United States Nuclear Regulatory Commission - Protecting People and the Environment

491st Meeting - April 11, 2002

                
                Official Transcript of Proceedings

                  NUCLEAR REGULATORY COMMISSION



Title:                    Advisory Committee on Reactor Safeguards
                               491st Meeting



Docket Number:  (not applicable)



Location:                 Rockville, Maryland



Date:                     Thursday, April 11, 2002







Work Order No.: NRC-325                               Pages 1-407




                   NEAL R. GROSS AND CO., INC.
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                          (202) 234-4433                         UNITED STATES OF AMERICA
                       NUCLEAR REGULATORY COMMISSION
                                 + + + + +
              ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS)
                               491ST MEETING
                                 + + + + +
                         THURSDAY, APRIL 11, 2002
                                 + + + + +
                            ROCKVILLE, MARYLAND
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                       The Committee met at the Nuclear
           Regulatory Commission, Two White Flint North, Room
           T2B3, 11545 Rockville Pike, at 8:30 a.m., Dr. George
           E. Apostolakis, Chairman, presiding.
           COMMITTEE MEMBERS PRESENT:
           GEORGE E. APOSTOLAKIS Chairman
           MARIO V. BONACA       Vice Chairman
           F. PETER FORD         Member
           THOMAS S. KRESS       Member
           GRAHAM M. LEITCH      Member
           DANA A. POWERS        Member
           VICTOR H. RANSOM      Member
           STEPHEN L. ROSEN      Member
           WILLIAM J. SHACK      Member
           JOHN D. SIEBER        Member
           ACRS STAFF PRESENT:
           JOHN T. LARKINS       Executive Director
           SHER BAHADUR
           SAM DURAISWAMY
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
                                 I N D E X
           Opening Remarks by the ACRS Chairman . . . . . . . 4
           Final Review of the Turkey Point License
                 Renewal Application. . . . . . . . . . . . . 7
           Advanced Reactor Research Plan . . . . . . . . . 116
           CRDM Penetration Cracking and Reactor Pressure
           Vessel Head Degradation
                 Peter Ford . . . . . . . . . . . . . . . . 206
                 Larry Mathews. . . . . . . . . . . . . . . 207
                 John Wood. . . . . . . . . . . . . . . . . 257
                 Ken Byrd . . . . . . . . . . . . . . . . . 278
           Staff Presentations
                 Mr. Jack Grobe . . . . . . . . . . . . . . 295
                 Ken Karwoski . . . . . . . . . . . . . . . 333
           Westinghouse Owners Group (WOG) and Electric
                 Power Research Institute (EPR) Initiatives
                 Related to Risk-Informed Inservice Inspection
                 of Piping
                 Allen Hiser. . . . . . . . . . . . . . . . 337
                 Andrea Keim. . . . . . . . . . . . . . . . 357
                 Stephen Dinsmore . . . . . . . . . . . . . 367
           Adjourn. . . . . . . . . . . . . . . . . . . . . 407
           
           
                                      P-R-O-C-E-E-D-I-N-G-S
                                                    (8:30 a.m.)
                       CHAIRMAN APOSTOLAKIS:  The meeting will
           now come to order.  This is the first day of the 491st
           meeting of the Advisory Committee on Reactor
           Safeguards.  During today's meeting the Committee will
           consider the following:  Final Review of the Turkey
           Point License Renewal Application; Advanced Reactor
           Research Plan; CRDM Penetration Cracking and Reactor
           Pressure Vessel Head Degradation; Westinghouse Owners
           Group (WOG) and Electric Power Research Institute
           (EPR) Initiatives Related to Risk-Informed Inservice
           Inspection of Piping;  and Proposed ACRS Reports.
                       This meeting is being conducted in
           accordance with the provisions of the Federal Advisory
           Committee Act.  Mr. Howard Larson is the designed
           federal official for the initial portion of the
           meeting.
                       We have received no written comments or
           requests for time to make oral statements from members
           of the public regarding today's sessions.  A
           transcript of portions of the meeting is being kept
           and it is requested that the speakers use one of the
           microphones, identify themselves and speak with
           sufficient clarity and volume so that they can be
           readily heard.
                       I will begin with some items of current
           interest.  First of all, we are welcoming back Mr.
           Graham Leitch.
                       MEMBER LEITCH:  Thank you.  It's good to
           be back.
                       CHAIRMAN APOSTOLAKIS:  That's good.  I
           would like to inform the members that Chairman Meserve
           will be here tomorrow at 11 a.m. to welcome our newest
           member.  And at 1 o'clock tomorrow afternoon we are
           all going as a group to have our picture taken
           individually because eventually we will get new
           budgets.
                       MEMBER SHACK:  I'll need to dress up for
           that.
                       (Laughter.)
                       MEMBER SIEBER:  Would that be possible?
                       (Laughter.)
                       MEMBER SHACK:  That's the problem.
                       CHAIRMAN APOSTOLAKIS:  You all have this
           handout, items of interest.  There are five speeches
           by the Commissioners at the recent Regulatory
           Information Conference.  Also, we have summary of the
           Reactor Oversight Process Inspecting Findings that
           should be of interest and also you will see on page 27
           a news item that Westinghouse Electric Company has
           submitted an application for design certification of
           the AP-1000 design.  And Dr. Kress has a tape perhaps
           we should all see?
                       MEMBER KRESS:  Yes, I have here in my hot
           little hands a copy of a copy of a copy of a copy. 
           Sandia at work, mostly, that I obtained by nefarious
           means and what this is is a tape showing a lot of the
           things they did to show the robustness of spent fuel
           casks, like running trains into them and dropping them
           off of buildings and etcetera.  So if anybody is
           interested in seeing this and I have it and I guess
           Theron can set it up and show it at noon time some
           time.
                       CHAIRMAN APOSTOLAKIS:  How long is it?
                       MEMBER KRESS:  It's not very long.
                       CHAIRMAN APOSTOLAKIS:  Okay, so maybe we
           can do that at 12:30 or so?
                       MEMBER POWERS:  After members have watched
           it and convinced themselves that the casks are
           incredibly robust, I'll them what's wrong with the
           tests.
                       MEMBER KRESS:  Okay, great.
                       CHAIRMAN APOSTOLAKIS:  Okay, so I think we
           are now -- do the members have anything else to add by
           way of introduction?  
                       Okay, so the first item on the agenda is
           the final review of the Turkey Point License Renewal
           Application.
                       Dr. Bonaca is our lead member.  Dr.
           Bonaca?
                       VICE CHAIR BONACA:  Yes, good morning.  On
           March 13, the Subcommittee on License Renewal traveled
           to Turkey Point and at that time we visited the site. 
           We were able to observe on the simulators the ability
           of the plant to interconnect the emergency diesel
           generators from one unit to the other unit for station
           blackout concerns.
                       We also heard from the plant about the way
           that they addressed closure of the open items.  There
           were only four open items in the SER for license
           renewal.  We had an opportunity to observe the site
           and note the excellent physical conditions of the
           equipment on the site.
                       In the afternoon on the 13th we met in
           Town Hall of Florida City and there we had a public
           meeting and we heard from the staff how the open items
           had been addressed and closed.  
                       During that meeting we also had some
           observation from a member of the public.  We also had
           in writing some concerns raised by another member of
           the public.  The two concerns really echoed each
           other.  One of the concerns that was raised had to do
           with voids in the concrete structure of the
           containment identified at Turkey Point, both units, in
           the early 1980s.  We heard from the site personnel on
           how the issue had been addressed.  We felt reasonably
           confident that they had been addressed properly.  We
           asked questions regarding the generic implications,
           how they had been addressed and for those we have
           asked the staff to come today and tell us how they
           were handled for the other sites.
                       And so with that in mind, we have a
           presentation this morning both from the Turkey Point
           people and from the staff and at this point I turn the
           meeting to PK Kuo who is here to present us on that.
                       MR. KUO:  Thank you, Dr. Bonaca.  Good
           morning, members of the Committee.  My name is PT Kuo,
           the Program Director for the License Renewal and
           Involved* Impacts Program.  This is my first week on
           the job.  Chris Grime has moved on to take on new
           challenges and we all wish him good luck.  I also want
           to introduce Mr. Frank Gillespie on my right.  Mr.
           Gillespie is the Deputy Director for the Division of
           Regulatory Improvements Program.
                       Today, after the Applicant's presentation,
           the staff will brief the Committee on the review
           results of the Turkey Point license renewal
           applications and specifically, the staff will address
           in detail the questions raised by Mr. Oncavage in
           their letter to the Committee on concrete voids and
           the hurricane damages.
                       We are going to have an assembled panel to
           brief the Commission.  We also have a technical staff
           sitting in the audience ready to answer any of your
           questions.
                       With that I will ask whether Mr. Gillespie
           has any opening remarks?
                       MR. GILLESPIE:  Yes.  Let me just address
           the concrete void issue because we may not have done
           as much research on it as we would like relative to
           everything from the old Oyster Creek problem with
           spalling concrete on the outside to the voids that
           were identified in the 1980s and going back and saying
           did we consider this generically at that time?
                       The staff is going to be prepared to
           address it for Turkey Point where we think it's been
           plant specifically resolved and I'm going to tell you
           right now we might have an IOU to have to come back as
           we were kind of talking about this last night,
           prepping for the meeting.  We might not have done the
           generic research on the other aspects of it quite yet
           and we're kind of still in a process.  The other thing
           is hopefully between the staff and the licensee's
           presentation, we will address things like Part 21 on
           analysis and decision points that are in Part 21 on is
           it significant, is it generic?  And the lack of -- and
           it's a question of documentation for convenience. 
           While the letter you got from this individual was, in
           fact, an open letter, the Agency did enter it and
           Region II is going to be on the phone to try to
           address this.  They did enter it into the allegation
           system.  Even though it was an open question it got
           put in the allegation system to make sure we followed
           up and got with the person and got back to them and
           got letters to them and did an inspection.
                       Unfortunately, that system gives the
           appearances because it, in general, was designed to
           protect people's identity of being kind of private and
           therefore the link to the plant-specific issue and
           what was done might not be obvious in public
           documentation because of that.  So Region II is going
           to be on the phone to try to address that to the
           degree they can.
                       We put ourselves in a procedural box when
           we put a public issue in a private system. 
                       MR. BLANCHARD:  Yes.  I realize just for
           the benefit for those members who were not in the
           meeting, this is all because in their mind there was
           an expectation that since this was a potentially
           generic issue, maybe the licensee had initiated a Part
           21 which speaks of a defect to a significant
           component.  And Part 21's intent is the one of making
           the issue known, available to all plants so that
           people can look at their own plant and inform the NRC
           that there is an action to be taken on that.  And
           that's why we raise these kind of issues and we will
           hear from Region II how it's handled.
                       MR. GILLESPIE:  So we'll take our best
           shot at answering all of the questions, but we may
           have a little something.  I talked to Goutam here and
           depending on how it all comes out when we get all the
           facts on the table, we might have an IOU still left.
                       VICE CHAIR BONACA:  Yes, it's important,
           however, today that we also separate Turkey Point and
           how it was addressed at Turkey Point --
                       MR. GILLESPIE:  Yes --
                       VICE CHAIR BONACA:  From the generic issue
           because that may have to be handled actually -- they
           should be handled differently.  We want to make sure
           that there isn't any outstanding issue to the drafting
           of a letter of the report at Turkey Point.
                       MR. GILLESPIE:  Yes.  And PT told me last
           night, he said "I'm the license renewal guy."  And he
           says, "this is an operating question."  I said, "Yeah,
           but you're stuck leading the meeting."  So --
                       (Laughter.)
                       Thank you.
                       MR. KUO:  And if I may add, we also have
           a Region II representative who will be tied up in the
           telephone line and to here and to answer any questions
           you may have.
                       VICE CHAIR BONACA:  Thank you.
                       MR. KUO:  Thank you.
                       CHAIRMAN APOSTOLAKIS:  Okay, the Applicant
           can go ahead.
                       MR. HALE:  Can everybody hear me okay? 
           Hi, my name is Steve Hale.  I'm the Project Manager
           for License Renewal for Turkey Point in St. Lucie.  I
           thank you for the opportunity to talk to you all
           today.  I know I've met several of you when you came
           to the site, as well as the ACRS subcommittee meeting
           we had last September.
                       What I'd like to do today is give you an
           overview of the application and then talk specifically
           about two of the open items which were a little more
           complicated to address than say some of the others and
           I'm going to talk about the closure of the nonsafety
           related which can affect safety related category of
           scoping and the license renewal rule, what we call
           Category 2.  Then I'll talk about field-erected tanks
           and the program that we propose for field-erected
           tanks to close that open item.
                       When we began the license renewal
           application effort for Turkey Point, a lot of the
           guidance that's in place today was really in draft
           form, so we had to drawn on multiple sources.  While
           we had Part 54, we have a draft standard review plan,
           but it was under major revision at the time.  We had
           a draft GALL report.  We tried to address and look at
           GALL as part of our overall process, but that was also
           in the developing stage for Turkey Point.  We had a
           draft Reg. Guide, but we had 95-10 which was issued,
           I guess the final rev. was in the 1996 time frame
           which had undergone somewhat of a demonstration
           program, so we utilized the methodology that was in
           95-10.
                       Additionally, we tried to use the lessons
           learned from previous applications, RAIs and RAI
           responses which were on-going with Calvert Cliffs and
           Oconee at the time.  And as generic issues were being
           resolved between NRC and NEI, we tried to factor those
           also in co-application as they were available and as
           they were applicable to Turkey Point.  
                       One of the efforts NEI underwent in 1999
           was working with the NRC staff and trying to come up
           with a format that we both could agree on so we could
           get used to the information being presented in the
           same places.  This was, I believe, in the 1999 time
           frame and essentially, based on the draft SCs that
           were issued for Calvert Cliffs and Oconee, plus some
           lessons learned through those reviews, we structured,
           we came up with a format that both the staff and NEI
           agreed to and ANO was really the first to follow that
           standard format and then we followed Hatch because of
           where they were in the development of their
           application, attempted as best they could to address
           that format, but based on where they were, they really
           had a difficult time in trying to comply with it
           totally.
                       And then I think the subsequent
           applications that have come down the pike, Dominion's
           applications, Duke's other applications as well as
           Peach Bottom, followed the standard format.  It's
           broken down into four chapters.  The first chapter
           addresses the administrative information requirements
           of Part 54.  Chapter 2 goes through the methodology we
           utilize for scoping and screening and presents that
           results.  Chapter 3 is where you do your aging
           management review and Chapter 4 addresses time-limited
           aging analyses.
                       Now I hadn't intended to go through
           scoping and screening methodology today.  We went
           through that in great detail with the subcommittee on
           September 25th of last year.
                       Also, as part of that standard format
           there were several appendices.  One was the UFSAR
           supplement.  The second is Appendix B where we have
           summaries of our aging management programs presented
           in the ten element format addressing staff
           requirements on how they want aging management
           programs presented.  We included an Appendix C and
           this was really to address some of the, what we call
           generic type RAIs, RAIs regarding positions, regarding
           aging effects and that sort of thing.  It wasn't
           required by the standard format, but this was an
           intent on our part to address some of the RAIs we had
           seen in previous applications and we felt Appendix C
           did a good job of addressing some of those.  Appendix
           D would include any of the technical specification
           changes that would be identified by the overall
           process and then as an adjunct or really an attachment
           with the application comes the environmental report.
                       When you look at the scoping criteria in
           the rule there's a criteria of safety-related
           components that -- and there's three criteria
           stipulated for safety-related.  Non-safety related
           which can affect safety-related, based on our review
           of this, we saw two types of non-safety which can
           affect safety.  One is where the non-safety system has
           to function in order not to affect a safety-related
           component.  And the other is one for potential of
           interactions, where the failure of the non-safety
           system could potentially affect the function of the
           safety-related system.  And then category 3 is the
           five regulated events:  fire protection, PTS, EQ, ATWS
           and station blackout.
                       In the application, you'll find in Section
           2.2 a summary of all the systems at the plant and the
           ones we had identified as in the scope of license
           renewal and we do the same with structures.  As you
           can see, about half the systems in the plant have at
           least some portions that fall within the scope of
           license renewal and a little less than or a little
           more than a third of the structures at the site.
                       I have to note that the structures at the
           site include anything in the protected area so you
           have a lot of the administration buildings and that
           sort of thing as why not essentially comes into play
           is the power block buildings.
                       For screening, this is where you really
           get down to the nuts and bolts of the components and
           structural components that support the functions that
           were identified in the system and structure level of
           scoping.  And going through screening, the first step
           you do a component level scoping.  Then you look at
           whether the component performs its function without
           moving parts or change configurations, essentially
           what we consider to be passive and/or they're not
           subject to replacement based on a qualified life.  So
           you take each major system or structure in the plant
           that falls within the scope of license renewal.  You
           break it down into its pieces, parts, you determine
           which ones support the functions and you establish
           which of those components are passive and which ones
           are not replaced regularly.
                       The results of screening are presented in
           the six column tables in Chapter 3.  One of the
           lessons learned that we had with the Oconee and
           Calvert Cliffs applications was the fact that it
           really makes it good to see the entire IPA on one set
           of tables, so you have the scoping and screening
           results essentially in the first two columns and then
           you have a balance of the aging management reviews, so
           rather than including duplicate tables in Chapter 2
           and Chapter 3, we simply provide a summary in Chapter
           2 and refer to Chapter 3 which lists the scoping and
           screening results and then you can see the rest of the
           IPA stacked up with each one of those components.  
                       The mechanical sections, again, this is
           consistent with the standard format that was
           developed.  You had a reactor coolant system,
           connected systems, emergency safety features,
           auxiliary systems and steam and power conversion.  
                       In the structural area, we chose to break
           it up between the containment and other structures and
           in the electrical and I & C section, it essentially
           looks at all the electrical components of the site and
           it follows a slightly different process than the
           mechanical and civil sections.
                       We also submitted license renewal boundary
           drawings along with our application.  Again, the staff
           has indicated that really facilitates their review in
           the mechanical area and lets them see what the
           boundaries were and what equipment was included in
           scope based on the actual drawings generated from the
           PNIDs at the plant.
                       Aging Management Reviews are presented in
           Chapter 3 and Appendix B because really the Aging
           Management Review not only consists of identifying the
           aging effects, but demonstrating the aging effects are
           adequately managed for the extended period of
           operation.  
                       To facilitate the review, we grouped the
           items in the Aging Management Review the same way
           they're grouped in the scoping and screening section
           so you had a one to one correlation through the
           application.  Again, the results are presented in the
           six column tables including identifying the aging
           program that manages any aging effects that
           requirement management.
                       For nonclass 1 components, again in
           Appendix C, some of the technical positions we took
           regarding certain types of aging effects are presented
           there for non-Class 1 mechanical as well as civil
           structural.  In the Class 1 area, we develop and
           discuss the aging effects specifically in Chapter 3.
                       One of the things that we felt was
           mandatory as part of our review for license renewal
           was doing an extensive review of both industry
           experience as well as plant-specific experience at
           Turkey Point.  We reviewed INPO and NRC generic
           communications and also our responses and any of those
           that really were related to aging we went back and
           relooked at those to see if we'd addressed them
           appropriately.
                       In terms of plant-specific history, we
           went back and looked at the nonconformance reports and
           condition reports, I think all the way back to the
           early 1980s.  We looked at event response teams. 
           These are teams we form when we have a significant
           event at Turkey Point like a plant trip, those sort of
           things.  We form teams whose goal is not only to
           identify what needs to be done to get the plant
           started up, but also root cause and this type of
           thing.
                       One of the great source of information we
           have, we have a metallurgical lab and all of the
           nonconforming conditions or condition reports that
           require metallurgical analysis are submitted to the
           metallurgical lab for determination of root cause and
           the type of aging effects.  We also drew on that
           population.  Those were available, I think, at Turkey
           Point we had over 200 metallurgical lab reports so we
           used as another major source of information for
           operating experience.
                       And as also part of our process, our
           procedures and the way we developed our Aging
           Management Review had us go and specifically talk to
           the system engineers and the component engineers.  My
           team was located on the Turkey Point site, so we had
           quite a bit of interface with the engineers that deal
           with the systems on a day to day basis.
                       CHAIRMAN APOSTOLAKIS:  Now from the
           metallurgical laboratory reports, I don't understand
           what benefit you had from those.  Is it possible that
           you would decide to do something by looking at one of
           those reports that you had not already done?
                       MR. HALE:  One of the issues that has been
           identified as the one -- hey, we don't think aging
           effects are occurring, but you need to go in and do
           one-time inspections to verify.  Pitting is a good
           example.  But if you go back and you look at
           metallurgical and you sort on things like stainless
           steel systems with chemistry control, you can look as
           whether you've ever had any specific failures related
           to pitting or stress corrosion cracking.  We use
           metallurgical lab reports when they determined that
           we've had loss of material due to MIC and we folded
           those -- we developed tools for doing aging management
           reviews on the non-Class 1 mechanical systems because
           those are the ones where you get the wide variety of
           materials and environments.  And one of the things you
           use is hey, the tools the industry may develop may say
           that you have to address stress corrosion and cracking
           in the system, but if we can go back to the
           metallurgical lab reports and say we've never had
           stress corrosion cracking in this system and we can
           develop a technical basis for it, it provides a good
           source of information.  Again, on the other hand, the
           tools the industry develops may say you don't get MIC
           in these kind of systems.  Where we have experienced
           MIC and we discovered that through our interface with
           the metallurgical groups as well as the metallurgical
           lab reports.  So we're not saying that we just use it
           carte blanche.  What we're saying we use that
           information as additional research in some of the
           technical positions we may have taken with regards to
           aging effects.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. HALE:  Any other questions related to
           that?  Okay.  
                       Time Limited Aging Analysis.  These were
           the major TLAAs at Turkey Point:  EQ, class and
           balance of plant fatigue, containment tendon
           relaxation, reactor vessel irradiation embrittlement. 
           We had a couple of cases wear/erosion where we had
           TLAAs associated with that.  Containment liner
           fatigue, crane fatigue.  Also as part of the rule we
           have to do a review of time bound exemptions whether
           we had any and our review determined we didn't.
                       With regard to the UFSAR supplement, we
           submitted a markup with the application.  In addition
           to that we included a new chapter in the SAR which
           includes all the AMPs that are committed to for aging
           management, as well as a description of every one of
           the TLAAs that were identified.  Also, in the FSAR
           supplements our commitments related to programs are
           included.  Now additionally, one of the things we did
           with the staff, we've updated the SAR supplement to
           include all the commitments that were identified as
           part of our review of the application.  In other
           words, with RAIs, responses to RAIs, we included any
           additional commitments that came out of that
           interchange into a revised SAR supplement that we
           issued late last year.
                       With regards to Appendix B where Aging
           Management Programs are located, for each aging effect
           requirement management an Aging Management Program is
           identified.  We presented these programs in the 10
           attributes following the guidance issued by the NRC.
                       We've got three categories of Aging
           Management Programs.  We have those that are existing,
           those that need to be adjusted and those that are
           brand new.  You see we have pretty equal distribution.
                       Again, I described Appendix C, non-Class
           1 component, Aging Management Review Process,it's not
           required by the regulation, but we did submit it to
           address some of the previous RAIs we had seen and
           other applications.  And Appendix D was technical
           specification changes.  We did not have any for the
           Turkey Point license renewal application.
                       I just wanted to mention the environmental
           report because there is an environmental piece.  Some
           of the unique things about the Turkey Point site, we
           have thousands of miles type of cooling canal system
           and you see it from satellite photos, in fact.  We do
           not identify the need of any major refurbishment which
           is one of the issues that needs to be addressed in the
           environmental report.
                       We do not use wells at the site.  We
           essentially, the only water we use from the local
           community is domestic water.  And the evaluation we
           performed against the alternative show that license
           renewal is the lowest impact option under the
           environmental review.
                       MEMBER LEITCH:  Steve, I have a question. 
           I'm not sure if this is the right time to bring it up
           or not, but the fossil units that are adjacent to the
           nuclear units --
                       MR. HALE:  yes.
                       MEMBER LEITCH:  It seemed to me that --
           and I'm going on memory of quite a few years back, but
           it seemed to me that during Hurricane Andrew there was
           some missiles from the fossil unit that damaged a part
           of the nuclear unit.  I think it was in the fire
           protection pump house or something like that.
                       MR. HALE:  What happened was we had a high
           tower out in the water treatment plant area and the
           high tower fell over on one of our domestic water
           tanks.  We have two tanks and the domestic water tanks
           are also what you credit for your Appendix R, I
           believe A-1, whatever, it's our fire protection water
           sources.  So the tower actually fell over on one of
           the tanks and as a result we got into one of the start
           up issues we had related post-Hurricane Andrew was
           providing the water sources until we could reconstruct
           that tank.
                       MEMBER LEITCH:  I guess my question is in
           the 20 years extension period for this license, what
           assurance do we have that the fossil units wouldn't be
           retired and as many fossil units abandoned in place
           and that there might be missiles, if you will, created
           as a result of that that could in future storms damage
           the nuclear unit?
                       MR. HALE:  Well, for one, the safety-
           related equipment is protected from missiles as part
           of our design basis.  In fact, the safety-related
           portions of the plant and even some of the nonsafety-
           related portions of the plant survive very well.  We
           were back on line within a month after Hurricane
           Andrew.
                       There were a lot of missiles during
           Hurricane Andrew, independent of whether the fossil
           unit was there or not.  We had winds in the area of --
           the eye passed over Turkey Point and we were in 150 to
           160 miles per hour range.  The South Florida building
           code is about 120 and so trees -- there was a missile
           that went through one of the oil tanks, what they call
           the day tanks that affected that particular tank.
                       The nuclear plant fared very well with the
           exception of that high tower falling on the fire water
           tank and a materials warehouse that was outside of the
           protected area.  The plant did very well.  I think
           it's a proof test on the plant so to speak, but one of
           the things in terms of interactions that was
           identified some years ago and has been evaluated is
           the seismic capability of the smokestacks.  And they
           have been evaluated.  In fact, we've included them in
           the scope of license renewal for that very reason.
                       MEMBER LEITCH:  Okay, the smokestacks at
           the adjacent fossil plant?
                       MR. HALE:  Yes, yes.  You'll find them
           discussed in the application, in fact.
                       MEMBER LEITCH:  That's good.  Thank you.
                       MEMBER SIEBER:  Those stacks aren't very
           high though, right?
                       MR. HALE:  About 400 feet.  I wouldn't
           want to climb to the top of them.  There are some
           folks who do who have to work on the lights, that sort
           of thing.
                       Okay now I'd like to go through the
           resolution of open items and Dr. Kress, I've tried to
           -- you had mentioned the criteria, so I've included
           some additional information there.  I hope I address
           your question that you had.
                       This is a presentation I went through with
           the subcommittee when they were at the site.  The open
           item is entitled scoping of seismic II over I piping
           systems.  It really goes beyond that.  This is really
           interactions between nonsafety and safety-related
           system and the potential impact on safety-related.  
                       One of the things I wanted to summarize
           was go through the components we included in the scope
           of license renewal to start with:  (1) any pipe
           segment beyond the pressure boundary which is included
           in the seismic analysis, we included that pipe segment
           in the scope of license renewal because it fit in that
           first category which is it's performing a function in
           support of the safety system.
                       We included all piping component supports
           for nonsafety-related mechanical systems with the
           potential of seismic II over I interactions because
           Turkey Point is an older plant.  We did this on an
           area basis.  We basically went through each building
           of the plant and any room that contained both
           nonsafety and safety-related equipment all the
           nonsafety-related supports were in the scope of
           license renewal in that area, regardless of whether
           the stuff could follow effect or whatever, we just
           said this area contains both types, so as a result all
           the nonsafety-related supports associated with
           ductwork, cable trays, conduit and in addition to that
           we included the conduit itself, the cable trays and
           other structural components outside of the mechanical
           area, in these areas where you had both safety and
           nonsafety equipment.
                       In addition to that, we had done a fairly
           extensive internal and external flooding analyses so
           anything related to that was included in the scope of
           license renewal and this basically included curbing. 
           We have some sump pumps down in the RHR pump rooms and
           those sump rooms that were included in the scope of
           license renewal as well to accommodate flooding
           effects and in addition to that, we included all the
           pipe whip restraints, barriers, these type of things
           that we credit for jet impingement, effects of spray
           and pipe whip.
                       That's what we included in the scope of
           license renewal to start with.  After a lot of
           dialogue between the staff and ourselves, the issue
           that was identified is that the effects of pipe whip,
           jet impingement, physical contact, pipes falling on
           pipes and leakage due to credible and that's an
           important word, credible nonsafety-related pipe
           failures, beyond the current assigned break locations
           because we've evaluated breaks in certain places, but
           we haven't evaluated them across the board, need to be
           considered based on the industry operating experience. 
           In other words, if you'd had failures of 
           nonsafety-related piping, through operating
           experience, and you have a piece of a similar type
           piping routed above safety-related equipment, then
           that should be something that should be included in
           the scope of license renewal and managed from an aging
           standpoint.
                       As a result of this issue, there may be
           some additional pipe segments that need to be included
           in the scope of license renewal and thus an Aging
           Management Review needs to be performed.  During our
           ACR Subcommittee walk down to the plant, I showed the
           ACR Subcommittee an example of the kind of pipe we
           were talking about.
                       What we did as a result of that and all
           these rooms where we had both nonsafety and 
           safety-related equipment we did an evaluation assuming
           credible failures based on operating experience of
           nonsafety-related piping beyond what's currently in
           our current license basis.  If there was an
           interaction with safety-related components as a result
           of this failure, we in turn included that pipe segment
           in the scope of license renewal. 
                       To address the criteria --
                       CHAIRMAN APOSTOLAKIS:  Let me understand
           this.  Something is credible if it has happened?
                       MR. HALE:  In operating experience in the
           industry.
                       CHAIRMAN APOSTOLAKIS:  Oh, in the industry
           at large.
                       MR. HALE:  In the industry at large.  Not
           necessarily -- although a lot of this piping is not in
           the scope of license renewal and that sort of thing,
           we don't operate with leaks at the site and we manage
           that, but the real issue is when you're looking into
           the future, without doing specific aging management
           say on a piece of pipe, could it fail, such that it
           would affect safety-related equipment.
                       So we used a fairly conservative criteria
           in establishing the interaction.  Basically, what we
           said if we had a nonsafety-related piece of pipe in a
           room with electrical equipment and that electrical
           equipment is not qualified for outdoor service, then
           we said that pipe is in the scope of license renewal. 
           We didn't do a rigorous evaluation or analysis of
           spray and see if the component could accommodate it. 
           We basically just concluded whether it would actually
           affect it or not through analysis, we said that pipe
           segment was in the scope of license renewal from a
           leakage standpoint.
                       From the pipe whip, jet impingement and
           physical contact and this was basically the high
           energy piping out on the turbine building, it really
           took walk downs and actual physical observation of the
           piping and essentially we took the criteria that if we
           could see the pipe and the safety-related equipment,
           that piece of pipe was in the scope of license
           renewal.  It wasn't based on a rigorous analysis, but
           we took a very conservative posture on this.  
                       And in this case it was primarily conduit
           and cable tray routed out in the turbine building, so
           if we had to run a cable tray between two walls and
           there was high energy piping in the area, we said that
           high energy pipe is in the scope of license renewal.
                       I don't know if that addresses the
           criteria question that you have, but we basically just
           took a conservative position on it.
                       What was the results of all this?  We
           included a number of pipe segments in five of the
           structures that contained safety and non-safety
           equipment.  We identified the aging effects requiring
           management for those pipe segments and for those that
           require aging management, we included them in our
           chemistry control program, our systems and structures
           monitoring program and our Flow-Accelerated Corrosion
           Program.  And we've already made al those changes in
           the program documents.  In most cases, they were
           already included in the program to start with.  We
           just had not identified the piece of pipes in the
           scope of license renewal.
                       MEMBER ROSEN:  What is the qualifier as
           applicable?
                       MR. HALE:  Well, this is just a broad
           statement, you know, you don't use FAC on a non-FAC
           system.  It was just a broad -- if you locate our
           open-item response, I don't know if you all have
           copies of that.  We highlight specifically what
           systems and what programs apply to which pipe
           segments.
                       MEMBER ROSEN:  But it's not an out -- all
           of the above is true except when we decide we don't
           want to.
                       MR. HALE:  No, no, no, no.  The intention
           here is not all these programs apply to all the pipe
           segments, that's all.  FAC applies to only certain
           types of systems.  Chemistry applies to certain
           systems as well as the system structures and
           monitoring program.  It's in a lot of detail in our
           open item response and we've incorporated it on a
           component level basis where we identify the specific
           programs that are required.
                       Any more questions on II over I?  Now this
           is one that I think the industry and the staff are
           working towards a resolution such that this will not
           become an open item on subsequent applications where
           the guidance gets clear, because a lot of it comes to
           communications and your ability to understand what the
           true issue is and I think once we understood, then it
           was easy for us to work through what it was we needed
           to do.
                       VICE CHAIR BONACA:  Do you think the
           guidance now is clear enough?
                       MR. HALE:  I think it's still going to be
           a challenge because for -- for older plants.  I think
           newer plants, we've done an initial scoping review for
           St. Lucie.  It's not going to be quite the same.  The
           older plants have some unique design features --
                       VICE CHAIR BONACA:  But the logic is
           pretty clear.  Older, previous evaluation, II over I
           were based on concerns with high energy line break, so
           therefore you're looking for those kind of effects,
           not aging.
                       MR. HALE:  Right.
                       VICE CHAIR BONACA:  Whatever.  Aging now
           introduces potentially some other locations for
           failures that are not already covered by previous, so
           it seems to me the logic is clear.  I mean --
                       MR. HALE:  Right.
                       VICE CHAIR BONACA:  The question is how is
           the guidance now because we're be looking for.  We
           thought that the guidance provided in the SER for
           Hatch was quite clear.
                       MR. HALE:  Yeah.  Once you understand what
           the true issues are, I think that -- again, these
           guidance and these generic interchanges we're having
           with the staff are a real positive step, I feel, get
           some of these down on paper, you know, so we can -- we
           don't get into the point where it's an open item.
                       But the other item I was going to talk
           about was related to field-erected tanks.  This was an
           item where the NRC had identified to us three times
           they wanted us to address regarding field-erected
           tanks.  One, we had not supplied specific acceptance
           criteria in the application regarding inspection. 
           They wanted us to include some additional provisions
           in our program that called for additional examinations
           if the one-time inspection we had proposed identified
           extensive loss of material.  And also provide a little
           more information regarding why we felt we only needed
           to do one-time inspection on these tanks.
                       With regards to the acceptance criteria
           and additional examinations, the acceptance criteria
           is any loss of material greater than the tanks
           corrosion allowance, okay, will require specific
           corrective action in our corrected action program and
           as part of that, we'll consider the use of any
           additional volumetric or service inspections and
           identify as well, whether we need to do follow-up
           inspections and that has been incorporated into the
           program requirements.
                       Our basis behind one-time inspection and
           I'd like to point out in any of these cases where we
           say a one-time inspection is because we're going into
           it with the thought that we don't expect to find an
           issue.  In any of these one-time inspections, if we do
           find problems we would be required under our
           corrective action program to follow up and establish
           future inspections and that sort of thing.  So when we
           say one-time inspections, we're saying that this is
           something where we don't expect to find anything, but
           our corrective action process would require us to
           follow-on if we had to.
                       VICE CHAIR BONACA:  So if you find
           something when you do the one-time inspection, you'll
           convert that to a program?
                       MR. HALE:  It depends on the aging effect
           and what it may be, but if it's something that looks
           like it's going to be a continuing thing that we need
           to manage, then certainly we would institute follow-on
           inspections, but that would be part of our assessment
           and evaluation and what we saw.
                       Again, the first plan is under the one-
           time we don't expect to find significant aging.  Our
           plant operating experience has revealed no incidents
           of degradation of CSTs, RWSTs and DWSTs, other than
           some repairs we had to do to the condensate storage
           tanks were attributed to one, we had some poor
           coatings to start with on the tank and secondly, the
           tank was being subjected due to an operational problem
           to hotter basically steam fluid was blown into the
           tank which was causing some degradation around the top
           that it was never really designed for.  This is a 
           field-erected atmospheric tank and it was being
           exposed to some higher temperatures.
                       Secondly, we went into the demineralized
           water storage tank recently to install a floating
           cover on it to help with oxygen control.  We didn't
           find any degradation in that tank as part of that
           modification we performed.
                       On top of that, the RWSTs, the CSTs and
           the DWSTs, we inspect those.  Those are part of our 
           on-going external inspection program so any problems
           with the tank, you would see corrosion that sort of
           thing on the outside of the tanks.
                       When the ACRS Subcommittee was at the
           site, we pointed out a couple of the tanks as part of
           our walk down we did.
                       Okay, that's all I had with regards to my
           formal presentation.
                       Do you have any other questions?
                       VICE CHAIR BONACA:  Do you have anything
           to say about the statements from Mr. Oncavage or are
           they going to be at a later time?
                       MR. HALE:  I went back and as part of Mr.
           Oncavage's statements I looked at what we did as a
           utility, with regards to the discovery, analyzing it,
           evaluating any corrective actions.   With regards to
           the Part 21 issue, our procedures require us to
           address defects under Part 21.  It's a mandated
           requirement.  It's in our quality instructions.  
                       One of the things that you have to do
           though is to do a significant safety hazards
           evaluation to establish whether it is reportable under
           Part 21.  With regards to this particular event, the
           evaluation performed by Bechtel one, determined that
           the pressure integrity of the containment was never
           compromised and this is documented in the Bechtel
           evaluation after discovery of the event --
                       VICE CHAIR BONACA:  The design capability
           of the containment?
                       MR. HALE:  Well, two things.  One the
           pressure integrity, certainly the containment had
           undergone integrated leak rate tests as well as the
           structural integrity test previously and if you look
           where the void was, it was beyond the welded portion
           of the pressure battery.
                       Secondly, in that evaluation that Bechtel
           performed they also demonstrated that the structural
           integrity of the containment was not affected by the
           voids.  So for it to be reportable, at least from our
           procedures, under Part 21, it would have to represent
           a significant safety hazard and based on the fact that
           the pressure integrity and the structural integrity
           were not affected by the voids, it would not represent
           a significant safety hazard.
                       VICE CHAIR BONACA:  What I'm asking about
           is the design capability, I'm referring specifically
           to what you're committed to in your testing which is
           your testing the containment for your design
           capability which typically is lower, much lower than
           the overall structure -- ultimate capacity.
                       MR. HALE:  Right.
                       VICE CHAIR BONACA:  So the question I had,
           I guess, is that evaluation did not address the
           ultimate capacity.  It addressed the --
                       MR. HALE:  The design capacity.
                       VICE CHAIR BONACA:  Design capacity. 
           Okay.  Just to make that clear.  And so because of
           that, it is now reported under Part 21?
                       MR. HALE:  Right.
                       MEMBER LEITCH:  I have a question about
           your ability to inspect the head as per this recent
           NRC inspection, NRC request, I should say.  There are
           different insulation configurations throughout the
           industry which make it more or less difficult for
           people to get a good look at the head.  What's your
           status as far as that response is concerned?
                       MR. HALE:  Turkey Point, we've completed
           bare metal inspections on both heads.  Unfortunately
           Turkey Point was, if you recall back in 1987, we had
           a leak that we operated with --
                       MR. WILLIAMS:  Excuse me, Steve?
                       MR. HALE:  Yes.
                       MR. WILLIAMS:  Is that the right slide? 
           You've got station blackout up there?
                       MR. HALE:  I'm sorry, I apologize.
                       (Laughter.)
                       I'm sorry, I had a slide for the 
           Davis-Besse.  
                       (Pause.)
                       Excuse me.
                       MEMBER ROSEN:  It's going to be
           interesting to see you tie the two together.
                       (Laughter.)
                       MR. HALE:  All right.  As far as the -- as
           I was saying, Turkey Point had an event with some
           significant leakage in the reactor vessel head area. 
           In fact, it's what prompted 8805.  We had operated, I
           believe, about -- I believe it was about six months
           with a known leak in the reactor vessel.  It was the
           conoseals.  
                       As a result of corrective actions related
           to that, one our insulation configuration was changed
           somewhat to where we had inspection ports. 
           Additionally, we installed a radiation detector that
           actually sniffs the head area and so we can get some
           intelligence, you know, when we get high radiation and
           containment and can help maybe locate whether --
                       MEMBER SHACK:  N-16?
                       MR. HALE:  Pardon?
                       MEMBER SHACK:  N-16s?
                       MR. HALE:  No, it's just radiation
           detector in the head region.  It's in an enclosure, so
           we actually have a -- it's something we did to tell
           us.  And we also instituted some very stringent
           leakage controls.  We require specific evaluation if
           leakage reaches .5 GPM and if needed, we'll actually
           go in and do containment walk downs.
                       So the combination of those things,
           although it was a negative event, I believe has
           created a situation that we're finding and what we did
           is we did a bare metal inspection as a result of
           bulletin in 2001 related to Inconnel 600 on Unit 3 in
           October of 2001 and we also did it in March of 2002. 
           I would also like to point out we were able to do this
           and accommodate it within a normal -- we're doing
           refueling outages in a 25-day type time frame and we
           were able to accomplish this with that.  We used
           remote TV cameras.  I actually went through the report
           evaluation and they addressed each individual nozzles. 
           We've got videos and pictures, but it was clean. 
           There was no evidence of leakage and there was no
           evidence of boric acid accumulations.
                       MEMBER SHACK:  And you can literally do
           100 percent inspection?
                       MR. HALE:  One hundred percent visual. 
           With remote, television cameras and that sort of
           thing.  I believe it was Framatone that's developed
           the -- but it's very detailed.
                       MEMBER ROSEN:  This radiation monitor you
           talk about, is it sampling the environment, the air
           and taking it through a filter and putting it in front
           of a detector?
                       MR. HALE:  Yeah.
                       MEMBER ROSEN:  Now those filters, are
           those looked at?
                       MR. HALE:  Yes.  They're replaced
           periodically.
                       MEMBER ROSEN:  What do you find on the
           filters?
                       MR. HALE:  I'm not sure.  You're asking a
           question that goes beyond --
                       MEMBER ROSEN:  Well, I ask it because 
           Davis- Besse found a lot of iron oxide on their
           filters and they had a similar system.
                       I think you ought to be finding that the
           filters are clean.
                       MR. HALE:  They replace the paper
           periodically because they have to for the monitor
           itself.
                       MEMBER ROSEN:  They take off the paper to
           replace it because they analyze it.
                       MR. HALE:  Yes.
                       MEMBER ROSEN:  But not because it's
           plugged up or anything.
                       MR. HALE:  Yeah.
                       MEMBER ROSEN:  But you don't know?
                       MR. HALE:  No.
                       MEMBER LEITCH:  As a result of your
           operating with the leakage back in the 1980s whenever
           it was, did you find any wastage at that time?
                       MR. HALE:  Not very much, but I think the
           number that was quoted, like I said, I'm reaching here
           was in the hundreds of pounds, had accumulated on
           three of the reactor vessel studs in that stud area,
           so there was some wastage on the studs.  There was no
           real wastage on the head itself, but again, this was
           a conoseal leak.
                       MEMBER LEITCH:  I understand.
                       MR. HALE:  And it was, I believe in the --
           it was within tech specs, but it was just spraying
           over about six months it accumulated boric acid.
                       MEMBER LEITCH:  Okay, thank you.
                       VICE CHAIR BONACA:  Going back a moment to
           the issue of the concrete, what did you do?  How was
           it repaired?  What I am trying to understand is what
           is the condition of the containment right now for both
           units?  I understand you repaired what you found. You
           did not open every part of the containment so you had
           the inspections to identify whether you had other void
           issues?
                       MR. HALE:  Bechtel essentially did a root
           cause on the issue that was discovered.  The root
           cause determined it was a combination of a difficult
           area to get concrete into plus where they had
           established a construction joint.  The repairs that
           were implemented called for -- we were actually
           putting in a heavier steel bottom to the equipment
           hatch to remove the steam generators, so they removed
           that.  They poured the appropriate concrete and they
           put a thicker piece of metal which was the intent all
           along when they had pulled it off and discovered the
           void.  In terms of generic implications, based on the
           root causes that were identified, Bechtel established
           based on that root cause that they wouldn't find
           similar type of areas like that based on that -- and
           so that's documented.
                       VICE CHAIR BONACA:  In other locations of
           your containment?
                       MR. HALE:  Right, right.  And that's
           documented in there.  It was a fairly extensive
           evaluation that they performed to demonstrate that.
                       VICE CHAIR BONACA:  So you do have
           confidence that there are no voids in your
           containment?
                       MEMBER POWERS:  It's an incredibly self-
           serving finding, isn't it, that everything is okay, we
           only made one mistake.
                       VICE CHAIR BONACA:  That's why I'm
           interested in hearing about -- what is interesting is
           that it happened in the hatch of one of the units and
           then they looked at the other one and they found the
           same problem right in the location.  That's why we
           would be raising questions about the generic
           implications for other units.
                       Now so there is a confidence that that was
           the only location in that containment that could have
           been affected by that and it was this position for the
           Turkey Point unit?
                       MR. HALE:  Right.
                       VICE CHAIR BONACA:  Containments.
                       MR. HALE:  And it was also communicated
           with -- communicated and inspected by the region. 
           There was an LER on it.  They came in and looked at
           the Bechtel evaluation as well as the disposition of
           the repairs, so I have confidence.  We've also
           undergone, I think about seven integrated leak rate
           tests on both containments and I have full confidence
           in our containments.
                       MEMBER LEITCH:  We had the same problem
           with Limerick during construction.  I think it was
           Limerick I in about 1977 when the forms were removed
           from the containment pour and this was above one of
           the containment hatches, a large void was found.  It's
           right above the containment hatch.  There was a real
           configuration, complex configuration of rebar in that
           area, but it was a very significant hole.  That was
           also a Bechtel job, by the way, and it was a very
           significant hole.  Were it for the rebar you could
           easily put a Volkswagen and maybe a Cadillac into this
           hole.
                       CHAIRMAN APOSTOLAKIS:  It saved a lot of
           concrete.
                       MEMBER LEITCH:  It saved a lot of
           concrete.  But of course that was self-evident and it
           was all chipped out and replaced.
                       VICE CHAIR BONACA:  Because that was
           visible.
                       MEMBER LEITCH:  Yes.
                       VICE CHAIR BONACA:  I had another question
           regarding another point that Mr. Oncavage raised
           regarding hurricane?
                       MR. HALE:  Yes.
                       VICE CHAIR BONACA:  Capability of the site
           and he presented the fact that he didn't feel that
           Hurricane Andrew was really a category 5 hurricane and
           the ability of the plant to withstand a category 5 and
           you addressed that issue.
                       MR. HALE:  Yes, yes.  In fact, the FSER
           highlights are design capability, the two aspects of
           a hurricane that you're concerned with is wind and
           tidal surge, but with regards to wind design, I think
           you'll find any FSER were designed for 225 miles an
           hour and all the way up to 300 some miles an hour
           without loss of structural integrity.  So we are not
           concerned from -- wind design is not an issue.
                       VICE CHAIR BONACA:  Tidal surge was the
           issue.
                       MR. HALE:  When we look at tidal surge, we
           are designed -- the plant elevation is at 18 feet.  We
           can -- we install stop logs as part of our hurricane
           preps up to 20 feet and all the safety-related
           equipment is located at 22.5 feet.
                       I had some friends that were affected by
           Hurricane Andrew's tidal surge and so I had some
           witness accounts of trucks at the top of their garage
           as the thing came in and hit their house, but I think
           if you look at historical data and that sort of thing,
           22.5 feet is plenty to accommodate any tidal surge
           that could be expected, even for a category 5
           hurricane.
                       VICE CHAIR BONACA:  Thank you.
                       MEMBER POWERS:  Mario, in light of the 
           Davis-Besse events, have inspections for these one-
           time inspections we do for license renewal, have they
           come under question?
                       VICE CHAIR BONACA:  I don't think so. 
           First of all, the components like such as a head are
           really under a different kind of inspection program
           that clearly is not one-time inspection.
                       MEMBER POWERS:  I mean it's the mindset. 
           If you go and inspect something expecting not to find
           it, you frequently don't find things.  And there are
           an awful lot of inspections in license renewal with
           the predisposition not to find anything.  And son of
           a gun, they don't.  
                       VICE CHAIR BONACA:  Yes, if you look at
           the issue or components which are related to the one-
           time inspection, I'm not sure that they are the type
           where your ability to detect would be so challenged. 
           For example, it's erosion, certain components or
           corrosion and so on and so forth.  The presumption is
           that if you do the inspection close to the 40-years
           life and you do it once and you don't find anything,
           then you have -- and the first -- I think there is a
           good provision in the license renewal that says you
           can roll that inspection into your program until you
           find something and it then falls under corrective
           action.  I think it's a good point you are raising. 
           I think you have to be sensitive to that as we look at
           new license renewal applications in the future and see
           what kind of one-time inspection we have, if it is, in
           fact, an obvious thing that you would identify those
           kinds of degradations easily or if your ability to
           detect is being challenged.
                       MEMBER POWERS:  Since we've been talking
           about Turkey Point concrete, I've got to tell the
           Committee at least one anecdote about the Turkey Point
           concrete, but Turkey Point doesn't know.  In 1976, the
           NRC asked me to look at the effects of interactions
           with concrete and they said use prototypic concrete,
           so I said well, what's prototypic concrete?  I decided
           the FSARs probably had prototypic concrete described
           in them, so I went to our library attendee and asked
           him for an FSAR and they handed me a box of
           microfiche, all jumbled together and they said these
           are all the FSARs.  So I went to sorting them out and
           the first one I sorted out so it was reasonably
           complete was Turkey Point and Turkey Point's FSAR has
           an excellent description of their concrete and I used
           that description of the concrete to create the
           concrete I was doing and since I wrote it down
           everybody else just used that as the specification and
           as far as I know every melt concrete experiment that's
           ever been sponsored by the NRC has used Turkey Point's
           concrete description.
                       (Laughter.)
                       Sand size.  I believe your aggregate is
           oolite.  I had to figure out what oolite was.  And I
           know more about the Southeastern United States geology
           than I ever cared to learn trying to understand what
           oolite is.
                       MR. HALE:  Any more questions for me?
                       VICE CHAIR BONACA:  I don't think so. 
           Thank you for the presentation.  It was very
           informative.  We'll hear from the Staff and the SER.
                       MR. KUO:  Yes.  I will call on Mr. Raj
           Auluck, the Project Manager for the Turkey Point
           license renewal application review and his panel.
                       MR. CHRISTIANSON:  Nuclear Regulatory
           Commission, Chris Christianson speaking, may I help
           you?
                       MR. AULUCK:  Chris?
                       MR. CHRISTIANSON:  Yes.
                       MR. AULUCK:  Raj Auluck.
                       MR. CHRISTIANSON:  Hi, Raj.
                       MR. AULUCK:  Hi.  We are just starting in
           a couple of places and I just wanted to make sure you
           are on the line.
                       MR. CHRISTIANSON:  Okay.
                       (Pause.)
                       VICE CHAIR BONACA:  Be aware we have about
           45 minutes left for the meeting, including
           discussions, so I leave it up to you to be --
                       MR. AULUCK:  Okay.  Good morning.  I am
           Raj Auluck, Project Manager for the Turkey Point
           license renewal application review.  With me around
           the table is Jim Medoff.  He's from Division of
           Engineering and helping us so he'll assist me on a
           couple of the slides.  Then we have some people from
           the technical division, Jim Lazeunick from electrical. 
           And they will discuss some of the issues which were
           especially asked by the Subcommittee during our
           meeting last week.  Hans Ashar from Mechanical
           Engineering and Barry Elliott from Materials.
                       The purpose of today's meeting is to
           present the staff's review -- Chris, are you there?
                       (Pause.)
                       Chris?
                       MR. CHRISTIANSON:  I'm here.
                       MR. AULUCK:  I forgot to introduce Chris
           Christianson.  He's the Branch Chief, Region 2 and
           he'll be helping us respond to some of the questions
           you have on the inspections or the allegations.
                       I will describe the resolution of the open
           items and the basis upon which we'll move forward to
           make a recommendation to the Commission on this
           application.
                       The application was received 18 months
           back, 19 months today exactly.  This was the firth
           application received by the NRC.  Four have already
           been approved.  This is the first Westinghouse.  It is
           two-unit site.  Each is designed for 2300 megawatt
           thermal.  The site is shared by two oil and gas fired
           generating units in Florida City about 25 minutes from
           the Miami, south of Miami.
                       Unit 3 license expires on July 19, 2012
           and for Unit 4, on April 4, 2013.  The application is
           for two years' extension.
                       The review schedule originally issued with
           an acceptance letter.  As you can see, the next --
           that line is completing the SERS briefing and
           preparing the Commission paper with the recommendation
           on middle of next month.  
                       The final SER was issued on February 27th
           and final environmental impact statement was issued on
           January 15th of this year.
                       MEMBER LEITCH:  I have a question
           regarding the length of the extension.  I read that
           the PTS value is very close to the allowable 300
           degrees.  It's 297.4.  And it's stated that that would
           be okay because that was the value, I guess after 48
           effective full-power years.  Now we're extending this
           to 60 years.  Is it mathematically impossible to get
           a number in excess of 48, full-power years, or is
           there some kind of a caveat that says 60, but no more
           than 48, effective full-power years?
                       MR. ELLIOTT:  Well, you could get 48
           effective full-power years corresponds to 60 years at
           80 percent capacity factor.  The plant could run
           higher than that and therefore it would exceed the --
           before it reached 60 years it would exceed 48
           effective full-power years.  But it's not the 48
           effective full-power years.  It's the critical factor
           here.  It's the neutron effluents received by the
           vessel and that's the critical factor and that's what
           they have to monitor to determine whether or not
           they're going to exceed the PTS screening criteria. 
           As long as they monitor the neutron effluents and they
           stay below their projections, they'll stay below the
           screening criteria.  According to the PTS rule, if
           they start exceeding the effluents values they 
           projected, they're required to do another projection
           of where they'll be with respect to the PTS rule.  So
           it's within the PTS rule there is a flexibility.
                       MEMBER LEITCH:  Okay, so there is no
           limitation then at 48 effective full-power --
                       MR. ELLIOTT:  No, it isn't 48 effective
           full power.  It's the neutron effluents.
                       MEMBER LEITCH:  And even although they go
           above -- if they went above 48 effective full-power
           years, presumably they'd be crowding that 300 degree
           --
                       MR. ELLIOTT:  They would have to tell us
           the impact on the neutron effluents for the vessel and
           then from that they would have to project the RPTS
           value to determine whether or not they're still below
           the screening criteria at end of license to extend the
           license.
                       MR. MEDOFF:  Barry, may I add something?
                       MR. ELLIOTT:  Sure.  
                       MR. MEDOFF:  I would like to add that in
           a reassignment they do exceed the screening criteria,
           the rule is written to require the licensee to take
           appropriate action including flux reductions and/or
           annealing of the reactor vessel.  So the rule does
           incorporate corrective action should those screening
           criteria be exceeded.
                       MEMBER LEITCH:  Okay, thank you.
                       MR. AULUCK:  Continuing, we'll start with
           how we reviewed the application.  There are two 
           self-regulatory requirements that govern the review of
           any license renewal application.  First is Part 54,
           the NRC staff conducts the technical review of the
           license renewal application to assure public health
           and safety requirements.  A second is Part 51, then as
           the staff completes routine review of the license
           renewal application, focusing on the potential impacts
           of additional 20 years of plant operation.  Now there
           are many programs which are routinely monitored and
           assessed plant operations, but the license renewal
           review focuses only on those which has the potential
           detrimental effects of aging and not addressed
           routinely by on-going programs.
                       Part 54 requires the Applicants who
           demonstrate how these programs will be effective in
           managing the aging process during the extended period. 
           Now staff's review consisted on reviewing of the
           Applicants' scoping and screening methodology, review
           of the aging management programs and review of the
           time limited aging analysis identified by the
           Applicant.  These reviews are supplemented by the site
           audits and inspections by the NRC staff.  There was
           one site audit done on this site and two inspections
           governing scoping, screening, aging and management
           reviews.  Scoping and screening methodology review was
           done in two parts.  And the first one is a desk top
           review which is basically initial review of the
           application supporting information and second is the
           on-site audit with a team of headquarters' staffs and
           regional participants in the review of the on-site
           documentation, review of the selected engineering
           reports, engineering procedures, design documentation
           and discussion with engineering staff.  
                       Incidentally, it was during this audit
           first done early in the review process which was in
           this case November of 2000 when the staff raised the
           issue of interaction of nonsafety systems, structures
           and components with the safety systems, structures and
           components.  And then later on this turned out to be
           one of the open items in the SER.
                       We had several discussions with the
           Applicant on this issue.  Now this Part 54.29
           describes the standards which must be met before the
           Committee issues a renewed license.  We have talked a
           little bit already about the first two items on the
           slide.  The last one relates to hearing and
           intervention on the license renewal application. 
           There was no hearing on this application.  There were
           two requests filed for -- filed to petition to
           intervene and request for hearing.  On January 18,
           2001, the Atomic Safety and Licensing Board Panel had
           a pre-hearing conference in Homestead, Florida to hear
           on the petitioner's standing and the admissability of
           their preferred contentions.  In the order issued on
           February 26, the Board ruled that all -- both parties
           have standing to intervene.  Neither petitioner
           proffered admissible contentions, so their
           intervention petitions therefore, must be denied.
                       The Board ruled that these contentions
           raise issues that fall beyond the scope of license
           renewal and renewal proceedings.  And on March 19th,
           one of the petitioners -- he appealed the decision to
           the Commission.  On July 19, 2001, the Commission
           issued an order affirming the Board's decision.
                       We have participated in several industry
           groups on license renewal including Westinghouse
           Owners Group and for that developed series of generic
           reports intended to demonstrate that aging effects
           will be properly managed.  At the Subcommittee, they
           asked us as a staff to make a specific presentation on
           these reports and how staff intends to use them.
                       Barry?
                       MR. ELLIOTT:  Yes, Barry Elliott,
           Materials and Chemical Engineering.  The staff has
           reviewed all these WCAPs.  The first four, in
           particular, are license renewal documents in which the
           Westinghouse Owners Group has done an aging management
           review to determine the aging effects for the
           components that are listed in the titles there for the
           reports and they listed the aging effects for the
           components and the aging management programs that we
           used to manage those aging effects.  The staff has
           written safety evaluations for each one of those and
           they've identified license renewal Applicant action
           items.
                       As far as Turkey Point is concerned, the
           staff was a little late in its safety evaluation, so
           they couldn't reference the actual staff evaluations
           in their report, so they wrote how their components
           fit the report and it was during the RAI process, the
           Applicant addressed the license renewal action items
           and the staff reviewed those and found those
           satisfactory.
                       Those first four reports were discussed in
           detail at the Subcommittee meeting. The fifth item
           which is the WCAP-15338 deals with the time limit
           aging analysis for underclad cracks, specifically it
           has to do with reactor vessel forgings that were
           fabricated using a course screen, a head treatment and
           fabrication process and where the clad was applied
           with high heat input.  
                       This is in BWR and in Westinghouse plants
           and we've had two topical reports on this.  This is an
           extension of a review that the staff did in the 1970s
           on this issue and what they've basically done here,
           Westinghouse, is extended the review that they did in
           the 1970s using 1990's technology and information. 
           They've updated the analysis for new technology, new
           information and also extended it for 60 years.
                       These are very small flaws on the order of
           10 7-inch, the largest in-depth, the largest we've
           ever seen is like 3/10ths of an inch.  The run in
           length from a tenth of an inch to like two inches. 
           Very difficult to detect with ultrasonics.  Therefore,
           we're relying on the analysis to assure vessel
           integrity.
                       The amount of floor growth here from
           fatigue is very, very small.  In sixty years, it's
           less than a tenth of an inch.  We don't expect any
           growth from stress corrosion or a very small amount of
           growth from stress corrosion, cracking.  This is borne
           out by the recent event this summer where the crack
           grew through the weld, reached the ferritic component
           and stopped.  The allowable flaw size for this is much
           larger than the 3/10ths of an inch on the order of one
           in three tenths or one in four tenths of an inch.  So
           there's a large margin here and for that reason
           there's no real concern about these cracks for license
           renewal.
                       VICE CHAIR BONACA:  So this WCAP actually
           was used to address one of the open items, right, the
           underclad?
                       MR. ELLIOTT:  They're required, licensees
           are required to identify time limit aging analysis. 
           There's criteria in the rule.  This would be one of
           them and this was used to address that requirement.
                       VICE CHAIR BONACA:  The reason I'm asking
           is that the first four were reviewed, but they were
           not referenced into the application.
                       MR. ELLIOTT:  Right.
                       VICE CHAIR BONACA:  Although for the fifth
           one, the review was completed before the open item was
           addressed.  So I think it was credited for.
                       MR. ELLIOTT:  The fifth one was credited
           for.
                       MR. AULUCK:  That's correct.  The
           Commission appeal prepared many internal license
           renewal documents under the QA program for use in the
           preparation of the application and training of their
           staff members.  The NRC staff reviewed selected
           portion of these documents during our site audit and
           scoping AMR instructions.  According to the Applicant,
           they had several discussions with the previous
           applicants and reviewed previously issued RAIs and had
           other experts look at the application.
                       In summary, the staff generated about 215
           requests for additional information on this
           application which was at that time substantially less
           than the previous ones of 300 to 400.  And as I
           understand, the number is going down, which is
           expected as the experience, the quality and clarity of
           the application is improving.
                       As part of this review, the staff review
           issued four open items in the draft SER in August of
           2001.  The first one was seismic II over I interaction
           of nonseismic safety-related piping because 
           safety-related structures and components are known as
           seismic II over I.  This was the same one that was
           identified early in the review process, but at that
           time the staff was in discussion with the Applicant to
           resolve the issue so we asked the FPL to just wait
           until the resolution is reached on the application and
           the staff position will be issued and then they can
           address that issue.  So in the meantime the SER time
           came, so we issued the SER with open items.
                       And I think basically, the Applicant has
           gone over the criteria of selecting which portion of
           the piping was not included in the first time and then
           included later on.  All I'd like to add here is since
           that time, the staff has issued two positions on this
           issue.  First one is seismic II over I which was a
           narrow scope of nonsafety-related piping closely
           related to the safety-related piping.  The second
           position which is broader in scope, it relates to all
           nonsafety-related piping and components.  I think in
           the future, the staff intends to work with industry to
           make it an issue to combine the two positions into
           one.
                       The second open item is -- it relates to
           the field-erected tanks internal inspection.  The
           reason it was an open item during the SER stage was it
           was a new program and the Applicant had not addressed
           all the attributes identified in our process, so we
           asked the specific questions in the RAI and the
           Applicant said it's applicable to five tanks, two
           condensate storage tanks, two refueling water storage
           tanks and one shared demineralized water storage tank. 
           The Applicant responded in late fall and the response
           was unacceptable.  So this item was considered closed.
                       The next item relates to Reactor Vessel
           Head Alloy 600 penetration program and Jim Medoff, who
           was the lead reviewer for this issue when he was in
           Division of Engineering, he will speak.
                       MR. MEDOFF:  Good morning, I'm Jim Medoff. 
           I'm acting as a backup project manager for the Turkey
           Point license renewal application.  
                       Prior to my rotation to the License
           Renewal Environmental Impacts Program I acted as a
           materials engineer for the Materials and Chemical
           Engineering Branch.  Part of my responsibilities in
           that branch included the review of the Reactor Vessel
           Head Alloy 600 Penetration Inspection Program.  
                       Basically what I need to say about the
           program is that the license renewal application was
           submitted prior to the issuance of NRC Bulletin 
           2001-01 which was the bulletin written on the Oconee
           circumferential cracking that they detected in a
           number of their penetration nozzles in a couple of
           their units.  We issued an open item to address
           whether the inspection program for the penetration
           nozzles was current with bulletin and whether the --
           and whether they were going to update the program to
           include the bulletin and FPL's responses to the
           bulletin and any changes to the inspection program
           that might needed to result from the program.
                       When the Applicant's response to the open
           item came in, we not only reviewed that, but we also,
           the Applicant referenced the bulletin and we looked at
           the bulletin response as well.  Our review of the
           responses to both the open item and the bulletin
           indicate that FPL is committing to continue
           participation in the industry-wide program for
           inspection of vessel head penetration nozzles and to
           update this program as necessary based on industry
           experience and any further studies that the MRP or
           EPRI might conduct regarding vessel head integrity
           issues.
                       Their response to Bulletin 2001-01
           provided revised rankings for the plants and indicated
           that they were going to do bare-head inspections of
           both Unit 3 and Unit 4 vessel heads.  FPL has
           completed both inspections and has not detected any
           visual signs of leakage or boric acids on the vessel
           heads for the units.  I will say since Davis-Besse has
           been brought up that the NRC issued Bulletin 2002-01
           to address the Davis-Besse issue and the impact on
           vessel head penetrations in pressurized water reactors
           in the industry and that FPL has provided its response
           to this bulletin.  The response further indicates
           FPL's commitment to participate in the program and
           update the program as necessary based on inspection
           results.
                       The next open item deals with reactor
           pressure vessel underclad cracking.  I'm not going to
           talk in depth on this because Barry has just addressed
           what the contents of the WCAP were and the technical
           details of the issue of underclad cracking.
                       What I will say is that when the NRC
           issued the safety evaluation on the topical report,
           they required two things.  One was for three-loop
           plants of which the Turkey Point units are three-loop
           plants.  They wanted the Applicants to indicate
           whether the number of design cycles for the transients
           assumed in the topical report bounds the number of
           cycles for 60 years of operation in terms of -- we're
           talking in terms of fatigue analysis for growth of
           cracks.
                       The second item that the safety evaluation
           indicated was that Applicants referencing the topical
           reports as being applicable to their facilities would
           need to ensure that the TLAA for the valuation of the
           underclad cracks was summarily described in the FSAR
           supplement for their application.  
                       FPL submitted responses to the RAIs
           relative to both of the action items so we decided
           that the FPL took appropriate action and closed the
           open item up.
                       MR. AULUCK:  As you recall the
           Subcommittee meeting, one of the items discussed was
           station blackout and staff was asked how we are
           addressing that at Turkey Point.  At that time we had
           stated that the issue is the position has not been
           finalized and when it is finalized it will be
           addressed like any other -- addressed by plants
           previously relicensed.  Since then, the staff position
           has changed the final position on that station
           blackout was issued on April 1 and at that time they
           decided since the position has been issued, this must
           be addressed by the Applicant on this application
           prior to issuing the license, relicense.  So we
           communicated this issue to the Applicant the following
           day and since that time we are having meetings, we had
           a public meeting yesterday. We're trying to resolve
           the issue from the perspective that certain components
           from the off-site power to the plant should be
           included as part of the license renewal.  
                       VICE CHAIR BONACA:  This is a change from
           the discussion we had.
                       MR. AULUCK:  This is a change from the
           discussion we had before and that -- so our intent
           here is to resolve the issue and still meet the
           schedule date of sending the recommendation to the
           Commission.  What we are thinking is we'll issue --
           the FSAR has been issued with all items addressed.  It
           will go to the printers at the end of this month, but
           we are in parallel, we'll be preparing a supplement to
           the SER addressing, focusing on the station blackout
           issue and our intent is to complete that in the time
           frame.
                       VICE CHAIR BONACA:  Okay, let me just for
           the benefit of the members who were not at the meeting
           at Turkey Point, the issue here is that there is a
           preferred station blackout recovery path and the
           guidance the NRC provided us before the meeting said
           essentially that that would include all the equipment
           that collects to off-site power.  That includes all
           the equipment that collects to off-site power.  That
           includes, for example, the start-up transformers which
           the Applicant has not included in the scope of license
           renewal.
                       And the Applicant made the case that they
           did not rely on off-site power for recovery from
           station blackout and demonstrated to us that they can
           connect one unit to the diesel generators of the other
           units and one diesel generator out of four is capable
           of carrying all the loads for both units in case of a
           station blackout.  They also pointed out that the
           experience from the Hurricane Andrew that that was, in
           fact, providing for them the most reliable source and
           they used it for that particular situation.
                       Our understanding up to now is that, in
           fact, that was the way of Turkey Point to address the
           license renewal commitments.  Now so irrespective of
           that, the staff is asking that Turkey Point includes
           all the collection to the off-site power?
                       MR. AULUCK:  Yes, that's why --
                       VICE CHAIR BONACA:  This is a change to
           SER that we have in front of us?
                       MR. AULUCK:  That's why we're going to
           issue a supplement to the SER and we hope to issue
           that shortly, address this issue.  Jim Lazevnick from
           Electrical will speak on this.
                       MR. LAZEVNICK:  Yes, the Turkey Point has
           an alternate AC power source as a means of coping with
           the station blackout and essentially the point of
           disagreement is whether that source is capable of
           recovering from a station blackout.  In order to
           recover from a station blackout, each plant has to
           develop a coping duration based on total loss of all
           AC power at the plant and the duration for Turkey
           Point was determined to be eight hours and they
           utilize an alternate AC source to demonstrate that the
           plant could cope for that period of eight hours. 
           These sources may have capability beyond eight hours,
           but the staff has not reviewed them to see if they, in
           fact, have that capability and the original
           requirements of the station blackout rule, the
           definition of an alternate AC source did not address
           that capability.  It spoke of the alternate AC source
           being a means to cope with station blackout for the
           period of the coping duration.
                       So based on other requirements in the
           station blackout rule, specifically Section 10 CFR
           50.63(a)(1), the coping duration itself is based on
           four factors and one of those factors is the probable
           time needed to recover off-site power at the site.  
                       The four factors that licensees use to
           determine the specific required coping duration at
           their plant was developed into licensee guidance and
           this guidance was included in NRC Regulatory Guide
           1.155 and an industry document that the NRC worked on
           the industry with which was NUMARC 87-00.  
                       And all the licensees essentially utilizes
           a guidance to determine their coping duration,
           relative to license renewal and age-related failures,
           it's our view that unless we control a portion of that
           off-site power system in terms of age-related
           failures, the licensee potentially might need a longer
           required coping duration if those age-related failures
           were not properly controlled and addressed under the
           license renewal rule. 
                       Our final position on this has been that
           the off-site power circuits between the switchyard and
           the safety buses should be included within the scope
           of license renewal.  We recognize that the off-site
           power system actually is a source that the power
           source that extends all the way into the transmission
           system of the United States.  We feel that this
           interface, this portion of the circuitry is an
           appropriate part to be included within license renewal
           because it's the portion of the off-site power circuit
           that feeds the plant and essentially has requirements
           only in the plant.  It has no transmission system type
           requirements associated with this portion of the
           circuit.
                       VICE CHAIR BONACA:  So this says we have
           SER with one open item.
                       MR. AULUCK:  Out of this stage, right, and
           we met with them and there is agreement, close to an
           agreement.  We have looked at the draft response and
           the Applicant believes they can finalize their
           response in the next couple of days and we have agreed

           to work with the Applicant and issue the supplement as
           soon as possible.
                       VICE CHAIR BONACA:  Well, we should hear
           from the Applicant what the Applicant thinks.  They
           made a case for us and they made a demonstration of
           what they consider the ultimate power supply and as
           far as our review was concerned, we asked questions
           specifically about a standard for transformers in
           October and the answer was they are not in scope.  And
           so I would like to hear what's happening there.
                       MR. HALE:  We still do not agree with the
           staff position.  We had long discussions with the
           staff yesterday.  We understand what their position
           is.  We have nothing but confidence in the capability
           of our system and I think we demonstrated that for you
           at the simulator.  But we understand what the staff
           position is.  We have spent the last two weeks, I
           guess week and a half, based on being informed by the
           staff what their position was and that they had
           finalized it.  So we have put together a response,
           draft response which they've highlighted the
           additional equipment.  There's not a lot of equipment
           involved based on the boundaries that the staff is
           proposing.  They're basically calling for the breakers
           and the switchyard that feeds the start-up
           transformer, the start-up transformer itself and the
           feed into the 4160 switchgear.
                       VICE CHAIR BONACA:  Which I'm sure you
           consistently maintained?
                       MR. HALE:  Yes, this equipment is
           maintained under the maintenance rule because the
           maintenance rule scoping criteria goes beyond our --
           is different than license renewal.  The maintenance
           rule considers things as trip hazards and that sort of
           thing.  So this equipment is inspected under the
           maintenance rule, but base don our interpretation and
           our CLE documents which include our safety evaluation
           report, on-station blackout which we reviewed in
           detail as well as our design basis documents and our
           FSAR, we cannot find where we've specifically credited
           restoration of off-site power, but we understand the
           staff position.  We think we're somewhat unique in
           that we have fully capable diesels.  In fact, we have
           over 400 KW, 300 to 400 KW of excess capacity of a
           single diesel, so it's their position.  That's the way
           they've interpreted it.  They've issued it formal and
           so we've issued a response to address the specific
           requirements --
                       VICE CHAIR BONACA:  So you have already
           issued a response?
                       MR. HALE:  A draft response.  They are
           reviewing it.  Once we factor in their comments, we
           will issue it formal probably within the next week.
                       VICE CHAIR BONACA:  Any other questions
           for Steve?
           Thank you.
                       MR. AULUCK:  Continuing, in February of
           this year, a public citizen, Mr. Oncavage, sent a
           letter to the ACRS identifying four safety concerns. 
           The first one relates to the effects of wires on
           aging, degradation rates and structural integrity of
           the containment structures at Turkey Point.  At the
           Subcommittee, we discussed this issue and you asked
           the staff to make a presentation as it may apply to
           some generic implications to the other plants.
                       Before Mr. Hans Ashar will speak on that,
           before he starts, I'd like to go a little bit of when
           the issue was first raised and what has happened since
           that time.
                       The issue was first raised by Mr. Oncavage
           at one of our exit meetings.  We had gone for
           inspection there and at the exit we provided the
           results at a public meeting and Mr. Oncavage raised
           this issue that he understands there was some voids
           formed at Turkey Point containment during 1980s when
           during the steam generator replacement process.  So at
           the meeting, the Region took this, considered this as
           an allegation and gave us a tracking number.  
                       And then they asked the Applicant forward
           the concern to the Applicant to respond to the NRC. 
           The Applicant responded with information to the NRC
           and on August 10, Region II sent a letter to Mr.
           Oncavage summarizing the results of the review.
                       But then in December 15th, he sent another
           letter to the Region stating that he's not satisfied
           with the results of the August 10 letter and NRC
           should ask FPL to start testing, looking for voids in
           the containment.
                       Region II informed Mr. Oncavage,
           acknowledging the December 15th letter and stating
           that they will respond to him after reviewing the
           material again.  So on April 5th, last week, a formal
           response was issued to Mr. Oncavage, summarizing the
           review, independent review by the NRC staff and the
           inspection reports, other documents.  Thus Region II
           considers this issue to be closed for Turkey Point.
                       Now Mr. Hans Ashar will speak on the
           general implications.
                       VICE CHAIR BONACA:  Now I imagine that the
           issue was closed for Turkey Point because the two
           identified voids were filled and those inspections
           were filled in the containment or was it simply some
           statement that said we don't expect to find any more?
                       MR. AULUCK:  I think it was review of
           other technical documents at the site and there was a
           technical member from Region II, went and spent a week
           there, earlier this year to review all the reports and
           results and discussions with them.
                       MR. ASHAR:  I am Hans Ashar --
                       MR. GILLESPIE:  Excuse me, Mario, if we
           could close this out because I know one of your
           concerns was documenting the stuff that was done. 
           Since we have Region II on the phone, if a person went
           to the site that means some place there's an
           inspection report which documents what he did.  Is it
           possible to get that inspection report to the
           Committee?
                       VICE CHAIR BONACA:  Chris?  Chris, are you
           there?
                       MR. CHRISTIANSON:  Hello, this is Chris
           Christianson, Deputy Director, Division of Reactor
           Safety.
                       VICE CHAIR BONACA:  Did you hear the
           question?
                       MR. CHRISTIANSON:  Is there a possibility
           to get a copy of the inspection report?  We did not
           document this in an inspection report.  We documented
           this as a memo to file in the allegation folder.
                       MR. GILLESPIE:  Okay, it's still the same
           question.  Is it possible to get a copy of that,
           Chris?
                       MR. CHRISTIANSON:  Mr. Auluck can forward
           it on to the appropriate person.
                       MR. GILLESPIE:  Okay, we'll contact you 
           off-line, Chris, and we'll get a copy of it and get it
           to the right people on the Committee and that might
           provide some closure to the issue for Turkey Point and
           that might be beneficial.
                       VICE CHAIR BONACA:  Yes, just to
           understand what was done to assure the issues of
           concerns with additional voids in the containment was
           properly addressed.
                       Thank you.
                       MR. DURAISWAMY:  Mario.  Raj, you sent
           another letter to Oncavage on April 5th?
                       MR. AULUCK:  Yes.
                       MR. DURAISWAMY:  From here?  From the head
           office?
                       MR. AULUCK:  No, from the Region.
                       MR. DURAISWAMY:  From the Region.
                       MR. AULUCK:  Because Region II considered
           the December 5th letter from Mr. Oncavage as the end
           of the follow-up allegation.
                       MR. DURAISWAMY:  Yes.
                       MR. AULUCK:  So they tracked it and they
           responded to that to him and just closing the loop. 
           The letter is April 5th from Region II to Mr.
           Oncavage.
                       MR. DURAISWAMY:  You guys don't have a
           copy of that thing?
                       MR. AULUCK:  Those are allegations --
                       MR. DURAISWAMY:  I know what the
           allegation is.
                       MR. LAZEVNICK:  I think I have copies of
           it.
                       MR. AULUCK:  They can be made available.
                       MR. GILLESPIE:  This is why I say when you
           put stuff in the allegation system, it's a very closed
           system, even though this individual didn't ask to be
           treated that way and so we can deal with it and get
           you copies of it.
                       VICE CHAIR BONACA:  But before the
           allegation issue, there was a finding, was an open
           finding.  There was an evaluation being done.  There
           was a response by Bechtel.  There were people that
           came in with concrete and poured it to fill those --
           I mean there were things that took place and in
           addition to that, if anybody had any question, they
           would have looked someone else to find are there other
           voids.  That's -- I would expect there would be some
           documentation that says yes, we did the following
           steps and then the committee can review it and feel
           confident that something was done that we can state
           today those containments were taken care of and there
           are no voids in containments to the best of our
           knowledge within the limitation of detection and so
           on.  It's not only the file on the allegation, it's
           just simply the paper trail that led to the
           documentation of the actions taken to deal with the
           voids.
                       MR. GILLESPIE:  And I'm hoping a memo to
           file actually references it reviewed this, reviewed
           that and then when you get those things, those things
           contain the subject matter and address these actions.
                       I'm just not sure having not seen the file
           how it strings it together, but that's -- the starting
           point, I hope would be the memo to file where they
           said okay, we reviewed all the existing information
           and existing actions taken to date and it appears to
           be satisfactory and I hope there's some reference to
           what those other documents were so we have a -- we
           should have the trail.  It's just it's in a system no
           one has easy access to.  So we'll take back the idea
           of working with Region II and copying the paper trail
           and trying to get it to you in the very near future
           here.
                       VICE CHAIR BONACA:  We asked for those in
           Florida City.  We asked for -- so that -- and Region
           II was there, present during the meeting and when we
           asked for this information.
                       MR. GILLESPIE:  Yes, because if this was
           followed up in the 1980s and there was an inspection
           report from the 1980s, I'm hoping that research was
           done that we can just pull it together in this one
           memo to file was kind of the cap on top of that
           review.
                       MR. HALE:  Dr. Bonaca, this is Steve Hale,
           Florida Power and Light, we interfaced with the
           regional -- the fellow that came down to do the
           investigation.  There were LERs on this event.  There
           was initial LER plus supplements.  There was also two
           inspection reports which documented the closure of
           those two LERs and the individual came to the site,
           looked at that information.  So I think this memo to
           file or whatever should have all the specific
           documents, but I can tell you for sure because we were
           supporting him and he went in and actually was looking
           at the original pours, concrete pours documentation on
           the testing that was performed on that concrete, so he
           did a very exhaustive investigation, just based on the
           interfaced we had with the fellow when he was at the
           site.  
                       VICE CHAIR BONACA:  Okay, so we'll see for
           this.
                       MR. ASHAR:  I am Hans Ashar from
           Mechanical, NRR.  I had read your transcripts of my
           tech. team and concerns expressed by various members
           of the SEI subcommittee and based on that, I want to
           address only the generic implication at this time as
           to what I think about it because we had a very short
           time to prepare for any in-depth research, but I'll
           try to tell you as much as I can gather from my own
           experience as well as other people's input into what
           I thought.  
                       Now first thing, what I want to refer to
           is are the worse possible.  First thing I want to
           emphasize is this, that having voids in concrete
           construction, in general, there is commercial
           application at nuclear power plant is not an
           acceptable way of constructing any structure.  It is
           not an acceptable matter.  People try very hard to
           make sure that the concrete that they pour is being
           consolidated very well through vibrators and the
           construction joints are being formed in such a way
           that this kind of voids can be avoided.
                       I also would like to let you know that it
           is possible, it is possible that some of the plants
           may have existing concrete voids.  Now my own
           experience, when I was a specification engineer at
           Burns and Roe and I was at Three Mile Island, Unit 2,
           and at that time we heard about voids in ring guard at
           Three Mile Island, Unit 1 and the United Engineers
           Construction was the constructor on that one and their
           engineer had found the voids and they took corrective
           action after that.  So what I would like to emphasize
           here is that the way the quality control, quality
           assurance works in the industry and it worked at that
           time, at least, I know because ACRS had very strict
           quality assurance criteria.  It had been in force
           because people wanted to keep their license and so
           there were attempts being made to award this kind of
           work being persistence in nuclear power plant
           structures.
                       Now somebody might say that that means
           that there are no voids in it.  I wouldn't say so.  I
           thin in spite of all the precautions there could be
           sometimes back down in some other thing, like a
           concrete venting plant, the pumping of the concrete,
           the vibratory spin work on the particular areas, voids
           might be there in some of the plants.  Okay?
                       Now as I said before, core requirements
           require concrete voids -- impact of voids.  What could
           happen to the containment if there are voids present? 
           Now in a very narrow way I would say there will be a
           reduction in thickness of the thick part of the
           sections of concrete.
                       MEMBER POWERS:  Before you go on to the
           impact, your slide says voids can occur where
           vibrators can't reach.
                       MR. ASHAR:  This is why I explain to you
           in much more depth is to what are the factors that can
           influence the existence of voids.
                       MEMBER POWERS:  There are many other
           causes of voids.
                       MR. ASHAR:  Please?
                       MEMBER POWERS:  There are many other
           causes of voids in the concrete.
                       MR. ASHAR:  Yes.  Well, in order to avoid
           voids in concrete construction, in general, the first
           thing to make sure that the construction joints that
           they are going to put in are in the right place, so
           that you can ensure that the oldest areas, very older
           concrete are accessible from the formwork.  And the
           vibrators can reach into those areas.  These are the
           items being made all the time.  As I told you in my
           experience, the voids were in the ring girder of the
           containment construction and the ring girder is a very
           thick area.  It is a liner plate coming down and again
           the voids were in the area of the liner plate was
           touching the concrete area.  But they took out all the
           concrete.  They rehashed everything.  They put new
           concrete in there to make sure there are no voids
           existing in that particular instance.
                       The other two you heard about were the
           Turkey Point and Limerick.  So yeah, voids can occur
           in various places and due to various reasons.
                       MEMBER POWERS:  I mean what I'm struggling
           with here is for this particular instance, you got an
           individual saying there are voids in the concrete. 
           How do you know there are not voids elsewhere?  The
           guy that placed -- the architect/engineer went in and
           said yeah, there were voids in this concrete and
           here's how we explain them.  He said it's because the
           vibrators didn't get there.  That seems very
           convenient to me.
                       MR. ASHAR:  Well, it explained to you.  I
           put one bullet, vibrators can't reach.  It is not the
           only thing, okay?  But the basic thing is to make sure
           that the old areas to be concreted out are filled up
           with concrete to make sure of that.  And then to
           consolidate the vibrators to beat the -- now sometimes
           it can happen, the water may be a little higher or the
           weather might be such that the water can bleed.  When
           it bleeds what happens the calcium hydroxide from
           concrete gets into that area instead of filling of
           with full concrete and integrate.  Only the water
           part, calcium hydroxide stays in that area and it
           would look like you filled up the things.  As the time
           goes by that water starts evaporating and the void
           forms.
                       So those things are possibilities.  I
           would not completely --
                       MEMBER POWERS:  What I'm trying to
           understand is the firm went in and they came up with
           a hypothesis of why they had a void in Turkey Point. 
           It was very convenient and it would not be something

           that would extend out of places in the containment. 
           What did the staff do to look and see if there was
           alternate explanations for this?
                       MR. ASHAR:  Well, I will ask open forum
           for other people to answer to this particular
           question.  As I said, the construction practice during
           that time, the time this plant was being built were
           such and the quality assurance requirements were very
           stringent because I know from my own experience on
           this side of the fence I was not with NRC.  I was with
           consultants and at that time, as a matter of fact,
           after I heard about that void and the cause for those
           voids, I wrote my specification for Three Mile Island,
           Unit 2 in such a way -- as a matter of fact, it is not
           very common for a specification writer to write about
           where the constructors would put their construction
           joints.  
                       But in our case, we did write it.  Okay,
           because we were concerned about the voids in
           construction of Three Mile Island, Unit 2.  That's why
           -- so people --
                       MR. GILLESPIE:  Dana, let me see if we can
           put our package of documentation together.  I think
           this is getting to the point where it may deserve a
           different -- I'm going to suggest a separate meeting.
                       VICE CHAIR BONACA:  The other point I
           would like to meet, we are here now, general
           considerations here.  I think that is on the right
           track.  The issue is you find a void under the hatch
           in concrete.  So now you say well, let's see if this
           is just one of a chance and you go to the next
           containment and you find you have a void in the same
           spot.  
                       And this seems to be almost like it's a
           design feature for this kind of containment, I guess. 
           It's present in two, let's see how many you've got
           where you have a spot.  I think you would want to go
           beyond.  Now typically, you have mechanisms by which
           you raise an issue that could be, I thought, would be
           Part 21, but Bechtel says oh, it's okay, the
           containment is too capable, so it's under Part 21. 
           I'm sure there was a paper trail by which the issue,
           the potential impact of being a generic issue was
           evaluated.  I mean normally the agency is very
           aggressive in pursuing these kind of issues.  That's
           why we've been looking for how did we address, how do
           we get confidence that other containments of Bechtel
           design do not have the same voids in the same location
           and other containments in general do not have that. 
           And that is really what we're looking for when we
           asked for that information in March down in Florida
           City.  And we really haven't gotten the information.
                       MR. GILLESPIE:  And I think that's exactly
           what we need to pull together.  Because now we're all
           trying to project what happened in the mid-1980s.
                       VICE CHAIR BONACA:  Yes.
                       MR. GILLESPIE:  And I'm having a tough
           time myself remembering what I did last month and
           these people weren't there.  How well were we
           documenting stuff in the mid-1980s?  We need to pull
           the inspection reports, look at what the people looked
           at, look at what the fellow, the inspector from Region
           2 that went in and re-reviewed the issue and then ask
           the question and look at other records and say now did
           we take that?  What did we do with it generically?  I
           just don't know.
                       I think we're talking about something in
           1985 or something like that, maybe and it's 17 years
           old at this time.  I like to assume the staff did the
           right thing.  We did pursue things aggressively at
           that time.  I just don't have the documentation in
           front of us.  We need to pull it together. 
                       Someone else from engineering --
                       MR. KUO:  Goutam Bagchi, he's going to
           make a presentation on related issues.
                       MR. GILLESPIE:  But I would suggest the
           opportunity to come back would be also fine with us.
                       VICE CHAIR BONACA:  My proposal will be if
           we feel, first of all, this committee will decide
           whether or not we feel confident that the issues
           themselves for Turkey Point, so we can focus on the
           license renewal for that plant.  If we feel it is
           dealt with properly, then we can say let's concentrate
           on that.  That will result, probably with separate
           letters requesting that we look at the genetic
           implications, how they were handled for other units
           and that would open the path.
                       MR. GILLESPIE:  Yes, and that would be
           fine.  I think we can get the Region 2 records pretty
           quickly for you for Turkey Point to kind of close that
           documentation issue and I'll tell you the truth.  I
           feel more comfortable coming back to talk about the
           generic issue versus trying to do something where
           we're potentially kind of patching some things
           together.
                       VICE CHAIR BONACA:  I agree with you one
           hundred percent.
                       MR. GILLESPIE:  Goutam did have some
           thoughts of some basic engineering he covered with me
           earlier of about why this is a safety issue we can now
           look at in an orderly way and not necessarily assume
           we didn't look at it 17 years ago, but let's see what
           we decided then and what the basis was. 
                       So I'd suggest coming back and let Goutam
           finish what he's going to go and we'd be happy to come
           back.
                       MR. ASHAR:  If Goutam is going to speak,
           then I won't say anything --
                       VICE CHAIR BONACA:  I would like to hear
           from the members, is it acceptable with you that we
           put this issue here, which is generic, separately and
           address it later or would you like through the
           presentation now?
                       MR. BAGCHI:  It's a very quick
           presentation.  I just wanted to share with you some
           idea of load sharing, what is it that is unique in the
           containment structure of design.
                       VICE CHAIR BONACA:  Okay.
                       MR. BAGCHI:  And I think there is
           something unique in the design itself that gives it
           the robustness and the ability to withstand the design
           basis.
                       And concrete, as you know, takes
           compression.  It cracks and it doesn't take an tensile
           load and it maintains -- the effective purpose of the
           concrete is to maintain the reinforcing bars in the
           designed locations.
                       Reinforcement carries all the load. 
           Post-tensioning tendons keep concrete in compression. 
           And very high quality, .2 percent ultimate elongation,
           ductile liner plates are provided as the leak-tight
           barrier.
                       Design basis load is internal pressure,
           due to the postulated accident load.  Containment
           structure goes into tension.  Concrete cracks due to
           tension.  Reinforcement bars take all tension loads
           and the liner plate maintains the leak tight
           integrity.  If there is any local void, it deforms
           plasticly and then expands and bridges the gap, as we
           have experienced in the reactor vessel head at one
           plant.
                       At the shell-mat and shell-dome junctions
           bending moment puts concrete into compression.  But as
           you know, this was not the area where the concrete
           void was found.  The concrete void appears where there
           is congestion of reinforcement and special provisions
           are sometimes lacking when putting in concrete.  And
           this is the area of the ring girder near the equipment
           hatch.
                       So only in those two junctions the
           concrete is put into compression.  By code
           requirement, concrete is under reinforced.
                       Crushing failure of concrete is prevented
           by code provision because the reinforcement has to
           yield first.  Redistribution of load around any void
           provides the necessary strength.  Structural Integrity
           Test would reveal locations of unacceptable voids by
           bulging, spalling or local failure.  Every reinforced
           concrete structure passed the Structural Integrity
           Test satisfactorily the very first time.
                       There are requirements to make predictions
           of deformations and measurements are made,
           observations are made, examinations are made
           afterwards and they have all been within the predicted
           limits.
                       Post-tensioning puts the highest load
           during construction.  Any weakness in concrete shows
           up at this time as we found in the delamination of
           dome.  It was a weakness in the design.  Reinforcement
           bars were not provided and later on they learned their
           lesson.
                       Containment weakened by pervasive voids
           will not pass the SIT, the Structural Integrity test.
                       So my conclusion is that the unique design
           of the containment structure, the high quality of
           construction, no matter the fact that there were voids
           found and these are construction areas those are
           imbedded in the code related factors of conservatism
           and the allowable stresses and so on, there are going
           to be voids and in a very thick structure 4.5 to 
           5-foot thick walls, you're not going to easily find
           the voids.  If they were found easily, they will be
           taken care of and if there are voids, as I tried to
           point out, the load path and the behavior of the
           concrete is such that the reliance is not on the
           concrete.
                       And this is -- the inside I just wanted to
           share with you and I feel that the containment
           structure is extremely robust as people have seen from
           the tests, although in the tests you wouldn't have
           expected any voids, but in a scaled condition,
           microvoids may well have been there in those third
           scale, quarter scale test models.  But it's the load
           and the design of the structure that provides us with
           the assurance that there will be good performance
           function, certainly, after the design basis load and
           way beyond that.
                       MEMBER SIEBER:  I have a question.  I
           recall during -- having witnessed a couple of
           Structural Integrity Tests of concrete containments
           that one of the steps was to find and map the cracks
           that appeared.  Was that common practice for every
           containment?
                       MR. BAGCHI:  Absolutely.
                       MEMBER SIEBER:  That would reveal the
           presence of the voids because the cracks would appear
           around the area of the void as the loads redistribute
           themselves.  Is that correct or not correct?
                       MR. BAGCHI:  I would like to agree first
           and then take away some comfort that I've agreed with
           you.  If it's 4.5 foot thick wall and if this void is
           adjacent to the liner plate, you're not going to see
           it.
                       MEMBER SIEBER:  That's right, that's
           right.
                       MR. BAGCHI:  This is a conservatism --
                       MEMBER SIEBER:  You will see it on the
           inside if it's adjacent to the liner because there
           will be a dimple there.
                       MR. BAGCHI:  It has to be a very large
           void to do that.
                       MEMBER SIEBER:  Yes, it does.
                       MR. BAGCHI:  yes sir.
                       MEMBER ROSEN:  So the conclusion is small
           voids you won't see, but they don't matter because the
           loads are being taken by the reinforcement steel and
           large voids, if they have occurred, you would see.
                       MR. BAGCHI:  Yes, that's my contention.  
                       MEMBER ROSEN:  In the performance of the
           concrete.
                       MR. BAGCHI:  If you allow me to
           characterize what kinds of voids, I would not consider
           as extremely critical is something in the order of a
           thickness.
                       MR. KUO:  If I might add to it, the large
           void, if it is located in critical locations, in other
           words, it's a stressed location, void stress location,
           you will see during the test, as a result of the test.
                       MR. BAGCHI:  That point about crack, map
           cracking, mapping the crack is really intended for
           that purpose.
                       MEMBER SIEBER:  That's right.
                       VICE CHAIR BONACA:  Thank you for
           informative presentation.  
                       MR. GILLESPIE:  Mario, now what I'm hoping
           is that we'll find that back in the 1980s someone as
           smart as Goutam wrote that down as a basis and I don't
           know if we will -- we need to look, but that's part of
           the reason I think some things didn't happen and how
           well did we document things in our actions, we need to
           do some investigation.
                       VICE CHAIR BONACA:  Okay.
                       MEMBER RANSOM:  A point of clarification,
           in Turkey Point, is it known that there are voids and
           do they know how big they are?
                       VICE CHAIR BONACA:  Oh yes.  They found
           voids, as you know.
                       MEMBER RANSOM:  They have found them?
                       VICE CHAIR BONACA:  Well, they found them,
           yeah, sure.  That's how the whole issue came up.  They
           found voids under the equipment hatch when they were
           replacing the steam generators.  They had to take off
           the hatches because they were not large enough.  As
           they removed them, they found these voids right under
           because of the complexity there and the amount of the
           rebar that --
                       MEMBER RANSOM:  So those presumably were
           remediated when they repaired them.
                       VICE CHAIR BONACA:  Absolutely.
                       MEMBER RANSOM:  This just led to suspicion
           that there may be other voids?
                       VICE CHAIR BONACA:  The concern of Mr.
           Oncavage was are there other voids in the containments
           and so we expected to find that there would be some
           documented trail that said yeah, we looked at it or we
           tested or we performed some assessment of the type
           that we received right now that gives us confidence
           that probably there are no voids or there are some
           that are not significant to the strength of the
           containment.  And we haven't found yet this paper
           trail.  That's what we're looking for.
                       The other issue is the genetic
           implications.  If you find this kind of issue in one
           location, in one containment and then you go to the
           next one and find the same thing as happened there, it
           tells us that very likely there is going to be
           something similar under the hatch in some other unit
           and so one will have to understand the significance of
           no remediation of that void and again, that may be
           some analysis done of this type that is sufficient,
           but we haven't seen any of that, so we're looking for
           how the generic implications of the issue were
           handled.
                       MEMBER POWERS:  I'll point out, Mario,
           that there were in construction of the McGuire plant
           that they found large voids in the concrete when they
           placed, had nothing to do with where they put
           vibrators.  There are lots of reasons for voids.
                       VICE CHAIR BONACA:  Yes, sure, the timing
           of pouring of the concrete, the density, the liquidity
           of it, how it flows.  
                       Okay, so are there any more questions? 
           Your considerations were still related to each other's
           presentation we had on the concrete, right?
                       MR. ASHAR:  Pardon me?  What's your
           question?  I didn't get you.
                       VICE CHAIR BONACA:  I'm saying what is the
           remaining portion of your presentation?
                       MR. ASHAR:  Yes, I can finish up with a
           few lines.  Now Goutam very well described this as to
           the robustness of containment and how the voids cannot
           be that much of a significance in integrity of the
           containment at least to resist the design basis
           pressures.
                       This is exactly what Goutam pointed out in
           the initial structural integrity testing, periodic
           leak rate testing being performed in the containment. 
           Containment -- they also conformed intended function
           of the structure.  Now one other question that I'd
           seen being asked was what would be the impact on LERF. 
           What I would say more succinctly is condition probably
           of containment failure.  That would be affected if
           there is any point in it.  
                       Now my judgment, it's my own judgment on
           this particular issue is that there are two model
           tests being performed at Sandia.  One in 1995 or so on
           reinforced concrete model and one in 1999 on viscous
           concrete model which was being financed basically by
           NUPAC in coordination with the NRC.  
                       On the first test, what I want to point
           out is the failure of the model at 137 psig or so, and
           at that time the concrete was quite a bit cracked and
           heavily cracked, but at that time they did not go all
           the way up to the failure of the complete structure. 
           They stopped when they saw the leakage was too high,
           but there was some stiffness left still at that time
           and now in the later test in viscous concrete
           containment in 1999, they did go a little farther than
           just leaking criterion.  It was considered the
           containment fate, but then they went a little bit more
           and they saw that there was few strength left,
           stiffness of the concrete to hold the liner in place
           and I think they went about 10 psig, more than what
           would consider as a failure, not the ability to -- so
           that was my judgment that the effects of LERF of the
           voids, in general, would not be that significant.
                       CHAIRMAN APOSTOLAKIS:  But the conditional
           containment failure probably in NUREG 1150 is
           extremely uncertain.  I mean it's always between 0 and
           1.
                       MR. ASHAR:  Yes.  
                       CHAIRMAN APOSTOLAKIS:  I wonder, does it
           include the possible presence of voids?
                       MR. ASHAR:  Yes, this is what happens. 
           Okay, that if the structure were intact completely,
           okay, the ideal structure, you find out one fragility
           curve occurred for containment probably so there is an
           FSAR and ordinate probably to a failure, FSAR used as
           pressure as a parameter.  Okay, that will give you the
           medium design pressure.  Point 5 failure could occur. 
           That was taken in the LERF calculation later on for
           structural containment.  Now if there is a
           degradation, a main degradation is not concrete, but
           the liner.  In the case of concrete containments,
           liner would be the prime candidate for reducing the
           effectiveness of containment because it would leak. 
           So if there is liner degradation of high level, then
           you can shift your facility curve in such a way that
           it meets with the damage assessment that has been
           performed.
                       CHAIRMAN APOSTOLAKIS:  My question is if
           I look at the -- not the fragility curve, but the
           final results of the NUREG-1150, they have very nice
           figures with various sequences and then the
           conditional containment is computed.
                       MR. ASHAR:  Right.
                       CHAIRMAN APOSTOLAKIS:  And this is a very
           uncertain quantity.  It goes from 10 to the minus
           something, all the way to .9 sometimes or even 5.
                       MR. ASHAR:  Right.
                       CHAIRMAN APOSTOLAKIS:  So that's extremely
           uncertain.  So I don't know what it means.
                       MR. ASHAR:  But normally the IPEs are
           performed with little more preciseness than those --
           excuse me?
                       CHAIRMAN APOSTOLAKIS:  You mean the IPE is
           no better than your NUREG 1150?  I doubt it.
                       MR. ASHAR:  Oh no, no, no.  What I'm
           saying that the uncertainties which are being in NUREG
           1150 considers number of uncertainties.  When you
           start in plant specific IPE, that means they have
           precisely characterizing the sequences and then
           putting the -- they also have uncertainties, but not
           as much as what we see --
                       CHAIRMAN APOSTOLAKIS:  Yes, but the IPEs
           also did not spend as much effort on the level.
                       MR. ASHAR:  I'm not saying I would put a
           lot of --
                       CHAIRMAN APOSTOLAKIS:  My question is in
           the original 1150 studies, was the possible presence
           of voids included?  You don't know?
                       MR. ASHAR:  I know that it was not.
                       CHAIRMAN APOSTOLAKIS:  Oh, it was not.
                       MR. ASHAR:  It was not.  None of the
           damage condition or anything was considered in the
           1150.
                       VICE CHAIR BONACA:  That's why I made a
           distinction between the design pressure that I
           believe, this condition is still allowed to meet as a
           requirement of the tech specs versus the ultimate
           containment.  So we don't know and typically we are
           looking at penetrations as the weak link or something
           of that kind and here you have an unknown.
                       CHAIRMAN APOSTOLAKIS:  Is the effect not
           significant because we are so uncertain to begin with
           what can happen?
                       MR. ASHAR:  Well, only from the existing
           condition.  It's not related to the insignificance.
                       MEMBER FORD:  Mario, you also managed to
           go about how we felt about this particular issue for
           Turkey Point as opposed to generic issues.  I feel
           really uncomfortable.  In all of the rest of the
           license renewal examinations we've been asked to
           comment upon, we've had detailed documents, ANPs that
           we can make good scientific judgments, our own
           independent judgments.  Here we're hearing engineering
           judgment, anecdotes.  We've got nothing to go on.  So
           I don't see how we can make any advice or judgment on
           this as an issue.
                       CHAIRMAN APOSTOLAKIS:  Yes, I think this
           kind of discussion will take place in the afternoon
           part--
                       VICE CHAIR BONACA:  But I would like to --
           I know, we know pretty much what we heard already.  My
           sense is that we should not write a report now.  There
           are two issues here that need some closure.  One is
           the station blackout issue.  Although we know that the
           plant is taking a position, a direction of fulfilling
           the requirements, it is important for us as a
           committee for us to understand is it a capricious
           requirement in addition to what already they are doing
           at Turkey Point?  Is it essential?  I think we need to
           reflect on that and review it.  Second, we also now
           need to look at this paper that will be provided to us
           and so my suggestion would be that schedule one hour
           meeting at the May meeting and we look at those two
           issues and then resolve them at that time.  That will
           give us at least time next three weeks --
                       CHAIRMAN APOSTOLAKIS:  Well, we have time
           this afternoon to discuss the letter.  We have already
           agreed that there will be some additional information
           provided to us with a possible presentation.
                       VICE CHAIR BONACA:  Yes.
                       CHAIRMAN APOSTOLAKIS:  We're already
           behind schedule.
                       VICE CHAIR BONACA:  I was attempting to
           say in a way that you're right and a means of probably
           doing some closure, but I think that for us to jump to
           something today is going to make it enough.
                       CHAIRMAN APOSTOLAKIS:  Okay.  So I'm
           wondering now is there anything else we need to
           discuss right now?
                       VICE CHAIR BONACA:  Any other questions
           that members would raise?
                       MEMBER LEITCH:  Not related to concrete,
           but I have a question about there's a figure in the
           environmental report.  It depicts a 6-mile radius and
           usually when you see these figures they have a 10-mile
           radius.  I don't know that this relates to emergency
           planning, but I'm just wondering --
                       CHAIRMAN APOSTOLAKIS:  Which figure is
           this?
                       MEMBER LEITCH:  Page 2.1-3 in the
           environmental report.
                       I'm just wondering is there any
           implication?  Does Turkey Point have a 10-mile EPZ
           like everybody else?
                       MR. HALE:  Yes, we do.  Steve Hale,
           Florida Power and Light.  Yes, we do.  That's not
           intended for emergency planning.
                       MEMBER LEITCH:  Okay and my other question
           is can someone tell me what's the CDF and LERF for
           these units and are they different from one another?
                       MR. AULUCK:  We'll have to get back to
           you.
                       MEMBER LEITCH:  Okay, I'm just looking for
           the CDF and LERF and are units, Unit 3 and 4 different
           from one another.
                       MR. HALE:  Unit -- I can't cite the
           specific numbers, but we're not an outlier or anything
           like that.  We have reasonable CDF numbers.  I can't
           speak to the specific numbers.
                       MEMBER SHACK:  Well, actually, your
           numbers reported int eh IPE are highest of anybody,
           but the discussion at Florida was that, in fact, that
           your updated PRA has numbers that are much lower.  So
           I think it's close to four times 10-4 in the IPE and
           the reported number was like 1 times 10-5, some PRA
           person gave this in Florida, but that hasn't been
           documented.
                       CHAIRMAN APOSTOLAKIS:  So how did it go
           from four times 10-4 to 1 times 10-5?  
                       MEMBER SHACK:  Divide by 40.
                       (Laughter.)
                       MEMBER ROSEN:  This is fairly typically
           actually --
                       MEMBER SHACK:  The discussion was that he
           was making some very conservative assumptions when
           they did the IPE.
                       MEMBER ROSEN:  That's the reason.  This is
           fairly typical, you see it in most PRAs that the very
           first ones are quite a bit higher than the more
           sophisticated ones that are done over time.
                       CHAIRMAN APOSTOLAKIS:  So that's something
           that we have to discuss.
                       VICE CHAIR BONACA:  Any other questions?
                       MEMBER POWERS:  But George, I'll remind
           you the number is totally meaningless because it only
           considers operational events.
                       MEMBER ROSEN:  Because of what, Dana?
                       MEMBER POWERS:  It only considers
           operational events.  It doesn't consider shutdown.
                       MEMBER ROSEN:  Plants generally have a
           shutdown assessment that considers the risk during
           shutdown which is additive to the internal events. 
           It's not meaningless, it's just part of the question.
                       CHAIRMAN APOSTOLAKIS:  Okay, any other
           questions for the presenters?
                       MR. AULUCK:  Do you want us to go over the
           other concerns of Mr. Oncavage?
                       CHAIRMAN APOSTOLAKIS:  Well, it's too late
           now.  
                       VICE CHAIR BONACA:  Let's just cover
           those.
                       MR. MEDOFF:  This is Jim Medoff again,
           Backup Project Manager for Turkey Point.  Basically,
           when Mr. Oncavage sent his letter in to you, we did an
           independent review of its concerns and basically we
           categorized them into voids which we just discussed. 
           The effect of hurricane windspeeds in storm surges,
           unsafe operation of the units.  He also went into
           concerns about the effect of terrorist attacks on the
           safety of the plants and he had a concern about spent
           fuel capacity.  
                       Basically, what we did is we called up the
           National Oceanographic and Atmospheric Administration
           to discuss the hurricanes.  Hurricane Andrew basically
           was one of the most severe hurricanes ever to hit the
           Atlantic coast.  It had wind speeds of 149 to 150
           miles per hour which puts it in Category 4, but with
           gusts above that which put the gusts into Category 5. 
           The storm surges for the Hurricane Andrew were of the
           order of 17 feet maximum.  As Steve Hale has
           indicated, the Florida Power Light units, the Turkey
           Point units, vital equipment are designed to withstand
           storm surges above 22 feet and all of the vital
           equipment such as emergency diesel generators, the
           reactor vessel, etcetera are put in design category 1
           structures and they're designed to withstand
           differential pressures created by the hurricane of the
           order of 225 psi without any deformation of the --
                       MEMBER ROSEN:  Now you said above 22 feet. 
           I don't think that's what he said.  I thought they
           said it was up to 22 feet.
                       MR. MEDOFF:  No, the location of the vital
           equipment is at 22 feet or higher.
                       MEMBER ROSEN:  Right.
                       MR. MEDOFF:  The maximum hurricane -- in
           our discussions with NOAA, the maximum surge ever
           recorded for the Atlantic Coast was 20 feet and that
           was for, I think, it was Hurricane Hugo on the North
           Atlantic coast. 
                       The maximum storm search for Hurricane
           Andrew was 17, so the vital equipment at Turkey Point
           are designed at levels currently to withstand the
           current storm surges for Category 5 hurricanes.
                       That's not to say that you might get a
           really, really severe hurricane to create a storm
           surge above 22 feet, but I think the probability, my
           educated guess on that would be the probability would
           be low given the data that NOAA had given me in our
           discussions with them.
                       The next one is the effective terrorist
           attacks on --
                       VICE CHAIR BONACA:  We know that that's
           being handled.
                       MR. MEDOFF:  And the last concern was the
           -- Mr. Oncavage was concerned that they were going to
           expand the spent fuel capacity in the spent fuel
           building.  Typically, they're covered by tech specs if
           they even come close.  FPL will submit action to
           address it.
                       MEMBER POWERS:  It strikes me that the way
           you have approached storm surges is a bit different
           than we usually approach natural phenomena, especially
           when you're prognosticating for another 30 years or
           so.
                       Don't we usually say what's the
           probability of storm surges of various elevations over
           that period?
                       MR. MEDOFF:  Not being the expert in that
           area, I'm not going to say yes or not, but I would
           expect that to be the case.
                       MEMBER POWERS:  Taking particular
           incidents since it got to 17 feet, it could get to 20
           feet within the last 100 years we've had as high as 20
           feet and this is at 23 feet strikes me that you're
           very close and I certainly listen to people, not too
           intently, that tell me that the weather is such that
           hurricanes are going to become more vigorous in the
           future.  I know that despite the prognostications last
           year was a particularly hurricane deficit year, so
           maybe their predictions are not too good.  But it
           strikes me that you need a little more quantified
           treatment of this.
                       MR. AULUCK:  I think the design of Turkey
           Point can handle Category 5 hurricanes.  Steve, do you
           want to add?
                       MR. HALE:  Well, one, I think this is
           beyond Turkey Point, I mean if the issue is that
           historically in establishing your natural phenomenon
           and what you address in your SAR, you go back, I
           believe 100 years or something like that and then you
           establish some conservatism on top of that in the
           design of your structures.
                       We are fully confident in the design of
           our structures of accommodating our design basis
           hurricanes which had margin well above 100 year storm
           that was identified.  So I believe that in considering
           storms in the future, would be more in the generic
           arena than I would a specific Turkey Point issue.
                       MR. AULUCK:  So, in conclusion, we have
           completed our review.  As I understand we owe you
           information on the documentation, how Region 2 closed
           the issue on voids.  It's available. It's just a
           question of getting it to you.  The staff
           recommendation will include the resolution of the SBO
           issue and applicant has met all the requirements
           required by 54.29. 
                       VICE CHAIR BONACA:  So mean the second
           bullet is not correct, of course, at this stage.  I
           mean there's one open item and we will --
                       MR. AULUCK:  All open items identified in
           the SER were resolved.  This is a new emerging issue. 
                       VICE CHAIR BONACA:  You're right.
                       MR. AULUCK:  It just came last week and
           that's why I made a separate bullet in the staff
           recommendation.
                       VICE CHAIR BONACA:  Thank you.  Any
           further questions?
                       MR. KUO:  And this concludes the staff's
           presentation on Turkey Point license renewal
           application review and we will take two actions back. 
           The first one is try to put together the paper trail
           on the concrete voids inspection from Region 2.  We
           will try to get as many copies as we can. 
                       The second action is to check the CDF and
           LERF values for the containment.
                       VICE CHAIR BONACA:  There's a third one
           which is the station blackout.
                       MR. KUO:  Station blackout.  We issue the
           staff position on April 2nd on station blackout and
           the issue has been there for quite a few months.  We
           have issued the first station blackout proposed
           position back in November of last year.  Since then we
           have met with NEI and the industry three times and
           this position was supported by the NEI and the
           industry.
                       VICE CHAIR BONACA:  On the other hand, the
           staff was present during the walkdown of Turkey Point
           and the demonstration of the alternate path and there
           was no mention that this requirement would come up, so
           I think it's important for us to review it to
           understand if the requirement is appropriate.
                       MR. KUO:  Sure, sure.
                       VICE CHAIR BONACA:  Because I was very
           convinced by what I saw there and that it was
           adequate, so I would like to just --
                       MR. KUO:  I understand.
                       CHAIRMAN APOSTOLAKIS:  All right, thank
           you all.
                       MR. HALE:  Just for my own benefit, so I
           understand these issues.  I guess right now the
           current schedule for the Turkey Point license shows a
           letter from ACRS by -- what is it, April 19th?
                       MR. AULUCK:  The 19th.
                       MR. HALE:  And so what I understand that's
           not going to occur?
                       CHAIRMAN APOSTOLAKIS:  It looks like it
           will not.
                       MEMBER POWERS:  Let's make very clear that
           that's somebody else's schedule.  That's not our
           schedule.
                       MR. HALE:  Oh, I'm not -- I'm not -- don't
           -- just for my own benefit in terms of where we stand
           with our license review.
                       CHAIRMAN APOSTOLAKIS:  There is a
           probability that it would get it, it went down by a
           factor of 40 as a result of today's --
                       (Laughter.)
                       MR. HALE:  Is there anything that we can
           do?  Certainly, we can get our hands on the
           information ourselves with regards to the concrete
           containment.  In fact, I brought quite a bit of
           information with me today.  If there's some way with
           regard to the concrete void issue, we can resolve it
           by inspection of the information I have with me.  
                       The second item was with regards to
           station blackout.  We met for an extended period of
           time yesterday with the staff and have come in general
           agreement to the approach.  We also have that
           information available.  And certainly, the CDFs for
           the plant can be obtained very quickly.
                       MEMBER KRESS:  I propose that the
           Subcommittee Chairman sit down with him and go over
           that information and see if it's enough to satisfy the
           Subcommittee Chairman and then he can report back to
           the full Committee.
                       VICE CHAIR BONACA:  There are Subcommittee
           member concerns, however, raised right here and I want
           to make sure that we satisfy those.  I'll be certainly
           willing to sit down and review what you have and still
           there are a number of issues here, it seems to me that
           put the Committee under pressure to come to a
           determination when these issues are raised in Florida
           City, with the exception of the session blackout.  And
           so it concerns me in the months, the elapse of time we
           haven't been able to find --
                       CHAIRMAN APOSTOLAKIS:  Okay, why don't you
           then interact with the licensee and report to us maybe
           at 5:30 where we have some time to discuss this?
                       VICE CHAIR BONACA:  I'll do that.
                       CHAIRMAN APOSTOLAKIS:  And see how the
           Committee members feel then about writing a letter. 
           Okay?
                       MR. HALE:  I would like for Dr. Ford, too,
           because he's the one that's voiced concerns with
           regards to -- if possible --
                       CHAIRMAN APOSTOLAKIS:  Yes.  We can do
           these things.  But you have to remember, the letter is
           from the full Committee.
                       MR. HALE:  I understand.  I understand
           fully.  I just want to make sure that I have brought
           information today and anything I can do to facilitate
           your review I would like to do that.
                       CHAIRMAN APOSTOLAKIS:  Certainly.  Okay,
           thank you all very much.  We'll recess until 11:30.
                       (Off the record.)
                       CHAIRMAN APOSTOLAKIS:  We're back in
           session.  The next topic is Advanced Reactor Research
           Plan.  
                       Dr. Kress is the cognizant member.
                       MEMBER KRESS:  Thank you, Mr. Chairman. 
           The staff is diligently working on a comprehensive
           research plan for advanced reactors.  We have a draft,
           a proposed draft, copy of it which is incomplete.  So
           I guess we could consider this kind of an interim
           briefing and I guess we're looking for any early
           feedback from us that we might be able to give them
           either orally now or perhaps in a letter.  So with
           that minor introduction, I'll turn it over to Farouk.
                       MR. ELTAWILA:  Thank you, Tom.  You are
           exactly right that this plan right now is in a very
           early stage, and as a matter of fact, we have not
           received the input from the user office like NRR and
           NMSS, so it's a work in progress and we'll continue to
           update this plan and we envision that we will be
           coming to the ACRS at Subcommittee level in the
           different areas of this program.  But for the time
           being, the staff developed that plan to identify the
           issues that will be needed to develop the safety
           criteria against which this advanced reactor design
           will be judged.
                       The plan is extremely comprehensive and
           includes a lot of information.  Some of this
           information might already exist through international
           research that's conducted somewhere else.  it is also
           available through the vendors and the old history of
           gas-cooled reactors, for example.
                       So the plan should not be construed as
           research activities that the Office of Research is
           going to be conducting.  As a matter of fact, a lot of
           the information that describes in the plant would be
           the responsibility of the Applicant of the new reactor
           design to try to make the safety case.  So we will be
           receiving a lot of information from the industry on
           that.
                       But regardless of where the source of
           information is going to come from, whether it's coming
           from NRC, from international cooperation or from the
           vendor or the Applicant himself, NRC will have the
           best information available to make its regulatory
           decision.
                       MEMBER LEITCH:  If it's not intended to
           identify research, would it be intended to influence
           research by the NRC?  Maybe identify is not the right
           word.  "Would influence" be the right word?
                       MR. ELTAWILA:  Influence research.  I
           really consider it now as a gap analysis to try to
           identify the weakness or the lack of information at
           the NRC because we saw it in this advanced reactor,
           particularly gas-cooled reactor very recently.  So we
           might identify an issue that there have been a lot of
           research being done somewhere else, so if I call it
           research or try to make it to influence research, it
           might be the wrong way of characterizing it.
                       So it's really gap analysis right now and
           once we collect more information we are going to
           refine that and find out which part of the research
           would be provided by the industry, which part will be
           provided by NRC.
                       Having said that, one more issue that the
           Office of Research, even though if the utility or if
           the vendor provide information research data to
           support their safety case, the Office of Research will
           be conducting confirmatory research to try to go
           beyond the information that's usually traditionally
           provided by Applicants like poking into the area of
           severe accident source term and the issue that not
           traditionally being addressed by Applicant and
           licensee.
                       MEMBER LEITCH:  So the operative word is
           "by the NRC"?  In other words, you're identifying
           research that needs to be done by someone.
                       MR. ELTAWILA:  By someone.  And eventually
           we'll try to narrow down to the research that will be
           done by the NRC.
                       MR. ELTAWILA:  Okay.  
                       MEMBER FORD:  Can you put a quantitational
           thing on "eventually"?  When are these decisions going
           to be made?
                       MR. ELTAWILA:  I think this decision -- we
           are supposed to go to the Commission in the fall of
           this year so we are planning to form inter-office task
           groups to look at the information in the research
           plan, identify which part of this information would be
           provided.  The NRC is going to ask the vendor and
           Applicant to provide and then decide after that the
           balance of that will be performed by NRC and finalized
           that in the fall and send it to the Commission, of
           course, after coming to you here.
                       MEMBER FORD:  So there will be several
           meetings with the ACRS to comment on the various
           points along that time line?
                       MR. ELTAWILA:  That's correct, yes.
                       CHAIRMAN APOSTOLAKIS:  By fall?
                       MEMBER KRESS:  Oh yes, we will several by
           fall, yes.
                       MR. FLACK:  I think what's envisioned is
           that we would come back at least once to the Full
           Committee before we go to the Commission with the
           plan.  And then Subcommittees as we feel are necessary
           or as the Committee feels necessary.
                       CHAIRMAN APOSTOLAKIS:  Maybe you need a
           better title though.  When you issue a report that
           says "Research Plan" it seems to me most people would
           think research to be done by the NRC.  Usually, these
           are technical issues.  They need resolution before you
           license them.
                       MR. ELTAWILA:  George, I agree with you,
           but we are -- are embarking on an area here that we
           really don't have too much experience, especially in
           the 
           gas-cooled reactor.  We don't have much experience and
           we have, for example, we are having a hard time
           getting information from the international community. 
           So the information might be out there, but we might
           still have to do the research because we are unable to
           get this information.
                       CHAIRMAN APOSTOLAKIS:  No, I understand,
           but I think the title of your report should be
           advanced reactor technical issues.
                       MR. ELTAWILA:  Information needs.
                       CHAIRMAN APOSTOLAKIS:  Yes, information
           needs, something like that.
                       MR. ELTAWILA:  We can change that.
                       CHAIRMAN APOSTOLAKIS:  Instead of Research
           Plan.
                       MR. FLACK:  Well, the reason why it's a
           plan is we're trying to build an infrastructure.
                       CHAIRMAN APOSTOLAKIS:  But you cannot plan
           for other people, John.
                       MR. FLACK:  No, no.  I understand.  That's
           when we exercise the plan.  The plan is to build the
           infrastructure and then part 2 is well, we're getting
           a license application that at some later date we're
           prepared to support the licensing office in that area. 
           So we have a plan to try to establish the
           infrastructure that will support the plan.
                       CHAIRMAN APOSTOLAKIS:  If you change the
           title you will not need a separate color for that
           bullet over there.
                       MR. ELTAWILA:  We'll change the title, how
           about that?  Really, it's not a big issue right now.
                       CHAIRMAN APOSTOLAKIS:  The second bullet
           there, you know, why do you feel that you have to say
           that?  Isn't that sort of understood that the
           Applicants are responsible for data?
                       MR. ELTAWILA:  It is -- well,
           traditionally, the NRC have been generating the data
           for all plans, you know, before the 1990s and things
           like that.  The NRC generated all the thermal
           hydraulic database, all the severe accident and the
           fuel.  So right now we are entering our strategic
           plan, put the burden on the industry for providing the
           data that's needed to justify the technical basis for
           the licensing of the plant.
                       So it is important to identify that so
           people when they read the plan, they don't think that
           we are -- whatever we're going to call it, they are
           not going to reach the conclusion that NRC is going to
           do this work and then they will sit and not do any of
           the work themselves.
                       MEMBER KRESS:  I think that's worth
           saying.
                       CHAIRMAN APOSTOLAKIS:  But you also have
           a sentence in the actual report.  I don't know if you
           want to come back to it, but where you say it is also
           recognized that an Applicant of a new reactor design
           has a primary responsibility to demonstrate the safety
           case of the proposed design.
                       MR. ELTAWILA:  That's correct.
                       CHAIRMAN APOSTOLAKIS:  And later on, you
           use a variation of this as well.  It wasn't clear, I
           mean somehow it sent a message that we are really not
           part of this.  We are setting the standards, aren't
           we, the criteria and the objectives.  It's their
           responsibility to demonstrate they comply with the
           criteria, but not -- what does it mean to demonstrate
           the safety case?  Are they going to also set the
           criteria?
                       MR. ELTAWILA:  No, no.  I think it's very
           difficult to put everything in the first bullets, but
           if you go a little bit further in our discussion you
           will see that one of our responsibilities is to
           develop the data to set the safety limits for this
           plan.
                       CHAIRMAN APOSTOLAKIS:  Sure.
                       MR. ELTAWILA:  So that will be our
           responsibility.  It's not going to be Applicant
           responsibility or anybody else.
                       CHAIRMAN APOSTOLAKIS:  Okay, but I think
           in the report it should be made clearer, because that
           was something that struck me when I read it.
                       MEMBER KRESS:  But when it comes to
           deciding what data and research that the Applicant
           needs to provide to you, do you have some sort of firm
           criteria for how to pick out of this comprehensive
           document so these are your guys and these are
           confirmatory and they're ours.  Do you have a way to
           decide that or is that just going to be judgment?
                       MR. ELTAWILA:  I think it will be a lot of
           things:  experience, judgment and our interaction with
           the user office about what are the information that
           they want independent capability from the staff to be
           able to do their job.  And our own initiative in the
           Office of Research about how to build that additional
           infrastructure to be able to ask more intelligent
           questions from this Applicant and licensees.  So it
           will be a combination of the three and the way we have
           developed this information and the past will play a
           major role in deciding which part will be ours and
           which part will be the Applicant's.  But in the past,
           Applicant tends to focus on the operation of the
           plant.  They have a safety envelope that they work
           within the safety envelope and they will provide the
           information to satisfy that need only.
                       NRC wants to go beyond that and to try to
           challenge the system in a different way and we will
           generate the information for that.
                       Although the plan itself is for AP-1000,
           IRS and GT-MHR and PBMR, you will see that most of our
           discussion will be on high temperature gas-cooled
           reactor because that's the area we don't have much
           information about.
                       CHAIRMAN APOSTOLAKIS:  Do you have
           sufficient information on IRIS?
                       MR. ELTAWILA:  Okay, IRIS, let me -- IRIS,
           we have very limited interaction with Westinghouse so
           it's not really a major part of our activities right
           now.
                       The other points that I want to make is
           that we -- Jim Lyons from NRR and I attended a meeting
           with Framatome and Framatome is proposing to submit
           SWR application.  So -- SWR -- honestly, I tried to
           look in the vu-graphs to find what -- simplified water
           reactor or something like that.
                       MR. LYONS:  This is Jim Lyons from NRR. 
           It's the SWR 1000.  It was designed by Siemens from
           Framatome and Siemens are now together.  It's a plant
           that's being considered to be built in Finland. 
           They're also looking at coming in.  That would be a
           BWR design that they're thinking about.  They're also
           exploring whether or not they'd want to come in with
           the EPR which is European Pressurized Water Reactor. 
           That's another one that they're thinking, they're
           considering coming in with for design certification.
                       CHAIRMAN APOSTOLAKIS:  Now the SWR is not
           the same as the SBWR?
                       MR. LYONS:  No, it's not.  It is a boiling
           water reactor.  It was --
                       MR. ELTAWILA:  It's almost the same
           principle, but it's different.  So again, we're going
           to change our plant as Jim indicated.  They are
           coming.  They want certification.  Next year, they
           submit application.
                       They are serious about submitting
           application.
                       We're having a meeting with them.
                       MR. LYONS:  We're meeting with them on --
           they're going to present these two basic designs and
           they're trying to understand the design certification
           process and to make a business decision on whether or
           not they want to come forward.
                       MEMBER ROSEN:  This raises the whole
           question in my mind of how you pick the things that
           you need to get researched, however you get them
           researched.  Because I was astonished in reading your
           report that the Generation IV program of the
           Department of Energy isn't mentioned until the 111th
           page which is the last page.
                       CHAIRMAN APOSTOLAKIS:  Because they
           couldn't do it after that.
                       MEMBER ROSEN:  Because they could not do
           it after that and still mention it.
                       And in that program which is a very vital
           program with lots of effort going into it, hundreds of
           people working on it, many of the concepts that were
           just mentioned and lots beyond that are being
           considered seriously to be down-selected for
           development of a roadmap and some research,
           significant amounts of research from the Department of
           Energy.  I know John Flack who's with you.  He's aware
           of these things and has attended many of the meetings.
                       So I would ask you why don't you even
           reference Generation IV in this report?
                       MR. ELTAWILA:  That's a good question.  We
           are keeping informed with what's going on in
           Generation IV, but it's a Commission direction.  The
           Commission directed the staff to work with this
           applicant at this time, and that's why we defined the
           work that will be needed for these four applications
           that we have, even though IRIS is at the very early
           stage.
                       So we get guidance from the Commission
           about what to work on and what not to work on, and for
           advanced -- for the Generation IV to continue to
           interact with DOE, we're keeping abreast of what's
           going on, and we keep the Commission informed with
           what's going on.  And once the Commission feels that
           the staff should be engaged in this process, I think
           the Commission will direct us to be working in this
           area.
                       MEMBER ROSEN:  I think perhaps the
           committee -- our committee ought to discuss this
           point.
                       CHAIRMAN APOSTOLAKIS:  It wouldn't make
           any difference, though, Steve.  I mean, they are
           trying to be as general as they can.  I mean, look at
           the very -- the penultimate arrow there.  The
           regulations will be technology neutral.  I mean, if
           they mention Generation IV on the second page, would
           it make any difference to what they're proposing?
                       MEMBER ROSEN:  Well, I think it would make
           a great deal of difference.
                       CHAIRMAN APOSTOLAKIS:  Really?
                       MEMBER ROSEN:  Oh, yes.
                       CHAIRMAN APOSTOLAKIS:  They are trying to
           be technology neutral.
                       MEMBER ROSEN:  Well, but I do think you
           have --
                       CHAIRMAN APOSTOLAKIS:  Yes.  Well --
                       MEMBER ROSEN:  -- ever do that.
                       CHAIRMAN APOSTOLAKIS:  Then, they will
           have, they say, Regulatory Guides.
                       MEMBER ROSEN:  No.
                       CHAIRMAN APOSTOLAKIS:  So they will not
           have --
                       MEMBER ROSEN:  For example, this report
           includes -- a third of the report is on the research
           to support nuclear materials, NMSS activities.  The
           Generation IV program will be -- if it continues to
           evolve the way it currently is, will include a major
           research track on sodium-cooled reactors, but the fuel
           cycle of it mostly.
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MEMBER ROSEN:  With an emphasis on fuel
           cycle research.  And that's not mentioned at all in
           this third -- last third of this 111-page report.  And
           it would seem to me that it would be a major thrust of
           the nation's going-forward activity.
                       MEMBER KRESS:  Well, I think Farouk --
                       MEMBER ROSEN:  So my basic --
                       MEMBER KRESS:  -- I think Farouk
           appropriately answered, though.  They've got
           constraints on what this report is supposed to look
           at, and it doesn't include that.
                       MEMBER ROSEN:  Right.  And I'd say if
           those are the constraints that they were asked -- that
           they were working within, because the Commission
           directed that, then, well, that's certainly what they
           have to do.
                       MEMBER KRESS:  Sure.
                       MEMBER ROSEN:  But we can advise the
           Commission that maybe they ought to be thinking about
           some broader issues.
                       MEMBER KRESS:  Well, that's -- I think
           that would be another issue, another thought.
                       MEMBER ROSEN:  I'm not faulting them.  I'm
           just --
                       MR. ELTAWILA:  No.  I think we encourage
           the committee to think about the reality of the budget
           situation, and things like that.  We have to -- even
           that we are encouraging NEI and the industry to come
           with identification of what's really their priority.
                       You know, if it is going to be AP-1000,
           PBMR, GT-MHR, we really need to get clear guidance
           from the industry about what's important, what's
           definitely going to be submitted for certification,
           and has a chance of continuing with the application
           here for review, because, as you can see from the
           report itself, the amount of information that needs to
           be gathered is tremendous.  
                       And given the staff limitation and even
           contractor availability and test facilities, and
           things like that, we need to plan in a much better
           structured way than trying to address everything at
           the same time.
                       MEMBER ROSEN:  I think there are major
           strategic issues that need to be addressed, and that
           one of them comes out of what you just said, which is
           wait for the applicant to come and then we'll get
           ready.  I'm not sure that's the only way that research
           should get defined, and we can discuss that more in
           the committee.
                       MEMBER KRESS:  Yes.  But surely you want
           to give priority to things you know are going to come
           in for certification, or at least you suspect very
           soon.  So, you know, you can't -- if you've got a lot
           of stuff to do, you're going to focus on the ones that
           you need first.  And I think that's what they've done.
                       MEMBER ROSEN:  Well, they've done what
           they were told to do, which is a good thing to do --
                       MEMBER KRESS:  Yes.
                       MEMBER ROSEN:  -- when you work here.
                       (Laughter.)
                       MR. ELTAWILA:  Okay.  With the -- I think
           George alluded about to the new regulatory structure
           that we should be looking at.  For example, some
           feature of the PBMR is not really covered by current
           regulation because -- which is developed for light
           water reactor.
                       So Exelon has proposed a risk-informed
           approach towards defining the license basing event to
           supplement the current regulatory structure.  And we
           are planning to build on Option 3, and that's why Mary
           is here, build on Option 3, try to provide -- maybe we
           need to develop additional supplemental risk metrics
           for the other type of reactor, and at a very high
           level for what criteria this design should mean that
           we can be technology or reactor design neutral.
                       And then, in the specific Regulatory
           Guide, we'll try to see how well they should be
           measuring against meeting the acceptance criteria, and
           we'll provide that for each type of reactor, a Reg
           Guide or a set of Reg Guides to address these
           acceptance criteria.
                       The overall objective of the research plan
           is to, as I mentioned earlier, to determine the
           critical information that is needed to establish the
           safety standard new reactor design is going to
           meeting.  That's NRC responsibility.  Although that we
           might get some data from the licensee -- from
           applicants, we have the major responsibility of
           developing this data.
                       Again, another issue -- the issue of
           uncertainty, we are planning to explore uncertainties
           in this design and this information, and that's the
           responsibility of NRC.  
                       And, finally, is the issue of developing
           independent analysis tool and give the data to assess
           this tool.
                       CHAIRMAN APOSTOLAKIS:  Now, the
           uncertainties.  You have in mind something,
           NUREG-1150?  That's the only place where I've seen
           large uncertainties handled.
                       MR. ELTAWILA:  I think we will be looking
           at something like NUREG-1150.
                       CHAIRMAN APOSTOLAKIS:  With expert opinion
           elicitation and doing something about it and --
                       MR. ELTAWILA:  For some of this new design
           which we're going to have, much of the experience or
           much of the data, that we will have to look into
           expert opinion.  And you can -- maybe when John
           discusses the issues of fuel you'll find some of this
           in his discussion.  I don't know if you were planning
           to discuss it.
                       Again, because of the -- we are going to
           rely a lot on cooperative agreement, although we have
           been having difficulty entering into some of these
           agreements, but there is work in China and Japan,
           European community, and we are looking for cooperation
           of the Department of Energy to do some testing in the
           fuel area.
                       I want to conclude my brief presentation
           here by saying that we looked at Dr. Powers' trip
           report.  I think Dana identified very important
           technical and policy issues that the Commission needs
           to resolve before we can say this type of PBMR in
           particular is -- can be certified or not.
                       CHAIRMAN APOSTOLAKIS:  Did you find that
           report --
                       MR. ELTAWILA:  So the issues are very
           important.
                       CHAIRMAN APOSTOLAKIS:  Did you find that
           report clearly written?
                       (Laughter.)
                       MR. ELTAWILA:  If you heard Commissioner
           McGaffigan say, it's plain language, you know, and he
           was looking for something from us to say the same
           thing.  But, unfortunately, he also admitted that our
           concurrence process will not allow me to write
           something like Dana Powers writes.  So --
                       (Laughter.)
                       CHAIRMAN APOSTOLAKIS:  Well, it's not that
           -- I'm not sure this committee would think about --
                       (Laughter.)
                       Yes, he certainly speaks with sufficient
           clarity and volume.
                       (Laughter.)
                       And volume.
                       MR. ELTAWILA:  Well, they are very
           important issues.  We identified these issues and sent
           them to Exelon, and we are in the process of gathering
           information about it, and we actually use this
           information in the development in our research plan. 
           In addition to Dr. Powers, we received other comments
           from Dr. Murley, for example, and all of this
           information is factored into our plan.
                       CHAIRMAN APOSTOLAKIS:  Now, why did -- I
           sense that you have some problems with international
           -- not problems perhaps, but you are not -- it's also
           clear how you're going to get information from the
           international efforts.  Why do you need to understand
           the status?  I mean, you send somebody there, you
           understand it.  What's the problem?  They are
           reluctant to give you information?
                       MR. ELTAWILA:  When you -- there is
           reluctance -- I think, for example, the European
           community is -- their system of working the everybody
           do -- does research, and the shared information --
           there is no exchange of money.  
                       So for us to try to get information from
           the European community, we'll try to get consensus
           from all of the members of the community.  And you
           know that that's extremely difficult, to enter into an
           ongoing program right now to try to get information. 
           So each country has said yes or no to sharing
           information with NRC.
                       When it comes to China, it is just -- we
           have limitations through the State Department and
           things like that about what level of interaction we're
           going to have with them.  Japanese, again, the
           organization -- so it's just -- in a nutshell, it's
           not that easy.
                       Yes, we're sending people to go and meet
           with them.  We've been exchanging e-mail.  We meet
           with them.  And it sounds very promising, and it looks
           like we are on the right track, and we are going to
           get the information.  But, unfortunately, nothing has
           materialized up to now.  We have not signed a single
           agreement with any of these countries.  You know,
           that's one of the most frustrating parts of this
           activity right now.
                       MEMBER FORD:  And do you have a backup
           plan should those agreements not take place?
                       MR. ELTAWILA:  Our backup plan is to go to
           the Commission and say, "We will have to develop this
           data, all of it, ourselves."  And which I think that
           will be -- will put some of this, like the PBMR
           schedule, in jeopardy because some of these data are
           very crucial for --
                       CHAIRMAN APOSTOLAKIS:  Do they have any
           incentive to cooperate with you?  Is there any benefit
           to them?
                       MR. ELTAWILA:  The benefit is that we
           definitely -- we are going to be doing research, and
           we'll try to exchange the information.  It's just
           government-to-government communication and the
           exchange of information is not that easy as a lot of
           people think it is, you know, including our
           Commissioner.
                       Our Commissioner believes that we should
           have had all of these agreements signed by now, but
           it's just not happening that fast, you know.
                       CHAIRMAN APOSTOLAKIS:  It's still not very
           clear to me, but, anyway, let's go on.
                       MR. ELTAWILA:  Okay.  With that, I will
           ask John to complete the presentation.
                       MR. FLACK:  Okay.  My name is John Flack.
           I'm the Branch Chief of the Regulatory Effectiveness
           and Human Factors Branch, which also has the advanced
           reactor group.  
                       I know we're time limited, and Farouk
           covered a number of things, so I will briefly -- I
           will go quickly through the viewgraphs.  And please
           slow me down if you need more information.
                       CHAIRMAN APOSTOLAKIS:  Don't worry.
                       MR. FLACK:  The plan was actually created
           with a number of --
                       CHAIRMAN APOSTOLAKIS:  Does this committee
           have a reputation that it does not ask enough
           questions?  Because every speaker who comes here
           encourages us not to hesitate to interrupt them.
                       (Laughter.)
                       Do we have a record of not interrupting?
                       MR. ELTAWILA:  For the record, I did not
           ask you to --
                       CHAIRMAN APOSTOLAKIS:  Is our image so
           terrible that --
                       (Laughter.)
                       MEMBER POWERS:  We're very shy.
                       (Laughter.)
                       We're tiring.
                       CHAIRMAN APOSTOLAKIS:  Okay.  John, we
           appreciate your --
                       MR. FLACK:  Okay.
                       CHAIRMAN APOSTOLAKIS:  I know it was well
           meaning.
                       MR. FLACK:  Thank you.  The plan itself
           had been created by -- over 20 authors actually wrote
           parts of the plan.  Many of them you'll find in the
           room today, so what I'm -- I'm offering you an
           opportunity, if there's anything technical that you
           want -- you've seen in the plan or you hear here
           today, we have the people here that --
                       CHAIRMAN APOSTOLAKIS:  Would you please
           introduce your colleagues?
                       MR. FLACK:  Oh, I'm sorry.  Mr. Rubin to
           my left.  Stu has been the -- in addition to work in
           the fuels issue on the HTTR, he is also the project
           manager on the pebble bed reactor.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. FLACK:  And Joe Muscara to my right
           prepared most of the material and the plan on
           materials, primarily high temperature materials and
           graphite.  Don Carlson also works in our group and has
           prepared most of the material on the nuclear analysis
           part of that, for both material and reactor safety.
                       CHAIRMAN APOSTOLAKIS:  Very good.
                       MEMBER KRESS:  When I read the plan -- by
           the way, I like the way it's organized.
                       MR. FLACK:  Oh, good.
                       MEMBER KRESS:  Yes.  It makes it very,
           very well put together to know what the issue is and
           what it -- but when I read it, most of it sounds like
           it was written by one person, except when you get to
           the materials part that sounds like -- a little
           different.  But did one person write most of that?
                       MR. FLACK:  No.  Actually, well --
                       MEMBER KRESS:  It was put together by a
           bunch of people, huh?
                       MR. FLACK:  We tried to establish a
           certain format I'll cover in a minute, but I'm trying
           to get that information out.  But what was important
           about the development of the plan is we didn't want it
           to be issue driven; in other words, try to figure an
           issue and then what research you need to resolve the
           issue.
                       What we were really focusing on is the
           infrastructure, the ability to ask the right
           questions.  And so we started -- well, I'll get to it,
           but we started from that perspective, what are the
           tools, what is the expertise that we're going to need,
           rather than try to identify issues.
                       But, in the end, I do have viewgraphs on
           some of the issues we see already -- technical issues
           that could bubble up to be safety issues, that could
           bubble up to be policy issues -- and we'll go through
           that towards the end.
                       Farouk went over many of the objectives of
           the -- the reason why we put together the plan.  Some
           of these I've just summarized on this viewgraph,
           trying to identify the areas, the expertise, having
           the plan as a communication tool, so people understand
           what we're trying to achieve.
                       MEMBER ROSEN:  But wait a minute.  Now,
           it's not to build an advanced reactor research
           infrastructure.  It's really to build an advanced
           reactor research infrastructure for three or four
           selected concepts.
                       MR. FLACK:  That's right.  The scope is
           there, it's only limited -- the scope of the plan
           right now is limited to the four concepts that we have
           on the table.
                       MEMBER KRESS:  You should read advanced
           reactor as these four concepts.
                       MR. FLACK:  That's right.  That's right.
                       CHAIRMAN APOSTOLAKIS:  And also --
                       MEMBER ROSEN:  Which may change tomorrow
           if somebody else brings another concept in with an
           application.
                       MR. FLACK:  Well, the idea is to see what
           we'd need to do.  We have an infrastructure in place. 
           It's what additional work or additional tools above
           and beyond what we have already.  So with these four
           concepts coming in, we already see that we're going to
           need new data, additional tools, and at that -- we're
           looking at it from that perspective.
                       If another concept came in, we'll have to
           see what tools can be applied to that concept.  And if
           there needs to be something new developed, then we
           would take it from there.
                       MEMBER ROSEN:  But, as you know, there
           were something like 19 concept sets in the DOE
           Generation IV program, which really meant that there
           were something like 75 or 80 concepts that were looked
           at overall.  So there's lot of concepts out there.
                       MR. FLACK:  Right, right.
                       MEMBER ROSEN:  Some day -- so you need a
           program that -- a thinking process that sets you up to
           be ready to respond to whoever comes in with whatever
           concept.
                       MR. FLACK:  Well, you have to have that --
                       MEMBER KRESS:  You can't do that for all
           of them.  I mean, you just don't have the resources.
                       MEMBER ROSEN:  What I think is the list of
           the four has some of the things that we might have to
           work on in the next decade, but it certainly doesn't
           have all of them.
                       MEMBER KRESS:  Well, it probably
           encompasses a good many of them.
                       MEMBER ROSEN:  But it would be clearly a
           mistake to believe that because the Commission has
           picked those four that that's all that will ever be
           brought to the table here and --
                       CHAIRMAN APOSTOLAKIS:  From 4 to 80 is a
           factor.
                       MEMBER KRESS:  Yes, but I don't think --
           to think in terms of which ones of these others might
           make it to NRC, and then try to prepare --
                       MEMBER ROSEN:  No, but you don't have to
           think about it.  You can just simply ask -- go out and
           see what people are doing.
                       MEMBER KRESS:  Well, I think their comment
           that they try to -- try to make the -- at least the
           acceptance criteria in the regulations reactor type
           neutral is a good way -- is a good thing to do to
           anticipate that.
                       MEMBER ROSEN:  It is.  I agree with that.
                       CHAIRMAN APOSTOLAKIS:  Now, the overall
           objective, is it really to build an advanced reactor
           research infrastructure, or is it to build the
           infrastructure that would allow you to license
           advanced reactors?
                       MR. FLACK:  Now, there's a distinction
           between the infrastructure, one being called
           regulatory infrastructure and one called research
           infrastructure.  What we're talking about, at least
           aside from the framework, we're really talking about
           research infrastructure.
                       CHAIRMAN APOSTOLAKIS:  But the objective
           ultimately is to support licensing.
                       MR. FLACK:  That's right.  Which will get
           us through the next phase of this plan that --
                       CHAIRMAN APOSTOLAKIS:  So that's what you
           should say, actually, right?  I mean, to build an
           advanced reactor research infrastructure, why?  This
           is a regulatory agency here.
                       MR. FLACK:  Well --
                       CHAIRMAN APOSTOLAKIS:  Only to the extent
           that it's required for licensing.  We've been told by
           the Commissioners many times, they have said it in
           public, this is a regulatory agency.
                       MR. FLACK:  That's right.
                       CHAIRMAN APOSTOLAKIS:  It's not the
           National Science Foundation.
                       MR. FLACK:  That's right.
                       CHAIRMAN APOSTOLAKIS:  So the overall
           objective probably needs to be reworded.
                       MR. FLACK:  Yes.  And it's driven a lot by
           regulatory needs.  
                       CHAIRMAN APOSTOLAKIS:  Of course.
                       MR. FLACK:  In fact, that was my next
           viewgraph was to say, where are we going on the second
           phase of this plan?  If I can jump to that, we can --
                       CHAIRMAN APOSTOLAKIS:  Of course you can.
                       MR. FLACK:  -- talk to that issue a little
           bit more.
                       The first phase of the plan was really to
           get out everything on the table as -- that we know it
           today, with no constraints to resources, and so on. 
           And so we held workshops, we had the preapplication
           review to capitalize on, we had talked -- we went
           around the world looking at what was out there.
                       So we're coming to the end of this first
           phase, and, actually, with this meeting, which will be
           the second phase of this research plan.  And the
           second phase of this research plan is really what
           focuses on that particular issue that you just brought
           up, George.  It's to set up working groups with the
           user offices now that we've seen -- and we gave
           everything -- put everything out on the table.  What
           is it that we really need to do now?
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MR. FLACK:  Okay?  And that's going to be
           the next phase, and we see this phase coming to
           completion.  The next time we come to the committee we
           would be more focused on that particular issue of
           supporting the process, the regulatory process in the
           global sense, and then going to the Commission with
           that plan at that time.
                       And then, the third phase is really to
           maintain it a living plan, to pick up new designs as
           they come in, see what delta needs to be done, what
           new tools we need to develop, and to state engaged in
           that Generation IV activity, to see if these things
           are materializing to the point where we need to start
           getting serious about something.
                       MEMBER FORD:  Now, how does the
           prioritization judgment come about?  Given the fact
           that your resources are undecided, management
           resources like collaborative agreements, people,
           dollars.  That's not a fixed amount right now.  So
           your prioritization is going to presumably change with
           time, isn't that correct?
                       MR. FLACK:  Well, I think Farouk might
           want to --
                       MR. ELTAWILA:  No.  I think the -- our
           budget and resources has been established for the next
           three years, you know, that at least to -- our 2003
           budget is fixed, and 2004 and 2005 is proposed to the
           Commission.  And we will try to prioritize within
           these budget constraints.  
                       And if we're going to be using the same
           PPM process, and we'll be competing with other
           operating events that depends on the priority, we'll
           be funding this research based on the available
           budget.
                       MEMBER FORD:  No, I recognize that. 
           That's how you're going to spend your money on your
           people and subcontractors.  But what happens if one of
           the priorities that -- technical priorities -- work on
           graphite, for instance.
                       MR. ELTAWILA:  Okay.
                       MEMBER FORD:  That work has been done in
           Britain, for instance.  And what happens if the Brits
           decide that they don't have to give you that data for
           whatever reason?  What happens?
                       MR. ELTAWILA:  The first point, that we
           are going to be asking the applicants to provide us
           for the data to support their case, and then based on
           the information we're provided we'll see what
           additional information we will be -- we need to
           develop ourselves.
                       MEMBER FORD:  Okay.
                       MR. ELTAWILA:  It is not very easy for a
           regulatory agency to try to develop a research
           program.  It has to be issue-driven, as George
           indicated, that we -- everything has to be related to
           the licensing process that we are working on.
                       CHAIRMAN APOSTOLAKIS:  I think the overall
           objective should be reworded to reflect that.  I mean,
           I appreciate the phases, but you said overall
           objective.
                       MR. ELTAWILA:  Okay.
                       CHAIRMAN APOSTOLAKIS:  Ultimately, that's
           what you're going to do.
                       MEMBER KRESS:  I think it's implicit in
           everything already anyway.
                       CHAIRMAN APOSTOLAKIS:  Another thing I
           noticed when I read the report is that you list
           everybody's workshops except the ACRS.  Was there any
           reason?  Did you find it useless?
                       MR. FLACK:  No.  There's no reason why we
           missed that.  That was an important oversight.  Thank
           you.
                       CHAIRMAN APOSTOLAKIS:  Maybe it was not
           very useful to you.
                       MEMBER POWERS:  Maybe they just didn't
           like our --
                       CHAIRMAN APOSTOLAKIS:  That's I thought,
           too. 
                       MEMBER POWERS:  Nothing useful emerged
           from it.
                       (Laughter.)
                       CHAIRMAN APOSTOLAKIS:  You list
           everybody's workshops, the dates and this and that. 
           Of course, it will never bias our views, but --
                       MEMBER ROSEN:  You're too sensitive,
           George.
                       CHAIRMAN APOSTOLAKIS:  I am not too
           sensitive.  I'm just sensitive.
                       (Laughter.)
                       MEMBER LEITCH:  The second bullet is --
                       CHAIRMAN APOSTOLAKIS:  Commissioner Diaz
           was there.  He gave the keynote speech.  Maybe the
           staff doesn't think much of what the Commissioner
           said.
                       MR. FLACK:  I think if -- you'll find --
           I'm sure I've seen it in there somewhere.
                       CHAIRMAN APOSTOLAKIS:  It is not here. 
           John, it is not here.
                       MR. FLACK:  It might have got scratched
           the last time.  I don't know.
                       (Laughter.)
                       MEMBER LEITCH:  The second bullet there,
           Johns, is there some reason the AP-1000 is not on that
           list or --
                       MR. FLACK:  No, that should really be on
           there.  It was for examples, and I was --
                       MEMBER LEITCH:  It says "for example," and
           I was just wondering if it --
                       MR. FLACK:  Yes, they're all HTTRs.  I
           should have put a light -- yes, a light water reactor
           on there.  Yes.
                       MEMBER ROSEN:  There's an astonishingly
           pervasive gas reactor focus on this, because of the --
                       MEMBER KRESS:  Well, you're almost through
           with the AP-1000 preapplication review anyway.
                       MR. FLACK:  Yes.  The preapplication is
           done, in fact.  I think the --
                       MEMBER KRESS:  Is that correct?
                       MR. FLACK:  But most of the gap that we
           see is in the high-temperature gas-cooled area, so,
           you know -- but we have an infrastructure in place
           pretty good for a light water reactor.
                       Okay.  I think we pretty much touched upon
           this.  The meaning on infrastructure, again, is the
           staff expertise, the tools, the facilities, contractor
           support, and the scope being the four reactors as we
           see it today.  And the structure -- and, again, we
           built the structure around not the issues themselves
           but on the technical areas, which you'll see in a
           moment.
                       MEMBER POWERS:  John, before you take that
           down, let me ask you a question about technical
           approach on this.  The second item on your list there
           is called analytic tools and analysis methods.  And
           one of the challenges that we repeatedly come up with
           when we look at things connected with current reactors
           and modest changes to those current reactors, like the
           AP-1000, is that many, many, many of our analytic
           tools going from simple neutronics through thermal
           hydraulics to fission product release had their origin
           in an era when the computing capabilities that people
           had were widely different than what it is now, and
           probably we'll see in the next 10 years even more
           dramatic changes.
                       Yet your plan doesn't seem to act upon
           those things.  I mean, it doesn't seem to take that
           into account.  There is lots of things like, well, we
           can take TRACM and put another patch on it, we can
           take MELCOR and gerry-rig it to handle something else,
           rather than saying, "Hold it.  We really have
           undergone a computer revolution here."  The way we do
           computing, the way people do coding now, it's just
           very, very different than what it was when our codes
           had their origin.
                       Maybe it's an opportunity for us to bring
           our codes up and to recognize that the hardware has
           just changed, and what not.  But your plan didn't seem
           to delve into that kind of an approach.
                       MR. FLACK:  You know, it's an excellent
           subject for a subcommittee, I think, to revisit this
           particular issue.  You're right.  We're really
           building on things that already have been developed
           and seeing where we're going to -- how can we extend
           them rather than go back to -- you know, and look and
           see is there a better way of doing this.  And I think
           it's an excellent question.  We just -- just built on
           what we have.
                       I know TRACM is improving, of course, has
           come quite a way from -- just in the Fortran part of
           that.  But as far as starting with something new --
           and this may be an opportunity to do that for these
           gas-cooled reactors, where you may have one code,
           because of the nature of the beast, that you don't
           have the core melt and the accident progression and
           that -- you have a fission product release over time
           and temperature and using one code to deal with the
           whole spectrum, right out into the environment, might
           be a way to go.
                       MEMBER POWERS:  One of the things that it
           seems to me that -- you know, in trying to think about
           the future, and you put it right up front in your
           plan, you say, gee, you know, we're going to move to
           a probabilistic risk assessment kind of framework. 
           And whereas I -- I know for a fact that a lot of our
           probabilistic risk assessment tools are kind of
           patchwork things.
                       They work pretty well until you get to the
           questions of, gee, let's do some of these
           deterministic analyses for a bunch of scenarios.  And
           then we run into a problem that our codes are fairly
           archaic.  And if somebody wants to run 150 MELCOR
           sequences, for instance, you know, you're -- and
           that's an enormous number for a probabilistic risk
           assessment; 150 is actually a fairly modest number.
                       You really are buying yourself a pretty
           big chore here.  So if you -- you know, if you were
           looking to say I want to make bigger use of
           probabilistic techniques in my licensing process, I
           want to have more assessments of them, I want to take
           that probabilistic technique deeper into the accident
           sequences, rather than just looking at Level 1 I
           actually want to go deeper into Level 2, and things
           like that, then my phenomenological tools, both
           thermal hydraulic and structural techniques and things
           like that, have to be better.
                       You might really come to the conclusion
           that you need to invest some in your tools, and that's
           regardless of what goes on in DOE land or in the
           vendor's land, that you really do need to encourage
           the Commission to get you the resources to develop
           your thing.
                       I mean, I guess my thinking on this is
           that, for instance, the thermal hydraulic area you
           have some people that are pretty qualified getting
           TRACM as a consolidation.  And that's going to be
           awfully useful for existing reactors, but I bet you
           they don't find it very satisfactory for looking at
           very innovative kinds of thermal hydraulics things
           where the analyses go, I think as you say in the
           document, instead of working on time scales of a few
           hours you're starting to work on time scales of days
           and things like that.
                       MR. ELTAWILA:  John, can I try to address
           this issue?  
                       Dana, you are raising a very good issue. 
           But I just -- actually, our problem is not really the
           speed of the computer, because you continue to enhance
           that, and the machine speed itself will make up for
           the difference.  
                       But the biggest problem is trying to
           develop a code.  You have to have a target that this
           code is going to be better than what we have right
           now.  And we really don't have the data to support
           development of models that we'll be able to put in
           this code.
                       So going -- embarking on a code
           development program, without having the supporting
           experimental data, will be just a waste of resources. 
           And we face that issue early, you know, when we are
           thinking about either developing a new thermal
           hydraulic code versus consolidating the existing code
           into a single code.  
                       And we'll get a group of experts, and they
           all advise us against developing a code from scratch,
           because we're going to end up -- the code is going to
           be slow because of the limitation of the model, not
           because of the machine.  
                       So unless somebody is willing to invest a
           few hundred million dollars in developing the data to
           support this fast running code with accurate, better
           models, I think going into the development of faster
           code is not going to be the best way we put our money
           to work.
                       MEMBER ROSEN:  I'd like to add that,
           although it's probably true, that many of the codes
           that we'd be looking at using in licensing reviews are
           built on older, previously developed codes.  There may
           be some pockets where there are new codes being
           developed in the current computing environment.
                       And I would give as an example in the fuel
           performance area, the European Commission has a high
           temperature reactor fuels task group in place.  And
           one of the areas that they are doing work in is to
           develop fuel performance models today.  And those fuel
           performance codes will be developed, obviously, in the
           current computing environment.
                       Also, INEEL, working with MIT, I believe,
           is developing fuel performance models and codes to
           predict fuel failure, etcetera.  So there are a few
           examples at least where codes are being developed in
           this environment.
                       MEMBER POWERS:  Well, I, of course, have
           come to learn that fuel research is irrelevant, so --
                       (Laughter.)
                       MR. ELTAWILA:  That's the subject of
           another meeting.
                       (Laughter.)
                       MEMBER POWERS:  I couldn't resist.
                       MR. FLACK:  We'll move right along on
           that.
                       Basically, to your comment, Tom, on how we
           structured the report was around three questions --
           why we -- why is it important for us to do this
           research, what it is we would actually do, and then
           how would we use the results.  And we tried to keep
           each of the people focused.
                       MEMBER KRESS:  And I thought that was very
           good.  It was very helpful in reading it.
                       MR. FLACK:  And the research plan
           structure, which is -- has been developed, and this
           was developed to sort of try to get the completeness
           of the work that we're doing.  We actually started,
           again, not from an issue perspective but from the top
           down, and we began -- well, we started by looking at
           the arenas that we would be working in as far as
           research is concerned.  Well, as you can see, most of
           it is reactor safety.
                       We're looking and pressing into these
           other arenas to see what work can be done, since most
           of the work that we do involves reactor.  So there is
           some of it discussed as far as nuclear waste and
           materials safety, and then, of course, safeguards. 
           Again, we're pressing that area.
                       But within the reactor safety arena, we
           laid out the work more or less along the lines of the
           cornerstones of safety.  And bringing that down
           further, going from accident -- starting from right to
           left, accident progression to initiating events, which
           dictates the sort of scenarios we need to look at as
           an office on a particular plant design, and then from
           there -- which actually sets the stage for the rest,
           coming down to look at accident analysis and what area
           or what technical work needs to be done in that area.
                       It's primarily driven by the PRA and those
           things that -- that influence the PRA, like human
           factors and I&C.  And so in these areas PRA was
           generally that part of the research under Mark
           Cunningham, as you know, Mary Drouin, and Alan Rubin,
           and John Ridgely.  And on the plant analysis it's
           primarily the human factors and I&C, which is Steve
           Arndt for I&C and Jay Persinski for human factors.
                       Moving across from there, from left to
           right, the next large area is the reactor systems
           analysis, which is primarily in Jack Rosenthal's
           branch.  And under that being the thermal hydraulics,
           the nuclear analysis, and the fission product
           transport work.
                       MEMBER POWERS:  You felt that it was --
           that the computational tools you have available to you
           for doing probabilistic risk assessment -- the actual
           analysis itself, you know, calculating out the
           probabilities, that those were in such fine shape that
           they deserve no improvement at all?
                       MR. FLACK:  Well, no, I don't think that
           would be the case.  There's really -- I don't know if
           Mary wants to respond to that, but there's really
           three areas there in PRA that we see as being --
           pushing our needs, and that is initiating event
           frequency for the high-temperature gas-cooled
           reactors.
                       MEMBER POWERS:  Yes, but those are data
           things.  I'm talking about the actual computational
           tools.
                       MR. FLACK:  Oh, the computational tools? 
           Do you want to comment on that, Mary?
                       MEMBER POWERS:  The way you go about doing
           the analyses.
                       MS. DROUIN:  I agree that there is going
           to need to be some research in the development of some
           of these tools, particularly in the computational
           area.  And that's --
                       CHAIRMAN APOSTOLAKIS:  But the report I
           think says that SAPHIRE will be used for the PRA. 
           Isn't that so?  That's what the report says.
                       MR. FLACK:  Yes, that's right.
                       MS. DROUIN:  SAPHIRE is a starting base,
           absolutely.  I mean, I would not like to think we
           would just start with a clean piece of paper and not
           take a tool that we already have and see where we can
           use it, modify it appropriately.
                       MEMBER POWERS:  At least through the
           classical Level 1 for normal operating events, the
           computational pathway is fairly straightforward, I
           think, Mary.
                       MS. DROUIN:  Yes.
                       MEMBER POWERS:  And adequately -- the
           blocks that you need are adequately there in SAPHIRE,
           maybe the computational way it's done.
                       The issue, it seems to me, that's been
           raised so clearly by the eminent Dr. Kress is that
           that computational framework may not be adequate if we
           were to extend the way we do PRA from an operational
           events to include all plant operational states.
                       I think that's a conclusion that has come
           from your own studies in looking at the other
           operational events, that the tool you have may not
           have all of the computational elements you need to do
           all operational states.
                       MS. DROUIN:  I don't disagree.
                       MEMBER POWERS:  And as we know, we trust
           you implicitly, because you're one of my heroes,
           right?
                       MS. DROUIN:  Absolutely.
                       (Laughter.)
                       MEMBER POWERS:  I told you I'd get it on
           the record.
                       (Laughter.)
                       MS. DROUIN:  But, you know, when you get
           into -- there's a lot of technical issues,
           particularly in the Level 2 when you start looking at
           the advanced reactors, and this will have a direct
           impact, then, on the calculational tools we use and
           where we'll be needing to do some work.
                       And right now we are in the midst of
           trying to -- when you look at the RES plan, you know,
           that plan there, when it gets into the PRA part, is
           very high level.  We are in the midst of trying to put
           together a very detailed plan of what we mean by that
           three-page plan in the RES-1.
                       MEMBER POWERS:  I'd like to see that. 
           That would be interesting.
                       CHAIRMAN APOSTOLAKIS:  If I look at
           this --
                       MS. DROUIN:  We do plan to come to the
           ACRS with it.
                       CHAIRMAN APOSTOLAKIS:  If I look at this
           figure, I see the acronym -- actually, it's
           initialism, right?  PRA?  It's an initialism.  Down
           there on the left.
                       But it seems to me that, you know, again,
           your report shows that the thinking is really that --
           if you look at the out within the four boxes, and so
           on, you will be looking at the accident sequences all
           the way from the initiating event all the way to
           offsite protection or somewhere in between, and use
           that information in your decision-making processes. 
           And that's PRA, is it not?  So it is a little bit
           misleading the way it's shown there.
                       MR. FLACK:  Under "accident analysis," do
           you mean?
                       CHAIRMAN APOSTOLAKIS:  Yes.  I mean, it's
           pervasive.  It's --
                       MR. FLACK:  Yes, that's true, very much
           so.  There was another figure in the report that shows
           these loops of information, how it flows between the
           groups, which I don't have with me.  But you're right,
           there is always this feedback mechanism, both within
           the groups and background PRA.  In fact, that's the
           way the office does work.  PTS is an example where you
           bring in, you know, the PRA people with the materials
           people with the thermal hydraulic folks and --
                       CHAIRMAN APOSTOLAKIS:  Well, the biggest
           question, really, here would be, how are you going to
           use the PRA?  I mean, right now, in the most important
           decisions the agency is making PRA is very peripheral. 
           It doesn't really play any role.
                       MR. FLACK:  In your regulatory decision-
           making or the use --
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MR. FLACK:  -- in the --
                       CHAIRMAN APOSTOLAKIS:  Regulatory, like
           license renewal, power uprates, PRA really doesn't do
           much there.  I mean, it's just, oh, by the way, this
           is the number we got from the CDF.
                       MEMBER KRESS:  And even in direct
           licensing.
                       CHAIRMAN APOSTOLAKIS:  And in what?
                       MEMBER KRESS:  Just licensing a plant
           doesn't seem to play a role.
                       CHAIRMAN APOSTOLAKIS:  Well, we're not
           licensing anybody.  That's what --
                       MEMBER KRESS:  Well, we will be.
                       CHAIRMAN APOSTOLAKIS:  Yes, that's what
           I'm saying, that this will be --
                       MEMBER KRESS:  Same thing is the license.
                       CHAIRMAN APOSTOLAKIS:  I mean, so that
           will be a major challenge, I think, how to use that,
           how to actually use it.
                       MR. FLACK:  Yes, we're moving towards the
           framework box there, I think.
                       CHAIRMAN APOSTOLAKIS:  You're going to
           talk about it separately?
                       MR. FLACK:  If you'd like.  Do you want to
           talk about it --
                       CHAIRMAN APOSTOLAKIS:  Do you plan to talk
           about it?  Are you planning --
                       MR. FLACK:  Well, we can talk about it to
           a certain extent.
                       CHAIRMAN APOSTOLAKIS:  Well, that, it
           seems to me, would be a major challenge.
                       MR. FLACK:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Because the
           Regulatory Guide 1.174 doesn't apply here.  I mean,
           that's for changes in the licensing process.
                       MR. FLACK:  Right.  That's right.
                       CHAIRMAN APOSTOLAKIS:  And you don't have
           a licensing basis here.  So it's really using this as
           part of your integrated decision-making process.
                       MR. FLACK:  That's right.  It is --
                       VICE CHAIR BONACA:  They show Option 3 as
           a foundation for this.  Option 3 has a very specific
           apportionment of certain goals --
                       CHAIRMAN APOSTOLAKIS:  I understand that. 
           I understand that.
                       VICE CHAIR BONACA:  -- which are really
           measurement for PRA.  So there is some structure that
           you can put inside here already.
                       MR. FLACK:  Yes.  But the point I think is
           that we're dealing with plants already built, and
           we're applying PRA concepts to those plants in the
           sense of changes.  And now we're thinking, well, what
           are we going to do with respect to regulatory
           decision-making on future plants that haven't been
           built?
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MR. FLACK:  And that gets us -- I think
           pushes us into this framework, what do we need?  And
           there's really two pieces going on there.  One is this
           blank sheet of paper starting from a clean approach,
           which is -- there is going to be work initiated next
           year, and there's work going on in NRR is -- how do we
           transition to that?  
                       And Mary can talk about the part about the
           research plan, and Jim Lyons could talk about the NRR
           approach that's now taking place, from that
           perspective.  So they're coming together in some form.
                       Mary, did you want to --
                       CHAIRMAN APOSTOLAKIS:  Well, you are
           basing it on Option 3, right?
                       MS. DROUIN:  Well, if you remember, the
           Option 3 framework has, you know, three parts to it. 
           It has -- started with, you know, what we call that
           hierarchical structure.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MS. DROUIN:  You know, a top-down
           approach.  And then, because it is risk-informed, it
           brings in how you bring in defense-in-depth both at
           the hierarchical, from the top down and the bottoms
           up, and then brings in, how do you bring in your
           quantitative guidelines?  And ultimately that is
           producing the criteria and guidelines that you would
           be using to help you in your decision-making process
           throughout your licensing.  
                       In terms of your earlier question, you
           know, the PRA and the framework and -- it's like
           they're all very intricately tied, and one of the ways
           that you do use your PRA, you know, would help in your
           decision-making also in terms of how much research,
           using that word loosely here, that you would need,
           because you certainly don't want to pursue an area
           that, from your PRA perspective, you don't need it to
           support the PRA, and you don't need it for -- it's not
           going to help you, and it's not going to contribute
           significantly to your risk is what I'm saying.
                       CHAIRMAN APOSTOLAKIS:  Well, the point,
           though, is -- I understand what you're saying, Mary. 
           But this is really something that is an ideal
           situation.  I can't imagine, for example, the guys who
           will be working on the reactor plant analysis and fuel
           analysis will be willing to take their criteria and
           objectives from the PRA guys.  They will just --
                       MS. DROUIN:  As an input.
                       CHAIRMAN APOSTOLAKIS:  That would be one
           of the angles to their integrated decision-making
           process which would have, I think, other major, major
           inputs.
                       MS. DROUIN:  Yes.
                       CHAIRMAN APOSTOLAKIS:  So the question
           will be, you know, to what extent will there be --
           will the PRA inputs influence that, or they will say,
           no, you know, defense-in-depth and safety margins is
           really the name of the game.
                       MS. DROUIN:  But that's where you're -- I
           mean, what we're calling it, the framework or the
           decision-making criteria comes in and provides you
           guidelines on that and how you bring in your defense-
           in-depth, your uncertainties, your safety margins, and
           your risk insights, and how you blend all of those
           together in your decision-making process.
                       CHAIRMAN APOSTOLAKIS:  Which we don't have
           right now.  We don't have those guidelines right now.
                       MS. DROUIN:  That is what we're going to
           be developing.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MS. DROUIN:  Where we're starting with
           Option 3.  Now, you can't just adopt Option 3, because
           Option 3 is, how do you make current changes?
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MS. DROUIN:  And so there -- you'd have
           other questions that you're going to have to answer,
           because we're not just making current changes, you
           know, in cases you're starting new.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MS. DROUIN:  So when you're starting new,
           you've got to --
                       CHAIRMAN APOSTOLAKIS:  Well, frankly, I
           don't know how you can use PRA in light of Davis-
           Besse.  That was, I thought, a major blow to the whole
           risk cause.  I mean, unless we recognize that.  I
           mean, 10-4 means nothing to me now.
                       MEMBER ROSEN:  In the case of PBMR, and we
           believe GT-MHR, they have proposed a licensing
           approach, which the staff has reviewed.  And I think
           we have briefed the committee on the licensing
           approach, and it is very much PRA-based, in the sense
           that licensing basis events are randomized for
           probability and consequences.
                       And they are put into the framework or
           approach that they utilize for operational events,
           design basis events, and beyond design basis events. 
           And I think it would be useful to have a PRA -- the
           staff to have its own PRA to kind of review those
           applicant placement of those events within that
           framework.
                       CHAIRMAN APOSTOLAKIS:  But, you know,
           about I think three years ago or so, or maybe longer,
           there was a major issue that was raised.  I think it
           was before 1.174 was published.  People, especially
           from the industry, were complaining that PRA was just
           another burden, that we had to do everything, you
           know, the regulations said, plus a PRA, to get those
           additional insights.  
                       So if we are to use it now, somehow those
           other requirements will have to be effective, and
           maybe some of them should be eliminated.  And I --
           this is where I think will be a major problem, how to
           do that, because we're going to have, again, the same
           philosophical conflict.  Okay?  And I think the Davis-
           Besse incident gives arguments to the structuralist
           defense-in-depth.
                       MEMBER ROSEN:  If you're correct, George,
           that --
                       CHAIRMAN APOSTOLAKIS:  They're about to
           win me over.
                       (Laughter.)
                       MEMBER ROSEN:  I think you would be
           correct if all 100 plants had that problem.
                       CHAIRMAN APOSTOLAKIS:  Hmm?
                       MEMBER ROSEN:  If all 100 plants had that
           problem.  We're talking about a plant.
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MEMBER ROSEN:  One of 100 or so.  So --
                       CHAIRMAN APOSTOLAKIS:  I missed that.
                       MEMBER ROSEN:  Well, I'm just responding
           to your point that the event -- that Davis-Besse
           invalidates all of the probabilistic thinking.
                       CHAIRMAN APOSTOLAKIS:  I didn't say it
           invalidates, but it creates serious questions in my
           mind.
                       MEMBER POWERS:  George, I --
                       VICE CHAIR BONACA:  It goes back to the
           proposal.  It has a means of filling the gap in the
           Code of Federal Regulations.  I mean, in that sense,
           PRA has been extremely successful.  Here we've
           attempted to see -- it could play a primary role, in
           and of itself, rather than defense-in-depth, and
           that's really where concern comes.  Okay?  Can it be
           the first, you know --
                       CHAIRMAN APOSTOLAKIS:  Dana?
                       MEMBER POWERS:  Well, I guess I had two
           points.  One, just to respond to Steve, all individual
           plants have individual peculiarities that can be
           problems.  
                       To your point, George, as one of the more
           ardent of the structuralists on the committee, I'll
           tell you that, no, I still think PRA has a -- despite
           Davis-Besse, and what not, has a really admirable
           place to play within any kind of reactor system.  It's
           just that it doesn't play in the defense-in-depth
           argument from a structural point of view.  It plays
           very much in the redundancy, and what not, within
           systems.  
                       I still think it has a strong place to
           play there, and I think it will be an even stronger
           place to play in the advanced reactors where we can
           relieve much more of the ad hoc determinism yet again.
                       CHAIRMAN APOSTOLAKIS:  I think unless the
           PRA guys do a better job on model uncertainty it will
           not play such a significant role in the process.
                       MEMBER KRESS:  I think you're right,
           George.  That'll be a key.
                       CHAIRMAN APOSTOLAKIS:  I think the lambda
           stuff, the log normal stuff, is nothing.  It's the
           model uncertainty that drives the decisions.
                       VICE CHAIR BONACA:  I think one thing
           that, you know, impresses me more and more as we go
           forth is the -- some of the wisdom in 1.174.  You
           know, the whole concept of integrated decision-making,
           etcetera, that comes --
                       CHAIRMAN APOSTOLAKIS:  It's an ideal
           document.  But show me one case where it was applied.
                       (Laughter.)
                       There isn't a single case where this
           beautiful discussion on uncertainty was actually
           applied.
                       VICE CHAIR BONACA:  That's true.  You're
           right.
                       CHAIRMAN APOSTOLAKIS:  It's model
           uncertainty.  That's the name of the game.  The
           distributions in lambda don't mean anything, and I
           don't think we're doing a good job there.  I
           understand, you know, some of the tradeoffs that Dana
           mentioned, sure, they are meaningful, and so on.  But
           it's really model uncertainty that does the trick.
                       MEMBER POWERS:  Well, I bet we see -- I
           certainly hope we see good uses of it in the PTS
           stuff.
                       MEMBER ROSEN:  In the PTS stuff?
                       MEMBER KRESS:  Pressurized thermal shock
           stuff, yes.
                       CHAIRMAN APOSTOLAKIS:  Even there I think
           there was more promise than actually done.
                       MEMBER POWERS:  Well, we haven't seen the
           final story there.  But, I mean, that's -- well,
           certainly, you can't criticize a program because
           there's more promise than was actually done.  I can't
           think of any program that that's not the case, so --
                       CHAIRMAN APOSTOLAKIS:  There's no question
           about it, that it's a pioneering study.
                       MEMBER KRESS:  Well, Option 3, though, is
           still highly focused on light water reactors.  It
           talks about CDFs and LERFs and sequence frequencies
           that are endemic to light water reactors, and it tends
           to -- to allocate risk among CDF and LERF and allocate
           it among sequences, actually.  
                       And you won't run into a difficulty when
           you get to the -- trying to apply Option 3 in that
           sense to the gas-cooled reactors, because you don't
           have the equivalent number of sequences, you don't
           have the same ones, you have a different set of
           frequencies that are important, and you don't have a
           well-defined CDF or even a well-defined LERF. 
                       And so I think one of the things that
           you're going to buck up against is you'll need more
           precision in your definition of defense-in-depth for
           these reactors.  You just can't say anymore that it
           means a balance between containment and CDF.  You're
           going to have to be more precise, and it's going to
           have to tie in the uncertainty some way, even though
           you could still keep the structuralist view.  You're
           going to have to tie in to uncertainties in some way.
                       CHAIRMAN APOSTOLAKIS:  Well, that
           uncertainty has to be a realistic assessment of
           uncertainties, not just the stuff that's easy to do.
                       MEMBER KRESS:  Yes.
                       MS. DROUIN:  If you go back to Farouk's
           slide, one of the things that we have identified in
           developing, you know, this -- taking the Option 3
           framework and, you know, modifying it for advanced
           reactors, the primary thing was to look at the
           surrogates of CDF and LERF.
                       CHAIRMAN APOSTOLAKIS:  Yes.  Yes.
                       MS. DROUIN:  And that's one of the
           critical items there, that those may not be
           sufficient, and we may need to come up with different,
           you know, figures of merit here than just those
           surrogates, and come up with some others.  So that's
           one of the big items that we have ticketed to look at.
                       CHAIRMAN APOSTOLAKIS:  Now, coming back to
           this figure -- oh, I'm sorry.  I can understand, and
           I agree, that this thing, you know, by and large is an
           effective -- contributing to an effective regulatory
           process.  I just don't know that it's efficient.  You
           say effective and efficient.  How do you know it's
           efficient?
                       MR. FLACK:  Well, it's something you
           strive for.
                       CHAIRMAN APOSTOLAKIS:  But how?  I mean,
           if you ask the guys who were developing all of these
           rules in the late '60s/early '70s, I'm sure what they
           wanted to do was also be efficient.  And here we come
           20 years later and say they are not.
                       VICE CHAIR BONACA:  I think if you compare
           it to the existing system, I mean, probably the
           inclusion of the PRA considerations, the risk
           considerations, are making it more effective and --
                       CHAIRMAN APOSTOLAKIS:  I'd like to see
           that happen.
                       VICE CHAIR BONACA:  Well, no, because I
           think in some cases you will limit the -- the
           necessary burden, okay, that's the only -- I mean, to
           the extent --
                       CHAIRMAN APOSTOLAKIS:  Mario, you will be
           told it's defense-in-depth, period.  Do it.  Okay? 
           It's a new system, we don't know, we don't want to be
           surprised again.  And I think there's a lot to that
           argument.
                       VICE CHAIR BONACA:  Well, we have seen
           some, you know --
                       CHAIRMAN APOSTOLAKIS:  If in a mature
           technology we get things like Davis-Besse --
                       VICE CHAIR BONACA:  Yes, I know.
                       CHAIRMAN APOSTOLAKIS:  You know, I'm just
           putting myself in a situation of the poor PRA guy who
           says, "Your inspections will fail with probability .2
           over a number of years."  He's going to be crucified. 
           My inspectors never fail.  Are you kidding?  My
           inspectors will go there and find it in a minute. 
           Okay?  That's exactly what you're going to get.  It's
           the same thing you were getting before 1978.
                       My operators know what to do, and it's
           always my -- I don't know why they put that "my" in
           front.
                       (Laughter.)
                       I remember.  I was in a PRA, and we said,
           you know, how about if the operators don't know how
           to --
                       VICE CHAIR BONACA:  See, but let me just
           say this.
                       CHAIRMAN APOSTOLAKIS:  Are you kidding? 
           They will not know?
                       VICE CHAIR BONACA:  Yes.  But I don't
           think we can make too much -- in a Davis-Besse event,
           we have to learn more.  There were a lot of
           indications for a long time that something was wrong. 
           Now, at some point --
                       CHAIRMAN APOSTOLAKIS:  And where is that
           in the PRA?
                       VICE CHAIR BONACA:  Well, I'm only saying
           that there is a burden on operations to, in fact,
           respond to the indications that you have.  And in this
           case, we may have a case where they did not respond
           for years to this indication, that they had plenty of
           those.  And so I'm saying that you cannot address
           everything in your PRA.
                       CHAIRMAN APOSTOLAKIS:  It seems to me that
           you will never make progress unless you punish people
           for the mistakes they make.
                       (Laughter.)
                       The PRA should be penalized now for that.
                       MEMBER ROSEN:  The PRA should be
           penalized?
                       CHAIRMAN APOSTOLAKIS:  Well, or the PRA
           practitioners on the use of the PRA.
                       MEMBER KRESS:  You're just going to change
           -- you're going to change the frequency of medium
           break LOCAs.  That's all you're going to do.
                       CHAIRMAN APOSTOLAKIS:  How about the
           efficient, though?  How are you going to make sure
           it's efficient?
                       MR. FLACK:  Well, that was the -- the
           question is using these risk insights, which you think
           or believe at this point aren't doing what they should
           be doing, to utilize those and focusing your resources
           on the right things and being efficient by doing that.
           I mean, without that, I don't know, it's just
           judgment.  I mean, I --
                       CHAIRMAN APOSTOLAKIS:  Well, one way to do
           that is to really put a lot of meat to what Mary just
           said.  I mean, if you start from the top and with a
           PRA structure you go down and you put objectives, then
           you know why you are putting them there.  But the
           moment you start saying, "No, I'll do it because of
           defense-in-depth, then you are deviating from
           efficiency."
                       MR. FLACK:  Yes, it could be.
                       CHAIRMAN APOSTOLAKIS:  It may be for a
           good reason, but --
                       VICE CHAIR BONACA:  I still believe that
           the use of PRA in many areas where you don't have this
           kind of grayness is going to really yield much more
           efficiency.
                       CHAIRMAN APOSTOLAKIS:  How do you decide
           when you have grayness?
                       VICE CHAIR BONACA:  Well, I mean, you
           know, an area, you know -- I mean, certainly you have
           some indications where you have balance with
           information and mitigation that you do not want to
           compromise, and you're going to be very committed to
           defense-in-depth.  There are a lot of decisions,
           however, in the design of a plant where, you know, the
           inclusion of consideration of probabilities will help
           you be more effective and have less of a burden.
                       MR. FLACK:  I think in that role of
           knowing what's not important, I mean, we are always
           focusing on the PRAs, trying to point out what is
           important, which is a good thing.  But it also points
           out things that are not important, and for certain
           reasons, then, justify that.
                       I mean, you have to have a technical basis
           for it.  But, I mean, it's a thinking process that
           allows you to do that.  So, you know, I don't think we
           should throw the baby out with the bath water, I mean,
           on this.
                       CHAIRMAN APOSTOLAKIS:  You're more
           optimistic than I am.
                       (Laughter.)
                       VICE CHAIR BONACA:  But there was really
           practical terms.  And in the 15 years or 20 years of
           use of PRA in this approach, it has paid off
           tremendously for the utilities that use it in those
           kinds of decisions where you are not only affecting
           defense-in-depth, but you are making intelligent
           decisions on imposition of your requirements or
           elimination of those.
                       And we have seen some proposals that have
           been approved, and 1.174 -- they were really
           acceptable, have not been, you know, undermined by the
           experience with Davis-Besse.
                       VICE CHAIR BONACA:  I think there's got to
           be some efficiency brought in by that.
                       MR. FLACK:  Moving right along --
                       MEMBER KRESS:  Please continue.
                       VICE CHAIR BONACA:  I'm trying to convince
           you that PRA is --
                       (Laughter.)
                       MEMBER KRESS:  I can't believe we're
           having this discussion.  Continue, please.
                       MR. FLACK:  Okay.  So this is the process
           we use.  It's clearly -- it's a matrix approach.  We
           use the entire office resources as input to the plant.
                       Now, the next few viewgraphs I go through
           and identify the different technical areas.  I don't
           know if we need to spend much time on that.  It's in
           the plan.  Those are the areas that are being hit. 
           And that kind of leads us on to what the technical
           issues are that we're seeing now.  Maybe we can, for
           the sake of time, jump to that viewgraph.
                       MEMBER KRESS:  Well, let me ask you a
           couple of questions about the technical areas first.
                       MR. FLACK:  Okay.
                       MEMBER KRESS:  You know, you're asking us
           for -- whether you think you have the right scope or
           you're missing anything or something.  I thought it
           was very comprehensive.  In fact, there's so much in
           there I don't know how it could ever get done.  
                       But there were a couple of areas I was
           going to ask you about that I really didn't see in
           there.  And one of them was the issue of licensing by
           test.
                       MR. FLACK:  Licensing by?
                       MEMBER KRESS:  Test.
                       MR. FLACK:  Test.
                       MEMBER KRESS:  For PBMR.  I didn't see
           that discussed in there anywhere, and I was thinking
           there might be a section talking about the -- where
           would that fit into the regulatory structure at all,
           if at all, and is it part of the thinking, or is there
           any research need?  Like, you know, research in the
           sense of how that would affect your decision-making
           process, or what licensing by test actually means.  I
           didn't see anything on that.
                       MR. FLACK:  Well, we have been thinking
           about it.  I don't know if --
                       MR. LYONS:  This is Jim Lyons from NRR
           again.  This is one of the areas that we've looked at. 
           There is certainly the ability within Part 52 to
           license a prototype reactor, and then you would -- you
           know, and then you would perform tests on that
           prototype reactor, and then you could continue on with
           using that reactor as a way of developing your I guess
           licensing by test.
                       I don't know if we've really completely
           looked at how we would do that.  One of the things
           that may happen if we do a license by test or a
           prototype reactor is that we may put extra features or
           have -- you know, request extra features be placed on
           that plant to provide us any, you know, assurance that
           there wouldn't be any real problems.
                       But it's part of our process.  It's
           something that could be done, but I don't think that
           we saw any real need in the research area to address
           that.
                       MR. FLACK:  Yes, it's a difficult question
           to deal with until we actually get a plant in as well.
                       MEMBER KRESS:  Well, along this same line,
           one of the issues that is sure to arise with PBMR and
           GT-MHR, GA, just in general, is how do you know that
           you actually have the fuel quality that's required
           when you -- after you load it into the reactor.  
                       And one way to do that is what you do with
           light water reactors -- you look at the level of
           activity in the primary system, and you infer the
           quality of the cladding or the quality of the fuel
           from that.  And the question I would have is:  isn't
           there some concept like that being thought of for the
           pebble bed modular reactor and the others?  
                       So that during start-up of the operational
           phases you can say, "All right.  Based on what we see
           now, you don't have the fuel quality you said you were
           going to have in your licensing basis, so you've got
           to do something." Is that part of the plan?  Is that
           in there?
                       MEMBER ROSEN:  It's not in there as
           explicitly as you just described it, but it is in
           there implicitly.  The way I like to refer to it is a
           defense-in-depth on fuel performance during operation
           and postulated events.  And you can think of that
           defense-in-depth as building in quality absolutely
           correctly every time, and that focuses you on the
           manufacturing part of the process, to look at the
           process and the product specification, make sure
           you're doing it right every time.
                       MEMBER KRESS:  You would look at process
           versus product.
                       MEMBER ROSEN:  And that's in our plan.
                       MEMBER KRESS:  Now we're wanting to look
           at product, too.
                       MEMBER ROSEN:  Okay.  Then, look at the
           products.  But before it ever gets put into a reactor
           and starts operating, then you get to the next
           defense-in-depth place, which is monitoring
           operations, and looking at activity and monitoring
           conditions. 
                       The question comes up, though, is that
           method qualified?  Is that method reliable?
                       MEMBER KRESS:  Yes.
                       MEMBER ROSEN:  Is there data that shows
           that --
                       MEMBER KRESS:  That's exactly my question,
           yes.  Is there something in the plan that will answer
           that question?
                       MEMBER ROSEN:  Yes.  Yes.
                       MEMBER ROSEN:  Well, I think you have some
           advantages here, if you're thinking about pebble bed,
           that you don't have in light water reactor.  You could
           do destructive examination on the fuel.
                       MEMBER ROSEN:  That brings me to the third
           -- 
                       MEMBER ROSEN:  And you could afford it.
                       MEMBER ROSEN:  Yes, that's right.
                       MEMBER ROSEN:  But you couldn't do that in
           the light water reactor, say, I'm going to destroy
           this assembly and say, therefore, the other 80 are
           okay.  You know, that wouldn't be -- it wouldn't make
           any sense.  But if you're talking about thousands of
           pebbles, you can statistically sample them and do
           destructive evaluation and gain some real confidence
           as to the quality of the pebbles.
                       MEMBER ROSEN:  Right.  And that's --
                       MEMBER KRESS:  You can't, because they
           have to be irradiated.  And you're not going -- that's
           the problem.  You've got to run through the
           irradiation first.
                       MEMBER ROSEN:  That's the research issue
           is how do you identify, from looking at the
           destructive evaluation of a non-irradiated pebble, how
           an irradiated pebble is going to work.
                       MEMBER KRESS:  Yes.  You can't make that
           judgment.  You have to irradiate them, and that's
           where your statistical problem shows up.  You just
           can't irradiate enough of them to get the right
           statistics to qualify the level of failure or pebbles
           that you think you have to have.
                       MEMBER ROSEN:  So that's the answer to the
           research program, Dr. Kress?  I mean, I was suggesting
           that there ought to be a research program to get to
           that answer.  But if you already know it --
                       MEMBER KRESS:  Well, you have to -- you
           just can't irradiate enough pellets over the timeframe
           to do that.  You can't do it.
                       MEMBER ROSEN:  Well, the approach that's
           taken when you have billions, literally billions, of
           fuel particles in the reactor is to test hundreds of
           thousands in a materials test reactor to qualify them,
           and then, even if you --
                       MEMBER KRESS:  Yes, to the right
           irradiation level.
                       MEMBER ROSEN:  To the right conditions,
           temperature, fluents, burnup, whatever it is, and even
           if you have zero particle failures you don't
           extrapolate if you have zero in the billions.  There's
           a statistic that you can use to project what the
           number would be.
                       MEMBER KRESS:  But it's an extremely
           difficult task.
                       MEMBER ROSEN:  But the question comes up,
           are the test statistics going to hold true in the fuel
           that you make later?
                       MEMBER KRESS:  That's right, because
           you're only testing one batch.
                       MEMBER ROSEN:  In a sense, that's true. 
           So you need to show that that's going to continue over
           the life of the fuel supply and the life of the plant. 
           And so you're stuck with, well, how do I then monitor
           later on fuel that's coming off the assembly line and
           put in the reactor?
                       MEMBER ROSEN:  Well, these are good
           questions.
                       MEMBER KRESS:  But you're saying that's
           implicit in --
                       MEMBER ROSEN:  Yes.  And if you look at
           the plan, and you look under the fuel performance
           piece, you see something called fuel manufacture.  And
           our plan is to try to understand as best we can what
           are the really critical aspects of fuel manufacture to
           get quality in the product and also performance in
           reactor and in accidents.  And there is work going on
           internationally to try to understand what it is that
           in the process and the product specifications that
           will do just that.  So we're following that.
                       And the question comes up, should there be
           a regulatory footprint in some sense on that piece as
           a way of assuring defense-in-depth?  I think there's
           a general belief that we ought not to regulate the
           product but the performance, which puts you into the
           next step, which is looking at operating performance. 
           If you're going to have --
                       MEMBER ROSEN:  It would be preferable to
           -- in my view, to regulate the performance.  But in
           the case we're talking about, because of the
           importance of the product protocols, it seems to me
           that the regulatory footprint in the processing of the
           fuel is crucial.
                       MEMBER ROSEN:  Yes. And part --
                       MEMBER KRESS:  And I think it's analogous
           to digital I&C for controls and --
                       MEMBER ROSEN:  And part of the
           preapplication review, a big part of the fuel
           performance review, is to look at the tradeoffs of,
           where do you put your regulatory imprint.  Do you put
           it in the manufacturing piece and/or also in operation
           and/or testing fuel after it has come out?  I mean,
           you can put it anywhere you want.
                       The data I have seen on monitoring
           operation and looking at some examples going back to
           the German testing program, there are failure modes
           that will not be caught by monitoring coolant
           activity.  They don't --
                       MEMBER ROSEN:  Stu, why do you think it is
           only one answer?  Why do you think that?
                       MEMBER ROSEN:  I'm not saying there's one.
                       MEMBER ROSEN:  Whatever answer you come up
           with now is the answer forever.  I don't think so.
                       MEMBER ROSEN:  I'm not saying one.  I'm
           not --
                       MEMBER ROSEN:  I think the answer is
           something you -- in the beginning you do almost all of
           what you've talked about, until you begin to get
           confidence that you don't need to -- that you do not
           need to do pieces of it and can begin subtracting away
           pieces.
                       MEMBER ROSEN:  And we very much believe
           that this whole area will be a Commission policy
           decision.  And what we plan to do in our SECY paper at
           the end of this -- not so much the advanced reactor
           research plan development process, but the end of the
           preapplication review, is to lay out those defense-in-
           depth opportunities for catching fuel that may not
           perform well in an accident, and talk about the
           advantages and the disadvantages in each one, and lay
           out our -- those options and lay out our
           recommendation, and then the Commission will have to
           make a decision.
                       But I'm not going to say what that final
           answer is, but it is, we believe, very much a
           Commission policy decision on where that imprint or
           multiple imprints need to be.
                       MEMBER KRESS:  Well, while I'm on a roll
           here, I want to have one complaint.  There's a
           statement in the document -- now I don't have mine
           with me, so I don't know what page it's on, but it's
           to -- the statement says that the -- I won't be able
           to find it, because I've got it dog-eared -- that the
           evolution of severe accidents and source terms will be
           similar to current operating plants.
                       Now, I just think that's flat-out wrong
           for IRIS, and it may be wrong -- I mean, you can't
           even relate it to PBMRs.  But for IRIS I think it's
           flat-out wrong, and I think there's contrary evidence,
           especially for high burnup fuel, and IRIS, of course,
           is going to go to really high burnups.  And I just
           don't think you can make that statement.
                       And I didn't see in the plan, Dana,
           anything on research for core degradation and fission
           product releases for high burnup fuel of the LWR type.
                       MEMBER POWERS:  It's totally irrelevant,
           Tom.
                       MEMBER KRESS:  I know it is.  Yes.  So
           that's a complaint.  That's the one major complaint I
           have.
                       CHAIRMAN APOSTOLAKIS:  You have commented
           on the whole report now, because I want to do that,
           too.  You are not just commenting on the --
                       MEMBER KRESS:  Yes, that's right.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. ELTAWILA:  I agree with you on IRIS. 
           And as I indicated earlier, we have very limited
           interaction with Westinghouse on the design of IRIS. 
           So we really -- this plan does not really address IRIS
           in any extent.  So your points are well taken.  And
           once we -- we are going to keep that plan as a living
           document.  Once we get information about IRIS, we will
           modify to address this plant design.
                       MEMBER KRESS:  Yes, okay.  Well, another
           question I have is you had a section in there
           discussing -- I don't even remember where it was
           either -- discussing underground siting.
                       CHAIRMAN APOSTOLAKIS:  Yes, I remember
           that.
                       MEMBER KRESS:  It's a good idea, but I
           don't think anyone is seriously considering that, are
           they?  I mean, is that -- that wouldn't be a priority
           in my research.
                       MR. FLACK:  Underground is pretty much the
           GA design, the GT-MHR --
                       MEMBER KRESS:  Well, that's partly
           underground.
                       MR. FLACK:  Yes.
                       MEMBER KRESS:  Okay.  One other thought. 
           You talked about, for the PBMR and the pebble -- the
           gas-cooled reactors that severe accident issues
           include water ingression and air ingression.  I'm not
           so sure water ingression is a severe accident issue. 
           I think it's a long-term degradation issue and not a
           severe accident issue, so you might want to rethink
           that one a little bit.  
                       I guess that's my list of items, George.
                       CHAIRMAN APOSTOLAKIS:  Well, I have a --
           I mean, if we are talking about broader issues now, it
           looks like -- first of all, you mentioned PIRT some
           place.  I can't find it now, but I remember.  I know
           it's a major deficiency on somebody's part not to know
           what it is.  But I've been on this committee for five
           years, and people use the word "PIRT" as if everybody
           knew what it was from birth.  Is there any place where
           I can go and find out what it is?  I don't know what
           PIRT is.
                       MEMBER KRESS:  There's a document called
           CSAU that --
                       CHAIRMAN APOSTOLAKIS:  Oh, is that part of
           CSAU?
                       MEMBER KRESS:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Can you -- I know
           what it is, but I'd like to know how it's done.
                       MEMBER KRESS:  Well, I don't want --
                       CHAIRMAN APOSTOLAKIS:  And I know that the
           thermal hydraulicists are ecstatic about it.
                       (Laughter.)
                       MEMBER KRESS:  I don't know what the NUREG
           number is.
                       CHAIRMAN APOSTOLAKIS:  So I'm very
           suspicious.
                       (Laughter.)
                       Now, that brings me to another point,
           which is related to my question about efficiency and
           the use of risk information.  It's a matter of style,
           of tone, how to write this rather than really
           substance.  I know what you mean, although the
           substance is effective.
                       I'm willing to bet that what's going to
           happen is you're going to have the PRA at the high
           level, and then you're going to use a hell of a lot of
           defense-in-depth arguments to really preserve most of
           the criteria you have now. 
                       And here is the sentence that justifies
           that.  I'm editing now as I go.  However, until
           appropriate models can be accurately developed for
           these new designs to define and prioritize these
           issues, conventional methods will -- may need to be
           applied."  So this is dismissing now PRA.  This gives
           you a way out.
                       I would say -- I would change the tone of
           this and say the following.  Yes, we've had all sorts
           of -- I'm reading from the human factors, but I don't
           want to single them out, because I don't think it's
           unique to them.  Yes, you've been looking at task
           analysis, at procedure development, training program
           development.  Please tell us how important these
           things are in the risk environment.
                       I agree -- you see, now they are putting
           the burden on the reliability analysts.  Until the HRA
           models are accurate, we will continue doing what we're
           doing.  I'll reverse that.  Show me why what you're
           doing is important to risk, and then you put a hell of
           a lot of pressure on a lot of people to actually
           quantify, because if that pressure is not there they
           will never quantify, and I say that with a license --
           I mean, the power uprates.
                       The answer was, we have an engineer who
           looks at the -- who looks at it.  You know, the
           available time was 42 minutes, now it's 39, and he
           says it's okay.  Now, where is the incentive of
           quantifying if that's the easy solution?  An engineer
           looks at it and decides it's okay.
                       So it seems to me it's a matter of tone
           rather than really substance.  Ask all these people to
           tell you why all these requirements are important from
           the risk perspective.
                       Now, they may come back and say, well,
           gee, not everything is important, you know, from --
           with respect to CDF, but there are other criteria. 
           Well, that would be progress in itself, because I do
           know there are other criteria that are not
           specifically stated.
                       MR. ELTAWILA:  If we sound quiet on this
           side, it's because Mary keeps saying, "I agree with
           you," so I -- we are really --
                       CHAIRMAN APOSTOLAKIS:  She agrees with me
           or you?
                       MR. ELTAWILA:  No, with you.  So we are
           agreeing with you, and I think that's a good point.
                       CHAIRMAN APOSTOLAKIS:  I think that if you
           say that clearly here, then I think you are well on
           your way of having an efficient -- I'm not saying that
           it will always work, but at least you are shifting the
           emphasis now.
                       MR. ELTAWILA:  Okay.
                       CHAIRMAN APOSTOLAKIS:  You have to tell me
           why this particular requirement is important from the
           risk perspective, whatever "risk" means in this
           context.  You know, it's not -- nothing is important
           with respect to CDF, by the way, unless you demolish
           the reactor.  There may be other intermediate
           objectives that are effective, and at least we will
           have them on paper.
                       Ah, come on, Steve.  You know you have to
           do big things to see a big change in the CDF.
                       MEMBER ROSEN:  Abolish the reactor?
                       MEMBER KRESS:  Almost.
                       CHAIRMAN APOSTOLAKIS:  Almost.
                       MR. FLACK:  Well, there are sensitive
           issues like, for example -- that would be difficult to
           quantify.  And since you brought up human factors, it
           would be like a question of whether an operator is
           qualified, what would be the risk from an unqualified
           operator?  I mean, these are --
                       CHAIRMAN APOSTOLAKIS:  All I'm doing is
           I'm shifting the emphasis.
                       MR. FLACK:  No, I understand.  I
           understand.
                       CHAIRMAN APOSTOLAKIS:  See, as long as you
           say it's the problem of the HRA analyst, they will
           never get anywhere.  If you say, "No, it's your
           problem, you tell me whether what you're doing here is
           risk-significant," then you will see a very different
           attitude.  I repeat, I don't want to single out the
           human factors.  I mean, it applies to I&C, and I am
           sure it will apply to other things with the new
           reactor.
                       I&C, too -- I mean, you look at it, there
           is a lot of work, and this is -- at the end it says,
           "Oh, by the way, we really ought to quantify it, too." 
           Well, yes, sure.
                       MEMBER POWERS:  John, let me ask you a
           question.  Since, obviously, we've blown your
           presentation completely to hell, we might as well just
           continue this trend.  Teach you to make viewgraphs, by
           God.
                       (Laughter.)
                       We have just had the IPEEE insights
           document given to us, and with arguable exceptions we
           find two things.  One is the estimates of risk that
           the licensee has submitted for fire were surprisingly
           high comparable to operational risks.  And the
           techniques that they used to derive those were
           relatively crude.
                       And, okay, so you can argue that maybe the
           risks are not as high; they were just very
           conservative when they went through and did it.  On
           the other hand, you can take them at face value and
           say, "Hey, one of the features of our current crop of
           reactors is there are very susceptible to fire and is
           an accident initiator."  And maybe we don't want that
           for advanced reactors.
                       I mean, it does seem kind of a crude thing
           to have a sophisticated, high-technology device like
           a nuclear reactor susceptible to fire as an accident
           initiator.  Why, then, wouldn't you want to put
           priority on having good technologies for evaluating
           fire and advanced reactors?
                       MR. FLACK:  I guess you looked through the
           report for that piece and didn't quite find it there. 
           Fire is a difficult issue.  It's a spatial interaction
           type of issue that you need to deal with almost on a
           plant-specific level.  So it's difficult to understand
           what that risk would be until a plant actually comes
           in and says, "Here is what I got, and here is where
           things are," and then you can study it from that
           perspective.
                       But I guess, again, this comes back to the
           code issue, whether or not our codes --
                       MEMBER POWERS:  I'm looking at -- I mean,
           I'm taking your lead in saying you're trying to create
           an infrastructure here, a capability --
                       MR. FLACK:  Right.  Exactly.
                       MEMBER POWERS:  -- and so I'm asking,
           isn't this a capability that you want to have?
                       MR. FLACK:  I would -- the answer is, of
           course.  I mean, it's certainly an important risk
           contributor we see in these plants.  How they play out
           in advanced plants, passive designs, is yet to be seen
           in what we'll have -- how we'll approach that problem.
                       Again, it's a difficult issue to deal with
           without seeing a plant.  But no, it's certainly
           external events.  Seismic and fire are two that's part
           of that.
                       MR. RUBIN:  Can I just -- John?  This is
           Alan Rubin from the PRA Branch and also the IPEEE
           External Event Program.  As part of the advanced
           reactor research plan, we do include external events
           in the PRA -- different operational states as well as
           external events, fire, and seismic.  So we --
                       MEMBER POWERS:  We don't doubt that you
           include them.  I'm really asking a question on the
           quality of tool that you have available to include
           them.  For instance, a noted member of this panel, an
           exemplary member of this panel, devised a code some
           time in the past, and he recount for you the details
           of it, called COMBURN, and we universally find COMBURN
           gets used beyond its stated limits of applicability,
           because there's nothing else available.
                       And the problem I see that you have is
           just what John outlined for you.  If you're going to
           analyze fire, you're going to have to do it on a
           plant-specific basis.  If you wait for a plant to come
           along in order to do a fire analysis, then there isn't
           time to develop a better tool, because you're under
           the gun and people are yelling at you to do it faster,
           better, cheaper, and things like that.
                       And so COMBURN lives forever.  And though
           I know the author of COMBURN is an exemplary
           individual, a noted phenomenologist in this world, I
           don't think even he thinks that it deserves to live
           forever.
                       MS. DROUIN:  Dana, let me just also
           interject something.  We have a huge research
           initiative going on in the area of fire that would
           support this effort.  I mean, that's looking into
           things -- you know, the models.  I think they've been
           in front of the ACRS.
                       MEMBER POWERS:  I get confused, Mary, over
           the strategy in preparing the report.  It's all well
           and good that you have a research effort going on
           there, but shouldn't you lay it down here to say, "And
           we need that research effort"?  I mean, this wasn't a
           litany of things that you're supposed to do.  It's the
           things that are supposed to be done.
                       MR. FLACK:  No, that's a good comment.
                       MS. DROUIN:  I mean, the whole intent was
           to take advantage of what was going on in that
           program, and, yes, we probably shouldn't have been so
           silent on it.
                       MEMBER KRESS:  I think we have reached the
           end of the allotted time for this subcommittee
           meeting.  I would like to, you know -- lest you go
           away thinking we were too negative, I think -- I think
           you're on the right track with this thing, and you did
           a magnificent job of identifying the -- what the needs
           are and the gaps that might exist.  And it's a
           comprehensive, well-written document.
                       So I think you're on the right track, and,
           you know, we got some specific comments.  I don't know
           if those were sufficient for feedback or should we
           have a letter or not.  Probably --
                       MR. FLACK:  No, we weren't looking for a
           letter at this point.
                       MEMBER KRESS:  Okay.  Well, the other
           question I wanted to ask is:  when should we think
           about having you back again on this same issue?  July
           meeting, is that too soon, or is that too late, or
           what do you think?
                       MR. FLACK:  Are we talking about
           subcommittee or full committee?
                       MEMBER KRESS:  Well, probably need a
           subcommittee and a full committee, too.
                       MR. FLACK:  On this subject.
                       MEMBER KRESS:  Yes.  When do you think it
           would be worth thinking about another meeting?  That's
           my question, I guess.
                       MR. ELTAWILA:  We are ready any time you
           want, Tom, so just set the schedule according to your
           -- the availability of you and other members of the
           committee.
                       CHAIRMAN APOSTOLAKIS:  There has to be
           some evolution.
                       MR. ELTAWILA:  So I think we will have to
           start scheduling all of these meetings between now and
           to end by August, to be able to finalize the plan to
           go to the Commission.  So if --
                       MEMBER KRESS:  That's why I was thinking
           if it was in July we --
                       MR. ELTAWILA:  -- every month you want a
           meeting, we will be supporting that.
                       MEMBER KRESS:  Well, thanks.  I guess
           we're going to talk about -- yes, go ahead.  One more
           thing.
                       MEMBER ROSEN:  I want to say one thing. 
           I associate myself with all of the comments of the
           eminent Dr. Kress, but I am still concerned about the
           scope.  So take that away.
                       MR. FLACK:  We gotcha.
                       CHAIRMAN APOSTOLAKIS:  And next time,
           John, just come with two viewgraphs.  It doesn't
           matter.
                       (Laughter.)
                       It just doesn't matter.
                       Okay.  Thank you, gentlemen.
                       MEMBER KRESS:  Thank you very much.
                       CHAIRMAN APOSTOLAKIS:  This was a useful
           discussion, and we will recess now.  How much time do
           you guys want?  Do you want a full hour?  Okay.  Shall
           we be back at 1:50?  45 minutes?  1:50, okay.
                                   (Whereupon, at 1:08 p.m., the proceedings
                       in the foregoing matter went off the
                       record for a lunch break.)
           
           
           
           
           
           
           
           
           
           
                                A-F-T-E-R-N-O-O-N  S-E-S-S-I-O-N
                                                      1:53 p.m.
                       CHAIRMAN APOSTOLAKIS:  Next item, "CRDM
           Penetration Cracking and Reactor Pressure Vessel Head
           Degradation."  Dr. Ford, please lead us through this
           discussion.
                       MEMBER FORD:  On April 9, presentations
           were made to the Materials and Metallurgy and the
           Plant Operations Subcommittees on the 2001-1 and 2002-
           1 bulletins relating to cracking of CRDM housings and
           the degradation of CRDM housings.  Obviously there's
           a tremendous amount of work going on on those two
           issues by both the industry and the staff.  And on
           April 9, we heard preliminary information especially
           on that from Davis-Besse related to the root cause and
           generic implications of the degradation.
                       Today, we're going to hear an update on
           these issues, and it's primarily for information.  The
           staff have not requested a letter from us.  Future
           meetings with the subcommittees and the full ACRS are
           scheduled somewhere in the near future for which there
           will be a letter, presumably, requested.  Jack, you
           didn't have any comments?
                       MEMBER SIEBER:  No.
                       MEMBER FORD:  I'd like to move on then. 
           We're going to take it in order, from the industry
           perspective, given by Larry Mathews, and then we'll
           move on to the Davis-Besse, and then finishing off
           with the presentation by the staff.  So Larry is the
           Chairman of the MRP Program and from Southern Nuclear.
                       MEMBER SIEBER:  What's MRP?
                       MEMBER SHACK:  The first test.
                       CHAIRMAN APOSTOLAKIS:  What's MRP?
                       MEMBER FORD:  Materials Reliability
           Program, sponsored by EPRI.
                       MR. MATHEWS:  Like Dr. Ford said, I'm
           Chairman -- is this on?  I'm Chairman of the Alloy 600
           Issues Task Group of the Materials and Reliability
           Program.  I work for Southern Nuclear, in case you
           care, or at least they pay me.  I don't do much for
           them.
                       (Laughter.)
                       MEMBER POWERS:  An extraordinarily honest
           man here.
                       MR. MATHEWS:  Not to imply I don't work. 
           I just don't --
                       (Laughter.)
                       These are kind of four topics I'd like to
           run through fairly quickly here today and provide a
           summary on:  The Alloy 600 82/182 strategic plan that
           we have developed, an update on where we stand on
           crack growth rate issues, some brief words on the risk
           assessment and the probablistic fracture mechanics
           that we're doing for the reactor vessel head
           penetrations and then, basically, how we are
           responding to the Davis-Besse issue at this point.
                       This is basically an outline of the
           strategic plan that the MRP has put together to
           address the Alloy 600 and the 81/182 issues.  The plan
           has a problem staying on the goal and mission of
           trying to manage the issue, how we're going to go
           about it, what the roles of our various stakeholders
           are.  And then we have a strategy right now, which are
           the five areas you see here.
                       Basically, on the -- are you looking for
           this presentation?
                       PARTICIPANT:  Huh?
                       MR. MATHEWS:  Are you looking for the
           presentation?
                       PARTICIPANT:  No, no, no.
                       MR. MATHEWS:  Oh, okay, okay.  On the butt
           welds, the basically strategy we've laid out is we're
           going to rely primarily on the ASME Section 11, the
           guidance for inspections and the frequency, but we're
           driving and we're trying to drive improvements into
           technology for doing those inspections.  And,
           primarily, Appendix 8 has to be implemented by next
           fall, and at that point, all the inspections will be
           done by qualified inspectors.
                       One of the things we will have to be
           looking at potentially in more detail is the
           frequency, is it appropriate, et cetera?  But that's
           where we are right now is we believe Section 11,
           coupled with Appendix 8, will be the appropriate way
           to do it.  There is a potential issue with the pass
           rates and the qualifications of the inspectors, and
           we're trying to address that right now.
                       There's other areas up here, excuse me. 
           The head penetrations in the near term, we put
           finalizing a safety assessment, but the real thing
           we're doing here is putting together mockups to drive
           the technology for doing volumetric inspections and to
           demonstrate those inspections.  We're having mockups
           built that will be used in blind tests this summer for
           vendors that will be qualifying to do volumetric or
           under-the-head inspections next fall.  There's also a
           mockup that was built that was available for people to
           use early and then another one for the spring outages.
                       In the area of the longer term, what we're
           doing to do is get out inspection guidelines on what
           people ought to be doing, as far as inspecting their
           head penetrations.  And then we want to work with the
           NRC and ASME to make sure this is, you know, all in
           conjunction with what's the right thing to do as far
           as inspecting the heads.
                       All the other locations, we're working
           with the owners' groups to see what's already been
           done.  We don't want to duplicate anything for all the
           other Alloy 600 locations.  And where there are holes
           in what they've accomplished, we know they've done a
           lot of work, where there's holes in what they've
           accomplished, we'll work with those owners' groups and
           vendors to figure out where's the right place to
           develop those guidelines and get those programs
           underway.
                       And, ultimately, the goal is to get out a
           management guideline for all the locations that would
           either provide information on how to manage it for
           your plant or direct you to where it would be
           available.
                       One of the first things we want to work on
           is the inspection plant.  We have draft inspection
           plant out now.  This is something we need to get with
           the staff and make sure we're all in agreement on
           what's the right thing to do in the inspection.  But
           it basically marches toward -- as the plant gets older
           and it has more time at temperature on the vessel
           head, the inspection should become more rigorous, if
           you will, going from a visual to ultimately,
           potentially all the way down to you must do a
           volumetric on some frequency.  We haven't finalized
           that.  That's in the final stages at this point.
                       In the area of crack growth rate for Alloy
           600, what we're trying to do is figure out what's the
           right crack growth rate people ought to be using when
           they're trying to do evaluations of cracks in the
           Alloy 600, initially looking at the base metal.  We've
           created an expert panel.  That expert panel has met
           several times, and they've screened databases
           available in the world.  They're trying to refine
           their approach.  It's been consolidated, but
           apparently, recently, we were very close to publishing
           the report, but then one of the labs said, "Well, we
           want to take another look at our own data."
                       And then while that's going on, Davis-
           Besse occurs, and so especially with respect to what
           the annulus environment might be and the impact of the
           annulus environment, the experts said, "Well, we know
           what we said," and I'll tell you what that was in a
           second, "but before we publish we want to take another
           look at that and make sure we still believe it."  And
           so they're meeting next week.  It's a sid bar meeting
           to a meeting going on in France to look at that issue.
                       CHAIRMAN APOSTOLAKIS:  So when you say
           "curve," what are the axes?  I mean one must be the
           growth rate.
                       MR. MATHEWS:  Growth rate and stress
           intensity factor.
                       CHAIRMAN APOSTOLAKIS:  Stress intensity. 
           Now, isn't there any uncertainty in those curves?  I
           mean are you displaying --
                       MR. MATHEWS:  Oh, yes, quite a bit.
                       CHAIRMAN APOSTOLAKIS:  And you are
           displaying it?
                       MR. MATHEWS:  Pardon?
                       CHAIRMAN APOSTOLAKIS:  You are displaying
           it or are you just showing one curve?
                       MR. MATHEWS:  What we're proposing is a
           couple of different approaches.
                       MEMBER FORD:  Well, before you -- are you
           going to continue answering that specific question?
                       MR. MATHEWS:  Yes.  Go ahead.  What were
           you going to say?
                       MEMBER FORD:  Well, answer that question,
           because I want to come back to that.
                       MR. MATHEWS:  Okay.  What we've done is
           we've taken the whole database and we've come up with
           a curve that we feel can be used for the deterministic
           evaluation of the crack growth rate for real flaws. 
           And, basically, any flaws that you're trying to
           evaluate to leave in surface, the main ones that have
           been evaluated are flaws that are either ID axial
           flaws or if they are on the OD, they're below the
           weld.  Anything above the weld it has to be a leakage
           path, and we can't leave that in service, so we
           wouldn't be evaluating real flaws above the weld.
                       We do want to evaluate hypothetical flaws,
           for instance, all in the circ direction to determine
           if it flows into the safety, how long have we got and
           that sort of thing.  And so above-the-weld flaws
           they've recommended a factor of two to account for the
           chemistry in the environment, but that's one of the
           things that the guys are going to take a look at next
           week in France, will make sure that Davis-Besse
           doesn't really throw a monkey wrench in.
                       CHAIRMAN APOSTOLAKIS:  But are on the
           issue of uncertainty now?  You said it can be used for
           deterministic evaluation.
                       MR. MATHEWS:  Right.  And the curve that
           we're proposing is for deterministic evaluation is
           like the one that would fit the 75th percentile of all
           the heats and material in the database.
                       CHAIRMAN APOSTOLAKIS:  Oh.  So you're --
           oh.
                       MEMBER FORD:  I think this is an ongoing
           argument within the industry for quite some time, and
           you've got a big scattered database, experimental. 
           How much of that scatter is due to experimental
           control?  Is much of it due to heat variations, for
           instance, in the materials in that database?  And we
           have requested that at the next meeting that that
           database will be shown to the committees and how that
           has been analyzed.  So that will directly answer your
           question.
                       CHAIRMAN APOSTOLAKIS:  Because it would
           seem to me to be an ideal place for a family of
           curves, would it not?
                       MEMBER FORD:  For a --
                       CHAIRMAN APOSTOLAKIS:  A family of curves
           rather than one curve.
                       MEMBER SHACK:  People recognize there is
           a distribution.  Just for deterministic evaluation
           you'd like to have --
                       MR. MATHEWS:  No, but if you knew exactly
           -- if you knew exactly.
                       CHAIRMAN APOSTOLAKIS:  No.  CGR data for
           base material feeds directly into the PRA.
                       MR. MATHEWS:  Well, that's not how we feed
           it into the probablistic approach, though.  Instead of
           feeding it into the probablistic approach as a single
           curve, we put the whole database and all the scatter
           of the database to be sampled in the probablistic
           approach.  The whole scatter for the whole database is
           put into the probablistic analysis.
                       CHAIRMAN APOSTOLAKIS:  I'd like to see
           that.
                       MEMBER FORD:  That is one of the things
           we've been asking that we do all see the database so
           we can understand the reasoning behind these words.
                       MR. MATHEWS:  Yes.  And some of the staff
           is saying but we haven't shown them the ACRS.  And
           part of the reason is it's in a state of flux right
           now.
                       CHAIRMAN APOSTOLAKIS:  So you're going to
           do this in a subcommittee meeting?
                       MEMBER FORD:  We'll do it in the
           subcommittee and present it at the full committee,
           yes.
                       MR. MATHEWS:  And hopefully we can do that
           at the next meeting.
                       MEMBER FORD:  Correct.
                       MR. MATHEWS:  I think we'll be much closer
           and we can do that.
                       MEMBER FORD:  Could you go back to your
           previous page?
                       MR. MATHEWS:  Sure.
                       MEMBER FORD:  The implications of the
           Davis-Besse, your last bullet, is that in terms of the
           question as to what the environment is in the
           circumferential annulus?
                       MR. MATHEWS:  Yes.  That's what -- I
           believe that's what the experts would want to take a
           look at.  They had made some assumptions, some MULTEQ
           calculations and some other discussions amongst the
           experts about what are the possible environments that
           could be in there in the annulus region, and then what
           effect would that have on the crack growth rate?  And
           they came up with what they felt was a conservative
           multiplier, a factor of two.
                       Given the situation at Davis-Besse,
           thought, they said, "Well, I don't know that it's
           going to change, but let's take a look at it and see
           if there's anything coming out of the Davis-Besse
           situation that would say that environment that we
           predicted is inappropriate to use for a
           circumferential crack growth.
                       MEMBER FORD:  And, again, that information
           will be discussed, presumably, at the next meeting,
           this specific information.
                       MR. MATHEWS:  We hope to have our report
           published well in advance of that meeting, and we can
           come talk about it.
                       CHAIRMAN APOSTOLAKIS:  Next meeting.
                       MEMBER FORD:  Well, in the near future,
           maybe one, two months time.
                       CHAIRMAN APOSTOLAKIS:  Subcommittee
           meeting.
                       MEMBER FORD:  Correct.
                       MR. MATHEWS:  Also, the expert panel they
           met very recently to look at the weld metal Alloy
           82/182 and what we know about the crack growth rates
           in the weld metal.  And they will be coming back to
           the MRP with recommendations on where there's holes in
           that database, and there are likely to be some because
           it's a limited database and where testing may be
           needed.
                       There's also a research effort that's
           being undertaken right now by EPRI, and it's a DOE
           part of the NEPO Program to look at some crack growth
           rates in weld metal.  And there may be some additional
           base metal crack growth rate in there, I'm not sure. 
           And we will certainly be willing to continue to update
           you as we get more data, maybe provide you some.
                       In the area of the risk assessment work,
           the approach is to predict the probability of leakage
           based on the industry experience and where we've seen
           links and modeling that in a Weibull model, Weibull
           statistics model.  Then compute, after a leak
           develops, the probability of a nozzle ejection,
           looking at or considering the initiation and growth of
           a circumferential flaw above the J-groove weld.  We
           can factor into that inspection and the probability
           that a leak might be detected prior to growing to an
           ejection situation.
                       CHAIRMAN APOSTOLAKIS:  How would you do
           that?
                       MR. MATHEWS:  I left that slide out.  What
           you do is as the model progresses through the time,
           it's a statistical model but it progresses through
           time, and at given points in there, depending on the
           inspection frequency that you put in, you can put in
           a probability of detection.  And if you -- and you do
           a sample on that.  And if you find the probability
           that it is detected on that particular sample, you
           take it out of the database for an ejection.
                       And if you don't, it goes on down to maybe
           the next level of inspection or the next whatever. 
           You just the run the statistics, and if you put a
           probability of detection of 80 or 90 percent in there
           and you're doing inspection at a certain point in
           time, then 80 or 90 percent of any flaws that might be
           in existence there would be taken out of the database
           or if they're not --
                       CHAIRMAN APOSTOLAKIS:  Would that be
           consistent with the Davis-Besse experience?  An 80, 90
           percent probability of detecting?
                       MR. MATHEWS:  Today, I would say, yes,
           probably.  I'm not sure what the POD, probability of
           detection, that we're going to put in there.  That's
           just the way it's modeled, and we'll have to decide. 
           We haven't settled down on exactly what kinds of
           inspections or when they would be into the model to
           figure out the risk.  But, you know, before Oconee the
           world was different than it was after Oconee, so
           people look at things a whole lot different.
                       CHAIRMAN APOSTOLAKIS:  See, what worries
           me is that I don't know how many times the world is
           going to change.
                       MR. MATHEWS:  Oh, yes.  I know what you
           mean.
                       CHAIRMAN APOSTOLAKIS:  I mean it
           shouldn't.  It should change any more for the current
           generation reactors.  That's my problem.
                       MR. MATHEWS:  Knowledge isn't perfect, I
           must admit.
                       CHAIRMAN APOSTOLAKIS:  Boy, you can say
           that again.
                       MR. MATHEWS:  Yes.  Anything else? 
           Finally, what we do is we grow the flaw to the
           critical flaw size on a statistical basis from Monte
           Carlo sampling, and some of them grow to critical flaw
           and some of them don't.  And then they take the
           fractions that do and that's the probability there.
                       Couple that with the probability of a
           conditional -- I'm sorry -- yes, with the conditional
           core damage probability from a small break or medium
           break LOCA, and you have the core damage frequency. 
           What we're going to do is assess the potential impact
           on the conditional core damage probability of the
           collateral damage.  We think it's going to be minimal
           that might occur from an ejection.
                       CHAIRMAN APOSTOLAKIS:  Is it clear to
           everyone why nozzle ejection is the issue here?
                       MEMBER SHACK:  That's what causes your
           medium-break LOCA.
                       MR. MATHEWS:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Oh, that's --
                       MR. MATHEWS:  In almost all -- you know,
           if you look at all the times that plants run most of
           the time, almost all the time these plants are up at
           power and all the control rods are essentially all the
           way out.
                       CHAIRMAN APOSTOLAKIS:  So what's the
           equivalent diameter?
                       MR. MATHEWS:  The inside of a nozzle is
           about two and five-eighths inches, I believe.
                       MEMBER SHACK:  But when the whole thing
           comes out, it's like four inches.
                       MR. MATHEWS:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Oh, okay.  So then
           it's --
                       MR. MATHEWS:  Well, you've still got to
           get through the part that's left.  If you have a circ
           flaw above the well, then you've got a segment that's
           left from the well down that's not ejected and the
           inside diameter of that is two and something inches,
           and if it's a control rod location, it will still have
           a shaft in it unless that gets pulled on out too.
                       CHAIRMAN APOSTOLAKIS:  How will you go to
           the condition core damage probability?  I mean you
           would just consider the new probability of a medium
           LOCA?  The probability of nozzle ejection would be --
                       MR. MATHEWS:  Well, the CCDP is the
           conditional core damage probability.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MR. MATHEWS:  Given that you have a
           medium-break LOCA, the plant risk assessments already
           have looked at what is the probability that you have
           core damage, given that you have a medium-break LOCA. 
           And that goes through all the possible failures of
           your ECCS systems and all of that.
                       CHAIRMAN APOSTOLAKIS:  Would you consider
           dependencies between the initiating event and some of
           the other events?
                       MR. MATHEWS:  Yes.
                       CHAIRMAN APOSTOLAKIS:  In particular
           SCRAM?  Would SCRAM be affected?
                       MR. MATHEWS:  Yes.  And that's what we
           would look at as would there be collateral damage from
           the ejection of a control rod nozzle that could make
           that conditional core damage probability of a medium-
           break LOCA higher than if it was on a pipe somewhere. 
           We'll look at that, and if it would make that
           conditional core damage probability, given the LOCA
           here as opposed to on a pipe higher, then that effect
           would be factored into the risk assessment.  We think
           that effect's going to be minimal and we've gotten
           some preliminary work from the vendor, but we need to
           finalize that.
                       CHAIRMAN APOSTOLAKIS:  So you are also
           looking at small-break LOCA, I see.  All right.
                       MR. MATHEWS:  From a risk standpoint, yes. 
           We're not doing a deterministic blowdown of a small-
           break LOCA type thing, it's more of a risk analysis.
                       CHAIRMAN APOSTOLAKIS:  Okay.  You're going
           to have to have experts again telling you what's going
           to happen if you have a nozzle ejection.
                       MR. MATHEWS:  Yes.  And the vendors know
           --
                       CHAIRMAN APOSTOLAKIS:  And how it will
           affect the SCRAM system.
                       MR. MATHEWS:  -- what's up there, and
           we're asking them to provide us input on that, and
           they've given us some preliminary stuff, and we need
           to follow-up on that and figure out how to factor that
           input back into the risk assessment.
                       CHAIRMAN APOSTOLAKIS:  So when will this
           be done?
                       MR. MATHEWS:  We were hoping to be through
           this month, but everything's kind of taken a --
           everybody's busy on Davis-Besse issues right now.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. MATHEWS:  Some of the key elements of
           the probablistic fracture mechanics analysis, which is
           the major part of the risk assessment, is the
           simulation of the leakage as a function of time and a
           Monte Carlo model.  That's based on our time and
           temperature model using the fracture for the stress
           intensity factors, for the various types of flaws that
           would be in there as the flaws grow.  The entire
           database for the structure crack growth rate database
           and the statistics, all of those statistics would be
           fed into for the sampling and then the effects of the
           inspection and the inspection reliability.
                       We have some very preliminary results for
           a tight temperature plant, and I do stress
           preliminary.  First cut thereafter after you've an
           inspection, the probability of nozzle ejection within
           the first or so is less than times ten to the minus
           three after you've done inspection.  And then the
           conditional core damage probability, the worst one we
           could find on the high temperature plants was five
           times ten to the minute three.  Multiplying those two
           together you get a core damage frequency in the range
           of five times ten to the minus six.
                       CHAIRMAN APOSTOLAKIS:  What is the main
           reason why the probabilities are so low?
                       MR. MATHEWS:  The main reason the
           probability of an ejection is so low after you've done
           an inspection is that you've found your leaks and
           repaired them.  But in a few cases, when you do the
           statistical Monte Carlo approach, you can have some
           very high crack growth rates on some of this sampling. 
           And those that grow very, very rapidly a few of them
           may grow all the way to the ejection in the sampling
           process, but it's a very, very few of them within one
           cycle or before you come back to do another
           inspection.
                       CHAIRMAN APOSTOLAKIS:  So you're assuming
           that when the size reaches a certain level, then
           there's a very high probability that they will be
           caught by inspection and somebody will act on it.
                       MR. MATHEWS:  Yes.  Given today's
           environment and what everybody knows about what they
           need to be looking for, yes.
                       CHAIRMAN APOSTOLAKIS:  Today's environment
           meaning?
                       MR. MATHEWS:  After Oconee.  I mean Oconee
           showed that you could have a leaking penetration that
           didn't have a lot of boric acid coming out down the
           side of your vessel.  And so now people are keyed into
           you have to look for popcorn instead of big piles.
                       CHAIRMAN APOSTOLAKIS:  And CCDP, why is it
           so low?
                       MR. MATHEWS:  Because a small-break LOCA
           or --
                       CHAIRMAN APOSTOLAKIS:  No, a medium LOCA.
                       MR. MATHEWS:  Okay.  I'm not sure of the
           exact square inches on the small and medium LOCA, but
           we have lots of safety systems that are designed to
           handle the LOCA and to keep the core from being
           damaged.  And the way you get damaged typically on a
           risk assessment analysis on the LOCAs is something
           fails, and there's probability and statistics put in
           on a failure probabilities of your various safety
           systems, and as you do that sampling on all the
           systems and their probabilities, it comes out with a
           fairly low probability for that size break that you're
           going to have core damage.
                       CHAIRMAN APOSTOLAKIS:  But how much credit
           are you taking for scrap?
                       MR. MATHEWS:  I'd have to go look at the
           PRAs.  I'm not sure if we -- I know in the design
           basis axis on LOCAs I'm not sure we take any credit
           for SCRAM.
                       CHAIRMAN APOSTOLAKIS:  You're not sure of
           what?
                       MR. MATHEWS:  I'm not sure they take any
           credit on the design basis analysis, but on the risk
           assessment I think we do take credit for SCRAM.
                       CHAIRMAN APOSTOLAKIS:  The question is how
           much because I don't know that we really know what's
           going to happen if you have a medium-break LOCA at
           that location.
                       MR. MATHEWS:  Well, that's what we're
           counting on the collateral damage assessment to tell
           us:  Does it have an impact on the conditional core
           damage probability?
                       CHAIRMAN APOSTOLAKIS:  Oh, so the
           collateral damage is not part of these numbers?
                       MR. MATHEWS:  Right.  But like I say, the
           conditional assessment we have from the vendors is
           that it will have very minimal impact, if any, on the
           conditional core damage probability.  A break at the
           top of the vessel is better than one that's at the
           bottom, and the CCDP is for all breaks.  But --
                       MEMBER ROSEN:  A break at the top of the
           vessel is better than one at the bottom but not for an
           event when you want the control rods drives to
           operate.
                       CHAIRMAN APOSTOLAKIS:  That's right.
                       MEMBER ROSEN:  Because the control rod
           drives on a PWR are at the top.
                       CHAIRMAN APOSTOLAKIS:  They're at the top.
                       MR. MATHEWS:  That's right.  And that's
           what we have to see and have to assess in this
           collateral damage is is there something that could
           happen that would prevent a SCRAM or a significant
           portion of the rods from not going in?  Severing the
           cables is great.
                       MEMBER SIEBER:  It's designed to have one
           rod stuck up.
                       MR. MATHEWS:  At least one.
                       MEMBER SIEBER:  And still get enough
           reactivity.
                       MEMBER ROSEN:  From a reactivity
           standpoint.
                       MEMBER SIEBER:  But if you damage the
           adjacent rods somehow so that they don't, then the
           probability of core damage goes up.
                       CHAIRMAN APOSTOLAKIS:  That's exactly what
           we're exploring here.
                       MEMBER SIEBER:  Wiping out 60 of them, I
           think, is pretty improbable.
                       MEMBER ROSEN:  What we're worried about is
           the steam environment, the jet environment and all of
           that that will be up there in very aggressive to the
           operation of the drives and the rest of the equipment
           up there.
                       MR. MATHEWS:  Well, most anything that's
           going to -- the real concern, if there is one, from a
           collateral damage, is if you could something that
           would prevent the rods from moving physically.
                       MEMBER ROSEN:  That's right.
                       MR. MATHEWS:  Severing the cables, no
           problem, they're going in.  It's the --
                       CHAIRMAN APOSTOLAKIS:  Physical, yes.
                       MR. MATHEWS:  If you bend the tube or
           something like that, that's the condition --
                       MEMBER ROSEN:  If you have a plate right
           above this, you know, above the point where you have
           the break, and you create a high pressure environment
           between the plate and the top of the head and what if
           that plate cocks or something like that?  I mean you
           can imagine --
                       MR. MATHEWS:  The insulation plate.
                       MEMBER ROSEN:  Yes.
                       MR. MATHEWS:  Yes.  Those are pretty low.
                       MEMBER SIEBER:  But what's the point if it
           does?
                       MR. MATHEWS:  And that's what -- we have
           to look at the --
                       MEMBER SHACK:   We're not done.
                       MR. MATHEWS:  We're not done yet, but, you
           know, I think I heard yesterday and it's, at least to
           my way of thinking about it, the first thing that's
           going to happen is the voids are going to shut the
           reactor down.
                       CHAIRMAN APOSTOLAKIS:  The point is that
           the five ten to the minus six number does not include
           considerations of this type.
                       MR. MATHEWS:  Right.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. MATHEWS:  It includes an initial
           estimate that it's going to be a very minimal impact
           on that number, but we still have to go back and tie
           all that together.  We're not through yet.
                       MEMBER FORD:  The first time that such an
           analysis was given, to the staff that is, was during
           the Duke presentations relating to Oconee, and my
           question now is have there been any subsequent
           discussions between you and the staff on this whole
           approach?
                       MR. MATHEWS:  We've had some fairly
           detailed meetings with the staff on how we are
           modeling primarily the probablistic fractured
           mechanics part.  We haven't really gone in in much
           detail on the rest of the risk assessment.  I think
           we've laid this level of detail out and discussed it
           with the staff.  But on the probablistic fracture
           mechanics and how we're modeling the crack and the
           crack growth rate, we've met with Ed Hackett and the
           research folks and their contractors and had a couple
           of rounds of questions about how we're doing it versus
           how they're doing it and trying to reach resolution on
           some of those issues.
                       MEMBER POWERS:  Suppose that after all
           that they said, "Gee, you're just doing great.  The
           crack growth rates are great, everything's great." 
           How do you know the results are right?
                       MR. MATHEWS:  Well, from the probability
           of leakage is -- well, it's based on the experience in
           the field, and we continue to get experience in the
           field, and that is adjustable to match the experience
           in the field.  We're trying to be somewhat
           conservative in this, and although it is a statistical
           approach --
                       MEMBER POWERS:  How do you know you're
           being conservative?
                       MR. MATHEWS:  There are a number of
           details of how we're modeling the probability fracture
           mechanics work that are -- like immediately upon a
           crack going to a leak, we assume that it's instantly
           like -- I think it's 20 or 30 degrees around branch of
           the flaw, and it's going to take some time to initiate
           a circumferential flaw, but we assume it happens
           instantly.  That's one thing.
                       CHAIRMAN APOSTOLAKIS:  Would assuming the
           presence of the degradation around this nozzle,
           similar to that of Davis-Besse, be a conservative
           thing to do and what numbers would you get?
                       MR. MATHEWS:  It might be a conservative
           thing to do, and we could model it.  And I guess the
           next slide is --
                       CHAIRMAN APOSTOLAKIS:  You don't know what
           number you're going to get, though, do you?  Because
           it's not just the normal rejection.
                       MR. MATHEWS:  No, I don't know.
                       CHAIRMAN APOSTOLAKIS:  You may have
           additional failures.
                       MR. MATHEWS:  There is the potential there
           that if you got a nozzle that was in a situation like
           Davis-Besse where there is a wastage cavity next to
           it, if the cavity comes all the way around so that you
           lose a back wall on the opposite side from where the
           cert flaw is growing, it might have an impact on how
           fast the crack grows.  And we can model that and do
           some studies on that, and we probably will do that,
           where we remove the nozzle, the constraint from the
           nozzle on the opposite side from the cert flaw.
                       CHAIRMAN APOSTOLAKIS:  Well, that would be
           an interesting case to see, a sensitivity case.
                       MR. MATHEWS:  Yes.  And it's not that hard
           to do.  There's gap elements on that side of the
           nozzle that we just set them to a gap instead of an
           interference and then see what happens to the nozzle
           leaning over as a function of the crack growing. 
           Really, the way we've modeled it, it would only have
           impact after the flaw hits 180 degrees in through
           wall.  If it's part through wall, we don't even model
           that restraint; that's ignored.  So, basically, we're
           modeling it without that restraint already.
                       CHAIRMAN APOSTOLAKIS:  So if you were
           doing this analysis before Oconee, what number would
           you get?  You said earlier, "in today's environment." 
           So in yesterday's environment, what number would you
           get, five ten to the minus nine or five ten to the
           minus --
                       MR. MATHEWS:  Well, we probably would
           have, yes.
                       CHAIRMAN APOSTOLAKIS:  Huh?
                       MR. MATHEWS:  Yes.  It probably would have
           been in that --
                       CHAIRMAN APOSTOLAKIS:  So all Oconee did
           was raise the number from ten to the minus nine to ten
           to the minus six?  No?  What?  That's what they said.
                       MR. MATHEWS:  I didn't do it before
           Oconee, so I don't know what the number would have
           been if we hadn't -- where it comes in is the
           probability of the ejection.
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MR. MATHEWS:  Which starts from the
           probability of a leak.  We would have thought that
           prior to Oconee in those flaws that have been recently
           discovered, we would have felt that the probability of
           developing a leaking penetration on a USPW head was
           lower than it really was.
                       MEMBER FORD:  I think the answer to both
           your questions, to a certain extent, is, again, I
           don't think you can -- the proof of the pudding, of
           course, is observation versus theory, and we haven't
           had any raw dejections, thank goodness.  But you can
           do it what's the probability of a number of through
           wall -- through circumferential wall cracks that have
           been observed.  And that's essentially the approach
           that Oconee did, or Duke did for Oconee, to compare
           these predictions against the number of
           circumferential cracks that they saw.  Now,
           admittedly, it's not going the whole way, you're
           absolutely correct, but it is going -- they're doing
           a check of observation versus theory.
                       MEMBER POWERS:  What I guess -- I mean
           you've certainly interpreted my question correctly,
           and what I'm really struggling to find we apply this
           probablistic fracture mechanics in a lot of regimes
           now.  This seems to be the first one where we don't
           get answers like ten to the minus 45, which I thought
           was a constant --
                       (Laughter.)
                       -- in probablistic fracture mechanics. 
           But I never -- I mean I'm sufficiently unfamiliar with
           the technology that no one ever shows me that it
           actually gives you good answers for any circumstance
           that isn't fairly well-contrived laboratory
           circumstance.  And so I'm wondering as the geometry
           has become more complicated, and here they're about as
           complicated as comes quickly to mind, do we really
           have data for any circumstances, I mean it doesn't
           have to be a reactor vessel, but how about an
           internally pressurized vessel of some sort where we
           can show that indeed the probablistic fracture
           mechanics has got all the physics in it so that if we
           do what the speaker has said, we parameterize the
           model conservatively, we should get a conservative
           answer?
                       MEMBER FORD:  Do you want to answer that?
                       MR. MATHEWS:  I'm not a probablistic
           fracture mechanics guy.
                       MEMBER POWERS:  Well, that speaks well of
           you.
                       (Laughter.)
                       MEMBER FORD:  I don't know -- quickly, off
           the top of my head, I don't know --
                       CHAIRMAN APOSTOLAKIS:  Are there any cases
           where probablistic fracture mechanics gave
           probabilities on the order of 0.2, 0.3 value?  Or is
           it an inherent thing of the methodology?
                       MEMBER POWERS:  Ten to the minus 45 is a
           really common number, I know that.
                       MEMBER SHACK:   Just to come back, George,
           you know, one of the things one observes is the way
           things depend on diameters, your famous Thomas
           correlation that you PRA guys love, you know, that
           comes out of the fracture mechanics.  The low
           probabilities, of course, are for a large diameter
           pipe where, again, for the crack to grow all the way
           around the pipe, you have to grow a crack that's many,
           many inches long.  So, obviously, that's going to take
           a lot longer than it does to, say, grow a crack around
           a four-inch pipe.  I mean the physical -- you still
           have to grow 330 degrees, it's just the 330 degrees on
           a four-inch pipe is a whole lot less metal than 330
           degrees on a 24-inch pipe.
                       Now, it's very difficult, of course, to
           get one-to-one comparisons, because we just don't have
           a whole lot of data, but when you go back to the
           database, you get probabilities of failure that aren't
           all that -- you know, they're in the ballpark of what
           you're computing for your probablistic fracture
           mechanics; it's not a one to one.
                       We have experimental confirmation of the
           ingredients; that is, you know, crack growth rate is
           measured independently.  It's not in a probablistic
           fracture mechanics test.  The biggest thing that you
           have are the loads on the pipe where we know the
           pressure loads very well.  PR over T really work.  The
           residual stresses you can measure independently.  So
           you can measure those independent ingredients, and
           then --
                       MEMBER POWERS:  But I never see anybody
           put the whole thing together and say, "Okay.  Here are
           a bunch of data on this thing, and this thing works."
                       MEMBER SHACK:   When you come out with the
           probability of large diameter pipe failure of ten to
           the minus nine, you're not going to find data.
                       MEMBER POWERS:  Well, give me a small
           diameter pipe.
                       MR. HACKETT:  If I could add, this is Ed
           Hackett from the staff, we briefed the Committee, I
           guess, numerous times now on the pressurized thermal
           shock reevaluation program.  I think that's where the
           staff and the industry have done the best job of
           applying this type of methodology.  And in fact that
           has been benchmarked to international reference
           experiments, and in several cases has done quite well.
                       In think in the case of Professor
           Apostolakis' comment, I'm not aware of any that have
           come up that high.  We see these failures for vessels,
           and, again, thankfully, as Dr. Ford was mentioning,
           are in the range of E minus six or less when we're
           looking at reactor pressure vessels, different
           application than what Larry's talking about here
           specifically.
                       MEMBER SHACK:   But even there, Ed, when
           you benchmark that, you benchmark the fracture
           mechanics, "Yes, I failed a vessel with a crack so
           big."
                       MR. HACKETT:  That's correct.
                       MEMBER SHACK:   Just to say that the
           probability of the vessel failure is ten to the minus
           eight, you're not going to get a whole lot of
           statistics to --
                       MR. STROSNIDER:  This is Jack Strosnider. 
           I'd like to make a few comments on this too and maybe
           to defend the credibility of probablistic fracture
           mechanics somewhat.  First of all, I think, you know,
           when you talk about benchmarking this, as Ed pointed
           out, thankfully we don't have an empirical database on
           pressure vessel failures or CD control rod drive
           mechanism failures, for that matter.  So it is rather
           difficult to get that sort of benchmarking.
                       However, I think when you look at the
           probablistic fracture mechanics, you can get results
           that are reasonable depending upon the conditions that
           are being considered.  And I think the ten to the
           minus 42nd number that was brought up a couple times,
           I think you're referring back to some of the PWR work
           on vessel inspection.  And in fact that number, it
           turned out, was the number that was generated when you
           assumed design basis conditions were satisfied.  In
           fact, when you go through the full risk assessment
           that was done and what we ultimately ended up with, we
           came up with more like ten to the minus six to the ten
           to the minus seven numbers when we took into account
           beyond design basis events.  The conditional -- or the
           vessel failure probability, given those events, was
           somewhat higher.  It certainly wasn't those low
           numbers.
                       But the other comment I'd make is that the
           analysis, methodology exists.  We know how to put
           models together, we know how to identify random
           variables, we know how to model those, how to do Monte
           Carlo simulations.  There's some challenges looking at
           dependence between the variables.  But the biggest
           challenge, and frankly I would say this is true in all
           our PRA modeling, is coming up with the distributions
           that represent those random variables.
                       For example, in this case, where one of
           the first things you had to look at was the initiating
           frequency, when does a crack initiate one of these? 
           There's very little data available until we started
           getting results from the inspections that were done
           and could try to construct a distribution.  So the
           biggest challenge that we have when we go into this
           sort of analysis is being able to define those random
           variables, the distributions for them, with some level
           of confidence.  And usually you have to go out and do
           some work, inspections or whatever to get the
           information to do that.
                       CHAIRMAN APOSTOLAKIS:  But speaking of
           that, though --
                       MEMBER POWERS:  Jack, you make huge
           amounts of -- when you do these probablistic fracture
           mechanics analysis, you're making huge simplifications
           in the way you describe the metal and the way you
           describe the crack, things like that.  And I guess
           what I'm struggling with is how do you know you got
           them all.  All the physics and all these
           approximations really are good ones to make.  I mean
           some of your approximations are made because you know
           how to solve the mathematics.
                       MR. STROSNIDER:  Well, again, I would come
           back to if you look at all these models have an
           underlying deterministic model associated with them. 
           If you look at the ability to predict crack growth
           rates as a function of stress intensity values, if you
           look at the ability to predict failure using either
           limit load or linear elastic correction mechanics,
           they work pretty well if you have a really well-
           controlled situation.  And it comes back again to
           defining the distributions that are associated with
           those in real life.  And I agree, that's a challenge.
                       MEMBER POWERS:  Well, every time I look
           for things that you predict well, you predict well
           those things that have been used to derive the
           physics, you know, nice, simple specimens, simple
           geometries.  Now, you're applying them in really
           complicated geometries.  There doesn't seem to be any
           database that I'm aware of, and I can't say that I've
           looked exhaustively, that says, okay, I've done my
           laboratory specimens, now I'm going to do this
           complicated thing that I don't understand very well
           and see if I can get it about right.  Is there such a
           database?
                       MR. HACKETT:  I guess the one -- this is
           Ed Hackett again -- I guess the one I could point out,
           Dr. Powers, is the one -- it's a complicated acronym. 
           They called it fracture assessment of large-scale
           international reference experiments; it's the FALSIRE
           project.  And then there have been follow-on series,
           and this is an international collaborative effort,
           where they have gone from the small specimen
           geometries where things are nice and fairly simple to
           predict, to trying to predict what actually happens in
           a vessel.  The Germans have blown up scale model
           vessels, we have at Oak Ridge.
                       MEMBER POWERS:  Yes.  Now you're hitting
           exactly what I want to see.
                       MR. HACKETT:  And we have in fact --
                       MEMBER SHACK:   Plus an enormous number of
           pipes at Battelle.
                       MR. HACKETT:  Absolutely.  The most recent
           one, thinking of the follow-on activity, the NESC 1
           spinning cylinder experiment in the United Kingdom. 
           In fact, the folks at Oak Ridge, using their
           probablistic model, the FAVOR code, which is what
           we're using in the PTS Program right now, predicted
           the propagation of an embedded flaw in that vessel
           almost dead on in terms of initiation and arrest.
                       CHAIRMAN APOSTOLAKIS:  Don't take the
           viewgraph down.
                       MEMBER POWERS:  But if somebody can point
           that out -- point it out to me or come present it or
           something like that, it adds a lot more credibility to
           some of these categories.
                       MR. HACKETT:  Probably in the context of
           the PTS project we'll do that.
                       MEMBER POWERS:  That would be great.  You
           know, if we could take a half an hour and just go
           through that, that would be great.
                       MEMBER FORD:  Could I suggest, Larry, that
           -- this will be --
                       CHAIRMAN APOSTOLAKIS:  What does it mean
           the probability is less than ten to the minus three? 
           Have you done an uncertainty analysis?  How uncertain
           is that?  How high can the ten to the minus three be?
                       MR. MATHEWS:  I don't have that right now.
                       CHAIRMAN APOSTOLAKIS:  But you will?
                       MR. MATHEWS:  I'm not sure we were going
           to do a full-blown uncertainty analysis.
                       CHAIRMAN APOSTOLAKIS:  Well, then what are
           you doing?  I mean there are so many questions about
           all this.  To give one number, what does it mean?  If
           the ten to the minus three can be ten to the minus
           one, I don't know what conclusion I can draw from
           this.  I mean all kinds of doubts have been raised,
           and it seems to me doing an uncertainty analysis means
           exactly, precisely to address these doubts and
           comments.  There's something about the five ten to the
           minus six that bothers me, okay?  That it was five ten
           to the minus nine and now it's ten to the minus six,
           that's all we learned.  I just don't believe that.
                       And the other thing I want to finish is
           that there is a certain pleasure in listening to Mr.
           Strosnider defend the probablistic method.  Usually
           he's a skeptic.  Today, he was on the other side.
                       MEMBER SHACK:   It's probablistic fracture
           mechanics he's defending.
                       CHAIRMAN APOSTOLAKIS:  I don't care what
           you put after probablistic.
                       (Laughter.)
                       It was nice to hear him talk that way.
                       MEMBER POWERS:  But, George, there is a
           difference.
                       MEMBER SHACK:   One's a science.
                       (Laughter.)
                       MEMBER FORD:  If I could just --
                       CHAIRMAN APOSTOLAKIS:  Go ahead, Dr. Ford.
                       MEMBER FORD:  -- move along here.  In
           defense of the MRP, a lot of this is dependent on
           having a reasonable database for crack growth rates
           upon which that is dependent.  Now I'm told that we're
           close to it.  The next meeting we will see that
           database, and then we will see the follow-on to your
           specific question.
                       CHAIRMAN APOSTOLAKIS:  Great.
                       MEMBER FORD:  -- on that particular
           kinetics-driven analysis.
                       Could I ask you to finish in five minutes,
           Larry?  I realize that I've now cut you down to your
           knees.
                       MR. MATHEWS:  I will.  In response to the
           Davis-Besse issue, we've had lots of interaction with
           the staff, but even before the bulletin came out we
           conducted, as an MRP, a survey, and it was based on
           some -- basically assumptions about what the possible
           causes at Davis-Besse were before the root cause or
           even the preliminary root cause was out.  And there
           were three possibilities that we tried to consider in
           our survey, and that was leakage from above, leakage
           from a crack in a nozzle or a combination of the two. 
           And then we'll be -- the ongoing Davis-Besse work will
           be used.
                       We did that survey, we came up with four
           questions basically aimed at how confident are you
           that you don't have wastage on your head?  And we
           received responses from all the PWRs in the country. 
           We wound up categorizing the responses into four
           categories plus another group that didn't quite fit,
           and they range from -- you know, category one was they
           got the best knowledge, they're darn certain, they've
           gone and looked, they don't have any wastage. 
           Category four, it was more like they were able to do
           from a historical view of leakage, et cetera, to feel
           confident.  And then there was a category, other, that
           they had leakage and perhaps had not fully cleaned it
           up or there was some other reason they didn't fit into
           one of the other categories.  And we categorized all
           these plants, gave the names of the plants to the
           staff, and I believe they've actually used our tables
           to help guide a little bit how they're contacting
           plants as far as what their intentions are.
                       This is our ranking of the units that we
           put together a while back.  If you look at it, the red
           triangles are the leaks, and most of those leaks are
           to the left of the graph, which is kind of where -- if
           the model's worth anything, that's where they'll be. 
           A couple outliers, we do have one plant that had some
           cracks that was a little bit further out.  Those
           cracks were nowhere near as severe as the cracks at
           these plants that have had leaks, so maybe we're
           picking up the precursor here.  That's something we
           have to look at.
                       All the blue diamonds have done
           inspections and haven't had leaks or the open blue
           diamonds are doing inspections this spring, yet to do
           a few plants in the fall and a few more next year. 
           We'll have done inspections per bulletin 2001-01.
                       Here's the table we sent to the staff. 
           Turns out most of the plants, as far as the wastage on
           the head, feel a good degree of confidence that they
           don't have any significance wastage on the head.  Some
           of these plants have even done inspections since then. 
           Cook 1 I know plans an inspection very soon.  Wolf
           Creek, I believe, has done an inspection, and I think
           Palo Verde just finished their inspection.  So most of
           these plants are moving into greater degrees of
           confidence that they really don't have an issue with
           wastage at this point in time.
                       MEMBER FORD:  You should point out that,
           Larry, that that's on the basis of your survey, not on
           the basis to the replies of 2002-1.
                       MR. MATHEWS:  Absolutely.  This was all
           put together -- it was probably right at about the
           time the bulletin was coming out or maybe shortly
           thereafter, but it was based on the response to our
           questions, not the responses to the bulletin.
                       A couple of points about that.  All the
           plants that are less than ten effective full-power
           years on our histogram will have been inspected by the
           end of this spring outage season.  That includes the
           highest ranked 20 units in the country.  And they
           should have a reasonable assurance that they don't
           have any significant corrosion on top of their head
           because of those inspections.  And of the plants that
           were less than 30 EFPY, 34 out of 45 will have
           inspected by this spring.  We're showing five in the
           fall and six in the spring of 2003.  There's a little
           bit of confusion right now.  We're not off more than
           one or two plants, I don't believe, but we've got to
           settle that out, straighten that out.
                       This is something that we wanted to say,
           that of the 34 leaking nozzles and penetrations that
           have been discovered to date, all of them displayed
           visible evidence of leakage or corrosion on top of the
           head, leakage primarily.  A total of 203 nozzles have
           been inspected at those -- let's see, is it nine
           plants where leaks have been discovered?  And NDE has
           confirmed through-wall leaks or cracks -- I mean
           through-wall defects in all 34 of the nozzles that
           showed leakage.  NDE did not detect through-wall
           defects in any of the others, and there have been,
           this says, four plants without evidence of leakage,
           and I'm sure by now it's much more than four plants
           have inspected the nozzles without any defects found.
                       MEMBER SHACK:   It would interesting on
           your chart, you know, where you've got the one with
           cracks that you found by NDE, to also see where the
           guys that inspected by NDE and found no cracks were on
           that chart.
                       MR. MATHEWS:  Yes.  Up until when I put
           that together there weren't a lot.  There was Cook 2
           and maybe a couple of others that had done volumetric,
           that didn't have a prior indication of a leak that
           they were going and confirming.  But we're getting
           more and more of the plants now that are doing
           volumetric inspections.  I think Palo Verde just
           completed a volumetric inspections, and I don't even
           have them marked as having done that.  But we will
           update the chart and try and figure out how many
           colors we could put on it.  But we'll do that.
                       Recent experience of the -- except for the
           Davis-Besse issue, in the other 31 leaking
           penetrations, there's no evidence of any significant
           corrosion or wastage.  There has been a hint at a
           couple of other nozzles that there was a little bit
           here and there on top of the head or whatever but no
           significant evidence.  And also on the plants that
           have repaired their nozzles that were leaking, most of
           those repairs have been performed using the Framatome
           repair technology where the nozzle is bored out and
           then rewelded up inside the head to the low alloy
           steel.  And if there were significant wastage there,
           it would have been evident.  They have to go PT that
           surface before they weld to it, and if there's a big
           gap, they can't even get it to weld.  So out of all
           those other nozzles, there hasn't been any significant
           wastage like the one big cavity at Davis-Besse.
                       CHAIRMAN APOSTOLAKIS:  So what do I learn
           from that?  What's the conclusion from that?
                       MR. MATHEWS:  Well, the conclusion is that
           something's different about Davis-Besse, the waste,
           the big cavity like they had compared to the rest of
           the industry.  And they're going to talk about it --
                       CHAIRMAN APOSTOLAKIS:  And the rest of the
           industry also had wastage there for the number of
           years that Davis-Besse had it?
                       MR. MATHEWS:  Well, that may be the key,
           and in fact it may be the difference between this one
           nozzle and the rest of them is the amount of time that
           the nozzle leaked.  And Davis-Besse will discuss that
           when they get up here.  That may in fact be the key is
           how long was the leakage allowed to go on without
           being detected?  But do I know that that's absolutely
           the reason?  I don't know that, not right now.  Okay.
                       I've only got two more.  Ongoing
           activities, we're reviewing or have reviewed the
           Davis-Besse initial root cause, and we will review the
           final root cause for generic implications of that and
           use that information to get back into MRPs
           recommendations as far as inspection to the plants. 
           And we're also taking a look back at the Owners' Group
           work that was done back in the early '90s.  They did
           some work on head wastage, and we want to take a look
           at that and see does this really change any of that?
                       CHAIRMAN APOSTOLAKIS:  Are you done?
                       MR. MATHEWS:  Yes.  I'll quit.
                       MEMBER FORD:  Questions?
                       CHAIRMAN APOSTOLAKIS:  Yes.  I mean I'm
           amazed that you say you are not planning to do an
           uncertainty analysis.  Uncertainty analysis is not an
           academic exercise.  You keep telling me that there are
           all these experts that are looking at the huge scatter
           of data and so on, and then at the end we're not going
           to do an uncertainty analysis.
                       MR. MATHEWS:  Well, we're definitely going
           to do all kinds of --
                       CHAIRMAN APOSTOLAKIS:  I'm amazed.
                       MR. MATHEWS:  We're going to do all kinds
           of sensitivity studies and look at the various
           parameters that go into the model and determine --
                       CHAIRMAN APOSTOLAKIS:  Sensitivity
           studies, are you going to do them two at a time, three
           at a time, variables, playing all sorts of games to
           really gain insights?  I mean to vary one variable at
           a time doesn't really do much for me.
                       MR. MATHEWS:  Well, the nature of the
           Monte Carlo is you do them all at once.
                       CHAIRMAN APOSTOLAKIS:  And that's a
           sensitivity study?
                       MR. MATHEWS:  No.  You do -- well, yes. 
           You put all of the uncertainty of all of the databases
           and all of that, it goes in there at one time and you
           do a Monte Carlo sample --
                       CHAIRMAN APOSTOLAKIS:  Well, that's not
           sensitivity, that's uncertainty analysis.
                       MR. MATHEWS:  Right.  But doing the
           sensitivity we'll go in and we'll change some of those
           parameters and distributions.
                       CHAIRMAN APOSTOLAKIS:  But you said you
           were not planning to do that.  That's why I'm amazed. 
           If you were planning to do it, I wouldn't be amazed.
                       MR. MATHEWS:  The term, "uncertainty
           analysis," caught me off -- we are going to do
           sensitivity studies to look at what the sensitivity of
           the analysis is to the various --
                       CHAIRMAN APOSTOLAKIS:  Well, that's a way
           of doing it.  That's a mechanics review.
                       MR. MATHEWS:  Yes.
                       MEMBER FORD:  Could I, just in terms of
           time management, call this one to a close but
           recognizing that there are questions along these
           lines, and when you come back within the next two
           months be prepared to answer them.
                       MR. MATHEWS:  Yes.
                       MEMBER FORD:  Mr. Chairman, am I allowed
           to go five, ten minutes over?
                       CHAIRMAN APOSTOLAKIS:  Well, if the Vice
           Chairman went over 45 minutes, I don't see why the
           members can't go over five minutes.
                       (Laughter.)
                       MEMBER FORD:  Okay.
                       CHAIRMAN APOSTOLAKIS:  There's no schedule
           today anyway, so keep going.
                       MEMBER ROSEN:  Let's establish some sort
           of quantitative mechanism or a curve here, we can
           begin to --
                       MEMBER POWERS:  Could I ask a question?
                       CHAIRMAN APOSTOLAKIS:  Yes, sir.
                       MEMBER POWERS:  Something perplexes me a
           little bit here.  The speakers indicated the time that
           the nozzle was allowed to leak, I guess is the word,
           and Davis-Besse may have been key.  And he said leak
           without being detected.  Okay?  And then we have
           inspections of the other things, which presumably have
           some probability of detection so that some of those
           declared not to have any cracks may in fact have
           cracks and may in fact be leaking but we just don't
           detect it.  What are we doing about that?
                       MEMBER FORD:  A related question to that
           is we are assuming that when you see a nozzle, the
           popcorn on the top of the nozzle, that is the
           sufficient evidence that you've got a crack
           underneath.  That's something that we've questioned. 
           Could you have a crack down below the J-weld and not
           see the popcorn at the top?
                       MEMBER POWERS:  Well, I think the answer
           to that is yes.
                       MEMBER FORD:  Well --
                       MEMBER SIEBER:  It's not through-wall or
           plugged.  Either way you won't get --
                       MEMBER FORD:  Well, plugged over the
           surface.  We've asked that question, and that's under
           consideration.
                       The other question is to whether from
           human error you don't see it.
                       MEMBER SIEBER:  Right.
                       MEMBER FORD:  That one has not been
           addressed apart from in the Duke presentation on
           Oconee the human error was addressed of not seeing it. 
           But recognize this is still a fairly recent
           phenomenon, if you like.
                       MEMBER POWERS:  Well, I mean isn't it the
           conclusion that you come out of this as, "Gee, our
           methods of inspection are inadequate."
                       MEMBER FORD:  This is something you may
           have from the staff, because this might be a policy
           decision.
                       CHAIRMAN APOSTOLAKIS:  I'm not sure it's
           the methods.  Ultimately goes to the safety culture.
                       MEMBER FORD:  But that question about --
                       CHAIRMAN APOSTOLAKIS:  It didn't say -- it
           doesn't say here that they didn't know because, it's
           just they didn't pay attention.
                       MEMBER FORD:  This question of management
           of this whole situation by inspectors --
                       CHAIRMAN APOSTOLAKIS:  This gentleman
           wants to say something; he's been trying for a while.
                       MR. MATHEWS:  I was just going to say that
           the human error -- this is Larry Mathews, I was just
           up there.  The human error part could be easily
           factored into the inspection on a probablistic
           fracture mechanics as a probability of detection.
                       CHAIRMAN APOSTOLAKIS:  It could be easily
           placed there.  Now what value you use is not going to
           be easy.
                       MR. MATHEWS:  Oh, yes.  We have to figure
           that out.
                       (Laughter.)
                       CHAIRMAN APOSTOLAKIS:  That's the whole
           issue.
                       MEMBER SHACK:   Sensitivity studies.
                       CHAIRMAN APOSTOLAKIS:  Oh, you do
           sensitivity, excuse me.
                       MEMBER FORD:  The answer to your question
           may well come up in the staff's presentation.  Could
           I ask the representatives from Davis-Besse to come up. 
           Normally half an hour but make sure you have enough
           time to present the stuff on the risk assessment
           aspect.  John Wood and Ken Byrd from Davis-Besse.
                       MR. WOOD:  Good afternoon.  My name is
           John Wood.  I'm the Vice President of Engineering
           Services for First Energy Nuclear Operating Company. 
           In our agenda today, I'll be discussing the
           information that we presented to the subcommittees on
           Tuesday.  And then at the end of that, we'll have, at
           the subcommittees' suggestion, a discussion of the
           safety significance assessment that was given to the
           staff early this week.
                       I'd like to just cover a couple points on
           background for Davis-Besse in that if you'll note in
           the middle there we have 15.8 effective full-power
           years at that Unit.  Toward the bottom, hot leg
           temperature is a little bit hotter than other Babcock
           & Wilcox plants at 605 degrees up.  That's about three
           or four degrees higher based on our core delta T.  And
           we have 69 nozzles at our Unit.  Sixty-one of those
           have control rod drive assemblies, seven are spare and
           one is used for a head vent that goes to our steam
           generator.
                       This is a depiction on the next page of
           our reactor pressure vessel head configuration.  The
           insulation is shown across horizontally here.  You'll
           note that the dose above the insulation in the area of
           the flanges is about one-half a rem per hour.  And
           beneath the head the dose is approximately three rem
           per hour.  And those are the fields that we have to
           engage as a head sits on the head stand.
                       In our next picture, or actually two
           pictures, what we have shown on this slide is the
           reactor vessel head sitting on the head stand in the
           left-hand picture with a couple gentlemen working up
           above.  The picture on the right has been cut open
           this outage in order to access at the flange level. 
           That area is 20-some feet below where those gentlemen
           on the left are standing, so typically people would be
           working in and around the flanges using 20-foot-long
           handled tools.
                       The next diagram depicts a typical B&W
           control rod drive nozzle.  It is shown in its
           position.  There's a shrink fit of about one-half to
           one and a half mils that enters into the low alloy
           carbon steel.  You can see there the shell cladding
           and the J-groove weld.  Now, when I talk in a little
           bit about cracks, the cracks that we have depicted
           actually are on the OD of the tube on the wetted side,
           or ID, of the main reactor vessel head.  And then
           through-cracks would go up past the weld into this
           annular space here.
                       We went through details Tuesday with the
           subcommittees in regard to the UT examinations that we
           performed at Davis-Besse.  This picture depicts the
           below or underhead UT examination tool.  It has been
           demonstrated, using EPRI capability, to detect actual
           and circumferential flaws.  It is delivered with a
           robotics system and an automated data acquisition
           system.  This was used on all 69 nozzles at Davis-
           Besse, and then those nozzles produced indications of
           flaws were also inspected the top-down UT examination
           tool, and that has ten transducers in order to
           characterize the flaws.
                       MEMBER POWERS:  Would you give me an idea
           how long it took to inspect 69 --
                       MR. WOOD:  That inspection period for
           Davis-Besse was approximately 96 hours.  And that is
           around-the-clock time.
                       Our UT examination results, and these,
           again, were detected with the underhead and then
           confirmed top-down, are shown on the next page. 
           You'll see that there's six nozzles listed here.  The
           first five had cracks indicated, the first three were
           the through-wall cracks.  You can see Nozzle 1 had
           nine actual tracks, two went through-wall, and nozzle
           Number 2 had eight actual cracks, one circumferential
           flaw.  And that circumferential flaw was approximately
           30 degrees, a little bit more than an inch in length,
           1.2 inches in length, and was about 50 percent
           through-wall for the nozzle.  I should mention also
           the nozzle is approximately 0.63 inches thick.
                       Number 3, of course, the one that has the
           cavity associated with it, had two through-wall leaks
           and there were cracks on Nozzle 5 and 47.  Number 46
           did not have a crack indicated; however, there's an
           investigation with a backwall signal on 46.
                       CHAIRMAN APOSTOLAKIS:  These examinations
           were done when?
                       MR. WOOD:  These were done approximately
           in early March, the first week in March.  Actually,
           the last part of February, early March.
                       CHAIRMAN APOSTOLAKIS:  After the problem
           was found.
                       MR. WOOD:  That's -- no.  This led to the
           finding of the problem.
                       CHAIRMAN APOSTOLAKIS:  Oh, this led to the
           problem.
                       MR. WOOD:  That's correct.  This was the
           100 percent UT examination of the nozzles at Davis-
           Besse was done in conjunction with our answering of
           2001-01 in our extension from the end of the year to
           February 16.
                       CHAIRMAN APOSTOLAKIS:  But were
           examinations like this done routinely and on a
           periodic basis?
                       MR. WOOD:  No.  At the time, we had the
           most extensive examination of the head using
           ultrasonic examinations.
                       CHAIRMAN APOSTOLAKIS:  So that was the
           first time you did this?
                       MR. WOOD:  That's correct.
                       MEMBER POWERS:  These were surprises to
           you?
                       MR. WOOD:  It was not entirely surprising
           that we had axial cracking.  Based upon the
           information of 2001 and the information that we were
           getting from the industry, we expected to find some
           cracking.  We did not expect to find through-wall
           necessarily and certainly didn't expect to find the
           cavity that we found on Nozzle 3.
                       MEMBER POWERS:  I'm sure that was a -- but
           I'm just asking about the --
                       MR. WOOD:  Right.  In fact, our plans
           included fixing up to four nozzles in our base plan
           for this refueling outage.
                       This diagram lays out the nozzles that
           were found with cracks.  Those are indicated in both
           the red and the green.  I will note that the five
           nozzles in the center of the head are all from the
           same heat, and I'll talk about that later.  Those are
           the only five nozzles from that heat at our Plant. 
           You can see Nozzle 2, which had the circumferential
           crack, was located in this quadrant, and there was a
           very small amount of wastage in this area of Nozzle 2
           that I'll talk about in a little bit as well.
                       I guess that's the next slide.  As we were
           going through the repair process for the nozzles, we
           did note, as it's shown here, as we machined up, as
           Larry discussed the repair process used by Framatome,
           you machine up and then the intent is then to weld
           onto the carbon steel.  We did find a small cavity in
           that area.  Its dimensions are approximated on this
           sketch.  We have since removed that nozzle for further
           clarification.  It is essentially as depicted here. 
           It goes about a quarter to three-eighths maximum
           depth, as indicated in the reactor vessel head.
                       MEMBER POWERS:  You mentioned that the
           afflicted nozzles came from a particular heat, and the
           reason you know that is because of your Appendix B
           requirements?
                       MR. WOOD:  That is part of the MRP process
           that we have been working on and also the response of
           2001 and the Babcock & Wilcox Owner Group efforts,
           knowing what the heat numbers are for the various
           nozzles in all the plants.
                       The primary reason we're here today is the
           Nozzle 3 cavity.  This is depicted in this drawing, or
           this picture.  I will remind you that this circular
           hole where the nozzle was located is approximately
           four inches across.  You can see there is some wastage
           on the right-hand side at the surface level, and this
           is the stainless steel cladding evident at this
           location.  This is our number one nozzle, so this
           would be the dead center of the head, and flow
           downhill in that direction.
                       The next page is more of a display of some
           of the numbers that we have determined using various
           tooling.  It does not show the surface wastage that is
           off to the right.  You can see there's a difference in
           color here.  This is to represent a nose or an
           overhang, and there is additional erosion at -- or
           corrosion that goes on underneath that zone.
                       You'll also notice that there is a
           proposed 13-inch circular cut line indicated here.  In
           order to better capture this area, we're going to cut
           that out in one piece using an abrasive water jet, and
           that will then be retained for further evaluation as
           we go forward.  That abrasive water jet will also
           leave us a very smooth finish that we can then prepare
           a final fit up of the forged disc that we discussed in
           concept yesterday with the NRC staff.  The exact
           location of that cutout will be determined to optimize
           all things involved.
                       After we found the cavity area around
           Nozzle 3, we chartered a root cause initial
           investigation team using First Energy personnel to
           lead the effort.  Those individuals were not from the
           Davis-Besse staff.  We did include members from the
           Davis-Besse staff on the team, as well as augmented it
           with industry experts from Framatome, Dominion
           Engineering and EPRI, as listed here.
                       The team came up with a probable timeline
           using best engineering judgment in looking at the
           evidence that we had from the period of time in
           question.  What you see here is a summary of that
           probable timeline.  It shows that the crack
           potentially propagated through-wall in the '94 to '96
           time frame, and thus went basically unaddressed for a
           period of two to three operating cycles.
                       CHAIRMAN APOSTOLAKIS:  Now, that's where
           I have a question.  What does that mean?  Were you
           aware that there were cracks?
                       MR. WOOD:  No, we were not aware that
           Davis-Besse had cracks at that time.
                       CHAIRMAN APOSTOLAKIS:  So when you say
           unaddressed, what do you mean by unaddressed?
                       MR. WOOD:  Unaddressed means that the leak
           was allowed to be active without awareness for that
           period of time.
                       CHAIRMAN APOSTOLAKIS:  Did you have any
           indications there was a leak?
                       MR. WOOD:  In a retrogressive look,
           certainly there were missed opportunities, and I
           believe the staff will relate those as well.  And as
           I go through some of the contributing causes, there
           were reasons that the staff used to perhaps not center
           on those clues that a leak was occurring on the nozzle
           region.
                       Now, I'll talk --
                       CHAIRMAN APOSTOLAKIS:  All the rules and
           regulations were followed.  You were not in violation
           of anything.
                       MR. WOOD:  I don't think I'm in a position
           at this point to say that there was nothing that was
           violated.  Certainly, there were people with very good
           intentions that were doing the things they thought
           were right.  As we look back, things did not go
           according to the desires and the expectations that
           should have been in place.
                       CHAIRMAN APOSTOLAKIS:  And that was, in
           your opinion, more a matter of judgment, which perhaps
           was poor in this case?
                       MR. WOOD:  Certainly, poor judgment.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MEMBER LEITCH:  What gives rise to the
           probability that the crack initiated about three years
           before it went through-wall?  Is that based on some
           crack growth rate?
                       MR. WOOD:  That's based on the same crack
           growth rate that you would have heard from the MRP
           individual -- Larry.
                       MEMBER LEITCH:  Then I guess one could
           assume that since we see no crack in Nozzle, what is
           it, four?
                       MR. WOOD:  Number four.
                       MEMBER LEITCH:  That we have a certain
           degree of confidence that it would not go through-wall
           within one cycle of operation.
                       MR. WOOD:  That's correct.  But that's
           based on probabilities and not certainty.
                       MEMBER LEITCH:  Yes.  Because Nozzle 4
           seems like it's crying out to crack, right?  I mean
           it's
                       MR. WOOD:  Well, and there have been
           numerous people, including myself, who have asked over
           and over and been told again and again that Number 4
           does not have cracks.
                       MEMBER SIEBER:  Yet.
                       MR. WOOD:  Yet.  And that's an important
           yet, and that's true with all the nozzles that are in
           that head.
                       MEMBER LEITCH:  Okay.  Thank you.
                       MR. WOOD:  Now, the probable cause here is
           really of the failure mechanism, that being the
           cracking.  And since we were in the repair process
           prior to finding the cavity -- as I have mentioned
           earlier, the repair effort requires us to grind up the
           nozzle from below to above the J-groove weld, and so
           the cracks themselves were taken out as a result of
           doing that.  So that's why it's listed as probable
           cause because we don't have material to identify it as
           a factual root cause.  But every indication --
                       MEMBER SHACK:   Nobody tried to map the
           cracks as they were grinding them either.
                       MR. WOOD:  That's correct.  We did have UT
           data that we showed the subcommittees Tuesday that
           mapped them out in the general sense but not to
           progress and grind in PT, as an example.
                       With what we know that is happening in the
           industry on Alloy 600 and the control rod drive nozzle
           issue, we feel confident that it is primary water
           stress corrosion cracking that resulted in the crack
           initiating propagation and then allowed leakage to the
           reactor vessel low-alloy steel head.
                       MEMBER FORD:  If I could ask a question. 
           It's fairly obvious that the initiating event was
           primary water stress corrosion cracking rising to a
           liquid of some sort in the annulus.  But the key
           question is why did that environment give erosion or
           corrosion of the low-alloy steel in your condition but
           did not in many of the others, like Oconee?  And
           that's the root cause question that needs to be
           answered.
                       MR. WOOD:  Correct.  And the root cause of
           the cavity being there is this next page.
                       MEMBER FORD:  Okay.
                       MR. WOOD:  And that is our Boric Acid
           Corrosion Control and In-Service Inspection programs
           did not allow us to see that leakage at an earlier
           time.  Now, this is, again, looking backwards at the
           data that we had at hand, but we feel that the leak
           had existed through-wall for two to perhaps three
           operating cycles and thus did not allow us to identify
           that --
                       CHAIRMAN APOSTOLAKIS:  I'm confused by the
           words on this slide.
                       MR. WOOD:  Okay.
                       CHAIRMAN APOSTOLAKIS:  "The Boric Acid
           Corrosion Control and In-Service Inspection programs
           and the program implementation resulted in the Plant
           not identifying the through-wall crack."  What does
           that mean?  That the program resulted in you not
           identifying it?
                       MEMBER SHACK:  The failure to implement
           the Boric Acid Control Program.
                       MR. WOOD:  Right.
                       CHAIRMAN APOSTOLAKIS:  Oh.
                       MR. WOOD:  The Program neither robust
           enough nor was it implemented sufficiently in its form
           to detect the crack.  So had it been, let's say, more
           robust and more rigorous applications, that would have
           been one approach.  Even apart from that, had it just
           been implemented appropriately or properly, it would
           have been the other case.
                       CHAIRMAN APOSTOLAKIS:  So you are blaming
           both the Program and the implementation, at this point
           anyway.
                       MR. WOOD:  That's correct.
                       MEMBER SIEBER:  Now, I have a question. 
           You, actually, when you asked for your extension from
           the bulletin schedule for inspections, you relied on
           videotapes, as I understood it, to say that leakage
           was not there?
                       MR. WOOD:  Yes.  And what I think is being
           asked, as we went through the effort on 2001-01 to
           extend our outage from the end of the year, as was
           requested from the staff, until the time of February
           16, we did an evaluation of the information we had in
           hand and knowing that there was some boric acid in the
           vicinity, the thought of the staff was that that boric
           acid had come down from the flanges from above and the
           mindset, for whatever reason, was focused on circ
           cracking and not on the potential wastage issue that
           we eventually found.
                       MEMBER SIEBER:  Did anybody from the NRC
           staff see those videotapes before the extension was
           granted?
                       MR. WOOD:  I cannot answer that question
           directly.
                       MR. BATEMAN:  Yes, I can answer that
           question.  We spent about three hours looking at
           videotapes from the 1996 inspection, the 1998
           inspection and the 2000 inspection.  And there were
           substantial amounts of boric acid on the head at that
           time.
                       MEMBER SIEBER:  Did you, like the
           Licensee, assume that it came from the joint in the
           housing up above?
                       MR. BATEMAN:  We did not have that
           discussion at that point in time.
                       MEMBER SIEBER:  Okay.  Thank you.
                       MR. BATEMAN:  By the way, Bill Bateman
           from the staff.
                       CHAIRMAN APOSTOLAKIS:  So let me
           understand the second bullet here, "Plant returning to
           power with boron on the RPD head after outages."  So
           Plant personnel knew that there was boron on the RPD
           head after outage?
                       MR. WOOD:  There were individuals at the
           Plant that knew there was boron on that head, that's
           correct.
                       MEMBER SIEBER:  And, apparently, the staff
           did too prior to granting the extension.
                       CHAIRMAN APOSTOLAKIS:  They thought it was
           coming from the flanges.
                       MR. BATEMAN:  This is Bill Bateman from
           the staff again.  I want to make it clear that the
           videos that we looked at were videos inside the shroud
           area around the mechanisms, not outside where the weep
           holes -- I think you saw the picture yesterday --
           where the weep holes actually -- it dripped down from
           the holes onto the -- near the bolt circle on the
           head.  We did not look at -- we did not see those
           particular pictures.  We were inside that shrouded
           area of the videos that we looked at.
                       MEMBER SIEBER:  This was through those
           mouse holes.
                       MR. BATEMAN:  Right.
                       MEMBER SIEBER:  Camera on a stick?
                       MR. BATEMAN:  Right.  Yes.  Those are the
           videos we looked at.
                       MEMBER SIEBER:  Okay.
                       CHAIRMAN APOSTOLAKIS:  Okay.  You said,
           Jack, that they knew there was boron there and they
           assumed it came from the flanges.  So what, didn't
           they still need to clean it up?  I mean whether you
           clean it up depends on where it's coming from?
                       MEMBER SIEBER:  I would have thought so at
           the time, but I'm not sure that everybody makes their
           -- up until today, makes their reactor vessel head
           squeaky clean each time they do an inspection.
                       CHAIRMAN APOSTOLAKIS:  But there's a
           difference between each time and not doing three or
           four times.
                       MEMBER SIEBER:  That's true.
                       MEMBER POWERS:  By the way, George, I just
           remind you of a point that was made at the beginning
           of the presentation.  This is -- doing things on the
           vessel head that aren't absolutely required is a
           highly costly thing, not only in time but because of
           the radiation dose that you incur to your workers.  So
           if you don't think you have to do it, you're probably
           not going to do it.
                       CHAIRMAN APOSTOLAKIS:  So the question is
           when do you decide that you have to do it?
                       MEMBER POWERS:  That's right.
                       CHAIRMAN APOSTOLAKIS:  Now, maybe you have
           already explained it, what is 12RFO?
                       MR. WOOD:  Twelfth refueling outage. 
           We're currently in our 13th refueling outage.
                       CHAIRMAN APOSTOLAKIS:  Okay.  Thank you.
                       MR. WOOD:  Okay.  And as we have just been
           discussing, the environmental conditions which
           contribute to this is the cramped conditions of the
           design.  And by that I mean there's about two inches
           of clearance between the top of the head and the
           insulation.  As was mentioned, we have 18 weep holes
           near the bottom that provide us some access.  And we,
           therefore, did not take appropriate compensatory
           measures as a result of these cramped conditions to
           allow ourselves to find that leakage.
                       Another contributing cause was the fact
           that in the late '80s, early '90s, there was much
           leakage of the CRDM and flanges above the insulation,
           which allowed some boron to pass through to the head
           and participated in the mindset of the staff at the
           time.
                       Now, I did mention the fact that we had a
           material heat that was unique for five nozzles, four
           of which had cracking, three of which had through-wall
           cracking.  And all three of those nozzles that had
           through-wall were from this heat listed.  We're aware
           that that heat is used at two other B&W plants.  One
           plant has all but one of their nozzles from that heat;
           another B&W plant has one nozzle from that heat.  The
           one that has the majority has been well-inspected and
           has thus contributed to a database that suggests that
           20 percent of this particular heat of nozzles has
           cracked or has had evidence of cracking thus far.
                       We spent some time Tuesday talking about
           crack length versus leakage.  I don't intend to go
           into a long conversation on that, but I did want to
           mention that our unidentified leak rate at the Plant
           during the period of time in question was
           approximately 0.1 to 0.2 gallons per minute.  So that
           is well below the tech spec limit of one gallon per
           minute.  And you can see the fact that the longer
           crack lengths have more damaging corrosion resulting
           from them.  Whether that's just evidence that it is
           interesting at this point or it is matter of fact, we
           don't know for certain.
                       MEMBER POWERS:  Could you give me some
           idea of what the width of the cracks is?
                       MR. WOOD:  The width of the crack, I don't
           have that information.  I don't know if anyone from
           the staff does in the back there.
                       MEMBER POWERS:  Real tiny, as big as my
           finger?
                       MR. WOOD:  Very tiny, and we're talking in
           the orders of a thousandths of a gallon per minute up
           to the 0.2, 0.8 region.  And so --
                       MEMBER POWERS:  That's what I was looking
           for.
                       MR. WOOD:  Okay.  As a result of our
           meeting Tuesday and getting together with --
                       CHAIRMAN APOSTOLAKIS:  Before we go on, if
           I were to take with me the top two causes why this
           situation developed, what are they?  Something must
           have gone wrong someplace, so what are the top two
           causes, so I remember?  I read a lot of stuff and they
           say a lot of things, the timelines and this and that,
           but if you ask me what was the number one and number
           two contributing causes, I have difficulty figuring
           those out.  So can you summarize them for us?
                       MR. WOOD:  Well, I think number one was
           the Boric Acid Control Program and the application of
           that.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. WOOD:  I guess almost everything else
           pales by comparison.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MEMBER KRESS:  I would have listed the
           potential for having a bad heat.  There are cracks
           already there.
                       MR. WOOD:  Granted however in this
           business we're accustomed to dealing with things that
           may be first of a kind or second of a kind or
           whatever.  So we wouldn't want to use the fact that we
           had a bad heat as the indicator of the cavities, the
           indicator of the crack.
                       MEMBER KRESS:  You still have to deal with
           those.
                       MR. WOOD:  Correct.
                       MEMBER SIEBER:  There may be an issue of
           standards involved too on the part of the inspection
           personnel and decision makers.
                       MR. WOOD:  Yes.  Those standards of course
           will go to the very top.  That's where standards come
           from.
                       CHAIRMAN APOSTOLAKIS:  I'm sorry.  What
           standards are these?  I missed it.
                       MEMBER SIEBER:  The kind of standards one
           would expect from a professional organization that
           operates a nuclear power plant.
                       CHAIRMAN APOSTOLAKIS:  Isn't that what
           some other people call safety culture?
                       MEMBER SIEBER:  That's a piece of safety
           culture.
                       CHAIRMAN APOSTOLAKIS:  Yes.  It can be all
           of it.
                       MEMBER SIEBER:  Questioning added to high
           standards.
                       CHAIRMAN APOSTOLAKIS:  Yes.  Okay.
                       MEMBER SIEBER:  Vigilance.
                       MEMBER ROSEN:  The application of the
           corrective action systems.
                       CHAIRMAN APOSTOLAKIS:  Okay.  Thank you.
                       MR. WOOD:  Okay.  Then as a result of our
           meeting on Tuesday, Peter Ford asked that we would
           include safety significant assessment.  So we have Ken
           Byrd who will present that.
                       MR. BYRD:  Okay.  My presentation will be
           a very brief summary of the results of a safety
           significance assessment that was provided to the staff
           earlier this week.  For this assessment, we considered
           a range of breaks from very small to the size
           described on the top of this page 23.  
                       So that for the maximum size, we assumed
           the failure of the exposed cladding area which is
           approximately 25 square inches.  In addition, we
           assumed that the whole was 50 percent larger than the
           exposed cladding area for about 38 square inches.  
                       We also assumed that CRDM Number 3 would
           eject.  So our total area was approximately 50 square
           inches or 0.35 square feet.  We're looking at a range
           from very small up to 0.35 square feet.  For our
           analysis, we evaluated three critical functions.
                       MEMBER ROSEN:  Now before you get off that
           in terms of assumptions.  You've obviously made the
           assumption although it's not shown here that nothing
           else was damaged.  There was no additional damage.
                       MR. BYRD:  No, sir.  I'm going to talk
           about that next when I look at these next three
           functions.
                       MEMBER ROSEN:  Okay.
                       MR. BYRD:  I'll get to that.  We looked at
           three critical functions when we did this analysis. We
           looked at the ability to have core cooling, to
           maintain shut down margin, and finally containment
           integrity.
                       We do not have a Davis-Besse ACE, an
           analysis for a LOCA at this specific location. 
           However our LOCA analysis covers a spectrum of LOCAs
           from 0.01 square feet up to 14.2 square feet.  
                       Setting aside at the moment collateral
           damage, this particular LOCA is equivalent to a hot
           leg LOCA with respect to core cooling.  In that
           respect we would get injection flow going through the
           core for both core cooling and for boron precipitation
           control.  Therefore with respect to core cooling, we
           were bounded by our existing LOCA analysis.
                       Let's go on to my second bullet here which
           relates to shut down margin.  I think this is where we
           get into the concern about the issue of collateral
           damage that might occur to adjacent control rod drive
           mechanisms.  Consequently we had Framatome ANP do an
           evaluation of the potential for damage to adjacent
           control rod drive mechanisms.
                       The Framatome Analysis looked at several
           different mechanisms.  They looked at jet loadings. 
           They looked at pressure loadings.  They looked at
           loose debris which might mechanically jam an adjacent
           control rod drive mechanism.
                       The results of their analysis was that it
           was unlikely that an adjacent control rod drive
           mechanism would be affected.  Not withstanding that
           result, we went ahead and had them do a further
           analysis to look at the impact of all of the control
           rod drive mechanisms.  We actually looked at five
           control rod drive mechanisms surrounding the affected
           area.  
                       Failing to insert is a result of
           collateral damage.  In addition to that, we added one
           additional control rod which would be a random control
           rod failing to insert with the highest shut down
           margin for that control rod.  With those six control
           rods failing to insert as a result of this accident,
           we were able to have both immediate and long term shut
           down margin.
                       MEMBER ROSEN:  Is that for the conditions
           that the Davis-Besse found themselves in at the end of
           the day on February 16 or whenever it was that you
           shut down?  Was that a more general conclusion for any
           time during the cycle?
                       MEMBER FORD:  Before you answer, Ken,
           could you just let the Committee know if the staff
           have not reviewed this analysis yet?
                       MR. BYRD:  No.
                       MEMBER ROSEN:  So let me repeat my
           question.  Is that result that you had plenty of shut
           down margin even with those six rods not reinserting? 
           Was that a general result for if this had happened at
           any time during the cycle or a specific result that
           applies only to that day, the day you shut down?
                       MR. BYRD:  It was really intended to apply
           only to that day.  But the analysis was done using the
           beginning of life for cycle 14 which was actually a
           more conservative time period.
                       MEMBER ROSEN:  Okay.
                       MEMBER SIEBER:  But is the break size you
           had, the larger the break the better able you would be
           to get reactivity reduction because of the insertion
           of highly borated water?
                       MR. BYRD:  Yes, sir.  That would be true.
                       CHAIRMAN APOSTOLAKIS:  The rod ejection
           effect is instantaneous, but you're at full power.  So
           you have some full power conditions.
                       MEMBER SIEBER:  Right.
                       MR. BYRD:  Right.
                       CHAIRMAN APOSTOLAKIS:  So that reduces the
           concern with the rod ejection.
                       MR. BYRD:  Okay.  If I could go on to the
           third condition that we considered.  We also
           considered containment integrity.  The issues we were
           concerned with here were two issues.
                       One was the control rod ejection, actually
           impacting on our containment.  The other issue would
           be the mass and energy release from the particular
           LOCA.
                       With respect to the first of these issues
           at Davis-Besse, we have missile shields above the
           control rod drive mechanisms which would prevent an
           ejected control rod from impacting a containment. 
           With respect to the second issue, mass and energy
           release, this particular LOCA is bounded by much
           larger LOCAs which have been analyzed.  So we did not
           see any significant issues with respect to containment
           integrity.
                       MEMBER POWERS:  Let me ask a question that
           you may not have the answer to.  If you have blow out
           in that particular location, do you put an unusually
           large amount of mass into your sumps that could clog
           some pumps and things like that?
                       MR. WOOD:  No.  That area would not be
           directly driven towards the sumps.  That would be
           within the refueling canal.  Then you saw the service
           structure arrangement around it.  So there's not a lot
           of direct accessibility out of that into the sump area
           which is quite a ways away from that.
                       MEMBER SIEBER:  The refueling canal is
           empty during operation.
                       MR. WOOD:  That's correct.
                       MEMBER SIEBER:  You use a diaphragm
           between the vessel flange and the edge of the canal.
                       MR. WOOD:  No.  There would be an opening
           in that area.
                       MEMBER SIEBER:  During operation.
                       MR. WOOD:  During operation.
                       MEMBER SIEBER:  That's the flow path to
           the sump.
                       MR. WOOD:  Right.
                       MEMBER SIEBER:  Okay.  So there is a
           connection.
                       MR. WOOD:  The sump itself is up on a
           different level beneath the head.  But would initially
           accumulate.
                       MEMBER SIEBER:  Okay.
                       MEMBER POWERS:  So it's a fairly contorted
           path that something would have to follow to get to
           your sump.
                       MR. WOOD:  That's correct.
                       MEMBER SIEBER:  It would have to go
           uphill.
                       MEMBER POWERS:  It wouldn't be so uphill.
                       MEMBER ROSEN:  The insulation that's above
           the head in that region is reflective insulation. 
           There's no silicacious insulation.
                       MR. WOOD:  That's correct.
                       MEMBER ROSEN:  That's all metal in pipe
           insulation.
                       MR. WOOD:  Right.
                       MEMBER POWERS:  That didn't help you much.
                       MEMBER KRESS:  It's gets really pushed
           around a lot.
                       MEMBER ROSEN:  Well it does actually.
                       MR. WOOD:  However all that insulation
           would have been inside of the service structure.
                       MEMBER ROSEN:  The three GSI-199 is the
           most damaging kind of material.  It is the kind of
           material that can plug the screens.  Typically it's
           the silicacious sand-like material that -- 
                       MEMBER POWERS:  No.
                       MEMBER ROSEN:  Plans toxin fibrous
           material and end up building the building up across
           the sumps.
                       MEMBER POWERS:  Fibrous material is of
           course very bad.  But we've seen experiments showing
           that you can shred this stuff up.  That shredded
           material is not too good either.
                       MEMBER ROSEN:  It may be.  But I think if
           you read GSI-199, the most recent staff stuff that
           came out of, which lab?  I'm trying to remember which
           lab.  I think that report indicates that the worst
           material comes out of Los Alamos and the University of
           New Mexico.  So I'm reasonably familiar with it.
                       MEMBER FORD:  If I could interrupt, could
           we just get this one through?  Again I'm looking at
           the time.
                       MR. BYRD:  Okay.  Going on to the next
           page.  As a further effort to address the safety
           significance of this condition, we had a stress
           analysis of the as-found head condition performed. 
           This stress analysis is a three-dimensional finite
           element, stress analysis of the wasted -- and the
           reactor pressure vessel head.  
                       We had a failure criterion set at the
           maximum strain of 11 percent through the thickness of
           the clad.  We had the results verified by an
           independent analysis.  We had this both performed by
           Framatome ANP and Structural Integrity Associates.
                       The results were that the degraded cavity
           would maintain its integrity in excess of twice the
           transient loads.  The results for the two analyses
           were fairly consistent.
                       MEMBER SHACK:  What's the rational for the
           11 percent?
                       MR. BYRD:  This particular analysis is an
           input to my safety assessment.  I think I have an
           expert here from Framatome who could probably address
           that better than I can.
                       CHAIRMAN APOSTOLAKIS:  Please identify
           yourself.
                       MR. FYFITCH:  I'm Steve Fyfitch from
           Framatome.  The rational here is that's actually a
           conservative value that they used for the analysis. 
           The 11 percent comes from an Oak Ridge report that we
           have access to that looks at 308 in stainless steel
           weld metal.  
                       The 11 percent is where necking starts to
           occur in the tensile test.  We assumed that 11 percent
           was the failure strain.  So it's in fact a very
           conservative because once the uniform elongation
           starts to disappear, it actually goes out and total
           elongation about 30 percent.
                       MR. HACKETT:  Bill, this is Ed Hackett
           from the staff.  A follow up to that would be we're
           doing confirmatory analyses too as you know for the
           criterion failure strain.  That number probably needs
           to be adjusted, Vom Mises or Treca for the multi-axial
           state of stress that would exist in the head.
                       So probably the real number should be less
           than 11 percent.  I don't know what the number should
           be.  As Steve pointed out, that number is from uni-
           axial tension test.  So what you have is at least a
           bi-axial state of stress in the head.  That will come
           down somewhat.  We're looking into that right now.
                       MR. HERMANN:  Ed, I think in the models
           the tensile stresses that were taken were compared to
           Vom Mises output in the models.
                       MR. HACKETT:  The 11 percent already
           reflects a Vom Mises or Treca adjustment.
                       MR. HERMANN:  Yes.  It's just a comparison
           of what came out of the tensile stress versus that's
           not what was in the model.  It was just a comparison
           of that.  A unilateral strains.
                       MR. HACKETT:  Okay.  Thanks.
                       MEMBER FORD:  For the Recorder, that was
           Bob Hermann.
                       MR. HERMANN:  Bob Herman from Structural
           Integrity.
                       MR. BYRD:  Now going to my last page.  The
           results of this analysis on the previous page
           indicated that the expected failure pressure was well
           in excess of the pressure for any postulated
           transients.  It's also well in excess of the pressure
           for any transients that have actually been experienced
           at Davis-Besse.  
                       However to estimate a risk of the as-found
           condition, we looked at the probability of a failure
           occurring at less than this estimated pressure based
           on our stress analysis.  The results of this indicated
           that there are core damage frequency we estimated to
           be in the range of 1 times 10 to the minus 5th per
           year.  The larger the release frequency was
           approximately of 1 times 10 to the minus 8th per year. 
           Our public health risk was approximately 0.56 person
           rem per year.
                       CHAIRMAN APOSTOLAKIS:  Are these Deltas
           given these conditions?
                       MR. BYRD:  Yes, sir.  These are Deltas.
                       CHAIRMAN APOSTOLAKIS:  So what is your
           baseline CDF?
                       MR. BYRD:  My baseline currently for
           internal events is 1.2 times 10 to the minus 5th per
           year.
                       MEMBER ROSEN:  Ten to the minus what?
                       MR. BYRD:  Fifth per year.
                       CHAIRMAN APOSTOLAKIS:  So your doubling.
                       MR. BYRD:  Approximately doubling our
           internal event baseline.
                       MEMBER SHACK:  Now as I'm corroding away
           at two inches a year, how many weeks do I have to wait
           until this thing goes?
                       MR. BYRD:  We have that analysis currently
           in progress.  We're expecting an answer to that
           relatively soon.  We have an analysis that will give
           us the size at which point we would have a failure at
           a normal pressure.  As far as how long it would take
           to get to it, I think that's a little bit more
           speculative.
                       CHAIRMAN APOSTOLAKIS:  So this is given
           that I have the amount of degradation that was
           observed, the core damage frequency would be 10 to the
           minus 5.
                       MEMBER KRESS:  The maximum it could be is
           conditional.  What's the conditional core damage
           frequency?
                       CHAIRMAN APOSTOLAKIS:  Well it is
           conditional.
                       MEMBER KRESS:  Given that you have the
           hole there.
                       CHAIRMAN APOSTOLAKIS:  Oh, the hole.
                       MR. BYRD:  If we had a LOCA?
                       MEMBER KRESS:  Yes.
                       MR. BYRD:  That would be a conditional
           core damage probability.  In the calculation of this
           core damage frequency, we evaluated the conditional
           core damage probability from a range all the way to
           very small up to the 0.36.  The largest was at about
           0.1 square feet.  That was 2.9 times 10 to the minus
           3rd.
                       CHAIRMAN APOSTOLAKIS:  You said 0.36?
                       MR. BYRD:  The hole size with the maximum
           core damage probability.
                       CHAIRMAN APOSTOLAKIS:  So you estimated
           the probability of this LOCA to be the order of 7 10
           to the minus 3.
                       MR. BYRD:  I'm sorry.
                       CHAIRMAN APOSTOLAKIS:  What's the
           frequency of this LOCA?
                       MR. BYRD:  I guess it might be easiest if
           I could just take a minute here and walk through the
           process because I think I have a few questions. 
           Essentially what we did was we understood that at the
           pressure we calculated we weren't supposed to get a
           failure.  So we looked at ways that this would fail at
           less pressure.  
                       There's a couple of things that came to
           our mind.  One was a sizemic event.  The other being
           overpressure transients that didn't actually get to
           this pressure.
                       With respect to the sizemic event, we have
           recently completed a sizemic PRA.  We looked at that. 
           Based on the results of that a sizemic event of
           sufficient magnitude to cause this damage in Northwest
           Ohio the frequency is very small.  So that was a very
           small contributor.
                       The other thing that we looked at though
           was overpressure transients.  We recognized that this
           number that we had from the stress analyses is a
           calculated number.  It's dependent on a number of
           things such as the analysis, the actual condition of
           the clad, and the material strength.
                       So we employed a process that is outlined
           in NUREG 2300, the PRA Procedures Guide and NUREG 5603
           and 5604.  This is a process we've used for doing our
           interfacing system LOCA type of evaluations in our
           PRA.  It's also similar to what we use in our sizemic
           analysis and in our external event tornado analysis.
                       To do that you actually assume a median
           failure capacity which we took to be the number we got
           from the stress analysis.  Then we had to develop a
           logarithmic standard deviation.  To do that we went to
           the new rigs and looked at the various different
           tabulated standard deviations for materials, for
           temperatures and different kinds of configurations.
                       We took one that basically bounded the
           results we've seen in there.  This is a way of
           approximating the probability that the failure might
           occur earlier.  Based on that we were able to
           calculate the probabilities of failures at pressures
           of about 5600.  We were able to come up with
           probabilities of 3 times 10 to the minus 3rd to 7
           times 10 to the minus 3rd depending on the pressure.
                       So that gave us a probability of failure
           at a given pressure.  Then we had to determine since
           we weren't trying to calculate a frequency, we had to
           calculate a frequency which over pressure transients
           would occur at the plant.  To do that we went back
           through our plant history all the way back to 1979 and
           looked at all of our overpressure transients.  
                       We actually calculated frequencies for
           various different categories in terms of the extent to
           which they overpressurized the plant.  Then we were
           able to calculate a frequency of that we would get a
           transient that would actually cause a LOCA.  That
           number was in the order of 4 times 10 to the minus 3rd
           which is about to give you a feeling two orders of
           magnitude higher than our normal medium LOCA number.
                       CHAIRMAN APOSTOLAKIS:  Does the number of
           10 to the minus 5 include as part of the conditions
           the possibility of the six rods not going in?
                       MR. BYRD:  Based on our deterministic
           analysis, we had evaluated that even if the six rods
           did not go in, we would have sufficient shut down
           margins.  So we did not specifically include that.
                       CHAIRMAN APOSTOLAKIS:  All right.
                       MEMBER FORD:  Okay.  If I could jump in
           here.  I'm watching the time here, George, unless you
           want to extend into your other time.
                       CHAIRMAN APOSTOLAKIS:  No.  That's unfair. 
           I shouldn't extend it if I want to ask questions
           myself.
                       MEMBER FORD:  That's right.
                       CHAIRMAN APOSTOLAKIS:  Let's move on.
                       MEMBER FORD:  Thank you very much indeed. 
           I appreciate your comments.  Let's call on Jack Grobe. 
           You're now going to hear two presentations by the
           staff. 
                       CHAIRMAN APOSTOLAKIS:  Should we take a
           break?  We've been going forever.  Do the members want
           to take a short break?
                       MEMBER KRESS:  Yes.  
                       MEMBER SIEBER:  That would be good.
                       CHAIRMAN APOSTOLAKIS:  Okay.  We're
           recessing until 3:50 p.m.  Off the record.
                                   (Whereupon, the foregoing matter went off
                       the record at 3:40 p.m. and went back on
                       the record at 3:50 p.m.)
                       CHAIRMAN APOSTOLAKIS:  On the record. 
           Back in session.
                       MR. GROBE:  My name is Jack Grobe.  As was
           mentioned, there's three presentations this afternoon
           from the staff.  I'm going to present the results of
           a recent inspection that was completed about a week
           ago.  We exited on that inspection last Friday.  Allen
           Hiser will then present the status of Bulletin 2001-
           01.  Ken Karwoski will present the current status of
           the bulletin responses for Bulletin 2002-01.
                       Being from Region III, I'm the Director of
           Reactive Safety.  I don't get to see you folks very
           often.  I appreciate the opportunity to be here. 
           Quite frankly I'm quite embarrassed to be here.  As I
           go through this you'll see why.
                       This wastage occurred over a period of
           years.  Our staff did not identify it.  Certainly the
           Davis-Besse caused it and had many opportunities to
           identify it.  We'll get into that a little bit.
                       I was going to cover three topics.  The
           first and third I think we've addressed pretty
           extensively with the staff's presentation from Davis-
           Besse.  There are just a couple of issues that I'll
           touch on in that area.
                       As was mentioned there were five cracked
           nozzles, three were through wall.  I'm going to get
           into a little bit of the description of the cavity,
           just some of the information that I think was
           important but not presented yet.  You've already
           understood what happened at nozzle 2.
                       This is just a little bit different
           rendering.  This is an artist's rendering of the
           cavity.  They spoke of the nose.  There was
           substantial undercut in the cavity.  
                       In addition to that, there were some UT
           measurements were taken from beneath the cladding. 
           There was an unusual result.  They were taken on one
           inch centers.  There were indications that for an
           extended distance outside of the visible cavity on the
           order of maybe two and sometimes more inches, there
           appeared to be a gap on the other side of the
           cladding.
                       It's not clear what that is.  When the
           licensee cuts out the cavity, they'll be able to
           investigate that more clearly.  It's not clear whether
           that's a reflection.  Whether it's actually a
           separation, it's just not clear.
                       If you look at the physical character of
           the cavity, there's an uneven area quite a bit bigger
           than the cavity that appears to be as a minimum de-
           bonded between the stainless steel and the --
                       VICE CHAIR BONACA:  Could you show us the
           location there?  Is it possible to see the location?
                       MR. GROBE:  I don't have a slide that
           shows the layout of that.  A plan view as it were.  I
           don't have that.  I apologize.
                       MR. HISER:  Yes.  I guess just to try to
           provide a little bit of an answer this is Allen Hiser
           from NRR.  It's around nozzle 11.  It's just not clear
           at this point how far --
                       VICE CHAIR BONACA:  Okay.  Down there on
           the picture.
                       MR. GROBE:  Well, it actually goes
           laterally across the cavity as well as downhill.  It 
           appears to go the whole way to nozzle 11 and maybe
           somewhat around nozzle 11.  Like I said it's at least
           in some cases two or more inches beyond the visible
           aspect of the cavity.
                       VICE CHAIR BONACA:  The reason I'm asking
           the question is that in the repair, they've already
           defined the size of the plug.
                       MR. GROBE:  Right.
                       VICE CHAIR BONACA:  Does that mean the
           plug may have to be larger than what they are planning
           right now?
                       MR. GROBE:  Or there may be repairs
           necessary.  One of the first things that they are
           going to do after they cut out the 13 inch diameter,
           their current plan, is they're going to do
           diapenetrate testing of the surface to try to identify
           whether or not there's additional damage to that
           surface.
                       VICE CHAIR BONACA:  Okay.  I understand.
                       MR. GROBE:  This is a view of the cavity. 
           I think you can see in the lower section of the cavity
           there's a shiny area.  That's where it was machined
           prior to the penetration to pitching as it were.  The
           tube has been removed.  You can see the walls of the
           cavity are fairly smooth.  They slope in.
                       You saw this drawing in the last
           presentation.  There's nothing more to report on this
           except a characterization of the wastage area is a
           little bit incorrect.  It comes out a little bit more
           now that we have impressions in the lower area.  Then
           it tails off to be a little bit thinner.  
                       So it appears that there may be more than
           one mechanism.  It may not just be corrosion.  There
           may be some other things as well.
                       I want to get into missed opportunities. 
           I'm going to cover three areas.  They are the
           containment air coolers, the containment radiation
           monitor filters and also the Boric Acid Corrosion
           Program implementation.
                       Dr. Apostolakis, you asked what are the
           two main causes.  The easy cause is to blame the Boric
           Acid Corrosion Program implementation.  The entire
           operation of these facilities depends on human beings
           whether it's people doing designs, operators of the
           control panels, human beings make mistakes.
                       Implementation of this program was not
           well implemented.  That's by engineers.  But the
           results of the program implementation were known to a
           number of people as well as a number of other
           precursors.
                       I believe that the most important cause
           here is a complete failure of the Corrective Action
           Program.  You'll see that as I go through my
           presentation.
                       Just a little bit of system knowledge that
           you may not have that's important to this.  There's a
           ventilation that the system intakes as suction on this
           volume here.  Discharge is near the top of containment
           above the D-rings.  
                       The area below the insulation is connected
           to the area above the insulation through small gaps
           around the nozzles and things of that nature.  So
           there is a communication of the ventilation system
           between these two areas.  
                       There are a series of almost 20 five by
           seven inch what are called "mouse holes" or "weep
           holes" that are right down here at the edge of the
           vessel.  (Indicating.)  So they are for air coming in
           through that direction.  It's critical to understand
           that the discharge from these areas at the top of
           containment just to see what happened in the
           containment air coolers and radiation monitors.
                       MEMBER SIEBER:  The way out of that bottom
           plate and the mirror insulation is such that since the
           air flow is up, they don't have conoseals, but in
           those joints the leakage is probably not going to go
           down.  Some of it does.
                       MR. GROBE:  The leakage will likely be
           horizontal.
                       MEMBER SIEBER:  That's right.
                       MR. GROBE:  It will be steaming
           horizontally.  It will spray against other surfaced
           and evaporate.  Then the vapor will be taken up
           through the ventilation system.
                       There's been sufficient leakage at times
           during the past ten years that has actually leaked
           down along the penetrations, through the floor of this
           service structure and through the insulation and
           gotten onto the top of the head.
                       MEMBER SIEBER:  My recollection is that
           it's pretty windy in that area.
                       MR. GROBE:  I haven't been there.
                       MEMBER SHACK:  That is a plate though
           there.
                       MR. GROBE:  Yes.
                       MEMBER SHACK:  There was some picture
           there yesterday that gave me the impression of a
           gridwork that you attached the insulation to rather
           than a plate.
                       MR. GROBE:  I think it's a framework.  Is
           it gridwork?
                       MR. MCLAUGHLIN:  It's angle iron.
                       CHAIRMAN APOSTOLAKIS:  Identify yourself
           please.
                       MR. MCLAUGHLIN:  This is Mark McLaughin
           from Davis-Besse.  There is actual angle iron that
           goes across the service structure.  That's what the
           insulation is laid on top of.
                       MEMBER ROSEN:  So you would not expect
           there be a large Delta P that would arise across that
           structure if there was a substantial steam leak below
           at the top of the head.  Is that correct?
                       MR. MCLAUGHLIN:  That would be correct. 
           The other thing that's not shown on there is there's
           insulation.  See on the outside of the flange, that's
           were the reactor vessel hold-down bolts are.  There's
           another layer of insulation that's L-shaped that's
           outside of that which covers up the bolt holes.  So
           that would even further restrict air flow in that area
           underneath insulation.
                       MEMBER ROSEN:  What I was getting as was
           I was postulating that if you had a big leak right at
           that point of steam at the top of the head that
           somehow that insulation in that structure would
           somehow cock and cause some stresses.  I'm trying to
           get the sense of whether you think that's possible. 
           I think you're saying is this the gridwork that came
           with the Delta P that could create some kind of
           cocking of that structure.
                       MR. GROBE:  No.  I think there's a fairly
           tight clearance around each penetration hole.  This is
           a sheet material.  Clearly the floor of the service
           structure is sheet material.  
                       I would expect if you're discharging 2,200
           pounds into this area that you're going to get a very
           substantial differential pressure between these two
           areas.  You would see some deflection in these plates
           which may result in some movement of the penetration
           tubes.  
                       I don't remember who asked the question. 
           But they were very interesting and complex questions. 
           These are also restrained near the top for sizemic
           purposes.  I think you'd really have to get into how
           much would those bowl and what are the clearances
           inside before you could say how many rods would be
           affected.
                       MEMBER ROSEN:  Now you made me worry
           again.  I was almost to the point where I was done
           worrying.  I was the one who postulated this
           originally.  Now I'm back to work.  That's exactly
           what I was worried about.  Because of the yards Delta
           P across some of this, there would be enough
           distortion caused by flexing of something that you
           could have some sort of common cause failure.
                       CHAIRMAN APOSTOLAKIS:  More about six
           rods.
                       MEMBER ROSEN:  Yes.
                       MEMBER SIEBER:  Well, the mirror
           insulation is in blocks.  Right?
                       MR. MCLAUGHLIN:  I'm sorry.  I didn't hear
           the question.
                       MEMBER SIEBER:  The mirror insulation is
           in blocks.  Right?  It's a puzzle that you put
           together.
                       MR. MCLAUGHLIN:  The way the mirror
           insulation was manufactured is if you look at it
           there's a flange right up above the insulation.
                       MEMBER SIEBER:  Right.
                       MR. MCLAUGHLIN:  The mirror insulation is
           really in long strips, I'll say.  Each strip has a
           cut-out area for half of a nozzle along an entire row
           though.  So what they did is they slid it in on its
           side.  Then they laid it on top of the angle.  So the
           insulation is installed with long strips.
                       MEMBER SHACK:  It's like around recessed
           lighting in your basement.
                       MR. MCLAUGHLIN:  Exactly.  If you cut it
           around if you have recessed lighting in your basement
           and you cut half of one of your ceiling tiles, that's
           how it would look.  So that's how it's installed.  I
           would think that if you had enough of a force you
           might move one strip.  However there is sufficient
           room between the insulation and the nozzles that it
           should move up.  I would think it would tend to flip
           out of the way.
                       MEMBER SIEBER:  Now is there or is there
           not a plate involved here someplace?
                       MR. MCLAUGHLIN:  There is no plate.
                       MR. GROBE:  What's the construction of
           this, Mark, the floor of the service structure?
                       MR. MCLAUGHLIN:    That's just showing the
           circle.  There's no plate inside there.  The only
           thing that you have is the angle iron that supports
           the insulation.
                       MEMBER SIEBER:  The insulation is sitting
           in there loose.
                       MR. MCLAUGHLIN:  That's correct.
                       MEMBER SIEBER:  Does that help you?
                       MEMBER ROSEN:  A little bit.  I'd actually
           like a more detailed drawing so I could conclude.
                       MR. GROBE:  Okay.  Thank you.  The tubes
           and fins of the containment air coolers obviously are
           cooler than atmosphere.  Anything that's in the
           atmosphere they'll condense water out of the air as
           they're cooling the air.  Contaminants in the air and
           moisture in the air will plate out on the fins and
           tubes.
                       The containment air coolers need to be
           cleaned occasionally depending on leakage inside
           containment.  They were cleaned in 1992.  Prior to
           some substantial leakage, there was equipment that
           needed corrective maintenance in the 1998 time frame,
           late '98/early '99 which resulted in unidentified
           leakage in containment going from about one-tenth of
           a gallon per minute to about 0.8 gallons per minute.
           During that time frame it was necessary to clean the
           containment air coolers 17 times.
                       A mid-cycle outage was taken in April 1999
           to repair that equipment.  Unidentified leakage only
           went down to about 0.3 gallons per minute after that
           outage.  It remained higher than it had been prior to
           '99.
                       Also during this time frame after the mid-
           cycle outage, the containment air coolers had to be
           cleaned twice in late '99 and seven times throughout
           2000 and 2001.  During that time frame, the engineers
           reported that the character of the material on the
           containment air coolers had changed.
                       Previously it might appear as a spray
           painting, a very white dusty material on the fins and
           the tubes.  During this time frame it took on a
           different color.  It was dark brown.  The Davis-Besse
           staff assumed that the change in color was due to
           corrosion of low alloy steel components in the air
           coolers themselves.
                       MEMBER ROSEN:  Did anybody do any
           measurement of the activity of that deposit?
                       MR. GROBE:  No.  I don't believe so.  When
           you say "activity" you mean specific activity, radio
           activity?
                       MEMBER ROSEN:  Yes.
                       MR. GROBE:  I'm not aware of that.  I'm
           not sure if the Davis-Besse folks here are aware of
           that either.  I did not ask that question.
                       Okay.  The radiation monitor filters. 
           There were routine preventive maintenance to change
           the filters on the airborne radio activity monitors
           inside containment every 31 days.  Prior to the '99
           time frame, that was sufficient to maintain that
           equipment.
                       Beginning in May '99, this is after the
           mid-cycle outage, the frequency of filter changes
           increased.  Between May and August of '99, it went
           from about once a month as a preventive activity to
           every other day.  In July '99, the engineer
           responsible for this equipment requested to have the
           material analyzed on the filter.
                       The filter itself had previously never
           appeared reddish-brown in color.  That was the
           character of the filter in this time frame.  It was
           analyzed in July '99.  The analysis came back that the
           filter was clogged with boric acid and iron oxide that
           was produced in a steam environment, not surface
           corrosion.
                       The facility staff looked for a leak that
           might cause this.  They were unable to find one.  They
           assumed that the leak was from flange leakage.  You
           can't observe the flanges during operation.
                       In August '99, they installed banks of
           HEPA filters with high volume fans to try to reduce
           the frequency change for the radiation monitor
           filters.  That was successful.  It reduced it to about
           every other week.  
                       In July '01, the frequency gradually began
           to increase again.  This is after refuel outage in
           2000.  It continued to increase to every other day. 
           In October '01, the staff reported that the filters
           were abnormally dark brown.
                       MEMBER KRESS:  Are these little filters?
                       MR. GROBE:  I haven't seen them.  What's
           the physical size of these filters?  I don't think we
           have anybody here that's seen them.  They're in-line
           filters in the air sampling system so I don't expect
           them to be very big.
                       MEMBER KRESS:  They're small I would
           guess.
                       MR. GROBE:  Yes.  I've talked about the
           containment air coolers and the rad monitor filters. 
           Nothing associated with the air coolers was reported
           in the Corrective Action System.  
                       The rad monitor filters was captured in
           the Corrective Action System.  But the Corrective
           Action was inadequate to identify the source of the
           material.  In fact some of the actions taken
           potentially insulation of the HEPA filters masked any
           ability to detect whether it was increasing on the
           short term.
                       I want to talk next about the Boric Acid
           Corrosion Control Program.  I think you're aware that
           this is an NRC required program.  Through our Quality
           Assurance Regulations, it's clearly a procedure
           affecting the safety of the plant.  So it's required
           to be implemented.
                       In 1998, we issued a bulleting that
           required licensees to describe their program for
           monitoring boric acid.  It's an extremely sensitive
           but not on-line of course way of detecting leakage. 
           Just a little analogy here.  One drop per second will
           leave about 15 pounds of boric acid in a year.  So
           it's an extremely sensitive indicator of leakage.
                       Ongoing nozzle flange leakage.  The
           engineer responsible for maintaining the quality of
           the flanges was provided a period of time each outage
           to repair nozzle leakage, flange leakage.  During some
           outages there was a little flange leakage.  All of
           them were repaired.  
                       During some outages there was more
           extensive nozzle leakage.  The engineer would
           prioritize those nozzles as far as how badly they were
           leaking and get as many of them repaired as he could
           before it was time to restart the unit.  Nozzles were
           left in service leaking.
                       In 1990, the Davis-Besse staff identified
           that it was necessary to have a modification to the
           skirt beneath the service structure.  The mouse holes
           or the weep holes at the bottom of that skirt were not
           sufficient to do adequate inspections and cleaning of
           the vessel head.  That modification would involve a
           number of large diameter openings around the parameter
           of the skirt, much higher in that skirt structure.
                       That modification was approved for
           implementation in the early '90s.  I think it was '94
           or '95.  It was scheduled in successive outages and
           deferred out of each of the successive outages.  So
           the fact that the licensee was unable to do thorough
           inspections and cleanings of the head was of their own
           doing.
                       Reactor vessel head boric acid deposits
           were not removed at the end of each outage.  It was
           believed throughout that period of time that boric
           acid deposits on the head were not significantly
           hazardous.  Moisture would be driven out of the boric
           acid and the remaining crystals would not be
           significantly corrosive.
                       In the '96 outage, the boric acid that was
           left on the head was characterized as "patches of
           white loose consistency material."  What could be
           gotten was cleaned up with mechanical means vacuuming.
                       In '98, the boric acid was characterized
           as "fist-size clumps and a thin layer of generally
           brown boric acid around the center penetrations." 
           Again, most of the boric acid was removed by just
           vacuuming.
                       In the year 2000, the boric acid was
           characterized as "accumulating over the head."  There
           was a thick layer of boric acid in the center of the
           head.  I'm going to put a slide up now.  This is from
           the 2000 Bulletin and as Bill Bateman mentioned a few
           minutes ago, the staff did not have the opportunity to
           see the condition of this part of the vessel head.
                       The Boric Acid Control Program clearly
           indicates that if there are indications of red or
           brown coloring, that's an indication of corrosion.  It
           should be pursued.  
                       In 2000, this material was approximately
           one to two inches deep.  It had flowed out the weep
           holes.  In fact, the material inside the weep holes
           was high enough to cover the weep holes.  The material
           had to be removed with crowbars.  Eventually a water
           wash was used to dissolve some of the material.  But
           a substantial amount of material was left on the head.
                       This was documented in the Corrective
           Action Program as was the boric acid on the head
           throughout this period of time.  The close-out of the
           Corrective Action Program document, the Condition
           Report, actually they call them "peacocks" at Davis-
           Besse at this time, was listed as "head was cleaned
           and inspected."
                       MEMBER ROSEN:  I'm sure that you're going
           to take a close look at the corrosion effects of all
           this leakage on those bolt circles.
                       MR. GROBE:  Yes.  We issued a confirmatory
           action letter that requires a review of the entire
           primary reactor coolant system.  Not only the head and
           the bolts on top of the head, but throughout the
           entire system including the bottom head and other
           areas.
                       Clearly there were indications of reactor
           head corrosion.  They were not recognized as
           indications of corrosion and not evaluated.
                       The licensee described the preliminary
           root cause, outside diameter, primary water stress
           corrosion, cracking cavity caused by boric acid
           corrosion.  Significant corrosion began at least four
           years ago.  It's pretty difficult to argue with any of
           that.  
                       There's a lot of issues that are clearly
           not addressed yet at least in documents that we've
           seen.  They haven't submitted their corrective action
           document to us yet.
                       There's very interesting chemistry I'm
           learning from this opportunity.  Boric acid crystals
           begin to react with air at a temperature far below the
           temperature of the head and begin to form boric oxide. 
           In addition to that the melting temperature is only
           slightly higher then the temperature at which that
           reaction starts.  
                       So you could have had a very interesting
           combination of boric acid, boric oxide, and liquid
           boric acid flowing down the head.  It's not clear what
           role that chemistry played in that cap over the top of
           the head and corrosion that might have initiated from
           the head down.
                       The role of head temperature throughout
           the operating cycle, outage times, start up times, it
           appears that there were times that boric acid was
           pooled in the bottom of this cavity.  That's certainly
           an opportunity during shut down times when the head is
           at ambient temperatures.  It's not clear what role
           that may have played in the corrosion process.
                       The rate at which the cracks progressed
           and the corrosion progressed is not clear.  I don't
           see a reason to believe that the corrosion progressed
           at a uniform rate through the years.  So those issues
           are not answered.  Clearly the correlation between
           Davis-Besse and the rest of the industry hasn't been
           explained.
                       So there's a lot of outstanding questions
           that I'm hoping are answered to a large extent in the
           licensees root cause assessment.  That completes the
           information.  I apologize for being quick.  
                       MEMBER FORD:  Jack, who has the action to
           provide that data.
                       MR. GROBE:  I'm sorry.
                       MEMBER FORD:  Who has the action to
           provide that data.
                       MR. GROBE:  The licensee is required to
           provide us the root cause.  It's not clear to me that
           those questions can be answered without research.  The
           grinding operation on the nozzle in penetration 3
           started.  The nozzle twisted a little bit and tilted
           a little bit.  
                       At that point the licensee did extensive
           cleaning operations on the top of the head to discover
           the cavity.  All of that material is gone.  Had we
           been able to take samples of that material, it would
           help.  The licensee at that point had no reason
           preserve that material because they didn't understand
           what was going on.  Maybe that's reason enough to
           preserve it.
                       In addition, of course all the cracks were
           machined out.  So we have no information on the
           cracks.  It's not clear to me that we're going to have
           sufficient data from the licensee's analysis to answer
           all these questions.  Likewise it's not clear to me
           that we need all those answers necessarily to approve
           an appropriate repair to the head.  
                       Those answers are important for going
           forward as far as Davis-Besse and the rest of the
           industry.  So there's a lot of things that play here. 
           I anticipate there may be some research, Hackett's
           ears are perking up, that will come out of this.
                       MEMBER FORD:  That comes down to the
           question of the timing of which this research goes to
           get to an identifiable goal.  Bearing in mind that
           it's assumed that there are no other observations of
           such magnitude in the existing fleet.  Until we have
           that data we don't know.  Tomorrow it may start,
           unless we know the chemistry, physical dimension
           interactions.
                       MR. GROBE:  It may be that the right
           answer is to do volumetric examinations of these areas
           every outage.  I don't know what the right answer to
           this is.
                       MEMBER FORD:  Okay.
                       MR. GROBE:  Then you never get into this
           situation.  At least not from these cracks.
                       MEMBER POWERS:  This is the part that I
           don't quite understand, Peter.  In the inspections of
           heads that we're doing elsewhere, are we looking for
           boric acid corrosion of the mild steel pressure
           vessel?
                       MEMBER FORD:  Inside the annulus?
                       MEMBER POWERS:  Yes.
                       MEMBER FORD:  Not as far as I know.  Not
           unless they're doing 100 percent UT.  They're not.
                       MR. STROSNIDER:  This is Jack Strosnider. 
           I just wanted to make two comments on the discussion. 
           First of all with regard to the research, NRR has
           requested the Office of Research to start doing some
           work in this area including looking at what
           information is already available.  Also looking at the
           feasibility of mock-ups.  We've also had some
           additional discussions with the industry I believe
           with regard to doing that kind of work.
                       With regard to what the inspections are
           expected to look at, I think that's a subject of the
           next presentations.  In particular Bulletin 2002-01. 
           When you hear the presentation, you'll see that's
           exactly the issue that we're trying to get to in that
           bulletin.
                       CHAIRMAN APOSTOLAKIS:  If I look at this
           incident from the New Reactor Oversite Process.  Is
           this white?
                       MR. GROBE:  The licensee's analysis puts
           it at the white, yellow order.  We haven't even begun
           to review that.  That's the next inspection that will
           begin in the next week or so, both to look at the
           regulatory implications of the findings of the AIT as
           well as the risk analysis.
                       CHAIRMAN APOSTOLAKIS:  But are you using
           the action matrix right now?  No.
                       MR. GROBE:  The AIT, the Augmented
           Inspection is an event response.  Now we'll go into
           the follow up inspections and apply the Significance
           Determination Process.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. GROBE:  It's an interesting
           opportunity.
                       CHAIRMAN APOSTOLAKIS:  Yes.  We've been
           hearing a lot about the utility personnel there and so
           on.  How about the resident inspectors?
                       MR. GROBE:  That's an excellent question. 
           As part of the follow up activities, I'm required to
           recommend to appropriate offices actions to take.
                       CHAIRMAN APOSTOLAKIS:  Were they aware of
           any of this?
                       MR. GROBE:  No.  The residents were not
           aware.  Our inspection program does not require
           inspections in these areas.  The in-service inspection
           program primarily focuses on piping and welds in the
           BWRs, BWR internals, as well as steam generators. 
           Reactor vessel heads was not included as part of our
           inspection program.
                       CHAIRMAN APOSTOLAKIS:  They were aware of
           the fact that the 1990 modifications to improve the
           reactor vessel heads had not been installed.
                       MR. GROBE:  No.
                       CHAIRMAN APOSTOLAKIS:  They were not aware
           of that.
                       MR. GROBE:  No.  I don't know how many
           modifications every year that Davis-Besse has.  But I
           would expect that it's certainly in the dozens and
           maybe many more than that.  Corrective maintenance
           activities would be in the thousands.  So the chance
           that a resident inspector may choose to pick one of
           these activities to look at is fairly small.
                       CHAIRMAN APOSTOLAKIS:  Now the Corrective
           Action Program is one of the cross-cutting issues.  Is
           it not?
                       MR. GROBE:  That's absolutely true.
                       CHAIRMAN APOSTOLAKIS:  So what?  We're not
           doing anything about it.  It's an old issue between us
           and the staff.  The staff claims that even if you have
           a defective Correction Action Program, then you will
           see the consequences of that.  That's what happened
           here.  
                       MR. GROBE:  I think that's what we have
           here.
                       MEMBER ROSEN:  I think that's what you
           said, Jack, is that you're doing a Significance
           Determination Process.
                       MR. GROBE:  Right.
                       MEMBER ROSEN:  What comes out of that is
           what's off the action matrix.
                       MR. GROBE:  Exactly.  Also to answer your
           question, we're going to have to look at our
           inspection program and how we implement it to make
           sure that we're addressing appropriate inspection
           activities.
                       CHAIRMAN APOSTOLAKIS:  The question is
           whether you should stick to this point of view that if
           there are problems with the Corrective Action Program
           let them be until something happens or you should try
           to devise some ways of evaluating the quality of the
           Corrective Action Program before things happen.
                       MEMBER ROSEN:  I don't think your premise
           is correct.  I don't think that they do.  I'm not
           talking about Davis-Besse, any place without a serious
           event.  If the inspection, resident inspectors and the
           NRC find that the Corrective Action System is somehow
           not working as it should, then that becomes an issue.
                       CHAIRMAN APOSTOLAKIS:  They're not
           looking, Steve.  They're not looking.
                       MEMBER ROSEN:  I think they are.
                       CHAIRMAN APOSTOLAKIS:  No.  It becomes a
           major contention.
                       MEMBER SIEBER:  There's a module for that.
                       CHAIRMAN APOSTOLAKIS:  There's a what?
                       MEMBER LEITCH:  It's 4500.  Isn't it?
                       MEMBER ROSEN:  I think it's a major focus
           of the inspection program now.
                       MR. GROBE:  There's three areas where we
           look at the Corrective Action System.  There's an
           inspection that's now conducted every other year which
           is a team inspection.  It's a large inspection.  It
           covers several weeks.
                       CHAIRMAN APOSTOLAKIS:  Of what?
                       MR. GROBE:  It's of the Corrective Action
           System itself.  A wide variety of condition reports
           are chosen on a risk informed basis to examine the
           effectiveness of the Corrective Action System. 
           There's also a series of interviews of staff across
           the facility to get a sense for their safety focus as
           it were.
                       In addition to that a certain percentage,
           I believe it's 10 percent of the hours of every
           inspection whether it's a radiation safety inspection,
           security and safeguards, maintenance, surveillance
           testing, or whatever it may be, is intended to spend
           in the Corrective Action area looking at Corrective
           Actions for deficiencies identified in that specific
           area.  In addition to that now we're implementing
           sampling of about ten more minor events.  
                       Events that wouldn't get to the level of
           a special inspection where you send a team out to the
           region.  More minor daily events that by following our
           nose, catch our fancy.  We spend a little bit drilling
           more on that specific event into how it happened.  So
           there are three ways we look at the Corrective Action
           Program.
                       It's very difficult to apply the
           Significance Determination Process to Corrective
           Action violations.  The Corrective Action Program if
           it's a violation of not fixing things correctly, it
           will most likely found the issue before it became
           significant from a risk perspective.  But didn't fix
           it properly.  So by definition that would be a low-
           risk violation.  
                       There's still quite a bit of dialogue
           among myself and my peers about whether or not it's
           appropriate to apply a risk-based, risk-driven
           Significance Determination Process to a Corrective
           Action Programmatic deficiency.  Or whether there
           should be some programmatic Significance Determination
           Process developed that's more deterministic.
                       MEMBER ROSEN:  So given all that, what was
           the staff's conclusion about the Corrective Action
           Program at Davis-Besse prior to this event?
                       MR. GROBE:  The staff's view is that the
           Corrective Action Program is well implemented at
           Davis-Besse.  That's what's very troubling.  It's
           something that I'm going to be getting to the bottom
           of over the next several weeks, maybe months.
                       The extent of the behavior that created
           this problem is multiple people weren't following the
           Corrective Action Program.  For example, engineers
           were not speaking laterally.  The rad monitor engineer
           wasn't talking to the containment air cooler engineer,
           who wasn't talking to the head engineer.  
                       There were several decisions that were
           made which included supervision and management that
           don't appear to have been good decisions.  Some
           examples are the delay of the modification,
           installation of HEPA filters in containment, the
           decision to not continue to pursue the source of iron
           oxide in the '99 time frame, quite frankly the
           decision to restart after the 2000 refueling outage.
                       So there's just a plethora of issues that
           we need to continue to follow up on.  Why those
           decision making processes, communication processes,
           supervision deficiencies didn't manifest themselves in
           other areas, that's another question we have to ask
           ourselves and try to find the answer to.  But they
           didn't.  I'm fairly comfortable with our inspection
           program.
                       CHAIRMAN APOSTOLAKIS:  Okay.  They didn't. 
           But we, the NRC, have no way of finding out that they
           did not because we were not looking for that.  Is that
           correct?  We were not looking for the existence of
           communication channels between this group of engineers
           and that group of engineers because that's a safety
           issue.  We're not supposed to look at that.  Is that
           correct?
                       MR. GROBE:  Whenever you identify, it's
           what I refer to hardware and software.  Most problems
           have fixes in two sides.  They have a hardware fix. 
           For example in this case potentially drilling out a
           hole in the head, installing a plug, welding it in. 
           They also have a software fix.  It's a human
           performance problem or a communications problem or a
           procedural deficiency.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MR. GROBE:  We look at all of those issues
           when we look at fixing a deficiency in the facility. 
           If it's our violation, we follow up on it.  The 10
           percent of each inspection procedure is spent doing
           that.  We pick about a half a dozen less significant
           events per year.  We drill down in each one of those
           to make sure that the root cause is identified and
           fixed.  Every two years we spend a significant period
           of time.
                       CHAIRMAN APOSTOLAKIS:  I think I'm getting
           a different picture from you of what our inspections
           do.  Then you guys would develop the ROP.
                       MR. GROBE:  Well, I can tell you that you
           get a picture of what we're doing in Region III.  I
           believe it's the same as the other regions.
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MR. GROBE:  I apologize.
                       MEMBER POWERS:  In fairness, you explained
           this when we visited you.  All of the regions have
           explained this.  They do this baring down on the less
           significant issues and things like that.  It's one of
           the values of our visit to the regions.
                       CHAIRMAN APOSTOLAKIS:  I know.  Sure. 
           Another thing that you said that I find very
           interesting is you said that you are not sure of the
           Significance Determination Process as it is structured
           now.  That makes sense for things like the Corrective
           Action Program.  Put another way, should we evaluate
           everything on the basis of CDF and LERF?  That's
           really what you are saying.
                       MR. GROBE:  Exactly.
                       CHAIRMAN APOSTOLAKIS:  I don't think we
           should.
                       MR. GROBE:  I agree.
                       CHAIRMAN APOSTOLAKIS:  You agree with me. 
           Okay.
                       MR. GROBE:  When you look at the Design
           Control Program for example if our inspectors go in
           and we spend a week and we find 20 calculational areas
           which are not minor oversights like a transposition of
           numbers or something like that --
                       MEMBER ROSEN:  This is at Davis-Besse.
                       MR. GROBE:  No.  This isn't Davis-Besse. 
           This is philosophical.
                       MEMBER ROSEN:  I apologize.  I won't
           digress.
                       CHAIRMAN APOSTOLAKIS:  That's fine. 
           Philosophy is good.  Keep going.
                       MR. GROBE:  If you find 20 calculational
           areas where the calculational area had a precursor of
           not understanding the engineering a mis-application or
           a mis-assumption or something of that nature but each
           one of them came out as to not render the equipment
           inoperable, currently the Significance Determination
           Process would classify those as either minor or green. 
           They would be non-cited violations.
                       When in fact that's a clear precursor that
           there's a problem with the competency of the engineers
           as well as the competency of the engineering
           supervisors.  So there are areas and these are the
           things that we're still working out in implementation
           of the ROP.
                       I think the Corrective Action Program is
           likewise.  It needs something less than less rigorous
           analytically than a risk analysis to evaluate the
           significance.  I certainly appreciate this podium to
           express these views.  I don't get it very often.
                       CHAIRMAN APOSTOLAKIS:  It can be a risk-
           like analysis but not using core damage frequency is
           the end stake.  Something before that.
                       MEMBER ROSEN:  It sounds to me like what
           you're suggesting is the Reactor Oversite Process
           ought to be risk-informed not risk-based.
                       MR. GROBE:  That's exactly right.  In some
           areas it can be risk-based, but overall it should be
           risk-informed.
                       CHAIRMAN APOSTOLAKIS:  Nothing we do is
           risk-based.
                       MEMBER ROSEN:  Well, if you're writing
           something that's agreeing because it's number that
           you've calculated is way down there, that's risk-based
           not risk-informed.
                       CHAIRMAN APOSTOLAKIS:  No, but that's a
           rule.
                       MEMBER ROSEN:  What Jack is arguing for is
           a true risk-informed regiment which is in my view the
           right answer.  It's always I think the wrong answer to
           use a risk-based regiment.
                       CHAIRMAN APOSTOLAKIS:  No, but the point
           is should you be using core damage frequency to make
           all these determinations.  I think that's a
           fundamental problem.
                       VICE CHAIR BONACA:  For example one
           concern that you have raised and I brought out at
           least personally was the fact that the Significant
           Determination Process doesn't take into consideration
           repeat events.
                       CHAIRMAN APOSTOLAKIS:  That's true.
                       VICE CHAIR BONACA:  And yet it is
           something that traditionally we have looked very hard
           at the plans as indicators of problems with the
           Corrective Action Program.  You fix something, you say
           you fixed it and it's not fixed again and again. 
           That's a major indicator.  Yet the Significance
           Determination Program doesn't deal with that.
                       CHAIRMAN APOSTOLAKIS:   Also the example
           with the calculations is a very good point.
                       VICE CHAIR BONACA:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Because you have 10
           wrong calculations spread over time.  Each one would
           probably become a "green."  But if you find a common
           cause behind them then I don't know what you are going
           to get.
                       MR. GROBE:  I think we still have growth
           in the area of how to apply our risk tools.  A good
           example of that in the maintenance area was at Quad
           City several years ago.  They were incorrectly
           maintaining their motor operated valves.  They were
           repetitively failing.  But at each failure they didn't
           have redundant equipment in a failed state or out of
           service.  
                       Consequently there was essentially no risk
           significance to each individual failure but there were
           17 valves that failed over a period of two years.  It
           was because the maintenance activity was inadequate
           and the Corrective Action Program wasn't identifying
           it.  So that's a situation I think that goes to right
           to both these issues.  
                       CHAIRMAN APOSTOLAKIS:  Exactly.
                       MR. GROBE:  We need to continue to mature
           in how we are using our risk tools.
                       CHAIRMAN APOSTOLAKIS:  Very good.  It has
           been really very useful.
                       MR. JOHNSON:  George, this is my chance. 
           Over here at the table.  George.
                       CHAIRMAN APOSTOLAKIS:  Oh, you again.  I
           thought you weren't in the room, Mike.
                       MR. JOHNSON:  I was hoping not to say
           anything here.  But I couldn't not say anything.  I do
           want to point out that we have had continuing dialogue
           with ACRS on cross-cutting issues.  I couldn't sit
           there and remind us that the goal of the ROP was never
           to make sure that we didn't have issues.  There is
           never a guarantee in the ROP that would say that we
           would not have issues and then you would find and look
           back and say hey you know what.  There were some
           cross-cutting issues that if the licensee had taken
           care of we wouldn't have gotten here.  
                       In fact what the philosophy of the ROP is
           is that if in fact there are problems in cross-cutting
           areas that those will be reflected in performance
           issues like perhaps this performance issue that we're
           talking about in time for us to take action before the
           performance is unacceptable.  So that's the premise of
           the ROA.  I wanted to be very clear about that.
                       The other thing is that I wanted to be
           sure that we remember that the commission has given us
           some specific direction with respect to treatment of
           cross-cutting issues.  The direction from the
           commission was before the agency takes action on a
           cross-cutting issue we need to make sure that it is an
           issue that has reflected itself in terms of
           performance that it has crossed some threshold.
                       So the commission has been very clear with
           us with respect to our previous process of looking at
           issues that have continued to aggregate if you will. 
           Aggregation was a feature of the previous process and
           has steered us away from aggregation towards where we
           are in the ROP.  
                       I'm sorry, George.  I just couldn't sit
           there and not say that.
                       CHAIRMAN APOSTOLAKIS:  Are you still the
           head of that?
                       MR. JOHNSON:  No, I am not.
                       MEMBER FORD:  George, I have one question
           from the public.  Then I'd like to get back on to the
           agenda.
                       CHAIRMAN APOSTOLAKIS:  Sure.  We can never
           go back.
                       MEMBER FORD:  That's true.
                       MR. GUNTER:  Paul Gunter, Nuclear
           Information Resource Service.  Just a quick question. 
           Jack, could you inform me if the 1990 modification
           that Davis-Besse didn't undertake was that part of
           compliance with generic letter 8805?  I mean 8805 had
           a specific piece about increasing accessibility for
           inspection.  I'm wondering in what context did the
           1990 modification come about.  Did Davis-Besse just
           volunteer it or was this part of 8805?
                       MR. GROBE:  That's Paul Gunter by the way
           for the records.  Paul, 8805 didn't require any sort
           of modifications.  It simply required the licensee to
           have a program in place that addressed certain
           attributes of boric acid corrosion management and to
           describe that program to us.  The modification that
           was identified in 1990 was proactive in a sense that
           the Davis-Besse staff identified for themselves that
           this would be a benefit to them.  There wasn't any
           requirement to implement a modification of any sort.
                       As a matter of fact of the B&W pressurized
           water reactors most of them have implemented such a
           modification.  Some have not.  So it's simply a matter
           of what a licensee views is necessary for their own
           organization.
                       The disturbing issue at Davis-Besse is
           that over the years their staff had identified that
           one of their inabilities to effectively inspect and
           clean the head what influenced that inability was the
           fact that they had limited access through these mouse
           holes or weep holes.  That reemphasized the need for
           implementation of the modification.  I think I've
           answered your question.
                       MEMBER FORD:  I'd like to move on if I
           may.  Ken, do you want to swap your presentations? 
           You deal with 2002-01 and finish off with 2001-01. 
           It's a suggestion.
                       MR. KARWOSKI:  That's fine.  For
           continuity purposes, I'll be discussing Bulletin 2002-
           01 which was issued in response to the findings of
           Davis-Besse.  Just to recap, the NRC is taking a
           number of generic actions as a result of the findings
           at Davis-Besse.  I'll be discussing some of those. 
           I'll also be discussing some of the results that we
           have to date as a result of reviewing responses to the
           bulletin and talking to licensees.
                       Just to go through it quickly because I
           know we are behind schedule.  The first slide just
           recaps what we knew about the findings at Davis-Besse
           at the time.  We knew that they had boric acid on the
           top of their head and we knew that they had leaking
           nozzles.  
                       With that information and the knowledge
           that there was a cavity, we contacted the industry and
           asked them three questions.  Those three questions are
           listed on this slide.  Basically we asked them for
           plants that had just recently completed their
           inspections in response to Bulletin 01-01 which had to
           do with circumferential cracking of the nozzles.  Were
           the techniques used during that inspection capable of
           detecting the type of wastage that was observed at
           Davis-Besse?  
                       The other thing we asked them is to
           provide a justification for continued operation for
           the plants that had not performed those inspections at
           that point.  We also asked them for a risk assessment.
                       The industry conducted a survey and Larry
           Matthews of MRP described that survey.  They
           categorized their results.  While the industry was
           performing that survey and about the time we received
           those results, the NRC issued Bulletin 2002-01 on
           March 18.  We had several reporting requirements in
           that bulletin and I've listed those on this slide.
                       Within 15 days of the date of the
           bulletin, we asked licensees to provide a summary of
           the reactor vessel head inspection and maintenance
           programs.  We asked them to evaluate those programs
           for the ability to detect degradation such as what was
           observed at Davis-Besse.  We asked them to identify
           conditions that may lead to degradation such that was
           observed at Davis-Besse.  We also asked for their
           plans for their next inspection outage and then the
           justification for continued operation.
                       We also asked that within 60 days that
           they provide a more comprehensive evaluation of their
           Boric Acid Corrosion Prevention Program.  We also
           asked the results of their next inspection to be
           provided within 30 days of the completion of that
           outage.
                       With respect with where we stand today,
           the staff as a result of the MRP survey, we took the
           plants that were listed in the other category that
           were on the slides of Larry Matthews that presented
           including Beaver Valley, Calaverdi, Wolf Creek, Watts
           Park.  We've contacted all those licensees because of
           possible concerns because the other category is a
           category where the results of the inspection were
           questionable and we felt we needed to understand a
           little better why they were categorized that.  Some of
           those plants have subsequently performed inspections. 
           We are still pursuing additional information from one
           of those plants.
                       We are also contacting licensees that are
           currently in outages to obtain the results of their
           results of their inspections and also to discuss their
           plans for the inspection recognizing that the bulletin
           went on the 18th and the responses weren't due back
           until the first week of April.  We wanted to make sure
           that we understood the licensees inspection scopes and
           we wanted to make sure that the results of inspection
           whether or not we wanted to evaluate those results to
           determine whether or not we needed to take additional
           regulatory actions.  Those phone calls are still on-
           going.
                       As a result of those phone calls, we have
           not identified any other plant with similar
           conditions.  In most cases, I have characterized the
           results as there is small debris on the top of the
           vessel head.  That debris could be a result of
           maintenance activities and be metal shavings or pieces 
           of metal or small pieces of boric acid crystals as a
           result of previous leaks but nothing to the extent as
           what was observed at Davis-Besse.
                       We are reviewing the responses to the
           bulletin.  We have completed initial categorization. 
           We are proceeding on those reviews now.  That's
           basically where we stand with respect to the
           activities of this bulletin.
                       MEMBER FORD:  Thank you, Ken.  Questions?
                       MR. HISER:  I'd like to describe that the
           status of review of Bulletin 2001-01 looking back that
           was on circumferential cracking of vessel head
           penetration nozzles.
                       VICE CHAIR BONACA:  Could I ask a
           question?  I'm puzzled.  It will be a quick question. 
           When they looked at the Davis-Besse, they looked from
           the bottom.  Then they did the inspection and
           identified cracking I guess through UT inspection in
           the sense.  So that means they never looked from the
           top because of the super structure (PH) I guess it
           was.  Right?
                       MR. HISER:  As a part of the 2001-01
           inspections for the prior bulletin, they looked using
           ultrasonics to determine whether or not they had any 
           circumferential cracks.  As a part of their overall
           activities, they intended to do a visual inspection of
           the head as well.  The sequence of events was such
           that they completed their ultrasonic inspections and
           then begun repairs before they did their visual
           inspection.
                       VICE CHAIR BONACA:  I just wanted to make
           sure for the other plants in genera that there is 
           always a plan to inspect visually from the top.
                       MR. HISER:  For many plants that's true. 
           For some plants the insulation configuration is such
           that the insulation is directly on the head.  Then
           there are cases that it really isn't feasible to do a
           visual exam of the head's surface.
                       VICE CHAIR BONACA:  So would you find the
           same problem if you -- Do you see where I'm going?
                       MR. KARWOSKI:  There are a number of
           plants whose insulation is either glued or cannot be
           removed for the head easily.  One of the recent plants
           that shut like that is Genet.  They had a well
           documented history of prior leaks.  They also did a
           visible inspection of the surface of the insulation.
                       In areas where it was stained they cut up
           pieces and looked down to the bare metal.  They also
           did additional examinations in areas where there was
           a known prior history of leaks.  In the case of Genet
           specifically they did UT thickness measurements from
           the bottom of the head near the center nozzle.  They
           also did some UT in the periphery around the shroud
           ring as result of a prior leak in that area.  
                       So there are other actions that plants who
           have nonremovable insulation can take.  Certainly if
           they have never had a leak there is a possibility that
           leakage would come down from the top.
                       VICE CHAIR BONACA:  But you would expect
           provisions however that they would take so if there is
           a faradic erosion over time taking place in the
           ferritic steel would be identified.
                       MR. KARWOSKI:  Yes.  I was just addressing
           the corrosion from the top of the head.
                       VICE CHAIR BONACA:  I understand.  I have
           just been wondering though since in some cases you
           cannot have a visual from the top, how do you assure
           that if you have an event of this type it's going to
           be identified in all cases?  That still puzzles me.
                       MR. BATEMAN:  Just a point of
           clarification.  Bill Bateman from the staff.  When Ken 
           says leaks, he's referring to flakes from above from
           the phalanges at the conoseals that would run down and
           land on the header and the insulation.
                       MR. HISER:  One of the things that the
           industry talked about on Tuesday was interpretation of
           the ultrasonic data above the weld and the inference
           fit zone and the ability of that to characterize
           whether they have metal behind the nozzle or not. 
           That's one approach that the industry is taking.
                       VICE CHAIR BONACA:  But they're addressing
           this issue.
                       MR. HISER:  Right.  Here's what I would 
           like to do today is to just provide a brief summary of
           the inspection results and how that fits within the
           context of the susceptibility ranking approach and
           then provide some observations and forward looking on
           where we are headed with this.  
                       The table illustrated here provides the
           inspection results for all the high susceptibility
           plants along with two moderate susceptibility plants,
           Crystal River 3 and Millstone 2 that did identify
           cracked nozzles.  In general, plants have tried to use
           a qualified visual exam if they are able to do that. 
           Again the qualified visual means that you are able to
           inspect the inner section of the nozzle with the head
           so that you can split to that bare metal to see if
           there are any boric acid deposits.  Also you have done
           a plant specific analysis to demonstrate that any
           leaks in the annulus between the nozzle and the base
           metal would provide a deposit on the head that would
           be available for detection.  In some cases in
           Millstone 2 and Davis-Besse, they also did a 100
           percent ultrasonic inspection because they were not
           capable of doing a visual exam with the as-found
           condition.
                       Now for the plants that have identified
           leaking or cracked nozzles, any positive findings from
           the qualified visual exam were followed up with
           ultrasonic techiques in order to characterize the type
           of degradation or is it actual flaws or a
           circumferential flaw whether it was through wall or
           not.  A number of nozzles have been repaired.  I guess
           two things to point out is from the susceptibility
           rankings, we do have two plants in the moderate
           susceptibility bin that have found cracked or leaking
           nozzles.  One of those Crystal River 3 is actually the
           first plant in the moderate susceptibility range. 
           They did identify a circumferential crack in the one
           nozzle.  Millstone 2 identified three nozzles with
           crack from the ultrasonic test.  None of those were
           thrown wall and none of them appeared to provide any
           leakage.
                       Some discussion of Oconee 3.  That was the
           first plant that identified circumferential cracking. 
           That was identified in February of last year during a
           midcycle maintenance outage.  A refueling outage in
           past November did identify additional degradation with
           the seven nozzles having cracks or leakage.  One of
           those nozzles did have a circumferential crack.
                       So I guess some of the points to be made
           here is at this point all of the high susceptibility
           plants with the inspection of Davis-Besse have been
           inspected.  We have continued to find cracked nozzles
           and also some circumferential cracking.  Looking at
           this within the context of the susceptibility ranking,
           plants are within zero to five EFPY of Oconee 3 were
           classified as high susceptibility.  As you can see
           many of these have identified cracked nozzles.  In two
           cases they have not from recent inspections this is
           the Crystal River --
                       MEMBER SHACK:  Those are really leaking
           nozzles.  Right?  They did visuals.
                       VICE CHAIR BONACA:  That's right.
                       MR. HISER:  In some cases.  In at least
           one plant all of the nozzles that were found to be
           cracked did not have definitive indications of leakage
           on the head, did not have definitive conclusions of
           through-wall.
                       MEMBER SHACK:  No, the two that we have
           down there in the high zone that say no cracking. 
           Those had some visuals on them.
                       MR. HISER:  That's correct.  Yes.
                       MEMBER SHACK:  So the no leaks is the true
           --
                       MR. HISER:  No leaks.  Yes.  That is
           correct.  The highest ranked plant that has leakage is
           Crystal River at this point.  Again Millstone 2
           identified cracking because they did an ultrasonic
           exam.  Probably if they had done a visual exam they
           probably would have been a blue square.  We would have
           said they have no cracking.  As you can see there
           clearly are a lot of plants that still will be doing
           inspections either later this spring, next fall or
           even next spring because of the cycle of outages.
                       MEMBER FORD:  Allen, did I hear that
           correctly that particular plant a visual inspection is
           not sufficient to determine that you have no cracking? 
           Is that what you said?
                       MR. HISER:  In this case the cracking that
           was identified as the maximum extent was about 40
           percent through-wall.
                       MEMBER FORD:  Oh.  So there it wasn't a
           through-wall crack.
                       MR. HISER:  Right.  It was not a through-
           wall crack.
                       VICE CHAIR BONACA:  Some of the confusion
           is that you are using the expression "cracking."  You
           should use the expression "leaking" because that
           really is what you are monitoring with the exception
           of that plant there, Millstone 2.  I would suspect
           that all of them are somewhat cracked.
                       MR. HISER:  They may be.  That's correct. 
           We'll improve the indications on this chart.
                       MEMBER SHACK:  No.  Matthews' chart says
           it has four plants with volumetric inspection that had
           no cracking.
                       VICE CHAIR BONACA:  I thought there were
           two.  There were two on that table.  Only two plants
           with UT.  Millstone 2 and Davis-Besse.
                       MEMBER SIEBER:  But there were others who
           found cracks.
                       MR. HISER:  Yes.  The plants that are
           shown in the table are predominantly those that are
           less than five EFPY.  Some of these other plants
           probably also did ultrasonic inspections.  They should
           be indicated a little bit differently.  That's
           correct.  
                       I guess the one point we wanted to make is
           that although all of the leakage is down in the low
           EFPY area we have seen cracking here.  Ultimately it
           is going to get to the point that cracking extends
           throughout the histogram.  At this point in time the
           history does justify I think the susceptibility
           ranking model that we have.
                       MEMBER POWERS:  I guess that's not
           apparent to me.  You have appointed 15 EFPY.  It seems
           to say that this ranking is not correct.
                       MR. HISER:  From the standpoint of
           circumferential cracking in nozzles, the plant had no
           circumferential cracks.  It had three nozzles with
           about 40 percent through-wall.
                       VICE CHAIR BONACA:  And no leakage.
                       MEMBER POWERS:  If I wait until 12 EFPY it
           has two wall cracks.
                       MEMBER FORD:  I think an explanation,
           Dana, is that this model is based purely on time and
           temperature.  It misses out the fact there is
           differences in stress and especially differences in
           heat.  Therefore you are going to expect a scatter
           around those values.  So it doesn't surprise me at all
           that you have at least one plant who when you look at
           the distribution of those plants that have seen
           cracking --
                       VICE CHAIR BONACA:  If that plant had
           performed a visual --
                       MEMBER POWERS:  Well, I think what this is
           telling you is that this ranking is just not adequate.
                       MEMBER FORD:  You're always going to
           scatter around those points.  You are absolutely
           correct.
                       VICE CHAIR BONACA:  If that plant had
           performed visuals like the other reds it would not
           have been red but it would have been green.
                       MEMBER POWERS:  That also says that visual
           inspection is not adequate.
                       MR. STROSNIDER:  This is Jack Strosnider. 
           I'd just like to make a comment on this discussion. 
           As was pointed out with these susceptibility models
           there are parameters that aren't taken into account
           here such as residual stresses, materials, et cetera. 
           We wouldn't expect this to be exact.  
                       I think the one thing I want to caution is
           when we say it's not exact.  When we ask the question
           is it adequate from a regulatory perspective, I want
           to point out that even the largest circumferential
           crack found in these plants had substantial margin to
           failure.  
                       Is it adequate in terms of protecting
           against the circumferential crack that's going to lead
           to failure?  That's what we're concluding that yes the
           inspections are happening soon enough to give us that
           information.  
                       It's not going to predict this plant is
           going to be at exactly this time or this plant will be
           exactly before that plant.  But when you look at the
           results of the inspections, we believe it's adequate
           to provide confidence that the cracks will be caught
           in time to preclude any failures.  
                       I guess the one other thing that I'd point
           out is then you ask the next question.  What about the
           Davis-Besse experience and the fact that a leak lead
           to the sort of thing that we saw at Davis-Besse? 
           That's the point of the bulletin that Ken talked
           about.  
                       For people who have already done these
           inspections, one of the things that they have to
           respond to is tell us why that inspection was good
           enough to tell you that you didn't have any
           degradation occurring in the head.  So I think you
           need to look at both the bulletins and what they're
           accomplishing there.
                       MEMBER KRESS:  Yes.  But there's going to
           be an unfinished part of that.  They're going to come
           back and say we're sorry we couldn't have found the
           Davis-Besse thing without inspection.  Then you'll
           have to come back with now what.
                       MR. STROSNIDER:  Yes.  If we see a
           responsible Bulletin 02-01 which says that we can't
           tell you a licensee that can't provide the argument as
           to why they don't have degradation occurring in the
           head, we need to have more discussions with them.
                       MEMBER KRESS:  They'll have some
           arguments.  But you'll have to use judgement as to
           whether they're good enough.  I think what you'll find
           out is they really can't tell you.  Then you have the
           decision to make.  What are you going to do?  I think
           you ought to be thinking about that.
                       MR. STROSNIDER:  We are.
                       MEMBER KRESS:  Okay.
                       MR. STROSNIDER:  If we get a response to
           Bulletin 02-01 which doesn't provide confidence that
           the type of degradation saw at Davis-Besse is not
           occurring, then we will have to follow up on that. 
           That's the point of our argument.
                       MEMBER POWERS:  Jack, let's come back on
           this regulatory adequacy.  You have this, I think it's
           Crystal River up there at 15.  Is that right?
                       MR. HISER:  That's Millstone 2.
                       MEMBER POWERS:  That's Millstone 2.  I'm
           sorry.  You say it's okay because this things going
           through a wall.  Isn't that an accident?  If I look at
           the next plant down, couldn't it be that it has
           through-wall cracks?
                       MR. STROSNIDER:  Which one?
                       MEMBER POWERS:  One of them.
                       MR. BATEMAN:  Right now we're managing
           this issue through leakage.  If we look at that plant,
           do a visual inspection and we see popcorn there then
           we know there's leakage.  The licensee fixes it.  They
           don't restart until they've fixed all their leaks. 
           Right now the way we're managing this issue is through
           leakage.
                       MEMBER POWERS:  Right now this curve is
           used to tell you the urgency with which they're doing
           an inspection.
                       MR. HISER:  Actually I should have set the
           stage on this.  The bulletin had two main purposes. 
           First of all is to identify any plants that had a
           safety issue such as the cracks that were identified
           at Oconee.  So far we've found no plants that have a
           safety issue with large circumferential cracks.
                       The other is to provide us with data in a
           graded approach that would help us to determine what
           the long term management, i.e. inspection methods need
           to be to assure that we don't get any large
           circumferential cracks.  Within that context, the
           susceptibility ranking is supported by the data that
           we have at hand.
                       MEMBER KRESS:  I don't think you should
           overlook the blue squares, Dana.  They tell you a lot
           of information.
                       MEMBER POWERS:  You have blue squares down
           here at three.
                       MEMBER KRESS:  I know. You would expect --
                       MEMBER POWERS:  They don't tell me
           anything except that the curve is not adequate.
                       MEMBER KRESS:  You expect some overlap at
           that level down there.
                       MEMBER POWERS:  It looks to me like the
           density is about the same.  I would argue that the
           blue squares are about uniform across that grid.
                       MEMBER FORD:  You don't think that the
           ratio of cracking to no cracking changes as you go
           from the left hand side to the right hand side.
                       MEMBER POWERS:  It doesn't look to me like
           it does.
                       MEMBER FORD:  There's no red squares up in
           the right side.
                       MEMBER POWERS:  But you haven't looked.
                       MEMBER KRESS:  I'm presuming that you've
           looked at the blue squares.
                       MEMBER POWERS:  First of all I have two
           blue squares in the first block.  I have four in the
           next block.  I have three in the next block.  I have
           three in the block.  Two in the next block.
                       MEMBER KRESS:  That's just an indication
           of which ones you looked at.
                       VICE CHAIR BONACA:  But let's change the
           name to leaking because really the cracking is just
           misleading.  Those two boxes on the left between zero
           and five may be --
                       MEMBER POWERS:  That's what I disagree
           with, Mario.
                       VICE CHAIR BONACA:  May be 90 percent
           through right now.  They show however no cracking.  No
           that's not true.  No leaking.  They haven't seen any
           leakage.  But they may be so close to all extent
           they're in the same bunch.
                       MEMBER POWERS:  I think I agree with you.
                       VICE CHAIR BONACA:  What will you shift
           the criteria?  Do you call the other one up there no
           cracking?  That means no leaking actually.  You have
           seen no leaking in less than two.  But you know that
           there is cracking.
                       I can make the same statement about any of
           those.  I probably could go at 20 years and find some
           at 20 years that have cracking but no leaking.
                       MEMBER KRESS:  But I would be awfully
           surprised to see that many blue squares if indeed
           you're supposition is right.  Some of them are that
           close to being --
                       VICE CHAIR BONACA:  I was talking about
           the one between zero and five, those two.
                       MEMBER KRESS:  Well, those two might very
           well be.
                       VICE CHAIR BONACA:  They may be very
           close.
                       MEMBER KRESS:  But that just validates the
           curve if that's the case.
                       MEMBER POWERS:  It may also be true that
           the two up around 15 are within 95 percent of through
           wall.
                       MEMBER KRESS:  But I would be very
           surprised.
                       MEMBER POWERS:  You see if I didn't have
           the red dot, I might be surprised.  But now I have the
           red dot.  Why am I going to be surprised?  You know
           already.
                       MEMBER KRESS:  The red dot is the one
           thing that raises a flag.
                       VICE CHAIR BONACA:  That's apples and
           oranges.
                       MEMBER KRESS:  If I had two red dots, I'd
           be more concerned.
                       VICE CHAIR BONACA:  But you don't have
           that.
                       CHAIRMAN APOSTOLAKIS:  So this is the one
           minute presentation?
                       MEMBER LEITCH:  Another important variable
           and it becomes a limitation I imagine of how much you
           can plot, is the inspection method.
                       CHAIRMAN APOSTOLAKIS:  Good.
                       MEMBER POWERS:  The one uncontested
           conclusion I get out of this is visual inspection
           looking for evidence of leakage is --
                       MEMBER FORD:  This is going to come up in
           further discussions because this is relating to the
           policy of how you manage these.
                       MR. HISER:  Okay.  I believe initially
           this whole two hour meeting was going to be on
           Bulletin 2001-01.  That overtook us.  So we're trying
           to squeeze two hours into about five minutes.
                       MEMBER FORD:  If I could just interrupt
           because this is a serious point.  Dana, this will come
           up for discussion in the near future to discuss that
           policy with regards to how we're going to manage this.
                       MEMBER POWERS:  Good.
                       MR. HISER:  This says conclusions.  But
           really these should probably be observations and
           status.  I guess what I really want to focus on is the
           implications of Davis-Besse to the future inspection
           needs for CRDM nozzles is yet to be determined.  Once
           the Bulletin 2002-01 review activities are completed
           and the root causes end then we will have a better
           understanding of that.  
                       In addition the bulletin addressed the
           next refueling outage for plants after August 2001. 
           In some cases plants a year from now will be up to
           their second inspection.  In all honesty, the
           bulleting really doesn't apply in that case.  What we
           hope to do is have some inspection guidance in hand by
           that time so that plants will be able to implement
           that next spring.  
                       I believe that the Committee was provided
           with a copy of our draft action plan that will be used
           to resolve the VHP nozzle cracking issue.  Again that
           was drafted before the Davis-Besse findings.  We have
           chosen at this point not to modify it because things
           are in such a state of flux.  Clearly that will be
           revised as the implications of Davis-Besse become
           understood.
                       MEMBER FORD:  That's both underlining I
           think, Allen, that parts of the actual experiments and
           analyses in that action plan are already being done by
           the MRP.  So you say it's a draft.  It is in fact. 
           The actions are already going on.
                       MR. HISER:  Yes.  That's correct.  That's
           what we had planned to talk about today.
                       MR. STROSNIDER:  This is Jack Strosnider. 
           I'd like to just add one comment here if I could to
           emphasize something that Allen touched on.  I don't
           know if this will go fully to addressing Dana's
           concern.  Hopefully it might help.
                       Again the bulletin was just a one time at
           their next outage, that's all it addressed.  We
           recognize that we need a longer term program to manage
           this.  I think that's where the work is ongoing.  
                       The Sub-Committee heard on Tuesday and the
           Committee today heard something very important from
           the MRP that I just wanted to go back and highlight. 
           That was that the MRP has reached a conclusion that
           just visual inspections to look for leakage is not an
           appropriate long term method for managing this type of
           degradation which has very important implications with
           regard to the type of inspections that would be done.
                       Basically it draws you to doing volumetric
           examinations and finding cracks before they ever
           develop into any kind of leak at all.  Hearing that
           from the MRP and that's an issue that we were looking
           to have some resolution on I think we'll be working
           with them to look at a longer term program that
           follows that philosophy.  We're waiting to see their
           proposal on that subject.  
                       Recognize that, yes, there is a longer
           term follow up that has to happen here with regard to
           managing this problem because it will show up at other
           plants.  This distribution is marching forward in
           time.  It will have to be managed.
                       MEMBER FORD:  I'll pass it back to you.
                       CHAIRMAN APOSTOLAKIS:  Well, thank you
           very much.  I guess we'll take another break now. 
           Then we'll go with the last item on the agenda.  We'll
           take 15 minutes, until 5:20 p.m.  Off the record.
                                   (Whereupon, the foregoing matter went off
                       the record at 5:07 p.m. and went back on
                       the record at 5:21 p.m.)
                       CHAIRMAN APOSTOLAKIS:  On the record. 
           We're back in session.  Risk-informed inservice
           inspection, break exclusion, region piping, that's
           what it says here.
                       MEMBER SHACK:  Just to remind everybody
           that we've been through this notion of risk-informed
           inspection for piping which seemed like a good idea at
           the time.  Again it was a notion.  Now we've learned
           about where pipes fail and about the consequences of
           failing.  In fact we could do better inspections by
           looking mostly at regions where we expected to find
           degradation of piping and looked hardest at the piping
           who's failure had the most severe consequence.
                       When we approved that it was basically for
           piping that was covered by the ordinary Section 11
           plants.  The augmented inspection regions were not
           covered under that one.  Now the industry is proposing
           to extend that to regions who are augmented and
           inspections were required.
                       One of those is the break exclusion region
           where in fact you're supposed to do 100 percent
           inspection of the welds.  There's a proposal then to
           risk-inform that.  The staff is going to tell us about
           their assessment of that proposal.
                       MS. KEIM:  Okay.  I'm Andrea Keim.  I'm
           going to be handing off this presentation later to
           Steve Dinsmore.  We have a few other support staff
           here to help us answer any questions.  Again we're
           here to talk about the risk-informed inservice
           inspection of an augmented inspection program covering
           break exclusion region piping.
                       A little bit of the background of the PRA 
           implementation plan included the following guidance
           that was developed for devising risk-informed decision
           making.  There were some general guidance developed
           and four application specific guidance in four areas. 
           They covered technical specifications, inservice
           testing, graded quality assurance and inservice
           inspection.  So far mostly the inservice inspection
           has been the most useful for industry.
                       MEMBER ROSEN:  A point of order.  I think
           our hand out is every other page.  At least mine is. 
           No, there's two on each page.  I'm sorry.  Human
           error.

                       MS. KEIM:  A little bit more on the
           regulatory project covering risk-informed inservice
           inspection.  Again we've developed a regulatory guide
           that was issued in September 1998 and a standard
           review plan.  We've also reviewed topical reports from
           Westinghouse Owners Group and an EPRI topical report
           covering inservice inspection.  Again that covered
           ASME code piping from code class 1 and 2.
                       These were issued back in '98 and '99. 
           Now what we're looking to do is extend that to a
           different augmented inspection.
                       First I wanted to go also and show the
           status of risk-informed ISI reviews.  We're proposed
           to receive 99 plants wishing to implement a risk-
           informed ISI inspection program.  We've received 46
           through December 2001.  We anticipate getting another
           42 in 2002.  We anticipate an additional 11 post-2002.
                       The 37 of these submittals that we've
           already received used the EPRI methodology.  The 13
           have used the WOG methodology.
                       CHAIRMAN APOSTOLAKIS:  What's the
           difference between the second bullet and the third
           bullet?
                       MS. KEIM:  Not much.
                       MEMBER KRESS:  A few months.
                       CHAIRMAN APOSTOLAKIS:  Major bullet. 
                       MS. KEIM:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Number of plants
           expected to implement RI-ISI is 99.  Number of plants
           that have submitted, what is that?
                       MS. KEIM:  That's what we have received so
           far to date.  So we have 50 applications so far.
                       CHAIRMAN APOSTOLAKIS:  So it's the 46
           through 2001 plus a few --
                       MS. KEIM:  A few that we have gotten this
           year.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MS. KEIM:  We've approved 46 of these
           plants.  All the ones through 2001.
                       CHAIRMAN APOSTOLAKIS:  I don't understand. 
           Why do you have to approve them since they are
           following methodologies that you have approved?
                       MS. KEIM:  Because these cover ASME code
           piping class 1 and 2 which require a submittal for a
           relief request.
                       CHAIRMAN APOSTOLAKIS:  Okay.  Even though
           they follow an accepted methodology.
                       MS. KEIM:  Yes.
                       MR. BATEMAN:  It's never quite so simple
           that they follow an accepted methodology.  Each
           licensee always has their own little differences they
           want to take from the accepted methodology.
                       CHAIRMAN APOSTOLAKIS:  So you have number
           of plants that have submitted is 50 or approved. 
           Sorry.
                       MS. KEIM:  So we have 50 that are
           submitted.  Our current activities are covering the
           Westinghouse Owners Group and EPRI submittals that are
           extending this risk-informed ISI methodology to the
           augmented inspection of break exclusion region piping.
                       MEMBER KRESS:  Could you give me a little
           idea of what break exclusion is about?
                       MS. KEIM:  We're going to get to that.
                       MEMBER KRESS:  Okay.
                       MS. KEIM:  That is coming.  Where that's
           defined and where those requirements came about. 
           Primarily our today's presentation will focus on the 
           EPRI methodology and the EPRI submittal because that
           one is farther along in the review process.
                       A little bit more background on the
           objective of ISI, inservice inspection.  That's to
           identify degraded conditions that are precursors to
           pipe failures.  I think we're all familiar with that. 
           For normal ISI, it's referenced in 10 CFR 50.55(a)(g). 
           That's the requirement that still requires them to
           still submit a relief request for the code class
           piping.  That again references ASME code for the
           requirements.
                       Now to what everybody's interested in. 
           The break exclusion region came around from reviews of
           general design criteria, number 4 which requires that
           structures, systems and components important to safety
           be designed to accommodate the effects of a postulated
           accidents and include appropriate protection against
           the dynamic and environmental effects of postulated
           pipe ruptures.  The staff has issued a number of
           documents that provide criteria for implementing the
           above requirements.  That covers the Standard Review
           Plan chapter 3.6.2 which also includes a staff
           technical position MEB 3-1.
                       The Standard Review Chapter states that
           breaks and cracks need not be postulated in break
           exclusion region piping provided they meet certain
           design and inspection criteria.  So from this they
           designed these pipes with the different criteria. 
           They also are required to inspect 100 percent of the
           piping welds in these regions.
                       CHAIRMAN APOSTOLAKIS:  I must say it's not
           clear to me what a break exclusion region is.  What is
           it?
                       MS. KEIM:  Well actually it's piping that
           is in the vicinity of the containment which is from
           the inside isolation valve to the external isolation
           valve.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MEMBER KRESS:  That's piping that you guys
           want them to design and inspect so that you can
           exclude the possibility that it won't break.
                       MS. KEIM:  Right.
                       MEMBER ROSEN:  That's what exclusion
           really means.  It doesn't have anything to do with
           excluding from the welds or from the inspection.
                       MEMBER KRESS:  Yes.  Okay.
                       MEMBER ROSEN:  It has to do with excluding
           breaks from the process.
                       MEMBER KRESS:  There are important regions
           of piping that you just don't want to break.  You want
           to be sure.
                       MS. KEIM:  Right.
                       MEMBER SIEBER:  So you have to do 100
           percent of every weld.
                       CHAIRMAN APOSTOLAKIS:  This is the only
           place where 100 percent inspection takes place.
                       MEMBER SIEBER:  I think that sampling in
           other places.
                       CHAIRMAN APOSTOLAKIS:  Everywhere else
           it's sampling.
                       MS. KEIM:  Yes.
                       MEMBER ROSEN:  The code typically requires
           I think 25 percent.
                       MS. KEIM:  Yes.  For class 1.
                       CHAIRMAN APOSTOLAKIS:  What is MEB?
                       MS. KEIM:  MEB is another acronym that we
           use to identify different branches.  MEB is the
           Mechanical Engineering Branch.
                       CHAIRMAN APOSTOLAKIS:  Oh, okay.
                       MS. KEIM:  That's included in the Standard
           Review Plan which is attached into the Chapter 3.6.2.
                       MEMBER SIEBER:  I think the nickname for
           the  break exclusion region piping is superpipe
           because it gets inspected so much.
                       MS. KEIM:  Also because it has additional
           design criteria.
                       MEMBER SIEBER:  Right.
                       CHAIRMAN APOSTOLAKIS:  Okay.  So now I
           understand what a BER is.  What is the first sub-
           bullet?  "Pipe breaks not postulated in BER if
           criteria is satisfied including augmented IDI of
           piping welds."  What does that mean?
                       MS. KEIM:  I think some of that we're
           going to cover a little bit later.
                       CHAIRMAN APOSTOLAKIS:  What do you mean
           "not postulate"?
                       MR. DINSMORE:  This is Steve Dinsmore from
           the staff.
                       MEMBER SIEBER:  You don't have to consider
           it.
                       CHAIRMAN APOSTOLAKIS:  Oh, if the criteria
           is satisfied --
                       MEMBER SIEBER:  You don't have to
           postulate a pipe break.
                       CHAIRMAN APOSTOLAKIS:  You do the safety
           analysis.
                       MEMBER SIEBER:  Right.
                       MR. ALI:  This is Syed Ali from the staff. 
           Maybe I can clarify just a little bit.  I think one of
           the big differences between the BER and the non-BER is
           in the regions breaks had to be postulated and
           hardware had to be installed for the effects of those
           breaks such as pipe replacing, check shields.  
                       This region which is generally between the 
           inside and the outside containment isolation valve is
           so congested that the staff came up with the criteria
           that you don't have to postulate breaks.  Therefore
           you don't have to install all that hardware provided
           a number of conditions can be met.
                       One of those conditions was 100 percent
           inspection.  Other conditions were stress below a
           certain level, you critique below a certain level.
                       CHAIRMAN APOSTOLAKIS:  Okay.  So I guess
           if you had written "pipe breaks need not be
           postulated" then it would be clearer.
                       MR. ALI:  Right.
                       CHAIRMAN APOSTOLAKIS:  Okay.  This is an
           interesting situation that you just described because
           it goes against the defense in depth philosophy.  Does
           it not?  It says you are shifting everything to
           prevention.  They say no longer areas.  You also do
           something to mitigate, to contain the possibility. 
           But here you just convince yourself that the break
           will not happen.
                       MR. ALI:  There are a number of conditions
           that have to be satisfied.
                       MEMBER POWERS:  George, you're promptly
           committing the cardinal sin of defense in depth.  That
           is applying it to every damn sub-system in the whole
           reactor.
                       CHAIRMAN APOSTOLAKIS:  That's a cardinal
           sin?
                       MEMBER POWERS:  Yes.
                       CHAIRMAN APOSTOLAKIS:  So big.
                       MEMBER POWERS:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Jesus.  I'm
           beginning to become a rationalist again.  All right. 
           That's clear now.
                       MS. KEIM:  So now what the proposal is --
                       CHAIRMAN APOSTOLAKIS:  Well excuse me. 
           But it doesn't tell me anywhere that the defense in
           depth stops at some point.  If I read all the
           documents, that's a philosophy.
                       MEMBER POWERS:  If you read the exemplary
           paper by Sorenson, Powers and Apostolakis, it would
           outline this for you.
                       CHAIRMAN APOSTOLAKIS:  That was probably
           the part that Apostolakis did right.  Okay.  Sorry,
           Andrea, it's late.
                       MS. KEIM:  That's okay.  So what the
           proposal is --
                       CHAIRMAN APOSTOLAKIS:  You're doing fine
           actually.
                       MS. KEIM:  Risk-informed methodology to
           select piping elements and welds to be inspected in
           lieu of the 100 percent examination.  With that I'm
           going to hand it over now to Steve Dinsmore.
                       MR. DINSMORE:  Hi.  I'm Steve Dinsmore
           from the PRA branch.  I've been involved in this risk-
           informed ISI since pretty much day one or since the
           beginning of time, whichever is longer.
                       CHAIRMAN APOSTOLAKIS:  That's where time
           started.
                       MR. DINSMORE:  Just to give you a brief
           overview that can avoid some confusion later.  What we
           have is this temporary ISI TR, the original TR.  It's
           about 200 pages.  It has a whole description of a
           methodology.  It's been approved to use.  Except it
           was explicitly excluded for use in the break exclusion
           region.
                       Now we have this second topic.  This is
           what we call the EPRI BER TR.  Not topical essentially
           identifies tweaks to the original methodology.  If
           they used them, they can take the original
           methodology, tweak it and apply it to the break
           exclusion region.
                       This slide is a quick overview of the
           different steps in the original methodology and how
           they're changed to let the BER program be included. 
           The first one is scope definition.  It's easy.  It
           used to be excluded.  Now we include it.
                       The consequence evaluation.  The BER TR
           includes a fairly well defined criteria which should
           be used to determine the consequences of ruptures in
           these regions.  So that's probably the major
           difference.
                       Degradation mechanism evaluation.  There's
           no change.  Piping segment definition.  There's no
           change.  Risk categorization.  There's no change. 
           Selection of welds.  There's no change.
                       Risk impact assessment.  Essentially what
           we --
                       CHAIRMAN APOSTOLAKIS:  Let me understand
           that.  When you say "no change" to what?
                       MR. DINSMORE:  To the original
           methodology.
                       CHAIRMAN APOSTOLAKIS:  Okay.  Not to what
           you used to do to the break exclusion area.
                       MR. DINSMORE:  Right.  This is to the
           original methodology.
                       CHAIRMAN APOSTOLAKIS:  This is to the
           report.
                       MR. DINSMORE:  This is to the methodology.
                       CHAIRMAN APOSTOLAKIS:  The methodology.
                       MEMBER ROSEN:  The existing approved
           methodology to the 46 plants.
                       CHAIRMAN APOSTOLAKIS:  Now it makes sense. 
           But did you explain to us what they propose to do to
           the exclusion region?
                       MR. DINSMORE:  The tweaks are described
           here.  This is a quick overview.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. DINSMORE:  The risk impact assessment. 
           We had to figure out how to apply the risk criteria
           that we'd been using to this region and to the plant
           in total.  There's also a slide on that.
                       Monitoring feedback.  There's no change to
           that.  The implementation is another one of the bigger
           changes.  A lot of these BER programs are only
           referenced in the FSAR.  You could use 50.59 to make
           changes that are referenced in the FSAR.
                       CHAIRMAN APOSTOLAKIS:  What does that mean
           implementation if you use 50.59?
                       MR. DINSMORE:  If you do a 50.59
           evaluation, you can determine whether you need to make
           a submittal for prior review or not.  Sometimes they
           are in other places, but those plants have their own
           problems.  
                       If it's only referenced in the FSAR, you
           should be able to apply your 50.59 evaluation, use
           this methodology and then apply the evaluation.  Then
           you won't have to come in with a submittal.  You can
           just make a change.
                       CHAIRMAN APOSTOLAKIS:  How would you apply
           50.59 to piping in the exclusion region?  Have you
           thought of the questions that you're effecting
           initiating vents?
                       MR. DINSMORE:  Actually the seventh
           question is are you --
                       CHAIRMAN APOSTOLAKIS:  I thought the first
           question of 50.59 was what you are about to do could
           effect initiating events.
                       MR. DINSMORE:  We have our 50.59 person
           here specifically for that.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MS. MCKENNA:  This is Eileen McKenna from
           the NRC Staff.  I think you're going to get to it a
           little later in the presentation.  I think part of the
           point that was trying to be made here is that this
           part of the program, the BER, is not in 50.55(a).  So
           you don't have to follow a 50.55(a) review and
           approval process.  
                       Then you look at what is the approval
           process if there is one that might apply to this.  To
           the extent that it's in the FSAR, then it would be
           50.59 that would apply to it.  
                       What we're talking about as you'll see a
           little bit later is we're really looking at the
           methodology by which you select your inspection
           locations as changing from the 100 percent inspection
           to the risk-informed approach.  Then using a
           methodology that has been approved through the topical
           process.  Then you would go through Criteria A which
           is the method of evaluation criteria in 50.59.
                       CHAIRMAN APOSTOLAKIS:  But I suspect that
           all of this will fail to pass the Criteria 50.59. 
           Would it not?  So you would actually have to come to
           the staff.
                       MS. MCKENNA:  We're approaching it from
           looking at it as being the method for determining the
           inspection locations.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MS. MCKENNA:  We're looking at it as being
           Criteria A method of evaluation.  The criteria that's
           established is that if you're changing from the method
           that you had in your FSAR to another method that has
           been approved by the NRC for the intended application,
           that is a change that can be done under 50.59.
                       MR. DINSMORE:  You don't have to answer
           the other seven questions.
                       MS. MCKENNA:  Right.  If it's methodology.
                       CHAIRMAN APOSTOLAKIS:  It's only
           methodology here?  You say you are reducing the number
           of locations.
                       MEMBER SHACK:   You're changing the method
           that you're selecting the inspection.
                       MR. DINSMORE:  Right.
                       MS. MCKENNA:  It has that effect, yes.
                       MEMBER SIEBER:  But that's already been
           approved by the staff as a generic methodology.  So it
           doesn't result in an unreviewed safety question.
                       CHAIRMAN APOSTOLAKIS:  No.  But it has
           been approved for regional solid of the exclusion
           rate.
                       MR. DINSMORE:  We're in the process.  If
           we issue this SE, it will approve it for use
           specifically in this region.  The SE even says that.
                       CHAIRMAN APOSTOLAKIS:  Let me understand
           this.  Before this, we were inspecting at how many
           locations?
                       MR. DINSMORE:  At 100 percent.
                       CHAIRMAN APOSTOLAKIS:  At 100 percent. 
           Now it's going to be in a smaller number.
                       MR. DINSMORE:  Yes.
                       CHAIRMAN APOSTOLAKIS:  You consider that
           a change in method.  Is that an unresolved question?
                       MR. DINSMORE:  No.  We're reviewing it as
           a change in methodology.
                       CHAIRMAN APOSTOLAKIS:  That's what I'm
           saying.  Why is that so?  It doesn't sound to me like
           it's a change in method.  It's a change in results. 
           You are inspecting less.
                       MEMBER ROSEN:  I think it's a change in
           method that results in a change in results.  It's a
           change in the methodology.
                       CHAIRMAN APOSTOLAKIS:  Which results
           though in a real change which may effect initiating
           events.
                       MR. DINSMORE:  But all methodology changes
           could result in a real change.
                       CHAIRMAN APOSTOLAKIS:  All?
                       MR. DINSMORE:  I think so.
                       MEMBER SHACK:  The assessment will find
           that it doesn't significantly increase your risk.
                       MEMBER SIEBER:  The generic assessment. 
           The SER.
                       MEMBER SHACK:  If you follow the
           methodology.
                       MR. DINSMORE:  Yes.
                       MEMBER ROSEN:  George, you're having a bad
           day.
                       MR. ALI:  This is Syed Ali from the staff
           again.  The original EPRI methodology is specifically
           excluded from its scope the application to this
           region.  So what they are doing now is coming with an
           addendum to that methodology that says their
           methodology can be applied to this region also.  
                       We are reviewing that addendum.  If we
           approve the addendum then we would have approved the
           original methodology but now being applied to this
           region also.  There are some slight tweaks to the
           methodology changes.  But it's basically the same
           methodology.
                       MR. DINSMORE:  I think the idea is first
           put out this NEI 97.06 that if you use this approved
           methodology or an approved methodology for the purpose
           it was approved for, you don't have to address those
           other questions.  The NRC has accepted that as
           guidance for using 50.59.
                       MEMBER KRESS:  These pipes penetrate the
           containment generally.  There's isolation valves on
           either side of the containment.  If the pipe breaks on
           the other side of containment, you've automatically
           violated your containment.
                       MEMBER SIEBER:  Not if the valves work.
                       MEMBER KRESS:  Well, the valves are
           generally open.  You have to close them.  Right?
                       MEMBER SIEBER:  Well, they close generally
           automatically.
                       MEMBER KRESS:  What I'm trying to
           reconcile is that 1.174 and by extension to the
           inservice inspection part of 1.174 there's a
           stipulation that you don't violate the defense in
           depth principle.  It seems to me like this is a
           defense in depth consideration.  I don't know whether
           it violates it or not.  It appears to violate it to
           me, but I'm not sure.
                       CHAIRMAN APOSTOLAKIS:  No.  The 1.174 says
           the defense in depth philosophy.
                       MEMBER KRESS:  Well, that's a philosophy.
                       CHAIRMAN APOSTOLAKIS:  So that's a way out
           of that.
                       MR. DINSMORE:  Well, we include the
           spatial effects of the failure of this piping in the
           evaluation.  Exactly what you gentlemen are talking
           about is why we have a much more well defined spatial
           effects evaluation process in the TR instead of
           leaving it somewhat up to the licensees to develop and
           document how they want to address spatial effects.
                       In this case, we've taken the extra step. 
           We've put in a good bit more description and criteria
           about how they're supposed to do that analysis.  But
           if the results of the analysis are acceptable
           according to all the other criteria that we have, then
           it's okay.
                       MEMBER LEITCH:  It seems to me that if you
           get past this first issue of the questionable
           definition of methodology and you applied the other
           seven questions, it would fail.  Would it not? 
           Clearly it would fail.
                       CHAIRMAN APOSTOLAKIS:  Yes.  Clearly fail.
                       MEMBER LEITCH:  So if the whole arguement
           is hinged on the definition of methodology then you're
           not going to get to the others.
                       CHAIRMAN APOSTOLAKIS:  Exactly.
                       MR. DINSMORE:  It might not fail so bad
           though because we did look at the questions a bit.
                       MEMBER SIEBER:  My way of looking at it,
           and you can correct me because it's a simple way of
           looking at it is that if it fails, that means it is an
           unreviewed safety question.  Then you have to go to
           the staff to get approval.
                       MR. DINSMORE:  Right.
                       MEMBER SIEBER:  But they've already
           approved when they write this SER the methodology.  So
           it's no longer an unreviewed safety question.  I think
           that's what that means.  So you don't end up having to
           go down that chain of questions to legitimately apply
           the methodology because the staff has already approved
           the methodology.  Is that a way to look at it?
                       CHAIRMAN APOSTOLAKIS:  How does that
           compare with the earlier information that Andrea gave
           us about the number of plants submitting risk-informed
           ISIs and being reviewed by the staff?
                       MR. DINSMORE:  But that's a totally
           different process.
                       CHAIRMAN APOSTOLAKIS:  You are reviewing
           the process that you have.
                       MR. DINSMORE:  If you want to get a relief
           from applying, that's going to be Section 11
           inspections, you have to come in to the staff and
           request relief.
                       MEMBER SIEBER:  An exemption.  Right?
                       MR. DINSMORE:  It's a relief request.
                       CHAIRMAN APOSTOLAKIS:  So that doesn't
           apply here.
                       MEMBER SIEBER:  From 50.55(a).
                       MR. DINSMORE:  Yes.
                       MEMBER SIEBER:  Right.
                       MR. ALI:  Again, it's Syed Ali.  I just
           want to add something on that also.  In the original
           program, they were specifically going below the
           inspections that are required by ASME 11.  So they had
           to come in for a relief.  Here in this region there's
           ASME piping and there's non-ASME piping.
                       For ASME piping that is in this region,
           they would have to maintain at least the ASME 11
           inspections in order to apply 50.59 and not come for
           a relief.  If they go below the ASME 11 then it will
           go into the same kind of a treatment as the rest of
           the plant.  They will have to come in with a relief
           request.  So the floor is still the ASME 11 in this
           region for the 50.59 process to be applicable.
                       MEMBER LEITCH:  The actual floor is about
           a 10 percent inspection.
                       MR. ALI:  Well, it's 25 percent for ASME
           class 1 and about 7 and a half for ASME class 2. 
           That's the ASME level in the floor.
                       CHAIRMAN APOSTOLAKIS:  Well, I guess if
           it's clear to all the members, we can go ahead.
                       MEMBER LEITCH:  Just one more question. 
           Is that 25 percent per 10 year interval?
                       MR. ALI:  The 25 percent per each 10 year
           interval, yes.
                       MEMBER LEITCH:  Thank you.
                       MR. DINSMORE:  Okay.  Now we move to the
           consequences.  We'll explain a little bit again the
           difference between BER piping and non-BER piping.  The
           non-BER piping had pipe failure postulated during the
           design and evaluated using these SRP guidelines.  The
           mitigative hardware was added as needed.  I guess we
           already talked about this a lot.
                       In the BER piping, the pipe failures were
           not postulated and the mitigative devices were not
           constructed.  So essentially when we did the original
           risk-informed ISI we were looking at the non-BER
           piping because that's the only place they were
           changing inspections.  We were more or less crediting
           this SRP analysis out there.  They had done this SRP
           analysis one time already.  So these guys can do their
           PRA realistic analysis on top of that.
                       Now inside the BER piping, we don't have
           that fall back.  It's just whatever is there.  That's
           the reason in the EPRI BER TR, we essentially said you
           can use the SRP guidelines or criteria or somewhat
           more conservative.  They can use somewhat more
           conservative because it's not as sensitive.  What the
           result is, is that the segment goes into higher
           medium.  The result of that is they do 10 percent or
           25 percent of inspection.
                       It's not that they have to build in all
           this equipment.  So I think the two pilots were
           somewhat conservative because it didn't hurt them that
           much to be conservative.
                       MEMBER LEITCH:  Once again I just want to
           make sure I understand this.  Under the BER piping,
           the reason that pipe failures were not postulated is
           because this particular piping was very conservatively
           designed and because we were going to do 100 percent
           inspection.
                       MR. DINSMORE:  Right.
                       MEMBER LEITCH:  Not because it's not
           important.  In fact it's to the contrary.  It's very
           important.
                       CHAIRMAN APOSTOLAKIS:  Yes.  I think that
           was the reason.
                       MEMBER LEITCH:  These are high energy pipe
           lines.
                       MEMBER SIEBER:  Some are, some aren't.
                       MR. DINSMORE:  We're working on it.
                       MEMBER LEITCH:  It's main stage.  It's
           feedwater.  Isn't it?
                       MEMBER SIEBER:  Sure.
                       MR. SULLIVAN:  This is Ted Sullivan.  I'd
           like to add a little perspective.  I think Dr. Kress
           really hit upon it earlier.  You couldn't postulate a
           break in these areas.  If you postulated a break for
           example in a boiler and coupled with it the single
           failure of the isolation valve --
                       MEMBER KRESS:  Or leaking at that.
                       MR. SULLIVAN:  You violate containment. 
           So it's really an outgrowth of that.
                       MEMBER LEITCH:  All the more reason for
           inspection though as I say.  I agreed you couldn't
           postulate a break.  But I just don't understand the
           logic of this.  If you couldn't postulate a break,
           it's not because it's not a problem.  It's a big
           problem.  So all the more reason to inspect.
                       MR. SULLIVAN:  I don't disagree with you. 
           There are some representatives of industry here if
           they want to add to what I'm saying, industry's view
           was that these are fairly high radiation areas.  They
           really have not been finding anything to speak of or
           much to speak of from doing these inspections.
                       They've done thousands and thousands of
           weld inspections.  The performance of this piping is
           very good.  So what they proposed and we've been
           reviewing is a concept of focusing inspections
           basically for cause.  Where is the degradation
           expected to have some potential to occur?  Let's
           inspect in those regions and couple that with regions
           where the consequences would be high rather than
           forcing the licensees to continue to do 100 percent in
           a lot of area where they really can't even identify a
           potential degradation mechanism.
                       CHAIRMAN APOSTOLAKIS:  It's a performance
           based initiative.  Because they haven't found anything
           in many inspections, they say why should we keep doing
           this.
                       MR. DINSMORE:  Why should we keep doing
           100 percent?
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MR. DINSMORE:  I think that's right.
                       MEMBER KRESS:  That's a different
           arguement than we've been hearing.
                       CHAIRMAN APOSTOLAKIS:  It's a very
           different arguement.
                       MEMBER KRESS:  It's a more persuasive
           arguement.
                       CHAIRMAN APOSTOLAKIS:  In fact, it's much
           more persuasive, yes.  This is not risk-informed
           stuff.  This is performance based.
                       MEMBER POWERS:  In fact, it has to be a
           risk-uninformed thing.  I mean, WASH 1400, NUREG 1150
           all tell us if you want to get yourself in real
           trouble you have a bypass accident.
                       MEMBER KRESS:  That's exactly right.
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MEMBER POWERS:  So if you bust these
           pipes, you have a bypass accident.  Anything that
           degrades your confidence in these, would have to be a
           risk-uninformed activity, inverse of risk-informed.  
                       CHAIRMAN APOSTOLAKIS:  You would never
           pass 50.59.  You just don't.
                       MS. KEIM:  We have someone from industry
           that would like to speak.
                       MEMBER KRESS:  You might if you postulate
           that the inspections aren't doing you any good because
           they never found anything.
                       CHAIRMAN APOSTOLAKIS:  No.  The
           inspections are always doing something good.  They
           never found anything.  That's strong evidence that the
           uncertainty has been reviewed significantly.  Right?
                       MR. DINSMORE:  Yes, sir.
                       MR. BALKEY:  This is Ken Balkey from
           Westinghouse.  I'm working with our team on the
           Westinghouse Owners Group methodology.  They fall as
           the same procedure in the EPRI method as well.  
                       To add to Ted Sullivan's comments, when we
           did the risk-informed ISI work from the original
           topicals a few years ago, we learned a lot.  That ASME
           code had 25 percent and 10 percent.  There was a
           history of how they came up with that.  It just says
           there's a history is why there's 100 percent here.
                       To do these exams, it's not simply just go
           out.  They are in congested areas and high radiation
           areas.  There are only so many examiners to go around
           as well too.  
                       When we did the risk-informed ISI process
           with either method to do the Section 11 exams, we feel
           that we've done a real service.  Even though we're
           doing a smaller population, we are in the process of
           moving the exams to the areas of active degradation.
           Therefore making very good use of the utility's
           resources in doing those examinations.
                       We knew about this area when we did the
           original program.  We even had a lot of discussion
           with the NRC of could we include this, even in the
           original topical three or four years ago.  
                       The staff felt and industry agreed that we
           have to take one step at a time here.  It was enough
           of an issue to get through the ASME Section 11 exams
           and working through a regulatory process with the
           relief as Andrea said in terms of utilities making
           submittals and getting approval for a relief request.
                       The industry now said we should be able to
           take the same knowledge we just gained from that
           program, and apply it to the high energy line break
           exclusion region.  We're not taking exams down to
           zero.  I think we're trying to support what Dr. Kress
           said.  Do you really 100 percent to give you assurance
           that the integrity is good within this piping?
                       If it was easy to do, we wouldn't be here. 
           They are difficult exams to do.  So we're saying can
           we do a smaller population and still get the same
           level of assurance in this region like was done in the
           same piping for the Section 11 program.  All the
           questions in terms of if it breaks, would it take out
           other areas or what it's effect is from a PRA, we
           still have to look at that.  There are areas where we
           will not remove examinations because the PRA indicates
           them a consequence.  You really still need to do a
           number of exams in that area.
                       In summary, what we are trying to do is
           really take what we learned on the original
           application and now extending it to this for the 100
           percent.  It does free up the resources to really get
           at some other degradation issues we're dealing with in
           our plants.
                       MEMBER KRESS:  Let me ask you a question.
                       MR. BALKEY:  Sure.
                       MEMBER KRESS:  When you say 25 percent of
           piping instead of 100 percent, let's just pick a
           number.
                       MR. BALKEY:  Okay.
                       MEMBER KRESS:  Does that mean you
           eventually inspect all the piping?  You would only
           spread it out in time a little more.
                       MR. BALKEY:  That's a good question.  The
           original concept for the 25 percent came from 30 years
           ago.  You do 25 percent in the first 10 years, 25
           percent in the second and so forth.  So over the life
           of the plant, you do 100 percent.  
                       But guess what?  As plants operated, folks
           said we did the first 25 percent and we really should
           go back and take a look to see if anything changed. 
           If you go another 25, going back to a location you
           just did 10 years ago and you get a different signal
           from your ultrasonic, you know degradation is under
           way.  So you're better off getting to a smaller
           population and really monitoring the degradation
           closer than trying to do it all one at a time.
                       MEMBER KRESS:  You could do a combination
           of those two.
                       MR. BALKEY:  Right.  In this application,
           the intent would be you'd have a smaller population. 
           But they are the areas that you would expect
           degradation and of course areas of high consequence. 
           You would go back to those areas each ten year
           interval.
                       CHAIRMAN APOSTOLAKIS:  So you are always
           inspecting the same 25 percent?
                       MR. BALKEY:  Yes.  Or whatever the percent
           ends up being in this region.  Yes.  You would go back
           to the same.  But the program also as part of its
           update if you find something whether it's in the
           Section 11 program or if it's in a break exclusion
           region, you may have to expand your sample.  Not may,
           it is.
                       There's a sampling scheme that if you find
           something in that outage, you have another population
           that sees it now somewhere else you weren't
           inspecting.  If you find something there, then you're
           doing 100 percent of your area.  So the process allows
           you to get to 100 percent if you start finding
           degradation in the sample that you're doing.
                       MEMBER LEITCH:  How big an issue is ease
           of inspection in determining which 25 percent?
                       MR. BALKEY:  I would actually ask one of
           my colleagues here who is an examiner at his plant.
           Dave, do you want to speak to the difficulty in
           getting to some of the locations.
                       MEMBER LEITCH:  I know some of the
           locations are very difficult.  My question was really
           how do pick your 25 percent.
                       CHAIRMAN APOSTOLAKIS:  Do you pick them
           randomly?
                       MR. BALKEY:  Right now Dave has to do 100
           percent of the exams at his plant.
                       MEMBER LEITCH:  I know some of them are
           really hard.  What I'm saying is when you determine
           your 25 percent sample view, do you eliminate the real
           hard ones?
                       MR. BALKEY:  No.  I can give you an
           example.  Turkey Point is one of the plants that's
           been submitted not for break exclusion but in the
           original Section 11.  We looked at their risk-informed
           ISI.  We indicated in their surge line for their
           operational experience.  They had to do 100 percent of
           the surge line.
                       That was a very difficult finding because
           they had to go back and spec underneath the
           pressurizer.  It's a very high radiation.  But we said
           you have to examine it because of the information you
           had.  We would use the same philosophy.  The same
           philosophy would apply here.  
                       Just because it's hard to get to is not
           the reason you would drop it out.  If you find it's an
           area of degradation and your PRAs telling you that
           it's really important if it fails, unfortunately
           you're going to have to go in and make the effort to
           do the examination.
                       MEMBER KRESS:  What is the risk criterion? 
           How do you establish whether the one pipe section is 
           more risky than another one?  Is it because of
           equipment that may be around it?
                       MR. BALKEY:  Yes.
                       MEMBER KRESS:  Is it the size of the pipe
           or the flow rates or a combination?
                       MR. BALKEY:  It's a combination of the
           temperatures and pressures.  That's part of what
           Stephen was talking about and the consequence
           evaluation on this slide here.  One has to go in and
           look a lot more carefully.  You look at your pipe whip
           for jet impingement effects and also flooding effects
           on the electrical equipment if there's anything that
           happens to be nearby.
                       MEMBER KRESS:  That's how you decide the
           risk.
                       MR. BALKEY:  Yes.  That's part of the
           process.
                       MEMBER ROSEN:  The functions of the piping
           as well.
                       MR. BALKEY:  As well as the functions of
           the piping.  We usually break it in to a direct
           consequence to address the functions.  Then the
           indirect effects are the pipe whip and jet impingement
           of pipes whipping and taking out other equipment
           nearby.  That has to be done as part of the process.
                       MEMBER KRESS:  Thank you.
                       MR. DINSMORE:  Okay.  I'm not quite sure
           this is resounded.  We do use some risk information in
           the process.  So that they don't have to come in with
           a submittal, you have to keep that in the back of your
           mind, the quality of the PRA needs to be the same
           acceptable quality as for risk informed ISIs since
           it's pretty much the same process.
                       MEMBER SHACK:  Can he do this without
           having a risk-informed ISI program for his Section 11
           piping?
                       MR. DINSMORE:  They can apply this to the
           BER region without doing a risk-informed ISI.
                       MEMBER SIEBER:  Right.
                       MR. DINSMORE:  Within the BER region then
           as Syed was saying earlier --
                       MEMBER SHACK:  Could you do it with 50.59?
                       MR. DINSMORE:  Yes.  But you couldn't
           change the ASME Section 11 inspections if there are
           any in this BER region.  You could only change the BER
           specific ones.
                       MEMBER ROSEN:  Do you expect anybody to
           actually do that, someone who hasn't done the basic
           risk-informed ISI?
                       MR. DINSMORE:  I have Pat O'Regon back
           there nodding.  He's from industry.  So I have a
           feeling he knows.
                       MR. O'REGON:  I'm Pat O'Regon from EPRI. 
           The answer is yes.  There are several plants that
           would like to implement BER only.  In particular a
           couple of BWRs will be implementing BWR VHP 75 on the
           stainless steel piping and risk-informed BER on the
           carbon steel piping.
                       MEMBER POWERS:  How would the quality of
           your PRA affect the conclusion that seems to be robust
           trough all PRAs that containment bypass accidents are
           very hazardous accidents?
                       MR. DINSMORE:   Well, they would assign a
           pretty high conditional core damage probability or a
           conditional large early release probability to those
           segments which would contribute to those sequences. 
           Then it would be up to whatever degradation mechanisms
           are in those segments.  
                       If there's no degradation mechanism and a
           very low failure probability then those segments would
           be lower risk.  If there's some degradation mechanism
           and a high probability, there would be a higher risk.
                       MEMBER LEITCH:  Do we have any idea how
           much man-rem per plant per year is attributed to the
           execution of this program as it now stands?  In other
           words, what's the man-rem saving per plant per year
           estimated to be?
                       MR. DINSMORE:  Maybe industry would know. 
           I don't.  I guess not.  No.
                       MEMBER ROSEN:  Another way to look at that
           same question is what's the percentage reduction in
           the program that would come out of this.  How big an
           effect is it on the remaining overall program?  Can
           you give us any feel for that?
                       MR. DINSMORE:  The EPRI TR says that if
           you get below 10 percent, you need to provide a good
           explanation of the design features in your plant which
           supports finding that you have to inspect less than 10
           percent of the welds in this region.
                       MEMBER ROSEN:  That's not exactly the
           question.  That's not the answer to the question that
           I thought I asked.  
                       The question is let's say before you have
           a start at this you were inspecting 1,000 welds in the
           10 year period.  Then you go to risk-informed ISI. 
           Now you're only inspecting 350 welds.  You knocked out
           two-thirds of them which I think is the number I
           remember.  
                       So you're down to 350 welds in the 10 year
           period.  Now can go to break exclusion piping and
           knock that out.  Now you're inspecting not 350 but
           only 175 or 300?  I'm trying to get a feel for the
           additional reduction.
                       MR. DINSMORE:  This is one of the pilots
           that we didn't review by the way we just looked at it.
           If you had 135 welds, one of them went down to 20 for
           example.  So that's about 11 percent.  The other one
           went down to 3 percent.
                       MEMBER ROSEN:  Wait a minute.  You said
           135 and you went to 20.
                       MR. DINSMORE:  Yes.
                       MEMBER ROSEN:  That's a reduction of
           almost 90 percent.  Right?
                       MR. DINSMORE:  That's because we're
           starting with 100 percent.  You see if you start with
           ASME --
                       MEMBER ROSEN:  Out of 135 welds you're
           total example was the BER scope.
                       MS. KEIM:  Yes.
                       MR. DINSMORE:  Right.  You inspect them
           all to start with.  In the ASME class 1, you were
           going from 25 percent down.  Here you're going from
           100 percent down.
                       MEMBER ROSEN:  So basically it's a very
           large reduction in the BER scope.
                       MR. DINSMORE:  It can be.
                       MEMBER KRESS:  When you do the risk
           assessment to calculate the change in LERF for
           example, can you check it along with the absolute
           LERF?  If you have more than one unit on the side, are
           you going to add the LERFs together?
                       MR. DINSMORE:  We don't have process to
           deal with that.  If you had more than one unit on the
           site I think what happens is if you add the two
           together, the relative increase would be the same.  We
           don't really apply these criteria.
                       MEMBER KRESS:  No.  You have an absolute
           LERF then you have a Delta LERF.  The Delta LERF stays
           the same.  If you do it to one unit only, the Delta
           LERF is for the unit.  But the LERF is a LERF for the
           site.  It ought to be the sum of all the plants that
           are on the site.  That's a glitch or a short coming of
           1.174 that I've been trying to get fixed.  That's why
           I ask the question every time.
                       MR. DINSMORE:  We haven't fixed it in this
           SE.
                       CHAIRMAN APOSTOLAKIS:  A straightforward
           answer.  You'll wait until 1.174 is fixed first I

           imagine.
                       MR. DINSMORE:  Right.
                       CHAIRMAN APOSTOLAKIS:  Okay.  Let's move
           on.  Go to 11.
                       MR. DINSMORE:  This is 11.
                       CHAIRMAN APOSTOLAKIS:  This is 11?
                       MR. DINSMORE:  I have a different
           numbering system.
                       CHAIRMAN APOSTOLAKIS:  So what number do
           you have for this one?
                       MR. DINSMORE:  I have 11 for the other
           one.  We took one out.  We put one together.
                       CHAIRMAN APOSTOLAKIS:  We discussed this. 
           Didn't we?
                       MR. DINSMORE:  Yes.  We discussed this in
           the beginning.  We can just maybe even skip it.
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MEMBER KRESS:  This is the final
           conclusion you have.
                       MR. DINSMORE:  Right.
                       CHAIRMAN APOSTOLAKIS:  Now let me
           understand the first bullet.  As I recall Regulatory
           Guide 1.174 as we said earlier today has a beautiful
           discussion of uncertainties incompleteness, models. 
           Are you guys doing any of that?
                       MR. DINSMORE:  Those are included mostly
           in the system level guidelines.  We don't allow them
           to for example take a bad weld in a dangerous system
           and start inspecting that.  They get a big plus risk
           from that and use that to stop inspection many welds
           in other systems.  We don't believe that the numbers
           support those type of large shuffling of risk.
                       CHAIRMAN APOSTOLAKIS:  When you say the
           basic acceptable quality of the PRA is the same as the
           risk-informed ISI, so you have already approved 46. 
           Right?
                       MR. DINSMORE:  Right.
                       CHAIRMAN APOSTOLAKIS:  These are 46
           submittals.  You are now reviewing four.
                       MR. DINSMORE:  There are five.  We got one
           yesterday.
                       CHAIRMAN APOSTOLAKIS:  Five.  Okay.  So
           you are really busy then.  When you reviewed the 46,
           did you look at issues like model uncertainty and
           incompleteness?  My impression is that nobody's doing
           uncertainty analysis anymore.
                       MR. DINSMORE:  What we required for the
           risk-informed ISI is that the licensee go back and
           look at all the negative comments made by the research
           review and the peer review process, the BWRG.  They
           evaluate all these comments and make sure that either
           they don't affect the results of the ISI analysis or
           that they incorporate somehow the comment into the
           evaluation.
                       CHAIRMAN APOSTOLAKIS:  But what if the PRA
           has not done an uncertainty analysis at all?  We were
           told last month that asking for uncertainty analysis
           means killing the program because nobody does it.  So
           I don't know how you conform with Regulatory Guide
           1.174 if you don't do that.
                       MR. DINSMORE:  Well, I think 1.174 says
           that if you do a reasonably conservative analysis or
           if you do something that you think is a bounding
           analysis, you can address uncertainty in that way.
                       CHAIRMAN APOSTOLAKIS:  I thought 1.174
           really looked at all these uncertainties.  How do you
           know something is conservative if you don't understand
           the uncertainties?  Don't you have to understand what
           is uncertain first before you say now what I'm doing
           is conservative?
                       MR. DINSMORE:  It's also that the
           uncertainties in the pipe failure probabilities are
           probably much larger than in the PRA.
                       CHAIRMAN APOSTOLAKIS:  That's also true. 
           So how are these uncertainties handled?
                       MR. DINSMORE:  We handle them by having
           different criteria.  Again this risk level criteria,
           we don't allow them to move risk around between
           systems very much.  The risk level criteria is you
           can't get more than a 10 to the minus 7th increase in
           LERF.  
                       So it's a factor of 10 below the plant
           level criteria.  It's regardless if you only have
           three systems.  Then the plant level is going to be 3
           times 10 to the minus 7th and not 1 times 10 to the
           minus 6th.
                       We've tried to deal with uncertainty by
           putting in this backstop of what you can move and what
           you can't move.  We've actually done it in the BER
           program as well.  We've taken the BER program by
           itself.  They have to apply the same criteria to the
           BER program.  
                       In other words, every system within the
           BER program they cannot increase the CDF by more than
           10 to the minus 7th per year.  For the total BER
           program although it's not really useful, they couldn't
           increase the CDF by 10 to the minus 6th.  Then if they
           put it together with the risk-informed ISI, they have
           to apply those criteria to the total change as well.
                       So there's a couple of steps in the
           criteria.  That's the main --
                       CHAIRMAN APOSTOLAKIS:  What you're saying
           is that they don't need to do the uncertainty analysis
           because the criteria we have established have allowed
           for the uncertainties that you may have which is a new
           interpretation of 1.174.
                       MR. DINSMORE:  We used it in the basic
           programs.
                       CHAIRMAN APOSTOLAKIS:  I understand that
           you have used it.  Okay.  Let's go on.
                       MEMBER ROSEN:  I have a question about
           those few licensees that might come in and just want
           the BER program.  Would they have to come and get
           approval or could they completely avoid any review,
           just do 50.59 and off they go?
                       MR. DINSMORE:  If they don't change the
           ASME Section 11 or any other licensing basis, they
           could.  Yes.  They would not have to come in.  They
           could just do it.  They have to put it in their yearly
           report that they've done it.
                       MEMBER ROSEN:  So the staff would never
           get a chance to talk to them about their PRA and how
           good it is or any of those things.
                       MR. DINSMORE:  No.  But they're required
           to do the same analysis which we've been requiring
           them to do for risk-informed ISI which is to take all
           the comments and everything and document it.  The
           documentation requirements to be maintained onsite are
           the same if they just do the BER as they are if they
           do a risk-informed ISI.  It's just that they don't
           send us anything.
                       MEMBER ROSEN:  That part troubles me quite
           a bit.  At least in the basic risk-informed ISI
           program licensees came in with the EPRI method.  The
           staff reviewed what they wanted to do, looked at their
           PRA and their peer review and had some handle on it. 
           With the small number of licensees I'm told who would
           never have to go through that process, could use 50.59
           and change the break exclusion region piping sample
           size without any staff at all of anything except after
           the fact.
                       MR. DINSMORE:  We do very limited reviews
           of the PRA.  Really all we ask for is who said what
           bad things about your PRA and what did you do about
           them.  We look at what they do.  They usually give a
           reason.  If somebody said you had a bad human error,
           they say we applied these new methodologies and so on.
                       We've occasionally gone back and said
           that's not enough, please give us more.  But that's
           not often.  These guys if they just do the BER,
           they're still going to have to do the same process. 
           If we go out and eventually audit one of these guys
           and they didn't do it or they didn't document it, then
           I'm not sure what we'll do.  But we'll do something.
                       MEMBER LEITCH:  I'm still a little bit
           confused with the approval of this proposal.  What
           determines whether it's 25 percent or 10 percent?
                       MR. DINSMORE:  Well, 25 percent of the
           welds in high safety significant segments have to be
           inspected.  The 10 percent of the welds in medium
           safety significant segments have to be inspected. 
           That's a hold over from the old methodology.
                       MEMBER LEITCH:  So the determination is
           based on whether it's high or medium safety.
                       MR. DINSMORE:  Right.
                       MEMBER LEITCH:  There are no low safety
           significant systems in this set, I guess.
                       MR. DINSMORE:  There are.  You do not have
           to inspect those.
                       MEMBER LEITCH:  Are they inspected now?
                       MR. DINSMORE:  On the BER everything is
           inspected, yes.
                       MEMBER LEITCH:  So there are some where
           there are low safety significant that you would go
           from 100 percent inspection to zero inspection.  Is
           that what I understood you to say?
                       MR. DINSMORE:  That's correct.
                       CHAIRMAN APOSTOLAKIS:  I'm missing
           something here.  Has anybody objected to that?  Why
           are they reluctant to do that when we talk about
           option 2?  The low risk significant SSC still impose
           some requirements.  They are unwilling to lump them
           with non-risk significant.  Yet for pipes it seems
           that they're willing to go to zero.
                       MR. DINSMORE:  Well we did a bounding
           calculation.
                       MR. O'REGON:  Pat O'Regon from EPRI again. 
           We looked at three plants, two sites out of the BER
           application.  We did find some low safety significant
           locations.  But they were as a result of the utility
           conservatively applying the BER rules.  They extended
           piping beyond where they would have had to if they
           held strictly to the SRP requirements.  
                       So that's why they fell as low safety
           significant.  They weren't big pipes that created big
           holes in containments.  As Steve mentioned, the high,
           medium or low are from the EPRI TR ISI, the base case
           methodology where we rank things as high, medium or
           low.  We just kept that consistent when we extended it
           to the BER programs.
                       CHAIRMAN APOSTOLAKIS:  All right.
                       MR. DINSMORE:  The methodology is
           consistent with the EPRI Topical Report.  The
           inconsistencies are the things we've explained to you. 
           The changes to BER program as described in the FSAR
           may be made under 10 CFR 50.59.  Inspections within
           the BER program to change that come from other
           regulatory requirements need to be changed according
           to how you change the other regulatory requirements.
                       MEMBER SHACK:  Anything else?
                       CHAIRMAN APOSTOLAKIS:  No letter.  Right? 
           No request for a letter.
                       MEMBER SHACK:  There's no request for a
           letter.
                       CHAIRMAN APOSTOLAKIS:  So there will never
           be a letter.
                       MEMBER SHACK:  Not unless we decide one. 
           They're not requesting one.  We can discuss whether we
           want to send one.
                       CHAIRMAN APOSTOLAKIS:  Okay.  Anymore
           questions to the lady and the gentleman?
                       MEMBER POWERS:  Well, there's another
           point to be made.  That is it is true enough that
           bypass accidents are risk dominant.  But bypass
           accidents initiated by failure of this particular
           piping don't show up in the PRA at all.  They never
           occur.
                       MEMBER SHACK:  There is one difference
           though.  When we did the original in service risk-
           informed, you could make the argument that you were in
           fact approving safety.  Obviously you might have been
           looking at fewer welds.  But you were looking at the
           more important welds.  So you could make an argument
           that your Delta CDF could have gone down.  In this
           case, it might be a small change but it has to go.
                       MR. DINSMORE:  That's part of the reasons
           that we applied the criteria specifically to the BER
           as well.  That was the best way we could think of to
           deal with that.
                       MEMBER POWERS:  But you still have this
           performance observation.
                       MEMBER SHACK:  Right.
                       CHAIRMAN APOSTOLAKIS:  That's really a
           powerful argument.
                       MEMBER SHACK:  That's incorporated in the
           argument that you're going to apply all that good
           performance to assign most of this stuff to a low
           probability of failure.  You don't want to give them
           double credit for that.  They're going to take that
           credit already.  Again, it's a very small change in
           LERF for perhaps ALARA reasons.
                       CHAIRMAN APOSTOLAKIS:  Isn't there a table
           that the regional methodology has when they have the
           risk significant of a piece of piping?  Then they have
           a susceptibility.  That's where the performance comes.
                       MEMBER SHACK:  That table still applies.
                       CHAIRMAN APOSTOLAKIS:  The performance
           comes there.
                       MEMBER SHACK:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Is this for
           everything or at Westinghouse?
                       MEMBER SHACK:  Yes.  It's everything.
                       MR. DINSMORE:  I wouldn't bring
           Westinghouse to EPRI SE.
                       CHAIRMAN APOSTOLAKIS:  No.  I mean, they
           have something similar I think.
                       MR. DINSMORE:  They have something
           similar, yes.  But you can see here if it's a really
           high consequence in this methodology, it would end up
           in a medium box even with no degradation mechanisms.
                       CHAIRMAN APOSTOLAKIS:  Medium means?
                       MR. DINSMORE:  The 10 percent.
                       CHAIRMAN APOSTOLAKIS:  My concern is
           bigger than what you're doing.  I think that the
           implementation of Regulatory Guide 1.174 has drifted
           away from what the guideline is saying.  It has a lot
           to do with you.  Are there anymore questions for Steve
           and Andrea?  Well, thank you very much.
                       MR. DINSMORE:  Thank you.
                       CHAIRMAN APOSTOLAKIS:  I would ask the
           members to stay here for a few more minutes.  Maybe we
           can discuss things among ourselves.
                       Shall we take a five minute break?  Eight
           minutes.  We don't need transcription anymore.  Thank
           you.  Off the record.
                                   (Whereupon, the above-entitled matter
                       concluded at 6:21 p.m.
Page Last Reviewed/Updated Wednesday, February 12, 2014