Plant Operations and Fire Protection - June 14, 2000

                         UNITED STATES OF AMERICA
                             U.S.N.R.C., Region III
                             801 Warrenville Road
                             Lisle, IL
                             Wednesday, June 14, 2000
               The committee met, pursuant to notice, at 8:30
          DANA A. POWERS, Chairman
          GEORGE APOSTOLAKIS, Vice-Chairman
          JOHN J. BARTON
          MARIO V. BONACA
          ROBERT L. SEALE
          JOHN D. SIEBER
          GRAHAM B. WALLIS.                         P R O C E E D I N G S
                                                      [8:30 a.m.]
               CHAIRMAN BARTON:  Good morning.  The meeting will
     now come to order.  This is a meeting of the ACRS
     Subcommittees on Plant Operations and Fire Protection.
               I am John Barton, Chairman of the Subcommittee on
     Plant Operations, and Jack Sieber is Chairman of the Fire
     Protection Subcommittee.
               ACRS members in attendance are George Apostolakis,
     Dana Powers, Mario Bonaca, Robert Seale, Robert Uhrig, Jack
     Sieber, and Graham Wallis.
               The purpose of this meeting is to discuss
     selective technical components of the plant operations and
     fire protection issues.  The subcommittee will gather
     information, analyze relevant issues and facts, and formally
     proposed positions and actions, as appropriate, for
     deliberation by the full committee.
               Jit Singh is the Cognizant ACRS Staff Engineer for
     this meeting.
               The rules for participation in today's meeting
     have been announced as part of the notice of this meeting
     previously published in the Federal Register on May 24,
               A transcript of the meeting is being kept and will
     be made available as stated in the Federal Register Notice.
               It is requested that speakers first identify
     themselves and speak with sufficient clarity and volume so
     they can be readily heard.
               We have received no written comments from members
     of the public.
               We will now proceed with the meeting, and I call
     upon Mr. Jim Dyer to begin.
               MR. DYER:  Thank you, Mr. Barton.  Good morning. 
     Welcome to Region III.  I'm Jim Dyer, I'm the Regional
     Administrator for the Regional Office.  With me here today
     are Mr. Marc Dapas, who is the Deputy Director of the
     Division of Reactor Projects; Mr. Jack Grobe, who is the
     Division Director, Division of Reactor Safety; and, Mr. Jim
     Caldwell, who is Deputy Regional Administrator.
               Also, throughout the day, we've scheduled an
     agenda, which copies are available for the public over by
     the coffee pot and as you come into the conference room, and
     the various members of the staff will be addressing the
     subcommittees today, based on the information we understand
     that you request, and if you want additional information,
     we're very flexible.  We'll try to get anybody who is here
     on the staff to answer your questions or present anything in
     particular you wish to address.
               I think, going to my first slide, a little
     background about Region III.  This was the recent addition
     to the package, so we'll have copies made.  But just Region
     III encompasses an eight-state area involving, on the
     reactor side, involves 16 operating sites, 24 operating
     reactors, and those are the people sitting at the table
     right now, particularly Mr. Grobe and Mr. Dapas, have the
     principal responsibilities for safety oversight in those
               We also have a Division of Nuclear Materials
     Safety and Division of Resource Management and Assessment.
               Our reactors are relatively close to each other in
     the eight-state region and particularly in the State of
     Illinois, and it makes convenient travel from the Region III
     offices here in Lisle.
               CHAIRMAN BARTON:  Something that can't be said
     about travel to here.
               MR. DYER:  Yes.  Just a little overview about the
     regional organization, and I can make some introductions of
     the folks, the staff.
               What I really want to just focus on is the upper
     half of the chart we provided you here.  For our
     presentation here, what we plan to do is I was going to go
     through the overall regional organization and then allow the
     division directors, particularly the Division of Reactor
     Safety and Division of Reactor Projects, to go into their
     more detailed reviews of their staffing and how we're
     organized to manage our safety responsibilities here in the
               I guess, first of all, we are organized with four
     divisions, three technical divisions; that is Division of
     Resource Management, the Division of Nuclear Materials
     Safety, Cindy Pederson is out today, and we didn't plan on
     her participating.  They do have some responsibility for the
     decommissioning reactors.  So if you have any questions that
     go into that arena, we'll bring somebody down to discuss
     that with you.
               Additionally, Mr. Grobe, Division of Reactor
     Safety, and in my oversight and role, the way I look at the
     way the region operates is somewhat of a matrix organization
     between DRS and DRP.  I view the Division of Reactor Safety
     as the functional experts in the various areas.  So their
     responsibilities are in the operations, engineering, plant
     support areas, radiological protection, fire protection, and
               In those areas, they're responsible for looking at
     specific areas across all of our 16 operating reactor sites. 
     So for the case of operator licensing, they're responsible
     for overviewing of the operator licensing and operations
     inspections, team inspections, and calibrating safety
     assessment at all 16 sites across that one functional area.
               Then separately from that is the Division of
     Reactor Projects, which is organized by reactor assignments
     to the various sites, under Mr. Dapas and Mr. Grant, and
     these are organized more in lines with projects.
               They're our generalist inspectors and basically
     they are responsible for everything that goes on at that
     site.  So within the region, if a particular event occurs or
     a particular issue comes up at a site, there should be two
     points of contact that have cognizance over that area.
               One, the DRP point of contact from a generalist
     view, because it affects that site and you can integrate the
     impact of the assessment across all the functions at that
     site and put it in that proper context.
               The second would be from the functional area
     review and taking a look at, from Mr. Grove's DRS point, how
     does this -- what are the lessons learned, how are we
     consistent across all of our 16 sites in the way we're
     treating that area.
               So that's the general oversight of how the region
     is orchestrated and integrated.  In particular, the key
     aspect of regional activities that establishes and
     identifies the issues we're going to follow up is at 8:15
     every morning, we conduct a review of plant events and plant
     status.  Normally, it's in this room.  This morning it was
     taking place in our other conference room down the hall on
     the third floor.
               But in that meeting, we will go through any
     reported events for the night and any emerging issues that
     come from the sites, from the resident inspectors, we bring
     them up and put them on the table and discuss what is our
     response going to be to those activities.
               CHAIRMAN BARTON:  So is this organizational
     structure you described pretty similar in all four regions?
               MR. DYER:  It's identical in all four regions. 
     It's just my concept of operations, if you would, as to how
     they -- other regions may decide to do things differently. 
     We all have morning meetings, but we all have some
     differences as to how we would approach a morning event or
     an emerging issues.
               CHAIRMAN BARTON:  Thank you.
               MR. DYER:  I think a little bit about the Regional
     Administrator staff; in particular, this is also similar to
     all the regions.  Of most interest to you is probably our
     area of enforcement and allegations.  If there are any
     questions that would come up regarding -- by the
     subcommittees today.  Mr. Brent Clayton is here this morning
     and he is available, if you have any questions, or he is
     going to spend some time this morning and we'll bring him
     back or we'll get a member of his staff, if there are any
     questions about the allegations or the enforcement
     activities that we have going on here in the region.
               Additionally, we also have an Office of
     Investigations, which is similar in all regions, a Public
     Affairs staff, and then a Regional State Liaison Officer. 
     Mr. Roland Lickus had to take his son to a doctor's
     appointment this morning.  He is going to come in a little
     bit later.
               I think what is unique to Region III is our
     relationship with the Illinois Department of Nuclear Safety. 
     I'm convinced there is no state that has the extent of
     nuclear oversight that the Illinois Department of Nuclear
     Safety has with their resident inspectors at all the six
     sites that are operating in Illinois and their extensive
     emergency planning and incident response capabilities.
               If you care to discuss our relationship or how we
     interact with Illinois Department of Nuclear Safety, Roland
     is probably the best person to talk to with that.
               Additionally, we have a regional counsel, who is
     in our -- spends a lot of his time involved with reactor
     enforcement cases, and particularly, now that recently we
     have had a lot of discrimination issues that have taken a
     lot of our time and have been a challenge.
               So that's the basic overview of our organization
     here, from a regional administrator's level.  I guess I
     would ask if there are any questions.
               DR. POWERS:  I guess one thing that has just
     emerged for the committee is we're anticipating getting a
     power upgrade application from Guianardo, rather substantial
     one.  So any thoughts you have on that power upgrade that
     you think we ought to know about would be useful, if there
     is a chance during the day.
               MR. DYER:  Okay.  You're going to have the senior
     reactor analysts later on the day and I know they may be
     more informed.  I know Mike Parker was out there with
     Research and did some walk-downs.
     DR. POWERS:  I think we would be interested in thoughts
     about are there synergistic effects associated with going to
     power upgrades and high burn-up fuels in an aging plant. 
     Things like that.  It's the first of what we see of many
     rather substantial power upgrades.  I hesitate to quote the
     exact amount, but it's about 15 percent power up rate, which
     would mean they're about 20 percent of what they had in the
               MR. DYER:  We can certainly comment on the impact
     that has on the inspection program.  But the technical
     viability, NRR reviewers get involved.
               DR. POWERS:  Sure.  And insights that you have
     that are peculiar to you that we would be most interested
               MR. DYER:  And Commonwealth Edison is also looking
     at what I consider to be rather substantial power up rates
     for both the Quad Cities and the Dresden stations.
               DR. POWERS:  I think there's going to be a covey
     of them coming in.
               DR. SIEBER:  Speaking of coveys.  You've had the
     privilege or honor or whatever of not being involved in the
     first sub-group of license renewal activities and perhaps it
     would be more appropriate to address this question for
     Regions I or II, but I don see any of them here.
               How do you anticipate a license renewal
     application would impact the regional activities?
               MR. DYER:  Quite frankly, I don't think it is
     going to impact.  We'd love to have one.  Right now, we
     don't have any takers.  I think Commonwealth Edison is --
     both Commonwealth Edison and the management company, which
     formed Duane Arnold, Monticello and that, are both talking
     about it, but --
               DR. SIEBER:  No one has committed yet.
               MR. DYER:  Nobody has committed and I think
     they're at least six months away from doing that.  I know
     that we really haven't taken a look at that for license
               MR. GROBE:  We can talk in a little bit more
     detail when we get into the details of how my division
               MR. DAPAS:  I think, in summary, though, it's
     probably relatively transparent to the new inspection
               DR. SIEBER:  I had one other question.  Are any of
     the people out here representing the public as opposed to
     members of your staff?
               MR. DYER:  They are all our staff.
               DR. SIEBER:  Okay.
               MR. DYER:  All of which I believe may be giving
     you presentations later today.
               DR. SIEBER:  Okay.  I was just curious.
               MR. DYER:  Okay.  Next slide, please.  Following
     up, I think that a few of the activities that we've recently
     completed or are in the process of completing that may
     provide some areas for later discussions, of course, is some
     of our more recent regional accomplishments.
               We did implement the pilot program at both Quad
     Cities and Prairie Island.  I think in particular, it was a
     unique relationship, particular with the Quad Cities sites,
     in that it involved integrating the Illinois Department of
     Nuclear Safety into this program.
               We conducted the training here in this room, in
     fact, and brought all the Illinois Department of Nuclear
     Safety folks in to cross-train them.  Secondly, Quad Cities
     had some unique performance indicator verification issues
     and it really opened up, I think for the industry and the
     NRC, an understanding as to just how many different ways you
     can calculate performance indicators.
               And as a result of that, Commonwealth Edison
     really took the lead, I believe, for the industry to
     solidify and come up with a common way of doing it.
               I think Oliver Kingly, at our last review, made
     the comment that he says he never realized that they had
     seven different ways of calculating EFTY within the
     Commonwealth organization, and depending on which
     organization you asked, as to how much reactor burn they've
     done, they have a different way of calculating it.
               So it was those kinds of things, and the same
     thing with how they recorded availability.  It was
               DR. POWERS:  The NRC seems to have about seven
     different ways of calculating availability, depending on
     what rule you go to.
               MR. DYER:  We have transitioned to the new
     oversight program at all our sites, with the exception of
     D.C. Cook.  I would like to add that while you were in
     transit yesterday, I signed the D.C. Cook 0350 closure
     letter.  So D.C. Cook is -- the closeout has been done and
     now they're in the process of heating up and testing their
     systems in mode three and trying to wrestle with a problem
     with the turbine-driven aux feedwater pump this morning.
               But they will be the final plant to transition
     after the restart of Unit 1, and that will be later this
               CHAIRMAN BARTON:  When do you see them fully under
     the new oversight process?
               MR. DYER:  Jack probably has the best -- I was
     asked that at the Commission meeting, and I would say about
     six months after startup.
               MR. GROBE:  One of the things that we have to
     consider is how effective the performance indicators are
     before we transition them back to the regular oversight
     program.  That's been shut down for almost three years.  So
     there is no valid performance indicator data, with the
     exception of maybe in the health physics and emergency
     planning areas.
               So we'll be looking at the performance indicator
     data and turn the plant back to the routine inspection
     program as soon as we feel comfortable that the way the
     program is structured, we can effectively monitor the plant
               CHAIRMAN BARTON:  Thank you.
               MR. DYER:  We completed our PPR reviews for the
     end of cycle on the pilot plants and also did some mid-cycle
     reviews for the other plants, just to get them going in.  Of
     note, as a result of the review, we, believe, are the only
     region, and we have two yellow performance indicators within
     the region, Kewaunee, alert notification system and siren
     system is in a yellow status, and we completed the 95-002
     inspection, which is the supplemental inspection at
               Additionally, Quad Cities, the HPCI system went
     into a yellow status because of availability on an auxiliary
     oil pump, and we can discuss those.  We have not done any
     supplemental inspections or held the public meetings yet
     with respect to the Quad Cities plants.  That was just a
     recent issue.
               Again, implementing the revised enforcement
     process, and if there are any questions, Brent Clayton is
     available in that arena.
               Some of the areas -- one of the areas that's been
     a major shift here in the region and a major focus is -- I
     don't know if you know of the RIT system, which is our cost
     accounting system, which is used as the basis to budget our
     resources.  We have found that we have not been accurately
     recording our costs and things that we thought were going in
     one of the cost bins, such as follow-up inspections or plant
     assessment, were, in fact, going in a completely different
     bin, some of our SRA training time.
               So we've wrestled with our cost accounting system
     and it's clear that under the new budget constraints and
     that, that we are going to have to become better managers of
     our resources and understand what our budget resources are
     and what the plans are that we're doing.
               DR. SIEBER:  Does that affect the licensee
               MR. DYER:  It turns out that licensee billing was
     about the only thing we did right, as far as the inspection. 
     We were very good with inspection reports, but there's a lot
     of non-direct costs.  That would be plant assessments,
     follow-up on technical issues, things like that that we were
     getting coded to other administrative duties and things like
               So it sort of skewed our model and didn't capture
     accurately what the costs of how the region did business,
     and we've subsequently gone back and cleaned it up.  So
     hopefully for the rest of this fiscal year, we should.
               But fee billing was it -- the inspection efforts,
     the direct inspection, as well as prep and doc for the
     inspection reports was pretty much -- that was done well.
               DR. SIEBER:  Is it fair to say that the net effect
     of all of this was to tend to put more time or more pressure
     on the administrative rather than the programmatic side?
               MR. DYER:  Yes.  The real impact was on -- we
     receive resources for plant assessment.  By and large, those
     were under-billed, those resources, and administrative was
               DR. SIEBER:  That can be embarrassing in the long
               MR. DYER:  As you'll find out later on, we've had
     -- when I first got here a year and a half ago, we had, I
     believe, six plants that were receiving enhanced oversight
     under 0350. Every one of the managers at this table was
     overseeing either Commonwealth Edison or at least one or two
     of the facilities that were preparing to restart.
               And when the budgets -- and the staff was
     similarly supporting all those activities.  And when the
     cost data came back and we were budgeted six and a half FTE
     for plant assessment, and we spent two and a half, which
     just didn't make sense.
               So we knew something was up.  Everybody was
     spending all their time in 0350 panels and oversight and
     when the cost data -- that's when we started looking as to
     why we did it and what it was was we had some old cost codes
     that we had been using for years and they were translating
     to some sort of different -- so it's caused a -- it's been a
     rather substantial effort.
               Again, we made also a focus on improving our
     communications, enhancing them, particularly to get the
     implementation of the new oversight program.  There's more
     rumors flying around about the program, as any time you go
     through a significant change.
               We've held monthly meetings, enhanced meetings,
     with the divisions and have done some very good training.  I
     think it's paying off now.  I think the folks at the working
     level that are actually leading the change and the
     transition and they are the ones that have the best concept
     of what's going on at the plants.
               CHAIRMAN BARTON:  I want to ask you a question.
               MR. DYER:  Sure.
               CHAIRMAN BARTON:  Regarding that.  If I were a
     "good plant" in this region, as defined by you folk, now
     under the new oversight program, with the baseline
     inspection program, would I be receiving more or less
     inspection hours?
               MR. DYER:  Absolutely more.  I have a slide.  I
     can diverge from that, if you want to.
               CHAIRMAN BARTON:  We just heard that yesterday
     loud and clear as a complaint.  So we wondered whether it
     was true or whether we were just hearing a story.
               MR. GROBE:  We are going to talk about that
     specific aspect in some more detail.
               CHAIRMAN BARTON:  Okay.  Good.
               DR. POWERS:  The question has some things to it in
     that it may be true now, but it is going to be true once
     you're in a more steady-state on the inspection program.
               MR. DYER:  Right.  We are probably the extreme
     region for that concept, but --
               MR. GROBE:  The reason for that is that under the
     old program, we had some flexibilities, and we'll get into
     that in detail.  We had a number of problem plants and I
     don't remember the total numbers, but it was upward, over a
     period of years, 20,000 inspection hours at D.C. Cook,
     similar at Clinton and other sites.
               So a plant like Davis-Besse, which was one of our
     better performers, under the flexibility of the old program,
     got significantly fewer hours.
               The baseline, the risk-informed baseline is
     intended to establish not a ceiling, but a floor, and that
     floor is higher than what Davis-Besse got in the past.
               MR. DAPAS:  And we'll explain why there was that
     flexibility under the old program and relative to the new
               DR. POWERS:  I mean, I guess the question that
     comes to mind is why shouldn't there be that flexibility.  I
     mean, if you're going to have problem plants, and you are on
     occasion going to have those, why shouldn't you put your
     resources where the squeaky wheel is and let the guys that
     are doing a pretty good job --
               MR. DYER:  Well, I think it's a little more
     complex than that.  We're going to get into it.  We have
     about an hour set aside for this.
               And let me just close out.  Part of the issue is
     that -- I'm quite pleased and, Jack, you couldn't wipe the
     smile off his face, but the fact that yesterday was the
     final closeout of our 0350 process and our formal restart
     0350 process for D.C. Cook is -- that has been a -- that is
     a significant impact on the region and that's the final one.
               As I said when I got here, we were doing it with
     LaSalle, Quad Cities had just started up, we had Clinton, we
     had Cook, Peach Bottom, Point Beach wasn't that far away
     from restart.  So there was a number of -- we have literally
     been focusing from plant to plant.
               And last year at this time, the great fear was
     that if Clinton kept delaying and LaSalle kept moving their
     schedule up, it looked like both of them were going to
     restart within a week of each other.  They subsequently
     restarted about a month apart.  So that was a great relief,
     because a region literally cannot handle two restarts
     simultaneously of problem plants coming up.
               So now we're poised to do the D.C. Cook restart
     and we are getting resources from all the other regions in
     order to support the final closeout of the inspections, as
     well as the actual startup.
               CHAIRMAN BARTON:  But with Cook coming back, that
     will only help the stability question in this area.
               MR. DYER:  I believe it actually helps more the
     northeast, because it's the tie lines.  When Commonwealth
     Edison came back, Chicago was flush and the last time I
     talked to Oliver Kingsley, it looks like they could actually
     have excess power.  What they want to do is it get to the
     northeast, where there's a need for power, and the tie has
     been right there at D.C. Cook.  They have been able to route
     power through that intertie out of the main grid.
               So they've actually been wheeling power south and
     then back up.
               DR. SIEBER:  Or it would go through Canada.
               MR. DYER:  Right.
               DR. SIEBER:  To what extent does headquarters hold
     the region accountable when a plant -- I'll speak louder. 
     To what extent does headquarters hold the region responsible
     or accountable if a plant emerges as a problem plant?
               MR. DYER:  Well, you have to take a look at how
     did it occur and it's more you do a root cause analysis, if
     it's caused by an event; you know, should we have found it
     earlier, and done that.
               I don't think it's any kind of fingerpointing or
     blaming as a result of that, but it always causes you to
     reflect.  And I can say it's not only just the region that
     has the problem plant.
               When the Commonwealth Edison problems came up and
     the Cook problems came up, and Millstone, even when I was in
     Region IV as Deputy Regional Administrator, we were all
     looking could that happen here.  It's a general --
               DR. SIEBER:  Do you think the oversight process
     will help you identify precursors to problem plant issues
     more so than the old inspection program?
               MR. DYER:  I don't that the oversight process will
     help the NRC identify it.  I think the deregulation is going
     to force the commercial nuclear industry to take a greater
     role in fixing, and the cost, the main cost in production,
     those areas, the pressures that they now feel are far more
     than what the NRC used to put on them.
     They have to be a much more demanding manager now of their
     plants in order to accomplish the shorter outages, in order
     to bless the less than one reactor trip per year, on an
     average now, in the industry.
               That's not NRC-driven.  That's economics-driven,
     in my mind.  And no matter how much I, as a regulator,
     challenge the licensee to improve performance, it's going to
     cost them a couple hundred thousand dollars a day now when a
     plant goes off-line, that's making the difference.
               So I think our critical focus is shifting to make
     sure that they follow the prescribed processes and that
     they're playing by the rules, if you would; that when a
     system is inoperable, they declare inoperable and do the
     right thing, as opposed to how are they fixing it.  That's
     the emphasis.
               MR. GROBE:  The new inspection program is more
     indicative than it is predictive and that's one of the
     concerns that we have in how we implement this, to retain
     the ability to identify the early precursors of more
     significant problems.
               We're going to get into that in a lot of detail
     with lessons learned on the new inspection program to date.
               DR. POWERS:  And if you find routes to prediction
     under the new inspection program, we're going to be real
     interested, because it really is an indicative program.
               DR. SIEBER:  One more short question.  With all
     the emphasis on cost-cutting and economical production, do
     you see things like the plant material condition going up or
     down, or programs being eliminated or consolidated to the
     detriment of the whole program, or other issues that are not
     being attended to that otherwise, in a more generous
     economic situation, might be attended to?
               MR. DYER:  I guess from my perspective, I've seen
     an investment in the plant.  The thought of looking at
     extending the life cycle, the prospects of doing that and
     whatever they run, they've got to run well.  Those are the
     key things that we've seen.
               Particularly, what we saw was a total focus, I
     believe, from some of our plants is when they were shut down
     under the 0350 process and trying to get restart, they took
     a focus away from operations and they were focused on
     getting the plant fixed, whether it was reconstituting the
     design basis, modifying the plant to fix a long-term
     problem, or doing whatever is necessary to get their
     procedures and infrastructure effective.
               There had been a lack of focus on maintaining the
     operating crews and maintaining the plant in an operating
     status net.  So now that we've seen the plants once they
     start up, there has been a shift toward that operational
     safety focus, an increase in number of licensed operators.
               In Region III, and I think Jack probably has a
     better handle on the budget numbers than I do, but I think
     we were looking at typically we were running between 30 and
     50 exams a year and once Cook, Clinton and ComEd got up and
     running, in the past year and a half, two years, there now
     -- our number of licenses are upwards of 160, demand for us
     to give 160 licenses.
               So it's literally tripled our workload in a short
     period of time.  That's put a pressure on the region to get
     a lot of qualified license examiners and borrow them from
     headquarters and management, which is what Jack has done,
     but that kind of a ramp rate, if you would, has put a severe
     strain on the regional resources for that program.
               But that's what we're seeing now, is an enhanced
     focus on operations and an investment in the plant.  So I
     think almost all the plants are --
               DR. POWERS:  I was just going to comment in
     response to your question about material condition.  I think
     under the new program, when you look at unavailability,
     performance indicators, if the licensees are maintaining a
     material condition, you would expect to see that manifested
     in transients caused by equipment problems and challenges to
     the operator.
               So I think the new program has carved out a role
     of ensuring that material condition is being maintained or
     at least flagging to us that there are problems in that
     area, and then we would go in and look at the licensees'
     root cause evaluation and corrective actions as part of our
     supplemental inspection of a particular performance
     indicator threshold, for like system unavailability.
               MR. GROBE:  Jim and Marc are focusing primarily on
     reactor operations and those issues that directly make
     money.  In some of the peripheries, we've seen some
     problems; for example, in the security and safeguards area. 
     Commonwealth Edison substantially changed their approach to
     event response and protecting the plant from a physical
     threat and we just recently completed what is referred to
     our OSRE, operational safety response evaluation, at Quad
     Cities and they performed poorly.
               They changed the strategy also at LaSalle and
     Braidwood, significantly reducing the number of armed
     responders, for example.  And we have exercises there later
     this month.
               DR. SIEBER:  So that was an issue involving the
     security organization as opposed to operation involvement in
               MR. GROBE:  And I think Jim's point on the
     financial demands is really key.  Those things that can
     produce power and ensure equipment reliability are getting a
     lot of attention.
               DR. POWERS:  I think we can say the same thing in
     fire protection, because it doesn't generate kilowatts, it
     may be getting less attention than some of the other things,
     as well.
               DR. SEALE:  Not very well.
               DR. SIEBER:  Well, this is apparent or has been
     apparent for some years.  I've worked with LaSalle for a
     couple of years and they had a lot of fire protection work
     orders that had aged substantially and I see the same thing
     on division valves at other sites and people say, well, as
     long as the valve is open, we're okay, but if you rupture
     the main, you may put the your whole system out, because you
     can't isolate.
               So I think that that often needs attention,
     because it somehow jumps outside the risk-significant
     portions of the plant, which are the CAT-1, structures,
     systems and components.
               MR. DYER:  One other, on the same spin, I was just
     thinking, you know, in the case of Clinton, was one of the
     plants that was really run on a shoestring.  It was a single
     unit utility.  I think we have seen a significant commitment
     of resources and improvement and a change over there,
     particularly since Amergen took over and purchased the site,
     and it was shortly thereafter that they came out with a
     business plan that included looking at license renewal as
     opposed to the mentality when it was Illinois Power, which
     was get the plant restarted itself.
               So it was do what was necessary to restart the
     plant, which it did not include training new operators.
               DR. WALLIS:  Do you find that consolidation of
     plants under single owners is helpful then, in general?
               MR. DYER:  We've had limited experience with that. 
     The Amergen is the first one under, and now the management
     company is just trying to formulate and they really haven't
     had an impact yet.
               Commonwealth Edison, we've had a seesaw
     relationship with over the years.  Right now, it's riding a
     wave up and it's doing better.  So I'm waiting to see.
               MR. CALDWELL:  I think the real answer to your
     question, though, is it's going to be case specific.  I
     don't think you can make a generic statement about how
     deregulation is going to affect all the plants.  The
     single-unit sites, if they don't have a lot of resources, it
     may have a major impact.  These sites that are now being
     taken over by large companies, they can't afford to have the
     kind of shutdowns that we've seen in the past, the
     multi-year shutdowns.
               So they're going to have to focus on making sure
     the plants are properly maintained.  So it's going to be up
     to us to look at the different facilities and the different
     situations they're in and to try and understand it.  But I
     don't think you can make a statement across the board that
     it's going to have the same impact.
               MR. DAPAS:  That's one of the things the agency is
     looking at is industry consolidation and there is a working
     group that I'm involved in to understand what changes may be
     necessary in certain program areas as a result of industry
               DR. SIEBER:  I don't want to ask too many
     questions and get you off schedule.
               MR. DYER:  I think I've blown my schedule.
               DR. SIEBER:  I'm sorry.
               DR. POWERS:  We have a tradition of doing that.
               MR. DYER:  Yes.  But what I was going to do is now
     turn the meeting over to Jack Grobe and Mark Dapas and let
     them got into more of the details of how the DRS and DRP
     organization goes, consistent with our program.
               MR. GROBE:  We had some donuts delivered and, Dr.
     Barton, do you want to just take three minutes?
               CHAIRMAN BARTON:  No, we're behind schedule.  If
     you want a donut, get up and help yourself.
               MR. GROBE:  Excellent.  We've laid out an agenda
     that I think that I think, we had coordinated with Jit, that
     hopefully meets your needs.  We've got about 65 slides to go
     through, which our ability to do that is probably limited,
     but our goal is to make sure that we answer all your
               So I'm going to try to be a little bit of a
     gatekeeper on the clock and move us along as we go.
               But the first thing we're going to do is talk a
     little bit about how we're structured, how we're
     implementing the new program and some lessons learned on the
     new program, and then invite Sonia Burgess up to talk about
     our senior reactor analyst program.  She's one of my SRAs.
               MR. DAPAS:  I thought I'd start out with kind of a
     broad overview of our geographic responsibilities.  You can
     use the slides of you can go through the handouts we
     provided, whichever is easiest for you.
               But we are responsible for 24 operating reactors
     at 16 sites, and that consists of 13 pressurized water
     reactors and 11 boiling water reactors.  As Jim said, our
     responsibility encompasses an eight-state area.  We've got
     six sites in Illinois, two sites in Wisconsin, three sites
     in Michigan, two sites in Minnesota, two sites in Ohio, and
     one site in Iowa.
               And as Mr. Dyer mentioned, it's relatively easy to
     travel to any site.  We can get to Prairie Island and
     Monticello, which is near Minneapolis-St. Paul, Twin Cities
     area, in a day; same thing with Duane Arnold, near Cedar
     Rapids, Iowa.  So that doesn't present the challenge that it
     does to some of the other regions in terms of being able to
     get to the sites.
               The Division of Reactor Projects, or DRP, has
     roughly 75 professional and administrative staff.  Most of
     the inspection staff in DRP has an engineering background or
     a technical science degree.  So we have a fairly
     professional staff.
               And we've organized the branches to provide
     additional oversight to D.C. Cook; D.C. Cook, of course,
     being an agency-focused plant.  We've got one branch
     dedicated to Cook, which results in the other five branches
     have three sites apiece, and we thought that was appropriate
     considering all the inspection activities and coordination
     of our technical issue resolution that's associated with
     restart preparations by the licensee.  And I'll go through
     more specifically how we're organized in a minute.
               Next slide, please.  I thought I would talk a
     little about the functional responsibilities for the
     Division of Reactor Projects.  One of the most important
     functions we have is inspection program management.  DRP is
     the clearinghouse for the inspection program.  We're sort of
     a gatekeeper for regulatory activities associated with the
     specific sites.  We manage the site-specific inspection
               I expect the branches to be cognizant of all NRC
     activities.  That means specialist inspections that are
     ongoing by the Division of Reactor Safety Inspectors, DRS,
     allegations, status of enforcement actions.  The branches
     are knowledgeable of all the inspection findings,
     performance indicator information, and any outstanding
     inspection follow-up items.   
               So all regulatory activities and issues that
     impact on inspection responsibility are pretty much
     processed through DRP.
               We maintain a continuous on-site inspection. 
     Specific inspection activities are carved out for the
     residents on a periodic basis, and that's, of course, within
     the context of the new baseline inspection program.
               But there is a premium placed on that on-site
     inspection and the ability to observe activities firsthand.
               DR. WALLIS:  Excuse me.  Continuous to me means it
     goes on all the time.  That can't quite possible.
               MR. DAPAS:  We don't have 24-hour coverage. 
     Continuous meaning that we have a day-to-day presence.
               DR. WALLIS:  That everyday there is a presence.
               MR. DAPAS:  Yes, correct.  Daily on-site
     inspection would probably be more appropriate.
               MR. CALDWELL:  They also, they live in the general
     area and are available to go in for event response, or if
     there is a particular issue.
               DR. SIEBER:  Do you have any problems filling
     those jobs, are you shorthanded?
               MR. DAPAS:  I was going to talk a little about
     some of the staffing challenges we have in maintaining the
     resident positions fully staffed and give you an idea of
     where we're at.
               DR. SIEBER:  When you do that, you can also talk
     about rotation, there is a certain rotation that's supposed
     to occur that sometimes doesn't because of lack of
               MR. DAPAS:  I was going to comment on that
     specific item.
               DR. SEALE:  I would also like to hear about
     growing those positions in the sense that the revised
     inspection process, the interest in risk-informed regulation
     and so forth seem to be adding to the challenges that the
     inspectors face, having to operate in a slightly different
     environment, knowing when to inquire of the risk analysts
     about appropriate information concerning the operations at
     the moment and so on.
               I would be interested in how you are growing those
     people in that sense.
               MR. DAPAS:  I think we will touch upon that.  If
     we don't, point that out, please.  The residents are the
     focal point for agency interface with the licensee.  Of
     course, there's the routine exit meetings and where the
     resident staffs discuss their specific inspection results.
               They maintain cognizance of the results of any DRS
     inspections.  When the licensee identifies any type of
     degraded equipment, which would result in like a technical
     specification limiting condition or LCO entry, that's
     communicated to the resident inspector and reportable events
     are communicated to the residents, any notice of enforcement
     discretion requests that are developing.
               Basically, the resident is the information conduit
     and that includes licensing issues.  Certainly, there's
     discussions between the NRR project manager and the specific
     licensee representatives involved in licensing activities,
     but the residents are cut in on that and they inform the
     region of outstanding licensing issues.
               So they're clearly the focal point for that
     communication between the NRC and the licensee, which
     underscores our goal of assigning mature, professional
     individuals to the sites, because they are the eyes and ears
     of the agency, in many regards.
               Also, the resident staff serves as first
     responders for incident response, as Jim Dyer mentioned and
     Jim Caldwell.  The resident inspector would respond to the
     control room and the senior resident inspector would respond
     to the technical support center for any type of emergency
     event declaration, like an unusual event or an alert. 
     Anytime the licensee mans their emergency plan.
               And they provide NRC management with information
     to determine the appropriate agency response, monitoring,
     standby, or initial activation, and they ensure the licensee
     is following their emergency operating procedures and
     actions for each emergency event classification.
               One of the central things that the residents
     communicate early on to regional management and headquarters
     management is, is the plant in a safe condition, what are
     the licensee concerns, what are the principal areas that
     they're focusing on.  So that first communication is very
     important in terms of the agency responding appropriately.
               Next slide, please.  I thought it would be
     informative just to discuss briefly some of the specific
     inspection activities that a typical resident encounters. 
     There is clearly a focus on operations.  We target
     activities where the plant is configured with the greatest
     risk impact.  As an example, if the licensee is going to
     perform an integrated test of the emergency core cooling
     systems, that involves a lot of coordination between the
     operators, both in the control room and in the plant, valve
     and switch manipulations.
               That may be a risk-significant evolution that we
     would want the residents to observe.
               Event follow-up, as I mentioned before, that could
     be a reactor trip, a partial loss of off-site power, plant
     transient, any particular event that challenges the operator
     response and the residents are there to follow-up on that.
               DR. POWERS:  Let me legitimately make a point
     about this response to any event that occurs, that the
     resident has to do.  He becomes literally the eyes and ears
     in those cases, at least for the first hour or two, he is
     the eyes and ears of the agency.
               But one would hope that that's an activity that he
     doesn't get to practice very often.  How does he practice? 
     How does he develop skill in that area?
               MR. DAPAS:  We will talk about the detailed
     qualification program that a resident goes through, but
     there's a lot of mentoring.  The senior resident inspectors
     have experience in event response.  There's, of course,
     simulator courses that the resident staff takes in
     Chattanooga, where the plant is put through -- the simulator
     is run through different emergency transients, and the
     residents clearly understand what EOP should be implemented,
     emergency operating procedures.
               And there is a specific procedure for event
     follow-up, which gives the inspectors guidance of particular
     things that they should be looking for.  And one of the
     things that I think is effective when we have our oral
     qualification board, which we'll talk more about, it's not
     uncommon to ask a question, you'll be walking into the
     control room and there's this, this and this going on, what
     areas are you focused on, what information are you trying to
               So we try, to the extent we can, to prepare the
     residents to be able to provide that event response and
     communicate the information.
               MR. GROBE:  The other thing is the resident
     inspectors in Region III, the folks we've tried to place out
     there, are experienced and, as Marc, said, mature people,
     extensive experience as system test engineers, integrated
     test engineers, folks that had come through the Division of
     Reactor Safety.  For the operator licensing program,
     operator licensing folks have extensive knowledge and
     appreciation of what's going on in the plant.
               And within a very short period of time,
     approximately a half an hour, they're going to have a ton of
     support from the regional office.
               DR. POWERS:  Yes.  But it's really that they're
     working on their own and having to use their own judgment. 
     Of course, nothing schools judgment better than experience. 
     And the number of events we have, I mean, we just don't have
     very many.
               So experience -- it did remind me of the
     simulators in Chattanooga.  That of course, would be a good
     thing, having a proceduralized thing, that's a very good
               MR. GROBE:  And that's the primary focus of our
     requal training.  They get extensive systems training
     initially, but the requal is primarily focused on the
               DR. SIEBER:  And it's been my experience, also,
     that resident inspectors participate in licensing drills. 
     They are either observers or actual players, and that's
     really good experience for them, because they not only learn
     what the licensee is supposed to do, but they see how the
     licensees act and how to communicate with them.
               MR. GROBE:  When we get into the new inspection
     program, you're going to see that we have less flexibility
     to do that.
               DR. SEALE:  You can't essentially tag along when a
     plant operator is going through -- or a plant operations
     team is going through a simulator exercise with a
     plant-specific simulators.
               Do your inspectors get to, if you will, watch this
     and ask themselves what their role would be as they go
     through that?
               MR. GROBE:  Once every two years, we have a
     requalification inspection, where we observe the licensees'
     simulator examinations, and a few years ago, we made a
     decision, for that exact purpose, to include one of the
     residents on the requal team, and we try to do that whenever
     we can.
               But we wouldn't be in a mode of interfacing with
     the people that are in the midst of an examination.
               DR. SEALE:  I understand that's a very careful
     line there.
               MR. GROBE:  It gets the operators into the
               DR. SEALE:  Exactly.
               MR. GROBE:  And it gets the resident inspectors
     into the simulator on some periodic basis.  The one area
     that I'm concerned about, and we're looking at trying to do
     something about, is that we have very limited training on
     CMG, the severe accident management guidelines.  All the
     licensees that had training on the CMG materials and our
     emergency responders have limited training in that area, and
     we're looking at trying to do something to familiarize the
     staff and management on the severe accident management.
               MR. DAPAS:  When I was talking about event, I
     talked about it in the context of a significant event.  Of
     course, event can cover a broad spectrum, certainly.
               One of things that we engulf with our event
     response procedure is an assessment of the risk associated
     with that particular event to determine should we initiate a
     special inspection, and that's pretty clearly defined.
               DR. APOSTOLAKIS:  How do you do this?  How do you
     assess the risk?
               MR. DAPAS:  We look at conditional core damage
     probability.  We look at what was the particular equipment
     configuration, mitigative systems, et cetera, and what is
     the risk associated with that challenge.
               Obviously, when you have an event, if it's a loss
     of off-site power, reactor scram, you had the initiating
     event, now what's the consequence of that, what systems were
               DR. APOSTOLAKIS:  So for each unit, you have a
               MR. GROBE:  No.  We have very limited tools
     available to the residents, broad guidelines on what are the
     most risk-significant systems and things of that nature.
               MR. DAPAS:  But it's different than what we did
     have in the past, which was more deterministic.  I think as
     a result of the Indian Point 2 event, we incorporated more
     risk perspectives into our event response procedure.
               DR. POWERS:  I'm not sure we can get into it right
     in this presentation, but one thing that you might comment
     on, we have discussed this issue of tools, risk tools
     available to the residents and the wisdom of whether they
     really want tools, to have more tools or not, because
     they've got a full-time job as it is, that's maybe adequate
     if they have risk information resources available to them,
     the role that normally is played by your senior reactor
               But asking a guy a question and being able to look
     it up yourself are two different things.  So this balance
     between information directly available to them and resources
     available to them is interesting.  I don't know how you make
     the decisions.  If you have thoughts on that, it would be
     interesting to hear.
               MR. GROBE:  Truly, I don't believe we want the
     residents doing risk analysis in an event response.  They
     need to be aware of what's going on at the plant, what are
     the precursors to further severity of the event, making sure
     that the licensee is focusing in the right areas and
     providing information to us.  
               But both of your risk analysts are on-call.  We
     got into this just recently with an event.  It's difficult
     to provide risk analysis on any sort of short timeframe. 
     We're trying to develop a concept where within a few hours,
     they can provide the agency some risk insight, but not any
     sort of analytical or very technically defensible risk
     analysis on a period of a couple of hours, to determine
     whether or not that could provide further insight on the
     extent of the team that we should send out or the type of
     response the agency should take.
               Within a matter of 24 hours, we should be able to
     provide some fairly defensible risk analysis of what's
               From a responder point of view, 24 hours is not
     terribly useful.  So there is an interesting conundrum
               DR. POWER:  That's really incredibly useful
     information there, because I'm wrestling with how fast we
     should be able to do risk information and I think you've
     given me a key.  Clearly 24 hours is too long.  Now, what is
     the appropriate time?  It sounds to me like an hour or two
     is the kind of rate you'd really like to be able to do
     things in.
               MR. CALDWELL:  Let me clarify something here. 
     What Jack is talking about is the type of follow-up event
     response we would conduct.  The inspector, the resident is
     still going to go to the site on an event response and
     they're in the mode of observation.  They'll go to the
     control room, they'll observe operator actions, they'll
     observe plant conditions, and that information will be fed
     back to us.
               But they will not be constrained by some sort of
     probabilistic review.  But our follow-up event response
     would -- our special inspection or AIT or whatever we decide
     we might need will depend on the risk of the event itself.
               MR. DYER:  I think the residents need to have a
     general understanding of the risk models, what are the
     vulnerabilities at the plant.  As they go in and they
     initially respond, they're not in an inspection mode. 
     They're in a protect public health and safety mode in the
     incident response, as we all are in that role.
               And so from that perspective, when they go in,
     they need to know what are the critical assumptions, what
     are the vulnerabilities, what are they going to check on,
     what are they doing, are they following their EOPs, are they
     staying in their modeled assumptions and that.
               DR. BONACA:  I have a question.  RES has been
     developing plant-specific models, PRA models, they are
     simplified, or apparently they're getting into a more
     complex presentation of the plants.
               Are they available at the region level, those
               MR. GROBE:  Sonia.
               MS. BURGESS:  Yes.  The models that we are talking
     about are available in the region.  Mike Parker and myself
     are the ones that have the models here in the region.  The
     residents at the sites do not have the models.
               MR. DYER:  They're going to make a presentation
     and talk to you later on.  So I think the answer is yes.
               MR. GROBE:  The residents understand the
     risk-significant systems and they understand that their
     principal focus is do you have the ability to move water, do
     you have the ability to provide electrical power where you
     need it, do you have containment through piping systems.  So
     that's what they're focused on, what the licensee is
     prioritizing as far as their response to the event, and
     that's where they need to be focusing.
               MR. DAPAS:  I think that's best illustrated -- we
     had a recent example here with Palisades, where they had a
     problem with the diesel generator output breaker, where the
     breaker failed and they could not open it.  They had lost
     control power.  The residents responded to the control room
     to understand what was the impact on emergency A/C power
     availability and communicated out to the branch chief, and
     then we had Sonia Burgess involved looking at what's the
     ongoing risk impact of not being able to open the output
     breaker and what damage may have been -- when you motorized
     the generator, was there a problem.
               So that would provide us a perspective, what's the
     risk significance of the plant continuing to operate in this
     condition and should we provide any augmented support to the
     resident staff.
               DR. WALLIS:  As the technology advances, one could
     imagine that inspectors in the future could have some
     handheld computation device which would give them a SPAR.
               MR. GROBE:  We get very anxious when we start
     talking in that area, because a lot of this is instinctual
     on how you respond to an event.  Let's just say we get
               DR. POWERS:  Well, I think my own view was that
     inspectors have more to do with providing the input to risk
     modeling on a pump than they do running the pump.
               DR. SEALE:  They need to be able to communicate.
               DR. POWERS:  And you'd be -- I mean, all of these
     things.  One of the biggest concerns that I have about the
     oversight program is it's taking away from hours in the
     plant to hours at the desk, and that's a tradeoff which
     ought to be consciously made.
               And having risk tools to play with, it quickly
     becomes risk tools that you have to play with and that is
     just another detraction from eyeballs on the plant.
               But I'm looking at, at the same time, this guy
     should have all of the support he thinks he needs in
     answering questions, in his mind, about risk.  So it's
     really tools for Sonia and her team that I think we're
     talking about here.
               DR. BONACA:  On the other hand, my question was
     more in the direction of just part of the maintenance rule
     now, the operators can take out-of-service multiple
     components and, of course, there is a requirement for the to
     evaluate the risk significance and to what extent a resident
     does a spot-check for a given configuration that he may
     consider risky enough for him to ask a question, without
     having to depend entirely on the plant staff.
               I think that is an important objective long-term,
     it seems to me.
               MR. DAPAS:  Nora Collins was smiling.  She is
     going to be talking later about on-line risk and I think can
     provide some insights in that area.
               MR. CALDWELL:  There are a couple of issues
     associated with the SRAs availability of having the analyst. 
     So we're looking at succession planning for the SRAs, but
     integral in that is there's a task group they're putting
     together with NRR and the regions to look at that question.
               But integral to that is a discussion on training
     and what types of training that the various levels need and
     one of the -- the regions, I guess, got together and decided
     one of the aspects of training that all the inspectors need,
     including the resident inspectors, was risk inspection
     planning, which would go to what you're talking about; what
     things should you look at and when should you look at them.
               So there is a task group that's going to look at
     the types of training that should go to the residents, the
     type of residents that should go to senior inspectors here
     in the region, and succession planning for the SRAs.
               DR. POWERS:  I think that speaks to the issue of
     how detailed and how high quality we have to have the risk
     resources, not necessarily the turnaround time, but the
     quality and detail, which is an issue in itself, whether the
     SPAR models are adequate or we need something more detailed,
     because inspectors tend to look at things at at least one
     level down on the level of modeling PRAs.
               I mean, it's the same problem the engineer at the
     plant has.  He tends to work on things that are a level
               MR. DAPAS:  For the sake of timeliness here, I'm
     just going to kind of go through examples of each activity
     here, but I'll just point out a couple of things. 
     Operability evaluations, clearly, the residents get involved
     in evaluating the impact of degraded equipment.
               If a pump is supposed to deliver X amount of flow
     for the surveillance procedure, it doesn't pass the
     surveillance test, and then the licensee does an evaluation
     and says, well, the pump can still perform its intended
     function, that can lead into a 50.59 evaluation, because the
     pump operation may be different than described in the final
     safety analysis report, et cetera.  So they get involved in
               Severe weather preparations --
               DR. POWERS:  We're going through a substantial
     change of 50.59.
               MR. DAPAS:  Correct.
               DR. POWERS:  And there's a high judgmental
     capacity content to this on what is a minimal change in the
     impact assumptions, things like that.
               MR. DAPAS:  I think our safety system design
     inspections get more intrusive into the quality of the
     50.59.  The role of the resident is the licensee conducts a
     50.59 and they kind of look at does this make sense.  If
     they need more additional help, they can engage DRS
               But looking at it from the programmatic aspect, I
     think select samples as part of your design inspection.
               MR. GROBE:  I think, if I understand your question
     correctly, it was what's the staff's reaction to the
     judgment and the subjectivity that might go into the new
     decisions in the rule.
               I think the staff truly was uncomfortable with
     some of the Draconian outputs of using the rule as it was
     written before.  Some unreviewed safety questions that were
     really insignificant would result in enforcement action.
               So on that specific issue, while it involves more
     judgment, I think the staff is more comfortable.  There are
     a number of areas with the new inspection program that the
     staff is not as comfortable as what we used to have and we
     can get into some of those.
               But that's an area I'm not sure we have a lot of
     concern with.  The implementation we haven't actually seen
     yet, so we're going to have to walk through that.
               DR. SIEBER:  I think we would like to hear your
     concerns later on that, so we know what they are.
               MR. DAPAS:  Now I more fully understood your
     question.  Severe weather preparation, with the plants we
     have located here in northern climates, we get involved a
     lot in that.  In fact, we had an issue at Point Beach
     regarding freeze protection for a safety injection recirc
     line, tangible example of where inadequate freeze protection
     resulted in problems.
               And problem identification and resolution.  An
     integral part of each inspection procedure is ten to 15
     percent of that is dedicated to follow-up for problem
     identification and resolution, and that, of course, is the
     foundation of new program, corrective actions.
               And there's two aspects to that.  Of course,
     annual review and then follow-up on issues specific to the
     area being covered by the individual module, like
     surveillance testing.
               DR. SIEBER:  In that regard, under the new
     oversight process and significance determination, they
     aren't writing as many violations.  On the other hand, we're
     probably writing more non-cited violations, and all those
     are supposed to go into the CAT.
               Do you folks follow-up inspecting CAT to make
               MR. GROBE:  Not all of them.  There's two.  One is
     that we do a regular inspection of the effectiveness of the
     corrective action program and that's run out of Merck's
     division, and we have people on that inspection.
               In addition to that, we sample a portion of
     non-cited violations as part of that inspection, but we
     don't look at all of them, and that's part of the new
     inspection program that actually makes sense, because the
     violations we identify are a very small portion of the total
     number of issues that need to be corrected on a yearly
               So we'll select a portion of the violations we
     identify and that were non-cited, as well as a large number
     of other issues that we focus, from a risk perspective, on
     trying to get the more important ones.
               DR. SIEBER:  I guess my personal feeling is that
     NRC gave up something when it moved from deterministic
     systems into risk-based systems and significance
     determination.  What you gave up was the ability to write a
     violation and get a written response and a commitment from
     the licensee that you could follow-up up on and for a given
     unit that could have been anywhere from five to 20 items a
               On the other hand, once you give that up, you have
     to put a little more emphasis and follow up with a
     corrective action program to make sure that it didn't
               MR. DAPAS:  You're right.  That's a balancing act,
     obviously.  The crux of the new program was what's the
     appropriate amount of regulatory burden.  You're writing
     violations, the licensee has to respond, what is the
     threshold for that.
               That's why we -- we put great stock in our problem
     identification and resolution inspection.  We think that's a
     critical aspect of the new program.
               DR. SIEBER:  Even the Commissioners see that as a
     key.  They're very adamant about that.
               DR. POWERS:  Well, I think the Commissioners see
     it more than the headquarters staff.
               MR. DYER:  Well, I don't know that.  I think it's
     we -- a lot of the violations, I think, as Jack said
     earlier, a lot of the violations that we wrote, we were
     spending a lot of time on correspondence that didn't improve
     the safety of the plant.
               DR. SIEBER:  Yes.  We were on the other end.
               MR. DYER:  So I think the new program does allow
     -- what we have to do is take significant actions when we
     find a licensee is not -- when they break that trust.
               And one of the things we get through here, when we
     start looking at the new program, that is the importance of
     the cross-cutting issues, in my mind, as a regulator, and,
     in particular, the corrective action program.
               As you said, we are turning a lot over.  This will
     make for a more efficient and effective way of regulating
     and allow the licensee to prioritize, but they have to have
     a good program.
               MR. CALDWELL:  There's a major challenge to the
     licensee that comes out of this.  In the past, when we wrote
     a violation, it came out in our report, they had to respond. 
     Typically, they had to get senior management to agree with
     the response, so that the managers were heavily involved in
     those activities, at least the inspection activities that we
               Now, it's included in their corrective action
     program.  So the licensee's management has the challenge of
     staying involved in those issues that occur.  They are going
     to have to be asking more questions and getting more
     involved in their corrective action program.  So it is a
               MR. GROBE:  Our ability to cause licensee
     management to engage in issues is diminished under the new
     inspection program.  One of the things that we got good at
     and our staff gets very good at is appreciating a broader
     perspective and focusing on root cause.
               Now, as Jim indicated, the licensee has to take
     that burden completely on themselves, which is appropriate,
     but our ability to direct that, unless it results in a
     risk-significant issue under the SDP, is limited.
               DR. SIEBER:  One final question, which you can
     answer yes or no.  You have exit meetings when you conclude
     an inspection, either a resident or a specialist inspection. 
     Since the new oversight process and the burden has changed,
     do you have any idea whether the level of management that
     attends those exit meetings has changed to a lower level
     since there is less management involvement?
               MR. DAPAS:  I can actually comment on that
     specifically.  I think there's actually been a higher
     engagement of management, because we communicate at that
     exit meeting some issues that may not be documented in the
     report, and that's a program office policy decision that
     some issues that don't rise to the threshold of an
     inspection finding or a green issue, the licensee is
     interested in hearing about those and those are communicated
     at the exit meeting.
               Many times, a site vice president or plant
     management wants to hear those firsthand.
               DR. SIEBER:  That's good input for me, because I
     would have expected, just human nature being what it was,
     that it would have gone the other way.  So that's good. 
     Thank you very much.
               MR. DYER:  I think the other dynamic in that is,
     again, the economic pressures.  Licensees realize that the
     NRC inspection findings that are below the threshold for
     being documented in the report can, in fact, affect their
     operation, you know, may provide them an insight or
     something maybe to address before it -- it's a precursor.
               In today's environment, that's necessary.
               DR. SIEBER:  Thank you.
               CHAIRMAN BARTON:  Gentlemen, we're going to have
     to move this along a little bit.  Maybe we can have some
     more questions during the lunch break.  We're one-third
     through item three, which was supposed to be completed at
     this point.  So I think we need to kind of hold questions
     and have maybe some discussion during lunch.  Otherwise,
     we'll never get through today.
               MR. DAPAS:  The last point I was going to make is
     performance indicator verification, obviously an important
     activity the residents are engaged in.
               We had a number of lessons learned from the pilot
     program that have been communicated to licensees, and that
     underscores the importance of consistent application of the
     performance indicators, and I think we're going to talk more
     specifically about those a little later on.
               Next slide, please.  This is just a slide showing
     how the division is organized, as Mr. Dyer said, relatively
     consistent across the regions.  We are currently only one
     site is staffed at N+1, that's D.C. Cook; of course, our
     agency focus plant, and we're actively recruiting to fill
     the reactor engineer vacancies that exist.
               I'm going to talk a little bit more later on about
     the challenges that have been presented to DRP in trying to
     fully staff in the context of the new inspection program
               DR. WALLIS:  You have four vacancies here at the
     reactor engineer level?
               MR. DYER:  That's correct.
               MR. GROBE:  What we've done is added overage
     positions.  Several of those positions are overage, and
     we've done that in operator licensing and both engineering
     branches and in the reactor engineering DRP.  And the goal
     is to minimize the amount of downtime we have, when we lose
     a number of the staff.
               So we're trying to fill those up.  Once we fill
     them, we're going to have a substantial buffer, we hope.
               MR. CALDWELL:  These reactor engineers are not
     intended to be overage positions.  We do have overage
     positions elsewhere, but we're trying to stay ahead of our
     -- unfortunately, we never meet our ceiling.  And so we're
     trying to get ahead of the ceiling so that we at least have
     utilization of all the FTE who are left.
               MR. DAPAS:  We bring the reactor engineer on board
     and a vacancy occurs at the plant and that's got to be our
     primary focus, is making sure the sites are fully staffed. 
     So it's an ongoing challenge to try and fully staff the
     reactor engineer position while keeping the resident program
     fully staffed.
               DR. WALLIS:  Because if you lose one more, you'll
     have none, it looks like.  Four out of five.
               MR. DAPAS:  We're heading the other direction.
               DR. APOSTOLAKIS:  I have a question.  I'm looking
     at the report from the web site regarding the maintenance
     rule.  It says that you interviewed two licensed reactor
     operators and three senior reactor operators to determine if
     they understood the general requirements of the maintenance
               Is this something that you do routinely?  I mean,
     what if they don't understand it, what would you do?
               MR. DAPAS:  Which -- I'm not familiar --
               CHAIRMAN BARTON:  This is the follow-up to the
     maintenance inspection report that was done in the regions. 
     Part of that was going in and asking various people on the
     stations what was their knowledge of the maintenance rule. 
     Remember that part of it?
               DR. APOSTOLAKIS:  Is it still the situation that
     we will interview people to see if they understand something
     under the new revised oversight process?  Is that part of
     the baseline inspection?
               MR. DYER:  Not that I know of.  That might have
     been a special inspection.  Was that done under a TI?
               MR. DAPAS:  I thought that was associated with
     implementation of the new maintenance rule.
               CHAIRMAN BARTON:  That's what it was.
               MR. GROBE:  It was a special inspection.
               MR. SINGH:  It was a follow-up inspection to the
     original inspection.
               MR. GROBE:  Right, where there were open issues,
     and you go back out, and part of that, I think, was ensuring
     that the licensee understood performance goals and on-line
     risk assessment.
               CHAIRMAN BARTON:  A lot of that was going into the
     control room to ask the SROs, the supervisors, how was their
     knowledge of the maintenance rule.
               MR. GROBE:  We have one our maintenance rule
     experts here, Any Dunlop.
               MR. DUNLOP:  The maintenance rule baseline
     inspections and most likely what this was, there were some
     open issues that came up during the baseline inspections and
     what we did at each of the sites, when we had open issues,
     we would go back and follow-up on them, and that's most
     likely what this inspection report is discussing, a
     follow-up inspection to address any open issues that had
     come up.
               I'm not sure, I wasn't part of the follow-up.  I
     was part of the original inspection.
               DR. APOSTOLAKIS:  It's not really this specific
     thing that I'm asking about.  I'm just asking, in the
     future, with the new oversight process, is there room there
     for us as an agency to see how much the licensee knows about
     something?  Aren't we supposed to be moving towards a more
     performance-based system?  Is there a cross-cutting issues
     that says try to see how much this operator at the plant
               MR. DUNLOP:  I think the maintenance rule is
     supposed to be one of our first performance-based rules that
     we put into effect and I think the purpose of the baseline
     inspections was to, unfortunately, have a programmatic
     review of what the licensees know and how the program was
     actually put together.  I know as part of the new A-4 new
     maintenance rule, there will be some PI developed and we'll
     be doing some inspections at some of the sites.
               How much we'll be looking into the programmatic
     aspects versus the performance-based, I don't that's been
     determined yet.
               MR. DUNLOP:  I believe that inspection was sort of
     a -- the baseline and the follow-up was sort of to set the
     groundwork to then go forward.  In the future, I don't
     believe we're going to be quizzing people on their knowledge
               I think part of the baseline inspection, if I
     remember correctly, part of it was to see did the training
     take.  When you go in and you took it, when they had
     implemented a change in the program, part of our inspection
     is, okay, did the training take, do people understand their
               And as a basis for that, that was the nature of
     the questioning and I think that was specifically called out
     in a temporary inspection, which would be not part of -- it
     would be a one-time inspection, not part of a routine
     inspection that we would continue.
               So it would take the headquarters, if they
     decided, for some other reason, that we needed to go back
     out and periodically reverify the training, then we could
     look at it again, but it wouldn't be part of our normal
     routine program.
               MR. GROBE:  I was going to say, by contrast,
     whenever we observe an activity, I expect the inspectors to
     be assessing the knowledge level of the people that are
     performing that activity of the procedures and the specific
     work they're doing.
               So we would continue to evaluate, if we observe a
     maintenance activity or a test activity or an operations
     activity or talk to an engineer about a calculation, we'd be
     assessing their understanding of what they're trying to
     accomplish and their understanding of the procedures
     involved in that.
               So we will still be getting into assessing the
     capability of the people to accomplish the work they're
     trying to accomplish for those activities where we're
     observing performance.
               But as Andy pointed out, that was strictly a
     programmatic inspection.  It didn't involve actual
     implementation of the program as much as on a day-to-day
     basis, as much as the programs, procedures and training.
               DR. APOSTOLAKIS:  There are similar findings in
     other places, and I'm not questioning you why you did this. 
     I'm trying to see what the future will be under the new
     oversight process.  We have the cross-cutting issues, of
               MR. DAPAS:  We have an individual that actually
     has probably conducted the resident inspector portion of
     that and certainly can speak to what the new program entails
     as far as the maintenance rule.
               DR. APOSTOLAKIS:  While you're getting the
     microphone.  I've made several findings here that really I
     didn't expect to see.  For example, The company nuclear
     review board members were thoroughly prepared for the
     September '98 meeting.
               MR. DAPAS:  Does that embody observations and --
               DR. APOSTOLAKIS:  Yes, but is it going to be in
     the future, are they going to be observe whether people are
     well prepared.  There was a finding later that the expert
     panel deliberations were not recommended, and so on.
               And I thought that in the new oversight process,
     what really matters is the decisions of the expert panel and
     not whether they document what they're doing.
               So the question is how much of this is going to
     change in the future, if any?
               MR. DYER:  I think you'd have to look at either
     the Quad Cities or the Prairie Island plant issues matrix to
     get a better understanding as to what the new program is
     going to look like.  Davis-Besse was under the old program.
               DR. APOSTOLAKIS:  I understand.  This is old.
               MR. DYER:  And there's a specific module.  So the
     resident inspectors, once every 18 months, had to go observe
     an off-site review committee, and they do the best they can.
               MR. COLLINS:  I can talk to that.  My name is
     Laura Collins, and I was a resident inspector at the pilot
     plant, Quad Cities, and did the maintenance rule inspection
     portions for the residents there a lot.
               The kind of observations that you're talking
     about, unless they were to really result in a problem,
     because we're more results-oriented, are not the kinds of
     things, I don't think, we would be documenting anymore.
               But we would still be, if we observed those
     things, communicating them to the licensee, so that they can
     learn from them.
               So if we make those observations, we're going to
     share everything that we observe with the licensee, but we
     have higher thresholds for findings.  There's got to be some
     kind of a result of that improper implementation of the
     maintenance rule.
               DR. APOSTOLAKIS:  So that in the future, then, you
     would not particularly care about how the expert panel
     conducts its business.  You would just look at the results.
               MS. COLLINS:  That's right.
               DR. APOSTOLAKIS:  Is that the correct perception?
               MS. COLLINS:  We start with the results.
               DR. APOSTOLAKIS:  But you may get back into the
     thing, I mean, if you want to understand --
               MR. DYER:  I think one of the things that the
     utilities, the vice presidents, are particularly interested
     in is if we said we observed the meeting, we have no
     findings, a lot of times they'll ask you, what did you think
     of the conduct of the meeting, and that's one of those
     issues that may be provided below the line, but it's not
     going to be documented in the inspection report, there's no
     response required.
               MR. CALDWELL:  And it's not that we don't -- you
     said we may not care about it anymore.  We still care, but
     we wouldn't document it necessarily.  We would communicate
     it to the licensee, if we felt that would give them some
               DR. SIEBER:  Unless you came away with the feeling
     that the result was inadequate, and then you may go further
     to find out why that is.
               MR. DYER:  Now, if we come out with an inadequate
     safety review, we may take it back to there was an
     inadequate safety review, it was not adequately reviewed and
     people weren't prepared, something like that.  But it would
     be tied to the results.
               MR. DAPAS:  Or then the expert panel concluded
     this system should be -- there should be performance goals
     established for this system to review its importance and
     risks, and the licensee didn't address that, that would be a
               DR. APOSTOLAKIS:  I agree, but that is clearly
     within the new rules of the game.
               DR. BONACA:  How do you know if there is no
     implementation.  What I'm trying to say, there are examples
     there, some examples where the PRA defined some component
     that's safety-significant, but determined it wasn't really
     safety-significant and, therefore, they did not report this
               Now, there is an importance also in the
     documentation.  You've got to make a determination that the
     decision ultimately was the correct one.  Performance-based
     doesn't mean you're waiting until you have an event.  It
     means that you're performing the right things.  So you still
     have a burden on the processes that you have to inspect and
     the show of the work.
               DR. APOSTOLAKIS:  See, what confuses me -- and,
     again, I'm not referring to a specific thing, but is that in
     Washington, we're being told time and time again that
     managing the plant and the organizational aspects are really
     the licensee's responsibility and we should not get
               In fact, several of the research projects of the
     Office of Research have been killed on that principle.  And
     then I come here and I see that an appropriate feedback
     process was in place, operators responded conservatively to
     plant transients, operators were prepared for the possible
     closure of feedwater regulating valve surveillance testing.
               All this is organizational management, isn't it?
               MR. GROBE:  No.
               DR. SEALE:  It's
               CHAIRMAN BARTON:  It's observation of plant
     operations, George.
               DR. APOSTOLAKIS:  But there is a feedback process? 
     That's their business.
               MR. GROBE:  Well, it's also required pursuant to
     Appendix B.
               DR. APOSTOLAKIS:  So what we are told there is not
     entirely accurate.  I'm trying to reconcile the views.  It's
     very fuzzy, isn't it?
               CHAIRMAN BARTON:  Especially when you're assessing
     management's competence and safety culture versus
     observation of plant operation.
               DR. APOSTOLAKIS:  That's an extreme, I agree.  I
     agree.  But having an appropriate feedback process, it seems
     to me, is an organizational issue.
               MR. GROBE:  I'm not sure what the context of that
     was.  But it's important, though.  For example --
               DR. APOSTOLAKIS:  Plant issue matrix of
     Davis-Besse, dated September 28, '99.
               MR. GROBE:  For example, within the training
     context, the feedback process is absolutely critical,
     because on a system-based training process, you have to have
     that loop.  In the training inspection, that's part of what
     we look at.
               Within the context of an oversight committee, the
     engagement of the committee in questioning the quality of
     the product and understanding it is critical to the outcome. 
     So if we only look at the outcome of the meeting, there may
     be significant things that they missed because they weren't
     well prepared for the meeting.
               And it gets to root cause, really.  If we're going
     to have inspectors in the field observing the activities,
     those are the kinds of things we expect them to look at.  As
     Laura pointed out, those issues wouldn't find their way into
     a report today unless they resulted in a risk-significant
               MR. DAPAS:  And that's the key.  Regulatory
     engagement is a product of the consequence of that, but we
     would still feed that observation back to the licensee.
               MR. GROBE:  Exactly.  Both positive and negative. 
     If we found that the people performing a maintenance or a
     test activity were very qualified and competent and
     displayed that in their discipline, in the way they
     approached their job, provide that feedback.
               DR. APOSTOLAKIS:  So the action matrix of the new
     oversight process, that would not be triggered.  That would
     not be affected by these observations.  You just provide the
               MR. GROBE:  That's right.
               DR. APOSTOLAKIS:  Because there is nothing white.
               MR. GROBE:  That's right.
               MR. CALDWELL:  You also understand we're in the
     initial implementation phase of this new process, this is
     what we think, we may learn something as we go along and
     change our approach, but right now, that would be the
               MR. DYER:  What we found at the two pilot plants
     that we've implemented the program in, when we first went to
     -- we actually applied the SDP to it and we went through our
     formal exit and said here's our formal observations and the
     utility management look at us and say is that all, you've
     been here for a month, you need to give us more feedback.
               It evolved out of that --
               MR. GROBE:  Tell us what you really think.
               MR. DYER:  Yes.  And evolved out of that is we
     have a formal exit now where we say here is what is formally
     going in the inspection report, here's our observations that
     aren't going to make the report.
               MR. GROBE:  Dr. Barton, in the interest of time,
     let me quickly go through the next six or eight slides, and,
     Bruce, keep up with me.
               In the Division of Reactor Safety, we really have
     five major functions; engineering inspections, health
     physics and emergency preparedness inspections, safeguards
     inspections.  We also have operator licensing and that
     includes initial examinations, upgrade examinations, as well
     as requal inspections, and incident response is one of the
     major functions of the Division of Reactor Safety.
               Let me just highlight a few things in the
     engineering inspection area that are new and exciting.  We
     have a much stronger emphasis today on design inspections. 
     We have an inspection called the safety system design
     inspection, or the SSDI.  We also have an inspection that
     focuses more heavily on the Appendix R design of the plant
     and the ability of the plant to sustain a debilitating fire.
               Those are two inspections that are new, much
     stronger emphasis in the design area.
               DR. POWERS:  I attended the fire protection forum
     and it was an interesting complaint.  They said, gee, you
     guys are focusing all your attention on this Appendix R and
     the safe shutdown and neglecting all this other fire
     inspection stuff, and it's just not right.  The fact is we
     haven't done the Appendix R safe shutdown inspections in the
     past to the extent that they probably should have been done.
               And now we're just bringing things back to some
     sort of proper balance.
               MR. GROBE:  And we're not disregarding classical
     fire protection either.  That's part of the resident
     program.  But there's a summary on the slide of the types of
     engineering inspections we get engaged in and we'll go into
     some more detail later on some of those.
               In the safeguards area, we look at contingency
     response, access control and fitness-for-duty primarily,
     and, as Marc indicated earlier, each component of our
     inspection program, we look at problem identification and
     resolution or the effectiveness of the corrective action
               DR. SIEBER:  When you do an OSRE, though, that
     also involves the operations people, right?  With strategies
     and so forth.
               MR. GROBE:  Exactly.
               DR. SIEBER:  But that's not part of your baseline
     inspection.  You're just looking at cameras in the field and
               MR. GROBE:  Contingency response is actually --
               DR. SIEBER:  Is that in there?
               MR. GROBE:  Yes.  It's kind of in there in hiatus
     right now.  OSRE is suspended and we're trying to work with
     the industry to come up with a better way to do
     force-on-force drills.
               DR. POWERS:  One of the questions that I've had
     about that is the extent to which we can use some of the
     computational tools that have been developed by the national
     laboratories, among other people, I think, for simulating
     these force-on-force exercises.
               They won't do everything that the OSRE does for
     you, but they would certainly augment or maybe reduce the
     need to do actual OSRE type activities.  Have you looked
     into this at all?
               MR. GROBE:  I don't know.
               CHAIRMAN BARTON:  It's a civilian industry
     initiative at this point.
               MR. GROBE:  These are simulation type tools that
               DR. POWERS:  They were originally developed -- the
     ones I know about, the ones that were originally developed
     were Air Force bases in Europe.  They became concerned when
     the Red Army was running around, could they, in fact, defend
     their weapons systems from an intrusion force, and that
     would be different than an ordinary military fighting force.
               And they had done a lot of exercises with these
     guys with laser rifles and things that had sensors all over
     them and they computerize it and out of that they come up
     with what's the optimal strike force against it, what are
     the vulnerable sites, locations on the facility and things
     like that.
               MR. GROBE:  I'll look into it.
               DR. POWERS:  They eventually got very
     sophisticated, but I don't know whether they've gone into
     the commercial sector or not.
               MR. GROBE:  I have not heard about it.
               DR. POWERS:  They resulted in massive changes to
     the way they the military protected their facilities.  I
     mean, they were shocked at how easy it was to break in.
               MR. GROBE:  Appreciate that insight.
               In the rad protection area, three primary focuses;
     plant protection of the people on-site, radioactive waste
     and transportation, and protection of the public, effluents
     and environmental protection.
               DR. SIEBER:  This is probably where Illinois
     Department of Radiation Safety comes in quite a bit.
               MR. GROBE:  Well, they're much more intrusive. 
     They have reactor safety specialists that are resident at
     the sites.  They are very sophisticated, very impressive
     organization.  Not quite as good as us, though.
               DR. SIEBER:  Well, I knew that.
               MR. GROBE:  In emergency preparedness, we observe
     exercises, as well as do programmatic reviews on a regular
     basis.  Operator licensing, I mentioned earlier, we do
     initial exams.  Sometimes those are SRO, instant SROs exams,
     sometimes reactor operator exams.
               We also do upgrade exams and requalification
     inspections.  In each area, again, problem identification
     and resolution.
               Incident response, we maintain and coordinate for
     the region maintenance of our incident response capability,
     and that includes exercises, training, equipment and
     facilities, as well as interface with Federal, state and
     local, and unique in Region III is some tribal interface up
     at the Prairie Island plant.
               The division is broken up into four branches.  Two
     engineering branches, one focusing primarily on electrical,
     which includes environmental qualification, I&C, fire
     protection, electrical engineering and analyses; mechanical,
     which gets into mechanical, civil structural, as much as we
     do these days, maintenance rule, in-service inspection,
     steam generator replacement, steam generator tube
     inspections, things of that nature.
               An operator licensing branch, which is very busy
     these days.  Unlike some other regions, for example, Region
     I puts emergency preparedness and operator licensing
     together in one branch.  This branch is strictly focused on
     operator licensing.
               DR. WALLIS:  Does mechanical engineering include
     thermal hydraulics?
               MR. GROBE:  Are you talking, for example, of -- we
     do heat sink inspections.
               DR. WALLIS:  Heat and fluid, yes.  Water and
     steam, where they are and what they're doing, how well they
     are performing their function.
               MR. GROBE:  Within the reactor, we don't do a lot
     of inspection from a thermal hydraulic point of view. 
     However, from a heat sink point of view, heat exchanger
     performance, we do some inspection in that area.
               Plant support is health physics, emergency
     preparedness and incident response in that branch.
               MR. DAPAS:  You can get into those aspects,
     though, like with an operability evaluation, where the
     licensee is using thermal hydraulic analysis to support a
     particular conclusion.  We might look at that.
               MR. GROBE:  We just completed safety system design
     inspection at Point Beach and the focus was the service
     water system, a lot of thermal hydraulic analysis involved
     in that.
               That was fired through the scrub oaks on Division
     of Reactor Safety.
               CHAIRMAN BARTON:  Very good, you did good.  At
     this point, I'd like to break until 10:30.
               CHAIRMAN BARTON:  We're back in session.  Marc,
     are you still on?
               MR. DAPAS:  Yes.  The next presentation that we
     wanted to address was the comparison of the new program to
     the old program.  I think some of you have raised some
     questions.  In the context of the new program, I think this
     is an opportunity to more thoroughly address some of those.
               As an example, I know Mr. Seale raised a question
     about the resource expenditure tracking and we can talk
     about what challenges that presents.
               Rather than continue to use overheads here, if we
     can just go through the slides, if that's okay with you.
               CHAIRMAN BARTON:  That's fine.
               MR. DAPAS:  Great.  Starting on page 20, when we
     looked at the old program, that was pretty much broken up
     into thirds between the core program, what was previously
     termed the regional initiative, and special inspections. 
     Special inspections was our mechanism for following up to
     specific events.
               And as we talked about a little earlier, we use
     risk as a gauge in determining what's the appropriate
     engagement in terms of numbers of folks we send to the site.
               The regional initiative, of course, involves some
     subjective judgment about the declining licensee performance
     in a particular area or aspect of plant operations, and we
     would send some folks out to do a more intrusive review of
               Under the new program, it's pretty much baseline
     loaded, and the baseline represents that minimum amount of
     inspection required to verify that licensee performance is
     within the licensee response band, whereas under the old
     program, the core represented that minimal amount of
     inspection to verify the plant was being operated safely.
               As you know, whether you're in the licensee
     response band or regulatory response band, there's still a
     sufficient safety margin.  So it's a little different
               There is clearly greater flexibility in applying
     inspection resources under the old program.  An inspection
     procedure could be closed using judgment on whether the
     intent was met.
               For example, inspection procedure 71.707, which
     dealt with operational safety verification, that would
     include observation of control room activities, an
     engineered safety system feature walk-down.
               The inspector could decide, based on reading the
     inspection procedure, I met the intent of this procedure
     with X number of hours.  Under the new program --
               MR. GROBE:  Before you go on, that's exactly what
     got Davis-Besse down in the 1,800 hour range.  I'm sorry.
               MR. DAPAS:  When you look at the sampling size
     under the new program, X number of surveillance tests need
     to be observed, X number of operability evaluations. 
     There's a certain periodicity; for example, looking at maybe
     a couple samples a month.
               And under the one-size-fits-all approach within
     the licensee response band, the baseline inspection program
     is fairly rigorous in the scope and estimated number of
     hours to complete the inspection procedure.  And as Jack
     pointed out, that can translate to what is perceived to be
     an increased regulatory burden for a licensee like
     Davis-Besse, where there was more flexibility in determining
     was the intent of the procedure met.
               In the new program, you have to implement the full
     scope to satisfy the inspection procedure objectives.
               MR. GROBE:  Philosophically, what we've done is on
     the side of the angels.  We looked at risk, we picked out
     what are the most significant risk-related activities. 
     Based on the impact on the risk of that activity, we
     identified those attributes that were important to inspect
     and we assigned, developed inspection procedures and figured
     out how much resources it would take to do it, and it came
     out to, whatever it is, 2,100, 2,200 hours.
               The challenge, point number one, is that that
     consumes almost 95 percent of our resources.  So the
     combination of things; the new thresholds to get to a white,
     yellow or red finding are fairly high.  So we don't expect
     to have much supplemental inspection.  But we also have much
     less capability to respond to a problem of that nature, and
     we're going to have to depend on other regions and
     headquarters to supply us resources, whereas in the past,
     that 33 percent regional initiative, we could target those
     resources based on management judgment.
               That made us less predictable, and that was one of
     the concerns the licensees had.
               DR. SIEBER:  The real opportunity, and I realize
     it may be a second or third generation in the application,
     to achieve this is the extent to which you can make the
     inspections plant-specific, with justification.
               MR. GROBE:  We make all the inspections
     DR. SIEBER:  In terms of coverage, not in terms of --
               MR. GROBE:  In terms of amount of hours, is that
     what you're saying?
     DR. SIEBER:  Yes.
               MR. GROBE:  We talked about modifying the baseline
     based on performance.  But that gets back to where we were
     and there is a lot of reticence to do that very quickly. 
     If, after a few years, we find out that they're --
     DR. SIEBER:  Maturing.
               MR. CALDWELL:  But it also is the way the system
     is set up, we're not capable of doing that right now,
     because there is not a gradation in green band.  That's
     licensee response band, that's where we stay at.  So those
     folks that are in that band get the baseline inspection
     program, whether they're at the top of the band or at the
     bottom of the band.  That's the way the new oversight
     process works.
               So to try to come up with a way of reducing
     inspection of one licensee over another is not -- within
     this current program, that's not possible.
               MR. GROBE:  The pendulum swung to predictability. 
     We are extremely predictable now.  The question is whether
     or not we've taken too much of the judgment out, such that
     we can no longer predict problems.
               DR. POWERS:  What I worry about, especially this
     point about the inspectors losing judgment capability, it
     seems to me that the good inspector can quickly say in this
     area, I've met the intent here, and there are enough
     problems for me to worry about here, this other area is more
     complicated for me to understand, me personally to
     understand than the average inspector, and there may be
     bigger issues here, and so I need to spend more of my hours
               That judgment seems to be something that I want
     him to exercise very much.
               MR. GROBE:  It's been reduced in the new program.
               DR. POWERS:  And it seems like he's -- that that's
     the flexibility that is a real loss.
               MR. DAPAS:  Let me comment on that.  As I
     understand the new inspection program, the sampling size is
     intended to be risk-informed.  Operability evaluations is
     clearly going to be a risk-significant activity.  If the
     licensee doesn't adequately evaluate the impact of degraded
     equipment, will the equipment perform its intended function.
               That's clearly related to risk.  So what is an
     appropriate sample size to gauge how the licensee is
     performing in that particular area.
               In the past, under the old program, you may decide
     to watch one surveillance test and you felt that you've met
     the objectives of the procedure.  Under the new program,
     there may be two surveillance tests that you look at on a
     monthly basis, and that's the risk-informed sample size.
               So it's more prescriptive in that regard and
     that's why the hours are more rigorous.
               Now, I think after the first year of
     implementation across all the sites, we may end up
     revisiting the scope of a given inspection procedure and
     we're also providing feedback on a continuous basis.
               If the inspector is performing a certain
     inspection procedure and feels that the scope of the
     procedure needs to be refined, they provide feedback and
     that's communicated to the program office.
               CHAIRMAN BARTON:  Well, the intent of the whole
     initial implementation for one year is to make adjustments
     after that one year.
               MR. DAPAS:  Correct.
               CHAIRMAN BARTON:  Right, sure.
               MR. DAPAS:  That's my understanding.
               DR. WALLIS:  It seems to very ironic that the
     reason for all this is to get away from prescriptive
     regulation.  They seem to have moved to more prescriptive
               MR. CALDWELL:  It's prescriptive in the sense that
     the inspection size or inspection scope and type were
     supposed to be, as best we could, risk-informed.  In other
     words, you're focusing your resources in the area where
     there is the biggest bang for the buck.
               The desire to make it such that each region and
     each inspector does it essentially the same way for
     consistency, but to answer Dr. Powers' question, if an
     inspector feels they have to spend more time to accomplish a
     given sample size or given objective, they would take the
     time necessary to accomplish the objective.
               So if the inspector felt comfortable in this area
     and was able to get it done pretty fast, that's what they
     would do to accomplish the objective of the inspection.  If
     they felt that they needed more time in another area, they
     would do it, they would spend the time.
               So the judgment in that respect is still there.
               MR. GROBE:  But they right now don't have the
     latitude to say I'm going to do 18 operability evaluations
     versus 24.
               MR. CALDWELL:  Right.
               MR. GROBE:  But in addition to that, there's
     barriers.  We have put -- depending on the types of
     inspections, the error bands can be up to 25 percent as far
     as number of hours.  To go outside that band requires fairly
     high approval.
               So we need to get engaged in what it is that's
     causing the inspector to have to spend a lot more time, as
               MR. DAPAS:  And that's because we've communicated
     that the baseline inspection program is that minimal amount
     of inspections necessary to verify licensee performance is
     still within that licensee response band.
               MR. GROBE:  We spoke earlier about observing more
     behaviors and you talked in the context of management. 
     Those are the types of things that would give you confidence
     that you can make your sample size smaller.
               If you looked at the procedures and the guidance
     and you looked at the training and you looked at how the
     people were engaged in their job, in the past, we -- and all
     of those things were very positive, so you had a high level
     of confidence in the competence of the people and how their
     work activity is controlled, we would feel comfortable
     scaling back on sample size.  Now we don't have that
               DR. APOSTOLAKIS:  Do you think that the new
     oversight process can be modified to accommodate some of
     these concerns, without affecting its intent regarding
     predictability, for example, too much?
               MR. GROBE:  It's difficult.  One of the things we
     haven't thrown on the table is that it's my sense that one
     of the motivators of this predictability was the financial
     community having confidence in a regulatory oversight not
     influencing negatively the financial viability of the
     company, from a stock point of view.
               So I'm not sure how that would work and we'd have
     to do that jointly with the industry.
               DR. SIEBER:  What do you do with a plant like
               MR. GROBE:  Zion?
               DR. SIEBER:  Yes.  They still do the -- they
     haven't applied for decommissioning yet.
               MR. GROBE:  In the decommissioning area, our level
     of inspection is directly related to the level of activity
     that the licensee has on-site.
               DR. SIEBER:  So you would cut back on the number
     of residents you have there.
               MR. GROBE:  There are no residents.
               MR. CALDWELL:  We have inspectors here in the
     region that go up there, and Zion is not that far away, but,
     yes, our inspection program is based on the decommissioning. 
     There is actual inspection plan for decommissioning
               MR. DAPAS:  Which is outside the baseline program.
               Moving right along.  Certainly, under the old
     program, we used deterministic processes in our enforcement
     policy to guide our assessment of significance associated
     with inspection findings.
               Under the new program, we process findings in the
     significance determination process, which is based on the
     probabilistic risk type analysis.  I'd just simplify that
     down into two concepts.  You've got frequency of initiating
     event and then the defense-in-depth regarding mitigative
     capability and if you have a particular piece of degraded
     equipment or unavailable equipment, you look at what impact
     does that have on the mitigative capability.
               You look at the availability of redundant
     equipment.  You can credit operators for recovery actions. 
     And then there is a plant-specific phase two worksheet that
     is supposed to bring to the table the specific
     configurations unique to that plant in terms of equipment
               CHAIRMAN BARTON:  Are they all out and back now,
     are the plants commenting on them?
               MR. DAPAS:  Yes.  Sonia, you might be able to
     speak to that.  I'm not sure of the exact status.
               MS. BURGESS:  As far as the agency-wide, no.  Our
     region, yes, with the exception of D.C. Cook.  We have put
     our comments back to Research, who has, in turn, given them
     to BNL.
               MR. GROBE:  We took a different approach in Region
     III than some of the other regions took.  We had either Mike
     or Sonia out on each site visit to make sure that we had a
     clear understanding of the SDP and the licensee effectively
     integrated plant-specific issues into the SDP.
               Some of the other regions had Research do that or
     headquarters staff.  As Sonia indicated, she and Mike have
     finished all the sites, with the exception of Cook, and we
     need to get on Cook pretty soon here.
               MR. PARKER:  But to be more specific, we don't
     have the comments back from BNL and back from Research yet. 
     So they're not integrated into the current process.
               MR. GROBE:  We have hand markups of the SDP.
               DR. APOSTOLAKIS:  Are you comfortable with the
               MR. PARKER:  Am I comfortable with the SDP?  I'm
     very comfortable with the site visits we accomplished and
     the corrections and the adjustments we made to them, but
     right now the difficulty we have is working with the
     residents, because it's not integrated into the formal SDP
               MR. GROBE:  It would be interesting to march about
     a dozen inspectors up and ask them that same question,
     because there's a lot of -- we use the terms risk-informed
     and risk-based.  The SDP is primarily risk-based.
               And an excellent example, and if Laura is still
     here, she can provide some of the details, if I screw up on
     the details, there was a finding at Quad Cities involving
     motor-operated valves, where the licensee did not
     effectively correct problems on a timely basis, the
     motor-operated valve setup.
               The end result was that they had a number of
     deficiencies that, if you take together, made it clear that
     their motor-operated valve program was not functioning.
               When I say motor-operated valve program, the setup
     of the valves to make sure that they could handle
     differential pressures and all those things.
               From an SDP point of view, though, at any given
     time, there was not sufficient valves that were determined
     at that time to be non-functional, such that you got out of
     the green band.
               So it was a green finding, yet, it was clear to us
     that there were systemic problems in the way the engineering
     work was done to set up the valves, and that was a green
     finding.  So those are the kinds of issues.
               We're comfortable with the SDP.  It clearly tells
     us what it's supposed to tell us, and that is whether or not
     that one specific finding is of risk-significance, given the
     other situations that occurred at exactly the same time.
               DR. APOSTOLAKIS:  So what you're saying is that
     the actual finding may be limited to one or two components,
     when, in fact, there is suspicion that there is a common
     cause failure that might affect many more.
               MR. DAPAS:  If you have information that there's a
     common cause --
               DR. APOSTOLAKIS:  This is one possibility.
               MR. DAPAS:  -- that has to be explored as part of
     the SDP.  You have to have clear information that --
               DR. APOSTOLAKIS:  But why couldn't you do that for
     the MOVs?
               MR. DAPAS:  This was more of a programmatic
               DR. APOSTOLAKIS:  A programmatic common cause
               MR. GROBE:  We have a task group right now working
     on what we call cross-cutting issues and right now what the
     agency considers cross-cutting issues are the effectiveness
     of the corrective action program, the effectiveness of human
     performance, and the safety conscious work environment,
     which is really kind of hard to separate from the
     effectiveness of corrective action program.
               We've got some concerns in other areas.  Being
     from the Division of Reactor Safety, engineering is a big
     part of my life, and effectiveness of engineering, we think,
     is a cross-cutting issue.
               We are trying to work through those things and we
     will be, over the next year, trying to more clearly define
     how you handle cross-cutting issues and this valve issue is
     a cross-cutting issue.
               DR. APOSTOLAKIS:  But let's come back to the
     common cause failure.  Usually there is a suspicion that
     there is potential for common cause failure.  Very rarely
     you find all valves down.  You look at one or two failure
     and say, well, gee, this mechanism could have affected the
               MR. DAPAS:  That's right.  If the torque switch
     settings weren't set appropriately on valve X, the licensee
     should try and determine extent of condition, is that the
     case with other valves, and that could be a potential common
     mode failure.
               DR. APOSTOLAKIS:  Then you would go to the SDP?
               MR. DAPAS:  Correct, if there is sufficient
     information to indicate that that is the case.  But the
     example that Jack was talking about, where the licensee is
     trending valve failures and it has programmatic
     implications, under the new program, the licensee should be
     putting that issue into their corrective action program and
     addressing it.
               In our annual PI&R inspection, problem
     identification and resolution, that might be an issue that's
     part of our smart sample, where we would go in and evaluate
     did the licensee look at this from a broader context, did
     they take appropriate corrective action.
               MR. GROBE:  On that specific issue, Mike and Laura
     -- Mike, you were involved in that, weren't you?
               MS. BURGESS:  I was.
               MR. GROBE:  Pardon me?  You were?
               MS. BURGESS:  I was.  I sat on the SDP panel and
     the SDP panel did not believe that that was a common cause
     failure, that that was a cross-cutting issue thing, but that
     was not a hardware, there was no evidence that other valves
     were exhibiting those kind of failures.
               So each individual -- or this valve had to stand
     alone and go through the SDP process, which turned out to be
     a green.
               MR. GROBE:  The threshold for a common cause from
     engineering issues is very high.
               DR. APOSTOLAKIS:  So when you say the SDP panel,
     is it you or the licensees?
               MS. BURGESS:  The SDP panel is the NRC.  It's one
     SRA from every region and a branch chief from every region,
     also, plus the program office.
               DR. BONACA:  Also, if you had a significance
     determination for a certain event and found it was not
     significant enough, but you have evidence that it would
     repeat again, the determination would not -- but then you
     would refer back to your corrective action program.
               MR. DAPAS:  That gets to how robust is your
     corrective action program.  Each time there is an event, you
     have to look at the significance, or each time there is an
     issue or equipment problem, you look at the significance of
     that associated with unavailability via the significance
     determination process.
               And if that reflects a repeat occurrence, that
     calls into question the licensee's corrective action
     program.  But, again, degree of regulatory engagement is
     based on the overall significance.
               For example, you could have repeat issues that are
     such low significance, it would be inappropriate for us to
     engage.  Now, we expect the licensee to address those,
     because, of course, the whole premise is the licensee needs
     to address those low level issues before they manifest
     themselves in more significant concerns or events.
               MR. GROBE:  I don't want to leave anybody with the
     impression that we're not committed to make the program,
     because we are.  I want to make sure that we help expose the
               DR. POWERS:  Understanding that the team that set
     these programs up were under an enormous time pressure, did
     a heroic job and did a job under the understanding that
     there were going to be rough edges.
               I think these are the kinds of rough edges that
     are anticipated in this program and getting them all out in
     the air early is the only way they're going to get
               What we're seeing is some resistance to any
     changes in programs on the licensee side, which is amazing,
     but I think there are things that have to be done better and
     managerial and inspector flexibility strike me as you're
     really losing something if you take that out of the ballgame
     where that judgment component comes in.
               I mean, what are we paying these guys to be
     educated for if they don't use their judgments?
               DR. BONACA:  The reason why I was pursuing that
     issue before, also, is the fact that on the licensee side,
     it's been a common defense for a long time that this issue
     happened, but it wasn't of such significance.
               And so although it is an important element of the
     determination, it's also, at times, a defense and an attempt
     to pick more -- there are other links to other events that,
     in fact, make it significant because it's a repeat.
               So I'm only saying that the significance
     determination process right now doesn't lead you necessarily
     to assess significance based on the fact that you have
     repeats, and those are very important because then we have
     programmatic issues.
               MR. DAPAS:  Well, if you recall, our enforcement
     policy previously had an allowance to address inadequate
     corrective action, which there are supposed to be actions to
     prevent recurrence.
               But in looking at this and taking a step backward,
     one of the issues clearly that the industry challenged the
     NRC on, and ultimately Congress, was that our regulatory
     activities resulted in unnecessary regulatory burden.  And I
     think, as an agency, we determined the best approach in
     trying to establish a uniform baseline to determine
     significance is using risk, and we came up with the
     significance determination process, and I think that needs
     -- there's additional modifications that need to be made to
               But I think we concluded that going forward for
     initial implementation, that exercising that process and
     engaging, as a regulator, when thresholds were crossed, if
     that had been sufficiently established to ensure that plants
     are being operated safely while we continue to refine and
     further exercise that.
               MR. GROBE:  Any other questions on number three? 
     Because that seemed to be a big focus of --
               DR. APOSTOLAKIS:  Well, I remember when we had a
     presentation on the significance determination process.  It
     seemed to me there was a lot of room for judgment there and
     that's why I asked the question whether you are comfortable
     with it.
               Given a certain finding, is it a routine matter to
     determine its risk significance or people are still learning
     how to do that is understandable.
               MR. GROBE:  The level one and level two reviews
     should be -- the staff should be capable of doing those. 
     Our risk analysts had primarily gotten involved at the level
     two as we're learning and their workload has just been huge
     to try to help the staff learn how to use these tools.
               When you get to level three, and our risk analysts
     are engaging with the licensees' risk analysts, you get, I
     think, a very highly defensible risk position.  It takes a
     lot of effort to get there, several months worth of work has
     been our experience.
               But the tools are still in the stage of
     development and as Mike and Sonia indicated, the level two
     worksheets, we just have pencil markups on them right now. 
     But the tools should be effective and there is going to be a
     growing period where the staff learns how to use them.
               But those tools -- do you want to comment on the
               MR. PARKER:  Yes.  I guess I'd say I agree with
     you, George.  There is a lot of latitude there and we need
     to make sure that we apply the appropriate assumptions and
     that we can validate them and support them.
     But in a lot of cases, it's very positive for the inspector
     because an inspector can sit back and say, hey, I've got an
     issue, I'm going to assume this equipment is out of service,
     and still results in an insignificant issue from risk, and
     he can move on without putting more resources into it based
     on that bounding assumptions.
               So it could help the inspector out to move on,
     where, in the past, we might have pursued an issue to the
               Now he can step back and say, hey, this is not
     risk significant, the licensee is addressing it, and he can
     move on to other issues.
     But Sonia and I would work with inspectors, if they have an
     issue they believe, with some of their conservative
     assumptions, is going to come out to be potentially risk
     significant, then we'll try to make sure that we can
     validate those assumptions.
               DR. APOSTOLAKIS:  It appears, then, from your
     answer, that item number two would be affected, as well, in
     that you haven't really lost all the flexibility that you
     thought you had lost.
               MR. DAPAS:  Let me comment on that.  This gets
     back to Dr. Powers' point about inspector flexibility.  One
     of the things that, in Region III, we have attempted to
     communicate to the resident staff, as well as the regional
     inspectors and DRS, is that we've put people out in the
     field that we think have mature judgment, have experience,
     and if an issue that the licensee identifies or that we
     identify doesn't comport with your internal risk meter, you
     think there are issues there, we should ask those questions.
               And as you screen that through the SDP and you
     look at the different assumptions, to understand why or why
     that is not a risk significant issue, and that's feedback
     that we would provide to the program office, if we think
     that the SDP should have an allowance to ensure that this
     issue screens out.
               And that's got to be well supported, but that's
     where, in my view, the inspector judgment is brought to the
     table and says I think this is reflective of the licensee
     performance and I think we ought to have a way in our
     process to capture that.
               Now, that might be in the context of a
     cross-cutting issue, that might manifest itself in a change
     to the SDP, but it gets back to we continue to refine this
     and we look at lessons learned, is there a particular issue
     that may be screened out as green that subsequently does
     manifest itself as a problem before you see a performance
     indicator threshold change.
               We need to go in and look at that and say does
     that mean that the SDP needs to be modified.  So I look at
     it as a continuing work in progress.
               DR. APOSTOLAKIS:  Now, this is done here, right? 
     The SDP.
               MR. PARKER:  The phase one and phase two would be
     done at the sites or with the regional inspectors or with
     the resident inspectors and if it screens out to be
     potentially risk significant as far as the colors go, then
     Sonia and I would be involved with those activities at that
               But we might be working with inspectors up front
     because they have some questions or difficulty.
               DR. SIEBER:  We had heard testimony a couple
     months ago about an incident at a plant, not in Region III,
     where the significance determination process was used by the
     staff and it screened green.  On the other hand, there were
     two orders of magnitude difference between the staff's
     opinion of risk and the licensee's opinion of risk.
               Are you prepared somehow or other to deal with a
     contest like that?
               MS. BURGESS:  The agency is part of the process of
     validating the SDPs.  We've done the first phase, where
     we've actually sat down with the licensee and looked do we
     have the right mitigating systems down, have we implemented
     everything in your updated PRA.
               The second portion of the validation is we would
     be going to the site with scenarios of a green-white
     threshold, something that would be -- an issue that would
     put it in a white issue, a potential risk significant issue,
     and we will have the licensee run it through their risk
     program, computer program, to see if they get the same
               We will also be looking for things that trip the
     green-white threshold from the licensee's computer program
     and then use our SDP to say are we getting a green-white
     threshold or are we still in the green and if we are in the
     green, yes, we do have a problem, we have non-conservative,
     and that's what we're trying to avoid.
               DR. SIEBER:  I think part of the problem there was
     not so much is the model correct or the process correct, but
     how the model was applied to this particular instance.
               MR. PARKER:  That's possible and that's what I
     think the new process makes -- makes it a little bit more
     comfortable, that we're supposed to be entertaining and
     having dialogue with the utility more sooner than we would
     in the past, where we would -- on a potential phase two, the
     residents, the senior reactor analysts will be talking with
     the PRA organization to try to understand how they've
     modeled it, they have more sophisticated models, and what
     did we miss or what perspective didn't we consider or that
     we might have inappropriately considered.
               So we're trying to have that before we get to any
     escalated activities in those areas.
               DR. SIEBER:  Have you and the industry agreed on a
     set of rules as to how these things will be modeled or is
     this a case by case basis?
               MR. DAPAS:  Again, the SDP, I think, to answer
     your question, is a tool that the agency is using to
     determine the significance of findings, and we want that to
     be sufficiently conservative that we don't screen out
     something that has risk significance.
               My experience with the pilot program and listening
     to discussions with sites and other regions involved in the
     pilot program is we concluded that an issue, say, was of
     white significance based on our application of the
     significance determination process.  The licensee brought
     more detailed risk information to the table, with maybe a
     more sophisticated model, with different assumptions, where
     they had concluded it's not that significant.
               So I've seen more examples of that versus --
               DR. SIEBER:  This is the one I cited as an example
     of that and I see that coming to a contest someplace down
     along the line if you get into civil penalty areas.
               MR. DAPAS:  But before we go there, before the
     agency is going to make a final risk determination, we
     afford the licensee an opportunity to engage us and explain
     here's the results of our analysis, and that's where the
     senior reactor analyst gets involved in phase three.   
               It essentially affords the licensee an opportunity
     to bring their risk expertise and assessment to the table
     and we would consider that.  But ultimately we would have
     responsibility for rendering a decision on the significance
     and then take appropriate action, per the action matrix,
     which, again, be it a white issue or yellow issue, doesn't
     get into civil penalties.  It gets into is it a cited or
     non-cited violation, if it's a regulatory requirement.
               MR. PARKER:  I think the burden is on us right
     now, though, and we need to be very careful in using SDP. 
     As Sonia pointed out, we haven't validated it yet with the
     licensees.  So it's a licensee -- if we have differing
     results, we need to step back and look at the reasonableness
     of theirs and why we have that discrepancy and make sure
     we're working with the program office and experts and the
     practitioners back in headquarters.
               DR. SIEBER:  There is some uncertainty, which
     could be quite large, going into all these things.  The
     question is, is it really different or is the uncertainty so
     large that they actually overlap.  That's the problem you'll
     have to deal with.
               MR. DAPAS:  And I think that's one of the most
     important aspects when the licensee brings their risk
     assessment to the table, is understanding the bounds of
     uncertainty and that gets back to the assumptions; that any
     risk conclusion is a function of the assumptions and that's
     something I think we wrestle with is the uncertainty.
               DR. SIEBER:  I see that as a challenge.
               MR. DAPAS:  Right.
               MR. GROBE:  I went to get back to the flexibility
     question, because I think that's critical to the ability of
     our programs to be predictive, and they're no longer
     predictive, and I'll use a case study, one that I'm familiar
     with, D.C. Cook.
               D.C. Cook would have been green and for years they
     would have been green.  Yet, we were never comfortable with
     their performance and particularly in the engineering area,
     and we applied a number of -- and this also gets to, I
     think, your question on lessons learned.
               We applied a number of special inspections over a
     period of three to four years, including an operations
     safety team inspection, what we called a system operations
     performance inspection, which had an engineering emphasis,
     and then we re-allocated one of our architect engineering
     inspections to Cook, because we still weren't comfortable.
               And it wasn't until we did that that we found the
     issues.  Those wouldn't have been found and they wouldn't
     have been revealed, I don't believe, through our PIs, at
     least looking back in history.
               There was a number of risk significant issues that
     were found after the plant shut down.  This is some of the
     soul-searching we did and it was emphasized by Chairman
     Jackson at the time that we do this.
               And we did two things, the lessons learned
     specifically on our inspection programs in the area of
     surveillance, because we didn't find the problems with the
     ice condensers at Cook, and it had to do with the way in
     which we were doing some surveillance testing activities.
               But more importantly, from a programmatic point of
     view, we looked at how we were looking at engineering and
     that really resulted in a safety system design inspection.
               We did not have as strong a design engineering
     emphasis in our program as we do today under the new
               So hopefully that new design engineering emphasis
     will help us reveal problems like Cook that we didn't find,
     and didn't find until we did the architect engineering
               MR. DAPAS:  Just to clarify, we did do a
     feasibility study that looked at the inspection issues at
     Cook and what would that result in terms of the action
     matrix, but as Jack said, taking that back one step, would
     the baseline program have resulted in the identification of
     those issues in order to assess the significance, and I
     think that's, as he pointed out, the genesis of a more
     comprehensive look at design via the safety system design
     inspection, because there is the recognition that
     performance indicators don't provide you the information you
     need to really get a good assessment of engineering
               DR. SIEBER:  Now, one of the industry initiatives
     is to change 303, I guess, so that you can change modes with
     something inoperable.  And if you had an incident at a plant
     or a condition that's screens green and the licensee shut
     down, you now would have lost another tool to keep them down
     until they fixed everything, before they start up again.
               What would you do in that instance?
               MR. DAPAS:  I'm not sure I fully follow the
               MR. GROBE:  Right now, if the licensee finds
     themselves in a situation where their technical
     specifications cause them to do something that is
     unnecessary, we have a process for dealing with that, the
     enforcement discretion process, and risk is a big
     contributor to that decision-making.
               I'm not aware of this initiative to do away with
               CHAIRMAN BARTON:  It's 304.
               MR. CALDWELL:  But that would require a change to
     the tech specs.  I mean, if the agency decided to allow them
     to change modes without certain pieces of equipment, then
     you're right, we would not have a dog in that fight.  We
     wouldn't be able to restrict them from starting up because
     of that particular component.
               But as far as I know, that hasn't occurred yet.
               DR. SIEBER:  I'm thinking about where we should be
     coming from as this issue matures.
               MR. DAPAS:  The tech specs, as I understand, are
     to prescribe which equipment is -- whose operation is
     important to assure you can respond to any kind of transient
     or impact on the plant.
               So if equipment is included in tech specs, the
     operability of that is --
               DR. SIEBER:  Where it is now is where it would be.
               MR. DAPAS:  Right.
               MR. GROBE:  Philosophically, it should be
     risk-informed, right?
               MR. DAPAS:  Right.
               MR. GROBE:  In which case, mode changes with risk
     significant equipment out of service shouldn't be committed.
               MR. CALDWELL:  I guess the big concern here would
     be if we did it generically.  I think each plant would have
     to say they're -- not get rid of 304, but to actually pick
     out the components they think are no longer required for
     specific modes and then you would have to do a risk analysis
     for each of those components.
               And if the agency were to agree, if the industry
     came in with a proposal that we shouldn't have mode
     restrictions based on equipment, then that would be a big
     concern, because you wouldn't have analyzed each component
     to see if it had a risk significance.
               DR. SIEBER:  The problem there is that most of
     those occur between the mode four and the mode three.
               MR. CALDWELL:  Right.
               DR. SIEBER:  Which there's not very many PRAs out
     there for that.  So what do you use for the tool?
               MR. GROBE:  It's an interesting question, because
     most of the safety systems are required at mode four and yet
     they're not necessary to mitigate an accident at that mode.
               MR. CALDWELL:  But they -- you're right.  It would
     be a philosophical discussion, because it is now a tool and
     a lever to make sure the plant is completely back in
     operation prior to changing modes.
               If you allowed folks to wait until the exact time
     when he component was needed, then you're running up against
     clocks and some people would put it off to the last minute
     and others wouldn't.
               Right now it works pretty good because licensees
     know, in their outage, that in order to come out of the
     outage, they have to have everything back and working.
               DR. SIEBER:  Right.  There's no way out.
               MR. CALDWELL:  It's been, I believe, successful in
     terms of plants are operating better coming out of outages
     now than they had in the past.
               DR. SIEBER:  I agree.
               MR. DAPAS:  Moving on to, I guess, insight number
     four that we offer regarding the new program compared to the
     old program.  The old program involved more direct
     observation of plant activities.  Under the new program,
     there is an increased emphasis on inspection preparation and
     office review, with, of course, the exception of testing,
     where we do continue to have a number of direct
               I'll give you an example, like maintenance.  Under
     the old program, we might observe the maintenance activity,
     like a pump rebuild, was the work procedure sufficiently
     comprehensive, are the steps being followed, et cetera.
               Under the new program, we focus on has the
     licensee conducted a risk assessment for that particular,
     say, on-line maintenance activity.  We would evaluate the
     effectiveness of that risk assessment and licensee control
     of the maintenance activity.
               And I thought Laura Collins, who actually has been
     an inspector under both the old program and then involved in
     the pilot program, could maybe give another example in terms
     of the maintenance rule, because I know there were some
     questions that.
               MS. COLLINS:  We actually have two procedures that
     we look at maintenance.  We have one that is called
     maintenance rule implementation and we have one I will talk
     about later, which is sort of our evaluation of their
     on-line risk assessments.
               Under the maintenance rule one, which is the
     resident inspectors' largest number of samples and largest
     number of hours, that is largely a review of equipment
     problems that they have had and how they've dealt with them
     under the maintenance rule, and that's quite a bit different
     from our previous maintenance observation kind of inspection
     that Mark talked about.
               So to me, that's a big distinct difference right
     there in the area of maintenance.
               The other one is the area of operations, which we
     largely reviewed routine operations.  Now we focus more on
     non-routine evolutions and don't look so much at the routine
               So those are just two examples of how we're not
     directly reviewing routine activities in the field.
               DR. SIEBER:  And that means much less observation
     of activities and more going through papers.
               MR. DAPAS:  The focus has shifted a little.  It's
     understanding the licensee's evaluation of risk associated
     with that activity, their control of that particular
               Inspection preparation, the inspectors need to
     understand the risk importance of a particular structure,
     system or component, or evolution that's being selected for
     the sample, and that's where there may be more preparation
     involved in saying, okay, here is a specific testing
     evolution I'm going to observe because it's important from a
     risk standpoint, and then the preparation involved with
     going out and reviewing that activity.
               But where that presents a challenge, that I'll
     talk about a little later, is the licensee may be planning
     to do a surveillance test tomorrow evening.  The resident
     inspector spends time getting ready to observe that and then
     it's deferred and the inspector was planning to do another
     activity on Thursday of that week.
               And we selected that specific surveillance test
     because it's more risk significant, where, under the old
     program, you could just pick another surveillance test and
     observe that.
               The risk importance was less of an issue, and
     that's where it impacts inspection planning and resource
               MR. GROBE:  We're getting way behind schedule.  I
     wanted to make one more observation regarding observation of
     activities.  In addition to some of the resident issues, in
     the plant support area, EPHP and safeguards, it's had a very
     significant impact.
               You can do the new safeguards inspection program
     from the guard shack.  You don't even have to go into the
     plant.  In the area of health physics, much fewer activities
     being observed in the plants as far as how they're
     controlling the activities from a radiological protection
     point of view.
               In the EP area, during the programmatic inspection
     it doesn't require you to go into any of the emergency
     planning facilities.  So you don't actually observe whether
     the facilities are in a state of readiness.
               A lot of these are compensated for through the
     PIs, the performance indicators, but in some cases, not very
               So there has been a shift from reviewing
     activities that have already occurred through looking at the
     paperwork to -- and away from direct observation in the
               DR. SIEBER:  How do you feel about that?
               MR. GROBE:  Our inspectors are not as comfortable
     with that as they were in the past.
               DR. WALLIS:  I'm wondering of the public would be
     as comfortable with that.
               MR. GROBE:  It's a new program and it's dependent
     on multiple prongs.  One of those prongs is performance
     indicators and another one is effectiveness of the
     licensee's corrective action system.  So we're putting our
     eggs in different baskets and we need to see how it works.
               MR. DAPAS:  But, also, when you look at the
     particular inspection procedure, there's associated
     objectives which are supposed to result in our acquiring the
     information we need, and that can be arrived at via direct
     observation or review of, for example, the licensee's
     control of the maintenance evolution.
               The key is do you obtain the information you need
     to make an informed judgment, from my perspective.
               MR. CALDWELL:  There is an ongoing feedback
     process.  These particular issues that Jack talked about are
     issues that we've fed back to the program office and will
     continue to feed back.
               So I expect to see some changes to the program
     after the first year of implementation.  So maybe a year
     from now, we can talk about it again and see where we come
     out on this.  These are just early observations.
               DR. SIEBER:  Have you made your thoughts known to
     the headquarters?
               MR. CALDWELL:  Certainly.
               MR. GROBE:  We do that and we've been rather
     proactive I that regard.  I think we've pretty much covered
     item number five.  Why don't we go on to item six.
               MR. DAPAS:  Regarding inspection resources, as
     we've touched upon, there was more flexibility under the old
     program, in a couple aspects.
               In addition to the inspection scope, where we
     talked about how prescriptive that can be under the new
     program, we had more opportunity with use of regional
     initiative, we had N+1 inspector, where you could use that
     particular inspector to conduct some regional initiative in
     the area of operations.  There was more flexibility with
     tapping DRS engineering resources to go out and do some
     regional initiative inspection.
               Now, under the new program, that DRS resource and
     that former N+1 resource, which now may be assigned to the
     region, is fully encumbered by the new program.  So there's
     less flexibility in that regard, which, of course, again,
     was by design with the new program and the inspection scope.
               But when you have extended absences or vacancies,
     that requires back-filling the complete program, and so that
     results in a greater degree of sophistication in inspection
     program management.  The branch chiefs out in the audience
     can tell you that they have to plan hours in detail for,
     say, a six-week inspection period so they can readily
     identify where there are holes and you can't -- you can only
     defer some inspection to a limited degree, because that
     creates the bow-way that you're going to have address during
     the next inspection period.
               And when you have sample size ramifications, the
     number of activities that you need to look at per month,
     that's where that becomes an issue.
               So we have to have contingency plans in place if
     we're going to support a rotational assignment to another
     program office or we've got a vacancy at a particular site
     because the individual left for a promotional opportunity or
     reassignment to the region.
               In order to implement the new program, we've got
     to have two fully engaged people at the site.  There is some
     flexibility there, but not a lot.  Frequently, you will hear
     a branch comment that I need some help during this time
     period because inspector X is going to be involved in this
     activity, and it causes is to continually focus on what are
     our priorities and what we can support, because we don't
     have the latitude right now of saying that we have completed
     the baseline program with this amount of inspection, like
     you could under the old program with the core inspection
               MR. GROBE:  I think as far as public awareness, we
     are greatly aware that the public is taking opportunity,
     taking advantage of the web site information that's
     available to them.  The PIs are on the web.  Our inspection
     reports are in the web, and that is a significant
     improvement over the --
               DR. WALLIS:  It's on the web.  Do you have a way
     of counting how many people -- how many times it's actually
     looked at?
               MR. GROBE:  Actually, Augie Specter counts it and
     reports on it regularly, in thousands of hits.  I can't
     remember what the numbers are.
               DR. WALLIS:  They actually stay with it.  They
     don't just hit and leave.
               MR. GROBE:  The question I got is how many of
     those were Augie logging on.  But he's counting those.  And
     I headed a public meeting out at Cook, a lady who called
     herself Auntie Nuke, who had downloaded a lot of stuff off
     the web.  So the public is taking advantage of it.
               DR. POWERS:  One of the things I find -- items
     that show up that say, in effect, management is very well
     prepared for the safety review, to be as helpful for me to
     understand the plant as those that say the operators didn't
     handle the jumper control very well.
               The upside and the downside are very valuable to
     me.  Now it sounds like the upside is going to be
               MR. GROBE:  No, it's gone.
               DR. POWERS:  It's gone.  And somehow I worry about
     the communication aspect, to me and everybody else.
               MR. GROBE:  We all shared your concerns, but it
     was the view of the industry that that's what they wanted
     from the standpoint of communication in our inspection
     report, and, by definition, that's what goes into the PIM
     and goes onto the web.
               MR. CALDWELL:  Well, our observations and findings
     that go into the PIM are supposed to be risk-informed and
     it's very difficult to risk-inform the positive.  So you
     wouldn't be able to do what you might like to do, and that's
     come up with a balance.  But a positive comment would weigh
     as heavily as a yellow or a white finding, in which case a
     positive comment may have little or no safety significance. 
     There is no way to evaluate that.
               So the decision was made to just --
               DR. POWERS:  Philosophically, George, I think he's
     hit upon a flaw in this PRA technology.
               DR. APOSTOLAKIS:  No, it has not been used.
               DR. POWERS:  It only gives us good ways to
     quantify the negative and no good ways to quantify the
               DR. APOSTOLAKIS:  That's what we have done so far,
     but one can actually say that because they're doing such and
     such, the human error probabilities that were assumed in the
     past are actually lower, so there's a positive impact on
     plant safety, or that the failure rates are expected to be
     on the lower side.
               DR. POWERS:  Your problem is one of communication,
               DR. APOSTOLAKIS:  Why?
               DR. POWERS:  That I can understand, well, a number
     going from three to four, as in
               DR. APOSTOLAKIS:  But not from three to two?
               DR. POWERS:  But the other way, the positive -- I
     mean, how do I understand going from 99 to 99.9?
               DR. APOSTOLAKIS:  It's just that we've never used
     it that way.
               DR. POWERS:  That's right.
               MS. BURGESS:  But I think you can understand that
     if a licensee puts -- adds another diesel, then I think
     everyone can understand they have decreased their risk.  So
     those kinds of things can be put into our report.
               DR. POWERS:  He tells me all the time that I can't
     assume they've decreased their risk.
               DR. APOSTOLAKIS:  I think that's a good point, but
     we can say something.  The thing is we've never attempted to
     say how improving things, if we're finding the good things. 
     I wanted to say something, but Dr. Powers destroyed my
               DR. POWERS:  I've been successful again today.
               CHAIRMAN BARTON:  Yes.  Before this deteriorates
     further, do you want to continue?
               DR. APOSTOLAKIS:  He probably can't even remember. 
     If everything is green, that is a message, right?
               DR. POWERS:  I insist that that's a degraded
               DR. APOSTOLAKIS:  And that's why people are trying
     to --
               DR. POWERS:  When everything is green, then you
     start looking at what are the shades of green and you see
     these things where guys plot where they lie on the green
     band and people start paying attention to that and not
     paying attention to the fact that it's green.
               MR. GROBE:  What's interesting is green is not
     good.  A green finding is a finding.  If you have 100 green
     findings, that's not better than having one green finding,
     that's worse, because that might be indicative of a systemic
               And the colorization, I have a lot of problems
     with these colors.
               DR. SEALE:  Amen.
               DR. APOSTOLAKIS:  So the ideal is no findings.
               MR. GROBE:  Well, no.  If we have no findings, my
     concern would be that the inspection program is not
     functioning effectively.
               MR. CALDWELL:  The idea should be that we're an
     active regulatory body, we're inspecting, we're having
     findings.  The findings are not such that it's outside of
     the industry response band, which means it's staying within
     a band that we're allowing them to correct their problems.
               That is a plus or minus, however you want to look
     at it.  If they drop out of that band, then people can ask
     questions about their safety.
               DR. APOSTOLAKIS:  But this raises, again, an issue
     that is a favorite of mine.  I've raised it several times,
     but I don't know that I got a response.
               CHAIRMAN BARTON:  So you're going to try again
               DR. APOSTOLAKIS:  Yes.  What is the purpose of
     these inspections?  I mean, there are two alternatives, in
     my mind.  One is to make sure that the risk profile of the
     plant, as we're understanding through the IPE and PRA,
     remains the same, especially hasn't shifted upwards.  So
     that's a plant-specific finding or determination.
               The other is to look at it as one unit in the
     population of 103 units and see whether you are -- I mean,
     that particular unit is within the industry norm or it's a
     percentile.  These are two very different things.
               And the third one, I guess, is to make sure that
     the licensing basis is still met, which is not -- it is
     related to the risk profile, but it's not the same thing.
               And I'm not sure that the designers of this
     process really articulated very well what their objective
     was.  In some instances, I get answers that, yeah, it's
     industry-wide, we're very interested in what's happening, is
     this an outlier or not.  In other cases, no, we really want
     this plant to remain the way it was risk-wise.
               So what, in your opinion, is the objective of all
     of this?  I mean, we have a risk profile, we have in the
     PRA, you do all these determinations such as PIs and the
     action matrix and so on, because that's related to the green
     now, because if everything is green and I can conclude that
     the risk profile has not changed, then things should be all
               Because then I get into the business of how many
     greens do I have, how many findings, one versus 100.
               MR. GROBE:  Possibly.  I wouldn't suggest you
     count findings, but what's important is to understand the
     root cause of the findings and what that root cause can do
     to the risk profile.
               DR. APOSTOLAKIS:  So the potential for getting out
     of the green.
               MR. GROBE:  Exactly.
               DR. APOSTOLAKIS:  That's what you worry about.
               MR. GROBE:  Exactly.
               DR. APOSTOLAKIS:  But have you any idea as to what
     the intent of the oversight process is?
               MR. DAPAS:  Both aspects are addressed.  When you
     have a particular inspection finding, that's got to be
     placed in the appropriate context of a given plant
     configuration.  You have to bring plant-specific PRA
     knowledge to bear.
               I think the performance indicators address that
     across the industry, where if we set a threshold for number
     of scrams that would result in regulatory engagement, that
     threshold is a function of overall industry performance.
               DR. APOSTOLAKIS:  And it shouldn't be, in my view.
               MR. DAPAS:  That may be a few, but that's at least
     my understanding of the intent of the program.
               DR. APOSTOLAKIS:  The inspection findings are
     plant-specific, but the PRAs are --
               MR. DAPAS:  Well, the PI is plant-specific, if you
     will, in terms of you had scram X, you had transient X, but
     the threshold --
               DR. APOSTOLAKIS:  It's an industry --
               MR. GROBE:  And the same thing with inspection
     findings in the SDP.  The base risk profile of a plant might
     be five-ten-to-the-minus-five, it might be
     one-ten-to-the-minus-seven, but the threshold for a green
     finding is ten-to-the-minus-six, no matter what the base PRA
     of that plant is.
               DR. APOSTOLAKIS:  But, you see, the fact that the
     thresholds are so high has made the utilities themselves to
     have more stringent plant-specific thresholds for internal
               MR. DAPAS:  Right.  And the reason for that is
     because we told the industry they shouldn't be using our PIs
     to manage their plant.  I would expect them to have more
     restrictive, if you will, indicators so that they can
     address problems before it does cross the threshold.
               MR. CALDWELL:  That goes back to what Marc had
     mentioned earlier.  The basis of this program is an
     effective problem identification and corrective action
     program on the part of the licensee.  So they have to have
     in place their performance indicators or whatever they think
     is necessary to identify their problems early and resolve
     them before they become bigger issues.
               That is what we are relying on.  We have to see
     now if that works or not by implementing this program and
     see how well the licensees' corrective action programs --
     how effective they are.
               DR. BONACA:  But you said before that D.C. Cook
     would have been all green.
               MR. GROBE:  It was all green.
               DR. BONACA:  So there would have been no signal
     coming from the indicators for action.  So does it mean that
     the action at D.C. Cook was successive or does it mean that
     the indicators really have been a big help?
               MR. CALDWELL:  I missed that conversation.  I
     think Jack is saying the performance indicators may have
     been all green.  I'm not sure our inspection findings would
     have been all green.  Our inspection findings likely would
     have been something other than green.
               DR. BONACA:  So you didn't check for that.
               MR. GROBE:  No, we did.  We ran all the LERs and
     findings prior to the outage through the -- at that time, it
     was a very preliminary draft SDP, and didn't come up with
     any significant findings.
               I don't know if we came up with any whites, but it
     wasn't until after the outage that you started seeing
     yellows and reds.
               The point I was trying to make was that the level
     of resource expenditure that we put into Cook, we would not
     be able to do today.  And somebody earlier mentioned that
     the program is more indicative than predictive, and that's
     true.  We have less capability of being predictive, unless
     the thresholds are crossed with a specific finding.
               MR. DAPAS:  And that gets back to, if you recall,
     our discussion with the Commission.  One of the fundamental
     premises that the industry proposes is that performance
     indicators would be crossed, threshold changes before there
     is a significant programmatic concern that manifests itself.
               Right now, I think there are some differing
     schools of thought and that's why the role of cross-cutting
     issues, I think, has played such -- the importance of that
     has been elevated.
               There is a task force that's looking at human
     performance and corrective action programs and safety
     conscious work environment, cross-cutting issues, because
     not everyone full ascribes to this tenet that you will see
     performance decline clearly manifested in the PIs before you
     see risk significant inspection findings.
               DR. POWERS:  The committee has advised the
     Commission that we consider that an assumption that needs to
     be validated.  You're only reinforcing that opinion.
               MR. GROBE:  The lunchroom across the way gets busy
     at around noon.
               MR. CALDWELL:  What we're doing is we're having --
     they're bringing over sandwiches and some salads.
               CHAIRMAN BARTON:  We'll just keep going then.
               MR. CALDWELL:  So I can let you know, it's $10 a
     person, and we should be bringing -- we'll bring a table in
     right behind here and you can go over and pick up and eat as
     you wish.
               CHAIRMAN BARTON:  Excellent.  I'd like to get
     through the SRA process before lunch, then we can take a
     break, if we can get to it.
               MR. DAPAS:  I've just got one point left to make
     on the public awareness.  I think clearly there has been a
     public outreach effort associated with the new program,
     industry workshops, et cetera, which I think is a positive
               We have touched upon the DRP --
               DR. WALLIS:  Well, public outreach, how broad is
     the public that gets involved?  Public outreach, how broad
     is the public involved?
               MR. DAPAS:  We've invited, like, for example, when
     we've conducted meetings on the new program and we're going
     forward with meetings at each of the sites within six months
     of initial implementation.  Certain officials, et cetera,
     we're inviting, but it varies, the degree of public
               We're trying to advertise that via web and other
     communication forums, but it does vary.
               MR. GROBE:  We don't see a lot of public awareness
     -- public involvement.
               MR. DAPAS:  It depends on the site.
               DR. WALLIS:  Public should not consist only of
     people with some personal interest, like an economic
     viability of their plant.
               MR. DAPAS:  Right.  Right.
               MR. CALDWELL:  It's strictly -- I think it's
     strictly related to how interested the surrounding area is
     in that plant and most of our plants do not have active
     public involvement.  So when we have these meetings, they
     are not widely attended.
               But we do put out a lot of announcements to that
     effect and people could attend, if they wanted.  And I
     suspect if there was an interest, like one of our
     facilities, Prairie Island, there's an interest in dry cask
     storage.  And so we always get a pretty good attendance at
     those.  But it's really related to how well the public - I
     look at it this way.  If you don't get a lot of public
     attendance, that means that they feel comfortable with that
     plant as it is.
               Otherwise, they would be coming to the meeting to
     try to understand or express their views.
               MR. DAPAS:  My comment was more in the context of
     the old program, where really the only public outreach, I
     would offer, was a meeting to discuss SALP results, versus a
     more concerted effort.
               I've touched upon some of the DRP challenges here. 
     One of the challenges we face, of course, is feedback and
     dissemination of lessons learned on the new program as we
     attempt to further revise that, and there's a number of
     forums for doing that.   
               We've got feedback forms, weekly conference calls
     with the program office, inspector seminars, and then, of
     course, DRP/DRS counterpart meetings, where Jack and Mike
     and Geoff Grant attend to discuss some issues with the new
               DR. WALLIS:  One measure of success might be that
     there were lessons learned which were useful when you
     actually look back at it.
               MR. DAPAS:  Right.  Which gets into the
     self-assessment area.  We have been given an opportunity to
     weigh in and comment on the self-assessment plan
     development, which includes appropriate metrics, and this is
     in support of the IOU we have to the Commission to evaluate
     the new program and report to the Commission in June.
               And headquarters is currently involved in our
     inspection report review to help ensure consistency and we
     do plan public workshops to obtain feedback, which was
     fairly well received in the pilot program.
               Unless there are any questions, that pretty much
     summarizes DRP's involvement in the new and old programs.
               MR. GROBE:  Let me just highlight one challenge
     that we're going to be talking about a little more later, I
     hope, in the Division of Reactor Safety.  There's a number
     listed here, but the one that's most significant for us is a
     change in required expertise.
               We depended heavily on contract resources when we
     needed design expertise in the past.  We no longer have the
     financial resources to procure contract resources in that
               So that's a challenge for us.  It's a staffing
     challenge.  It's a recruiting challenge, and we're trying to
     meet that and we'll get into some more detail later.
               The other issue is risk analysis capability and
     why don't we just go right into the risk presentation that
     Sonia has prepared.
               MS. BURGESS:  Here's a little background.  In
     October of 1995, the SRA position was developed to assist
     the agency in transitioning to a new risk-informed arena in
     the way we do business.
               I don't believe that in 1995 the Commission
     realized what a large leap we were going to make ultimately
     into getting our whole process into the risk-informed arena.
               Fortunately, when the transition, the pilots, the
     new reactor oversight pilot program started, the SRA program
     was fully staffed in all of the regions and we were fully
     trained and qualified and certified.
               I think that has been a big asset in the success
     we have had in implementing the new reactor oversight
               Some of the bullets highlighted here are just some
     of the key things that we do here in the region.  Our
     biggest role right now is to support the new oversight
               We were very much involved in the development and
     the implementation of a pilot process here in the region and
     we sat on a lot of committees, helped in reviewing many
     procedures, things of that nature.
               Our main support now is in the SDP arena.  As has
     been brought up, Mike and I have visited every site in our
     region, because we think it's imperative that these SDP
     tools that we have been giving to the inspectors are
     accurate, that the licensee agrees that they're accurate,
     and that they are -- although simplified, they are the best
     tool that we have produced to date.
               DR. POWERS:  The question that often comes up, to
     my mind, is the scenarios they have are very simplified. 
     Are they simplified by intent or out of necessity?
               MS. BURGESS:  The scenarios on the SDP worksheets,
     like the loss of off-site power?
               DR. POWERS:  Right.
               MS. BURGESS:  I think, yes, they're definitely
     simplified out of necessity.  We certainly do not have the
     resources of the capability to model 50 initiating events
     and that's typical of a licensee's own PRA analysis.  So we
     have narrowed it down to probably ten to 12 initiating
     events.  Has there ever been a demonstration that -- with
     some rigor -- that narrowing it down to these ten or 11
     events constituted an adequate description of the risk
     profile of the plant?
               DR. POWERS:  Yes.  And in our site visits, along
     with the other regions, these scenarios, these initiating
     event scenarios have captured the majority of the risk
     contribution from their PRAs.
               MR. PARKER:  I would also add that we started out
     with, I think, four to six initiators and we did some pilot
     activities with the program office.  One of them was one of
     our plants in the region.     
               We went there and tried to do some V&V by taking
     some scenarios, some major systems and correlating it with
     the licensee's PRA and we found some non-conservative in
     ours, where the licensee identified it as a fairly high risk
               And that's where we had to step back, as an
     agency, and I think it set us back several months, trying to
     identify additional initiators that were necessary to truly
     capture the majority of the risks, as Sonia says, that we
     are right now, that we were able to pick that up.
               DR. POWERS:  I might be willing to concede they
     captured the CDF.  The question is, did they capture the
               MR. PARKER:  That's some of the -- I mean, right
     now, what we're looking at is internal events and some of
     the difficulty we have in using the tool is we don't have an
     effective took in place for containment, for shutdown, for
     external events.  So there's a lot of -- the majority of the
     risk is still being captured through screening tools that
     we're trying to put in place right now and when we have
     those type of issues, that Sonia and I have to get involved
     with it, we have to get involved with the licensee's IPEEE,
     and we have to work with headquarters in a lot of cases if
     it involves external events, it's just a screening basis in
               So we might not be able to capture all that
               MR. DAPAS:  A good example of that is a recent
     issue we had at Quad Cities with -- what is it, Marc -- safe
     shutdown makeup pump and that being unavailable and how you
     bring the external event fire risk into play.  There's not a
     tool used.  We used risk achievement worth, I think, and CDF
     to come up with an overall risk assessment.
               We discussed it as part of the significance
     determination panel.  We communicated that to the licensee
     as the most appropriate tool we have right now and then the
     licensee is going to come to the table with their assessment
     of the risk impact in terms of fire risk.
               DR. POWERS:  So you don't even have things like
     five available to you.
               MR. PARKER:  No.
               MS. BURGESS:  No.
               DR. POWERS:  One of the -- an anecdote, to which
     I've never had a resolution, is I believe it's Brown's Ferry
     that uses ORAM for outage management and they were showing
     me how it worked.  I know a little bit about ORAM.
               And they said, well, look for this particular
     outage, we set up a configuration that had this red region
     and by manipulating things around, we were able to change
     the way we did our outage, so that instead of having a red
     region and everything else green, we had two orange regions
     and everything else green.
               And I have puzzled and puzzled to understand how
     one concludes that two oranges is better than one red.
               MR. PARKER:  That, I think, is some of the
     difficulty in ORAM, is it's mainly a deterministic tool and
     you're looking at defense-in-depth and most utilities don't
     have a probabilistic shutdown model.
     I think some of the plants are going there and we might be
     able to look at it a little closer, but you pointed out some
     of the difficulties we have with our tools.  The licensees
     are trying to suppress and reduce their overall risk and
     from their perspective, they didn't enter a red, which was
     prohibited, and it's very subjective and that's
               DR. WALLIS:  When you compare with the licensee's
     PRA, you just compare with the results or you compare with
     the details?
               MR. PARKER:  You're talking about SDP?
               DR. WALLIS:  Yes.
               MR. PARKER:  When we're looking at findings?
               DR. WALLIS:  Looking at your model versus the
     licensee's.  You have a simplified model.  How much of his
     PRA do you have access to?
               MR. PARKER:  We have very little access to most of
     the PRAs, but when we did some of our benchmarking, we
     wanted to get the cut-sets and the importance from there so
     we can extract that and figure out what were the dominant
     cut-sets that were affecting our SDP model.
               DR. WALLIS:  It's a peculiar kind of detective
     work, or maybe there are some assumptions made that you
     don't know anything about.
               MR. PARKER:  That's right.
               DR. WALLIS:  Which is reducing the licensee's
     result.  Don't you have a way of finding out what they are?
               MS. BURGESS:  Only if there is an issue or a
     finding in that.  I mean, we don't have a PRA inspection.
               MR. PARKER:  I think you're stepping back to what
     I would call the infrastructure.  We still haven't even
     established a PRA certification.  But on the other hand, we
     are basing our SDP as closely as we can to the licensee's
     IPE or their updated PRA model, and we haven't validated
     that model yet.
               So I understand and appreciate your comment and I
     think the agency is pursuing that, but, again, we're
     progressing slowly.  Maybe there's different things we need
     to prioritize in this arena, too.
               MR. DAPAS:  There is a conceptual issue here,
     though.  I think we -- if a piece of equipment is failed or
     unavailable, we run that through the SDP, we communication
     the results of that, then the licensee can bring to the
     table more risk-specific information from their PRA.
               Now, obviously, when we've got an issue and we're
     running it through the SDP, the licensee is doing the same
     thing, because they understand the SDP, we've communicated
     to them, 0609 defines specifically what that SDP tool is.
               If it looks like this is going to screen out as a
     white finding, they're rather proactive in communicating to
     us their assumptions and what their PRA model says.  So
     there is that dialogue.
               DR. WALLIS:  Assumption is the key word, because
     assumption really is not worth anything unless it can be
     challenged and defended.  And if there is some mysterious
     assumption you don't know about, that's like magic.  It's
     just like getting whatever you want.
               MR. DAPAS:  We should challenge that.
               MR. GROBE:  Your point is very good, and that is
     that we don't know what the assumptions are in the model. 
     The IPE that the staff reviewed a number of years ago was
     many generations earlier than what is currently being used
     at the sites.
               So to a large extent, we have to depend upon the
     -- that there has been an intelligent evolution of the model
     that the licensees use.
               DR. BONACA:  On the other hand, the event,
     whatever you're evaluating, it's a fact.  So you know what
     you're going to check inside the model.  It's not
     hypothetical issues.
               In general, you may question their assumptions in
     the model to represent the --
               DR. APOSTOLAKIS:  Do we --
               DR. BONACA:  But now the fact that you have a
     specific event happening, it allows you to go back and
     verify the assumptions.
               MR. GROBE:  But they don't have it here.  Is that
     part of the SDP, the phase three?
               MS. BURGESS:  Phase three.  Phase three will
     challenge the licensee's assumptions, where we're different,
     and take a look at what their program does, what their
     assumptions are, and the validity of those assumptions.
               DR. APOSTOLAKIS:  What, in your opinion, would be
     the ideal tool that should be available to implement a
     risk-informed regulatory system, especially the oversight
     process?  What would you like to have?
               MS. BURGESS:  Personally, I think that some kind
     of standard for a PRA is just essential.
               DR. APOSTOLAKIS:  But you would also like to have
     a plant-specific PRA on the computer.
               MR. PARKER:  Right now we have safety monitoring
     and I guess my perspective is to be able to have access to
     the licensee's plant models and be able to manipulate them
     and understand them.  But we need to start where Sonia says,
     that we certify your PRA or have some level of certification
     to say this PRA meets certain thresholds and standards.
               DR. APOSTOLAKIS:  Let's take a specific plant,
     like Davis-Besse.  What PRA information do you have?
               MS. BURGESS:  In fact, I was there two weeks ago
     to do their SDP worksheets.  They have gone through an
     extensive PRA update.  Prior to my visit, the only thing we
     had was what was documented in late 1980s.
               DR. APOSTOLAKIS:  But do you have --
               MS. BURGESS:  We have the docketed IPE here, which
     is --
               DR. APOSTOLAKIS:  The PRA as they changed it.
               MS. BURGESS:  I was able to bring back, from my
     visit of two weeks ago, the executive summaries, some of the
     system notebooks that are used in the service water systems,
     component cooling water.  I was able to get risk achievement
     worth, a lot of importance measures of systems, things like
     that.  They give us a better idea of how they have changed
     their --
               DR. APOSTOLAKIS:  I don't understand why they
     don't give you the whole PRA.
               MR. PARKER:  Because we haven't mandated it.  It's
     not required through the regulations and no utility --
               DR. APOSTOLAKIS:  The risk achievement worth is
     not required either.
               MR. PARKER:  I understand, but I guess what -- you
     said this is our chance.  I would like to see us have some
     type of requirement or standard where the utilities are
     providing us their routine updates, no different than they
     would on an FSAR.  That's a difficulty we're having right
     now with our SDP tool.
               The SDP tool was put together by BNL, Brookhaven
     National Lab, using the IPE and the SRAs are having to go
     out and reevaluate that based on the licensees' current
     models.  So significant changes are taking place.
               DR. APOSTOLAKIS:  We have been told by some
     licensees that they have -- especially the ones who have
     risk monitors -- they have PC versions of their PRA, they
     can see the impact of the change within a minute.
               MR. GROBE:  On-line risk monitor.
               DR. APOSTOLAKIS:  Sure.  Would you like to have
     something like that?
               MS. BURGESS:  Yes.  Now, we do have -- like Mike
     said, we do have safety monitor.  Unfortunately --
               MR. PARKER:  We have the program.
               MS. BURGESS:  We have the program and we have the
     eight models, which are like the Westinghouse tool for a
     Westinghouse four-loop or things like that.  We do not have
     plant-specific models.
               Now, some plants in our region -- as a case in
     point, Kewaunee has given Research their program, their
     model, and Research has given it to INEL and INEL is in the
     process of converting it to SAPHIRE.  So we have their
     actual model.
               DR. APOSTOLAKIS:  Now, wouldn't the SPAR models
     eventually meet the needs you have when INEL completes --
               MR. PARKER:  I think there is a potential that it
     could meet most of our needs.  The difficulty is going to be
     they're working on low power shutdown models.  They're
     working on some containment and those have -- a lot of that
     activity has been deferred because of the SDP activities in
     progress that we can't -- we weren't able -- there are
     competing resources.
               So I don't see us getting there for several years.
               MR. GROBE:  We're significantly resource
               DR. APOSTOLAKIS:  But you mentioned that the
     licensee is under no obligation to give you the PRA.  But
     isn't it in their best interest to do that?
               MS. BURGESS:  We believe it is.
               DR. APOSTOLAKIS:  I mean, if they want
     risk-informed regulation, we can't do it without risk
               MR. GROBE:  We've been able to encourage several
     licensees, just from an efficiency point of view, of
     interacting with the staff, encouraged them to give us some
     of their risk analyses.
               The problem is, as Sonia and Mike have pointed
     out, one, is that there is no standard.  So you have widely
     differing approaches, and second is there is no requirement
     to provide it.
               So it's only a phone call from Steve or myself
     that says, listen, our interface would be much more
     efficient if we had such and such and then we'll get some
               DR. WALLIS:  I'm not sure you need the standard. 
     If I look at thermal hydraulic codes, it used to be that the
     staff would simply look at some codes provided by licensees. 
     But now in reviewing thermal hydraulic code, the staff is
     moving to the position we want the code, we want the source
     code, we want to be able to run it, we want to be able to
     try things with it and see what it does.
               MS. BURGESS:  Many licensees are very reluctant to
     put their updated PRA on the docket.
               DR. WALLIS:  But ideally that's what it should be. 
     It should be completely open.
               MS. BURGESS:  They just do not wish to have it on
     the docket.
               DR. POWERS:  If you can think about the headaches
     it would involve when it's updated, it's a significant
               Let me ask you.  You've mentioned this need for
     certification a lot and there is an activity going on with
     the standards committee to set the standard for the PRA, and
     I think NRC has a limited voice in that committee setting
     that up.
               Do you have a voice with those representatives on
     that committee?
               MS. BURGESS:  The regions?
               DR. POWERS:  Yes.
               MS. BURGESS:  No, we don't have a particular
     voice.  Research is the member of that committee and I would
     characterize their participation as much more than just a
     minor committee member.
               DR. POWERS:  Mary Drouin and her troops.
               DR. SEALE:  That confirms what we found out from
     them last week.
               MR. DAPAS:  We're not precluded from providing
     input there.  If Mary Drouin is the representative, I've
     worked with Mary, I know Sonia.  We'd have no problem
     calling her up and saying, hey, we think this needs to be
               So we are not precluded from that opportunity, but
     there is not an outreach effort, if you will.
               DR. SEALE:  You're not getting timely information
     on what the status of that -- the evolution of that
     so-called certification process.
               MR. DAPAS:  Nobody else is either.  Other than
     what I read in the PRA implementation plan updated
     Commission paper.
               DR. POWERS:  It seems to me that -- I think
     there's a wealth of information at that tend of the table on
     what the minimums ought to look like, just because of the
     pain, it's knowledge that's been gained by pain.
               I'm wondering if we can't find a mechanism to do a
     download so that there is some hope that maybe that gets
     represented in the standard, because the last thing you want
     to do is get a standard back that's no good to you, that
     doesn't standardize the things that you want standardized.
               DR. SIEBER:  It's harder to undo that kind of a
     thing than it is to write it in the first place.
               DR. APOSTOLAKIS:  Will you have an opportunity to
     comment on the ASME standard?  I mean, the public is
     welcome, so you are welcome, too.
               MS. BURGESS:  I believe the region will have a --
               MR. PARKER:  More than likely, Research has been
     very accommodating in requesting our resources to comment
     and provide feedback to all the new inspection processes and
     generally the NUREGs that are coming out, too.  So I would
     see no difference in this regard.
               DR. APOSTOLAKIS:  There is a workshop, as you
     probably know, on the 27th of this month.  Do you plan to
               MS. BURGESS:  No.
               DR. POWERS:  They've got more than they can keep
     up with as it is.
               MS. BURGESS:  Yes.  We've been very busy.
               MR. DAPAS:  But, George, not to convey we don't
     think that's an important activity.  Like verification and
     phase two workshops we think is a high priority, as well, so
     that we can ensure we're capturing the licensee
     plant-specific information.
               So there's competing priorities we're trying to
     wrestle with.
     DR. APOSTOLAKIS:  Is it fair to say that we risk-inform the
     regulations with very limited risk information on our part?
               MS. BURGESS:  Yes.
               DR. POWERS:  When you look at this risk-informed
     regulation, only a third of it is risk-informed.  The rest
     of it is something.
               MR. GROBE:  It's all risk-informed, it's to a
               DR. APOSTOLAKIS:  It's not quantitative.
               DR. POWERS:  This is the argument I sometimes make
     with the gentleman to my left and say we've always done
     risk-informed regulation, we didn't write these regulations
     because we didn't think there was any risk there.
               DR. APOSTOLAKIS:  That's right, and I have been
     persuaded, as always when I hear a reasonable argument.
               CHAIRMAN BARTON:  All right.  Where are we here?
               DR. APOSTOLAKIS:  I think Sonia is telling us --
     the last four bullets, we understand that you're doing that. 
     Do you want to move on to --
               MS. BURGESS:  One initiative that we actually -- I
     did want to make a point, the initiative that we are doing
     that we are going to -- we're doing outage risk assessments. 
     The plant is in an outage, Mike and I will go out to a site,
     sit down with the scheduling people of the outage from the
     licensee, understand where their risk significant evolutions
     are and helping to focus the resident staff on what to look
     at out, what to be observant of, what the most risk
     significant issues and evolution is.
               DR. POWERS:  Do you have an understanding of what
     the risk significant evolutions are during an outage, can
     you tell me?
               MS. BURGESS:  Quite honestly, I think that our new
     inspection procedure for outage work is pretty good on
     hitting PWR/BWR risk significant evolutions, from a broad
     perspective, to give, I think, excellent guidance to the
     resident staff.
               DR. POWERS:  I'll look at it.
               MR. GROBE:  What we found is that the licensee's
     risk analysts aren't getting involved early enough in
     looking at the outage plan.  We have been prepared to go out
     and look at the outage plan and the risk analysts, in some
     cases, haven't even started looking at it.
               Are you asking the question because we haven't
     really developed a shutdown risk model yet?
               DR. POWERS:  The committee has had the chance to
     review a proposed rule in the area of shutdown regulation,
     and rejected it, fairly sternly, on the basis that we didn't
     feel like we had risk information about shutdown sufficient
     to know what to regulate, and asked that Research undertake
     a study to develop a risk profile during shutdown
     operations, not only planned outages, but unplanned outages,
     as well, and that has not progressed.
               So as a result, I don't have the kind of
     information base of what constitutes risk-significant
     evolutions during outages that I have for normal operations
     gained from things like the beginning of WASH-1400 and up to
     NUREG 1150, and even the IPE insights document I find a
     wonderful source of information about what is risky in a
     plant during operations.
               But I don't have that for outages.  I've got a
     huge inventory of, which I seem to now have a hobby of
     collecting, of incidents that occur during various types of
     outages and I know the kinds of things that get you in
     trouble and I'm sure I could write a regulation to make sure
     those things never happen again and I find, in general, they
     don't ever happen again, people correct things.
               But I don't have a feeling for how you get into
     these problems and what kinds of things to look for.
               MR. PARKER:  And you bring up a good point. 
     That's what we're trying to do is look at those issues,
     those risk insights that we have some knowledge on, but
     we're using the tools defense-in-depth and some of the NEI
     guidance to say, hey, mid-loop operation and different
     operations like that are highly risk significant conditions
     and that's the one tool we have.
               But to go back to your point, the one opportunity
     that we have is Perry is developing the shutdown model and
     they intend to put that on their safety monitor, where they
     will be able to have a probabilistic on-line risk monitor,
     and it will be very interesting to be able to tie that into
     their outage coming up next February.
               But they hope to have it in place so they can use
     it for their outage planning activities and that will be a
     unique opportunity for us in the region to be able to see if
     there's any insights that come out of that and share it with
     other plants.
               DR. POWERS:  I think these things are all good.  I
     wish that you would have the kind of data that's in the PRA
     community about the details of these models, because I know
     that we have substantial questions about how you go about
     modeling human error in these kinds of situations, which are
     very different from operational situations.
               And I don't see the kind of debate between
     gentlemen, such as on my left, and his peers on how you go
     about doing that modeling that I have seen in connection
     with operational events and see the way that you set up the
     structure, the fault trees and event trees for shutdown
     events and the detailed discussions and the philosophy that
     I see for operational events.
               And so these things get created, I'm glad, and
     they're going to help a lot, just like you said, but I would
     -- I'm not sure they raise my comfort level an awful lot.
               MR. PARKER:  Well, that's what stirred up my
     interest as far as certification.  When we went out and did
     the SDP activities, to look at some of the human performance
     that we're crediting in our SDP that we have generic values,
     ten-to-the-minus-one for a high stress and
     ten-to-the-minus-two, and then we see the utility call it a
     ten-to-the-minus-four for the same thing, we haven't
     validated that and we're very uncomfortable and headquarters
     is stepping back and looking, is it appropriate to use the
     licensee's numbers versus ours.
               And when we have an issue that results in a human
     performance, how do we deal with that and where do we go; do
     we step back and look at the licensee's assumptions and
     their basis and validation behind that.
               So there's a lot of questions in that area where
     human performance becomes a real issue.
               MR. DAPAS:  That underscores the need for some
     type of standard, in my view.  From my perspective, your
     comments are clearly valid about we have limited
     risk-informed our processes.  You're attempting to use the
     tools you have.  If the licensee is proactive, like they are
     at Perry, you want to learn from that.
               I think in the interim, though, we've tried to
     come up with the SDP, recognizing its limitations, and we
     have some tool to use to assess significance until we maybe
     develop some standard where the licensee says here is my PRA
     and we have confidence that it's sufficiently rigorous and
     we can use that in our determination of risk.
               Right now, we have this --
               DR. APOSTOLAKIS:  But will the licensee say here
     is my PRA?
               MR. DAPAS:  They don't have to right now.
               DR. APOSTOLAKIS:  So does the Commission know that
     you are a little bit constrained in your efforts?
               MS. BURGESS:  Yes.
               MR. DAPAS:  I hope so.
               DR. POWERS:  They should understand the
     limitations of the SDP.
               DR. APOSTOLAKIS:  But, I mean, in order to
     understand -- if we are the only ones, it doesn't work.
               DR. POWERS:  They have asked for us to talk to
     them on the SDP, on whether the PIs are truthfully risk
     significant.  I don't think they're ready for the answer
     we're going to give them.  And since I get to be the
     messenger, I may be dead next week.
               MS. BURGESS:  Slide 28 just highlights three
     bullets, that the SRAs in the region are extremely involved
     in the new process, very active and very busy just resolving
     findings and issues that inspectors from DRS and DRP are
     bringing to the table, running through the SDP process.
               Since these worksheets are not yet completed, done
     with the revisions, the SRAs are involved in almost every
               DR. POWERS:  I understand people are looking into
     expanding the workforce of SRAs.
               MR. GROBE:  We can talk about that a little bit.
               MR. DAPAS:  That's one of the staffing challenges
     Jack mentioned.
               MR. GROBE:  Yes.  Could we hold off on that?
               DR. POWERS:  Sure.
               MR. GROBE:  Because we have another staffing
     issue.  There is one thing we haven't touched on with Mike
     and Sonia that we talked about briefly earlier was how the
     SRAs and risk analysts are going to get involved in event
     response.  We've only had one substantive event since the
     new program went into force, and that was at Palisades.
               And what we found was that there was a disconnect
     between management's expectation of what could be provided
     and what we actually had the capability to do.
               So why don't you guys talk a little bit about how
     Palisades went and what we expect to be able to perform in
     the future, how we expect to be able to perform?
               MS. BURGESS:  With any event, preliminary
     information is just that, preliminary, and it seems to
     change minute by minute.  So with the best information that
     we get, based on a senior resident at the site giving us, we
     were able to probably within an hour or an hour and a half
     give a rough big picture estimate of the situation of the
     event, conditional core damage probability.
               DR. POWERS:  I just have to interject an anecdote. 
     In the hours following the Chernobyl accident, they called
     Moscow to explain they had an accident and the guy on site
     says, well, they've had accident here, but things don't look
     too bad.
               That shows you how good preliminary information
     can be.
               MR. DAPAS:  Pretty gross estimate.
               DR. SIEBER:  It's all relative.
               MR. GROBE:  But our residents have a little bit
     more flexibility to speak what's on their mind.
               MS. BURGESS:  So we're able to give -- we have
     limited tools with the SAPHIRE model and the GEM model and
     obviously our model is not as extensive as the licensee is
     being able to model certain components and that, but I think
     we are able to provide a rough estimate, for event response
     purposes, of whether we need to send a special inspection or
     an EIT or an IIT.
               I think in a lot of cases, definitely IIT is going
     to be self-revealing anyway.
               DR. POWERS:  You're saying that you've got enough
     information that you can provide information to management
     to make these kinds of decisions.
               MR. DAPAS:  Right.  Do we need a special
     inspection?  Are we comfortable that we have the big deal
     threshold or do we have time to acquire additional
     information and then maybe we need to send another inspector
     from another site versus --
               DR. POWERS:  When you decide, you make a decision
     and say I'm going to send a special inspection team to get
     to the bottom of this.  You give that team a charter.
               MR. DAPAS:  Correct.
               DR. POWERS:  And you have enough information to
     give a charter.
               MR. GROBE:  The charter is developed within the
     first couple hours.
               DR. POWERS:  But when they do their best, they've
     had their week or maybe a weekend, they never occur at good
     times, right?  You've had -- and they've brought forth what
     they need.  Can you write what you would say is a good
     risk-informed charter from one of these AITs or IITs?
               MS. BURGESS:  I believe we can.  Just in the past,
     before the probabilistic risk insight was used, we also used
     deterministic risk insights.  And our charters were very
     right on the money when we sent out a team and I don't see
     any difference now that the probabilistic risk insight is
               I think we can do a very capable job of giving a
     real good charter to the team.
               MR. DAPAS:  But I think we would focus on things
     like is the licensee evaluating the risk significance, is
     the licensee trying to determine extended condition, is the
     licensee conducting a root cause, and, if not, we would
     challenge the licensee.  And, again, that assumes that there
     is clearly risk significance associated with this that
     prompted us to send the special inspection.
               MR. SINGH:  I want to ask a question.  SRA is a
     part of the AIT team most of the time?
               MS. BURGESS:  Not necessarily.  It's dependent.
               MR. GROBE:  The last time we went an SRA out was
     the tornado that hit Davis-Besse.  That was a year and a
     half ago or so.
               MR. PARKER:  The flexibility is in the program
     that if they think that there is a potential that there is
     some uncertainty or some concerns that we have, that they
     can --
               MR. SINGH:  How about, say, if you have an
     inspection team inspection, do you have an SRA as part of
     the team?
               MR. GROBE:  We certainly have that flexibility. 
     But generally, usually, a special team is our lowest level
     of response.  Generally, that's very targeted on equipment
     problems, root cause, things like that.
               MR. CALDWELL:  But I guess the answer, we haven't
     had a special inspection in this new process yet.  So we're
     telling you what we think.
               MR. SINGH:  Because the reason I ask, I asked the
     question to Region IV when they had a fire at Diablo Canyon
     last month, and they had a special inspection and they sent
     the SRA up there.
               MR. GROBE:  That was a significant, complicated
               DR. POWERS:  One of the things the committee has
     to do is advise the Commission on where it should be
     spending its research resources and we're wondering if they
     are under-investing in developing these tools to be used by
     the SRAs.
               MR. GROBE:  We're clearly resource constrained
     right now.  Almost all of our agency resources are going
     towards the SDPs and as they pointed out, the shutdown
     model, low power model, containment model --
               MR. DAPAS:  Risk-informed PIs is another
     initiative that Research has embarked on.
               MR. GROBE:  The interesting, I get anecdotal
     feedback, but I understand that the industry is not
     interested in risk-informed PIs.  That the amount of money
     that it would take to implement it doesn't give them
     sufficient payback.
               DR. POWERS:  What had been proposed up till now, I
     agree with industry on that.
               DR. APOSTOLAKIS:  But if we couple this with the
     maintenance rule, will it be much easier to define those
     PIs?  They already did a lot of it for the maintenance rule. 
     So there seems to be a distance or gap between the
     maintenance rule and risk-informed regulations and using the
     PIs.  I don't understand why.  I mean, what I don't
     understand is why didn't the staff at headquarters say, when
     they were establishing the oversight process, that the PIs
     were plant-specific and the licensees should propose the
               They did it with the maintenance rule.
               MR. DAPAS:  I think the licensee, in many regards,
     has weighed in on the thresholds here.
               DR. APOSTOLAKIS:  But they have their own.
               MR. GROBE:  Not plant-specific.
               DR. APOSTOLAKIS:  They have their own.
               MR. DAPAS:  There was a strong emphasis with the
     PIs to minimize the dollar cost of implementation.  So they
     depended very heavily on indicators.
               DR. APOSTOLAKIS:  Now they'll pay the price for
     the severe criticism that everything that is expected to be
     green and they don't mean anything and this and that, and it
     seems to me that there was an easier way of approaching it.
               DR. WALLIS:  Dana was asking about tools and I
     think you gave an answer about resources.  Tools, to me,
     enable you to do more with fewer resources.
               MR. GROBE:  That's what I was talking about; that
     is, the resources are currently focused on other tool
     development and our ability to develop all these tools is
     resource constrained.
               MR. DAPAS:  From a regional perspective, I would
     offer we are certainly interested in any tools research can
     provide us.
               DR. WALLIS:  It may be we could get some
     resources, or someone, to RES to develop things for you,
     that's a different kind of resource.
               MR. DAPAS:  As long as they don't come from the
               DR. WALLIS:  Yes.
               DR. POWERS:  That's another question. 
     Unfortunately, the ACRS has no role to play in that.  That's
     an NRC management function.  But it's one we certainly worry
     about, because it doesn't do any good to pay Peter by taking
     from Paul.
               DR. SIEBER:  Well, I think there is one other
     point, and that is that recently in the development of a lot
     of the criteria involved with license renewal, there was a
     notable contribution made by some people from one of the
     regions in helping to put together part of that approach.  A
     lot of us, at least I personally am convinced that the
     Commission would do itself a great favor if it would make
     greater use of the talent that exists within the regions
     and, in particular, those people who are the senior
     inspectors, who have real knowledge of how the plants work,
     when they put together some of these proposals and ideas.
               And so to that extent, we may be doing you the
     disfavor of suggesting that you be a greater participant,
     but I hopefully would believe that that's, in the long run,
     a productive thing rather than counter-productive.  I mean,
     we have to be frank with you on that.
               MR. GROBE:  We're one agency, though, and what's
     best for the overall safety of the industry is where our
     focus is.
               DR. SIEBER:  Yes.
               DR. POWERS:  My boss used to say that he was
     giving you an opportunity to exercise your management
               MR. CALDWELL:  I think you're exactly right that
     there are resources in the regions that would help out a lot
     of the development of new programs, et cetera, but there
     needs to be a shift in resources, because typically the
     development is in headquarters.
               So in order for that to work effectively, then we
     need to shift some resources to the regions so that the
     regions have that flexibility to interact or get involved in
     the development activities.  Because right now, it's the
     program office that does all the development and they
     resources for that.  But we wouldn't disagree that we think
     the talent we have in the regions could help that process. 
     It's just that we are base-loaded right now.
               DR. SIEBER:  Every time we've had a blood drive in
     this organization, the people who have contributed have been
     research and the regions.  You don't understand.
               MR. CALDWELL:  I understand.  I have to say,
     though, that the program offices have taken some pretty
     significant cuts and tried to prevent those cuts from the
     region.  So we have fared reasonably well in the past; in
     fact, most recently.
               My point is that if we're going to use regional
     resources for developmental programs, then you have to
     recognize that in the budget.
               DR. SIEBER:  I agree.
               MR. CALDWELL:  And take some of the developmental
     resources from the program office and put them in the
     regions.  We are perfectly happy to do that and be involved. 
     It's just that we have to be careful that we have enough
               DR. WALLIS:  You can be very involved in defining
     what are the problems, what could be the solutions, what
     would help you.  You're the customer for something.  I don't
     see you being quite so involved as a resource in developing
     something, but very involved in being articulate and somehow
     expressing what it is you need, what the characteristics
     have to be of something which comes out of some research
               MR. CALDWELL:  A lot of the details of this new
     program, though, were developed by regional resources.
               MR. GROBE:  That's right.  That happened under the
     old program, so we had some flexibility and we sent a lot of
     folks into headquarters.
               MR. DAPAS:  Task groups, et cetera.
               CHAIRMAN BARTON:  Since lunch seems to be out the
     door, we'll break for lunch from now until 1:15.
               [Whereupon, the meeting was recessed, to reconvene
     this same day at 1:15 p.m.].                           AFTERNOON SESSION
                                                      [1:15 p.m.]
               CHAIRMAN BARTON:  We've got till 3:00.  We don't
     want to miss anything that you want to tell us you feel is
     important, but try to get wrapped up by 3:00.
               MR. GROBE:  Well, why don't I fly through the
     training analysis, then.
               CHAIRMAN BARTON:  Okay.
               MR. GROBE:  I mentioned earlier that in the area
     of engineering inspections, that we've had to evolve our
     expertise and that's because we're doing more design
     inspections and we can no longer rely on contract resources.
               CHAIRMAN BARTON:  Right.
               MR. GROBE:  In addition, we've got a fairly high
     turnover rate.  A number of our individuals have left the
     jobs with utilities, as well as we had a number of
               So we've been in a fairly strong recruiting mode
     and we've been trying to emphasis recruiting of individuals
     with a stronger design expertise.
               That's different than the expertise we've had in
     the past in the region.  We've had some design expertise,
     but not a lot.
               CHAIRMAN BARTON:  Are those people hard to find
               MR. GROBE:  Absolutely.  Absolutely.  And we had
     some folks go out to the east coast out of Region I to try
     to find out if there was anybody interested in joining up.
               But basically it's the engineering firms,
     utilities and military that are our recruiting pool.
               The safety system design inspection is five
     engineers for three weeks and, again, if we're going to be
     successful in those inspections, they have to be qualified
     with design experience, mechanical, electrical and I&C
     system engineers.
               The Appendix R inspection, the fire protection
     inspection is three multi-disciplined engineers, and, again,
     they have to have very unique experience.  They have to be
     experienced in Appendix R inspection capability, and we're
     going to talk a little bit about the kind of training that
     they --
               CHAIRMAN BARTON:  Are they ongoing or is that a
     one-shot deal?
               MR. GROBE:  We had inspections early, following
     publishing the rule, through the '80s, that were, at that
     time, intended to be one-shot inspections.  Since then, the
     inspections were suspended.  Now, under the new program,
     we've re-initiated some inspections.
               For a while, we were doing inspections out of --
     that had the acronym FPFI, fire protection functional
     inspections, those were done out of headquarters and they
     were not programmatic in nature in the sense that they were
     mandated to be done at every plant.
               But this is not an FPFI.  It's not at that level
     of detail.  But it does touch on the same elements that a
     fire protection functional inspection touched on.
               You need somebody with fire protection engineering
     capability.  We don't have a fire protection engineer, but
     we've trained one of our engineers to assess those kinds of
     attributes of the licensees' design.
               We also need an I&C or an electrical engineer, but
     it's unique expertise in evaluating Appendix R types of I&C
     issues.  And then you need a system operations engineer to
     look at how the licensee would implement procedures
     post-fire and whether their plans are feasible.
               DR. POWERS:  Do you have plans to do induced
     station blackouts?
               MR. GARDNER:  Yes.  I'm not saying Region III has,
     but there are some in the country, that because of the fear
     of not being able to contain spurious operations, they go
     into a station blackout condition, and that's a concern,
               MR. CALDWELL:  We don't have them.
               MR. GARDNER:  Not that I'm aware of in Region III,
     that's what I said.  I'm not sure there are any in Region
     III.  We'll find out.
               MR. GROBE:  We should introduce Ron.  This is Ron
     Gardner.  Ron is my electrical engineering branch chief.  We
     do our fire protection inspections out of the electrical
     engineering branch.
               DR. POWERS:  The induced station blackout is a
     problem, it's a recovery.
               MR. GARDNER:  Well, it puts you into a condition
     that you don't want to get into.
               MR. GROBE:  Just to touch briefly on what we've
     been able to accomplish to date, we hired a Ph.D. I&C
     engineer who had 12 years of experience designing control
     systems for fighter jets, digital control systems for
     fighter jets.  We're trying to turn him into a nuclear power
     plant I&C inspector.
               We hired, he's on yet on board, but he's accepted
     our offer, an I&C engineer who was one of the co-chair of
     the Appendix R BWR owner's group.  So extensive Appendix R
               We hired an electrical engineer that had extensive
     experience in the industry, as well as prior inspection
     experience, and we just brought in a mechanical engineer,
     he's a former senior resident inspector, into the mechanical
     engineering branch.
               The area that we're having trouble is mechanical
     design, piping stress analysis, that sort of thing.  We're
     still looking for that resource and we're still looking for
     another electrical engineer.  But we've had some success in
     this area.  They are hard to come by.
               I want to talk a little bit about training.  Ron?
               MR. GARDNER:  In the 1980s, when we did the
     64-100, I don't know if you remember that number, baseline
     inspections, that were actually to make sure licensees were
     meeting their required date for implementing 50.48 and
     Appendix R, we had degreed fire protection engineers in just
     about every region and we augmented our people with NRR
     resources and contractors.
               We had a very good team.  Unfortunately, since the
     1980s, we've lost those fire protection engineers.  We lost
     one to NRR, one went to actually OI.  And then the FPFIs
     came back, and I can talk about how we got to where -- some
     of that's with Generic Letter 92-18, you might be aware.  So
     you know how we've gotten there.
               In any case, unfortunately, today, with the
     baseline program introducing the FPI, we don't have degreed
     fire protection engineers.  We have inspectors that were
     doing the base fire protection inspection and that is a far
     degree of difference between that and design of fire
     protection systems.
               As Jack indicated, we have started training a fire
     protection engineer.  We had a training session that NRR put
     on, two sessions each a week in Brookhaven, you may have
     heard of that.  We're having a follow-up training session in
     the region here in September, one day, unfortunately.
               For the first couple of inspections, we're having
     a contractor assist.  We're doing an inspection right today,
     the last day of the inspection is Friday, at Braidwood, fire
     protection inspection.
               We have two Brookhaven contractors.  That's OJT
     that we're getting from them.  We have NRR technical expert
     also on that team that's also giving them some training.
               So through a combination of OJT and classroom
     training, we are attempting to reach a level that we feel
     comfortable with as far as the technical capability of our
     people in this area.
               As you know, it's very complex, though.
               MR. GROBE:  For a period of six months, we've
     gotten limited contractor resources in the fire protection
     area, and for about 18 months in the design area, to put one
     contractor on each inspection team.  And the goal of that is
     to develop some on-the-job training.
               In addition, we're doing some internal course work
     on heat sink, thermal hydraulics, somebody mentioned heat
     transfer earlier, because we have a new inspection we hadn't
     done before, it's called heat sink.  What it primarily
     focuses on is the viability of heat exchangers.
     And we're exploring the TTC in other regions,
     discipline-specific course work in heat transfer, set-point
     methodology, instrument loop uncertainties.  We hadn't
     focused a lot in the past in these areas, so we're looking
     at developing some internal course work in those areas.
               CHAIRMAN BARTON:  TTC?
               MR. GROBE:  TTC is the technical training center,
     currently in Chattanooga.  I would expect most of this is
     stuff we're going to do.
               MR. SINGH:  I have a question.  Before you
     suspended the inspections back in the '80s, did you ever do
     the triennial inspections in fire protection?
               MR. GROBE:  No.  We didn't do one in this region.
               MR. SINGH:  You did not.
               MR. GROBE:  No.  There were, I think, only three
     done in the entire country.
               MR. SINGH:  No.  There were lots of them.  I did
     all of them in Region IV.
               MR. GROBE:  Oh, did you?
               MR. SINGH:  Yes.
               CHAIRMAN BARTON:  How many did you do in Region
               MR. SINGH:  Eight.  So nothing was done.  Thank
               MR. GROBE:  Any other questions in engineering?
               MR. DAPAS:  I just wanted to touch upon, starting
     with slide 42, some of the staffing challenges in the
     resident inspector program.  We've experienced a relatively
     high turnover rate and consequent with that is the challenge
     to fill vacancies.
               You have to post the vacancy, go through the
     selection process, and then train the individual, and with
     the qualification process, it can be several months before
     we have a fully engaged resident inspector replacement once
     we've identified the vacancy.
               CHAIRMAN BARTON:  The primary reason for the high
     turnover rate or does it vary?
               MR. DAPAS:  It varies.  It can be promotional
     opportunity for the resident inspector that may go on to be
     a senior resident inspector or come into the regional
     office.  It can be -- and that goes for both resident and
     inspector and senior resident inspector.
               It's a bit more limited for the senior resident
     inspector in terms of promotional opportunities, but there
     have been a number of residents that have received
     promotions, or requests for lateral transfers.  We had a
     resident inspector that wanted to go back to NRR to be a
     project manager and we supported that.  He, of course, had
     family in that area and that seemed to be a win-win.
               And in addition to that, there's attractive salary
     offers out there in the industry.  Some of these plants that
     were in extended shutdowns, like Cook and others, plants
     that are merging, there's opportunities for experienced
     resident inspectors and you're dealing with signing bonuses,
     et cetera, and lucrative salary offers, that's been an
     attractive draw.
               MR. CALDWELL:  Was your question -- were you
     trying to get to whether there's dissatisfaction?  I don't
     think we have -- I mean, there's always going to be some
               CHAIRMAN BARTON:  But 12 percent is pretty high
               MR. CALDWELL:  I think most of the folks that left
     went for either geographic, promotion, or something that
     benefited them, either money or whatever.  I don't think we
     lost anybody that just --
               MR. DAPAS:  Or early-out, I don't think so.
               MR. CALDWELL:  -- didn't like the program anymore.
               MR. DAPAS:  And that's one of the things we try
     and probe, was there some concern with or dissatisfaction
     with your working environment or et cetera.
               DR. POWERS:  But if the inspection program is
     going to turn them into automatons and eliminate
     discretionary and judgmental aspects of it, are you going to
     lose people?
               MR. DAPAS:  I'd challenge that characterization of
     the new program, but --
               DR. POWERS:  I put the worst spin on it I can
               MR. DAPAS:  I think we are asking the inspectors
     to bring judgment to bear and as I said, in the context of
     what revisions do we need to make to the program, I know
     that Jim and I have had a lot of discussions, we place a
     high value and premium on experienced individuals with
     mature judgment and we value that and we're going to
     consider that input.
               And we -- divisional meetings or one-on-one
     discussions with the residents, we go out to the site, we're
     continuing to encourage them to flush issues up to branch
     chief management, so those can be considered and evaluated,
     and not get locked into this, well, the new program doesn't
     allow me to do X or Y.
               CHAIRMAN BARTON:  One of the concerns I have is
     they do an SDP and they get frustrated because in the past
     it was the findings of violation and now you do it and it's
               MR. GROBE:  It's an issue that we're having to
     focus some management attention on, because we've completely
     perturbed all of the structures that the staff had to
     demonstrate their own --
               CHAIRMAN BARTON:  Exactly.
               MR. GROBE:  -- in terms of value.  So we're
     building what is currently called a significant reactor
     finding.  We're going to rename it, but we're doing more
     internal recognition of inspection issues that add value,
     but don't get to a white, yellow or red threshold, add value
     because they provide insight to the licensee or provide
     insight to us as far as inspection techniques or other
     issues that other plants can look at.
               So we're trying to find ways to give the staff
     anchors for their value, but it is a challenge.
               MS. NESTON:  Does this 12 percent also include the
     rotation out of a particular plant because they've been
     there for so long?
               MR. DAPAS:  I'm not sure on that.
               MR. CALDWELL:  In the range, it could include
     someone who has rotated back to the region, because either
     their time was up or we've had individuals who didn't stay
     the full seven because they were grandfathered with the
     five.  They came up to their five and decided they wanted to
     do something different and rotated either back to
     headquarters or here.
               MS. NESTON:  And they would be included in that 12
               MR. CALDWELL:  They would be included in that.
               MR. GROBE:  In honesty, we haven't had a lot of
     folks that have been -- that have moved because they've
     gotten to their time limit.  That's the exception, not the
               MR. DAPAS:  That's with the extension to the seven
     years.  But I think, and I view this as a positive, I think
     we've had a number of instances where feedback we've
     provided to the program office, discussion that we've
     generated in the different forums to discuss the new program
     has resulted in some change, and we try and build upon that
     as positive examples for the inspection staff, where
     expressing their views has resulted in revisiting of a given
               So we are encouraging that across the board as we
     go into initial implementation.  The pilot program, we had
     input from really two branches, and now we've got input from
     all the branches, and there is a learning curve that they go
     through.  Some of the feedback we're able to address as a
     result of lessons learned from the pilot program and then
     there's also additional insights that are communicated that
     we discuss and forward to the program office.
               So I view that as kind of healthy.  There's a long
     training period, as I mentioned, for qualification.  You
     have to attend the BWR, the PWR series, plant-specific
     system knowledge, on-the-job training, that's certainly a
     large aspect of the resident qualification program, and then
     the emergency preparedness responsibilities, understanding
     the licensee's emergency response plan, the NRC
               And I caveat this, appropriately.  Some PRA
     training that the residents receive so that they can
     understand the use of the SDP process and how risk impacts
     inspection activities, and then they go through a course, an
     oral qualification board, where we have various branch
     chiefs that sit and ask questions to test knowledge in the
     regulatory perspective.
               CHAIRMAN BARTON:  What happens if they fail the
     oral board?  Do they get another shot?
               MR. DAPAS:  We have had a couple individuals, in
     my experience in the region, that we felt needed another
     qualification board.  So there were particular areas where
     they had to concentrate and devote some additional study and
     then they were successful in their second board.  But the
     branch chiefs, I think, are fairly successful in not
     offering or sponsoring a resident for a qualification board
     until they're pretty confident that they've acquired the
     requisite knowledge to be successful.
               So we've had limited experience where that has
               MR. SINGH:  Do you also have an oral board for the
     regional inspectors?
               MR. GROBE:  Absolutely.  Every inspector goes
     through an oral board.
               MR. DAPAS:  And then when we looked at the pool of
     experienced resources, that's a bit limited.  Obviously, we
     draw from the Navy or shipyard or licensee operational
               DR. POWERS:  If the Navy keeps working its folks
     as hard as they are right now, you'll have a big pool of
               MR. DAPAS:  We get some applicants that have a lot
     of experience in the nuclear power program that the Naval
     Reactors runs and that's because they are downsizing.  So
     they're looking for other opportunities.
               But this does require an aggressive recruiting
     program, because as I said, the competitive salaries and the
     signing bonuses in the industry, the lengthy process we have
     to go through for selection, rating panels and interviews,
     et cetera.  So that can sometimes -- where employee X can
     say here, we're offering you a job here.
               Sometimes we've been in the process of going
     through the selection and we're ready to forward an offer
     and individual X has said, well, I just took an offer a
     couple weeks ago with company Y.  So sometimes we're
     confronted with that and we look for ways to streamline
               One of the things that we're also looking at is
     the entry level program, and that certainly is a resource
     investment, but we want people with experience.  But, again,
     that can be limited, so we look and explore the entry level
               MR. CALDWELL:  Mark is going to try to hustle up
     here so we can get into the fire protection stuff, but I
     want to make sure, before he gets out of this, if you have
     any questions on this, because it is probably one of the
     most important programs we have; not necessarily because the
     other aspects, what we do is not important, it's because
     these are the folks that are on the site that are there all
     the time.
               What they do is -- what I saw as the biggest
     change in the way the agency worked was that licensees now
     expect to have somebody there, so that they don't operate
     differently than they would if an NRC presence wasn't there.
               I talked to some staff people and they told me
     that in the old days, when they knew the inspection team was
     coming out, they changed their mode of operation for that
     week and then changed back after they left.
               So the resident program has provided a routine
     presence which keeps folks from operating differently when
     we're there.
               CHAIRMAN BARTON:  It keeps them honest.
               MR. CALDWELL:  Well, I didn't want to say it that
     way, but that's essentially it.  I didn't mean to interrupt
     you, Marc.
               DR. POWERS:  Well, there's another thing that you
     have to bear in mind, that all of us have to bear in mind,
     that there is a very, very crucial role that they play and
     this SDP process is their process for screening their
     findings and whatnot.  So their level of responsibility, to
     my mind, has actually gone up in this new procedure and some
     of these things I worry about are responsibility and
     judgment, notwithstanding I think there are still concerns.
               MR. GROBE:  The SDP is not limited.  The residents
     obviously have a role in evaluating their findings, but the
     region-based inspectors also use that, that the value to the
     inspection program that the residents add is -- I can't
     remember the number -- but several hundred hours of their
     time is allocated to what we call plant status and that --
     it's 650, and that's supposed to be a risk-informed
     assessment of what's going on, so that they can engage
     themselves in the right activities and also engage the
     region-based folks that come out in the right activities
     from the risk perspective.
               MR. CALDWELL:  I cut Marc off and I apologize.
               MR. DAPAS:  One of the things we talked earlier
     about is the impact of the training courses at the technical
     training center, when they're offered, but branch chief X
     has a vacancy and is successful in filling that, but the
     annual PWR course just completed, that individual has to
     wait till the next year to pick that up.
               CHAIRMAN BARTON:  So it's only given once a year.
               MR. DAPAS:  Right, and I guess that is a function
     of the demand that they have when you look across all the
     regions and all the offices, that they were only able to
     justify one course a year, but sometimes that does have an
     impact depending on when your individual reports on board.
               And we already talked about absence from the site
     for an extended period.  If you're attending a seven week
     course in Chattanooga, you're going through the
     qualification process, that impacts baseline program
     execution and site coverage and that requires pretty
     involved branch management of the inspection --
               CHAIRMAN BARTON:  You bring another inspector on
     board for that period of time, right?
               MR. DAPAS:  Right.  We were looking at like a
     contingency plan.  A good example is in an outage.  The
     licensees are short during outages.  There's I forget how
     many hours associated with the resident inspection portion
     of the outage.  Do you recall, Laura?
               MS. COLLINS:  Eighty.
               MR. DAPAS:  Eighty hours.  Doing that at what
     might be a 22-23 day period can be a real challenge if
     there's only one inspector on-site and branch chief X might
     ask the other branch chiefs can you help me out with sending
     someone during this outage period.
               And as I mentioned, on-the-job training is a large
     part of the program.  And the experienced SRIs look at
     resident inspector development as a high priority and their
     responsibility.  It's kind of like I'm training my
     replacement coach.  So they place a premium on that and I
     think we get a lot of value-added.
               And the other thing, as I mentioned, we look at
     reduced training length when hiring high quality individuals
     who can hit the ground running.  We have had some interim
     certifications in selected areas of the inspection program
     because an individual comes on board that has an extensive
     operations background.
               And then the extensive cross-training.  I was just
     looking yesterday at the number of residents and senior
     residents that have both PWR and BWR training, and so
     they're fungible to go to other sites without having to take
     the specific series course.
     And the other aspect of this cross-pollinization is between
     DRS and DRP.  We've had a resident inspector go to operator
     licensing and a senior resident that reported to operator
     licensing, as well as an individual from the engineering
     branch going out and being a senior resident.
               So there is some cross-pollinization between
     divisions which we think is real beneficial.
               If there are any questions.
               CHAIRMAN BARTON:  Do resident inspectors get
               MR. GROBE:  Yes.
               CHAIRMAN BARTON:  Are they paid overtime?
               MR. GROBE:  Absolutely.  Let's move on to risk
     training.  What I'd like to do -- do you folks have any
     questions about the SRA training program?  Are you familiar
     with that?
               CHAIRMAN BARTON:  No, I'm not familiar with it. 
     What slide are you on, Sonia?
               MS. BURGESS:  I'm on 46.  There's Region III is no
     different from the other regions.  There's two SRAs in each
     of the regions and there is consideration of an additional
     risk trained person and that can take the form of a couple
     of different options.
               One is using existing inspectors with additional
     risk training, so they can do it part-time, and another
     person that's dedicated to assist the SRAs in the analysis
     of risk.
               CHAIRMAN BARTON:  Have you been in a position of
     trying to assess what your needs are?
               MS. BURGESS:  Yes.
               CHAIRMAN BARTON:  You need another warm body or do
     you need an assistant?
               MS. BURGESS:  We have.  The SRAs have put their
     input in and what we would desire, what we think we would
     need.  We definitely think we'd need at least one additional
     risk person.
               CHAIRMAN BARTON:  A lot of times people will have
     one slot and they say, well, what I'll hire is a new senior
     reactor analyst.  Point in fact, they've got enough senior
     reactor analysts.  They need an assistant for them to help
     them carry out their jobs, and I'm just wondering if you had
     thoughts on that.
               MR. CALDWELL:  There's no plans to have an
     additional SRA slot.  As I mentioned earlier, there's a task
     force that, in fact, the meeting starts -- the first meeting
     is on the 26th, of the four regions and headquarters, to
     talk about SRA succession planning, and that really is to
     talk about the type of training that you would give one,
     two, three, four, five individuals, I'm not going to
     prejudge how it comes out, but a number of individuals who
     would not be fully SRAs, but would have additional training
     that they could support the SRAs and the region in risk
               Not a short-term thing.  I mean, the two SRAs are
     going to be just up their necks in work, but it's a
     recognition that there needs to be some more expertise in
     that area and a recognition that that you need to have
     somebody in the pipeline unless an SRA gets promoted or
     decides to leave.
               DR. POWERS:  They better not.
               MS. BURGESS:  That's a great segue into the next
               MR. GROBE:  I was going to say there's a lot of
     personnel barriers associated with this, because the SRA
     position is a higher graded position than any other staff
     position we have in the region.
               So there's a lot of issues that come up in the HR
               MS. BURGESS:  On slide 47 is the SRA training
     certification program or process is an 18 to 24-month
     program.  It's divided into classroom and rotation and I've
     listed some of the technical training, the statistics, PRA
     training, and then the NRC PRA computer modeling training. 
     That, in itself, can be up to 27 weeks of training.
               CHAIRMAN BARTON:  Where do they get the PRA
               MS. BURGESS:  In headquarters.  And most of the
     time, much of the training is contracted out.  Brookhaven,
     INEL.  So just the classroom portion of the training is a
     significant amount of time.
               Rotations, there's nine months of rotation.  Mike
     and I did five months in NRR in the PRA branch, we did three
     months in the Research PRA branch, and then we did one month
     at another region to get on-the-job training, with the
     assistance of an existing SRA, to see what their job duties
     were and how they conducted business in the region, and took
     that back to our region.
               MR. CALDWELL:  And that's one of the areas that
     we're going to look at.  Now that we have experienced SRAs
     in the region, we may not need these extensive rotational
     assignments.  They'll just spend their time with the SRAs in
     the region to get their on-the-job training.  But the
     classroom training that she was talking about is extensive.
               It's not a short-term fix if somebody leaves or
     you need additional help.  It's something that we're trying,
     for the long-term, and come up with a plan that will keep
     people in the pipeline and bring up the whole level of the
     region's expertise of risk.
               DR. POWERS:  It also offers the opportunity for
     substantial job satisfaction improvements there, the guy
     feels like he's going into modern technology.
               MR. GROBE:  I think we've covered slide 48.  Why
     don't we go on to 49?
               MS. BURGESS:  Slide 49 just highlights some of the
     training that the regional inspector and the resident
     inspector would receive.  This first bullet is a two-week
     class.  It's a combination of the PRA basics plus we have
     how integrated the SDP process and now the PRA and the IPE
     all integrate into the SDP process.  That's a two-week
               An then also we've given extensive training on the
     SDP process itself.  We've had a lot of workshops and with a
     lot of examples of issues from other regions and that's
     helped the inspectors put some practical use to the SDP.
               MR. GROBE:  Any questions in the risk training
     area?  Before we get into the fire protection area, there
     were two questions that you asked earlier that we didn't
     really get a chance to answer, and I'll just give my
     perspective and open it up to Jim and Marc.
               One had to do with power up rtes.  We don't have a
     lot of insight on power up rate, other than the fact that I
     could share with you a concern that I have.  Jim Dyer
     mentioned Quad and Dresden are going to be coming in for
     some fairly significant power up rates and you indicated
     Duane Arnold is, and that has to do with secondary side
     capability and the ability of the operators to operate the
     plant in a higher, significantly higher power level, and
     whether that's going to impact on initiating event
               I don't have any more insight to share with you,
     other than that's a concern that we have, and I'd throw that
     open to Marc and Jim.
               MR. DAPAS:  The power up rate, I guess from the
     resident inspector perspective, I think you would get
     involved, the resident inspectors get involved in looking at
     if there's any tech spec ramifications.  Many times, the
     tech spec package that comes out, headquarters is
     considering, the residents will be asked to review, to offer
     any perspective procedural implications.
               So it's just really changes to the tech specs and
     procedures that result from the power up rate.  I can't
     really envision any other area where the residents might be
     CHAIRMAN BARTON:  With a number like that, you're going to
     have to make some hardware system changes when you go in
     that level.
               MR. CALDWELL:  Right.  Set point changes that have
     to be made and they have to be made as they go up.
               MR. DAPAS:  Which are captured in the tech specs.
               CHAIRMAN BARTON:  Yes, but they actually have to
     make changes in the plants.  You have to -- because the trip
     set point stays the same, but the 100 percent power, as it's
     calculated, changed, and so the trip set points have to be
     changed in the instrument and control.
               But what Jack mentioned is something that I don't
     know that we have any insights into, but some licensees find
     that they get the up rate and they just don't have the
     capacity we have any insights into they tripped their auto
     valves or their turbines aren't set up, at least the way
     things are set up, to handle that type of --
               CHAIRMAN BARTON:  Fermi is a good example of that.
               MR. CALDWELL:  Right.  So those are things that
     they have to kind of inch up to and that's what we will be
     watching, how they do that, how they control it, and most
     licensees, at least today, had done it very slowly and very
               DR. SIEBER:  These major up rates, though, they're
     really talking about a new front end on the turbine and the
     things like that.
               MR. CALDWELL:  Yes.
               DR. SIEBER:  Which really changes the physical
               MR. DAPAS:  But I'm not aware of any prescribed
     inspection activity where we would go out and verify that
     what the licensee communicated in their licensing submittal
     is, in fact, the case in terms of equipment modifications.
               MR. GROBE:  It would be an opportunity through the
     affirmative plant mods inspection and the safety system
     design inspection to target some of those areas.
               DR. SIEBER:  But you know that the stress level on
     the plant is going to be higher.
     The other you raised earlier was license renewals and we
     haven't had any in Region III, but we've seen that train
     coming down the tracks, and we assigned a project manager to
     stay aware of what's going on in the other regions and
     The inspection program for that activity is fairly
     significant and while it doesn't have any direct impact on
     the baseline program, it doesn't change anything we do in
     the context of baseline.
               It's resource intensive and as we shared with you
     earlier, we don't have a lot of resources.
               It's also a fairly unique expertise that's
     necessary.  There is discussion underway right now, and
     maybe, Ron, you can expand on this, too, to capture that
     inspection activity out of headquarters or currently it's
     out of the regions.
               Why don't you talk about what we've done as far as
     trying to gain insights in this area?
               MR. GARDNER:  As Jack indicated, we have a
     principal inspector that we've assigned to get with the
     other regions who have started down that path, to find out
     what they've done, how they did it, what worked, what
     didn't, to try to get to the point where when we get our
     opportunity, we're not starting at ground zero, that we've
     already built on what other people have done and tried to
     make improvements.
               AS Jack indicated there is some discussion about
     who will do what.  There's a big portion, as you might
     imagine, of environmental qualification questions that come
     into life extensions of license renewal.
               And I have been part of one of the research
     working groups, for years I was on that, on aging of
     materials and such.  So I have an acute background in that
               So I think we have the wherewithal to do the
     inspections, the challenge will be finding the resources to
     do it.
               MR. GROBE:  What's the total number of inspection
     hours we've seen?
               MR. GARDNER:  I can't remember.
               MR. GROBE:  My recollection is on the order of 700
     and something.
               MR. GARDNER:  I thought it was 800, roughly 800.
               MR. GROBE:  It's a very significant impact,
     because it has to be done a very short period of time.
               DR. POWERS:  We have a statutory responsibility
     for all those and we're looking at a major tidal wave coming
     in at us and it could literally consume everything we do.
               MR. GROBE:  I think that captured all the
     questions that I had written down earlier.  I think what I'd
     like to do now is go into the fire protection issues and
     turn it over to Ron Gardner.  I know that you're going to
     have some questions.  I suspect you're going to have some
               MR. GARDNER:  As Jack indicated, my name is Ron
     Gardner.  I'm the Chief of the Electrical Engineering branch
     in DRS and fire protection falls in my branch.
               What I've tried to do is make a presentation that
     would address where the new program is going with fire
     protection, not only triennial, but also the more day-to-day
     review of fire protection and the normal fire protection
     things that the regions have been doing over the years.
               We didn't stop that.  We're just doing it in a
     different manner.
               The first thing, I guess, on slide 55 that I want
     to emphasis is the risk contribution of a fire.  It is
     significant and if you stop and think, with the fire, you
     can have a plant transient, you could have a reactor trip,
     you could have a loss of off-site power, you can -- we
     talked about self-induced station blackout.
               All those require fairly significant reactor
     operator actions.  You can go beyond that, though, with the
     high-low pressure interface problem or a stuck-open PORV, a
     spurious operation of an SRV, and you enter a LOCA
               Compound that with a loss of off-site power and
     you've got very numerous operator actions.  Then with a
     fire, you may have smoke, which could inhibit or prevent
     operator actions.  You have flooding, you have the heat of
     the fire.
               The fire itself is a very significant area of NRC
     historical perspective and it looks like it's going to
     continue, that we're going to maintain our focus on this.
               There were a number of years where we backed off. 
     Information Notice 92-18 and the subsequent problems we had
     with the implementation of that, that was regarding
     motor-operated valves and the potential for spurious
     operation and control room fires, to have the valves not
     only go to the wrong position, but to be destroyed
     mechanically because of the bypassing of the torque
               Also, we had some FPFIs that failed, with
     significant findings.
               So going on to page 56, I wish there was a silver
     bullet where we could say here is the fix, that we could say
     the risk of fires has gone away by just doing this one
               No one has been able to find that silver bullet. 
     So that instead, what we find is the best approach and
     licensees have found the best approach is the definition
     methodology or mentality.  It starts off by preventing
     fires, and I'll talk more about that when we talk about what
     the resident does and how we try to gauge how licensees are
     doing in preventing fires.
               Then we have the part of rapidly detecting,
     controlling and putting a fire out.  Great success, if you
     remember the Fermi turbine explosion, it released thousands
     and thousands of gallons of oil, EHC fluid, et cetera, and
     distributed it all over the plants, with all the water
     systems that were ruptured, and the fire was extinguished
     and rapidly extinguished, and that could have been a very,
     very significant fire and it didn't happen.
               So that says that in that case, the rapid
     detection, control and extinguishment of the fire worked,
     and that involved obviously even the hydrogen system for the
               DR. SIEBER:  One of the problems is, though, that
     when you have a big fire in the plant that involves
     operations, it's the operators who are the fire brigade.
               MR. GARDNER:  Often, and I'll about it.  They have
     a lot of manual actions, too, sometimes to mitigate the
     fire.  One of the things that the licensees are required to
     do is for any fire area, is to dedicate or to preserve
     enough equipment to safely bring the plant to cold shutdown,
     and the performance goals they're trying to make is
     reactivity control.
               They want to make sure the plant is no longer
     critical.  They want to have makeup.  They want to have
     decay heat removal.  They want to have enough indication for
     the operators to know which manual actions to take or which
     actions and EOPs to follow.  And a support system.
               So that's quite a lot that you have to maintain
     regardless of whatever fire you can postulate.  To do that,
     you have barriers, suppression, safe shutdown procedures,
     and you have a number of equipment and systems that are
     dedicated just for those operations that have to survive in
     the event of a fire in any given postulated fire area.
               Unfortunately, there are no performance indicators
     existing today, and this is slide 57, to provide insights or
     to help us to say that we don't need to do an actual
               And we haven't given credit for self-assessments. 
     One of the reasons, and I'm not saying a significant reason,
     but one of the reasons was when we were doing the FPFIs,
     Prairie Island did a self-assessment.  When we did the FPFI,
     we gave them credit for it.  So our FPFI was focused on
     determining the adequacy of their self-assessment.
               When we went out there and looked around the
     plant, we found a number of issues that their
     self-assessment had missed, and they weren't small issues. 
     I don't have -- if you look at the inspection report, you
     could see them.
               They were fairly substantive issues, and we were
     surprised.  I'm not sure if that had a major contribution to
     the fact that the NRC wants to at least start down the road
     of doing our own inspections, but it probably didn't help
     the licensee's cause any, because I know NEI was looking to
     see if they could have more credit for self-assessments.
               MR. DAPAS:  Didn't we also, though, Ron, have some
     have some real significant inspection findings in that area
     and that has furthered the point that we should
     independently verify.
               MR. GARDNER:  Right.  Now, a number of licensees
     are doing self-assessments and they are finding significant
     issues, and that's to their credit.  It's just whether or
     not we are comfortable with saying they are to the point now
     where they can find the amount of problems that we think are
     there still, and that's an unfortunate statement, but that's
     true, unfortunately.
               Now, as I was indicating, it's not just a
     triennial or design inspection.  We have a constant focus on
     fire protection that's brought about by the residents.
               On a quarterly basis, residents tour six to 12
     areas of the plant, and they're looking at the classical
     fire protection features.  They're making sure that the
     licensee doesn't have extensive combustibles or ignition
     sources for those combustibles in the plant.
               The licensee has requirements for storage of
     combustibles, et cetera, they're looking at that.  They're
     making sure that the material condition of the fire
     protection systems is up to par, that they're not degrading. 
     Operational lineup, say, for a C02 or a halon system,
     they're making sure it's properly lined up, so if there is
     an automatic initiation, it would function.
               They look at operational effectiveness of the
     equipment and of the licensee's fire brigade and fire
               CHAIRMAN BARTON:  Are those quarterly inspections
     what you require to be done during an outage?
               MR. GARDNER:  Required to be done during an
               CHAIRMAN BARTON:  Yes.
               MR. GARDNER:  I'm not sure that the procedures
     differentiates between an outage and a non-outage condition.
               CHAIRMAN BARTON:  The only reason I bring it up,
     because in outage, you've got an opportunity to bring in a
     lot more fire loading combustibles.
               MR. GARDNER:  That's why the residents are out
     doing this, because they're there during the outages and
     not.  Usually, the region stays away from an engineering
     type inspection during an outage, the residents are there
               MR. SINGH:  This question came up last week when
     we were got in the NEI conference on fire protection.  They
     don't want it during the outage, because there's too many
     combustibles, too many --
               MR. GROBE:  They don't want us to do an
               CHAIRMAN BARTON:  Yes, that's why.
               MR. SINGH:  They emphasized the point that they do
     not want the NRC doing inspections in the outage.
               DR. APOSTOLAKIS:  Do you have any IPEEEs yet?
               MR. GARDNER:  Any I what?
               DR. APOSTOLAKIS:  IPEEEs.
               MR. GARDNER:  We have the Generic Letter 88-20,
     Supplement 4, IPEEEs that the licensees have been providing.
               DR. APOSTOLAKIS:  So you have their IPEEEs.
               MR. GARDNER:  Yes, we do.  If you recall, in fact,
     several years ago, Quad Cities released their
     5E-to-the-minus three that really stirred up the region to
     take action on that.
               DR. APOSTOLAKIS:  I wonder whether you can
     prioritize these fire areas that you're inspecting according
     to their --
               MR. GARDNER:  And I'll get into that in a minute,
     if I could, because that's one of the things we do as part
     of our triennial and it's also done by the resident
     inspectors when they are looking in their areas.
               MR. GROBE:  Step back for just a second.  That's
     one of the reasons that we have to spend more time preparing
     for these inspections, because everything we do has to be
     risk-focused.  So something as simple as selecting which
     plant fire areas to look at would involve some consideration
     of the risk significance of fire areas.
               DR. APOSTOLAKIS:  That's a one-time job, though. 
     After you've done it, you have it for that time, correct? 
     Unless something dramatic changes.
               MR. GROBE:  That's correct.
               DR. APOSTOLAKIS:  So it's an initial investment in
     a new process.
               MR. GARDNER:  No.  What we find, and I'll go into
     that.  It's changing.  It's not a static.  It's a dynamic
     number --
               DR. APOSTOLAKIS:  But the critical locations,
     unless you really change the plant, it's where the cages
     come together.
               MR. GARDNER:  Evidently there's other things.  We
     have found that it's changing, and I'm going to that in a
               DR. APOSTOLAKIS:  Okay.
               DR. POWERS:  There's a little problem in using the
     IPEEEs as the basis for prioritization.
               MR. GARDNER:  Right.
               DR. POWERS:  Because there are some crucial
     assumptions that some licensees have made in screening
     things out, I mean, things that just don't appear in the IPE
     have gotten screened out because though there's a high
     combustible loading, you can say, well, there's no ignition
     source.  I can screen this area out.
               Well, that's all well and good.  What happens when
     an ignition source gets introduced?
               MR. GARDNER:  And I hope to get to that point,
     too.  That's one of the subtle aspects of the new program
     versus the old, in that when we postulate a fire that can
     affect safe shutdown equipment, we have to be able to
     demonstrate how the combustibles, whether they be cables,
     scaffolding, whatever, how it can ignite, what is the
     ignition source, and then how you can get the fire to
     migrate from one part of the fire area to another.
               In the past, we used to assume it just happened. 
     We just say you have to assume it happens.  Now we have to
     develop a scenario to show reasonably that it will, in fact,
     because of the heat plume and of the effects of that plume,
     it will transverse the fire area.
               So if I don't get into that further, if you need
     more when I go through it, let me know.
               DR. POWERS:  There are other subtleties in there,
     as well, because a lot of the IPEs have been done saying,
     well, the fire barrier penetration seals are 100 percent
     guaranteed absolutely effective.  And I don't know of
     anything that's that guaranteed.
               It's just one of these problems.  You just can't
     look at an IPEEE and say, well, this is truth, it's truth if
     one person saw it.
               MR. DAPAS:  Ron, do the inspectors look at the IPE
     to understand the assumptions before they go out?
               MR. GARDNER:  Yes, and that's what I'm going to
     get into in just a couple slides.
               On page 59, if we can go to that one, we shift
     from what the residents are doing on a monthly and a
     quarterly basis to an annual inspection.
               It's always important to understand how the
     licensees fire brigade can perform.  It may come down that
     they are the last of the defense-in-depth for a given fire
     area.  So we hold them to a high standard.
               DR. POWERS:  We usually just assume that
     defense-in-depth.  In the good old deterministic days of
     Appendix R, we just assumed that fires aren't out until the
     fire brigade goes in to put it out.
               MR. GARDNER:  That may be true.  I don't recall
               DR. POWERS:  Automatic suppression systems were
     assumed only to control fire and to actually put it out, you
     had to have somebody walk in there and put it out.
               MR. GARDNER:  At 3G, it gives credit for
     separation and if you don't have separation, for suppression
     and detection.
               DR. POWERS:  It's just suppression.  It's not
     putting it out.  The fire's not over until somebody actually
     goes in there and declares it out.
               MR. GARDNER:  From a design approach, it gives
     credit for suppression.
               DR. POWERS:  Under the new program, we weigh
     suppression.  We have a fire mitigation frequency, I don't
     know if you're familiar with the new SDF, significance
     determination process for fire protection, and there is a
     formula for SMF which includes fire barriers, ignition
     frequency, and automatic suppression, manual suppression,
     and CC, which is common cause.
               So that is figured in to the equation.  Again, on
     the resident inspection portion, on an annual basis, they
     check certain aspects of the fire brigade.  What they would
     probably do is not ask for the fire brigade, but find one
     that is routinely scheduled and observe it.
               The triennial inspections do not demand that a
     licensee do a fire brigade just for the triennial.  We would
     get information from the residents about whether their
     perception of the fire brigade's adequacy was, as well
     reading what licensees are finding and documenting their own
     critiques of their fire brigade drills.
               Now, on page 60, I shift to the triennial team
     inspection.  This is not a classical fire protection,
     looking for combustibles.  It is more focused on design.
               And in the preparation aspect, we talk or
     communicate, get with the SRAs, the regional SRAs; if they
     are tied up, we get with headquarters SRAs, and we get the
     risk rankings for different fire areas, and we have found
     that the IPEEE can give you some numbers.
               We go out to the site and we find that those
     numbers may have changed.  That just happened at Braidwood. 
     The numbers changed.  I don't have all the reasons as to why
     it happened, I just know that it did happen.
               We also look at the transient sequences.  All of
     this is done in conjunction with the SRAs to assist us in
     saying which of these fire areas would probably be the best
     for our inspection to focus on.
               One of the things we may stay away from, by the
     way, is the control room.  The control room is so analyzed
     and has so many people in it that some of the other rooms,
     sometimes we think would be more bang for the buck, so to
     speak, to look at than the control room, which a licensee
     automatically assumes they're going to evacuate anyway.
               But that is a case by case basis, we'd have to
     look again and look at the rankings.
               We have a very important two to three day full
     team information gathering visit.  That's where the full
     team goes to the plant.  They walk down the fire protection
     systems, safe shutdown systems.  They look at the P&IDs. 
     They determine what might go wrong.  They say that the
     licensee is relying on HPSI for makeup and they may look and
     say, okay, let's see if we can find a valve that, if it were
     to close, would isolate HPSI from the water supply it needs.
               And then they would check that cable or that valve
     to see if it's been protected or not.  They would look at
     spurious operations, et cetera.
               So that first two or three days is a very
     important aspect of our inspection.  Obviously, we look at
     risk rankings, we look at things like that.
               Then we come back into the region for a week, the
     whole team does, take that information that they gleaned
     from that two to three day bag trip, we call it, and
     determine their inspection plan.
               They've finalized the areas they're going to
     inspect.  They determine some cables, some areas of question
     they're going to focus on, and they get just about ready to
     go out there and start the inspection as if they had a very
     limited time, which they do, by the way.
               CHAIRMAN BARTON:  Wouldn't an inspector go look in
     the corrective action system to see how many outstanding
     items there are against fire protection system, deficiencies
     that haven't been corrected or are backlogged?
               MR. GARDNER:  We don't go into the licensee's
     corrective action program in detail.  We have a small
     percentage of our inspection that looks at that.
               What we try not to do is mind the licensee's
     corrective action program.  We try to do an independent
     assessment of the licensee's fire protection program.
               DR. APOSTOLAKIS:  On 60, it says that you select
     three to five plant areas important risk for inspection.
               MR. GARDNER:  Right.
               DR. APOSTOLAKIS:  Then on 58, you said that you
     are inspecting six to 12 fire areas on a quarterly basis.
               MR. GARDNER:  On page 58, I was talking about the
     resident inspections.  That's covered on a monthly or
     quarterly basis.
               MR. GROBE:  And that's just looking at classical
     fire protection, combustibles, controlled ignition sources.
               DR. APOSTOLAKIS:  But the question is why can't
     these six to 12 plant fire areas be ranked according to risk
     so you focus on the risk significant areas?
               MR. GARDNER:  We do under the triennial design
     inspection.  We pick the most risk significant --
               MR. GROBE:  Laura, did you guys, when you did this
     module, did you use IPEEE insights to focus risk?
               MS. COLLINS:  We did.
               CHAIRMAN BARTON:  So even the six to 12 areas are
     among the --
               MR. GARDNER:  Yes, sir.  They are also risk-based
     or risk-informed.  Excuse me.
               DR. APOSTOLAKIS:  The areas are risk-based.  They
     come from the PRA.
               MR. DAPAS:  The inspections risk-inform, though,
     when they're selected in the areas.
               DR. APOSTOLAKIS:  That's right.
               MR. GARDNER:  The triennial inspection shifts from
     the classical fire protection to a design focused
               DR. APOSTOLAKIS:  Are these areas, though, you
     take them from the licensee's risk assessment.
               MR. GARDNER:  We look at the IPEEE, we talk to the
     SRAs and we get the licensee's assessment of the relative
     DR. APOSTOLAKIS:  So you may decide there are additional
     that require a tool, even though the licensee may have not
     found them to be a not very significant safety.
               MR. GARDNER:  That could happen.  I'm not saying
     it's going to happen, but it could happen, certainly, if we
     found a basis for it.  The resident inspector may have a
     reason for us to go to a particular fire area based on what
     they've been seeing.
               DR. APOSTOLAKIS:  See, that's where the standards
     w discussed earlier this morning become very important,
     because many licensees have used screening methodologies and
     unless you really look carefully at the assumptions that
     they have made, you may have missed important five areas.
               The IFPI-805 is going to solve that, right? 
     That's why ASME and ANS are not looking at fires.  It's an
     IFPI that will do it.  That means there's something fishy. 
     You have to understand means this.  Go ahead.
               DR. POWERS:  IFPI's expertise in fire risk
     assessment, just the personnel on the committee, it's just
     very, very limited.  It's like one guy that really knows a
     lot about fire risk assessment.  He may be the only guy in
     the country who a lot about fire risk assessment.
               So to say that we will have a standard that means
     that you can look at a five analysis and have some
     confidence that you don't have to go plowing into the
     assumptions.  I think that's overly optimistic.
               DR. APOSTOLAKIS:  So they should have given to the
     ANS then.
               DR. POWERS:  We haven't see any product from ANS
     at all.
               DR. APOSTOLAKIS:  Yes.  They are more experienced
     fire analysts there.
               When are we going to review this?
               MR. SINGH:  August 28.
               DR. POWERS:  That's when the committee meeting is.
               DR. APOSTOLAKIS:  Do I have it?  You gave it to
               MR. SINGH:  Yes, so you do have it.  I have a
     question.  Did you have a chance to provide a comment on the
               MR. GARDNER:  I did.  I believe I did.  It was
     some time ago, I believe, and I think I remember --
               MR. SINGH:  Let me ask you another question.  When
     I was at the conference last week, they discussed this
               Did you realize that they have taken out the high
     pressure enthalpies from the core and also the -- it's
     really watered down.
               DR. APOSTOLAKIS:  The agency is going to endorse
     it for sure.
               MR. GARDNER:  Isn't it true that 805 will not be
     required to be endorsed?  Is NFPA-805 going to be required
     to be endorsed or is it going to be --
               MR. SINGH:  It's not required, but they are
     forcing the NRC to look at it.
               MR. GARDNER:  But licensees will have an option as
     to whether they choose to enforcement.
               DR. POWERS:  And I suspect the number of licensees
     that will pick it up is going to be zip.
               MR. GARDNER:  That's my point.
               DR. APOSTOLAKIS:  I don't know about that.  If
     it's nice and doesn't get into too much detail and it's a
     national standard, I think the licensees are going to push
     for it.
               DR. POWERS:  It makes Appendix R look like a
     cavalier off-the-cuff document.  It's like doing Appendix R
     with a risk assessment.
               DR. APOSTOLAKIS:  That's tragic.
               MR. GARDNER:  Okay.  Slide 61, the triennial team
     inspection has about 200 hours direct inspection and Region
     III is doing it in two weeks, other regions are doing it in
     a one week time period.  And Region III is an outlier.
               We think that two weeks gives us more time to
     develop our inspection questions and to have the licensee
     give us the answers in a more deliberate fashion, so that we
     feel like we've accomplished what we need to accomplish.
               DR. POWERS:  One of the issues that came up at the
     fire protection forum, and if you're not attending those, I
     would really encourage you to attend.  They are great
     meetings that are put on by NEI, but they have lots and lots
     of information coming in about lots of things.
               One of the questions they had, when you take this
     bag visit, people have been through this, said, gee, it
     works a lot better if the whole team comes for the bag
     visit, not just a few guys.
               Is that what you're planning to do?
               MR. GARDNER:  Yes, sir.  In fact, we had the first
     plat, which was Braidwood, they questioned us as to why we
     had more than a team leader coming.  They thought that just
     the team leaders only should show up and for the reasons I
     spoke to earlier, it's of great benefit for the whole team
     to be there, and that's what we plan to do.
               DR. POWERS:  And I think that's the experience in
     industry.  It makes life a lot easier for them, and actually
     NRC got some pretty high praise for the people running these
     things, saying that they had -- they get a letter that says
     assemble the entire universe of documentation on fire
     protection, that the team leaders have been very effective
     in whittling that down to what actually was needed and used.
               So NRC got some real strokes from the licensees on
     that, triennial inspections.
               MR. GARDNER:  Going on.  We look at the fire area
     boundary design.  Some plants have been forced, because of
     the vintage of the plant, to use huge areas.  Quad Cities,
     originally, based on their design, used practically a whole
     turbine building as one fire area.
               They and most licensees, through further review,
     are trying to narrow the scope of the fire areas to make it
     more user friendly, so to speak, for themselves and for the
               MR. DAPAS:  That's because Quad Cities had to use
     bounding assumptions, because they didn't know the cable
     routing configuration.
               MR. GARDNER:  Yes, and also because unfortunately,
     when the first plants were built in the '60s, they didn't
     understand that it may be better to have more concrete walls
     than fewer, that those concrete walls could, in fact, be
     natural fire barriers.  Brown's Ferry hadn't occurred yet,
     in other words.
               Safe shutdown system selection adequacy.  We see
     if the system they chose to have for makeup or for heat
     dissipation is functional during the fire or after the fire,
     et cetera.
               System separation evaluation, we look at the 3G2
     aspects.  Any questions about those, I can enumerate on
     them.  There's three basic ones.
               When you're doing the inspection, you do a fire
     suppression -- slide 62 -- fire suppression.
               DR. APOSTOLAKIS:  What happened to 61?  I have a
               MR. GARDNER:  Yes, sir.
     DR. APOSTOLAKIS:  The separation, as I recall from Appendix
     R, it says that trace carrying cables or redundant trains
     should be separated by at least 20 feet.
               MR. GARDNER:  There are three criteria, 20 feet is
     one,. No intervening combustibles, and automatic suppression
     and detection, if you use that method.
               MR. GROBE:  That's one exam criteria.  Plus
     suppression and detection, plus no intervening combustibles. 
     The 3G2A says --
               DR. WALLIS:  So this is 20 feet in the horizontal
               MS. BURGESS:  Right.
               MR. DAPAS:  Right.
               DR. APOSTOLAKIS:  But in a PRA context, though, if
     they are 20 feet apart, that will, of course, inhibit spread
     of fire from one tray to the other, but there is a fire in
     the room and they're near the ceiling.  Does it matter if
     it's 20 feet or 30?
               MR. GROBE:  That's why it requires -- the 20 feet
     is permitted, but only with suppression and detection.  So
     you've got a sprinkler system to knock down the heat, you've
     detection to bring the operators in promptly or the fire
               DR. APOSTOLAKIS:  But these are all the
     defense-in-depth measures.  But the separation criteria
     means nothing to identification, because you have a layer
     that tries --
               MR. GROBE:  It's somewhat of a compromise.  There
     is a three-hour barrier or 20 feet horizontal with
     suppression and detection and no intervening combustibles.
               The staff concluded that those were approximately
     equivalent in protective capability.
               DR. APOSTOLAKIS:  But if I have the suppression
     capability, then why do I need the 20 feet?  Why is that
     important if I have --
               MR. GROBE:  Defense-in-depth.  Probability of
               DR. SIEBER:  If they're right up next to each
     other, suppression isn't going to help you.
               DR. APOSTOLAKIS:  I think they had in mind only
     propagation from one tray to the other.  The fact that you
     will have a layer of gases that are hot.
               MR. GARDNER:  Well, if you have the 20 feet of
     separation, you don't have intervening combustibles, and you
     have detection and suppression, we don't affect that the
     fire will affect both redundant trains and we will give you
     credit and say you are successful, you have protected
               DR. APOSTOLAKIS:  If there is a fire somewhere
     else in the room generating hot gases, then both the trays
     will be --
               MR. SINGH:  No, George.
               DR. APOSTOLAKIS:  No?
               MR. SINGH:  If the fire is in the corner, you
     still meet the 20 feet criteria.
               DR. APOSTOLAKIS:  If I have the trays 20 feet
     apart, near the ceiling.
               MR. SINGH:  Right.
               DR. APOSTOLAKIS:  And there is a fire in the
     corner.  Very quickly, if you have enough combustibles,
     you're going to have a hot gas layer there.
               MR. DAPAS:  You have a sprinkler system.
               MR. SINGH:  You have a sprinkler system and you
     have a detection system.
               DR. APOSTOLAKIS:  So then why isn't the sprinkler
     system relevant if the separation is only ten feet?  See, we
     selectively use it when it's --
               MR. DAPAS:  We can only conjecture what was in the
     thought process.  Some of us were around when that happened.
               DR. APOSTOLAKIS:  I think that you do not
     anticipate the hot gas layer from a third fire, that what
     they had in mind was spreading from one to the other, in
     which case all these measures make sense.
               MR. DAPAS:  We could only conjecture what was in
     their thought process.
               DR. APOSTOLAKIS:  There is one fire in the corner. 
     You don't need a second fire.  It is too hot.  The reason
     I'm saying this is because the first time it was pointed out
     was after the first fire PRA was done and people said, yes,
     that is correct.
               MR. GARDNER:  Again, though, if you're going to
     use 20-foot, you can't have intervening combustibles.  If
     you get into a diesel generator room, you're probably going
     to have to use a three-hour or a one-hour fire barrier.
               So, you can't just blindly pick 20-foot.  It
     depends on whether or not there's a chance that a fire that
     could occur as you were postulating in the middle.  Then
     both drains go, but if that can happen, don't try to use the
     20-foot.  Use another one.  Okay?  That's where we'd be
               One of the things -- on the first slide -- the
     first point on slide 62 is the fire suppression damage
               This is the part where, when we come into a fire
     area that we've picked and we do the what-if scenario, what
     could go wrong, in other words, how likely is it, and then
     what are the consequences of it, that's the basis of our
               Licensees would have protected, let's say, through
     20-foot separation, three-hour fire barrier, whatever.  We
     don't find a problem with the barrier and we don't find a
     problem with the 20-foot, our rule indicates it's 21-foot,
               We still don't stop, because what we find is that
     -- let's say, again, the licensee for a fire in that area is
     relying on a charging pump.
               They have reliance on the BCT to be the initial
     source of water.
               DR. WALLIS:  How do you use this ruler when the
     conduits aren't parallel?
               MR. GARDNER:  We can take a average plane, a
     vertical plane, and walk that off.  We can do it.  We look
     at the valves from the DC-2 -- in fact, we've got this
     question at Braidwood.
               The licensee had a cable for one of the valves on
     the BCT that ran through the fire zone and was unprotected,
     and it had been overlooked.
               So, that's the kind of things we look at.
               Sometimes the licensee has manual actions in a
     fire area, and they have -- in their procedure, the operator
     will come in and operate the valve manually.
               At Braidwood, we found they were going into a room
     that was going to be 178 degrees.  Our question was is this
     going to be a good idea?
               They said water packs, and we said, well, it looks
     like he has to be there for cold shutdown.  That's 72 hours. 
     You know, most water packs will start boiling, if you're not
     too careful, after so many hours at 170-some degrees.  It
     won't be boiling, but they'll be darn hot.
               So, we have issues like that.  That's the kind of
     thing we do through every fire area we pick, even when the
     barriers look pristine.
               DR. POWERS:  The step at which you have to assess
     the level of degradation of these is a step I've never
     understood very well.
               MR. GARDNER:  What level of degradation?
               DR. POWERS:  Okay.  When you come in and you look
     at either manual fire capability or the fire suppression and
     detection capability, you have to make some sort of an
     assessment on the level of degradation -- high, medium, or
               MR. GARDNER:  Right.
               DR. POWERS:  And that's the step I've never
               What constitutes high and what constitutes low?
               MR. GARDNER:  It is somewhat subjective.  I'm not
     sure it is completely objective.
               Let's say you found the BCT valve and now you say
     I have a potential fire area degradation; I want to run it
     through a SDP screening.
               Phase one, which would be just a cursory, is there
     a potential for any significance, you whip right through and
     say yes.
               You go into a phase two and you have to calculate
     the fire mitigation frequency, which uses, then -- which
     requires you to have first an ignition frequency for
     whatever combustibles are in that room, it looks at the
     barriers, and if there is degradation of the barriers,
     starting with the fire barriers, you do a moderate or --
     what's the term? -- highly degraded, I think, and those have
     numbers that adjust the risk.
               That's somewhat subjective.
               DR. POWERS:  Yeah.  I mean the numbers that are in
     there, that you actually plug into the formula -- I even
     actually found out where they came from, and they come out
     fine, but you have to make the subjective judgement on these
     things, what's the level of degradation here, and that was
     the step I never understood, and I have a set of notes from
     the BNL course to see if I could understand better just that
     exact issue.
               MR. GARDNER:  I went to the BNL course, and I
     don't think the notes will help you.
               What will happen is this -- whatever method -- and
     we usually are fairly conservative -- you go to, you will
     come out with, let's say, a white issue.  That doesn't end
     the process.  That's when you start refining the level two
     evaluation.  You'll get the SRAs.  The licensee will get
     their own SRAs in there.
               You will elaborate to the licensee what
     assumptions you used to come to a white conclusion.  One of
     them would be that you're assuming significant or high-level
     degradation to the fire barrier or the manual suppression,
     whatever it may be that you're doing in that part of the
     calculation, and the licensee would obviously come back and
     say they think it's moderate, and the difference between
     moderate and significant can make you from a green to a
     white, as you know.
               DR. APOSTOLAKIS:  But shouldn't the ultimate
     criteria, though, be, really, the relative speed with which
     a fire is expected to spread, how quickly you can stop that. 
     That really should be the ultimate criteria.
               MR. GARDNER:  That's a part of it.  It's much more
     complicated than that.
               DR. APOSTOLAKIS:  Like what else?
               MR. GARDNER:  Well, ignition frequency -- okay. 
     First of all, you have to postulate --
               DR. APOSTOLAKIS:  Oh, you mean when you deal with
               MR. GARDNER:  -- the plume and that there is a
     potential for --
               DR. APOSTOLAKIS:  But suppression deals with a
     fire that's already there.
               MR. GARDNER:  Yes.
               DR. APOSTOLAKIS:  So, Dr. Powers asks how do you
     decide that degradation is significant.  What I'm saying is
     the criterion really should be can you arrest the growth of
     the fire before it does damage.
               DR. POWERS:  That's not the way the thing is set
     up, George.
               DR. APOSTOLAKIS:  I know it's not, because it was
     not done using risk assessment.
               DR. POWERS:  Yeah, it was.  It was done using your
     wonderful fire technique.
               DR. APOSTOLAKIS:  No.  No.  We very clearly have
     an equality there.  The time to damage has to be less --
               MR. GARDNER:  I think if you're familiar with the
     fire protection SDP process, you can see that they have
     tried to make --
               DR. APOSTOLAKIS:  It's very hard to do.
               MR. GARDNER:  -- a mathematical estimate of the
     significance, and I think the fire protection is less
     subjective than the internal events.  It makes it more
     difficult and it makes the people that use it have to be
     more sophisticated in their capability to understand risk
     and how to use it, but it's not perfect, and we're going to
     use it, and just like with the other one, we'll probably be
     revising it before long.
               Continuing on with operator recovery action, when
     the fire has been somewhat put out, there's still smoke
     removal, de-watering.
               At FERMI, we had six or seven hundred thousands of
     gallons of water to -- because of surface contamination --
     to decontaminate, and you'd be surprised at the public
     outcry when you tell them you're going to put it through
     filters and send it out to the lake.
               DR. POWERS:  I'm not going to be surprised.
               MR. GARDNER:  That's quite tricky.
               Control re-unitization -- you try to re-establish
     your power systems that you've lost, get all your systems
     back now, instead of the ones that got you to safe shutdown,
     and return to service.
               We also do a manual fire-fighting capability
     assessment just to assist us with the SDP if it becomes an
               As parts of the design aspect we're looking at --
     and that's slide 63 and 64 -- we're looking at electronic
     circuit analyses common enclosure, high-impedance faults,
     spurious circuits.
               If you want to discuss a high-impedance fault,
     it's an arcing fault.
               Any of those things I could talk to you about in
     specifics, but in general, just for the purpose of what we
     do, is we're looking -- as electrical engineers, we're
     looking at common enclosure, associated circuit faults.
               We're looking at common power supply.  This goes
     into breaker coordination, fuse coordination.
               A high-impedance fault is not your classical
     volted fault.  It's not the one where you're estimating the
     contributions of your inductive motors.  As they start
     stopping, they will actually feed faults, and when you're
     doing a normal fault analysis, you have to get all your
               In this case, you're just doing a -- assuming that
     the fault is what they call a arcing fault, and that
     actually can be of more problem than a volted fault.
               DR. APOSTOLAKIS:  How can you have a spurious
     signal from an open circuit?  Can you give me an example?
               MR. GARDNER:  If you have a circuit that's
     supposed to be open and you have a dual ground -- first
     ground on one side of the contact that's open and then you
     ground the other side, you now create a bypass around that
     closed -- an open circuit.
               DR. POWERS:  The Europeans, in testing their new
     modern cable insulation, found out that open circuits became
     closed circuits, because there was some copper oxide in the
     material that got reduced by the boric acid or borate that
     they put into it, and open circuits all became closed.  I
     mean it was a conduction pathway.
               MR. GARDNER:  Sure.
               DR. POWERS:  And so, needless to say, they've kind
     of redesigned that new super insulation.
               MR. SIEBER:  Why are high-impedance faults more
     significant sometimes than volted vaults?
               MR. GARDNER:  If you can visualize the fact that
     you have a distribution panel -- let's say it's feeding
     125-volt DC and you're feeding, let's say, three loads that
     are part of your safe shutdown, and then you have four or
     five loads that aren't, but unfortunately, those four or
     five loads run through the fire area, and we will postulate
     that you will have multiple high-impedance faults on each
     one of those loads that runs through that fire area.
               Each one of them could be an arcing fault, which
     means the current of that fault will be slightly less than
     its breaker.
               So, the combination of all of those currents can
     equal the tripping of the supply breaker to the whole
     distribution panel, which cuts off the power to the one you
     needed to suppress the fire or to deal with the fire.
               MR. GROBE:  We have about 30 minutes left.  We're
     still in fire protection, and then we had a discussion of
     on-line maintenance.
               Is your preference to stay with fire protection?
               DR. POWERS:  I would like to.
               MR. GROBE:  Okay.  And if we have a few minutes --
     Laura, I'm kind of cutting you off, but -- Laura and Mike. 
     If we have a few minutes, we'll talk about on-line
     maintenance; if not, then we'll just conclude with fire
     protection.  And we'll skip the break.
               MR. GARDNER:  Any other questions about hot
     shorts, open circuits, high-impedance faults, common
               DR. POWERS:  Well, you'll never get a resolution
     on that between the NRC and the licensees.
               MR. GROBE:  Well, you're not going to get it from
               DR. POWERS:  I understand.  I'm asking for
     prognostication, not resolution here.
               MR. GARDNER:  I think you're talking about the
     classical question that's confronting us about whether a
     licensee has to assume multiple hot shorts versus a single.
               That issue we wrote a TIA on, which is a task
     interface agreement, and we have not seen the definitive
     answer yet.
               There have been meetings between the staff and NEI
     and the owners groups.
               I believe, in talking to the staff, they're pretty
     sure that our position is going to be the position, but I'm
     sure if I talk to NEI, they'll probably tell me the
               DR. POWERS:  Are your licensees in this particular
     regional happy with that, or are they resisting?
               MR. GARDNER:  No, but Braidwood -- Commonwealth
     Edison is one of the licensees, and they were the basis for
     our task interface agreement.  They emphatically said one.
               MR. GROBE:  Put some time-frames on it, Ron.  The
     TIA was based on Dresden, wasn't it, and that was about four
     years ago?
               MR. GARDNER:  Yeah, four years ago, I'd say, we
     wrote that, right.
               MR. CALDWELL:  I think we were the first region to
     really address the issue.
               MR. GARDNER:  It might have been, yeah.
               MR. SINGH:  Hey, Ron?  Does Perry have that same
     similar problem?
               MR. GARDNER:  Who's that?
               MR. SINGH:  Perry?
               MR. GARDNER:  As far as their position?
               MR. SINGH:  No, I mean do they comply with their
     hot short issue?
               MR. GARDNER:  When you're talking about hot
     shorts, you mean do they assume multiple hot shorts?
               MR. SINGH:  Yes.
               MR. GARDNER:  I'm not sure.  We're getting ready
     to go to Perry, and one of the next two inspections will be
     Perry, and we'll find that out.
               I didn't keep a catalog of who does what.  We're
     going to pick them up on the FPI, and hopefully that will
     give NRR an opportunity to come to one position or the other
     when we find it during these inspections.
               MR. CALDWELL:  I think we scheduled our fire
     protection inspections to target those plants where we
     thought we would probably have the most question in terms of
     their approach, if I recall correctly.
               MR. GARDNER:  We did Braidwood partially for that
     reason.  That was the first one.  Perry is number three, and
     we're going to be looking at that.
               Actually, we also picked Quad-Cities in December,
     because Quad-Cities will complete, we hope, all of the
     modifications necessary to establish full compliance with
     Appendix R by November, which would make our December
     inspection like just in time, and if you have any questions
     on Quad --
               DR. APOSTOLAKIS:  Was there a high number?
               MR. GARDNER:  Yes.
               DR. APOSTOLAKIS:  The result of wrong analysis,
     very conservative analysis, or are they actually doing
     anything about it?
               MR. PARKER:  It depends on who you ask.
               DR. APOSTOLAKIS:  See, that's why I'm asking.
               MR. PARKER:  The licensee pointed out that there
     were some over-conservatisms in their analysis.  So, they
     had to make some bounding assumptions.
               So, that was part of it, and then they did
     implement some compensatory actions and were making
     modifications, because they did agree that their plant had a
     high fire risk vulnerability, but they claimed the 5 times
     to 10 to the minus 3 was really over-stating the full
     as-found condition, if you will.
               MR. GROBE:  You have to appreciate that the
     refined analysis with significant improvement is still 5 10
     to the minus 5.  It's not low-risk, but it's equivalent to
     their --
               DR. APOSTOLAKIS:  Just from fire.
               MR. GROBE:  Yeah, just from fires.
               We have two more topics.  One's the SDP, which I
     sense a lot of familiarity with.  The other is -- we've put
     together some slides on Quad, if you guys are particularly
     interested in Quad.
               DR. POWERS:  I think we can get Quad from another
               MR. GROBE:  Okay.
               MR. GARDNER:  Okay.
               I can finish the last two slides, then.
               Sixty-five is where I was headed.
               The next, baseline use of risk information at the
     baseline fire protection inspection -- and as I tried to
     state earlier that both the triennial and the resident
     inspections are using risk information to guide where they
     look and how significantly and deeply they look when they
     pick those areas; also, that the fire protection
     significance determination process is in its own
     compartmentalized document, and it's IMC-0609, Appendix F,
     and that's a good document to have available if you're going
     to be following fire protection issues.
               DR. POWERS:  At least in the version they gave us,
     there's an egregious typographical error in Appendix F. 
     When you go through the calculations, you come up with --
     depending on how you read the typographical error, either
     with astronomical numbers for any plant or minuscule numbers
     for any plant.
               MR. GARDNER:  We had tried it a few weeks ago at
     Brookhaven, and we didn't find any errors like that, so
     maybe the version we had was a later version.
               Slide 66.
               We would expect that the resident inspector, with
     their understanding of the fire protection issues and the
     complexity of the SDP, would only be involved in phase one
               If it looks like it had to go further, they would
     engage the region and the SRAs.
               The inspection team, however, will do a phase one
     and a phase two, and if, in fact, we find that the phase two
     is heading us towards other than green, we would continue to
     do that, and that would be a more protracted evolution, with
     inputs from the licensee and more refinement with the SRA in
     helping us to look at our assumptions and seeing if we were
     overly conservative.
               That was all I had prepared.
               Jack indicated I have some material on Quad, but
     you indicated you didn't need that.
               So, any questions you have on this material, I'd
     be glad to discuss.
               MR. SIEBER:  I think your presentation was very
               MR. GARDNER:  Thank you.
               MR. GROBE:  You can tell, this is about as excited
     as Ron gets, but this and the SSDI inspection we feel are
     very meaningful inspection efforts.  You can really find
     stuff with this kind of inspection, and we're excited about
     both of those inspection efforts, very detailed,
     design-oriented, intrusive-type inspection.
               If there's a problem, we could find it with this
     type of inspection.
               MR. PARKER:  I hope all our inspections are
     meaningful, though.
               MR. GROBE:  Yeah, but these are new tools that we
     didn't have before.
               DR. APOSTOLAKIS:  There are no performance
     indicators.  They are planning to --
               MR. GARDNER:  No, sir.  I think we haven't --
     we're not smart enough to figure out which ones would be
               DR. POWERS:  Great men have tried.
               MR. GARDNER:  That's right.
               DR. APOSTOLAKIS:  How about fires, the number of
               DR. POWERS:  It just turns out to be meaningless.
               MR. SIEBER:  They're mostly wastebasket fires.
               MR. GROBE:  And they're fairly frequent.  You'll
     have a couple of fires a year.
               DR. SEALE:  Any good performance indicator is
     something that is not so rare that, in itself, it's a
     catastrophic event.  So, you want something that happens
     every once in a while as a performance indicator.
               DR. POWERS:  Yeah, but wastebasket fires just
     aren't going to do anything.
               DR. SEALE:  I agree with you.  I'm saying the
     frequency is not the problem.  It's the wastebasket.
               MR. GARDNER:  I think we're also concerned,
     though, that a low number might lull you into a false sense
     of security.
               So, there's some danger on taking any number and
     saying that is going to make your determination as to
     whether you're there or not as far as defense-in-depth.
               DR. POWERS:  With NFPA, when they tried to do it,
     they ended up putting in this incredible core of Appendix R,
     essentially, kinds of inspections and deterministic
     activities, because there was no way to say, okay, if
     they're doing all this, this indicator will indicate that.
               MR. GROBE:  I think you could develop an indicator
     that could result in your ability to cut back in the
     classical fire protection inspection area, but this and the
     SSDI are very design-oriented, and I can't think of any
     performance indicator that could result in you giving
     justification to cut back in this area, because this is
     focusing not just on ignition sources or initiating events,
     those kinds of things.  I think we could develop an
     indicator in those areas.  It's focusing on did your
     engineers do a good job designing it, in a very complex
               DR. POWERS:  And are your people maintaining it
     and subverting it inadvertently?
               MR. CALDWELL:  Right.  In actuality, the
     performance indicator is the results of the inspections over
     a period of time.
               DR. POWERS:  Yeah, that may be it.
               MR. PARKER:  When we met in Region II to discuss
     inspection resources and how we were going to implement the
     new program and what is the appropriate estimated number of
     hours, there was discussion about the frequency of these
     inspections, and I think there was the recognition across
     the regions that the safety system design inspection and the
     fire protection inspection were -- the two inspections where
     probably the most risk-significant findings will emanate,
     and as a result, do you want to continue with that intrusive
     inspection, versus looking at performance indicators, and
     so, there was that discussion.
               DR. POWERS:  One question, in thinking about
     smoke, are you staying aware of these difficulties people
     are having with their assumptions on how well-sealed their
     control rooms are?
               MR. GARDNER:  You mean to keep the smoke out of
     the control room?
               DR. POWERS:  Yeah, leakage rates.
               MR. CALDWELL:  The control room habitability has
     been a problem as long as I've been in this agency.
               DR. POWERS:  We're seeing occasions of enormous
     discrepancies between what's assumed in the FSAR and what
     the actual tracer gas types of mixing are.  I mean they're
     just not even close.  I mean it wasn't even a good guess. 
     And it's really because the FSAR is writing about what
     somebody drew up on a piece of paper.
               MR. GROBE:  That in-leakage is when the door is
     closed.  If you have an event, that door is going to be
     opening and closing on a regular basis.
               DR. POWERS:  That's another question that comes up
     on the leakage test, is there's a lot of other things
     happening.  The HVAC system gets manipulated around and
     changed, may be off, and whether the test actually relates
     to the environment during an accident, but over and above
     that, even with the test and the conditions you have, we're
     seeing huge discrepancies.
               MR. SIEBER:  Well, the duct work is like a furnace
     duct in your house, and it deteriorates, too.  They use
     those Pittsburgh seams to hold them all together.
               MR. GARDNER:  Well, there's also an over-reliance
     on IEEE-383, I think, cable fire tests, to say that that's
     the end-all to say I won't catch fire.
               In reality, all that does is raise the ignition
     temperature, but once it's ignited, it burns faster and
     hotter than a non-IEEE-383 cable.
               DR. POWERS:  I've heard that.
               MR. GARDNER:  It's true.
               DR. POWERS:  I have not seen the data, but that's
     definitely what I've heard.
               MR. GARDNER:  Yeah.
               DR. POWERS:  But on the other hand, we also find
     that aging cables are less combustible.
               DR. SEALE:  They've already evaporated.
               DR. POWERS:  It's actually a cross-linking thing
     and you get rid of the plasticizers, which are the real
     flammable part.
               MR. GARDNER:  It's the oxygen scavenging from the
     neutrons, yeah.
               MR. GROBE:  Any other questions?
               Laura, you're on.
               MS. COLLINS:  We can be brief.  We don't have that
     many slides.  I'll answer whatever questions you have.
               DR. POWERS:  If you haven't learned by now, the
     ACRS has an infinite supply of questions.
               MS. COLLINS:  I'm going to talk on the topic of
     risk associated with on-line maintenance, and we have a
     procedure in the new baseline inspection program that's
     carried out by the resident inspectors, and it's actually
     7111.13, titled "Maintenance Risk Assessments and Emergent
               Part of that inspection, we would sample between
     five to eight maintenance activities per quarter, and that's
     dependent on a unit size, and I'll say right up front that
     this is a lot more emphasis on reviewing these types of
     assessments than we had under the old core program.
               The concept is to evaluate the effectiveness of
     the licensee's risk assessment and control of the
     maintenance activities.
               That's the objective, and this was really
     developed because we knew (a)(4) was coming, (a)(4), the
     requirement of the maintenance rule, which, really, under
     (a)(3), we previously said they should do a risk assessment,
     and they were for the most part, but we didn't have -- it
     wasn't really a requirement, so now it's becoming a
               Since we knew it was coming, we put it in a
     baseline inspection program and we've been doing it kind of
     ever since then, but I will say, because of that, and
     because (a)(4) isn't fully in effect, we really anticipate
     more changes to this procedure.
               We've had two throughout the pilot program.  The
     guidance is changing.  My understanding is that NRR is even
     going to come out to the region and do a temporary
     instruction, go out to the licensee's facility and really
     see what they're doing and what we should be looking at, to
     help us, I think, define what a finding is going to be in
     this area.
               On the next slide, I've just written down the
     inspection objectives from the inspection procedure.
               We looked at planned work.  We also look at
     emergent work, and then the last bullet is verifying that
     the licensee has adequately identified and resolved problems
     in this area, and that's just a standard thing we have in
     all of our inspectable areas.
               If they come up with some kind of problem in this
     area, we can select that and go in and see what they do
     about it to fix it.
               MR. BONACA:  Some of the emphasis in -- you know,
     in the rule is manage risk.  Any consideration to limit the
     risk?  That's a question which is somewhat open, because in
     absence of criteria and in absence of tools to quantify the
     risk, I mean it seems to me like there is some option there.
               We were shown yesterday that, you know, increasing
     risk from a baseline of about a factor up to 10 is not
     considered high enough increasing risk that you have to go
     to management for approval.  It's a judgement.  It depends
     on how low your baseline is.
               So, any sense on how this is being implemented at
     the sites?
               MS. COLLINS:  Well, we can go on to the next
     slide, where I start to talk about our inspection
               MR. BONACA:  Okay.
               DR. WALLIS:  I was going to ask you -- I see
     you're evaluating effectiveness several times and you're
     looking at adequacy.  Is there a lot of judgement involved
     in this?
               MS. COLLINS:  Absolutely.
               DR. WALLIS:  It's all judgement.
               MS. COLLINS:  It's all judgement at this point,
     and we're looking forward to new guidance and new
     information from NRR, as I said a minute ago, to what would
     be a finding in this area.
               Even right now, we have preliminary information in
     our inspection procedure that I understand is from the NEI
     guidance which we're endorsing with our reg guide, and
     there's different levels with increase in CDF and increase
     in CDP, and I had an inspector call me recently because I
     was in a pilot program and say, well, I'm here at this plant
     and they don't calculate increase in CDP, they only do CDF,
     what do we do about that?
               I don't know what we do about it at this point.
               You know, we're going to -- those are the kinds of
     questions and some of the feedback, I think, that we've been
     giving throughout the pilot program to the program office,
     that not only do we need guidance for licensees, but we need
     the guidance for the inspectors to say what is really an
     issue in this area?
               DR. APOSTOLAKIS:  Now, the NRC staff developed
     this upper bound on the CCDP of 5 10 to the minus 7, I
     believe.  Why can't we use that here?
               I mean instead of having a licensee say, well,
     gee, I'm really managing risk, because under exceptional
     circumstances, all I'm doing is raising the CDF by a factor
     of 3 and I'm already very low, but in the context of, what
     was it, allowed outage times, they came up with this number
     of 5 10 to the minus 7, which means about three hours you
     have a CDF of some value.
               Can that be -- you know, lacking anything else,
     why can't that be a starting point for evaluating or
     verifying how the licensees manage the risk?
               MR. PARKER:  There are some thresholds in some of
     the documents.  The problem I think Laura is pointing out is
     there's no requirement.
               So, if the licensee were to exceed those and the
     residents and the SRAs or challenge the utility, what do we
     do with that and how do we address that?
               DR. APOSTOLAKIS:  The 5 10 to the minus 7 is one
     of the Region V risk-informed regulatory guides.  It may not
     be a requirement here.
               DR. POWERS:  It's an allowed outage time.
               DR. APOSTOLAKIS:  Yeah.  Well, it's an increase,
     an increase in CCDP.
               MR. PARKER:  But I think Laura's point is that
     this task group is looking at the maintenance rule,
     implementing procedures associated with (a)(4) here.  We
     would assess that, you know, what is a finding.
               If we identify that the licensee did a CCDP and
     determined it was greater than 5 times 10 to the minus 7, in
     what context do we put that on the table, what's our
     assessment of that, etcetera.
               DR. APOSTOLAKIS:  I'm not saying this is the
     answer.  I'm saying at least there is a starting point there
     where somebody thought about it and came up with a footnote
     that is really very nice.  We don't know what to do, but
     let's assume this.
               MR. BONACA:  Yeah, because -- in part, also, is
     because -- I mean the risk increases associated with how
     many components you're taking out of service and what kind
     it is.
               Now, especially for those power plants that are on
     24-month cycles, they have plenty of time over two years to
     do maintenance on-line without taking multiple components
     out of service.
               So, what does it mean, this managing risk?  I mean
     does it mean that since I can go up to whatever I want, I
     can take five components out of service simultaneously.
               There is a balancing act there that I don't think
     has been properly defined, and that's why I was asking those
               DR. APOSTOLAKIS:  Maybe that will be the next
     round of refinement.  We haven't really had a chance to
     think about these things.
               MR. CALDWELL:  First of all, at least there's a
     recognition that they have to put something in place to do
     an assessment of it.
               I guess I'm a little removed from the inspection
     program, but what Laura is saying -- we don't have the
     criteria or guidelines yet to do an assessment of it.  But
     at least we're requiring them to do an assessment.
               As we get smarter, those licensees that -- they
     actually know what is good and what's bad.  Those licenses
     that -- because we don't have the tools yet or the whip or
     whatever, the lever -- that want to push the envelope will
     be the ones that we catch as we get smarter and come up with
     our criteria.
               Those that are good and smart and know how to do
     this -- they'll already have set themselves a limit that
     will be within where we end up.
               DR. APOSTOLAKIS:  I think the staff, though, at
     headquarters should think a little bit about this, because
     this is very important.
               Now, yesterday, as Dr. Bonaca said, we were shown
     some spikes in the core damage frequency, but I don't recall
     any discussion of the duration.
               MR. BONACA:  There was no duration.
               DR. APOSTOLAKIS:  There was no duration.  It was
     just the core damage frequency went up, and then they said
     themselves, regions -- you know, we told them to change
     their names, but they call them now very high risk, high
     risk, and so on.
               But they were prepared to go up by a factor of 10.
               Now, you might say, well, gee, they're already
     starting at 5 10 to the minus -- no, 1.5 10 to the minus --
     so, why can't they go to 10 to the minus 4 or a little
               MR. BONACA:  And they implied that they could
     higher if they get management approval.
               DR. APOSTOLAKIS:  I guess the issue you're raising
     is, even if the CDF goes up by some number, it's still not
     clear that adequate protection is still preserved.
               MR. BONACA:  Absolutely.
               DR. APOSTOLAKIS:  I mean that's even higher.
               MR. BONACA:  The other issue is, even if you stay
     within a certain limit, wouldn't just limiting the number of
     components you're taking out of service mean good
               I mean there is the other issue that it doesn't
     say that you have the liberty to go wherever you want, as
     long as you don't meet a certain number.  There is another
     way to do it, which is to only limit the number of
     components you're bringing out of service.
               DR. APOSTOLAKIS:  But then again, you are going
     back to the deterministic way.  I would be reluctant to do
     that.  I would like to explore the CDF and CCDP first. 
     Instead of calculating probabilities of minimal cut-sets,
     count the number of events in there.  So, let's be
     consistent in our evolutions.
               I think we should explore the CDF and CCDP issues,
     see how far we can go with those, and if necessary, then
     we'll go back and limit it more.
               MR. CALDWELL:  For those licensees that have real
     strong management, that are interfacing with the plants on a
     day-to-day basis, they're no different than we are, and
     they're old school, too, deterministic approach.
               For those licensees, they'll probably do that. 
     The manager is going to say I don't want the diesel -- I
     don't want these six components being taken out at the same
     time, I don't care what it says, that doesn't feel good to
     me, and you know, until we have a better approach, we're
     going to have to rely a lot on licensee management in order
     to keep their plant safe.
               MS. COLLINS:  Some of them are pretty developed. 
     I mean they already have these kinds of limits.  The limit
     I've seen in the guidance that's coming out -- CDF -- it
     says something like 10 to the minus 3 should not normally be
               Well, the procedure I'm familiar with is not even
     close to that.  So, they're already way far away from that.
               The other thing that I think is kind of
     self-limiting is resources, taking these systems out of
     components.  Oftentimes, they have LCOs that -- they don't
     have enough resources to take all this stuff out, equipment,
     so I think it's naturally limited that way.
               DR. APOSTOLAKIS:  Let me ask you a question.  In
     your view, should the criteria be bounds on CCDP or CDF?
               MR. PARKER:  Our procedure has both in it.
               MS. COLLINS:  Yeah.
               DR. APOSTOLAKIS:  Very good.
               MR. PARKER:  It has a threshold of the ICCDP of
     less than 10 to the minus 5 and ICCF less than 10 to the
     minus 3.
               So, it's asking the inspectors to look at that if
     they exceed either of those thresholds, because some
     utilities, like Laura pointed out, are using CDP, some are
     using CDF.
               But you want to -- CDP, I believe, would be
     looking at the duration, and you want to factor that in
               DR. APOSTOLAKIS:  If you say that you have an
     ICCDP of 10 to the minus 5, that's almost two orders of
     magnitude greater than what the NRC staff had proposed.
               Now, you are NRC staff, too.  The other staff.
               Yeah, we have to really work on those things and
     make sure that we have some consistency.
               MR. PARKER:  That's instantaneous, too.
               DR. POWERS:  When you look at these plants, do you
     find them taking out multiple systems at the same time?
               MS. COLLINS:  We do find that there are multiple
     systems or multiple components at the same time.
               DR. APOSTOLAKIS:  What's multiple?
               MS. COLLINS:  There could be two or three, but --
               DR. APOSTOLAKIS:  Two or three systems?
               MS. COLLINS:  Yeah.
               MR. PARKER:  Some plants may have divisional
     outages and take out all their divisional equipment or any
     maintenance on a particular division at a time.
               MR. DAPAS:  Train outages.  They'll take out maybe
     RHR and the charging pump, let's say, associated with the
     same train.
               DR. APOSTOLAKIS:  But that doesn't defeat the
     whole system, does it?
               MR. DAPAS:  Sure.
               MR. GROBE:  Sure.  They'll do maintenance on
     several systems on the same train.
               MR. CALDWELL:  Multiple systems within a given
               DR. APOSTOLAKIS:  Is it fair to say, Laura, that
     there is a need for guidance in all three bullets?
               MS. COLLINS:  Oh, yes, absolutely, and we know
     that there are major changes coming to this.  I mean we
     already know that.
               Of all the procedures that we have, this is
     probably the one that is sort of newest to the resident
     inspectors and where they need additional guidance, and I
     think that's a well-known fact.
               DR. APOSTOLAKIS:  Okay.  Thank you.
               MS. COLLINS:  When we go to slide 70, though, and
     talk about inspection techniques, kind of the way -- what we
     do -- we would probably select a planned work week, a week
     or so in advance, or if it's emergent, you know, we don't
     have that time, and we focus on that work that does involve
     the risk-important systems and components.
               We also tend to focus, I think, on unique
     activities or first-time evolutions, and then we take that
     safety assessment, we try to understand what the assumptions
     are, we talk about the licensee's PRA staff, and their
     operations staff, and the next week, perhaps when the work
     is going on, we evaluate the plan and the safety assessment
     against, really, the conduct of the work to make sure that
     it's consistent, and this also applies to shutdown risk
     assessments, where configuration of the plant is changing,
     and we try to know up front what the assumptions are, this
     has got to be back in service before we take this out. 
     Those are the kinds of things we would go out and check.
               MR. CALDWELL:  Laura said something about we'd
     focus in on first-time evolutions.
               I can tell you that once on-line risk started, the
     majority of the transients or events that were caused were
     because they transitioned from an activity they did while
     shut down to an activity while they were operating and
     didn't fully evaluate how they were going to get there, and
     they either didn't tag out a component correctly or they
     operated a piece of equipment the wrong way or whatever that
     resulted in a transient.
               So, it is a good area to focus on as they're
     moving to on-line risk.
               DR. APOSTOLAKIS:  Let's say you have a plant
     that's a 18-month cycle.  If I look at a random -- at the
     plant at a random time during that 18-month period, is there
     a high probability that some on-line maintenance is going
               MS. COLLINS:  Yes, every week.
               DR. APOSTOLAKIS:  Every week.
               MS. COLLINS:  Yes.
               DR. APOSTOLAKIS:  So, I wonder, then, whether the
     -- what so-called baseline CDF is meaningful anymore.  We
     should revise it to take into account this plant's on-line
               MR. DAPAS:  Supposedly, the SDP accounts for that.
               DR. APOSTOLAKIS:  No, no, no, the baseline, the
     PRA itself.
               MR. DAPAS:  When you look at, if a component is
     out of service, what's the additional contribution to the
     baseline CDF, and there's some assumed amount of
     out-of-service time associated with that.
               DR. APOSTOLAKIS:  What I'm saying is you don't
     have a baseline.  If your baseline is moved to the point
     where you have something --
               MR. SIEBER:  You already have assumed a certain
     amount of outage time per component.
               DR. APOSTOLAKIS:  Not with on-line maintenance.
               MR. GROBE:  With on-line maintenance, if you look
     at the fault tree, there's some component for equipment out
     of service time, which can be on-line, can be shutdown.
               DR. POWERS:  What George is saying, I think, is
     that that's gotten kind of averaged over the entire year,
     and in truth, it's peaked, it's spiked, and so, now he's
     moving from spike to spike with maybe a little trough in
     between or something like that.
               DR. APOSTOLAKIS:  What we used to call baseline
     CDF perhaps is not baseline anymore.
               MR. DAPAS:  It may not truly capture the risk
     posture of the plant at the time a piece of equipment is
     taken out of service.
               DR. APOSTOLAKIS:  This is a very interesting
               MR. BONACA:  If they showed that they were
     integrating that value, as I've seen other plants do, to
     assure that you stay within the assumed unavailability in
     the IPE.  So, I mean there is a self-controlling mode.
               DR. APOSTOLAKIS:  No, but what they showed us was
     that there was a line that said this is 1.5 10 to the minus
     5, our baseline, and here we had a spike because we did
     this, then we had another spike because we did something
               Now, Laura is telling me that actually they should
     have spiked every week.
               MR. PARKER:  There are typically spikes every
     week, but I think you're right, they generally --
               DR. APOSTOLAKIS:  If you have a lot of spikes,
     then --
               MR. PARKER:  It has to balance out, because
     they're looking at the availability and the un-availability,
     and that all should be modeled appropriately within the
     scope of the PRA.
               I understand what you're saying as far as the
     spikes, and we need to look at it in a different context.
               MS. COLLINS:  The other part of the maintenance
     rule is sort of their annual assessment where they're
     supposed to be looking at that, and we also go in -- and the
     concept of balancing the unavailability and reliability,
     which I guess we assume that, if they meet their performance
     criteria for those systems and components, that they've
     achieved that goal.
               So, that's under a different inspection procedure
     that's done by Division of Reactor Safety.  They do that
     once a year.
               DR. APOSTOLAKIS:  Okay.  I got the answer.
               MS. COLLINS:  Okay.
               Page 70, the last bullet, I say consult with
     senior reactor analysts.  If we have some kind of an issue
     -- and I say we haven't really decided what a finding in
     this area is -- the SDP doesn't apply to these findings. 
     So, my understanding is that there is a SDP for these kinds
     of issues under development in NRR.
               To date, we've just been using our best judgement
     and the judgement of the SRAs.
               DR. POWERS:  Your understanding is our
     understanding, and you've apparently seen just as much as we
               MS. COLLINS:  Okay.  But I guess the good thing
     is, throughout the pilot program, we've seen pretty good
     programs with risk assessments, and we haven't identified
     what we believe to be any significant issues.
               DR. POWERS:  That does seem to be what we see. 
     For these planned outages, they're doing good work, they're
     doing real good work, and there's an economic incentive,
     because people that do well-planned, well-thought-out work
     have short outages, costs less money to get more done.
               The difficulty is what about unplanned and what
     you call emergent events, and how well is that going to be
     done, and I don't have a handle on that.
               MS. COLLINS:  I think in our experience we've seen
     it done pretty well, but we don't know what's coming.
               DR. POWERS:  Your experience is extremely
     important to me, because you have an experience that I
     don't, and so, I take your word very sensitively.
               MR. DAPAS:  There is a spectrum of performance
     depending on the licensee.
               DR. POWERS:  I'm sure that's true, but I mean if
     the general feeling is, hey, they're doing a pretty good job
     here, then I'm going to worry a lot less about it than oh,
     my god, can I tell you some horror stories.
               MS. COLLINS:  There are a couple of areas that I
     think are of interest to us, and that is how the licensee
     might evaluate initiating event frequencies or
     probabilities, which is kind of what I'm seeing in the
               Other than weather-related, impending weather kind
     of problems, I don't necessarily see a lot of that, and I'm
     not sure how that will be done.  So that's another area that
     I think we'll explore.
               On page 71, inspection observations, again, I said
               DR. APOSTOLAKIS:  Yeah, the second bullet -- would
     you elaborate a little bit?  We don't have to go through all
     of them.
               MS. COLLINS:  Right.  We have seen where the
     duration of the maintenance exceeds the planned duration,
     but if it doesn't exceed an LCO, there isn't much
     involvement we have other than a comment.
               DR. APOSTOLAKIS:  But this is common?  Is this a
     common occurrence?
               MS. COLLINS:  No, I wouldn't say it's common.
               MR. BARTON:  It happens occasionally, yes.
               MS. COLLINS:  But we've seen it.
               MR. BARTON:  Because you have a system outage
     scheduled for 36 hours and it ends up 42 for some kind of
     problem, and that happens not too infrequently.
               MR. DAPAS:  And I just wanted to comment -- this
     has brought to bear an issue where the procedure would ask
     us to assess is the actual time to execute the maintenance
     greater than planned, okay?
               You're asked to look at that as part of the
     inspection procedure.  Then what do you do with that,
     because does that really translate to an increase in risk,
     and they're within the LCO time and they may be within the
     time assumed as part of your baseline CDF.
               What do you do with that, and that's one of the
     questions that we've been wrestling with with the program
               MR. BARTON:  I think you understand why it is it
     happens, and if it's the same cause that always happens,
     then you've got an issue.
               MR. DAPAS:  You're right, but again, the result of
     that has to be some increase in CDF that crosses some
     threshold where you can land that issue with the licensee
     and engage them, versus an observation per se.
               DR. POWERS:  It's like drunk driving convictions. 
     The penalties are very severe in New Mexico for the second
     one, but since they always excuse the first one, nobody ever
     has a second one.
               MR. PARKER:  We've seen that happen on occasion,
     and the SRAs have gotten involved on a few of the issues
     where the licensee's risk assessment assumed, let's say, 36
     hours on a 72-hour, and they had some bounding analysis, and
     now, because of parts availability or some additional
     concern, they might have went up to the 72-hour, and so,
     we've asked the residents, that this is a good opportunity
     to challenge the utility on their risk assessment and their
     bounding analysis and go back to risk assessment and see if
     the licensee is comfortable with the new numbers, where it's
     taken them.
               DR. POWERS:  It's also a good vehicle for asking
     them about the uncertainty in their analyses, what kinds of
     things did they think about that might change their numbers?
               DR. WALLIS:  If this is a best estimate, then half
     the time the duration will exceed the plan, roughly
               DR. POWERS:  Based on the reports I see, I think
     most maintenance is less than the plan.
               DR. WALLIS:  Less than the planned time?
               DR. POWERS:  Yes.
               DR. WALLIS:  So, it isn't so bad that a few take
               MR. DAPAS:  Getting back to Mr. Bonaca's point, I
     would offer that a licensee that is managing the risk would
     say, okay, if we run into a problem, then here is the risk
     if it takes 72 hours versus 20, and that's a sufficient
     increase, now we want to doubly insure we've got parts and
     we've, you know, done mock-up training or what have you to
     ensure the actual time is bounded.
               DR. WALLIS:  But surely all you're really
     interested in is the average over all the maintenance you
     do, and the fact that some may take longer and be a bit more
     risky doesn't matter, as long as it's compensated for
     throughout the year or whatever by the others that take less
               MR. CALDWELL:  We probably have a little more time
     than we anticipated.  O'Hare is closed right now.  So, we're
     calling on your particular flights to find out what that
     actually means.
               My secretary is going to call and check and see if
     it means they've been canceled, delayed, or whatever, and
     then we'll let you know.
               MR. GROBE:  We can give you a nice list of
               MR. CALDWELL:  Flying out of O'Hare and into
     National, which is what we do when we go to headquarters,
     your chances of one of the two of them getting there is 100
               DR. POWERS:  Now, I know why the risk analysts
     here are so busy.  They're calculating the probability the
     boss is going to get back.
               MR. GROBE:  Other questions on 71?
               [No response.]
               MR. GROBE:  Mike, do you want to go into a little
     bit of what you're doing?
               MR. PARKER:  Yeah.  I just wanted to take a little
     time and go through some of the observations that Sonia and
     I had during our SRA site visits.
               We went out to all the sites over the last --
     probably -- I think it was six months to a year ago, and we
     went to each one of the sites together as a team and tried
     to get a pretty good idea of what tools the licensee has,
     how they're using them, and how they're integrating into the
               So, it was more of an observation visit to
     introduce ourselves, to go through the new inspection
     program, and how we're going to -- how we would like to deal
     with them on risk issues, but some of the things we found --
     on-line risk assessments -- most of the utilities were using
     a probabilistic risk assessment such as Safety Monitor,
     EOOS, or Sentinel.
               There were a few outliers out there that are still
     using deterministic.  In other words, they're still using a
     matrix or procedure to look at things, and it's more of a
     defense-in-depth-type approach, and some of them also have
     pre-solved cut-sets that they're using on some of their
     on-line monitors, but it looks like quite a few of them,
     including Commonwealth, is moving to some very good systems. 
     They're going to Sentinel at the Commonwealth facilities.
               So, most of the utilities are using risk programs,
     and there's, I think, one or two outliers right now in our
     region that are still using matrix procedures.
               Shutdown risk assessments -- the majority or all
     of them at this time are deterministic.  Several of them are
     matrix procedures with defense-in-depth, and I'd say the
     majority at this time are using an ORAM-type program, outage
     risk assessment matrix, and that's defense-in-depth.
               We have seen a couple plants that are in the
     region -- I mentioned Perry as an example -- that are
     looking at developing shutdown models right now.  So, that's
     going to be very interesting seeing a full-blown shutdown
     model and how they're using that and integrating it into the
     organization and into outage planning.
               So, it will be a very good tool, but they're
     completing that.  They expect to use it the next outage,
     which is in February, and they're hoping to use it for some
     of their pre-planning activities right now, and they're
     going to tie it back in to -- they need to do some
     conversion and put it into Safety Monitor.
               So, that will be one of our first plants in our
               I know several plants out west are using shutdown
               So, that will be very interesting.
               As far as risk assessments, most of the utilities,
     I think, are doing some very good risk assessments. 
     Generally that's involved with the work week managers and
     not the PRA organizations.
               Generally what we've seen is the PRA organization
     or the corporate staff develop the tools and put them in
     place and then it's turned over to the line organization to
     look at normal work activities, and it's not until they've
     determined that they have a risk-significant configuration
     that they may have the PRA organization get involved and
     deal with the issue and look at the acceptability or
     challenge the model.
               MR. BARTON:  Well, don't they -- if they have any
     changes at all to that planned maintenance, don't they
     bounce that back off their PRA groups?
               MR. PARKER:  Right.
               MR. BARTON:  Okay.
               MR. PARKER:  But some of the organizations will
     have the line organization where they'll put it in the
     schedule and then run the program, and as long as the
     program is, let's say, a green baseline, they won't get
               So, to address George's question as far as what
     happens if they have a higher risk, do they try to balance
     that, some of the plants do, other plants will have like a
     12-week rolling average or rolling schedule, where they have
     certain equipment that comes out periodically, and they will
     try to stick with that equipment at that timeframe and to
     complete that 12-week cycle.  So, they've looked at certain
     combinations of equipment that they would like to take out
     at the same time.
               So, they'll try not to manipulate that equipment
     and put it into a following week.
               As far as integrating risk assessments, I think
     Laura mentioned that, in general, the information we're
     familiar with is licensees are doing a pretty good job at
     integrating their emergent work with the pre-planned, and
     we've seen a lot of occasions where the licensee has
     pre-planned activities, some equipment to identify
     degradation.  They'll put off or defer or cancel some of
     their pre-planned activities so as not to incur that
     additional risk, and so, we've seen some good indications of
     that, which makes us feel pretty comfortable.
               Maintenance rule (a)(4) -- as Laura mentioned,
     that's not out yet.  I think that's supposed to take effect
     in November.
               There are some direction coming out NRR right now.
               There's two visits planned for Region III. 
     There's a visit, I think, in the next few weeks that's
     tentatively set up to go to Braidwood, and with the region's
     assistance, they want the SRAs, the regional inspector, and
     then headquarter involvement just to see how Braidwood does
     activities.  I think Braidwood was picked because they
     indicated they think they have a pretty good program in
     place.  So, that's a one-day visit.
               And then the other activity that's being planned
     is more of a comprehensive V&V inspection, and that's
     planned for Clinton, and that would be more than likely --
     and I'm somewhat speculating, but I think it's to actually
     have the draft TI and see how the utility does things.  So,
     it would be somewhat of a pilot or just maybe go through the
     exercise and see how our procedures develop.
               MR. DUNLOP:  I just got off a phone call a little
     while ago about the (a)(4) rule.  NRR is not really going to
     prepare a TI.  What they're going to do is -- in the
     verification -- is re-validate the new Attachment 13.
               So, during the first survey visit to Braidwood,
     they'll figure out what kind of -- and at all the other
     regions -- they're doing five surveys -- they'll go out,
     look at the different types of assessments that the
     licensees are doing, come up with a new or revised
     inspection program procedure, and then, during the four
     verifications -- ours is at Clinton -- verify that the new
     procedure will work and it will be acceptable.
               That's one change that we just found out, that I
     had just found out today.
               MR. PARKER:  That's Andy Dunlop.  He's with the
     maintenance rule in Region III.
               One of the challenges I think we're going to have
     in the maintenance rule -- and like we said, we don't know
     where it's all going, but we have some thresholds, there's
     some thresholds in some of our reg guides and other
     guidance, but I don't know how we're going to deal with the
     fact if the utilities exceed those thresholds and how they
     balance that and what tool do we have to encourage the
     licensee to reduce that overall risk, and so, those are
     questions that we have outstanding and we'll be involved
     with the development of these activities.
               As far as risk assessments, I think, since the new
     inspection program, there's been significant implementation
     of the licensee evaluating risk.
               In the past, as far as events, we've challenged
     the utilities, and we didn't see that they were truly
     assessing it.
               So, I think the new revised oversight program has
     really forced the utility to look at some of those emergent
     work activities and the impact it has or transients, and
     we're seeing significant involvement on the part of the
     utility to assess that, and Sonia and I are actively
     involved in looking at the impact particular transients have
     on the plant, overall risk, and communicating that in our
     morning meetings and other avenues that we have.
               We've also seen the utility and we've been
     strongly encouraging the utility to address the risk
     significance in LERs.
               An LER asks the licensee to talk about safety
     significance of the event of interest, and we're seeing the
     utilities taking an opportunity to address what they
     characterize as the overall risk significance of the
     activity as part of the safety significance.
               So, I think that helps the region and anybody
     that's following that particular activity to put it in
     perspective.  It gives the licensee their first shot, and
     then certainly the residents and the SRAs are evaluating the
     risk significance of LERs.
               The last thing is -- Sonia has already talked
     about how we're involved with the SDP process in the phase
               Is there any questions?
               That's all I have.
               MR. BARTON:  I want to thank you all for a real
     informative session and thank you for the work you've put
     into it.
               I think, of the visits we've made, this has
     probably been one of the best if not the best, from my
     perspective.  I don't know how the other members feel, but
     it's been very informative and a good dialogue and we
     learned a lot.
               DR. POWERS:  Yeah, I'd say that the meeting far
     exceeded expectations.  I think it was an extremely good
     discussion among colleagues in these areas, and we got some
     things for us to go puzzle about.
               I reiterate my belief that the wealth of
     experience that needs to be injected into this process,
     especially as we look to the next year of refining some of
     it, because you guys are really finding the rough edges, and
     I don't blame the people that put these new systems
               They had millions of things to take into account,
     and they did a wonderful job doing as much as they did, and
     they knew they weren't going to get all the rough edges, and
     so, now, it's a process of making sure we find out about all
     those rough edges and do things, and what we just heard
     about on this maintenance rule business is something I
     hadn't anticipated.
               We've clearly got to think about that a lot in the
     coming weeks.
               So, it's starting to make me think.  This is
     difficult, but I really appreciate it, and we had a
     fantastic visit out at Davis Bessie.  They really pulled the
     stops out for us.
               MR. CALDWELL:  I thoroughly enjoyed this.  I
     learned quite a bit.
               I wanted to compliment the staff, those folks that
     are here.  They did an excellent job, I thought, and Marc
     and Jack, and I certainly appreciate that, as I understand
     you did.
               MR. BARTON:  I think that's what was better.  In
     our past visits, we've heard from the management of the
     region, and I think what was great today is we really heard
     from the people that are out there involved in the process
     and doing the work and having the interface with the
               MR. SINGH:  I just want to thank you, especially
     to Bruce Burgess, for his hospitality here.  He has been
     really helpful, and he has worked since last October to
     arrange all this.
               So, I really appreciate his help.
               MR. CALDWELL:  I think I ought to tell Bruce I
     appreciate it, too, because I jerked him around a bunch
     today, and it came out relatively smooth.
               MR. BARTON:  On that note, the meeting is
               [Whereupon, at 3:08 p.m., the meeting was

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