am aware of

           was the housings and ventilation, et cetera, et
           cetera, where if applicants said, hey, NEI Appendix
           whatever kind of excludes this, but it really doesn't,
           that there is an issue there.
                       CHAIRMAN BONACA:  That's right.
                       DR. BARTON:  There is an issue there with
           the NEI guidance.  That somehow has to get closed in
           or closed out here as a factor.
                       MR. DYLE:  That's exactly correct.  I am
           a member of the NEI working group, and Ray Baker next
           to me is a member of the NEI task force.  What NEI
           does is that they take each of these issues that we
           have as open items, and they look at them, and we also
           make a decision on whether they are generically
           applicable or not, or whether they need to be pursed
           with further discussions with the NRC.
                       And some of these issues are likely to be
           discussed further with the NRC staff on a generic
           level as we move through time.  What happens in the
           real world here is that when an issue like seismic 2
           over 1 comes up, the plants that have just submitted
           haven't -- you know, they were faced with that issue,
           and as were us, as those plants were making
           submittals.  
                       So you may very well see open items and
           issues with those plants that are currently going
           through, and the plants coming in next year after
           that, there should be enough time to where these
           issues sort of get some legs to them, and the staff
           and the industry can come to some agreement on how
           this should be pursued in the future.
                       MR. NAKOSKI:  Mario, if I could, I would
           just like to take a minute here and go over what I see
           are the issues that we need to emphasize when we meet
           with the full committee.  I think I have identified
           four topics that you all would like to hear discussed.
                       The first one is the inspection of buried
           components, particularly fuel oil storage tanks.  And
           really I think the focus of that is on what is the
           safety implication of that, and how that relates to
           the rule.  So I think, Butch, if we could focus on
           that.
                       DR. KRESS:  There was another part of that
           that you might want to think about, and that is for
           the codings of various typings and things.  I think
           that the commitment was that whenever they excavate
           and uncover these in an inspection, that is kind of a
           lose type of commitment.
                       I don't know that they will ever excavate
           and uncover those, and --  
                       DR. BARTON:  Well, you see, the problem
           that you have got with that, Tom, is that if you don't
           commit to do an inspection when you are doing an
           excavation, or you are chasing a leak, how else do you
           inspect buried -- because there is so much stuff that
           is buried in the site that there is no program that
           really makes much sense to go and randomly dig holes,
           because these holes -- you have got to shore them, and
           depending on what your soil condition is -- the Oyster
           Creek excavation was a million dollar excavation.
                       DR. KRESS:  So you are telling met that is
           really the only practical alternative?
                       DR. BARTON:  Yes, on the coated buried
           stuff, yeah.  I mean, it is hard to swallow, but --
                       DR. KRESS:  Is there no other way to do it
           besides excavating?
                       DR. BARTON:  Well, there is -- well, I
           guess not.  I guess you can run things in pipes and
           stuff, and look, but --
                       DR. SHACK:  Well, you can put UT and look
           at it from the inside, but since it is a localized
           corrosion --
                       MR. NAKOSKI:  And you might even miss it. 
           I mean, it is such a localized --
                       DR. KRESS:   Somebody mentioned measuring
           electrical potential? 
                       MR. NAKOSKI:  Well, let me keep us focused
           here if I could.  It really is when does it become a
           safety concern, and you are going to have to have some
           substantial degradation in a buried component before
           it is going to impact the ability of most of this
           stuff to do its safety function.
                       So if we stay focused on that, what they
           are proposing -- and correct me again if I am wrong,
           but I think that's why the staff included what they
           are proposing is sufficient.
                       CHAIRMAN BONACA:  Well, that is exactly
           right.  On the tanks probably that is the right
           answer, and to go back to the scope of license
           renewal.  
                       MR. NAKOSKI:  Right.  And I would even
           argue that having a similar experience with Mr. Barton
           at Oyster Creek on service water piping, it would have
           had to have been a substantial degradation of that
           piping before it impacted the ability of that piping
           to perform its safety function.
                       CHAIRMAN BONACA:  Okay.
                       And if I could, the next item that I
           thought that I heard that we wanted to talk further
           about is the applicability of NFPA-25 and nuclear
           power plants raised by Dr. Kress.
                       DR. KRESS:  Right.
                       MR. NAKOSKI:  And commitment tracking
           raised by Mr. Barton regarding the level of quality. 
           We got a feedback that that was an Appendix B program. 
           And I am not sure, John, but with that in mind do we
           -- do you think we need to talk about that further?
                       DR. BARTON:  I think what you need to
           describe to the rest of the committee is how are some
           of these commitments, or promises, or whatever you
           want to call them, how is it assured that they are
           implemented in programs, and how does the NRC make
           sure that these things get closed.  I think that
           process should be described to the full committee.
                       MR. NAKOSKI:  Have you got that?
                       MR. BURTON:  Yes, I've got it, and perhaps
           revise the SER to give a little more information on
           how that is done as part of the methodology section.
                       DR. BARTON:  That's fine. 
                       MR. NAKOSKI:  And then the last one is
           related to the pipe break TLAA raised by Mr. Shack,
           and I think the fundamental question you had was why
           are we only considering the postulated pipe break only
           for fatigue, rather than looking at the other
           mechanisms.
                       DR. SHACK:  Yes.  Once you decide that a
           piping system is susceptible to other kinds of damage,
           why not pick those as candidates for a pipe break.
                       MR. NAKOSKI:  Okay.  And those were the
           four issues.  I mean, you had talked about some other
           SER updates, but I don't think that those necessarily
           need to be discussed.  Was there anything else that
           the subcommittee wants to add?
                       CHAIRMAN BONACA:  Let me do the following
           now.  First of all, I am going to go around the table
           and first of all ask the members if they have any
           further questions for Mr. Burton?
                       DR. SHACK:  Just a quick one.  I stepped
           out and maybe it was addressed, but one of the unique
           features of Hatch is the core shroud repair, and it is
           sort of almost not mentioned anywhere.  It is going to
           be covered by the VIP program, and is that VIP-76 that
           discusses that?
                       MR. BAKER:  The shroud repair was actually
           done under VIP-02.
                       DR. SHACK:  It is not referenced at all in
           the SER.
                       MR. BAKER:  Right.  The reason for that is
           that VIP-01 was the original inspection criteria, and
           the VIP-02 was the repair criteria, and VIP-07 was the
           reinspection criteria, and VIP-63 was the vertical
           weld inspection criteria.
                       We rolled all of those into one document
           now, which is VIP-76.  So, 76 is referenced, and there
           is not a staff SE yet on it, but this is a compilation
           of the other four VIP documents for which there are
           Ses.  
                       So we have rolled them all into one
           document, and so now an owner goes to one place to
           figure what to do with everything on the shroud.  The
           shroud reinspection frequency is consistent with what
           the original designer called for, which is what was
           specified in VIP-02.
                       And what the staff reviewed and approved
           when they did the review of the shroud repair itself.
                       CHAIRMAN BONACA:  Okay.  Any other
           questions for Mr. Burton?  If not, thank you for a
           very informative presentation.
                       MR. BURTON:  Thank you.
                       CHAIRMAN BONACA:  And then what I would
           like to do is two things.  One is to go around the
           table and get views from the members, and your
           observations.  And also suggestions -- you know, we
           have to draft a letter report on what are the
           important points.  You may give me that information
           later by E-mail if you want.
                       MR. BURTON:  Excuse me, but am I to assume
           that I need not go over all of the open items next
           week?
                       CHAIRMAN BONACA:  Well, wait a minute, and
           then after that I would like to go around the table
           and suggest what we are going to have in the
           presentation two weeks from today, whenever it is
           going to be.
                       So with that, I will start with Mr.
           Barton, our guest consultant here.  What do you think?
                       DR. BARTON:  As far as the -- let me start
           with the items for the full ACRS meeting.  John picked
           up several of them that I had on my list. I think one
           thing, Butch, that as far as -- and you don't have
           this much time in a full meeting, but you are going to
           talk about open items and appeals issues.  
                       What I would recommend that you do is to
           have the list of items, but differentiate between
           those that were closed, and the applicant said, yeah,
           we agree with the NRC's position.  So those are really
           simple, right?
                       But then there are some where there is
           some action required or whatever.  There are two
           different categories of how these open items were
           handled, and I think you can save a lot of time by
           just whipping through all of those where they say this
           is the NRC's position and we are going to do it.
                       Also, I think you need to have some
           discussion on the appeal process, and decisions and
           resolutions, and actions that are yet required to
           close appeal issues, and discuss the process you now
           have, and what John mentioned -- and I wasn't aware of
           NEI proposing a change.
                       So I think the full committee ought to
           hear how this appeal process is all about, and what it
           is all about, and what items are still required for
           those issues that are -- to close those issues that
           have been appealed.
                       Another one is -- well, Mario talked about
           part of this also, I think, the handling of the
           generic type components, the seismic 2 over 1 and fuel
           tanks, and how will these things be handled in the
           future so that they don't keep cropping up when you
           talk about guidance documents or whatever.
                       And skid-mounted equipment, and housings
           for HVAC, and those kinds of issues that will keep
           coming up, and explanations to the committee, and some
           of those crept up during this discussion with Hatch,
           and how were they resolved here, and what do you guys
           plan to do with these things down the road.  That's
           about it.
                       CHAIRMAN BONACA:  Any other thoughts in
           general with the application, and realizing that this
           is the final presentation to the committee, and after
           that, hopefully we are going to write a letter after.
                       DR. BARTON:  Well, based on what I heard
           today, there is no burning issues that I have got that
           should prohibit this thing from proceeding down the
           path of granting them the extension.  I mean, we
           talked about a lot of issues today, but I think they
           are all going to get resolved to the satisfaction of
           the ACRS.
                       CHAIRMAN BONACA:  Okay.  Tom.
                       DR. KRESS:  My issues were pretty well
           covered by the list he had back here, and with respect
           to what ought to be presented other than those at the
           meeting, I don't think you have a lot of time to go
           over all these open issues.
                       And what I would do is I would list them
           and hand them out, and say you guys can read these and
           read what the issue was, and how it was resolved.
                       But I wouldn't spend a lot of time going
           over them.  I think the main committee is going to put
           some sort of an ACRS position on whether the license
           renewal review process was sufficient.  So if it were
           me, I would think about talking about here is the
           review and the things that we did, and here is how
           many RAIs we had, and here is how many open items we
           had.  
                       It would be very general.  It would be
           almost one slide that tries to convince the full
           committee that this was a comprehensive review, and
           that we went over the review, and the screening, and
           the scoping process, and we questioned why these
           things weren't in scope and that sort of stuff.
                       Just as a flavor of what you did so that
           you can be sure that the full committee thinks it was
           a comprehensive and thorough review, and that would be
           my only real recommendation.
                       DR. BARTON:  That's a good point, because
           I think that the committee felt that this was a tough
           application and hard to follow.  That's a good point,
           Tom.
                       MR. BURTON:  Can I say one thing?  I think
           that is very good.  That would actually bring up
           something that happened at the previous meetings, and
           --
                       CHAIRMAN BONACA:  It doesn't matter. 
           That's fine.  
                       MR. BURTON:  That's okay?
                       CHAIRMAN BONACA:  Yes.  In fact, I support
           totally Dr. Kress' comments because if you look at the
           way that we format the letter -- you know, you can go
           back to the Arkansas letter in the spring.  
                       We are trying to address scoping and
           screening being adequate, and we are making a judgment
           on what you did, and I think it is important that you
           give us that feeling that your judgment, that your
           evaluation, was thorough and you feel good about that.
                       And second are the aging effects properly
           defined, and are the programs appropriate.  So we are
           attempting to pass a judgment on those terms.
                       DR. KRESS:  And with respect to that, I
           would -- you know, we really didn't get it here, but
           I would add some comment about what aging programs
           were already in place, and what new ones had to be put
           in place as a result of license renewal, and not going
           into any detail.
                       CHAIRMAN BONACA:  In fact, I think it
           would be very helpful if the existing programs and the
           enhanced programs, and I believe there are several of
           those, or five of those, and the new programs.
                       And the fourth thing would be the
           modifications due to closed items, because there were,
           I believe, one new or two new one-time inspections,
           and one of them is part of another program, and it
           gives us a sense of what took place, and what specific
           commitments are for the site.
                       And the other thing that I guess that I am
           continuing here is that the other thing that I think
           would be important is that often times -- and I
           realize that you have a limited amount of time.
                       But a lot of issues are -- well, for
           example, you have in TLAAs, you have certain analysis
           that you do.  But then you have in other programs
           certain things that support.  
                       For example, in the vessel, you have an
           inspection of the materials, and so on and so forth,
           and it would be good that those pieces are well-
           integrated and the programs are supporting in fact
           analysis, and just some suggestions in that case.
                       And again keep the general message to the
           full committee regarding the whole application,
           because that is really what we are going to write
           about.  And again some element may come from the
           previous letter or previous report that you made to
           us.
                       For example, there is clearly an interest
           in BWRVIPs. I mean, they are supporting other
           comments.
                       DR. KRESS:  With respect to the appeal
           process, the full committee may not be so much
           interested in the process itself.  I think what they
           are interested in is that they have a general concern
           that quite often the technical staff gets overridden
           by upper management without due consideration of all
           of the technical elements that go into their decision.
                       And I think the full committee would like
           some reassurance that that is not the case, and that
           the process doesn't just do that to it.  So rather
           than just looking at the four processes and what they
           are, get some assurance that there is due
           consideration given to the staff's technical views.
                       MR. BURTON:  Because the elements of the
           appeal process are expected from a working engineering
           organization, and so therefore why do you need a
           formal one?  
                       That's why I think that undoubtedly is an
           transparent one, but I think that is in the interest
           of the committee.  Peter, I will let you raise your
           issues.  I was going to talk about CASS, because the
           conversation at the end left me uneasy, if nothing
           else, because I am not an expert in materials.  
                       DR. FORD:  Well, I have two concerns.  One
           is CASS and the justification for one-time
           inspections, and you are qualifying or inspecting is
           not necessarily a time dependent degradation
           mechanism, and so therefore it is very dependent upon
           when you do that one-time inspection.
                       And I don't follow the justification, and
           there is the question of tanks, which is not really a
           big safety issue as I understand it, and the fire
           protection system I would imagine would be a
           significant safety impact.
                       And I follow the corrosion argument that
           if you leave it there and don't open it up, you are
           not going to have too much corrosion.  I can
           understand that, but I don't see any control of that. 
           And the 50 year thing, that just makes no sense at all
           to me.  
                       CHAIRMAN BONACA:  Let me just say that we
           have gone through a one-time inspection concept a long
           time, and the expectation of the ACRS has always been
           that it is confirmatory of an aging mechanism that is
           expected to be, or it is not expected to be there.
                       So it is applied to an aging mechanism
           that it is possible and expected to be there I think
           is inappropriate.  So that is the way we always
           understood it.  
                       So now the only reason why I felt
           comfortable enough was a listing of some supporting
           statements, because this morning the pipe was designed
           to a thickness that would be in fact supportive of 50
           years of operation.
                       Now, if in fact there is a design, that
           should have taken into account the corrosion, because
           that is the only degradation mechanism that I could
           think of.  But I think it is valuable to raise it as
           an issue, and so we can discuss it.
                       DR. FORD:  And it goes beyond just Hatch.
                       CHAIRMAN BONACA:  It is central to -- if
           you look at most of the new programs, there are one-
           time inspections, and so they are central to the whole
           license renewal process.
                       DR. KRESS:  I think that this is a generic
           license renewal question, and shouldn't impact
           anything having to do with Hatch.  And like Butch
           says, it is an ongoing thing maybe -- well, I think
           the staff considers it resolved, and that one-time
           inspections are considered okay.
                       DR. FORD:  Well, that is what worries me. 
           Somehow or another it gets into the law that it has
           passed once, and therefore it is okay.  
                       CHAIRMAN BONACA:  Well, in my mind, I have
           always considered it as what you want to do to
           prevent, recognizing that a lot of things is going to
           happen and you are going to react to it.
                       So really it is being proactive on the
           issues that you understand may be there, versus to be
           ready to be effectively reactive should they happen. 
           Of course, reactiveness also -- that when you accept
           that, you imply that you can survive the event. 
                       I mean, you accept that it could happen
           because it still would not be a major seismic event,
           and that sometimes is difficult to distinguish.  But
           what I am saying is that there is an expectation in
           license renewal that these plants will not have in
           fact new degradation mechanisms.  
                       I mean, that's going to happen, and it is
           just life, and that we would be proactive enough to at
           least take care of what we understand today.
                       DR. FORD:  The other issue I had was the
           CASS situation, and how you are going to manage that. 
           I can follow the argument, but I don't necessarily
           technically agree with it, about using the degradation
           of the associated weld as a precursor to the cracking
           and possible failure of the CASS.
                       I don't necessarily agree with that, but
           that's an academic point of view as you said, and the
           whole thing will depend to a certain extent on
           upcoming data.  But I am open, as usual, to academic
           discussion.
                       CHAIRMAN BONACA:  Well, we identified in
           the beginning four items that would be -- that you
           will discuss in the committee that were brought up at
           the beginning, and we can include these two also, and
           that makes six. 
                       DR. FORD:  I don't now how it can be
           presented at the ACRS meeting in a meaningful level. 
           I mean, they are open only for technical discussion.
                       CHAIRMAN BONACA:  Well, they in the CASS
           situation, they can simply state the position that
           they are taking, the one that says that we will
           perform the inspections of welds.
                       DR. KRESS:  And then as usual, we can
           discuss it ad infinitum.
                       CHAIRMAN BONACA:  Well, the one-time
           inspection also.  We have the specific one on the
           fire, and I think we should raise that issue.
                       DR. SHACK:  Is it the notion that you are
           going to use a lead component as a surrogate for other
           components that you are objecting to?
                       DR. FORD:  Yes.
                       DR. SHACK:  Is that because --
                       DR. FORD:  The kinetics of what is
           happening in that component --
                       DR. SHACK:  So you don't believe that a
           weld is more susceptible to IGSCC than CASS stainless?
                       DR. FORD:  Not necessarily, because we
           don't have the data to disprove it.
                       DR. SHACK:  Well, GE did a lot of data on
           Tom Devine, and critical --
                       DR. FORD:  But that was 20 years ago.
                       DR. SHACK:  I know, but --
                       DR. FORD:  And it certainly wasn't under
           radiation conditions, even though there was a low
           flux.
                       MR. BAKER:  But radiation doesn't seem to
           be something that is going to change it.
                       DR. SHACK:  Well, we will have a technical
           disagreement on it.
                       DR. FORD:  But my point is that we have
           been bitten time and time again by this presumption
           that we know what is happening when we don't know what
           is happening.  It is a concern.
                       MR. BAKER:  Peter, if I could, just one
           thing, and I won't be here, but what the staff could
           discuss is the safety implications.  And again there
           are other things that go into the plant to ensure that
           there is not a safety issue related to that.
                       You have daily jet pump surveillance, and
           other things, and so from a safety perspective that is
           a whole other issue.
                       DR. FORD:  Well, if you had to categorize
           things, you would do it by that sort of thing, and I
           would put fire protection over the tank for this one-
           time inspection.  And this one here, I would go along
           and state maybe it is an academic exercise, and it is
           not a big issue as far as PRAs.
                       And another thing I have got to mention is
           -- and again this should not be brought up at the ACRS
           meeting, but just for the record, I do have a problem
           with some of the disposition curves that are being
           used for the BWRs in general.
                       There is a huge scatter of disposition
           curves, and we are not going to resolve that, and that
           will not be resolved in the short term.  But again I
           am pinning my hopes on the statement that I keep
           hearing, that these are all living documents, and they
           will be revised.  
                       But I don't want us to get into the trap
           of it has been passed once, and therefore it is the
           bible.  It is not the bible.  
                       MR. BURTON:  I do want to say one thing,
           because as I am listening to it, it is clear that one
           of the broad topics that I need to discuss is how the
           process allows for change, and new data, and emerging
           issues, and things like that, and it would fall into
           that category.
                       DR. FORD:  And CASS is --
                       MR. BURTON:  Yes, in several of these
           things.
                       CHAIRMAN BONACA:  And there is a
           distinction between license renewal and current
           existing problems.  
                       MR. DYLE:  Just a comment, Butch, that
           might help you pull that information together.  The
           VIP provides on a semi-annual basis the inspection
           results across the entire fleet, and to the staff for
           review to see what is going on.  So that is ongoing
           and documented, and we can respond to that.
                       MR. BURTON:  How often was that?
                       MR. DYLE:  Semi-annually.  And after each
           outage season, we compile the stuff, and then forward
           it to Gene.
                       CHAIRMAN BONACA:  I think that is one of
           the strengths by the way, and we noted that in our
           interim letter that the fact that you have so many
           power plants into a program, and even if one new event
           occurs, it will occur once, and then you will know
           that it is possible in the whole fleet.
                       So therefore you are reactive to that one,
           but you can be proactive on the other units.  So there
           is a big strength coming from that.
                       DR. BARTON:  Well, Mario, has the
           committee made a statement regarding the BWRVIP
           program, which I think is a pretty good program.  Have
           you guys already gone on record on that?
                       CHAIRMAN BONACA:  Yes.
                       DR. BARTON:  Okay.
                       DR. KRESS:  I thought it was a good
           program.
                       DR. FORD:  And that is a jolly good idea. 
           It is a question about change.  Again, I am thinking
           about it from a public perception, and reading the
           proceedings of the ACRS meeting.  There are people out
           there who have got concerns on some of these issues.
                       CHAIRMAN BONACA:  Bill.
                       DR. SHACK:  I think everybody has sort of
           raised the issues that I think need to be brought up
           at the committee.  I will say that I liked this safety
           evaluation report.  I thought you made a fairly good
           case that we should renew their license, and better
           than their license renewal application did.  The staff
           saves them again, huh?
                       CHAIRMAN BONACA:  It was very good.  I
           think we gave you so much that you must be totally
           confused, and you have to spend now every day until 11
           o'clock at night putting things together.
                       MR. BURTON:  I'll be busy.  I think it
           would be beneficial because it came up several times
           today to talk about the corrective actions program as
           part of the whole -- again, change process, because I
           know that came up several times.  And if I can talk
           about it up front, I think that would probably be
           helpful.
                       CHAIRMAN BONACA:  Indeed, and you can talk
           about that and how does the whole thing get together,
           and I think it is important, but again my suggestion
           would be that you go on the topics that Dr. Ford
           highlighted, and then the second part would be more
           like some concluding statements on those portions of
           the application that refer or that are essential for
           license renewal. 
                       MR. BURTON:  Okay.
                       CHAIRMAN BONACA:  Including some -- well,
           maybe bring up data on the BWRVIPs, because when we
           look at them, they weren't reviewed most of them.  Now
           we know they were being close to being completed, and
           if there is additional information that you can
           provide us with that, that's fine, and tell us.  But
           don't go into detail, but just simply when you think
           the SER would be completed.
                       MR. BURTON:  We have an interface meeting
           every week, and we have a sheet that gives the status
           of not just VIP, but all the topical reports, and I
           will just put that on there.  No problem.
                       CHAIRMAN BONACA:  With that, are there any
           other comments or questions from the members of the
           public or the applicant?  If not, the meeting is
           adjourned.
                       (Whereupon, at 11:52 a.m., the meeting was
           concluded.)

Page Last Reviewed/Updated Wednesday, February 12, 2014