United States Nuclear Regulatory Commission - Protecting People and the Environment

490th Meeting - March 7, 2002

                Official Transcript of Proceedings

                  NUCLEAR REGULATORY COMMISSION



Title:                    Advisory Committee on Reactor Safeguards
                               490th Meeting - OPEN SESSION



Docket Number:  (not applicable)



Location:                 Rockville, Maryland



Date:                     Thursday, March 7, 2002







Work Order No.: NRC-272                  Pages 1-38/50-97/118-271




                   NEAL R. GROSS AND CO., INC.
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           NUCLEAR REGULATORY COMMISSION
                     + + + + +
  ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS)
                   490TH MEETING
                     + + + + +
                     THURSDAY,
                   MARCH 7, 2002
                     + + + + +
                ROCKVILLE, MARYLAND
                     + + + + +
           
                       The committee met at the Nuclear
           Regulatory Commission, Two White Flint North,
           Room T2B3, 11545 Rockville Pike, at 8:30 a.m.,
           George E. Apostolakis, Chairman, presiding.
           
           COMMITTEE MEMBERS PRESENT:
                 GEORGE E. APOSTOLAKIS       Chairman
                 MARIO V. BONACA             Vice Chairman
                 F. PETER FORD               Member
                 THOMAS S. KRESS             Member
                 DANA A. POWERS              Member
                 WILLIAM J. SHACK            Member
                 JOHN D. SIEBER              Member
           
           ACRS STAFF PRESENT:
                 MAGGALEAN W. WESTON
                 PAUL A. BOEHNERT
                 SAM DURAISWAMY
                 SHER BAHADUR
                 CAROL A. HARRIS
                 JOHN T. LARKINS
                 MICHAEL T. MARKLEY
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
                                 I N D E X
                         AGENDA ITEM                       PAGE
           Opening Remarks by the ACRS Chairman . . . . . . . 4
           Clinton Nuclear Power Station Core Power   . . . . 5
             Uprate
                 By Bill Bohlke . . . . . . . . . . . . . . . 7
                 By Bill Specer . . . . . . . . . . . . . . .11
                 By Eric Schweitzer . . . . . . . . . . . . .32
                 By John Zwolinsky. . . . . . . . . . . . . .78
                 By Ed Throm. . . . . . . . . . . . . . . . .93
                 By Bob Pettis. . . . . . . . . . . . . . . .96
           Proposed NEI 00-04, Option 2 Implementation
           Guideline for Risk-Information for Special
           Treatment Requirements of 10 CFR Part 50
                 By Tony Pietrangelo. . . . . . . . . . . . 170
           Arkansas Nuclear One, Unit 2 Core Power
           Uprate
                 By John D. Sieber. . . . . . . . . . . . . 180
                 By Craig Anderson. . . . . . . . . . . . . 181
                 By Bryan Daiber. . . . . . . . . . . . . . 185
                 By Dale James. . . . . . . . . . . . . . . 208
           Adjourn. . . . . . . . . . . . . . . . . . . . . 271
           
           
           .                           P-R-O-C-E-E-D-I-N-G-S
                                                    (8:33 a.m.)
                       CHAIRMAN APOSTOLAKIS:  The meeting will
           now come to order.  
                       This is the first day of the 490th meeting
           of the Advisory Committee on Reactor Safeguards. 
           During today's meeting, the committee will consider
           the following:  Clinton Nuclear Power Station Unit One
           Core Power Uprate; Proposed NEI 00-04, "Option 2
           Implementation Guideline," for Risk-Informing the
           Special Treatment Requirements of 10 CFR Part 50;
           Arkansas Nuclear One, Unit 2 Core Power Uprate; and
           Proposed ACRS Reports.
                       Portions of the meeting may be closed to
           discuss GE Nuclear Energy and Westinghouse proprietary
           information.  This meeting is being conducted in
           accordance with the provisions of the Federal Advisory
           Committee Act.  Dr. John T. Larkins is the designated
           federal official for the initial portion of the
           meeting.
                       We have received no written comments or
           requests for time to make oral statements from members
           of the public regarding today's sessions.  
                       A transcript of portions of the meeting is
           being kept, and it is requested that the speakers use
           one of the microphones, identify themselves, and speak
           with sufficient clarity and volume so that they can be
           readily heard.
                       The first item on the agenda is the
           Clinton Nuclear Power Station Core Power Uprate.  Dr.
           Powers is the cognizant member.  Please.
                       MEMBER POWERS:  A fact.  Thank you, Mr.
           Chairman.
                       We're going to discuss the Clinton power
           uprate with both the applicant and the staff.  There
           is going to be episodic interruptions in the meeting
           in order to close it to handle proprietary data, and
           I'll beg the Chairman's indulgence for any extension
           of the schedule that occurs because of that.
                       The Clinton power uprate is for BWR6. 
           We've certainly heard power uprates before, but this
           is the first BWR6 we'll hear about.  The uprate is
           significant.  It's overall 20 percent.  It's taking
           place, however, in two steps -- a seven percent, a 13
           percent.  It also involves a change in the fuel.
                       There was a subcommittee meeting dealing
           with this subject, and some draft positions have been
           taken -- developed by that subcommittee.  What the
           subcommittee found was that the licensee is, of
           course, pursuing this power uprate under what has come
           to be called the ELTR1 and ELTR2 methodologies that
           the staff have approved.
                       But, in fact, this is a constant power --
           a constant pressure power uprate, and the details of
           that methodology are still being reviewed by the
           staff.  As a consequence, the applicant will take
           certain exceptions to the ELTR1 and ELTR2
           methodologies, and I encourage the committee to pay
           close attention to these exceptions.
                       At least one of the exceptions is the
           familiar large transient testing that we've discussed
           before.  I'm disappointed Mr. Rosen is not here to
           hear the discussion on that particular exception, but
           there are other exceptions having to do with the
           analyses.  And I, again, suggest the committee pay
           close attention to it.
                       The use of a constant pressure power
           uprate converts the problem of power uprate from one
           that's primarily from a hydraulic issue to one that's
           much more neutronic flavor.  There are, however, some
           thermal hydraulic issues that you have to deal with,
           even for a constant power -- constant pressure power
           uprate, because you've got to have increased flow
           someplace in this system.
                       And, of course, that flow takes -- those
           increases in flow take place in the feedwater and the
           steam flow, and that raises some issues of flow-
           assisted corrosion in some of the piping systems. 
           And, indeed, we have issues of flow-assisted corrosion
           in this particular unit, and I encourage the committee
           to pay close attention to those particular issues.
                       The applicant and the staff, of course,
           think they have this issue well under control through
           a combination of modeling and monitoring.  There is a
           history in the nuclear industry of these methods not
           working, with some substantial consequences.  So it's
           worth paying attention to that.
                       With that introduction, I will turn to Mr.
           Bill Bohlke from the applicant to begin the discussion
           of their proposed extended power uprate for the
           Clinton Power Station Unit Number 1.
                       MR. BOHLKE:  Thank you.  Good morning, Mr.
           Chairman, and members of the committee.  I'm Bill
           Bohlke, Senior Vice President of Nuclear Services for
           Exelon Generation.
                       I just thought I'd spend a minute or so
           giving you the background on AmerGen, which is a
           company that you may not be particularly familiar
           with.
                       MEMBER POWERS:  True.
                       MR. BOHLKE:  AmerGen is co-owned by
           British Energy and Exelon.  When it was recently
           formed, it was co-owned by British Energy and PECO. 
           But with the Comed and PECO merger, Exelon assumed the
           original PECO share.  So that's the ownership, and
           AmerGen is, in fact, the licensee.
                       Operationally, Clinton is part of the
           Midwest Regional Operating Group, just as Oyster Creek
           and TMI are parts of the Mid-Atlantic Regional
           Operating Group.  What that means is we share a Chief
           Nuclear Officer, who last week became Jack Scolds who
           succeeded Oliver Kingsley who is now our head of
           generation.
                       And specifically, in the Midwest, the
           executive direction and corporate oversight for the
           Clinton station is executed by the Midwest ROG out of
           Warrenville, Illinois.
                       The staffing for Clinton, similar to the
           staffing for the other two AmerGen units, is a
           combination of Exelon employees and AmerGen employees. 
           Those AmerGen employees have various heritages
           depending upon the utility from which they came.  In
           fact, the station leadership at Clinton currently
           consists of a site vice president, plant manager, site
           engineering director, site operations director, and
           training manager, all of whom are Exelon Nuclear
           employees.
                       So we also use Exelon policies, Exelon
           programs and processes, down to a level where we want
           station or unit individuality as opposed to common or
           standardized processes, so that many of the
           organizational structure and management approaches for
           Clinton are the Exelon approaches.  And the technical
           approaches, including the technical approaches
           embodied in this request for power increase, is
           derived from the Exelon approach.
                       Specifically, this is a fourth boiling
           water reactor station in Illinois that we've subjected
           to this.  LaSalle was the first one, and you reviewed
           that in either late '99 or early 2000.  And then, of
           course, last fall you heard the presentation on the
           Dresden and Quad Cities power uprates.  
                       Dresden 2, in fact, has been uprated and
           is operating at 912 megawatts, which is its generator
           limit.  That startup and testing went extremely
           smoothly.  Quad Cities 2 has just completed its outage
           and is at about 40 percent power this morning going --
           undergoing its testing.  And so far so good on that
           one also.  So Clinton will be the fourth in a series
           of that.
                       To try to achieve continuity, the project
           manager for the Clinton power uprate was, in fact,
           project manager for the LaSalle power uprate.  Some of
           the technical people are the same.  You probably
           recognize some of them.  So what we do is we allow
           ourselves to benefit from the lessons learned and move
           it on down the line, so that every project has a
           benefit of its predecessor.
                       And so what we'll see is, when we do the
           startup testing for Clinton, it's subject to the
           granting of the power uprate license.  We'll have
           startup testing personnel who have worked at Dresden
           or Quad or LaSalle previously, so that we'll have that
           lessons learned.  We think that's a real strength of
           the program.
                       So that's the extent of my introductory
           remarks.  I did want to set the stage for that, and
           now let me introduce Dale Spencer, who is the Project
           Manager for the Clinton extended power uprate.  
                       Thank you.
                       MEMBER POWERS:  Mr. Bohlke, I appreciate
           your giving us that introduction to this company.  We
           see the name all the time, but we really don't know
           too much about it.
                       MR. BOHLKE:  You're quite welcome.
                       MR. SPENCER:  Thank you, Bill.  Good
           morning.
                       Dale Spencer, Exelon Nuclear, Project
           Manager for the Clinton Unit 1 extended power uprate. 
           Over the next hour, our experts will be providing a
           summary of the EPU project, including the
           modifications, the analyses performed, and our plans
           for implementation.  Presentation material has been
           chosen based on the agenda that been provided to us by
           the ACRS.
                       As we discussed previously, portions of
           our material are proprietary to the General Electric
           Company, and we'll ask that a portion of the meeting
           be closed.  We have grouped the information that's
           proprietary together, so we can minimize
           interruptions.
                       MEMBER POWERS:  If you will just indicate
           to me when you need to close it --
                       MR. SPENCER:  Yes, sir, we will.
                       MEMBER POWERS:  -- we will go through
           whatever machinations we have to.
                       MR. SPENCER:  Yes.  Yes, sir, we will.
                       As an introduction, I want to first spend
           a few minutes and provide a summary of the overall EPU
           project, and then I'll follow by an overview of the
           modifications and analyses that we have performed.
                       We're requesting a license for a 20
           percent increase in reactor power.  We use the GE
           standard EPU process as the guide for our analyses and
           the schedule.  These GE processes, as you know, have
           been used for a number of extended and stretch power
           uprates in the industry, both domestically and abroad.
                       We'll be performing modifications to the
           plant to facilitate power ascension, and I'll cover
           these in more detail in a couple of slides.  And these
           modifications will be installed between now and early
           2004.
                       Of these modifications, we'll show that
           we're making relatively few changes to the operation
           of safety systems.  Our plans are to implement the
           power ascension in two steps.  The first step will be
           -- take place when we start up this May after our
           refueling outage.
                       MEMBER POWERS:  Let me ask a question. 
           You make a point that you're making relatively few
           changes to the safety system.  Am I supposed to derive
           comfort from that?
                       MR. SPENCER:  Yes.
                       MEMBER POWERS:  Why?
                       MR. SPENCER:  Essentially, our analyses
           have shown that the modifications to the plant and the
           limits to the plant post uprate will be on the BOP
           side.  Our changes are essentially, as I'll get into
           in the next slide, the nuclear instrumentation that
           we're going into.  Other plants have gotten into
           modifications in other areas, and with the BWR6 we
           have found that this is not the need.  And this is a
           plus.
                       MEMBER POWERS:  I mean, what you're
           essentially saying is that your safety systems have
           enough margin to handle the additional 20 percent.
                       MR. SPENCER:  Absolutely.
                       MEMBER POWERS:  Okay.  But, clearly,
           you're reducing the margins you have in those systems.
                       MR. SPENCER:  Yes, absolutely.
                       MEMBER POWERS:  And somehow that's
           acceptable.
                       MR. SPENCER:  Yes, it is.
                       We talked about our first step for our
           license, for our power ascension in May of this year. 
           And the second step of our power ascension will take
           place after our ninth outage, and that's scheduled for
           early 2004.
                       On the next slide is a simple graph of the
           power-to-flow map at EPU conditions.  For clarity, in
           the upper right-hand corner, the gold area, is the EPU
           operating region.  Simply, as we stated in the
           subcommittee, we're increasing power along the
           previously licensed MELLLA flow control line.  
                       Other plants that have licensed the
           extended power uprate have licensed the MELLLA as part
           of their EPU process.  In the case of Clinton, this
           has already been licensed, so we are not changing any
           of the flow control line in our power uprate.
                       MEMBER KRESS:  The axis is 100 percent of
           what?  The core flow is for what -- percent of what? 
           I mean, core power -- core flow.  Is that 100 percent
           of what?
                       MEMBER POWERS:  It's both.  I mean, the
           question applies to both.
                       MEMBER KRESS:  Yes.  What are the units on
           your --
                       MR. SPENCER:  The axis on the power is the
           100 percent of uprated reactor power, in the top of
           the graph right here, the 3473.
                       MEMBER KRESS:  Okay.  So that's the full
           new uprated power.
                       MR. SPENCER:  Yes, sir.
                       MEMBER KRESS:  What's the one on the
           bottom?
                       MR. SPENCER:  The one on the bottom is the
           core flow.  The core flow is not changing.  The core
           flow is based on the capability of the recirc system. 
           So we will need to --
                       MEMBER KRESS:  So when you go up to 110
           percent almost there, what does that mean?
                       MR. SPENCER:  I'm sorry.  Which --
                       MEMBER KRESS:  Well, at the --
                       MR. SPENCER:  Are you looking right in
           here?
                       MEMBER KRESS:  No.  Looking at the yellow
           part.
                       MEMBER SHACK:  The X axis.
                       MEMBER KRESS:  The X axis, and looking
           there.  That's like 109 percent or something.
                       MR. SPENCER:  Oh.  This is the ICF, the
           increased core flow region.  This is previously
           licensed on --
                       MEMBER KRESS:  This is the previously
           licensed core flow.
                       MR. SPENCER:  Yes, sir.
                       MEMBER KRESS:  There's a maximum core flow
           in your license?
                       MR. SPENCER:  Yes, sir.
                       MEMBER KRESS:  I see.
                       MR. SPENCER:  This was our license as we
           have it right now, and it's in the same X axis, if you
           can see on the graph.
                       MEMBER KRESS:  The dotted line is --
                       MR. SPENCER:  Yes.
                       MEMBER KRESS:  It goes all the way up to
           108 percent?
                       MR. SPENCER:  In core flow, that's
           correct.
                       MEMBER KRESS:  Okay.  
                       MR. SPENCER:  You know, that's actually
           107, I believe.
                       MEMBER KRESS:  Is there any reason why you
           can't use that little triangle up at the top?
                       MR. SPENCER:  That's basically the
           capability of the recirc system.
                       MEMBER KRESS:  Okay.  You would have to
           change out your jet pumps to --
                       MR. SPENCER:  That would be a pretty
           significant change.  Yes, sir, that's correct.
                       On the next slide, I just have a brief
           summary of the change in plant conditions graphically. 
           Briefly, the increase in steam flow is accomplished by
           replacement of the high pressure turbine, and, thus,
           no changes in the reactor steam dome pressure is
           needed.  And we discussed this at the opening of the
           meeting.
                       I'd like to spend just a few minutes going
           over some of the modifications we'll be performing. 
           As we stated in our uprate safety analysis report, no
           safety-related hardware changes will be required to
           implement the EPU at Clinton.  
                       Upon issuance of the revised operating
           license, we're going to perform changes to nuclear
           instrumentation which will allow us to increase our
           output.  These set point changes include the APRM, the
           flow bias, both the SCRAM and the rod block, the main
           steam line group 1 isolation, the control and stop
           valve and recirc pump trip bypasses, and the low power
           and high power set points on the control rod block
           pattern controller.
                       Proceeding to the modifications we'll be
           performing on the BOP side of the plant, as I talked
           previously, we're going to be implementing our power
           ascension in two steps.  During our upcoming refueling
           outage, we'll be replacing the high pressure turbine. 
           We'll be replacing the main power transformers, as
           well as associated changes to the isolated phase bus
           duct configuration and cooling.  
                       The main generator hydrogen coolers will
           be replaced, and we'll increase the hydrogen pressure
           in the generator from the current 60 to 75 pounds. 
           The exciter anode transformer will be replaced, and
           we'll be upgrading five supports associated with the
           feedwater system, all of which will allow us to
           achieve the additional 80 plus megawatts for the next
           operating cycle.
                       MEMBER POWERS:  When you make changes in
           your hydrogen system, changes in transformers, how do
           you affect the risk of fire-initiated accidents in
           your plant?
                       MR. SPENCER:  The fire-initiated accidents
           were analyzed, and we are going to be discussing some
           of the risk from all of the risk factors a little bit
           later in the presentation.  I believe Bill Burchill is
           going to get into that at some later time.  Can we
           discuss that then, or would you like to --
                       MEMBER POWERS:  That would be fine.
                       MR. SPENCER:  Okay.  And that is part of
           our presentation material at a later time.
                       Proceeding on, to ensure we get the full
           potential from our uprate, we'll be performing
           additional modifications to -- and I call them BOP
           efficiency improvements in the future.  These are
           targeted to be installed either online or during the
           ninth refueling outage to facilitate future power
           increases.  And since these are a little bit down the
           road, these modifications are in the scoping stage,
           and I'm just going to provide a conceptual overview
           right now.
                       Improvements will be made to the condenser
           to perform at a higher efficiency.  Improvements will
           be made to allow condensate polisher stop rate and
           balanced flow configuration at the higher condensate
           flows we expected.  Moisture separator reheat Chevrons
           will be replaced to improve the MSR, and that goes
           forth to the plant efficiency.
                       Changes will be made to the breakers,
           conductors, relay schemes associated with the
           switchyard to allow the increased megawatts electric
           and MVA output of the plant.  Improvements to the
           exciter plan, which will allow the plant to run at the
           full capability of the generator.  And we do foresee
           future improvements in the cooling capability of the
           bus duct cooling.
                       MEMBER FORD:  Can you just elaborate on
           the --
                       CHAIRMAN APOSTOLAKIS:  Microphone.
                       MEMBER FORD:  Could you elaborate on the
           main condenser improvements?  What are they, and why
           are they being made?
                       MR. SPENCER:  Okay.  These are changes
           that we're going to make in our ninth refueling
           outage, which is currently scheduled for early 2004. 
           And I'll preface it with the fact that we're doing
           conceptual studies, and this is not finalized at this
           time.
                       The most -- I'll say the most front
           runners we have right now are changes in online
           cleaning system and making sure that we're using the
           condenser to its full capability, not having any air
           entrained in the condenser.  Essentially, making sure
           we run it at its highest efficiency.
                       MEMBER FORD:  With the increased steam
           flow, are you not expecting vibration problems in the
           condenser --
                       MR. SPENCER:  We have --
                       MEMBER FORD:  -- with the current design?
                       MR. SPENCER:  We have performed analyses
           of the condenser tubes.  We are -- obviously, we are
           putting more steam flow in.  We have analyzed this to
           be acceptable.
                       MEMBER FORD:  Was there any basis for
           saying that?  I mean, is it based on analysis, or
           other plants' experience?  I guess these are GE
           turbines, and there's plenty of other GE turbines with
           the same design out there.
                       MR. SPENCER:  Sure.  And --
                       MEMBER FORD:  Are there any with the same
           flow rate, the increased flow rates, to draw on?
                       MR. SPENCER:  For our analysis, we used a
           specialty vendor who does this kind of work in several
           locations, and every condenser is just a little bit
           different.  There is a mix between analytical
           techniques and actual industry experience that he
           factors into his work.  We also do routinely monitor
           the performance and perform inspections on equipment,
           even down to the condenser stage in our plant.  And
           that's an ongoing type evaluation.
                       We'll continue to do these inspections
           even post uprate and continually monitor the
           performance of all of our plant equipment.
                       MEMBER FORD:  Okay.  So these improvements
           aren't necessarily related to increased steam flow,
           the EPU.  It's just -- you just want to increase the
           efficiency.  It's got nothing at all to do with --
           it's not driven by the fact that you've got increased
           steam flow.
                       MR. SPENCER:  At the current efficiency of
           the condenser, it's not -- we're not going to be able
           to get a whole lot extra out of the condenser, unless
           we do something to it.  So it is a little bit of both.
                       MEMBER FORD:  Okay.  Thank you.
                       MR. SPENCER:  So I'd like to change the
           focus just a little bit here, and I want to
           concentrate on some of the analyses and evaluations
           that we've performed in support of EPU.  Listed on the
           slide are the specific subjects for which we have
           prepared presentation material and our experts will be
           talking.
                       As I stated previously, we have chosen the
           subjects based on the agenda provided us to the ACRS. 
           So at this time, I'd like to introduce Fran Bolger of
           General Electric, who will discuss the core and fuels
           analyses.
                       MR. BOLGER:  Morning.  I'd like to discuss
           some of the details of the core fuel analysis that
           have been performed.  As part of the power uprate,
           there was an equilibrium core analysis, which did
           demonstrate a full extended power uprate power, that
           the core was able to provide the desired energy and
           have adequate thermal margins.
                       I'd like to discuss some of the details of
           the actual core design which was performed for
           Cycle 9.  Cycle 9 is the first step in the two-step
           process that was previously described.
                       Next slide.
                       To the left, there is a -- this is a
           picture of the core design for Cycle 9.  What you see
           are the color -- these shaded bundles are the fresh
           core, the fresh bundles in the core.  Up here on the
           top you see the locations.  And the I and J location,
           we'll be talking a little bit about those.
                       Looking at the core design map, you'll
           notice a value in the center of each square, and
           that's the bundle exposure, megawatt days per shore
           ton.  The zero indicates that it's a fresh bundle.
                       The value here on the bottom, which you
           can't see very well, that correlates to a bundle type
           used in the simulator.  This core was analyzed with
           the PANACEA 3D simulator, and that relates to this
           value here called IAT down here on the bottom.
                       If you look on the bottom, you'll see the
           bundles that are loaded in this core.  The top bundle
           is a two cycle depleted bundle, which is a GE10 type
           fuel, which is eight by eight design.  The next two
           bundles are one cycle depleted bundles, which are GE14
           type.  And the last two are the fresh fuel, which are
           also GE14 type.
                       If you look, you'll -- if you look on this
           bundle name, you'll see these numbers here.  These
           indicate what the bundle average enrichment is for the
           bundle.  There is 268 fresh bundles being loaded,
           which is a fairly large bag size.  These values here
           are the batch average exposures for the fresh bundles
           at beginning of cycle.
                       Over here on the right is a batch average
           radial peaking.  These values are actually rounded two
           points past the decimal.  
                       What I'd like to do now is talk a little
           bit about -- a question?
                       VICE CHAIRMAN BONACA:  Just G14, what is
           it, a 10 by 10, 11 by 11?
                       MR. BOLGER:  G14 is a 10 by 10 design.
                       VICE CHAIRMAN BONACA:  10 by 10.
                       MR. BOLGER:  I'd like to talk now about
           some of the results -- the key results in the core
           design, cycle design analysis.  Over here on the right
           you see this column here, which is the cycle exposure,
           and this is measured in megawatt days per shore ton. 
           And you see the core is designed with various steps
           through the cycle, and each one of these steps has a
           different control rod pattern.
                       For example, you see here this is the
           control rod pattern at the beginning of cycle.  You
           see the rod positions shown here on the map.  The red
           boxes are actually the controlled cell locations.
                       The next column is the critical Eiger
           value.  When a core is designed, a target critical
           Eiger value is developed through the cycle, and this
           target is developed based on previous cycle experience
           with that plant.  It's based on other plants with a
           similar fuel design and size, and also based on the
           fuel design characteristics.
                       The next column is a -- is for this
           depletion, the core flow as a function of exposure. 
           If you look at the core flow, you'll notice that some
           of the core flow values are below what was on that top
           corner of the power flow map previously shown.  The
           minimum core flow at full EPU is 99 percent, but this
           is lower than that because this depletion is actually
           about 90 percent of full EPU power.
                       The next column is the ratio of the
           operating limit, minimum critical power ratio -- I'll
           call it MCPR -- to the calculated MCPR.  When a core
           is designed, you try to achieve sufficient MCPR margin
           so that the core will operate when it is actually
           monitored in the plant.  You design the core typically
           with about seven percent MCPR margin.  
                       In this case, this core -- the maximum is
           about .9, and so there is a little bit of margin
           relative to what typically would be the target of
           about .93.  So there is actually a little bit
           additional margin, and this core could probably
           operate at a little bit higher power.
                       These values in parentheses over on the
           right of the MCPR margin is the location of the
           limiting bundle, and those values correspond to these
           locations on this I and J location over here on the
           core map.  And you see the limiting location does move
           around in the core.
                       The next column is the ratio of the
           calculated peak rod LHGR relative over the LHGR limit. 
           And in this case these locations are the I and J
           location as described over here, but also this right-
           most is the axial location.  The core is designed with
           25 axial nodes.  So, for example, you see over here
           node 4 is toward the bottom corner of the core.
                       MEMBER POWERS:  You said that the core was
           designed with 25 axial nodes.  Do you really mean it
           was analyzed with 25 axial nodes?
                       MR. BOLGER:  Yes, that's correct.  The
           core was analyzed with 25 axial nodes.
                       The right -- this column here is the ratio
           of the average planar linear heat generation rate to
           the average planar linear heat generation rate limit. 
           And this is where the LOCA limits are factored in.
                       The right-most column is the core average
           axial power shape peak value, and what you see here is
           the value for the core average peak and the node.  For
           example, node 10 is toward the center of the core. 
           You'll notice that the core peak for most of the time
           in the cycle is toward the bottom of the core.  And as
           you get down toward the end of the cycle, the power
           shade moves up to the top.
                       The BWR will naturally try to peak to the
           bottom because of the voids -- the voids in the core. 
           The core -- this core, as shown, has -- provides the
           desired energy and has adequate MCPR and LHGR margin.
                       Next slide, please.
                       What I'm showing here is -- this is the
           same core design as you saw on the previous slide at
           beginning of cycle.  This is just to show what you
           would get if you depleted the same core with the same
           control rod patterns at a lower reactor power -- in
           this case, about a seven percent lower reactor power.
                       You'll see, if you compare the two pages,
           that the critical Eiger value is slightly higher,
           because it's at a lower void fraction.  The thermal
           limits are lower because -- obviously, because the
           core is at a lower core thermal power.  
                       And you'll also see that the power shape
           has shifted up somewhat, because the core is at a
           higher void fraction.  That allows the power shape to
           move somewhat.
                       If this were an actual design in this
           case, there is more than adequate MCPR and LHGR
           margin.  So you would -- the designer would try to
           take advantage of that additional margin.  And we'd
           try to reduce bundles.  We would try to move some of
           the bundles towards the center to try and improve the
           efficiency of the core.  The designer might try to
           simplify the operating rod patterns to give more
           flexibility to the site.
                       So the designer will actually try to
           target the same margins to limits at the power level
           that it is being designed to.
                       Next slide, please.
                       MEMBER POWERS:  Might I ask you one
           question on this?  Your axial power peak moves fairly
           continuously through this.  But there's a
           discontinuity in the node where you have your axial
           peak power.  That occurs around an exposure of 11,500. 
           Why does that discontinuity occur?
                       MR. BOLGER:  Right here you see the power
           shape moving -- moves -- starts moving up to the top. 
           You'll also -- I can't tell you exactly, but you'll
           notice that the actual peak is -- the value of the
           peak is not very different.  It could be that the
           power shapes are -- have a double peak or a fairly
           flat distribution, and just a very small variation in
           the power shape will shift it up to the top.
                       MEMBER POWERS:  So this is more a
           numerical thing than it is --
                       MR. BOLGER:  Yes.
                       MEMBER POWERS:  -- a real discontinuity in
           the core performance.
                       MR. BOLGER:  Yes. 
                       Next slide.
                       In summary, the equilibrium core design
           that was analyzed for the EPU, and also the Cycle 9
           design, has adequate margin.
                       Any questions?  I'd like to -- the next
           presenter is Eric Schweitzer from AmerGen, who will
           present the containment analysis.
                       MEMBER POWERS:  Maybe before you depart,
           I'll just ask you one question.  The fuel exposures
           that you've shown in these two analyses are relatively
           modest.  If I ask you about Cycles 10, 11, and 12,
           what kinds of fuel exposures do you anticipate taking
           fuel to?
                       MR. BOLGER:  You know, I don't -- I can
           just answer you generally.
                       MEMBER POWERS:  Yes, a general answer is
           fine.
                       MR. BOLGER:  You know, the fact that the
           batch size is fairly large means that the two cycle
           depleted bundles are -- it's not a full batch, and
           it's -- you wouldn't expect it to go to a three cycle
           depleted bundle.  So the fuel will be depleted -- will
           be discharged after its second cycle.  And the two
           cycle depleted bundles are primarily on the periphery.
                       So from a batch average standpoint, the
           batch has not a significantly different batch
           discharge than you would have if it were depleted at
           the current rate of power, just because the batch size
           would be lower and it would be possible to have a
           larger percentage of the batch loaded in the internal
           part of the core on the -- on its third cycle.
                       MEMBER POWERS:  Can you give me a number?
                       MR. BOLGER:  I don't have the value with
           me.
                       MEMBER POWERS:  It sounds like you're
           going to discharge something a little over 30.
                       MR. BOLGER:  I have a picture of the end
           of cycle exposure map.  It may be around slide 30 or
           so of the backups.  Actually, you're interested more
           on the -- even the further on cycles.
                       MEMBER POWERS:  I'm really interested in
           the --
                       MR. BOHLKE:  Dr. Powers, let me see if I
           can -- if I recall correctly -- this is Bill Bohlke
           from Exelon.  We won't have any burnups over 50,000
           megawatt days per ton.
                       MEMBER POWERS:  That's what it sounded
           like.  Thank you.  That's all the more precision I
           needed.
                       VICE CHAIRMAN BONACA:  Just have a
           question regarding the cycle length.  What is the
           cycle length of Cycle 9?
                       MR. BOLGER:  The cycle length for Cycle 9
           is a 21-month cycle. 
                       VICE CHAIRMAN BONACA:  And the following
           cycles, are they planning the same cycle length or --
                       MR. BOLGER:  Maybe Exelon would like to
           discuss that.
                       MR. SPENCER:  Future cycle lengths.
                       MR. SCHWEITZER:  Your question was, what
           is the future cycle lengths?
                       VICE CHAIRMAN BONACA:  Yes.  Are you going
           to stay at a 21-month cycle or --
                       MR. SCHWEITZER:  Exelon does plan to
           transition to 24-month cycles, and there will be a
           future license amendment submittal for that.
                       VICE CHAIRMAN BONACA:  Any idea now how
           that would change some of this neutronics here?  What
           you just showed us?
                       MR. BOLGER:  With -- go back to the
           previous slide.  There is a -- for a 24-month cycle,
           there is a little margin for a higher enrichment. 
           These bundles have not been designed to the maximum
           enrichment capability.  So they can probably go to
           about the 415 level, and that will provide some
           additional energy for a 24-month cycle.
                       There is a benefit in having higher
           enrichment bundles in preceding cycles.  They will
           carry more of the load as they get down into further
           cycles.  So as you have higher enrichment
           transitioning, that will help you to create such a
           core design.  And there is still a little bit of room
           to add a little more fuel, so it'll be challenging but
           the capability exists to do that.
                       VICE CHAIRMAN BONACA:  Thank you.
                       MR. SCHWEITZER:  My name is Eric
           Schweitzer from AmerGen, and I'd like to present the
           Clinton MARK III containment analysis.
                       To evaluate the containment for extended
           power uprate, we followed the established method for
           containment analysis in ELTR1.  The limiting events
           that were analyzed were the main steam line break, the
           recirculation suction line break, and the alternate
           shutdown cooling.
                       The next slide shows a summary of the
           results.  This table shows the drywell and containment
           pressures and temperatures and the suppression pool
           temperature following the analyzed events.  The first
           column of values on the left are the original analysis
           in the Clinton updated safety analysis report.
                       The second column of values are the
           comparison benchmark cases, which used the EPU methods
           with the original licensed power.  The third column of
           values are the EPU results, and the last column shows
           the design basis.
                       Comparing the first and second columns
           shows the effect of the change in methodology.  And
           comparing the second and third columns shows the
           effect of EPU, which is relatively minor with no
           vessel pressure change.  Comparing the third and
           fourth columns shows the margins to the limits.
                       I'd like to point out that all remain
           below the design limit with the exception of the
           drywell temperature.  This value is above the design
           temperature of 330 degrees for less than .5 seconds. 
           This has been evaluated as acceptable, because there
           is insufficient time to heat up the structure.
                       In conclusion, these results show
           acceptable performance for the containment in EPU.
                       MEMBER FORD:  Could I ask a question? 
           This is more for clarification.  This seems fine,
           assuming that a containment maintains its original
           integrity.  Now, I'm out of my depth here, but that's
           a big assumption, isn't it?  That the containment
           maintains its original design integrity.  Could you
           not have degradation of that integrity?
                       MR. SCHWEITZER:  The containment is tested
           on a periodic basis, leak rate tested, and so it's
           maintained.
                       MEMBER FORD:  So corrosion of rebar, for
           instance, that would be detected?
                       MR. SCHWEITZER:  The leakage would
           definitely be detected, if that would cause any
           leakage, but the strength of the materials would not
           be expected to be changed outside its design margins.
                       MEMBER FORD:  I know this is a topic that
           can be -- probably go into the -- a revised version of
           GALL.  But you're taking as right that the monitoring
           programs you have regarding the containment integrity
           are adequate.
                       MR. BOHLKE:  Dr. Kress, let me -- excuse
           me.  Dr. Ford, let me answer that.  First of all, it's
           a steel containment.
                       MEMBER FORD:  It's a steel containment.
                       MR. BOHLKE:  And it's accessible.  It's go
           ta shield going around it, so it's accessible for
           inspections and it does have the periodic leak rate
           test --
                       MEMBER FORD:  So it's rather like Oyster
           Creek.
                       MR. BOHLKE:  -- of the penetrations and
           the shell as a whole.  So it's pretty robust, and it's
           pretty inspectable.  We don't -- we have been doing
           containment ISI inspections on other plants in the
           fleet, and the extent of corrosion that we found after
           as much as 30 years of operation at Dresden and Quad
           Cities, for example, is pretty minimal.  But, in fact,
           there is an inspection program as part of our
           requirements.
                       MEMBER FORD:  The reason why I bring up
           the question is I never hear this topic mentioned, and
           yet I remember when I was employed by General Electric
           that we were concerned about corrosion at Oyster Creek
           of the containment.
                       MR. BOHLKE:  That's right.  Exactly.
                       MEMBER FORD:  And I have never heard
           anything along these lines mentioned since, and this
           is why I just bring the question up.  As I say, it's
           more for my information.  Are we kind of opening up a
           potential there for --
                       MR. BOHLKE:  No.  We think we're okay
           because we have a program which specifically focuses
           on that.
                       MEMBER FORD:  Fine.  Okay.  Good.
                       MEMBER POWERS:  I'm a little surprised
           that the applicant didn't bring to your attention that
           in establishing these limits that they take a certain
           amount of corrosion and degradation into account.  I
           mean, there is a margin built into them for those
           reasons.
                       MEMBER FORD:  Yes.  A concern -- my
           concern is that whenever you look at these corrosion
           allowances they are almost going to be picked out of
           the air.
                       MEMBER POWERS:  They are, and they are
           minuscule compared to what you saw at Oyster Creek.
                       MEMBER FORD:  Correct.  Correct.
                       MR. BYAM:  Good morning.  I'm Tim Byam
           with AmerGen.  The next part of our presentation will
           address the exceptions that we've taken to the
           requirements specified in the extended power uprate
           licensing topical reports.  That is, ELTR1 and ELTR2.
                       This portion of our presentation does
           contain General Electric company proprietary
           information, and we, therefore, ask that the meeting
           be closed at this point.
                       MEMBER POWERS:  Okay.  There will be a
           little interruption while we go through our steps
           here.
                       MR. STROMQUIST:  This is Eric Stromquist
           from General Electric.  I'd kindly ask that Mr.
           Wilson, Mr. Huff, and Mr. Moss leave.
                       MEMBER POWERS:  You will switch to --
                       CHAIRMAN APOSTOLAKIS:  You have to speak
           in the microphone.
                       MR. STROMQUIST:  I'm sorry.
                       MEMBER POWERS:  I don't know for this
           step, but we need to -- no, I don't think this is --
           we should be switching at this point.
                       MR. STROMQUIST:  This is Eric Stromquist
           with General Electric.  All persons are acceptable in
           the room now.
                       MEMBER POWERS:  Thank you.
                       (Whereupon, the proceedings went
           immediately into Closed Session.)
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           .                       CHAIRMAN APOSTOLAKIS:  Okay.  Proceed.
                       MR. BYAM:  Kent Scott will now continue
           with our presentation on the anticipated transient
           without SCRAM event response.
                       MR. SCOTT:  Thanks, Tim.
                       Now I would like to discuss the response
           of the plant to an ATWS at uprated conditions.  First,
           we found our response as operators to an ATWS remains
           unchanged.  For example, when we lower reactor water
           level to reduce subcooling and trip the reactor
           recirculation pumps, we find the plant operating at
           the same power-to-flow conditions as pre-EPU.  
                       This is due to the fact that the plant is
           currently licensed and operating under the maximum
           extended operating domain analysis.  This is the
           MELLLA analysis with increased core flow that Dale
           spoke of earlier.
                       Since we already operate at these extended
           load lines, the plant reacts the same, simply moving
           down the existing load line on recirculation pump
           trips.  Also, the symptoms we must observe as
           operators to detect an ATWS remains unchanged.
                       And, finally, our actions to mitigate an
           ATWS remain unchanged for controlling reactor power,
           reactor level, and reactor pressure.
                       MEMBER KRESS:  But do you have to change
           how far you lower the water level into the core?
                       MR. SCOTT:  No.  We haven't changed -- we
           still lower level to the same values.  We train on the
           same bands that we lowered the level to reduce
           subcooling.  So that did not change at all.
                       VICE CHAIRMAN BONACA:  The time for you to
           take action, however, has been reduced, right?
                       MR. SCOTT:  And the analysis that Bill
           Burchill is going to talk about a little bit later
           about probabilistic risk assessment talks about those
           times.  Those times are well within the capabilities
           of the operators to perform.  The sequence of the
           actions we take are the same.  The required times do
           reduce, but they are well within the capabilities of
           the operators.  We're trained to do that, and I fully
           expect everybody to be --
                       VICE CHAIRMAN BONACA:  Could you tell me
           what the times are?  I mean, just for information.
                       MR. SCOTT:  And Bill may be able to help
           me out a little bit with those times.  I could tell
           you on the order, but I'd rather Bill tell you some
           particulars with that.  Bill?
                       MR. BURCHILL:  This is Bill Burchill with
           Exelon.  The realistic analysis indicates that with --
           I think it's with one slick pump the time is reduced
           from nine minutes to six minutes, and with two it's
           from 12 to nine minutes.  And those times, as you
           recognize, are well beyond the licensing calculation,
           which assumes the times are on the order of a couple
           of minutes.
                       MR. SCOTT:  Right.  And my experience with
           initiating standby liquid control in an ATWS situation
           -- the times that Bill is talking about are an
           eternity for operators to get those actions performed.
                       MR. BURCHILL:  Yes.  This is Bill Burchill
           again.  Again, the operator, of course, operates off
           of symptoms.  You know, the response is specifically
           to the symptom, and, you know, the time is probably
           not in their mind at the moment when they're doing
           that.  They're reacting to a symptom and taking
           action.
                       VICE CHAIRMAN BONACA:  Yes.  But, I mean,
           time available is important to determine whether they
           will take the action within a certain time.  
                       Now, you mentioned something about two
           minutes.  That's the design basis analysis rather than
           the -- so these values you gave us, nine minutes
           versus six, are a best estimate?
                       MR. SCOTT:  Those are the probabilistic
           risk assessment values, realistic analyses.
                       MR. BURCHILL:  Right.  Right.  Dr. Bonaca,
           those are based on map runs specifically to look at
           the time available.
                       VICE CHAIRMAN BONACA:  Okay.  But your
           ATWS analysis that you have docketed with the NRC has
           different values.
                       MR. BURCHILL:  Those are the licensing
           analysis.  You're correct.
                       VICE CHAIRMAN BONACA:  And two minutes are
           the reduced times for this design, or the previous --
                       MR. BURCHILL:  Two minutes are the design.
                       VICE CHAIRMAN BONACA:  And before it used
           to be three?  Two?  Two.  So --
                       MR. BURCHILL:  Yes, it's the same.
                       VICE CHAIRMAN BONACA:  Why would it be the
           same?
                       MR. BURCHILL:  I'm sorry.  I didn't
           understand.
                       VICE CHAIRMAN BONACA:  I said, why would
           it be the same time?
                       MR. BURCHILL:  Because it's already a
           bounding time.  It's already well within what we
           consider as a realistic evaluation of the time
           available.
                       VICE CHAIRMAN BONACA:  I mean, as a number
           that comes out of an analysis, which is a bounding
           analysis, I would have expected to see a change in
           that time, too, with respect --
                       MR. PAPPONE:  Yes.  This is Dan Pappone,
           GE.  The two minutes is actually an input assumption
           into the analysis.  And, again, that's based on --
           that's based on the knowledge that the operators are
           going to be working off of the symptoms, performing
           the same actions based on the same symptoms that are
           occurring actually a little faster when you get to
           power uprate, when you're looking at power levels
           going up and water levels coming down.
                       When you're getting into those ATWS
           situations, the symptoms are going a little bit
           faster.  So the operator is going to go through his
           motions in the same time period.  The two minutes is
           what we're assuming in the analysis.  It's not a
           number coming out -- it's not a number calculated from
           the analysis results.
                       VICE CHAIRMAN BONACA:  Okay.  thank you.
                       MR. SCOTT:  Okay.  One thing we have done
           is to raise the minimum allowable standby liquid --
                       CHAIRMAN APOSTOLAKIS:  Let me understand
           this.  The two minutes are used in the analysis.  What
           analysis is this?
                       MR. SCOTT:  Dan, can you --
                       MR. PAPPONE:  This is Dan Pappone again. 
           We perform a safety analysis to confirm that the peak
           vessel pressure, the peak suppression pool
           temperatures, are going to be acceptable.  And in
           performing that analysis, we have to make certain
           assumptions, say, on operator reactions, because we're
           using --
                       CHAIRMAN APOSTOLAKIS:  So the shorter you
           assume the action is, the more optimistic you are,
           aren't you?
                       VICE CHAIRMAN BONACA:  That's right.
                       CHAIRMAN APOSTOLAKIS:  So if you are
           saying in the PRA that the actual number will be
           around six minutes, and you assume two, then the
           deterministic analysis is optimistic.
                       MR. PAPPONE:  No.  The --
                       CHAIRMAN APOSTOLAKIS:  No?  Am I missing
           something?
                       MEMBER POWERS:  It's the time available.
                       MR. PAPPONE:  The PRA analysis is looking
           at the maximum time available for the operator to
           perform those actions as part of a success criteria. 
           He has a period of six minutes or nine minutes to
           perform that action. 
                       CHAIRMAN APOSTOLAKIS:  Okay.  And in --
                       MR. PAPPONE:  And if he completes that
           action within that time, then the event is successful. 
           If he fails --
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MR. PAPPONE:  -- if he fails to complete
           that action in that six minutes, then that's
           considered failure.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MR. PAPPONE:  It's just a simple success
           criteria on the PRA side.
                       CHAIRMAN APOSTOLAKIS:  Yes.  Well, I mean,
           if I do the deterministic analysis --
                       MR. PAPPONE:  The deterministic
           analysis --
                       CHAIRMAN APOSTOLAKIS:  -- it's six minutes
           down to two minutes.
                       MR. PAPPONE:  No, no.  The --
                       VICE CHAIRMAN BONACA:  The deterministic
           was a previous analysis they did for licensing --
                       MEMBER SHACK:  No.  But George's point is
           if they used six minutes in the deterministic
           analysis, they wouldn't have liked the answer.
                       MR. PAPPONE:  Absolutely.
                       CHAIRMAN APOSTOLAKIS:  And, therefore,
           would you fill in the blanks there?
                       MR. PAPPONE:  The deterministic analysis
           has certain levels of conservatisms in the code.  So
           that's going to -- and methods that we're using.  So
           that's going to push the answer above what we'd like
           to see.  In the PRA analysis --
                       CHAIRMAN APOSTOLAKIS:  But we can't
           separate the PRA analysis from everything else.  I
           mean, it's not a different world.
                       MR. PAPPONE:  But it's a different set of
           -- it's a different set of modeling assumptions that
           are used in the calculation.
                       CHAIRMAN APOSTOLAKIS:  For the same
           system.
                       MR. PAPPONE:  Right.
                       CHAIRMAN APOSTOLAKIS:  Yes.  So, you know,
           which ones do we go by?  I mean, would the calculated
           temperatures and pressures change significantly if you
           assumed a realistic six-minute response time?
                       MR. SCOTT:  In my experience, as an
           operator and watching the crews train, and being a
           part of the crews in training, is that the PRA
           analysis versus the two-minute analysis, it doesn't
           matter to me.  You know, my actions are the same.
                       I'm going to step through, and I'm going
           to do those actions in the same amount of time.  I can
           get those actions done in two minutes whether we have
           a power -- whether I'm at 50 percent power or 100
           percent power or at 120 percent power.  It doesn't
           matter.
                       I think the key is that as long as we can
           say that, yes, the times change from nine to six
           minutes, and two minutes is still bounding, I'm
           comfortable as an operator in being able to take those
           actions to protect the plant.
                       CHAIRMAN APOSTOLAKIS:  Right.  And you are
           speaking now in PRA space, the response of the
           operators.
                       MR. BURCHILL:  Well, this is Bill Burchill
           again.  I want to clarify one thing, Dr. Apostolakis. 
           The PRA doesn't calculate that it will take the
           operator six minutes.
                       CHAIRMAN APOSTOLAKIS:  I understand that. 
           I understand that.  It's the deterministic analysis
           that bothers me.
                       VICE CHAIRMAN BONACA:  Yes.  
                       CHAIRMAN APOSTOLAKIS:  I mean, the --
                       MEMBER SHACK:  Well, he's using a more
           conservative analysis.  You know, it's sort of a
           bounding analysis versus a best estimate.  So that
           when he does the bounding analysis --
                       VICE CHAIRMAN BONACA:  Yes.  But two
           things bother me there.  One is that for the
           deterministic analysis there must have been a best
           case that was analyzed some time in the past for this
           plant that said that, based on conservative estimates
           of what it takes to reach those points, it takes two
           minutes.  Okay?
                       And now you are saying you feel
           comfortable with two minutes, and I don't.  I mean, at
           some point I will become uncomfortable.
                       MEMBER SHACK:  Well, I think the answer is
           he takes the action in two minutes.
                       VICE CHAIRMAN BONACA:  I understand.
                       MEMBER SHACK:  And, you know, he gets 1440
           in one case and 1477 in the other.  So as he keeps the
           time fixed and he ups the power, the temperature does
           go up, which is what you would expect.
                       VICE CHAIRMAN BONACA:  Yes.  No, but I was
           saying that now I would have expected that if you now
           go up in power you will have a change in that time.
                       MEMBER SHACK:  He kept that time fixed,
           presumably because the regulator accepted the two
           minutes, and so he lives with the two minutes and sees
           what happens.
                       MR. CARUSO:  Dr. Bonaca, this is Ralph
           Caruso from the staff.  I've been informed that I
           believe that the two minutes was a number that came
           about as part of the original ATWS rulemaking.
                       VICE CHAIRMAN BONACA:  That's right.
                       MR. CARUSO:  That was an input assumption
           that was established at that time as a reasonable
           amount of time for an operator to respond to these. 
           So that's an input to these assumptions.
                       I believe also there's a comparison going
           on here between a deterministic calculation using one
           particular GE code and the PRA calculations which are
           done using the MAP code, which is an entirely
           different code.  So you get -- unfortunately, you get
           different numbers when you use different codes.
                       VICE CHAIRMAN BONACA:  I understand.  But
           the fact is, you know, it's important we understand
           how going up in power -- okay, what effect it's going
           to have on operator reaction.
                       MR. CARUSO:  Yes.
                       VICE CHAIRMAN BONACA:  And time is always
           an effect on that.  There may be confidence on the
           part of the operator that he can perform the action,
           but at some point the confidence will be decreased,
           just because time is an issue for him to detect, to
           respond, and to take action.  
                       So that's why we're pursuing this kind of
           questioning, and it's confusing to hear an assumed
           number of two minutes for the ATWS and, you know,
           there -- I would have to look at the analysis to
           understand why it's done in a particular way, because
           you cannot get an input from that.  And, therefore, we
           have to depend on the MAP analysis to get the sense of
           time dependency.  That's the whole issue.
                       CHAIRMAN APOSTOLAKIS:  So we have to live
           with the two minutes, then.  This is something
           that's --
                       VICE CHAIRMAN BONACA:  I guess so.
                       CHAIRMAN APOSTOLAKIS:  -- NRC given.
                       MEMBER KRESS:  Well, the two minutes --
                       MEMBER SHACK:  NRC accepted at least.
                       MEMBER KRESS:  The two minutes in the
           original rule must have come out of observations on
           simulators and saying, "Well, they've always" --
                       MEMBER POWERS:  Oh, I wouldn't think so. 
           I bet -- I bet the original analysis came out a wide-
           ass guess with a bunch of conservative --
                       MEMBER KRESS:  Well, it's one of --
                       MEMBER POWERS:  -- considerations.
                       MEMBER KRESS:  It could be one or the
           other.
                       MEMBER POWERS:  It could be one or the
           other.
                       MR. CARUSO:  I am informed by people who
           have some knowledge of this that this arose out of the
           recirculation pump trip time.  And there are a number
           of different things that go into this 120-second value
           that's used.  We can identify this for you in more
           detail if you wish, where it came from, but I think
           the issue here really is, for the deterministic
           analysis, they use a value of 120 seconds, then come
           up with a certain result which is acceptable.
                       In PRA space, they've determined that they
           might be able to go even longer, might be able to go
           six or nine minutes.  
                       VICE CHAIRMAN BONACA:  Okay.
                       MR. CARUSO:  Okay?  But as the operators
           here are saying, they feel comfortable that they would
           recognize these symptoms and respond to them very
           quickly.  So there is a little bit of a disconnect
           here, but it's -- I think it's explainable and
           understandable.  It's more of an artifact of the way
           that the different methods calculate these parameters.
                       CHAIRMAN APOSTOLAKIS:  So if they respond
           in six minutes instead of two, in real life now, the
           peak clad temperature will be higher than this, won't
           it?
                       MR. BURCHILL:  This is Bill Burchill
           again.  No.  In fact, if they respond in the six or
           nine minutes, depending upon the number of pumps, they
           will meet all of the success criteria in the PRA
           analysis.  It's likely you would not meet the
           licensing limit, but you would be using an apples and
           oranges comparison because --
                       VICE CHAIRMAN BONACA:  The 2200 degrees? 
           Is that the licensing --
                       MR. BURCHILL:  Right.  But that also has
           restrictions on the -- you know, the various inputs to
           the calculation, the heat transfer correlations, and
           all of that stuff that we're -- you know,
           traditionally imposed on the design basis analysis,
           which would not be true in a realistic analysis that's
           used for the PRA.
                       CHAIRMAN APOSTOLAKIS:  So where does that
           leave us?  I don't understand that.  Now, are you
           saying --
                       MEMBER POWERS:  Wherever it leaves us,
           let's move on, so that I cannot destroy your schedule.
                       MEMBER KRESS:  It leaves us with the
           thought that the idea of using best estimate codes
           with 95 percent confidence was a pretty good idea,
           because you can understand what the number is.
                       VICE CHAIRMAN BONACA:  Well, I think it
           would have been interesting I guess -- and I really
           don't need -- I accept the fact that two minutes in
           the design basis analysis are acceptable for both
           conditions.  I would have liked to know at what point
           I could see those two minutes -- what number does it
           become before it becomes unacceptable?  You know, to
           understand what -- how the margins --
                       MEMBER POWERS:  It depends on -- it
           depends critically on whether you're taking core
           damage as your criteria for acceptability or 2200
           degrees Fahrenheit as your criteria for acceptability.
                       VICE CHAIRMAN BONACA:  I mean, whatever
           was the licensing value. 
                       MEMBER POWERS:  I mean, it seems to me
           that had I known when I did the analysis for peak clad
           temperature that my maximum temperature was going to
           be 1440, I would have said, "Well, instead of putting
           in two minutes for that criteria, I'll put in three
           and a half, because I've got more room and I like my
           operators.  I don't want to put too much torque on
           them."  And, indeed, they would have probably found
           that they met the 2200.
                       If instead they said your criteria is core
           damage, they might well have been able to put in seven
           minutes.
                       VICE CHAIRMAN BONACA:  Well, I understand
           that, but that was --
                       MEMBER POWERS:  Or 15 minutes maybe.
                       MR. CARUSO:  Dr. Powers, I mean, actually,
           you're focusing on peak clad temperature here.  For
           ATWS events, the more limiting parameter is the pool
           temperature. 
                       MEMBER POWERS:  And if I bring that up, I
           protract a discussion that's already gone on too long. 
           Okay?
                       MR. CARUSO:  Oh, okay.  I just wanted to
           make that point.  Everyone is focusing on peak clad
           temperature, but in an ATWS really the limit that
           you're going to hit first is the suppression pool
           temperature.  That's more important than the peak clad
           temperature, because you've got water going through
           the core.  So you -- it's -- you're going to keep --
                       MEMBER POWERS:  They were trying to
           understand where the time comes, and I was --
                       MR. CARUSO:  Okay.
                       MEMBER POWERS:  -- trying to point it out
           to them.  And even if you had taken the suppression
           pool temperature in PRA space, that's not too
           important.  What is overpressurization of the drywell
           becomes important.
                       MR. CARUSO:  Right.
                       MEMBER POWERS:  And the times even go
           longer than that.
                       MR. CARUSO:  Right.
                       MEMBER POWERS:  Can we go ahead?
                       MR. SCOTT:  Certainly.  Okay.  One thing
           that we have done is to raise the minimum allowable
           standby liquid control boron concentration with --
                       MEMBER POWERS:  The points that you might
           want to make is, where do you inject your boron into
           this core?
                       MR. SCOTT:  The boron goes in through the
           high pressure core spray sparger, which goes right
           onto the core, so it's a core --
                       MEMBER POWERS:  On top of the core.  
                       MR. SCOTT:  That's correct.
                       MEMBER POWERS:  And not on the bottom. 
           And so now you're not relying on raising and lowering
           the water to mix the boron.
                       MR. SCOTT:  That's correct.
                       MEMBER POWERS:  That's an important
           feature of this plant.
                       MR. SCOTT:  Thank you. 
                       So we are raising the minimum allowable
           standby liquid control boron concentration to ensure
           the rate of negative reactivity addition remains
           acceptable after the power uprate.  And we have
           included the table here.  I'm showing some of the
           major parameters pre- and post EPU, along with the
           associated design limits.
                       And just to conclude, that these values
           show and support the acceptability of maintaining the
           existing operator response to an ATWS after
           implementing the power uprate.  
                       So now I'd like to introduce Harold
           Crockett from Exelon Nuclear, who will discuss plant
           response to flow accelerated corrosion.
                       MR. CROCKETT:  Thank you, Kent.
                       I'm Harold Crockett, and I'm the flow
           accelerated corrosion program manager for AmerGen and
           Exelon, and I'd like to talk with you a few minutes
           about our program and what we have done.
                       The Clinton station has a program that is
           consistent with the industry recognized EPRI
           recommendations for flow accelerated corrosion, and
           what we have done is we have updated our analysis with
           the new design conditions.
                       MEMBER POWERS:  And the spelling of
           CHECKWORKS.
                       MR. CROCKETT:  Yes.  And as noted, we use
           the EPRI program CHECKWORKS.  It is a predictive
           analysis.  And because our analysis is largely cycle-
           dependent, dissolved oxygen temperatures flow, we want
           to look at each line that is modeled.  
                       And so what we did, we saw the results,
           and in our particular station here, the scavenging
           steam line had the most significant increase.  And we
           wanted to cite this example, because the numbers are
           a little bit high in the world of fact.
                       Normally, there are generally small
           numbers -- wear rates are maybe five mils per year and
           you get a 15 percent increase, so you're up to a
           whopping six mils per year.  This one was a little bit
           higher.  We went and focused on this particular line
           and looked at the actual measured wear and compared it
           with the previous predicted wear.  Actual measured
           wear was about 20 mils per year, and the old predicted
           methodology gave us 38 mils per year.
                       And what -- the goal is to merge the
           predicted with the measured and get a refined
           correction factor on this --
                       MEMBER POWERS:  Well, somehow 52 mils per
           year doesn't give me much more comfort than 70 mils
           per year.
                       MR. CROCKETT:  That's correct.  And as
           we'll note further down, this particular line we will
           be visiting for replacement.  We have found that
           proactive replacement is a good policy for us if, at
           the same station we've seen wear, or at our other
           stations we've seen wear.
                       By the time you put up the scaffolding and
           remove the insulation, you've spent so much effort
           that a lot of times it's easiest just to go ahead and
           upgrade it with chrome-olly and stainless.  And yes,
           sir, you're exactly right.  We have done that, and we
           continue to do that.
                       We've learned a lot in the past decade
           about which lines are wearing.  And Clinton being a
           younger station, they're just getting to the point
           where they're doing some of these replacements.
                       MEMBER FORD:  Maybe it's a moot point if
           you're going to replace the carbon steel steam line
           with chrome-olly.  But could you comment on the
           qualification of CHECKWORKS for wet steam?  Given the
           fact that there are different corrosion mechanisms or
           different corrosion criteria between wet steam and
           water.  So how well has CHECKWORKS been qualified by
           observation versus prediction, with steam versus
           water?
                       MR. CROCKETT:  Yes, sir.  The check family
           predictions -- the CHECKWORKS, it is set up for a
           single phase and two phase, and steam quality is an
           input.  And we continue to refine the code.  There has
           not been a dramatic amount of changes in the past
           eight years.  There's been some small refinements.
                       EPRI sponsors meetings twice a year, and
           we are very active in those meetings, which is the
           domestic utilities as well as the international
           utilities.  We have strong support from around the
           world at these meetings.  And when we're seeing high
           wear we go visit those very areas.  So it's --
           everybody is pretty much talking to each other.
                       MEMBER FORD:  Would the fact that there
           are different mechanisms involved, between those two
           environments, is it fair --
                       MR. CROCKETT:  Yes, sir.
                       MEMBER FORD:  -- is it fair to use
           CHECKWORKS from one -- from water and then just do a
           flip to steam?
                       MR. CROCKETT:  Right.  As I mentioned
           earlier, steam quality is an input.  And what we're
           really talking about is not a mechanical attack.  It's
           a corrosive attack.  It's a dissolution of the oxide
           layer -- washes away, dissolves the next oxide layer,
           and repeats itself.
                       And it is different, but the code has been
           consistently substantiated where it has been used. 
           And there have been some industry events, and the code
           was not properly used.  I think at the last
           subcommittee meeting --
                       MEMBER FORD:  Okay.
                       MR. CROCKETT:  -- they talked a little bit
           about Fort Calhoun's rupture.  And when they did go
           back and look at the code and properly analyze it, it
           did have wear rates that were exactly or very
           consistently with the --
                       MEMBER FORD:  But a difference between
           less than 20 and 38, between measured and calculated,
           that's not unusual.  Is that unusual or not?
                       MR. CROCKETT:  That is not unusual to have
           a predicted off by that much.  And that's why we
           continue to select, inspect, and evaluate, and feed it
           back into the process.  It's not unusual for it to be
           off by that much.
                       MEMBER FORD:  And is a discrepancy always
           the same way?
                       MR. CROCKETT:  No, sir.  It can be --
                       MEMBER FORD:  Plus or minus.
                       MR. CROCKETT:  That is correct.
                       MEMBER FORD:  Oh, okay.
                       MR. CROCKETT:  It could be more than
           measured in a prediction or less.
                       MEMBER FORD:  Okay.
                       MR. CROCKETT:  As I mentioned earlier, the
           model will continue to be calibrated with post-EPU
           conditions.  And these changes were anticipated.  We
           talk about power uprates at our conferences, so the
           code is consistently applied.
                       The schedule replacements, we will
           continue to inspect this particular line, both trains
           of it.  So if we get up to data we receive from this
           particular outage that will start up next month, we
           may elect to proactively replace this line even before
           that time.  But it is an ongoing process.
                       And the programmatic controls are in place
           to ensure that inspections continue, and the extent of
           the condition is assessed.  So if we find wear, we'll
           measure upstream and downstream and that -- that
           analysis.
                       MEMBER POWERS:  Let me just ask one point
           of fact.  This line that's corroding at 70 mils per
           year in your analysis, what's the wall thickness on
           it?
                       MR. CROCKETT:  This is a half-inch wall
           thickness.
                       MEMBER POWERS:  Half-inch.  And I can't
           resist just pointing out that programmatic controls
           were in place at Fort Calhoun and Surry.
                       MR. CROCKETT:  Well, Surry certainly was
           the birthplace of the modern codes.  And Fort Calhoun
           -- I was asked to be on a team that assessed that
           particular station.  And prior to their rupture, they
           had not been active with the industry meetings.  And
           their analysis was partial I guess would be the way to
           address that.
                       MEMBER POWERS:  A generous way to put it.
                       MR. CROCKETT:  Yes. 
                       MEMBER SHACK:  What are your wear rates in
           your feedwater lines?
                       MR. CROCKETT:  Feedwater lines -- BWRs
           typically, because of the dissolved oxygen, are not
           high.  Some of the PWRs have had some feedwater
           replacements --
                       MEMBER SHACK:  It's a big difference.  But
           just -- I mean, is it a couple mils a year?
                       MR. CROCKETT:  On the order of five to 10
           mils per year.  And that's a much thicker pipe
           typically.  That's an inch and a half or more.  
                       Yes, sir.
                       MEMBER FORD:  I have a question, not
           related to flow assisted accelerated corrosion. 
           Fluent use vibration -- I recognize that fatigue is
           probably another problem in the upper head.  However,
           there have been stress corrosion problems of core
           spray lines and dryers, and this was brought up at the
           Quad Cities and Dresden applications.
                       We raised the question about whether
           there's a loose parts problem, and we were assured
           that it was not a problem.  Has this been revisited
           for this particular station -- Clinton?
                       MR. MOSER:  Yes.  Dr. Ford, Keith Moser,
           Exelon, Reactor and Internals Program Manager. 
                       Yes.  We did exactly the same thing we did
           for Dresden and Quad.  We went back, component by
           component, looked at all of the different problems. 
           And as you suggested, flow-induced vibration was one
           of the issues we looked at.  You know, for this plant,
           we didn't have to put in any mods.  Everything worked
           out fine.  The dryer we looked at before.  We're going
           to be looking at it right after this outage.
                       Again, we don't think there will be any
           issues.  But we do have programs in place to look at
           it, and we will be looking --
                       MEMBER FORD:  My concern was entirely the
           fact -- I'm not concerned about exceeding -- that it's
           going to cause fatigue.  I'm more concerned about
           exacerbating cracking, stress corrosion cracking, by
           the fact that you're superimposing a vibrational load,
           which has been increased because of the EPU.
                       Therefore, if you're going to inspect once
           every outage, which is appropriate, is that good
           enough?
                       MR. MOSER:  For which component in
           particular?
                       MEMBER FORD:  Well, I was thinking of core
           spray lines, steam dryers, the brackets holding the
           steam dryers to the pressure vessel.  They have all
           undergone stress corrosion cracking at one time or
           other.
                       MR. MOSER:  You know, for the core spray
           lines, flow-induced vibration really isn't a big
           problem in those lines.  The steam dryer, yes, we have
           concern, and we have some industry experience on that
           -- Peach Bottom, some other overseas plants.  But
           based on the fact that the loose parts issue got such
           a big dryer, big component, even if it would crack
           there's nowhere for it to go, and it's not a safety
           concern.
                       MEMBER FORD:  Except down.
                       MR. MOSER:  Yes.  But that would go right
           on top of the separator, correct?
                       MEMBER FORD:  That's correct.
                       MR. MOSER:  And so, in a sense, you don't
           have anything that can really cause you concern as far
           as a safety perspective.  And so from that
           perspective, yes, we are absolutely sure that we want
           a cycle of looking at the dryers, making sure there
           isn't any gross degradation -- is the right thing to
           do. 
                       For the brackets themselves on the RPV
           wall, yes, we looked at them before.  There has been
           some industry experiences.  We are going to look at
           them after the outage -- after the EPU conditions and
           make sure that we have everything modeled correctly.
                       MEMBER FORD:  Okay.
                       MR. MOSER:  Does that answer your
           question?
                       MEMBER FORD:  Yes.  Kind of.
                       MR. MOSER:  Okay.
                       MEMBER FORD:  Yes.
                       MR. CROCKETT:  In conclusion, the EPU
           changes are acceptable to the FAC program.
                       I'd like to turn the --
                       MEMBER POWERS:  Well, at this point, I'm
           going to intercede.  We've exceeded the allotted time
           for this.  This is not a risk-informed submission.  I
           believe those interested in the risk significance of
           this submission can read the viewgraphs, and I propose
           that we move right to the closing.  And any points you
           want to make about the implementation you can make
           there.
                       MR. SIMPKIN:  I am Terry Simpkin.  I'm the
           Manager of Licensing for Exelon Nuclear.  First of
           all, I'd like to thank the staff for their rigorous
           review and I'd like to thank this Committee for its
           consideration of our request to uprate the power level
           at the Clinton Power Station.
                       We have completed extensive analyses,
           using accepted methodology.  We have identified no
           significant impacts on plant response or system
           integrity.  Our request involves minimum changes in
           plant risk and we believe that plant operation is
           acceptable at the extended power uprate conditions. 
           Subject to any questions from the Committee, this
           concludes our presentation.
                       MEMBER POWERS:  Do Members have any other
           questions they would like to pose on this to the
           licensees about this?
                       Well, thank you very much, gentlemen, and
           I'm sorry to eliminate a couple of sections of your
           presentation, but I think the visual aids were very
           clear and made your essential points there.
                       I'd like now to call on Mr. Zwolinsky to
           make a presentation for the Staff and their review of
           this application.
                       (Pause.)
                       Mr. Zwolinsky, I understand that in the
           course of teh Staff's presentation we'll have to
           interrupt the meeting for a protection of proprietary
           interests?
                       MR. ZWOLINSKY:  This is my understanding.
                       MEMBER POWERS:  You'll let me know when
           that has to take place?
                       MR. ZWOLINSKY:  Yes sir.
                       MEMBER POWERS:  Please.
                       MR. ZWOLINSKY:  Good morning.  For those
           of you that don't know me, my name is John Zwolinsky. 
           I'm the Director for the Division of Licensing Project
           Management.  Staff is here to present its review of
           the 20 percent power uprate request for the Clinton
           Plant.  
                       I'd like to take a minute to acknowledge
           several of our management team that are in attendance
           today that are clearly supportive of our staff and are
           here to represent that support, beginning with Suzanne
           Black, our Deputy Director for the Division of System
           Safety and Analysis; along with her, we have Gary
           Holahan, the Division Director of the Division; John
           Hannon, our Plant Systems Branch Chief; Ted Quay, our
           Equipment and Performance and Human Factors Branch
           Chief; Singh Bajwa, our Project Director responsible
           for power uprates.  We also have a number of our
           Section Chiefs, our first line supervisors responsible
           for assuring a high quality product:  Dale Thatcher in
           the Equipment Performance Branch; Corney Holden,
           Electrical and Instrumentation and Control Systems
           Branch; Matt Mitchell from our Materials Branch; Ralph
           Caruso, of course, from Reactor Systems, Kamal Manoly
           from our Mechanical Branch; Brian Thomas from our
           Plant Systems Branch; Louise Lund from our Materials
           Branch.
                       I go through that only to articulate the
           sense of importance that we place on assuring that top
           notch products are generated and thatwould be in
           response to the Committee and any concerns or
           questions that may arise.
                       The Staff made a presentation on this
           review to the Subcommittee on thermohydraulic
           phenomena on February 14.  The Clinton power uprate is
           similar to the Duane Arnold, Dresden and Quad Cities
           power uprates which were reviewed by the ACRS late
           last year.  Clinton's application does deviate from
           teh approved ELTR1 and 2 methodologies for GE BWRs and
           extended power uprates in four areas.  These areas are
           and we did go through this with teh Subcommittee,
           transient analysis, LOCA analysis, stability and large
           transient testing.  The Staff will discuss these areas
           today.
                       The Staff has conducted thorough reviews
           of the Clinton power uprate with the focus being on
           safety.  The reviews were conducted consistent with
           the existing practices which includes the lessons
           learned from Maine Yankee.  As indicated in the draft
           safety evaluation, many areas affected by the power
           uprates have been reviewed and evaluated and results
           were transmitted in that draft safety evaluation
           report.  We have additional work to perform in
           cleaning the safety evaluation up.  
                       With that, I'd like to get on with the
           presetatnions.  Our lead project manaber for this
           particular facility, Clinton, is John Hopkins.  John
           will walk up through the presentations as we go
           forward and as I said earlier to Dr. Powers, our staff
           is available to answer any questions associated with
           the presentation or beyond.
                       MEMBER POWERS:  Let me ask you one
           question.  You said this was similar to the ones we've
           looked at before including Quad Cities, Dresden.  It
           strikes me, in fact, that this is simpler than those.
                       Clinton just seems like a much easier
           power uprate than those other plants have.  Is that
           your kind of sense or not?
                       MR. ZWOLINSKY:  The amount of time that we
           spent, staff time in reviewing especially Quad Cities
           and Dresden was quite large compared to the other
           applications.  We did not spend as much time reviewing
           this application.  That would be a metric.
                       MEMBER POWERS:  That may or may not be a
           metric, but I mean the general amount of changes, the
           effort that they have to go to and the changes -- I
           mean, I point to just the power uprate is much easier
           in this plant than --
                       MR. ZWOLINSKY:  Yes sir.  I think as a
           general comment, I think we can agree with that.
                       MEMBER POWERS:  Good.
                       MR. ZWOLINSKY:  John.
                       MR. HOPKINS:  Good morning, I'm John
           Hopkins, NRR Senior Project Manager assigned to
           Clinton.  I'll go quickly over the overview.  To start
           with, I'll be starting and then our next presenter
           will be Plant Systems area and then we'll have --
           discuss large transient testing and then in the end,
           we'll discuss reactor systems and those exceptions. 
           We will need to close the session for when we discuss
           those, even though the handouts are all
           nonproprietary.  We really have to close it to discuss
           it.
                       To start with, as has been previously
           stated, this is a BWR6 Mark III.  After the 20 percent
           uprate is completed, Clinton will still be just the
           third largest BWR6 as far as megawatt thermal power is
           considered.  Perry will be slightly larger and Grand
           Fulf will be about 400 megawatt thermal larger.
                       The licensee went through many balance of
           plant mods to accomplish this uprate.  GE14 fuel is
           being used and they'll have about a two-thirds core
           after they start up from this upcoming refueling
           outage which is projected to start April 2nd.
                       MEMBER POWERS:  Maybe you better be clear
           by what you mean by two thirds core.
                       MR. HOPKINS:  Two thirds GE14.
                       MEMBER POWERS:  You are not loading jsut
           two thirds of the core.
                       MR. HOPKINS:  Okay, I'm sorry.  I was
           trying to go quickly.
                       (Laughter.)
                       This application came in in June of last
           year and so it's been a fairly quick review.  To
           respond to you, Dr. Powers, what you asked John, I
           think this has been a simpler review.  They already
           have had GE14.  They already have had MELLLA approved
           for this plant.  There's no recirculation, new recirc
           runback system associated with the plant, so I do
           think it's been simpler in those regards.
                       It is on 18-month cycles.  However, this
           next cycle is expected to be run approximately 20 to
           21 months and I expect to get an application to go to
           24-month cycles during that time.
                       It is nonrisk informed as previous EPUs,
           however, risk was looked at and we did not identify
           anything that would argue against the uprate.
                       AmerGen is the licensee and they have
           previous experience in operating applications as the
           staff does also.
                       We have one license condition at this
           time.  It's on a feedwater nozzle cumulative usage
           factor.  The licensee is still performing analyses of
           this and they expect to submit the analyses to us
           fairly soon and so we'd condition the license for the
           next operating cycle for us to review these analyses
           and then find them acceptable.
                       MEMBER POWERS:  John, just for Members'
           information.  Your cumulative usage factor refers to
           the fatigue issue?
                       MR. HOPKINS:  Yes.
                       MEMBER POWERS:  And it is a thermal
           fatigue or vibrational fatigue?
                       MR. HOPKINS:  My understanding is it's
           thermal fatigue.
                       They list the four exceptions there.  We
           will discuss each of the four exceptions during this
           presentation.  Again, teh first three will be
           discussed at the last presenter and that will be
           closed.
                       Right now, unless there are any other
           questions, I'm going to briefly discuss flow
           acceleration corrosion.  This is a question that came
           out of the Subcommittee meeting and the qeustion I
           received was basically when NRC inspectors look at
           flow acceleration corrosion, what understanding do
           they have of it and what resources can they tape to
           help them?
                       MEMBER POWERS:  I think more so than that
           particular question is do the people doing the
           inspection of programs at the plant understand from
           you in looking at this power uprate quest that there
           are certain critical copmonents including teh
           scavenger line where flow acceleration corrosion could
           be high and the licensee is relying very heavily on
           programmatic issues, constraints to assure this
           doesn't get out of hand.
                       MR. HOPKINS:  My answer to that is we are,
           the staff is developing a power uprate inspection
           procedure at this time.  It's out to the Regions for
           comment.  We expect to finalize it in a few months.
                       One issue that's being considered to be
           included in there, specifically FAC.  Now all of our
           inspections are based on risk importance and mainly
           from a nuclear safety perspective.  So I don't --
                       MEMBER POWERS:  It seems to me one of the
           problems you're going to run into is that we're
           talking about flow acceleration corrosion in a line
           that probably doesn't rank very high on a risk
           analyses, but when you break these lines, they
           typically have some pretty substantial conseqeunces,
           nevertheless.  
                       So you worry about using risk where you're
           talking about damage to the public in tehse kinds of
           context.
                       MR. HOPKINS:  I undrestand that.  I think
           we'd have to get back to you as we develop our uprate
           inspection procedure to fully respond.
                       MR. ZWOLINSKY:  I think your comment is a
           fair comment.  Yesterday, at the Regulatory
           Information Conference, Jack Robe was our Division
           Director for Reactor Safety and Region 3 was
           presenting the inspection program that was conducted
           at Quad Cities, Dresden and Duane Arnold and he did
           not get to that level of specifics, but they did
           implement a specific inspection program, targeted to
           power uprate, seeking key vulnerability that they felt
           had been identified not just in the application, but
           in the safety evaluation.
                       MEMBER POWERS:  I think that's what needs
           to -- there needs just to be some communication here.
                       MR. ZWOLINSKY:  Okay, the left hand and
           right hand were clearly communicating and I think that
           was one of the major points he was making.
                       MEMBER POWERS:  Very good.
                       MR. ZWOLINSKY:  But as John alluded to, we
           are developing the temporary instruction for more
           uniformed inspection across the country.
                       MEMBER POWERS:  If you happen to have the
           slides from his presentation, I'd enjoy seeing them.
                       MR. ZWOLINSKY:  We can forard those to
           you.
                       MEMBER POWERS:  Okay.
                       MR. HOPKINS:  Okay, at this time I'd like
           to introduce Richard Lobel who is from our Plant
           Systems Area.  And he will talk about another question
           from the Subcommittee on spent fuel pool temperature
           distribution and briefly discuss contributory
           containment analyses that we performed on Clinton.
                       MR. LOBEL:  Good morning.  I was giving a
           presentation on the plant system's areas of review for
           the Subcommittee and a question came up about the
           temperature distribution, the water and the spent fuel
           pool and I said that I believe there had been studies
           done on that.  Let me just go over it briefly.
                       The heated water in the spent fuel pool is
           collected around the periphery of the pool and
           circulated through heat exchangers and then discharged
           at the bottom of the pool to enhance circulation.  The
           power uprate doesn't change the design aspects of the
           spent fuel pool, cooling, the circulation mixing
           patterns and the operation of the spent fuel pool. 
           Based on staff experience, it's not power uprate, but
           spent fuel pool reracking that results in the greatest
           increases in spent fuel pool temperatures and we have
           reviewed many rerack applications.  As part of that,
           the staff reviews the thermal hydraulic analyses
           including the maximum water temperatures with and
           without water circulation, without forced circulation. 
           In one rerack review that was done a while ago, the
           staff performed extensive two and three-dimensional
           calculations of the water distribution in the spent
           fuel pool, compared the calculations with the
           licensee's calculations and concluded that the
           license's calculations were conservative.
                       As we discussed with the Subcommittee, the
           spent fuel pool water and the fuel temperature
           increases aren't a concern for the Clinton power
           uprate.  Their analyses show that they're below the
           spent fuel pool limits.
                       I hope that answered the question.
                       MEMBER KRESS:  Those limits are set based
           on the concrete --
                       MR. LOBEL:  Right.  The limits are really
           separate from the question of the temperature
           distribution.  There's a limit because of the material
           that's used in the purification system and there's a
           limit of 150 degrees on the concrete.  And Clinton was
           well below both of those limits.
                       MEMBER KRESS:  Was the temperature
           distribution significantly different from what it is
           normally?
                       MR. LOBEL:  Well, it depends on the
           loading pattern and the density of the loading pattern
           and that's why the reracking really has more of an
           effect than the power uprate.  Typically, in a rerack
           you're moving the fuel closer together and higher
           energy density into the same amount of water.
                       MR. ZWOLINSKY:  Dr. Kress, the biggest
           issue we've identified is length of time that the
           licensee retains the fuel in the core and it's initial
           configuration from shutdown.  The longer it cools in
           the reactor vessel and then transfers over to the
           pool, the smaller effect it has on the pool's
           temperature.
                       MR. LOBEL:  Also at the Subcommittee
           meeting I mentioned that we were doing confirmatory
           analysis for the containment calculations and at that
           time I wasn't sure whether we'd be done in time for
           this meeting, but it turns out that the calculations
           are completed and if you'd like, we can talk about
           that a little.
                       MEMBER KRESS:  Yes, I think we would like
           to.
                       MR. LOBEL:  Well, let me introduce Edward
           Throm from Plant Systems Branch who did the
           calculations and he can discuss it.
                       MEMBER POWERS:  Well, maybe you better get
           the speaker on with a mobile microphone.
                       (Pause.)
                       MR. THROM:  Am I on?  Okay, real quick, my
           name is Ed Throm.  I'm with the Plant Systems Branch
           and what we attempted to do in a very short time was
           do some confirmatory calculations for the Clinton
           extended power uprate.  
                       What we wanted to do was look at the
           contained two which is the staff containment code and
           compare it to the M3CPT and SUPERHEX results that GE
           typically calculates.
                       We started off with an existing Grand Gulf
           Mark III deck and modified it to look like Clinton. 
           This modification is dry well/wet well.  Volumes,
           initial conditions to reprsent th eplant.  We used the
           mass and energy releases provided by the licensee
           directly and this leads to a little bit of a
           discrepancy and one of the results of that I will show
           you.
                       This particular time we've done three
           calculations, two short term for the recirculation
           line break and then the steam line break and we also
           did the recirc line long-term cooling temperature
           response calculation.  We couldn't do the shutdown
           calculation in a short time because that would have
           required additional model changes that I didn't have
           time to do.  And basically, by looking at the
           qualitative comparison for the studies we've done, we
           believe that our conclusion that the licensee's
           analyses are acceptable for the extended power uprate
           is a true statement.
                       The model is fairly simple.  It's
           basically got three models of dry well with the
           annulus region that connects to the wet well and for
           this particular design it has the three vent paths.  
                       I'm just going to put up two results
           because of time.  This is the short term recirculation
           line break.  This is a comparison of the contained
           results to the M3CPT.  As you can see, M3CPT is
           calculating a little higher pressure than the staff's
           calculation and overall the dry well temperature
           response is very consistent with the licensee's
           calculation.
                       And the long term break, this is one of
           the areas where you learn as an analysis that you may
           have missed a piece of information that was important
           if you were trying to do it, an audit calculation and
           what's happening here is by using the licensee's
           provided mass and energies, we got a very coarse set
           of data and the data tends to show more of a steam
           release, high energy release over the initial portion
           of the transient.  That's why we're predicting this
           higher initial pressure response and a slightly higher
           temperature in the suppression pool.
                       This is very evident from that little
           spike there, where we have three points, one at a
           liquid, one at a steam, and one at a liquid.  So we've
           just done a linear interpolation so that's what the
           offset is doing for these types of calculations.  But
           again, qualitatively, we don't see anything between
           the two codes that suggest that the analysis method
           that's been approved and accepted by GE, by the staff
           or GE plants is any different for Clinton than it was
           for the Duane Arnold which basically the staff did a
           similar evaluation for Duane Arnold.  That's pretty
           much what I have to present.
                       MEMBER KRESS:  Thank you.
                       MR. ZWOLINSKY:  Thank you, Ed.
                       MR. THROM:  Okay, sure.
                       MEMBER POWERS:  Thank you.  
                       MR. THROM:  Sure.
                       MR. ZWOLINSKY:  Okay, our next presenter
           will be Bob Pettis and he'll talk about the exception
           from ELTR1 and 2 to not perform large transient
           testing.
                       MR. PETTIS:  Good morning.  My name is Bob
           Pettis and I'm with the Quality and Maintenance
           Section within the Division of Inspection Program
           Management. 
                       Our review of the Clinton application
           focused on the testing section of the application with
           some specific attention to the exception for not
           performing a large transient test.  The Clinton EPU
           tst program follows ELTR1 which is basically 
           delineated in Appendix L2.
                       As discussed previous by the Applicant,
           Clinton will perform a limited subset of original
           start up tests to demonstrate capability of the plant
           systems to perform as designed through the EPU power
           extension.  Routine measurements are taken for reactor
           and system pressures, flows and vibrations, up through
           EPU conditions and main steam and feedwater systems
           will be monitored for vibration.
                       The exception to ELTR1 is in the area of
           the mainsteam valve closure and generator load reject
           tests.  This exception was also previously approved
           for the Dresden and Quad Cities EPUs.
                       The staff felt that the exception to the
           ELTR1 is acceptable for several reasons.  First
           reason, GE had stated the constant reactor dome
           pressure simplifies the analyses and plant changes to
           achieve EPU conditions.  
                       Text spec surveillance testing will
           confirm the performance capability of the compnents
           challenged by large transients.  Another point is that
           CPS is not installing any new safety-related systems,
           features or significant additional components as a
           result of achieving EPU.  There are some balance of
           plant modifications that were discussed previously.
                       An analysis was also performed by the
           licensee in coordination with GE that reviewed some of
           the compnents that would be challenged by large
           transient testing.  Some of those components included
           MSIVs, safety relief valves, turbine stop valves and
           turbine control and bypass valves.  They also reviewed
           main steam line geometry and control rod insertion
           times.
                       The CPS test program also will monitor
           important plant parameters during power ascention,
           operating preassures and flows, temperatures,
           vibration and closure times for MSIV turbine stop adn
           control valves.  Operating history and experience at
           other BWRs has also been recognized.  There's been a
           slide that was presented yesterday that was more
           extensive than this, but the KKL plants or the KKL
           plant is operating at 116 percent; the KKM at 117;
           Monticello at 106; and Hatch around 113.  And also,
           the Dresden, a plant as well.
                       MEMBER POWERS:  Have any of these plants
           performed the equivalent of a large transient test?
                       MR. PETTIS:  To our knowledge, the only
           plant that has was the KKL plant in Sweden and from
           what we have reviewed, at least in our section, those
           results appear to correlate very well with the
           analytical models that would ahve predicted the
           resonse to the tarnsients.
                       MEMBER POWERS:  What I'm struggling with
           is what you mean by operating history and experience
           at other uprated BWRs.  If say one has performed the
           test, that's not a whole lot of experience to judge
           them, is there?
                       MR. PETTIS:  Well, the way that should be
           looked at is KKL did perform the large transients and
           there is information that correlates well for the KKL
           plant.
                       MEMBER POWERS:  Okay, so if I were to
           rewrite the line, it would say we have one plant
           that's done this test and it seemed to match the code
           predictions and so we'll live with code predictions?
                       MR. PETTIS:  The expectation level, I
           think, has been achieved with KKL.  With respect to
           the domestic plants, the only experience tehre that
           we're trying to demonstrate is the fact that they have
           undergone EPU conditions.  They are operating at EPU
           or near EPU conditions with no anomalies.
                       MEMBER SHACK:  They had a transient at
           Hatch, right?
                       MR. PETTIS:  Yes, that was in 1999.  It
           should also be noted that Clinton is not making any
           modifications to the reactor recirc runback system
           which was an area of concern for one of the ACRS
           Members previously for Dresden and Quad Cities.
                       Large transietn testing is also not needed
           for code validation.  I believe that's probably the
           ODEN code, but I'll let our reactor systems folks
           discuss that.  
                       And also, the incident that did or the
           event that happened at Hatch in 1999 where they
           experienced a load reject from 98 percent power and
           KKL had a turbine trip at 113 and a low generator
           reject at 104, and both of those events followed again
           code predictions.
                       Our conclusion is taht conducting large
           transient tests would not provide significant new
           information regarding transient modeling and component
           performance and that the Clinton EPU test program is
           acceptable.
                       Thank you.
                       MR. ZWOLINSKY:  Good job.  Okay, I would
           ask that the session be closed now because we'll be
           doing our reactor systems.
                       (Whereupon, the proceedings went
           immediately into Closed Session.)
           
           
           
           
           
           
           
           
           
           
           .                       MR. HOPKINS:  Again, this concludes our
           presentation.  The Staff finds that 20 percent power
           uprate for Clinton can be accepted and approved.  We'd
           request a letter from the licensee discussing our
           presentation.
                       MEMBER POWERS:  You discuss, you request
           a letter from the licensee discussing yoru
           presentation?  I'm sure they'd be happy to critique
           you.
                       (Laughter.)
                       MR. HOPKINS:  They probably will.  
                       CHAIRMAN APOSTOLAKIS:  Or disagree with
           you.
                       MR. HOPKINS:  You got me.  A letter from
           the Committee.  Thank you.
                       MR. ZWOLINSKY:  I do thank the Committee
           for your time and while we may have rushed through a
           few of our presentations, we were trying to push a
           number of our Staff before the Committee to give an
           indication of some of the areas that we focused on. 
                       With that, I feel the staff has completed
           their presentations.
                       MEMBER POWERS:  Thank you, John.  I'm
           going to pass on a comment from teh Subcommittee and
           that is that the Subcommittee found that this safety
           evlauation report was among the most readable in the
           power uprates that they had.  I know that's been an
           area of concern for you and the Subcommittee detected
           real progress in improving the readability of those
           reports.
                       MR. ZWOLINSKY:  Thank you.
                       MEMBER POWERS:  Mr. Chairman, I think at
           thi spoint I think we're done with this session.
                       CHAIRMAN APOSTOLAKIS:  Thank you, Dr.
           Powers.  I also thank the representatives from the
           licensee and the Staff for their presentations and we
           will recess until 10 minutes past 11.
                       (Off the record.)
                       CHAIRMAN APOSTOLAKIS:  Okay, we are back
           in session.  The next agenda item is the proposed NEI-
           00-04 report, Option 2 Implementation Guideline for
           Risk-informing the Special Treatment Requirements of
           10 CFR Part 50.
                       We sent to the Staff and NEI a set of
           questions last January and we had an opportunity at
           the Subcommittee meeting in February, February 22nd to
           discuss these questions and the rsponses from NEI. 
           The Staff has forwarded the questions to NEI.  So --
           well, I must also point out as it will be pointed out
           later, this Committee has also written two reports to
           the Commission, one dated October 12, 1999 and the
           other February 11, 2000 on importance measures and
           related matters.  
                       So today, we will -- the Staff has
           requested a letter.  Last time, at least, at the
           Subcommittee meeting, you said that you would like to
           see a letter with the Committee's views.  I assume you
           still would like to have a letter from us.  You can
           change your midn, if you wish.
                       MR. REED:  Yes, as you'll see in the
           slides, currently, we're asking for a letter.  If
           there are big issues, show stopper issues that the
           Committee has that we really need to address in order
           to go forward and get your concurrence on the proposal
           --
                       CHAIRMAN APOSTOLAKIS:  Okay, so why don't
           we start then and see how well -- and then we'll
           discuss the issue.
                       MR. GILLESPIE:  Well, knowing that the
           Committee was really going to focus today on
           categorization process which is kind of a cornerstone
           of the rule, let me kind of give you just in a
           nutshell the status of kind of where we stand.
                       Frank Gillespie, NRR.  The rule has been
           delayed.  So the nature of the letter and the nature
           of this meeting might be slightly different, so let me
           kind of give you the context of that.  Two things
           we're still wrestling with that within the staff.  One
           is having a categorization document, guidance document
           and working with NEI which right now is kind of a work
           in progress.  We sent 17 pages and comments to them
           and they're digesting them and so it's going to be
           another iteration. 
                       And the importance of the categorization
           document going with the rule and being substantially
           finished or at least let's say at 80 and 85 percent,
           so the people can understand what the cost of doing
           this rule is, having a categorization process and
           committees and other things.  So that was considered
           an important element.  Our original schedule for
           April, even my optimistic view, I said well, let's
           send up what they have with our 17 pages of comments
           and that wasn't going to be the right thing to do.  It
           wasn't going to be -- we would not have worked out
           back adn forth with all the stakeholders the right
           kind of document, so we've delayed the rule from April
           to July.  
                       Now, if we can beat July, our criteria
           really is less to date and is more having both the
           rule and a guidance document that goes to set.  And
           taht's our real criteria.  And the guidance document
           has to be close enough that we have a high possibility
           of general acceptance that it's rational.
                       So the guidance document is still kind of
           a work in progress.  Besides the guidance document and
           it might be a subset and I know you're not here to
           discuss this, but in my mind they're not unrelated, is
           the question under special treatment, if you notice
           the last draft words, the only real special treatment
           that still is left in for RISC-3 components is
           50.55(a).  And what the Staff is still grappling with
           is how to achieve -- how do we write achieving what
           50.55(a) is trying to achieve, even for low risk
           components.  And do you have to continue to have
           50.55(a) apply or is there a way to deal with that
           wthin a more performance-oriented approach, for
           example, within cateogroization.  And I"ll give you
           one example and then turn it over to Tim of -- this is
           kind of an on-going discussion in the staff so I can't
           even say ther'es a position on it.  There are several
           positions.  
                       It's not clear to me right now that our
           current rule and the current guidance says explicitly
           that you have to consider known degradation mechanisms
           as part of your consideration in what you're going to
           do relative to a RISC-3 component.  Yet, does not
           50.55(a) try to continue a certain level of assurance
           for a compnent, even if you're ina risk-informed space
           which fundamentally is saying we're maintaining our
           input reliability or the input to our decision process
           is being sustained.
                       And so what kind of what we're grappling
           with is the only way to say to do that for some
           mechanical components and pressure things and passive
           things is by dictating 50.55(a) or is there another
           way of dealing with it in waht the various committees
           would be considering within the guidance and within
           categorization.
                       I've taken my best shot at waht we're
           grappling with and we've got the staff here.  If you
           want to discuss that later as a point, Tom Scarboro
           and John Fayer are here, Gareth and Mike Cheof, so
           we're still grappling with that one point.  And it's
           an important point and we haven't come up with the
           exact way to deal with it and make that decision yet.
                       There is a meeting next week where we're
           trying, going to try to make a definitive decision and
           the Staffs are kind of working on different points of
           view and how do you approach that problem.  Not a
           problem, but how do you say what you want to say and
           get what you want to get in th emost performance-
           oriented risk-informed way?
                       So, that's in my mind those two decisions
           are not mutually exclusive.  And the other comment we
           did get back to NEI was that these committees, the IDP
           Committee, we haven't necessarily articualted how they
           should establish criteria or what the higher level
           criteria they should be considering is.  And that's a
           piece that we need some time to go back and forth on
           to discuss because clearly all the components are not
           considered in the PRA and the mathematical model and
           in particular, how do you deal with the passive
           components.  Again, not disconnected from 50.55(a) and
           is that in or out, particularly for passive pressure
           kind of things.
                       So that's waht we're wrestling with and
           with that, I'm going to turn it over to Tim.  I talked
           to George, yesterday, and I've asked Tim to go through
           the presentation, the formal presentation as quickly
           as possible, so taht maybe we can get your advice on
           these questions we're grappling with and we got the
           staff here that maybe we can have some interactive
           discussion on it.  Because we don't know the right
           answer.
                       CHAIRMAN APOSTOLAKIS:  Good idea.
                       MR. GILLESPIE:  Thanks, George.
                       MR. REED:  This is Tim Reed from NRR and
           I have with me also over at the side table Mike Cheof
           from Gareth Parry to assist here today.  The focus
           here really is focusing on the categorization pieces,
           Option 2 and looking at what are the remaining key
           issues that we need to resolve so that ultimately we
           can get this Committee's endorsement going forward. 
           So that's what I'll be trying to focus this discussion
           towards.
                       And this won't look -- this should look
           very familiar to most of you from the Subcommittee. 
           This tries to give a high level overall status of
           where we stand on categorization.  We recently sent
           our third round of comments to NEI back in early
           February and those comments, as Frank mentioned, like
           14 pages or whatever, reprsent what the Staff belives
           are the key issues that need to be resolved for us to
           reach agreement on the categorization guideline NEI-
           00-04.  They reflect both the Palo Verde activity
           feedback that we've had to date.  We've observed three
           pilots.  In effect, next week is the last pilot, Palo
           Verde, and we'll be observingt that one two.  And they
           also reflect the staff's review of draft revision B of
           NEI-00-4.  As you're aware, that document is goig to
           be revised and it's a work in progress and ultimately
           will become, I believe, draft revision C.
                       There are some major issues and I've just
           hit a few here and there are several other issues in
           this 14 pages that, in fact, I agree with some of the
           comments that ACRS brought up in the Subcommittee, but
           hitting some of the bigger ones here, the issue of
           long-term containment integrity and how you consider
           that within the element of defense-in-depth and how
           the IDP considers taht.  That's an issue, that's a
           comment, you'll see in our comments back to NEI.  It's
           been an on-going issue.
                       The element of the IDP, the IDP guidance
           and whether that's sufficiently structured, I think it
           probably needs a little bit more structure there. 
           That's the nature of our comments.  I think the
           Committee has that.  In fact, I think NEI would agree
           to that to some extent.  That's a feedback coming back
           to the pilot activities also.  And then the whole
           issue of the PRA quality, the use of the PRA review
           process, how we roll tht in and how the staff develops
           review guidance to judge whether, in fact, a PRA has
           sufficinet to support the categorization process.  So
           that's a very key issue here.
                       All these issues, I believe, from a
           technical standpoint, I think the staff belives, can
           be resolved.  So there's nothing here that can't
           technically be resolved.  Taht doesn't mean that we
           have signfiicant work, but nothing appears to be a
           technical roadblock at thi spoint.
                       Of course, we have to come back to this
           Committee and get -- the Committee needs to see more
           of a final product, obviously.  And so we need to come
           back for the proposed rule concurrent stage and as
           Frank mentioned, our schedule at this point is to try
           to get this to the Commission by the end of July.  And
           so that puts us actually in a very, very tight,
           difficutl schedule to try to get this Committee, get
           a letter from this Committee to support that schedule
           to get this whole package to the Commission by the end
           of July.
                       And I don't know if NEI is going to speak
           today or not, but NEI is in a very tight situation
           too.  They have our comments.  They'll hvae the IDP
           next week.  They have to take the feedback from that. 
           Roll it back into NEI-00-04, work through their side
           to get agreement and then send it to us and then we
           need to look at that and with the draft reg. guide,
           get it to the Committee and all taht before July.  So
           you can see there's an awful lot that has to happen
           here in the schedule.
                       So that kind of gives you the high view,
           the important pieces of categorization and wehre they
           fit into the proposed rule schedule.
                       Now these are some of the high points and
           I'm not going to success that this is the Committee's
           views.  This is what the Staff heard, waht we think
           are important and I'm sure the Committee would think
           there are other issues that were discussed that are
           more important to indiviudal members.  But I'm just
           going to hit a few of the high oints here.  But an
           overriding theme, I think, we heard numerous times
           during the Subcommittee meeting was that sevearl
           members mentioned or expressed concerns with the
           underlying basis that supports the NEI-00-04 document
           and whether or not that basis is really there, or the
           document or hte studies there -- is there something
           you could point to that says yeah, we all agree.  I
           think most people, in fact, agreed, taht they thought
           it was conservative, but that's more of a subjective
           judgmetn and I think it was the Committee's view that
           we probably ened to have more in place as far as
           something to point to, in fact, that demonstrates more
           clearly, in fact, that a lot of these assumptions that
           we're making are, in fact, robust and lead to a robust
           categorization.
                       These were some of the isseus that we took
           away, the staff took away, you see listed there, what
           should be the -- what kind of failure rates and what
           should be the increase in failure rates.  AS you're
           well aware, the numbers are being bantered about
           between 3 and 5 increase in factor of failure rates
           for the sensitivities.  When you roll this up into the
           CDF and LERF sensitivities, as you're well aware,
           South Texas uses a 10.  What hsould be the
           sensitivity?  Wht should the nujber be?  Should it be
           a distribution?  There's lots of discussion there.
                       The fuseell-Vesely and the risk
           acheivement worth screening criteria or guideline
           values, whta they should be?  I think there was even
           mention of distributions and how you might want to
           handle that. 
                       There was consideration of rolling up and
           addressing uncertainties in the whole model, whether
           that should be done or not.  And the whole issue of
           common cost failure was addressed pretty extensively
           also.  Adn also in combination with RAW, as a matter
           of fact, at the Subcommittee.
                       And as I mentioned, the Committee's --
           I'll let the Committee speak for itself, but I think
           some of the Committee would like to see some of this
           more documented out there for everybody so everybody
           could -- and I believe the ACRS mentioned another
           important comment.  I think it agrees with the staff
           that perhaps the 00-4 guidance, the NEI-00-04 guidance
           should have a little more structure, a little more
           guidance to the IDP.  I think we think that too.  I
           think it would help to make more effective, efficient,
           repeatable decisions from IDPs, wherever they occur. 
           I think we all agree with that.  I think even Mike
           even agrees with that to some extgent also.
                       CHAIRMAN APOSTOLAKIS:  After the expert
           panel makes its determination in whatever way, we're
           going to work on the process, but let's say at teh
           very end, they ahve categorized now system structures
           and components, how do you know that they're right? 
           You're putting all your trust in the process or are
           there other mechanisms at the end for you to gain some
           confidence that yes, what they have done is, in ract,
           reasonable?
                       Remember now, we're talking about
           thousands of system structures and components.  IN
           other words, are we approving a process and then
           telling the licensee go ahead and impleent it and as
           long as you follow the process, we're happy.
                       MR. REED:  I'll answer the easy part.  It
           is a process approval.  To the extent of the
           confidence in the process and whether the validity of
           that process is maintianed over time, I'll answer
           another easy piece of it.  That's a function, I think,
           of monitoring and bringing information, operational
           experience back into the process and ensuring that
           you're assumptions, the cateogrization assumtoins are
           maintained valid over time.
                       I'll let Gareth and Mike, if you want to
           say something intelligent than that.
                       MR. CHEOF:  Basically, I think after the
           IDP categorizes all the SSCs, the PRA is supposed to
           qualify the change in risk from all the SSCs that are
           put in RISC-3.  Adn this change in risk is supposed to
           be shown to be small, according to the guidelines we
           provide in Reg. Guide 1174, but I don't think that's
           the question you're asking.  I think the question is
           --
                       CHAIRMAN APOSTOLAKIS:  That's part of the
           process.
                       MR. CHEOF:  That's right, that's part of
           the process.
                       CHAIRMAN APOSTOLAKIS:  The process has
           been completed and they go ahead an they categorize
           things.
                       How do yo uknow that what they are doing
           is reasonable?
                       MR. CHEOF:  I think --
                       CHAIRMAN APOSTOLAKIS:  Not that they are
           trying maliciously to not implement it, but we're
           talking about thousands of SSC's here and peoplea re
           people.  They make mistakes and so on.
                       MR. PARRY:  I think Tim was right.  In a
           part of this follow-up is the monitoring of the SSCs
           and we do have an update requirment for the risk
           analysis and the process itself that takes into
           account operating experience.  I think the one problem
           we see is that in the monitoring for the RISC-3 SSCs
           might also decrease which might not provide you with
           enough feedback that you might need.  So it's
           something we need to work on.
                       CHAIRMAN APOSTOLAKIS:  Operating
           experience in these things is probably admitted by
           you, I would say, because a lot of these systems and
           components, I mean we are really intersted in their
           performance during an accident, right?  So I mean you
           would probably be concerned about the proper
           categorization of particular things and you would not
           wait until something happens to see whether things
           work.  Are you planning to have sort of an audit on a
           random basis or some other basis to get that feeling
           that things are being implemented the way they're
           supposed to and the results are reasonsable?  
                       I've heard -- Frank told me the otehr day
           that the MSIVs wer according to some people were
           miscategorized at teh South Texas projec.  I'd like to
           know a littl emore about it, why they feel that way.
           That's a major component.  I mean it's something that
           we can look at.
                       I don't know, Gareth, if you don't have an
           answer now, that's fine, but that's osmething that
           concerns some Members of this Committee.  Waht is
           happening?  Are we turning over the responsibilities
           now to the licensees?
                       MR. PARRY:  There's one other progarm we
           have on place, the reactor oversight program that I
           think also has a role in finding degradation for
           components.
                       CHAIRMAN APOSTOLAKIS:  Good.
                       MR. PARRY:  It obviously is not foolproof,
           but I think it is -- if there is a finding, then it
           has to pushed through the SDP and that can -- that may
           reveal another --
                       CHAIRMAN APOSTOLAKIS:  The actual
           oversight process it not really looking at the
           categorization.
                       MR. PARRY:  No, no, it's not looking at
           the catgegorization.  It would be looking at
           conditions that might arise because, for example, a
           lack of treatment in certain areas.
                       MR. GILLESPIE:  This is hard to answer,
           but the answer is we haven't figured it out yet and I
           think I want to be careful.  The overight program is
           us overseeing a licensee carrying out its
           responsibilities.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MR. GILLESPIE:  And we cannot build in a
           dependency on our actions for the safety of the
           facility.  And one of the things that we're gropiong
           with just a little bit this morning and in an earlier
           meeting was how do we deal with the eact question
           you're asking.  And have we actually, have we
           necessarliy given either the right commetns in the
           area of reinforcing -- you're attesting is the quality
           of the decision.  What's our confidence when we made
           the decision that RISC-3 is really RISC-3?  I don't
           have an ansswer for you, but it was a question that we
           had on the table and we were kicking it around this
           morning.  
                       The other question is how do you know that
           the input criteria tha tyou made you rdecision are
           continuing to be sustained?
                       For example, if you did a sensitivity
           study and you did varythings by a factor of 4, how do
           you know that all those RISC-3 components were still
           within that envelope?  And then we got into a
           discussion of the word degradation mechanisms need to
           be considered and right now it's not clear that within
           our guidance and clearly not within our rule that the
           word considered known degradation mechanisms up front
           is actually any of our rule or the guidance.  And I'm
           going to -- Tom Scarboro has got an example he gives
           of - and I've got to give him credit, but I got it
           third hand, so if I don't say it right, Tom, jump in,
           is if you have valves, a lot of samll valves that have
           grease on the stems and they are in a steam tunnel and
           you're going to get hardening of the grease, that's an
           environmental condition that needs to be considered in
           all aspects of what we now have in the rule where
           we've got monitoring and all those different
           paragraphs.  And yet we haven't necessarily written in
           the rules the idea of considering environmetnal
           conditions.  So we're grappling with that right now. 
           And I'm going to suggest that that's my connection to
           50.55(a) which is a mechanism right now within our
           requirements that tries to grapple with assuring that
           continued reliability.  So what we're trying to do is
           get to the roots of how do we say that.  We don't have
           it righ tnow.
                       CHAIRMAN APOSTOLAKIS:  It's something that
           woudl be --
                       MR. GILLESPIE:  WE've got it on the table. 
           I'm not sure qyite how to do it, and do it without
           superimposing just a bevy of QA requirements on the
           PRA and decision process also.  I mean in my mind I've
           got to keep, we've got to keep this as a staff in
           perspective.  We are delaing with low risk components
           to the greatest degree possible.  We hope we have a
           credible process, but how do you check that your
           process was carried out the way you thought it hsould
           be.
                       MEMBER SHACK:  But in yoru particular
           example, that's an active component.  Wouldn't that be
           covered under the maintenance rule?
                       MR. GILLESPIE:  The miantenance rule is
           one of the exemptions within 50.69.  So that's a
           special treatment rule that this RISC-3 copmonent
           would be exempted from.  So it's consideration in
           advance of that to meet the other aspects of the rule,
           good enough, or do you need a requirement that says go
           inspect it every eyar and we're caught between how do
           we get at the essence of the deterministic go and
           inspect it every year and the right onctext of kind of
           a risk-informed, performance-based and we're wrestling
           with it.  Again, I don't know the answer.
                       CHAIRMAN APOSTOLAKIS:  I undrsatnd.
                       MR. GILLESPIE:  I think we've got the
           question.
                       MR. REED:  Saying it a little bit
           different way, when you look at whether you feel
           comfortable with this process going forward as an NRC,
           a regulator, you look well, what, whwere were the
           requirements reduced, so that focuses you down on
           RISC-3.  That's where we removed ruqirements. 
           Everything else, we're keeping requirments and putting
           more on.  So I look down at Box 3 first and say what
           could go wrong there.  Well, what could go wrong there
           is obviously they could degrade over time.  YOu could
           lose either functionality or you could go outside the
           bounds of your sensitivity analysis.  How do you fix
           that?  Well, then you look at what's the feedback
           mechanism.  So you can see how our logic works to try
           to get to the exact sisue you just brought up and
           maybe we can do it in a performance based manner
           that's consistent with the principles of Option 2.  I
           don't know.  We're wrestling with it.
                       MEMBER BONACA:  On the issue that you
           raised regarding how do you know, okay, one comfort we
           got from SDP was that they claimed that for each
           component that was in a certain category there was a
           full document description of how they got to that
           particular based.  So therefore, one could envision
           that you could have an audit to understand how it was
           applied and there was -- I didn't understand that this
           would be a requirement under the NEI document. 
           Traceability wasn't clear there to me. 
                       MR. GILLESPIE:  Yes, and that's part of
           what I said.  The guidance document is a work in
           progress, and in fact our thoughts are actually
           evolving even right now as people are putting these
           issues, like the valve in the steam tunnel, or there's
           RISC-3 and there's RISC-3.  Which 3 is the spectrum,
           and you draw a threshold.  But as you get closer to
           the top end of that threshold, the sensitivity study
           actually takes on more importance as to whether you're
           within the threshold or not.
                       How do you that in rules space and in
           guidance space without overburdening a system?  It's 
           a compromise to some degree.  We're wresting with
           that, and that's why I think we're going to actually
           have some more interaction with NEI on it, because we
           want them wrestling with us with some of these same
           questions, and we might not have articulated them the
           same way in the letter we sent them.  Because as we're
           talking to you and other people, our thought processes
           are saying how can we get along with this?  How can we
           kind of -- we're focusing in on these specific kind of
           questions that we might not have -- our thinking might
           not have been completely clear even three months ago.
                       CHAIRMAN APOSTOLAKIS:  Anything else on
           this topic?  The second bullet there, "Some ACRS
           Subcommittee members would like studies to perform." 
           I think it's important to make it clear what kind of
           studies and what kind of analysis we're talking about
           here.  I think there are two categories.  One is
           genetic type of studies.  And, again, we're not
           talking about multi-year kind of things.  I mean
           experienced people can do these things in a short
           period of time.  But generic kinds of studies that can
           support various approximations or assumptions that are
           being made routinely, and NEI 004 articulates those,
           what is being done.  I don't expect that if one does
           these studies, the basic approach will be really upset
           too much.
                       But it seems to me that we ought to be
           doing things that we understood very well.  For
           example, this issue of uncertainty in importance
           measures.  Frankly, I don't think it's going to be a
           big issue, but I would hate to have the only evidence
           that I have come from a professor and a graduate
           student somewhere who did something six years ago. 
           Can we make sure that we understand that this is not
           an issue?  And how long will it take to do that?  I
           don't think it's going to be a long study, and this is
           kind of generic.  It's not something that every
           licensee will have to do later.
                       Now, speaking of what the licensees will
           have to do, I don't understand why -- I mean, I agree
           with you that the sub-bullet there, parametric as well
           as model uncertainties, the real issue is really model
           uncertainty here, not the parametric.  And yet we're
           mixing the two.  We know -- I mean if there is one
           thing we know now is how to handle parametric
           uncertainty.  And it's easy to do, to propagate.  But
           still the document ask that this be done.  It plays
           with sensitivity studies that it's not clear now which
           part of the sensitivity study addresses the model
           uncertainty, which part addresses the range of the
           parameters of lambda and so on.
                       Some of this stuff, it seems to me, can
           become much cleaner and more convincing.  And, again,
           I don't -- I think it's going to be of great value to
           the independent panel.  It really will be.  In fact,
           in our letter of three years ago, we said that one
           should do studies of this type, and then the insights
           that will be gained -- let's see how we put it.  Now,
           at that time we were looking at Appendix T, but "The
           guidance to be provided in the proposed Appendix T for
           the Expert Panel should include insights gained from
           the implementation of Recommendation 4 above, which
           was really doing all these studies that I just
           mentioned."
                       And that I see as an essential part to
           making sure that the whole process is on solid ground. 
           In other words, just because somebody's an expert on
           plant systems I'm not sure he's really qualified to
           use fussell vesely and RAW without any other
           information to categorize things.  I mean, we need a
           combination of types of expertise here to come up with
           a reasonable product for the same reason that I
           wouldn't trust a guy who understands RAW and fussell
           vesely and never been to a plant to do this
           categorization.  Should you have some --
                       MEMBER POWERS:  But I mean isn't that
           fairly a hypothetical thing?  I mean who is going to
           be involved in a categorization process that only has
           fussell vesely and RAW data only?
                       CHAIRMAN APOSTOLAKIS:  We should take PRA
           guy who has never really been to a plant?  I mean, I
           don't think would be a proper member, but that's not
           my point here.  My point is that when you're
           presenting the results from the PRA using RAW and
           fussell vesely, to what extent should you train the
           Expert Panel, or educate them, as to what these
           measures mean, limitations perhaps, and so on.  It's
           like the expert opinion thing that was done for the --
                       MEMBER POWERS:  Well, I think that's the
           point is that it's the limitations on these measures. 
           I mean nobody's going to use them with no other
           information.  You simply can't.  I mean, it's just not
           physically possible to close your mind to other
           information.
                       CHAIRMAN APOSTOLAKIS:  No, no.  That's not
           what I meant.  But I mean --
                       MEMBER POWERS:  No.  I think your point
           that the limitations of these things are not well
           appreciated.
                       CHAIRMAN APOSTOLAKIS:  Right.
                       MEMBER POWERS:  And they are severely
           limited, and it's the one of time variation that's the
           principal limitation, to my mind.
                       MR. PARRY:  George, I'm not sure that the
           members of the IDP necessarily to be looking at the
           RAW and fussell vesely values themselves.  I think
           that they would be looking at the overall results of
           the categorization that would have been performed PRA
           analysts that would have taken into account all these
           uncertainties about fussell vesely and RAW.  I mean
           it's not clear to me that they need -- that the IDP
           needs to actually understand what a RAW is.
                       CHAIRMAN APOSTOLAKIS:  If I were them, I
           would like to understand.
                       MR. PARRY:  But that's not the only thing
           that goes into the categorization that they're going
           to be presented with.  There's a whole slew of --
                       CHAIRMAN APOSTOLAKIS:  But it's a major
           input, though.  It's a major input.
                       MR. PARRY:  It's an input.  I'm not sure
           it's that major of an input.  It's the starting point
           for the categorization.
                       MEMBER POWERS:  Well, I mean even if it's
           just that, even if it's just the starting point for
           the categorization, then I think it's important to
           understand the limitations on that starting point.
                       MR. PARRY:  Yes.  And I think the process
           recognizes the limitations on the starting point and
           compensates for it by requesting some other additional
           studies.  In particular, it also requests the
           valuation of delta CDF and delta LERF.
                       MEMBER POWERS:  Well, I think the concern
           is that the choice of those augmenting studies that
           you speak of here, the additional information,
           requires some substantial understanding of what the
           limitations of the fussell vesely and RAW numbers are.
                       MR. PARRY:  And shouldn't that be a part
           of the process NE 00-04 that recognizes those
           limitations and designs the process to compensate for
           them?
                       MEMBER POWERS:  Yes.
                       MR. PARRY:  And that's what it tries to
           do.
                       CHAIRMAN APOSTOLAKIS:  But the point is
           that the Expert Panel also should become aware of
           these at some level anyway.  You don't want them to
           become expert but at some level.
                       MR. PARRY:  I think that might involve a
           quite considerable amount of PRA training if go
           through all that.
                       CHAIRMAN APOSTOLAKIS:  Well, I don't know
           about that.  You know, you can -- I'm not sure that's
           the case.
                       MR. CHEOF:  I guess let me add something. 
           I guess in the current NEI 00-04 guidance and in the
           IDP that we have observed so far the IDP members have
           been pre-trained in a one-day PRA training as to the
           results they are getting and what they mean, and I
           guess, like you all say, the limitations of the PRA. 
           I am not sure that the training includes things like
           the uncertainties in terms of parameters and models. 
           And perhaps the models might get -- the modeling
           uncertainty might get mentioned in the fact that these
           initiators are not modeled and we will account for
           these initiatives this other way using this flow
           chart, for example, in NEI-00-04.  But there is
           training for the IDP members, for all IDP members, and
           that training does include importance measures.
                       CHAIRMAN APOSTOLAKIS:  I don't remember
           that, but if there is, fine.
                       Now, you guys agree with the NEI, at least
           the version we saw, that it's good enough to use so-
           called point values and then do sensitivity analysis?
                       MR. PARRY:  In general, yes.
                       CHAIRMAN APOSTOLAKIS:  Even when you
           calculate delta CDF, which is a very small number?
                       MR. PARRY:  Well, going back to --
                       CHAIRMAN APOSTOLAKIS:  And why do it that
           way?  What do you say?  Is it a big deal to do it
           right?
                       MR. PARRY:  Actually, for some people it
           may be.  But then that's just a technical issue on the
           codes.
                       CHAIRMAN APOSTOLAKIS:  For some people.
                       MR. PARRY:  It depends on the
           quantification code you have, George.  Some of them
           are not set up to do the proper state-of-knowledge
           correlation on uncertainties, and you have to do that.
                       CHAIRMAN APOSTOLAKIS:  Maybe they
           shouldn't then be following Option 2.
                       MR. PARRY:  No, no, no, no.  Because what
           it also -- we address this issue also in Reg Guide
           1.174.  We had the same issue.  And what we said there
           was you should do it by propagating uncertainties to
           get the correct mean, but you could also -- if you
           could demonstrate, by reviewing the cutsets, that in
           fact this impact of the state-of-knowledge correlation
           was not significant, then that would be another way of
           demonstrating that you got close enough to the mean
           value.  Because that's the only thing that changes the
           mean value from using input mean value as a point
           estimate in all the calculations.
                       CHAIRMAN APOSTOLAKIS:  No, no.  It's not
           the only thing.
                       MR. PARRY:  I believe it is.
                       CHAIRMAN APOSTOLAKIS:  When you propagate
           point values, don't you need the values?
                       MR. PARRY:  No.
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MR. PARRY:  No.  Not with cutsets, you
           don't.  Only if you have correlated variables.
                       CHAIRMAN APOSTOLAKIS:  The early PRAs were
           done that way.  I did it by hand, and you have to use
           the variance too.  The expressions for the mean
           involve the variance.
                       MR. PARRY:  If you are multiplying
           together basic events that depend on the same
           parameter for their probabilities, yes, you have to
           propagate the variance, but otherwise the mean
           translates.  If they're totally independent variables,
           it doesn't matter if you add them or multiply them,
           it's the mean value.
                       CHAIRMAN APOSTOLAKIS:  Anyway, we don't
           need to debate that now, but I don't think you're
           right.  I think to propagate the nth moment, you need
           the N plus one moments.
                       MR. PARRY:  You don't need the nth moment
           if --
                       CHAIRMAN APOSTOLAKIS:  Well, you need the
           first one; therefore, you need the second too.  But
           the point is that even though the -- by and large,
           you're right, the number will be close enough.
                       Wouldn't the sensitivity studies be more
           meaningful if you had such a baseline analysis to do
           them, rather than playing with the point values and,
           say, "I multiplied by two and I will go now to the
           95th percentile."  What's the basis for all this?
                       MR. PARRY:  I think you'll find in the
           latest version of NEI-00-04 that you were looking at,
           certainly as far as the independent failure rates,
           that taking them to the 95th percentile and the 5th
           percentile's been taken out.  The parameters that are
           varied in that way are things like common cause
           failure parameters and human error probabilities.
                       And the reason I think they're put in
           there that way is because we know that those are
           pretty uncertain values, and what we want to do by
           doing those sensitivity studies is to make sure that
           either -- the importance of certain components has not
           been either inflated by using pessimistic common cause
           failures value or deflated by using very optimistic
           values.  It's like a safety net, if you like.  And I
           think that's the reason for it being there, and I
           think it is informative to do that.
                       CHAIRMAN APOSTOLAKIS:  And how will you
           know that the point values that they will use will be
           the mean values?
                       MR. PARRY:  Because they've been declared
           to be the mean values.  And I think you'll find that
           that's a lot of the way things were done in the past
           and it's historically.  But those point values are
           probably chosen from generic -- for a start, if they
           were point values and purely point values, they would
           probably have been got from generic estimates.  And I
           think most people, in choosing the values, would have
           chosen the mean value of any generic estimate.  And if
           it's a --
                       CHAIRMAN APOSTOLAKIS:  So, in essence,
           what you're arguing is that we should forget about the
           additional uncertainty analysis, because it doesn't
           really matter.  I mean that's what you're saying.
                       MR. PARRY:  That's not quite what I'm
           saying.
                       CHAIRMAN APOSTOLAKIS:  Well, when does it
           matter then?
                       MR. PARRY:  I'm saying that you don't
           necessarily need -- that you can survive without doing
           it.
                       CHAIRMAN APOSTOLAKIS:  The document was
           very clear that you don't need it.  It didn't say
           necessarily.
                       MR. PARRY:  We all said it's preferable to
           do it.
                       CHAIRMAN APOSTOLAKIS:  But you should have
           some benefits when you do it.
                       MR. PARRY:  If there is indeed a major
           benefit to be obtained from it.  And that's perhaps
           one of your studies.
                       CHAIRMAN APOSTOLAKIS:  Well, I mean one of
           the goals of the Commission is to inspire public
           confidence.
                       MR. PARRY:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Also doing things
           right has to have some value.
                       MEMBER POWERS:  Well, I don't know that
           doing it right, but calling something a mean value
           that isn't a mean value does not sound very confidence
           inspiring.
                       CHAIRMAN APOSTOLAKIS:  That's right.
                       MR. PARRY:  But there is -- I think for
           very many of the parameters it's actually quite
           difficult to get the generic distributions.  And I can
           give you an example.  A long time ago, I was involved
           in an exercise to generate a database, a generic
           database for ASEP.  The way it went was that everybody
           voted on what value they should use for the
           parameters, and they said, "Okay, what uncertainty
           should we put on this?  Put down a factor of three or
           should we put ten?"  And that was a vote as well.  And
           that's how some of these old, generic databases were
           generated.
                       Now, it turns out, actually, as data is
           being collected that they were not all that bad, and
           as more and more people have done data collection on
           their own plants and updated the distributions using
           the Baysian methods, they haven't found that the mean
           values, in general, have strayed too far from those
           originals.
                       CHAIRMAN APOSTOLAKIS:  My experience has
           been different.  In some plants, their operating
           experience did indeed change the mean values.
                       MR. PARRY:  There will be some specific
           cases, yes.
                       CHAIRMAN APOSTOLAKIS:  But were the IPEEEs
           done that way?  I mean did they use --
                       MR. PARRY:  They're all over the map.
                       CHAIRMAN APOSTOLAKIS:  -- mean values that
           --
                       MR. PARRY:  They're all over the map.
                       CHAIRMAN APOSTOLAKIS:  They're all over
           the map.
                       MR. PARRY:  Yes.
                       CHAIRMAN APOSTOLAKIS:  So how do we know
           that these will not be all over the map as well?
                       MR. PARRY:  I think one of the things that
           we're proposing to put in our view guidance with the
           staff is that indeed the parameter value should be
           compared to well-documented generic databases to see
           if they are significantly different.
                       CHAIRMAN APOSTOLAKIS:  But it seems that
           the reason why you're arguing that way is because some
           people might have difficulty doing it rigorously.  So
           why don't you then say, "This is the rigorous way of
           doing it, and if you don't do it that way, you do it
           another way, you also have to do something else, so
           there is a penalty"?  And that's fine.
                       MR. PARRY:  But they do have to do
           something else.
                       CHAIRMAN APOSTOLAKIS:  The version we saw
           did not ask for uncertainty propagation at all.  It
           just said --
                       MR. PARRY:  Right.
                       CHAIRMAN APOSTOLAKIS:  -- these are the
           point values.
                       MR. PARRY:  But in calculating the delta
           CDF.
                       CHAIRMAN APOSTOLAKIS:  It didn't say
           anything there either.
                       MR. PARRY:  Maybe it didn't, but -- well,
           I can't defend the NEI document in that regard, but --
                       CHAIRMAN APOSTOLAKIS:  I mean when we
           calculate the difference of two very small numbers,
           are we arguing that uncertainty doesn't count?  I
           mean, boy, that's really -- when you calculate delta
           CDF and delta LERF, has anybody demonstrated that if
           you work with mean values, you get a reasonable
           difference when you're talking about ten to the minus
           six and seven?  I don't know.  Because as we know, the
           uncertainty increases, right?
                       MR. PARRY:  Again, I think you can -- by
           reviewing the cutsets that drive those deltas, you can
           see whether there's likely to be a difference.  That's
           the extra work you have to do to show it.
                       CHAIRMAN APOSTOLAKIS:  One of the papers
           that was published in '68 by Allen Cornell, that was
           one of the first papers that showed that probablistic
           methods can indeed give you counter intuitive results,
           had this example in it.  You have the difference of
           the stress minus the strength, you have some
           uncertainty in each, okay?  And the variance of the
           difference is in fact the sum of the variances, which
           is kind of counter intuitive.  It increases the
           uncertainty.  The difference of the means -- I mean
           the mean of the difference is the difference of the
           means, and everybody says, "Yes, big deal.  I knew
           that."  But the uncertainty increases by how much, and
           the variance is the sum of the variances.
                       So now we are calculating these delta CDFs
           and delta LERFs that are such small numbers, and this
           morning we saw ten to the minus seven, and we are
           completely ignoring these subtleties, if you wish, of
           the methods.  I mean somebody has to demonstrate that
           it doesn't matter, if it indeed it doesn't.  I don't
           know.
                       So even if we accept the premise that
           point values, mean values -- the declared means values
           really don't matter when you do the baseline
           calculation using fussell vesely and RAW, when you go
           to the delta CDF they still don't matter, the
           uncertainties?  I mean when you're now calculating
           differences of very, very small numbers?  I don't
           know.  I'm not saying it does, but can someone show me
           some evidence that it doesn't matter?
                       And I think it's the same thing as we were
           talking about the availability or unavailability of
           PRA.  If you have a PRA, your life should be easier
           using fussell vesely and RAW and all that stuff.  If
           you don't, then your categorization process should be
           much more conservative, right?
                       MR. PARRY:  Yes.
                       CHAIRMAN APOSTOLAKIS:  I mean is that
           evident in NEI 00-04?  I don't know.
                       MR. CHEOF:  We think it is.  We have made
           that comment before that, you know, if a licensee has
           a PRA for an external event, that they can be less
           conservative, and if they were to categorize using a
           method that's not PRA quantified, they have to be a
           lot more conservative.
                       CHAIRMAN APOSTOLAKIS:  Yes.  We can agree
           that that's the way it should be.  But does the
           document do something that guarantees that this will
           happen?
                       MR. CHEOF:  I think there's at least one
           statement in there that says that.  I'm not sure if
           the process itself --
                       CHAIRMAN APOSTOLAKIS:  Oh, okay.
                       MR. CHEOF:  I mean they do have flow
           charts in there and how they can treat the other
           external events.  And the staff has looked at those
           flow charts, and I think we are working with NEI as to
           how we can ensure that those flow charts will indeed
           give you more conservative results than if you had a
           PRA.
                       MEMBER KRESS:  Let me ask what might sound
           like a strange question.  This process of
           recategorization of SSCs is -- the view, seems to me,
           we've got to already have a categorization.  That's
           the reason we end up with four categories.  And that
           the process is going to be applied to plants that have
           already categorized and we're just going to
           recategorize.  Can the process be applied to a brand
           new plant that comes in and says, "I haven't
           categorized yet."
                       MR. REED:  Yes.
                       MEMBER KRESS:  Do they have to go through
           the old process first and categorize and then --
                       MR. REED:  Yes.
                       MEMBER KRESS:  So is the old --
                       MR. REED:  I think they would have to.
                       MEMBER KRESS:  So the old process would be
           part of the overall process.
                       MR. REED:  Obviously, this hasn't happened
           yet, and so it's going to be a little bit of a
           speculation on my part, but if somebody was to, today,
           decide to apply for a new license and follow the
           current Part 50 and then try to adopt 50.69 in the
           process, I think what they would first have to do is
           basically go through like the old design basis,
           safety-related world --
                       MEMBER KRESS:  They have to go through the
           whole design basis.
                       MR. REED:  Do that on paper now.
                       MEMBER KRESS:  Yes.
                       MR. REED:  And then basically do a
           categorization, and then take that whole safety-
           related and non-safety-related world, translate it
           into the four boxes, now all on paper, come in
           basically with that submittal, and they would procure
           from the get-go Box 3 to be RISC-3.  So they would --
           right from the start the whole plant would be procured
           that way.  That's a big difference versus current
           facilities.
                       MEMBER KRESS:  Yes.  That's my impression
           of what would have to be done.
                       MR. REED:  That's correct.
                       MR. GILLESPIE:  Yes.  On the other side,
           if it's a certified design, the certification is, in
           and of itself, a rulemaking.  And so someone who has
           a certified design could apply the concepts of Option
           2 likely within the context of the certification.  So
           Tim described someone who would be coming in applying
           for a license under the current Part 50 as if they
           were 20 years ago.  Yet we have a different process
           which might actually allow a little more freedom and
           innovation.  Because a rule can offset a rule.
                       MEMBER KRESS:  Yes.
                       MR. GILLESPIE:  And the certification
           itself is a rule.
                       MEMBER KRESS:  I understand.
                       MR. GILLESPIE:  I think that's how we'd
           end up getting around this without rewriting all of
           Part 50 again.
                       MEMBER KRESS:  Yes.
                       CHAIRMAN APOSTOLAKIS:  I can give you an
           example from this morning's presentation of abuse of
           PRA models, and only if you really have seen a lot you
           appreciate it.  We were told that the time to respond
           to something was reduced from nine minutes to six
           minutes.  And there was a table that said, "and the
           core damage frequency increases by less than one
           percent."  Now, Gareth, you don't believe that, do
           you?  You know that it can't and on the face of it is
           a misleading statement.  Are there any models -- any
           reliability models that can really tell the difference
           between a nine-minute response and a six-minute
           response, and everybody agrees that, yes, that's true? 
           I mean there are ideas, there are judgments, there is
           this, there is that, and yet it was presented this is
           what it is.
                       Now, the application was not risk-informed
           so it didn't matter, but you see that my point is that
           somebody who knows will look at this thing and say,
           "What's going on here?  This is really nonsense."  But
           it's not essential to the decision, so you let it go.
                       MR. REED:  I think I'll just add a
           comment; hopefully it's constructive.  But I think
           some of the issues you bring up are why in Option 2
           space why we're risking forming only assurance
           requirements and maintaining the design basis down in
           Box 3, albeit with less assurance.
                       It almost -- I'm not saying I know what
           you think, but sometimes I get the feeling that we're
           trying to justify significant technical changes here,
           and I think you'd have to know a lot better some of
           these uncertainties if you were trying to make
           technical changes to the facility.  At least that's my
           own personal opinion; perhaps you don't.  But in
           Option 2 space, in think we get some comfort from the
           fact that we're going to be maintaining the design
           basis functions.
                       CHAIRMAN APOSTOLAKIS:  The problem is that
           when we start using PRA in real decisions, we seem to
           be going backwards, and we seem to treat methods and
           models in a cavalier way.  You know, you want the
           delta CDF involving time-dependent human errors?  I'll
           give you one.  Okay.  And everybody says it's one
           percent.  I mean when in fact the answer is there are
           ten different models out there, and you can get any
           answer you want.  And the truth, in my mind, is that
           you can't really quantify such a difference, I mean,
           with any degree of confidence at this level.
                       I mean you know that it's a good thing. 
           It's actually a bad thing in this case because
           available time was decreased by a little bit.  But you
           can't really put a number.  But if you keep doing it
           that way and you never really raise the flag and so
           on, eventually it will become practice, and that's
           bad.
                       MR. PARRY:  Well, I think though, George,
           in that particular example, I think it's incumbent
           upon the reviewer to figure out what model's been used
           and whether if they used alternate models if they'd
           get a different answer.  And that's part of --
                       CHAIRMAN APOSTOLAKIS:  And why isn't that
           applicable here?  If you use a different model, you
           may get a different answer.
                       MR. PARRY:  I think that there are -- I
           mean at least in one of our comments, one of the
           things we said was that you should identify the
           assumptions that drive the changes, and they should be
           candidates for performing sensitivity studies --
                       CHAIRMAN APOSTOLAKIS:  That's right.
                       MR. PARRY:  -- to see whether they impact
           the categorization.
                       CHAIRMAN APOSTOLAKIS:  I guess we're
           talking about two different things now.  You're
           referring to comments you have submitted to NEI, which
           I am not aware of.
                       MR. PARRY:  Right.
                       CHAIRMAN APOSTOLAKIS:  And I'm referring
           to NEI 00-04, the document I have viewed.
                       MR. PARRY:  I know.  And one of the things
           in 00-04 is if you look at the sensitivity studies
           that are specified, they do have a category there
           which are those that I think that are revealed by the
           facts and observations from the peer review process. 
           So that gets part of the way to where we want to be,
           but I don't think it gets all the way there.
                       CHAIRMAN APOSTOLAKIS:  Anyway, shall we go
           on?
                       MR. REED:  Sure.
                       CHAIRMAN APOSTOLAKIS:  Unless there are
           other --
                       MR. REED:  Anymore questions on this
           slide?  Okay.
                       So continuing with two more key points
           then, one of which has been made several times already
           today, NEI 00-04 is an interim product, it's in a
           state of flux.  It's certainly going to change.  NEI's
           going to update it and roll back in the feedback
           they've gotten from pilot activities and also address
           our comments.  And it's understandable and of course
           appropriate that ACRS would reserve its final judgment
           until they have a more final product.  So that's all
           this slide simply reflects.
                       MR. GILLESPIE:  I think, George, part of
           the discussion this morning has highlighted why it's
           a work in progress.  Fourteen pages of comments, and
           I forget how long NEI 00-04 was, but I think it was
           only -- Tony, help me out, about 30 pages long?
                       MR. ULSYS:  Categorization piece --
                       MR. GILLESPIE:  Categorization piece.
                       MR. ULSYS:  -- was 17 pages long.
                       MR. GILLESPIE:  Okay.  So we've submitted
           comments that are in excess of approaching 15 percent
           of the total document.  And we need to see how it now
           comes out of this next step in the process and have
           another iteration.  I'm not promising that everything
           you've said will be considered, but I think the idea
           of assuring the applicability of the study to what
           we're using it for, the need to do that is a concept
           that we will be trying to embody in it.
                       I don't know how to do it, and there's
           been discussion that's over my head on how to do it,
           but I think we understand the comment and have some
           sympathy for it.  Now, we have to figure out is how to
           articulate it where it's consistent with what we think
           are low-risk components also.
                       CHAIRMAN APOSTOLAKIS:  The way I see it,
           Frank, is you have to make approximations, you have
           to.  I mean that's the way life is.  If you do, it
           seems to me, somewhere there you have to demonstrate
           that it's an approximation, rather than saying, "Well,
           we've done it many times, and it came out that way."
                       The other thing is I think it would be
           useful to say, "Look, if you do it this way, in a
           rigorous way, this is the benefit you get.  If you do
           it in a less rigorous way, you should be a little bit
           more conservative, and this will guarantee that that's
           case.  And typical example here is when you have a PRA
           or you don't.  A guy who has a PRA for fires, for
           example, should be able to get more benefit out of it
           than somebody who did five, right?
                       MR. GILLESPIE:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Or the seismic
           Heathcliff, whatever they call it, or rigorous PRA. 
           And then when you go to the places where there is no
           PRA at all, then you make sure that you have a
           conservative approach.  So this kind of phased
           approach, I think, would go a long way towards
           convincing me, at least, that this is a good, solid
           approach.
                       MR. REED:  I think everybody agrees with
           that concept, and I believe we are trying to assure
           that's in this guidance document.
                       MR. GILLESPIE:  Yes.  In fact, I'll say it
           a little different way.  What the staff would like to
           do is give people who have gone that extra mile to do
           an external event PRA in some detail or shut down PRA
           in some detail or fire analysis, we'd like them to be
           able to maximize the benefit they get from their
           investment.
                       CHAIRMAN APOSTOLAKIS:  Exactly.
                       MR. GILLESPIE:  So in principle, we're in
           total agreement.  And right now, though, we're trying
           to endorse what -- I could generalize, this is a
           generalization -- a one-size-fits-all kind of guidance
           document.  And what you're saying is when you read the
           guidance document, you didn't see the spectrum that
           would actually encourage people to do the right thing
           because of the benefit from it.
                       CHAIRMAN APOSTOLAKIS:  Exactly.
                       MR. GILLESPIE:  So I think I got -- I know
           where you're coming from and we're in total agreement,
           but the staff being in agreement doesn't mean the
           industry who's writing the industry guidance is
           necessarily writing it with that same concept in mind. 
           We can give them the comment and they're here.  If
           they heard the comment.  But how they embrace that
           comment, we're going to be reviewing for the purpose
           involved, whatever they submit.  But I think it's a
           valid comment.  And, indeed, in disk space and risk-
           informed tech spec space, we would also, in a risk-
           management sense like to give people the maximum
           payback for what they've invested and what should be
           a better decision tool.
                       How do we get there?  We haven't figured
           that out yet.  You know, it's difficult.  As a
           regulator you can't dictate that to somebody, but we
           would hope the industry would kind of grasp that
           concept and maybe figure out how to factor it into
           their document also.
                       A mutual gain on that, because there is a
           spectrum of facilities out there with a spectrum of
           tools available.  And how do you give that guy who's
           put a big investment in the maximum return, and that's
           really your question, versus writing a guidance
           document to the median level?  It's a fair comment. 
           Tony, you've got the comment.
                       MR. PIETRANGELO:  We'll wait our turn.
                       MR. GILLESPIE:  Okay.
                       CHAIRMAN APOSTOLAKIS:  Well, are there any
           more questions for the staff?
                       MR. REED:  I guess I'd just like to say on
           this last slide, it kind of rolls everything up, I
           would simply mention that, probably said already, I
           think we've said everything here, but if the Committee
           has major issues, then we'd like to have a letter, and
           we certainly appreciate the Committee's input, and
           it's obviously a great deal of expertise in the PRA on
           this Committee, so appreciate that.
                       MR. GILLESPIE:  And I hate to say it, this
           being March and our rule due in July means we probably
           need a letter in June.  So it gives us about 30 days
           to get you something for potentially an April or May
           meeting.
                       MEMBER POWERS:  We're not that slow.
                       MR. GILLESPIE:  No, but we may -- just in
           counting back, if we're trying to get something to the
           Commission and we need a letter by July, I'm not sure
           that we might not have to have something to you so
           that you can read and review it for a June meeting. 
           Which may mean, I don't know, a May Subcommittee
           meeting.
                       So, anyway, we're going to be back again. 
           I'm anticipating, George, that we'll probably have
           another Subcommittee meeting and full Committee
           meeting.
                       CHAIRMAN APOSTOLAKIS:  Yes.  That would be
           good.  When you say that the staff requests a letter,
           you mean now, this letter you are --
                       MR. REED:  Yes.  The letter I'm asking for
           right now if there are major issues that -- I'd like
           to be able to --
                       MR. GILLESPIE:  Yes.  We're going to have
           to come back again for a second letter.  So the
           context of this letter is we're really having a
           dialogue now and we're looking for suggestions, advice
           and anything you want to give us.  We'll be back again
           for another letter.
                       CHAIRMAN APOSTOLAKIS:  The two letters
           that I mentioned that we have already written they
           still stand.
                       MR. GILLESPIE:  Yes.
                       CHAIRMAN APOSTOLAKIS:  Okay?
                       MEMBER SHACK:  Just coming back to your
           degradation problem for a minute, isn't part of that
           an artificial thing where you insist on -- or at least
           the guidance sort of gives all components the same
           increase in failure rate.  If you really went through
           and you said, you know, "A valve and a steam tunnel,
           if I don't have the special treatment, it's failure
           rate may go up X a valve sitting out in a benign
           containment environment."
                       MR. GILLESPIE:  Well, exactly, and that's
           why --
                       MEMBER SHACK:  And it seems to me that
           that might be a sensible place to begin to attack that
           kind of a problem.  I think we're going to have to go
           to sensitivity analyses, but I'm not sure that -- you
           know, the broad X approach that's been chosen at the
           moment really, I think, penalizes the industry to a
           certain extent.
                       MR. GILLESPIE:  And that's something we
           just really started coming to grips with, because it's
           kind of an overriding consideration for all those
           paragraphs we've got in the rule for monitoring and
           conditioning and all those different things.  So it's
           kind of an -- there's a sentence in there someplace
           that we might not have right now that says, "Consider
           this when you're doing these things."
                       We're not saying hide a monitor, but
           clearly monitoring of these components, whether it's
           needed or not in that decision, the intent is to
           maintain the credibility of the decision process that
           you made when you made your decision on what you
           needed to do or the decision that it was RISC-3.  How
           do we sustain the credibility of the decision process,
           both in the beginning and as an ongoing basis?  We're
           wrestling with that right now.  Because you would
           penalize people.  If you make a blanket statement,
           it's like, well, we're going back to the old way of
           doing things.  So we want to leave some flexibility in
           there.
                       MEMBER SHACK:  Okay.
                       MR. GILLESPIE:  Thank you.  I think that's
           it for the staff.
                       CHAIRMAN APOSTOLAKIS:  Thank you very
           much.  Tony?  Welcome.
                       MR. PIETRANGELO:  Good afternoon.  I'm
           joined by Adrian Haymar and Biff Bradley from NEI.  We
           wanted to -- we were primarily going to talk about the
           categorization guides today, and I know you had a
           Subcommittee meeting where you got a pretty extensive
           presentation on that guidance.  We're not going to
           redo that today, obviously.
                       What we did want to talk about, though,
           and I think Tim set it up quite well, this is a work
           in progress.  We have your comments, we have the
           staff's comments.  We think we have a comprehensive
           guidance document for this categorization.  Before we
           began the pilot categorization effort that began last
           fall, I think we had a critical time last July with
           the staff to make sure there were no show stoppers in
           the guidance that would preclude the pilots from
           trying to demonstrate the usefulness of NEI 00-04.  We
           got to that point.  I'm sure there's additional
           comments that can be incorporated.
                       I think Tim captured the issues we're
           working on quite well, in terms of addressing the late
           containment failure and the IDP guidance.  I think the
           peer review piece is a separate issue.  Quite frankly,
           that applies to all the PRA applications.  We have an
           entirely separate effort dealing with that.  We met
           with the Office of Research last month on the guidance
           to endorse both the ASME standard as well as our peer
           review guidance, so that's going in parallel with
           this.  Certainly, this is one of the most important
           applications that exercises all elements of the PRA.
                       One thing I do want to point out where we
           are in kind of our stage of development here, and this
           issue has come up and we've talked about the ASME
           standard and PRA quality, in general, this is an
           evolutionary process.  I think if we get too hung up
           with the level of precision about where we are today,
           I mean that stops progress.  That's why we've been, I
           think, pretty adamant from the outset on here that
           there's a need for NRC staff review of any Option 2
           application.
                       We didn't buy the Appendix T concept of
           you raise your right hand and swear that you meet all
           the stuff that's detailed in Appendix T and then the
           staff doesn't have to review it.  We're not in the
           stage of development with PRA and the comfort level
           yet to do that.  And we were glad to see the staff
           pull that out of 50.69, because, again, that's a nice
           goal to shoot for maybe in five or ten years when we
           do have added confidence in the studies, but we're not
           there yet.
                       So if Gareth or Mike or any other NRC
           staff reviewer has a particular question about what
           the licensee did in the Option 2 application, they can
           ask the question in the process.  We still intend to
           define a template, just like we did -- we're using
           risk-informed ISI as a model for this, a template of
           what the licensee would submit as part of an Option 2
           application.
                       So I think the process -- that's another
           part of the process.  We've tried to follow 1.174. 
           That has worked quite well.  I think some of what I
           gathered from the discussion this morning, George, is
           that we're starting reopen some of the things that
           were discussed when 1.174 was developed.  And I think
           in the context of an application, that's not the time
           to do it.  It should be done independently of the
           application.
                       We think sensitivity studies were one of
           the things that 1.174 said you could do to address
           areas where you have uncertainties.  And that's what
           we're doing.  So we're trying to follow the guidance
           that's out there that's been successful, and not try
           to reinvent that, with the Option 2 guidance.
                       Your Committee spent a lot of time on
           1.174.  All those issues were debated quite
           thoroughly.  And to reopen that as we go through this
           process again, I'm not sure is the most --
                       CHAIRMAN APOSTOLAKIS:  Well, and I would
           have to be convinced that I'm reopening issues.  I'll
           go and read 1.174 again, but lets go on.
                       MR. PIETRANGELO:  Okay.  The other thing
           we wanted to briefly chat about today is the
           treatment, and Frank teed up some of those issues.  I
           mean to us we've been talking about treatment I think
           going back to graded QA now for almost ten years.  And
           it continues to bewilder us that the focus of the
           reviews are on the low safety significant SSCs. 
           That's not what risk-informed regulations are all
           about.  That's what we see all the hand wringing about
           just about in every application we get into.  And it's
           like each application, before we get to the end of it,
           it seems like the entire regulatory process has to be
           dumped into this one application, and we forget about
           all the other things that are at play out there.
                       Besides the revised oversight process,
           there's requirements in the rule that the licensee has
           to meet, all right?  And they're subject to inspection
           and enforcement.  And if they don't do what they said
           they were going to do, then that's willful non-
           compliance, and the staff knows very well how to deal
           with willful non-compliances.
                       So I mean we have to remember there's
           whole other regulatory construct around Option 2 that
           doesn't go away.  And we just started hearing about
           these known degradation -- failure mechanisms and
           degradations.  Well, we know what those are.  They
           don't go away when we go to Option 2.  If a valve or
           any other piece of equipment goes into the
           preventative maintenance program, you don't forget
           about all the other stuff that happened to it.  All
           that operational experience is still there.
                       And so NRC can audit the implementation of
           Option 2.  They can audit the performance monitoring
           that goes on with Option 2.  Most of it's already
           captured in the maintenance rule.
                       And the other thing, you know, the
           industry has experience with categorization, even
           before the maintenance rule with some of the MOVs and
           a graded QA application.  So we've been doing
           categorization for a long time.  Let's demystify
           what's going on here.  I mean this is not going to
           hinge on some number in the PRA as the one thing going
           up or down.  I mean to even suggest that that's
           happening through this is absurd, okay?  The Expert
           Panel there's guidance in our document now that talks
           about the requirements for the Expert Panel, that's
           similar to the folks that are around the table here,
           okay?
                       So, again, to get tied up in the level of
           detail and the PRA calculations and all that, we want
           to do a good technical job, I'm not here to say
           otherwise, but unless it has an impact on the result,
           then we can spend an awful lot of time in the noise
           level of this and not get to the fundamental purpose
           of it, which is we've been categorizing SSCs for a
           long time, we have a very comprehensive process we're
           trying to develop and get the staff to endorse, and
           your endorsement, and give the best guidance we can to
           the licensees who wish to go into Option 2.
                       And the short answer to your question that
           you posed at the end, if they don't have a sound
           technical basis from which to defend moving the thing
           down from RISC-1 to RISC-3, they're not going to do
           it, because they're going to be subject to the NRC's
           review, and if you don't have an argument, you can't
           just wave your hands at it and say, "Now, it's RISC-
           3."  There's an extensive process to go through, both
           PRA and other studies done, as well as the Expert
           Panel review, and that will be subject to the staff's
           review also.  We have to put faith in that process.
                       And even afterwards in implementation, if
           there's new information that comes to the table,
           there's mechanisms to treat that, just like there is
           with any other regulation.  And how do you know we're
           implementing a(4) from day to day, how do you know
           we're doing 50.59 right from day to day?  So that
           whole rest of the regulatory process is there to bring
           those up again within this context.  I mean we've all
           been in this business a long time, and to wring our
           hands over that kind of stuff at this point just seems
           to me to be a waste of time.
                       I'm being very candid with you this
           morning.  We've been working on this for a long time,
           progress has been slow.  We've got the last pilot on
           categorization next week.  We'll be rolling that into
           the next draft of our guidance.  We're way ahead of
           where we are normally on a rulemaking with regard to
           the development of guidance.  In most cases, the
           guidance document isn't even developed until the final
           rule is done.
                       (Laughter.)
                       We're way ahead of the game on this one. 
           It's even been piloted already to a certain extent. 
           So remember where we are in the context there.  That's
           all I'm asking.
                       And we've been listening to the questions
           back there and we could point out places in the
           guidance to try to address your questions, but I'll
           ask Adrian and Biff if they want to add anything to
           that.
                       MEMBER POWERS:  In thinking about things
           to add, I guess this philosophical issue that George
           brings up on rigor in the use of PRA, I'd be
           interested in your comments on that.  You've already
           addressed it somewhat.  But I guess what I'm
           interested in is the desirability of having a nice
           rigorous treatment with respect to PRA, understanding
           that the PRAs that we have today bear faint
           resemblance to the PRAs we'll have in ten years or 20
           years.
                       MR. PIETRANGELO:  Right.  We want them to
           be rigorous, we want it to be a repeatable
           application, we want to have some stability in the
           process.  We're all for rigor, okay?  But if you don't
           have the study for a particular scope element of the
           PRA, then you've got to use another means.  You're not
           even going to be an Option 2 potential applicant --
                       MEMBER POWERS:  Because you're too far
           away, yes.
                       MR. PIETRANGELO:  -- right, if you're too
           far away from that.  I mean no one's going to submit
           themselves to the gauntlet of review here if they
           don't think they've got a good technical basis from
           which to do the categorization.
                       MEMBER POWERS:  But doesn't everybody
           think that because of the IPEEEs?
                       MR. PIETRANGELO:  No.  I don't think
           everybody thinks that.  Not to the extent we're
           talking about here in Option 2.  I think for purposes
           of the maintenance rule when we were trying to
           establish the level of monitoring that was done, I
           think the answer to your question was yes.  For this
           purpose, I think this is much more rigorous, and I
           think we're finding out from the pilots, not only more
           rigorous but more costly to do and resource-intensive. 
           So unless you're really serious about it, you're not
           going to do it.
                       CHAIRMAN APOSTOLAKIS:  Anything else? 
           Thank you.
                       MR. PIETRANGELO:  Thank you, George.
                       CHAIRMAN APOSTOLAKIS:  I always appreciate
           Tony's way of -- elliptical way of making a point.  I
           would like to thank the staff as well.  And we will
           reconvene at 1:25.
                       (Whereupon, the foregoing matter went off
                       the record at 12:27 p.m. and went back on
                       the record at 1:27 p.m.)
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           .                     A-F-T-E-R-N-O-O-N  S-E-S-S-I-O-N
                                                      1:27 p.m.
                       CHAIRMAN APOSTOLAKIS:  We're back in
           session.  The next item is the Arkansas Nuclear One,
           Unit 2 Core Power Uprate.  The ACRS cognizant member
           is Mr. Sieber.  Jack, it's yours.
                       MEMBER SIEBER  Thank you, Mr. Chairman. 
           The application and the SER that we're going to
           discuss this afternoon differs from the previous power
           uprates that we've had in that this is the first
           pressurized water reactor that has applied for an
           uprate in power greater than our cutoff limit, which
           has been five percent.  And so this will be the first
           PWR that we have undertaken to examine.  On the other
           hand, the staff has done previous uprates of lesser
           increases in power in the past.
                       Interestingly enough, the Arkansas One,
           Unit 2 is a combustion engineering plant, and in the
           process of deciding what guidance the applicant would
           use in order to make sure that they have covered all
           the aspects that are recommended or necessary to do a
           power uprate, they ended up going to a Westinghouse
           document, which was published in 1983, and it's WCAP
           10263, and that was the basis for the applicant's
           process of coming up with the analysis and studies
           necessary to do the power uprates.  And on the other
           hand, in 1997, the staff did a uprate SER for the
           Farley Plant, and the Farley uprate was also based on
           the WCAP that I discussed and mentioned.
                       And so there is a sort of de facto
           template out there for the staff to write its SER and
           applicants to do the analysis for a power uprate for
           a PWR.  Even though the Plant's combustion
           engineering, there are plenty of similarities between
           the combustion engineering plants and Westinghouse
           plants so that these documents are generally
           applicable.
                       What I'd like to do now is to introduce
           Mr. Craig Anderson from Entergy, and he is Vice
           President of Operations, and he will guide us through
           Entergy's presentation on the power uprate.
                       MR. ANDERSON:  Okay, sir.  Thank you very
           much.
                       MEMBER SIEBER  Sure.
                       MR. ANDERSON:  Again, I'm Craig Anderson. 
           I'm the Site Vice President for Entergy at Arkansas
           Nuclear One.  We've got several other presenters here
           I would like to introduce, and if you all would raise
           your hand in the back.  Bryan Daiber is the Senior
           Staff Engineer that will present a lot of the
           technical information today.  Rich Swanson is the
           Senior Reactor Operator that we brought.  I think the
           operational aspects of a power uprate are very
           important, and we felt like we needed to discuss
           those.  Dale James, the Manager of Engineering
           Programs and Joe Kowalewski, the Director of
           Engineering.  We also have other folks here, members
           of our staff, that might address questions that might
           come up.  And also Westinghouse folks here to address
           any questions that they might help us with.
                       One of the thoughts might be, well, you're
           combustion engineering in NSSS, you've got
           Westinghouse here.  If you recall, Westinghouse
           acquired combustion engineering a few years back, and
           these folks were previously on the combustion
           engineering staff, so we've got good technical
           expertise here to try and address those questions.
                       Over the next hour, we will discuss the
           results of years of work to both analyze our Plant
           and, where necessary, to install modifications to
           support a safe power uprate of the Unit.  You'll see
           that we were careful to maintain the operating and
           design margins, and just as importantly to us, to
           minimize new challenges to the operators.  We
           certainly don't want a power uprated plant that's not
           reliable or that presents difficulties to the
           operators.
                       Where we weren't comfortable with our
           margins we modified our Plant, and we will talk about
           several of those modifications during our
           presentation.  We, of course, used accepted
           methodologies and we've, in all cases, demonstrated
           compliance with regulatory and safety limits.
                       A little bit about the project before I
           turn it over to Bryan.  Our goal is a seven and a half
           percent uprate.  That's where we've completed our
           analysis to support that uprate.  And it essentially
           was a balance on the financials between the investment
           that you make in the Plant and the return you get from
           the investment, and, of course, that without adversely
           impacting the available design and operating margins.
                       I think one of the things that's important
           to point out, the majority of the modifications that
           were needed to support power uprate have already been
           made.  They were installed during the last refueling
           outage in the fall of 2000.  And we've operated this
           operating cycle, which ends next month, with those
           modifications, and the modifications have performed
           quite well.
                       The most significant modification was
           steam generator replacement.  Steam generator
           replacement, while it was not driven primarily by
           power uprate, it was driven by the degradation of
           alloy 600 tubing.  We took advantage of the need to
           replace the steam generators and increased the heat
           transfer area, both to support power uprate and also
           give us some more margin.
                       The rest of the mods, most of them, in the
           balance of Plant will be installed in the spring, and
           we will complete all the necessary work for the power
           uprate, including the start-up testing following the
           outage to support the power uprate.
                       So we believe we're prepared for the
           uprate.  We've done a thorough review of the equipment
           and our analysis and our procedures, and that's been
           completed.  We have been and are continuing to train
           our operators on the uprated Plant to make sure that
           they are ready, and we believe our people and
           equipment are ready.
                       And let me turn it over to Bryan Daiber
           who will go through the technical portion of our
           evaluation.  Bryan?
                       MR. DAIBER:  Make sure the microphone's
           working here.  I'm Bryan Daiber.  I'm the Safety
           Analysis Lead.  I was the Safety Analysis Lead for
           both the RSG and the power uprate projects.  I will be
           going through several of the presentations today.  The
           first one I'm going to go over are the plant
           modifications for considerations of power uprate.
                       For ANO2, we've been considering power
           uprate for the past four cycles.  We were obviously
           considering steam generator replacement due to
           degradation of the alloy 600 tubes in those.  In
           preparation for that, we were trying to move the
           copper from the secondary side system, so we replaced
           the condensers and other major components to do that. 
           And in doing those replacements, we kept power uprate
           in mind in the design of all those components we've
           replaced over the past four cycles.
                       So we have replaced many of the
           components, many of the major modifications have
           already been implemented, and we've operated with
           those for at least one cycle on most of the major
           components.  And as I mentioned, we did keep that in
           mind, the power uprate was considered for those
           modifications.
                       On this slide, we list many of the
           modifications, balance of plant, and other
           modifications needed to support power uprate
           conditions.  Many of the major modifications, like I
           said, have already been installed and have
           accommodated for power uprate conditions.  Rather than
           go over these balance of plant type modifications, I'd
           rather focus in on three key areas, the highlighted
           ones in blue here:  the replacement steam generators,
           the containment uprate considerations and the fuel
           core design considerations that we implemented for
           power uprate itself.
                       The first key modification, the steam
           generators.  We did replace steam generators last
           outage.  There were degradation concerns with the
           alloy 600 tubes.  When we replaced these steam
           generators, we replaced them with steam generators
           that were specifically designed for the power uprate
           condition.  In light of that, when we designed these
           generators, we did increase the tube sheet diameter by
           four inches to accommodate greater number of tubes in
           the steam generator.  We also increased the surface
           area and the number of tubes in the generator by going
           from three-quarter-inch diameter tubes to eleven-
           sixteenths diameter tubes.  The net effect of these
           changes allowed us to gain 25 percent surface area on
           the tubing material in the new steam generators.
                       The result of that also resulted in an
           increase in the primary side volume.  Now this is key. 
           The increase in primary side volume did cause a
           challenge to the containment building pressure.  As a
           result of that, we did have to look at the building
           pressure considerations.  The volume, we essentially
           went from 1,600 cubic feet to 1,839 cubic feet per
           steam generator.  That increase in volume obviously
           resulted in an increase in mass of energy available to
           blow down to containment for our LOCA analysis.
                       In comparing that to the effects of power
           uprate, for power uprate considerations on the
           containment analysis, power uprate results in a
           slightly higher increase in Tav, and we're also
           proposing to increase Tcold by two degrees.  Both of
           these effects essentially increase the energy content
           in the RCS available for the blowdown, but it does
           decrease the mass available.  So really the net effect
           is the increase in volume had a much bigger impact on
           the containment pressure considerations than the power
           uprate considerations.
                       The other thing on the new steam
           generators, the secondary side volume also went up as
           a result of the change.  To offset that change in
           secondary side volume, we didn't modify the steam
           generators.  The new steam generators have an integral
           flow restricting nozzle in them.  This integral flow
           restricting nozzle, in combination with high
           containment pressure actuation signal, the containment
           spray actuation signal, was sent to isolate main steam
           and main feed.  The combination of those two
           modifications essentially reduced the peak building
           pressures associated with the higher power steam line
           break considerations.  As a result, the hot zero power
           steam line break is actually the most limiting.
                       MEMBER SIEBER  Did you not increase the
           sprayed area of containment also?
                       MR. DAIBER:  No, we did not -- the sprayed
           area of containment by the containment spray system
           stayed the same.
                       MEMBER SIEBER  All right.
                       MR. DAIBER:  So we have designed a new
           steam generator to accommodate power uprate
           conditions.
                       The second key design consideration that
           we made to accommodate power uprate was, as we
           mentioned, we did uprate the containment design
           pressure.  We went from a design of 54 pounds to 59
           pounds.  We accommodate this increase in design
           pressure by recognizing the fact that the Unit 2
           containment is very similar to the Unit 1 containment,
           although not identical.  And the Unit 1 containment is
           already designed to 59 pounds.
                       There was a detailed finite element
           analysis done to verify the structural capabilities of
           the containment.  That detailed finite element
           analysis did credit additional tendons.  We didn't
           install additional tendons, but there were -- as part
           of uprate, but during original construction,
           additional tendons were put into the containment to
           account for surveillance considerations and
           construction considerations that weren't originally
           credited in the original structural analysis.  We did
           credit those in this analysis to accommodate the
           increase in design pressure.
                       Not only did we verify that the structure
           itself was capable of operating at the higher design
           pressure, we also verified the equipment inside
           containment was also able to accommodate the higher
           design pressure.  The containment was tested at 68
           pounds to verify its capabilities.  All of this work
           was done obviously as part of the replacement steam
           generator project and has already been approved by
           License Amendment 225.
                       The third key change or consideration with
           respect to power uprate deals with the fuel core
           design itself.  At ANO2, we are currently using a
           Gadolinia integral burnable poison.  We are going to
           switch that integral burnable poison from Gadolinia to
           Erbia.  Now, back in Cycle 13, Cycle 16 being the next
           core design and it's our operated core design, but
           back in Cycle 13, we started replacing the poison
           schims before c-schims with integral burnable poisons,
           and Gadolinia was the burnable poison of choice at the
           time.  By replacing those schims with these integral
           burnable poisons, we have effectively gained almost
           four percent additional pins available in assemblies
           for additional fuel considerations.
                       The Gadolinia burnable poison is a much
           more potent poison, and the typical assembly will have
           about eight weight percent Gadolinia versus about two
           weight percent for Erbia.  The Gadolinia within an
           assembly that has Gadolinia pins, they'll be somewhere
           between four and eight pins, or four and 12 pins per
           assembly.  Whereas with Erbia, we'll have somewhere
           between 30 to 100 Erbia pins per assembly.
                       The Erbia is current approved methodology. 
           There are many plants within the CE fleet already
           using the Erbia core designs.  There's essentially
           over 159,000 Erbia pins already in operation, 64,000
           of which have already been discharged.  As I
           mentioned, the Erbia is a more dilute poison, it
           allows us to have better power control and gives us
           better peaking control within the assembly itself. 
           And that helps us out just during normal operation
           conditions and also as a result of any transient
           conditions that would occur.  It also allows us to
           have a better control over the moderate temperature
           coefficient.
                       MEMBER POWERS:  What was the attraction of
           selecting Erbia as the poison?
                       MR. DAIBER:  Again, within the assembly
           itself, the Erbia allows for a much more equal power
           distribution within the assembly.
                       MEMBER POWERS:  Well, I understand that. 
           That's based on the number of pins that you put in
           there.
                       MR. DAIBER:  Pins and the amount of the
           poison.  Erbia's more at two percent, whereas
           Gadolinia's more at six to eight percent.
                       MEMBER POWERS:  But you could have just as
           well have put two percent Gadolinia and put more pins
           in and done the same thing, couldn't you have?
                       MR. DAIBER:  Jeff?
                       MR. BROIDA:  Use a microphone and identify
           yourself, please.
                       MR. DAIBER:  I'll let Jeff Brown from
           Westinghouse speak to that question.
                       MR. BROWN:  Jeff Brown, from Westinghouse. 
           Another major difference is the cross-section of
           Erbia.  It has about 200 barns cross-section for Erbia
           compared to, I believe, about 10,000 barns for
           Gadolinia.  Gadolinia, on a per atom basis, is much
           more stronger thing, and it depresses the local power
           distribution almost like you had a small control rod
           there.  Whereas Erbia, you know -- so even in a two
           weight percent concentration, the Gad would have a
           similar effect as it does not.
                       MEMBER POWERS:  Oh, okay.  So you're just
           avoiding the high cross-section --
                       MR. BROWN:  Yes.
                       MEMBER POWERS:  Sure, I understand.
                       MR. DAIBER:  I'd like to make two major
           points here with these comparisons of the core
           designs.  The most -- the first issue, which we've
           already talked about is that going to the Erbia
           burnable poison allows us to do the flatter power
           control within the assembly itself.  Also, the number
           of assemblies we're putting in for Cycle 16 it's a
           larger reload.  Eighty new fresh assemblies are going
           into the Cycle 16 core design.  By doing that, we also
           control the peaking factors, the radial peaking factor
           is going down by over seven and a half percent for the
           uprated core designs.  That gives us a flatter power
           distribution within the whole core itself.
                       The other important point I'm trying to
           make on this slide is the energy content.  The energy
           content for Cycle 16 is actually bounded by the energy
           content that we've already implemented under our
           current power rating conditions in Cycle 14.  The
           Cycle 14 length was 557 EFPD.  For Cycle 16, the EFPD
           is 485.  When converted to a comparable power of
           2,815, it's more like 521 EFPD.  So it's actually
           lower energy content.  That also can be noticed by the
           cycle burn-up value.  The cycle burn-up for Cycle 14
           was 19,770 megawatt days per ton, whereas for Cycle
           16, it's 18,825 megawatt days per ton.
                       I'd like to make two clarifications from
           the Subcommittee presentation.  There was a question
           asked at the Subcommittee about the fuel zoning.  For
           Gadolinia fuel assemblies, we typically have three
           zones of U235 considerations.  I believe we may have
           mentioned only one in the Subcommittee presentations. 
           With the Erbia, there are essentially two zones of
           zoning in the Erbia designs.
                       The other question that came up at the
           Subcommittee meeting was with respect to the cycle
           burn-ups, and we've just discussed the cycle burn-ups
           for the different core designs.  Yes?
                       MEMBER BONACA:  I had a question, but I
           couldn't find the answer here.  You must have changed
           your Delta T, T hot to cold.
                       MR. DAIBER:  Yes.  Our RCS flow stays the
           same, so the T hot goes up.
                       MEMBER BONACA:  Yes.  Have you changed
           your pressurizer program?
                       MR. DAIBER:  The pressurizer --
                       MEMBER BONACA:  Program.
                       MR. DAIBER:  Yes.  The pressurizer level
           control system was reviewed and verified and updated
           as necessary to account for the Tav increase.
                       MEMBER BONACA:  Because some of the early
           CE five percent power increases didn't, and they used
           to lose pressurizer level when they were SCRAMing.  So
           you did look at that.
                       MR. DAIBER:  Yes, we did look at that.
                       With that, I'd like to move on to the next
           agenda item, which deals with compliance with
           regulatory requirements, and in particular they deal
           with the Plant margins.  We did review the ANO2 design
           to make sure it could accommodate the power uprate
           conditions.  We did obviously look at all the balance
           of plants, and we made modifications as necessary on
           the balance of plant to ensure that it could
           accommodate power uprate within its design
           considerations.
                       We also looked at the NSSS, the nuclear
           steam supply system, which is a CE-manufactured
           product, and we verified that all the design
           components there could also withstand the
           considerations on the power uprate conditions.  We
           also looked at the control systems, the pressurized
           level control, feedwater control system and all the
           control systems and made sure that they also could
           accommodate power uprate.  And as we discussed, steam
           generators containment and the fuel design were also
           considered, along with all the safety systems.
                       In the review of any of these systems, in
           any place where we felt margin was not being
           maintained as a result of the power uprated
           conditions, modifications were implemented or will be
           implemented in the next outage to ensure that all the
           components could operate satisfactorily at uprated
           conditions.  And for the control systems, appropriate
           set point changes have been made for those systems.
                       MEMBER SIEBER  I'd like to go back to RSC
           flow.
                       MR. DAIBER:  Yes.
                       MEMBER SIEBER  During the Subcommittee
           meeting, it was stated that the replacement of steam
           generators had a lower DP --
                       MR. DAIBER:  Yes.
                       MEMBER SIEBER  -- on the primary side than
           the original ones.
                       MR. DAIBER:  That is correct.
                       MEMBER SIEBER  That would increase RCS
           flow instead of having it stay the same, right?
                       MR. DAIBER:  That is correct.
                       MEMBER SIEBER  And that's why your Delta
           T change was not as much as you would ordinarily
           calculate from a seven and a half power increase?
                       MR. DAIBER:  There are several things that
           went on.  Obviously, with the old steam generators we
           had plugged those quite a bit, and flow -- the delta
           P had gone up, and flow had gone down.  When we
           installed the new steam generators, we designed those
           to essentially restore the delta P of the steam
           generator essentially comparable to the unplugged
           original steam generators.  So flow went back up as a
           result of that, but it was more due to the plugging --
           the removal of the plugging restrictions.
                       MEMBER SIEBER  Now, it would seem right
           now with the new steam generators that you have a --
           you take into account the fact that I690 has a cooler
           heat transfer coefficient, so that takes away surface?
                       MR. DAIBER:  That's true.
                       MEMBER SIEBER  Looks like you have a plug
           of about ten percent.  Is that correct?
                       MR. DAIBER:  When we did all of our work,
           we did it with a ten percent consideration, so all of
           the efforts that we undertook, we assumed a ten
           percent plugging consideration.
                       MEMBER SIEBER  And so that -- if I add the
           eight percent and the ten percent and the seven and a
           half percent increase in power, that accounts for all
           the additional surface that's in there.
                       MR. DAIBER:  Essentially, yes.
                       MEMBER SIEBER  Okay.  Thank you.  Now, I
           have one other question, going back to containment. 
           What was the containment test pressure?
                       MR. DAIBER:  Sixty-eight psig.
                       MEMBER SIEBER  Sixty-eight.
                       MR. DAIBER:  Yes, 68.
                       MEMBER SIEBER  That's 110 percent of the
           design.  Okay.  Thank you.
                       MR. DAIBER:  Hundred and fifteen percent. 
            Right, 115 percent.
                       One other point I'd like to make is that
           when analyzed the safety analysis and control system
           considerations, we are a CE NSSS Plant, and we
           utilized many of the CE Westinghouse methodologies for
           performing the safety analysis, core design
           considerations.  These methodologies that we utilized,
           that Westinghouse utilizes are the same methods used
           by other CE plants of higher power rating than where
           ANO2 is projected to go.
                       As we've discussed, we did install new
           steam generators.  Those steam generators were
           specifically designed to accommodate power uprate to
           ensure adequate margin was accommodated in those steam
           generators.  Containment was uprated from 54 to 59
           pounds.  We installed integral flow restricting nozzle
           in the CSAS actuation to accommodate the secondary
           side inventory associated with that.  We did have to
           modify the containment cooling fans.  The horsepower
           requirements in the cooling fans went up above the
           motor rating at the 59 pound consideration.  To
           accommodate that, we reduced the pitch, we lowered the
           flow a little bit, brought the horsepower requirements
           back down within design considerations.  To offset
           that effect, out tech specs only required us to have
           one containment cooling fan per train.  We upped that
           to two containment cooling fans per train to offset
           that.
                       MEMBER KRESS:  How did you increase your
           design pressure?
                       MR. DAIBER:  The design pressure on the
           containment, again, we went back and we looked at the
           -- did a finite element analysis on the structural
           containment design itself and verified that the
           structure could maintain additional pressure
           associated with that.
                       MEMBER KRESS:  So you reanalyzed it.
                       MR. DAIBER:  Yes.
                       MEMBER KRESS:  Okay.
                       MR. DAIBER:  We did a reanalysis.
                       MEMBER KRESS:  And you needed that for
           five pounds?
                       MR. DAIBER:  Not all of the five pounds. 
           The 59 pounds came more from the Unit 1 design
           consideration.
                       MR. ADAMS:  Let me address that.  My name
           is Doyle Adams.  I was on the containment uprate
           project itself, also the steam generator replacement,
           and then was also the responsible engineer for the
           mods and things that was done to the containment and
           the repair and the testing of the containment when it
           came out.
                       The way we came up with the amount we
           could actually go, which is only about five pounds,
           it's about ten percent additional capacity -- Unit 1
           is very, very similar.  It only lacks in tendons in
           some areas due to the design time that it was actually
           come in.  What happened when we went through and
           developed a complete reanalysis of the containment
           using the BECHTEL BSAP program they have, which is
           used for San Onofre.  It was designed for concrete
           containment.
                       There was additional tendons put into the
           containment, like we said a while ago.  There was
           three additional tendons in each grouping for the dome
           and the hoop and the vertical tendons.  There was
           three additional ones for surveillance only.  They
           added an additional three tendons in each group to
           take care of construction problems that you might go
           into and then loss of wire with the surveillance
           processes over the life of the containment itself.
                       So you have these 18 additional tendons
           that were not accounted for in the original analysis,
           and that's where this additional capacity came in. 
           You also have additional -- use very conservative
           creep values for the concrete when it was originally
           done, and that allowed us to maintain more of our
           compression in the concrete due to less loss of creep
           in the concrete.
                       MR. DAIBER:  So we have reviewed the Plant
           as a whole and verified that the Plant with design
           margin considerations can be operated at uprated
           conditions.
                       With that, I'm going to move down to the
           fifth agenda item, dealing with ECCS analysis.  I'm
           going to switch things up here a little bit.  And for
           the ECCS analysis, emergency core cooling system
           analysis, we analyzed the ANO2, large break LOCA and
           small break LOCA considerations using 10 CFR 50.46
           Appendix K, approved methodologies.  We used approved
           methodologies, a combustion engineering, all
           Westinghouse methodologies, to do that analysis for
           power uprate considerations.  These are in compliance
           with Appendix K and hence have the conservatism
           associated with Appendix K built into them.  They are
           not the best estimate methodologies that are
           available.
                       We did -- in order to accommodate power
           uprate, we did move to the 1999 evaluation model for
           the large break LOCA considerations.  That was
           necessary to ensure that under uprated conditions we
           did not have to impose any additional operating
           restrictions.
                       So we did use approved methodologies.  The
           large break LOCA methodology is documented in CENPD-
           132, Supplement 4-P, Revision 1.  The small break LOCA
           methodology, for that we used the same methodology
           that we were currently licensed to -- are currently
           licensed to, which is referred to as the S2M.  It's
           documented in CENPD-137, Supplement 2-PA.
                       In performing these analyses, obviously we
           got acceptable results.  We stayed within the
           acceptance criteria.  The peak clad temperature for
           the large break LOCA analysis went up from 2,029
           degrees Fahrenheit, which was analyzed with the old
           methodology, and it went up to 2,124 degrees with the
           new methodology.  The small break LOCA, the peak clad
           temperature went up from 1,905 degrees to 2,090
           degrees.  We also verified that the maximum clad
           oxidation, the maximum core-wide oxidation and
           coolable geometry requirements were also maintained.
                       MEMBER SHACK:  Did you do a full spectrum
           of breaks or you analyzed your limiting breaks from
           your previous?
                       MR. DAIBER:  We did a spectrum of breaks. 
           We did a spectrum of large break LOCAs and a spectrum
           of small break LOCAs.
                       MEMBER SHACK:  How did that spectrum
           compare with your previous analyses?
                       MR. DAIBER:  It was effectively the same
           spectrum, a very similar spectrum.  The break size
           changed on the large break LOCA, so the spectrum
           changed a little bit to accommodate that, to make sure
           we bounded it on each side.
                       MEMBER BONACA:  For the large break LOCA,
           you say you used a new, approved methodology?
                       MR. DAIBER:  That's correct.
                       MEMBER BONACA:  Was it specifically for
           this change, to support this modification?
                       MR. DAIBER:  The large break LOCA
           methodology was developed not for power uprate.  It
           was developed generically.
                       MEMBER BONACA:  Okay.
                       MR. DAIBER:  But it was implemented, and
           it was necessary.  The margin gained by going to the
           1999 EM was necessary to ensure power uprate
           conditions without any additional operational
           restrictions.
                       MEMBER BONACA:  Okay.  So you were looking
           for some margin there, and this new methodology gave
           it to you.
                       MR. DAIBER:  That is correct.  Again, the
           methodology, though, is still in compliance with
           Appendix K --
                       MEMBER BONACA:  I understand.
                       MR. DAIBER:  -- considerations.
                       MEMBER SIEBER  It was --
                       MEMBER KRESS:  What were these values for
           the ANO2 without the uprate?
                       MR. DAIBER:  The peak clad temperature for
           large break LOCA was 2,029.
                       MEMBER KRESS:  Okay.
                       MR. DAIBER:  For the large break.  And for
           small break LOCA, it was 1,905.  I don't have the
           other ones readily available.
                       MEMBER KRESS:  Okay.
                       MEMBER SHACK:  And that's with the same
           analysis methodology.
                       MR. DAIBER:  The same break LOCA, yes. 
           The large break, we switched.
                       MEMBER SIEBER  It was my understanding
           that the large break LOCA evaluation model used FLECHT
           data, or reflood heat transfer coefficients.  Is that
           correct?  And that was one of the factors that gives
           you additional margin?
                       MR. DAIBER:  I'll let Joe Cleary from
           Westinghouse address that.  He can more appropriately
           answer that question.
                       MR. CLEARY:  Yes.  The large break
           evaluation model does use FLECHT-based reflood heat
           transfer coefficients, and one of the improvements we
           made going from the 1985 EM to the 1999 EM was to
           improve the procedure for applying the FLECHT
           correlation.
                       MEMBER SIEBER  Could you tell me about how
           much margin you think you gained on a Plant like this
           in degrees between old and new --
                       MR. CLEARY:  For that change, I believe it
           was a little bit less than 100 degrees on that
           particular one.
                       MEMBER SIEBER  Okay.
                       MR. CLEARY:  The sample calculations we
           showed in the topical gave a range of 64 to 72 degrees
           --
                       MEMBER SIEBER  Okay.
                       MR. CLEARY:  -- for a couple of
           calculations.
                       MEMBER SIEBER  Okay.  But 100 is a good
           number?
                       MR. CLEARY:  I would go a little bit less
           than 100.  Overall, the change from the '85 EM to the
           '99 EM resulted in a change of 150 degrees net.
                       MEMBER SIEBER  Okay.  Thank you.
                       MR. CLEARY:  Approximate.
                       MR. DAIBER:  So we have performed the LOCA
           analysis and verified acceptable results under
           operating conditions.
                       With that, I'm going to jump back up to
           Agenda Item Number 4, which are the review issues, and
           with this I'm going to switch things on around here a
           little bit again too.  I'm going to start out with
           ATWS considerations.
                       ANO2 is a CE-designed Plant, and so our
           approach to ATWS is different than that that the
           boilers and some of the Westinghouse plants have
           considered.  Boilers and some of the Westinghouse
           plants do credit operator action and perform analyses
           to ensure compliance with the ATWS considerations. 
           ANO2, being a CE Plant, for our compliance with 10 CFR
           50.62 ATWS requirements, we installed a diverse and
           redundant SCRAM system.  We also installed a diverse
           emergency feedwater actuation system and took credit
           for a diverse Turbine Trip system at the Plant.
                       For power uprate considerations, we
           verified that these systems and their set points and
           response times associated with these systems would
           still remain valid under uprated conditions to ensure
           compliance with the ATWS considerations.
                       I'm going to move on to the impact of
           containment response.  We did, obviously, redo the
           containment analysis.  When we redid that analysis, we
           looked at both the steam line break and the LOCA
           considerations.  The mass and energy that was
           generated for that peak building pressure
           consideration, they were generated using Westinghouse
           CE combustion engineering, Westinghouse methodologies
           to generate mass and energy release.  That mass and
           energy release data is input into the BECHTEL COPATTA
           code, which is our containment peak building pressure
           analysis code, to get the new peak building pressure
           considerations.  When we did all this, we did it as
           part of the RSG project, and we did it to account and
           cover power uprated conditions, and it's all been
           approved as part of License Amendment 225 already.
                       For the LOCA, we did look at cold leg, hot
           leg -- cold leg discharge, cold leg suction, hot leg
           break considerations.  We did look at various single
           failures to come up with the limiting LOCA peak
           building pressure considerations, and the loss of an
           EDG was a limiting single failure.  For the steam line
           break, we looked at a range of power levels and a
           range of single failures associated with this.
                       And as I mentioned before, we installed
           integral flow restricting nozzles in the CSAS
           actuation signal to isolate main steam and main feed,
           such as the hot zero power steam line break is now the
           most limiting break with the single failure of a
           spray.  The new peak building pressures associated
           with the LOCA was 57.6 psig, and with the hot zero
           power steam line break, it's 57.4 psig.
                       As part of compliance with Appendix K
           methodologies for peak clad temperature
           considerations, we also do a minimum containment
           pressure analysis, and that peak pressure was 27 psig,
           but that's for Appendix K compliance considerations,
           just to show the relative margin between peak building
           pressure and minimum building pressure for LOCA
           considerations.
                       With that, I'd like to turn it over to
           Dale James for alloy 600 considerations.
                       MR. JAMES:  Thank you, Bryan.  Good
           afternoon.  My name is Dale James.  I'm the Manager of
           Engineering Programs and Components at Arkansas
           Nuclear One.  I will be discussing the impact of the
           power uprate on our alloy 600 nozzles in the RCS and
           on the secondary components due to the flow
           accelerated corrosion.
                       As Bryan mentioned, the power uprate was
           made possible by the replacement of the ANO2 original
           steam generators with new generators made with alloy
           690 tubing, but also with a heat transfer area of
           approximately 25 percent greater than our original
           steam generators.
                       By increasing the heat transfer area by
           this magnitude, we were able to accommodate the power
           uprate with only a marginal increase of the T hot to
           609 degrees.  Historically, our T hot has run between
           600 and 607.  Under the power uprated condition, T
           cold will be approximately 551, which is actually a
           reduction in the T cold from our original cycles of
           operation by about two degrees.  The pressurizer
           conditions will remain unchanged.  Temperatures and
           pressures there will be consistent with the power
           uprated conditions.
                       Therefore, for the uprate, we evaluated
           the effects of the increase in temperature on the
           reactor vessel head nozzles and the hot link nozzles. 
           The increase in T hot for the reactor vessel head
           nozzle has been evaluated using the same methodology
           as the industry has used to evaluate the conditions
           identified in NRC Bulletin 2001-01.  That was dealing
           with the Oconee 3 circumferential cracking issues.
                       The methodology is founded -- or is based
           upon EPRI Material Reliability Program documents 44
           and 48.  And this process ranks components based upon
           their potential for a primary water stress corrosion
           and cracking of the reactor vessel head nozzles.  And
           that ranking is based upon a plant's operating time,
           adjusted for the difference in reactor vessel head
           operating temperature using an activation energy
           model.
                       Considering the increase in T hot at ANO2,
           the ranking time was decreased for the power uprated
           condition from 17.1 EFPY to 14.2 EFPY.  With this
           reduction, ANO2 remains in what I've characterized as
           a moderate category.  That is a range of five to 30
           EFPY that the bulletin established for reaching a
           condition similar to that at Oconee 3.
                       For this category of plant, the bulletin
           recommended that the licensee perform an effective
           visual examination of the reactor vessel head nozzles
           during the upcoming refueling outage.  Due to
           constraints that we have with respect to our
           insulation design on ANO2, we are unable to perform a
           100 percent visual examination of the reactor vessel
           head.  Therefore, during our upcoming refueling
           outage, we will be performing a 100 percent UT
           examination from below the head.
                       With respect to the hot leg nozzles --
                       MEMBER SHACK:  When is that outage, this
           spring?
                       MR. JAMES:  This spring.  It begins this
           April.
                       For the hot leg nozzles, we will be
           continuing to perform a 100 percent bare metal
           examination at each of our refueling outages to detect
           any signs of leakage.  To date, we have replaced nine
           of the 19 hot leg nozzles, and those replacements are
           performed with alloy 690 material.  All the nozzles
           below the water line in midloop have been replaced to
           date.  As I mentioned, we will continue to perform
           those examinations in the future to detect any
           leakages of any additional nozzles.
                       MEMBER SHACK:  I asked this question
           before, and I can't remember the answer.  Your surge
           line, is that stainless, so do you have 182 butters
           anywhere?
                       MR. JAMES:  Yes.  Because they're all
           shop-welded safe ends, then connected to the stainless
           nozzles.
                       MEMBER SHACK:  But that's just for the
           pressurizer.
                       MR. JAMES:  Yes.  Now, we have other
           stainless components.  Our reactor coolant pump
           casings are stainless also in the cold legs.  Those
           also have shop-welded safe ends on them and butters at
           the shop.  Okay?
                       With respect to FAC, the impact of power
           uprate on secondary components were evaluated
           utilizing the EPRI CHECKWORKS Program.  A parametric
           study was performed assuming a maximum steaming rate
           under the power uprated conditions.  The Check rate
           model predicted minimal impact on FAC wear rates. 
           This prediction is consistent with those that other
           utilities have evaluated under power uprate conditions
           and is also consistent with measured values following
           uprated conditions.
                       Following uprate, we will continue to
           monitor those areas that are most susceptible as a
           result of the power uprate condition, and if we see
           any deviations from what the model predicted, we'll
           factor that back into our modeling for any future
           repair and replacement decisions.
                       MEMBER SIEBER  Could you give me an
           estimate, from a percentage standpoint, about how much
           increase CHECKWORKS predicted for FAC?
                       MR. JAMES:  Yes.  What we did was looked
           at some of the more susceptible components as were
           identified as a result of the power uprated
           conditions.  What we saw there is probably an average
           increase in wear rate of about five mils per year. 
           That's added on to what we would consider a relatively
           low wear rate right now.  So we were not anticipating
           any major modifications or any major changes in our
           wear rate.
                       MEMBER SIEBER  Okay.  Thank you.
                       MEMBER SHACK:  Have you done chrome-olly
           replacements?
                       MR. JAMES:  Yes.  All of our replacement
           is done with two and a quarter chrome-olly, which
           essentially eliminates FAC wear.
                       MEMBER SHACK:  But how much of your
           secondary piping now is chrome-olly or you just do it
           as you go?
                       MR. JAMES:  Well, we do it as we go, but
           we take a very proactive approach to that.  We're
           replacing probably on the order $300,000 to $400,000
           worth of piping each refueling outage.  So we're not
           waiting until a system wears to a point where we're on
           threat of losing a component.
                       Okay.  In conclusion, our evaluation shows
           power uprate will only have minimal impact on both our
           alloy 600 nozzles and our FAC wear rate, although we
           will continue to evaluate and monitor those systems to
           ensure our predictions are consistent.
                       I'm going to turn it over now to Rich
           Swanson in our operation organization.
                       MR. SWANSON:  Hi.  I'm Rich Swanson.  I'm
           a senior reactor operator on Unit 2.  I'm the ops lead
           for power uprate, and I was also a member of the Steam
           Generator Replacement Team.
                       Training has already started on our new
           plant.  Simulated changes have been made, and we have
           two training cycles that are concentrating on power
           uprate.  Each crew will be evaluated on an uprated
           plant prior to outage.  And I'd like to point out, the
           changes we're doing for power uprate have much less
           impact than those we did last cycle for steam
           generator replacement.
                       Changes to controls and displays have been
           minimal or none.  We've made no physical modifications
           to control stations due to power uprate, and there's
           no change in the format or the Safety Parameter
           Display System.
                       We have made about 75 procedure changes
           for power uprate, and that includes emergency abnormal
           and normal operating procedures.  There's been no
           change to the type and scope of procedure, and we
           haven't had to write any new procedures for power
           uprate.  As far as emergency operating procedures,
           once again, there's no change to type and nature of
           actions, and we have added no new actions.
                       Operations is heavily involved in the
           development and implementation of Power Ascension
           Testing.  We have test teams designated to perform all
           the testing coming up out of outage.  They'll be
           working with the test group.  And these are
           experienced teams.  The operations leads on these test
           teams are also involved in the steam generator
           replacement testing.
                       This slide shows our power ascension
           profile for coming up out of our next outage.  The
           first four points are standard for coming up out of
           any outage.  You have turbine over speed testing and
           three points for physics testing.  And we'll stop at
           90 percent power, which is approximately 98 percent of
           our current power level.  And they'll be performing
           walkdowns, vibration checks, control system checks,
           parameter verifications.  And we'll make sure
           everything is where we predicted it to be before we
           increase power.
                       You see those hold points?  About 24 to
           48 hours at each hold point.  From there we'll go up
           in 2.5 percent increments and repeat all the testing.
                       I'd like to turn it over to Joe
           Kowalewski, who will talk more about our Start-Up Test
           Program.
                       MR. KOWALEWSKI:  Joe Kowalewski.  I'm the
           director of engineering, and going to review the
           Start-Up Testing Program that we've got outlined.
                       Our Start-Up Test Program is in compliance
           with Test Spec 6.9.1, which requires that we review
           against our original start-up testing program as
           documented in the Safety Analysis Report.  Original
           testing for the plant was in compliance with
           Reg Guide 1.6.8.
                       We've gone through the Safety Analysis
           Report, reviewed approximately 150 tests specified in
           that report.  We've also looked at the scope of all
           the modifications that were done both for the
           replacement steam generator as well as the power
           uprate.
                       We've used industry experience to look at
           our Start-Up Test Program.  We looked at recent CE
           System 80 plants that have started up and reviewed
           their test programs.  We reviewed the start-up test
           programs associated with other steam generator and
           replacements in power uprates.  And then after we
           completed the development of our test program, had an
           assessment done with industry expertise, both
           combustion engineering in Westinghouse and start-up
           leads from other plants that validated our test
           program.
                       We have done extensive start-up testing
           for the steam generator replacement already.  Much of
           that is credited for the power uprate.  That includes
           post-modification testing associated with each of the
           modifications that was performed in the plant;
           performance of the components as well as the control
           systems; the containment testing for the uprate of
           containment, which was the Structural Integrity Test
           as well as the Code Test there.  And steam generator
           performance testing-- both components effects on the
           plant as well as performance of the generator itself.
                       Additional testing we intend to do, we
           will as part of our shut-down into 2R15 do a
           25 percent load rejection to further benchmark our
           integrated control system response.  We have tested
           each of the control systems, and this will give us
           additional data to see if there's any final
           adjustments we need to make before we go up further in
           power.
                       And we will be doing the routine
           pre-criticality low power physics and power range
           testing to validate the core design.  So we'll do the
           power range testing both at our 90 percent, and then
           again when we reach 100 percent in our operating
           conditions.
                       As Rich talked about, we have a overall
           work plan for control of the power extension coming
           out of the outage.  We'll stop at 90 percent, take
           extensive data, baseline the plant there, and then go
           in 2.5 percent increment above that.  As we take the
           data both on the primary and secondary side, we'll be
           looking and comparing it to our heat balance as well
           as all of our design predictions.  And it will be
           reviewed by a test working group made up of senior ANO
           plant management, including the operations manager,
           systems engineering manager, design manager, and our
           on-site Review Committee chair.
                       We'll be verifying our heat balance at
           each of those points and collecting a wide variety of
           key parameters, both on the primary and secondary
           side.  We'll be doing biological shield surveys at
           each point and piping vibration testing both inside
           and outside of containment.  And inside containment
           we'll be using hand-held instrumentation on the feed
           water and steam lines.
                       Once we get up at our operation condition,
           we will be doing a moisture carryover test as well as
           performance testing of the steam generator.  A
           question that came up in the subcommittee meeting was
           relative to steam quality and effect on the turbine. 
           Right now, at our current conditions, in the
           replacement steam generator we're seeing .02 percent
           on one steam generator and .013 on the other, with an
           acceptance criteria of .1.  That's compared to a steam
           quality of .2 percent -- approximately
           .2 percent -- for the old steam generator.  So the
           steam quality is actually an improvement over what we
           had before.  And we don't expect any negative effects
           ont the turbine.
                       MEMBER SIEBER  Do you offhand know what
           the turbine rating is for inlet quality?
                       MR. KOWALEWSKI:  The rating.
                       MEMBER SIEBER  A lot of times they're
           something like 1 percent.  And so, below 1 percent,
           that sort of tells you how much margin you have.
                       Do you know what it is?
                       MR. KOWALEWSKI:  I don't know offhand what
           the turbine rating is.
                       MEMBER SIEBER  Who's the turbine
           manufacturer?
                       MR. KOWALEWSKI:  It's a GE turbine.
                       MEMBER SIEBER  Okay.
                       MR. KOWALEWSKI:  Vince, do you know that
                       MR. BOND:  I've heard the term 1 percent.
                       I'm Vince Bond, start-up testing group
           supervisor.  I've heard 1 percent before from various
           design people.  I don't know that for a fact myself,
           but 1 percent is the term that I've heard.
                       MEMBER SIEBER  I guess it's not very
           important.  But it looks like you have a lot of
           margin.
                       MR. KOWALEWSKI:  Okay.  The acceptance
           criteria for the test is 1 percent.
                       MEMBER SIEBER  Thank you.
                       MR. KOWALEWSKI:  .1 percent.  I'm sorry.
                       The plant will be verified form -- 
                       MR. WILSON:  Excuse me.  I'm Roger Wilson
           with Entergy.
                       On moisture carryover, the design of the
           RSG gave us a lot more volume for feedwater control. 
           The original steam generators had a conical section
           that went into a cylindrical sectional.  Now it's
           strictly in a conical section.  So we've done a lot of
           looking at high-level trip, and we have a lot more
           margin for that than we had with the original steam
           generators.  And, of course, the turbines being more
           efficient, they're designed for going deeper into the
           two-phase dome.  And they're probably designed for
           that.
                       MR. KOWALEWSKI:  Our test program will
           verify that we're performing in accordance with the
           design parameters, and we'll document that in our test
           report within 90 days of the plant start-up.
                       Now I'd like to return it to Bryan Daiber,
           who's going to talk about the impact of power uprate
           on point risk.
                       MR. DAIBER:  I'm Bryan Daiber, again.
                       For the power uprate considerations, not
           only did we look at the safety analysis
           considerations, but we also looked at the potential
           risk impacts associated with power uprate.  And we did
           this effectively in several forms.  We did quantify
           the effects of power uprate on the core damage
           frequency and the large early release frequency
           considerations.
                       We also in more of a qualitative fashion,
           we addressed the effects of power uprate on the
           external events--  seismic, fire vulnerabilities,
           tornadoes, winds, failures, transportation accidents
           at nearby facilities and awful long shut-down risk
           considerations.
                       For looking at the core damage frequency, 
           the Level 1 considerations and the impacts of power
           uprate on those, we reviewed the initiating event
           frequencies, we reviewed the success criteria,
           component failure rates, system fault trees, and
           operator responses associated with the Level 1 CDF
           considerations.
                       We reviewed all of these and implemented
           the effects of power uprate in all of these areas. 
           The area that was most impacted by power uprate were
           the operator responses.
                       For the operator response considerations,
           we did review the operator responses credited in the
           Level 1, core damage frequency considerations.  To
           quantify the impacts of power uprate on those we ran
           a CENTS analysis for various sequences.
                       The CENTS code is a Westinghouse code used
           to do the Chapter 15, Thermal Hydraulic Analysis. 
           When doing that analyses, we ran that code to
           determine the time to core uncovery.  And we did a
           comparable run both at current power rating and at
           uprated conditions to determine the different times
           associated with each.  We then took those times, and
           we put them into the human reliability analysis to
           come up with a human error rate.
                       We took those human error rates along with
           all the other changes that were necessary with respect
           to the success criteria, initiating band frequencies,
           and the fault tree considerations.  We put those into
           a power uprated model.  We quantified both the
           pre-power uprate model and quantified the post-power
           uprate mode, came up with a delta CDF.  The delta CDF
           was 2.7E-6, which was essentially a 16 percent
           increase.  This falls within Region 2 or small change
           as defined by Reg Guide 1.174.
                       In a similar manner --  
                       MEMBER KRESS:  Is that the same number,
           that pre, that you had in your IPE?
                       MR. DAIBER:  No, it is not.  Over the
           years, we have updated the model several times, and
           this value is different than the IPE value.
                       MEMBER KRESS:  Okay.
                       MR. DAIBER:  In a similar fashion, then,
           we accounted for the effects of power uprate, and came
           up with a change in the large earlier release
           frequency, the LERF.  The delta LERF was 9.3E-8, which
           is a 24 percent increase associated with power uprate. 
           This fell within Region 3, which was a very small
           change from Reg Guide 1.174.
                       MEMBER KRESS:  That LERF is almost two
           orders of magnitude lower than your CDF.
                       MR. DAIBER:  Yes.
                       MEMBER KRESS:  Is ANO2 a large dry?
                       MR. DAIBER:  Yeah, it's typical for a
           large dry EWR.
                       MEMBER KRESS:  So that's why you get that
           kind of -- 
                       MR. DAIBER:  That is correct.
                       As I mentioned, we also looked at the
           external event considerations-- fire, seismic
           considerations, shut-down risk considerations.  And
           when we did those assessments, we looked to see if
           there was anything unique about power uprate.  And
           doing those assessments, we determined there were no
           unique or significant insights to be gained as
           associated with the power uprate impacts on the plant.
                       So in summary, we've looked at the plant
           from -- 
                       MEMBER POWERS:  Are you changing any
           electrical equipment at the plant?
                       MR. DAIBER:  Major electrical equipment,
           no.
                       MEMBER POWERS:  No transformers are
           changed?
                       MR. DAIBER:  No.  The transformers
           themselves -- 
                       MEMBER POWERS:  No relay being changed. 
           That doesn't affect your fire?
                       MR. DAIBER:  No, not in a fire-initiating
           event frequency consideration.
                       MEMBER POWERS:  How can it not?
                       MR. DAIBER:  I'm sorry?
                       MEMBER POWERS:  How can it not?
                       MR. DAIBER:  Affect the fire frequency?
                       MEMBER POWERS:  Sure.
                       MR. DAIBER:  Mike, are you aware of the
           basis for the combustible loading considerations with
           respect to fire?
                       MR. LLOYD:  My name is Mike Lloyd.  I'm
           the ANO lead engineer in PSA area.
                       We did a separate fire analysis, and I
           don't -- that part of the analysis was done by our
           fire protection folks.  They did a fire loading.  And
           the loading itself considered those aspects of the
           plant.  I don't believe that the increase loading,
           however, was explicitly considered.  But there are
           large, I guess -- degree of conservatism in the fire
           analysis that we did perform.  We used the five
           methodologies, an EPRI method.
                       MEMBER SIEBER  I guess we're talking
           specifically about the main unit transformer.
                       MR. DAIBER:  Yes.
                       MEMBER SIEBER  That's located outside?
                       MR. LLOYD:  Right.  That is correct.
                       MEMBER SIEBER  Is that away from the
           buildings.
                       MR. LLOYD:  Yes.
                       MEMBER SIEBER  Twenty or 30 feet?
                       MR. LLOYD:  Yes.
                       MEMBER SIEBER  Do you have a dike around
           it?
                       MR. LLOYD:  I'm not -- yes, there's a dike
           around it.
                       MEMBER SIEBER  And it has water
           suppression?  Automatic water suppression?
                       MR. LLOYD:  Yes.
                       MEMBER SIEBER  Okay.  Thank you.
                       MEMBER POWERS:  Have we ever had
           transformer fires at nuclear power plants?
                       MEMBER SIEBER  Pardon?
                       MEMBER POWERS:  Have we ever had
           transformer fires at nuclear power plants?
                       MEMBER SIEBER  Yeah, I had two of them.
                       MEMBER POWERS:  I mean, it just seems
           remarkable to me that we can do an analysis that says
           we've increased the power running through the
           transformer, and we didn't change the fire frequency.
                       MEMBER SIEBER  Well, the initiation
           frequency should change because the linings are
           hotter.  The potential fault currents, as long as the
           breakers continue to be interrupted, don't explode. 
           That's usually not an issue.  But the transformers are
           located anywhere from 20 to 50 feet from the nearest
           building.  And I haven't seen -- even with major
           fires, I haven't seen it spread to the buildings. 
           They seem to get trapped in the diked area.
                       MR. DAIBER:  I would venture to say that
           that was one of the screen zones, below the 1 x 7-6.
                       MR. LLOYD:  But the impact of the fire,
           because of the exterior location of these
           transformers, would cause a loss of off-site power,
           yes.  And we did evaluate the loss off-site power in
           our analysis.  But that would be, I believe, the major
           effect of such a fire in that exterior to the plant
           location.
                       In addition, the location is very distant
           from the safety-related equipment.  It's in the aux
           building, which is quite distant from the location of
           the transformers.
                       MEMBER POWERS:  Well, saying that the only
           effect of the fire and the transformer is to increase
           the frequency of loss of off-site power is not what I
           would call heart-warming.  That's usually a fairly
           significant accident.
                       MR. LLOYD:  We evaluated that.  And I
           believe that roughly it represents about 5 percent of
           the CDF.  It's not a major single contributor.  And
           BWRs, typically this loss off-site power represents a
           much, much larger fraction of their risk.
                       MEMBER POWERS:  It tends to be plants,
           specifically.
                       MEMBER SIEBER  Typically, in a PWR, you
           have two buses fed from the system and two fed from
           the main unit.  If you blow the transformer, then you
           lose two of the four, and then they automatically
           cross-connect.
                       Is that the way your plant is -- 
                       MR. LLOYD:  Our unit has two divisions. 
           Should we lose off-site power, what would happen is we
           would use on-site diesels, one emergency diesel
           powering each of the emergency buses.  And in addition
           to that, quite distant from the transformers we have
           another unit that's a station blackout unit which was
           installed for the station blackout rule.  And it is a
           stand-alone island of power basically dependent on
           only itself for all intents of purposes.  It has its
           own DC system for starting.  It can be started from
           the control room.  It has its own air cooling system. 
           It's totally independent of service water.  So it sits
           there ready to be used from the control room.
                       MEMBER SIEBER  Okay.
                       MEMBER KRESS:  Are there two units on that
           site?
                       MR. DAIBER:  Yes.
                       MEMBER KRESS:  About the same power level?
                       MR. DAIBER:  Unit 1 is slightly lower. 
           Thermal is 2856.
                       MEMBER KRESS:  Is it the same kind of
           reactor and containment?
                       MEMBER SIEBER  No.
                       MR. DAIBER:  No.  It's 25 -- 
                       MEMBER SIEBER  It's a BMW.
                       MR. DAIBER:  BMW.
                       MEMBER KRESS:  It's a BMW.
                       MR. DAIBER:  With that, we've looked at
           the plant both from a design capability standpoint to
           make sure all the components could operate properly
           within the design criteria for the plant.  We also
           looked at it from a risk perspective and verified from
           a risk perspective the plant and their operating
           conditions were acceptable.
                       With that, I'd like to turn it over to
           Craig Anderson for concluding remarks.
                       CHAIRMAN APOSTOLAKIS:  Is the staff going
           to make a presentation, Jack?
                       MEMBER SIEBER  Yes.
                       MR. ANDERSON:  All right.  Let me start
           off by thanking this committee for your time this
           afternoon.  I'd just like to close by saying, our 
           focus has been throughout this project -- as it should
           be -- in keeping the plant safe and reliable.  And
           through analysis, through modifications, through
           training, we believe that we've done that.
                       Our plant, and our equipment, and our
           people are ready for the power uprate.  And if there's
           not any additional questions, that concludes our
           portion of the presentation.
                       MEMBER SIEBER  Okay.  Well, I thank you
           and your staff and Entergy for putting together a good
           presentation that we can understand.  And it appears
           to me like you have done a lot of work to get this
           unit ready to run at a higher -- 
                       MR. ANDERSON:  Yes, sir.
                       MEMBER SIEBER  Thank you very much.
                       MR. ANDERSON:  Thank you.
                       MEMBER SIEBER  What we'd like to do now is
           have the NRC staff come forward.  And as they get set
           up for their portion of the presentation, which will
           discuss the Safety Evaluation Report, I would like to
           introduce to you someone we haven't seen for several
           hours, which is John Zwolinsky, who seems to show up
           for every operation.
                       MEMBER POWERS:  He just can't stay away. 
           We're so kind to him that -- 
                       MEMBER SIEBER  So when you folks are all
           set, you can begin.
                       MR. ZWOLINSKY:  Give us just a couple
           minutes.  Thank you.
                       MEMBER SIEBER  All right.  No problem.
                       MR. ZWOLINSKY:  Can I get started?
                       MEMBER SIEBER  Yes.
                       MR. ZWOLINSKY:  Great.
                       Good afternoon.  To those of you that
           don't recall who I am, I'm John Zwolinsky, director of
           Division of Licensing Project Management in NRR. 
           Joining me today are our management team and
           first-line supervisors that have overseen the review
           of the Arkansas power uprate.  I'd like to take a
           minute to identify those folks.  They're here in
           support of our staff.  And, certainly, we have a large
           number of staff here to answer any of the questions
           that may go beyond the agenda.
                       I'd first like to recognize Ms. Suzanne
           Black, our deputy director for the Division of Safety
           and Systems Analysis; Richard Barrett, our branch
           chief in the PRA Branch; Stu Richards, our project
           director for PD4.
                       We have a number of our section chiefs,
           our first-line supervisors.  Bob Graham out of PD4.  
           Frank Akstulewicz of Reactor Systems Branch will be
           making a presentation; Ralph Gruso of Reactor Systems;
           Kamal Manoly of Mechanical Branch; Brian Thomas from
           Plant Systems; Matt Mitchell from our Materials
           Branch; Corney Holden from our Electrical and
           Instrumentation Control Systems Branch; Louise Lund
           from our Materials Group; Mark Rubin from our PRA
           Group, at the table.
                       I feel it's important to ask the staff to
           join me for meetings such as this.  We place high
           emphasis on bringing these to closure.  And as you
           know, the Commission has placed a high degree of
           importance on power uprates in general, and I
           appreciate our staff being here with me.
                       The staff is here to present its review of
           the 7.5 percent power uprate for the Arkansas
           Nuclear 1 Unit 2 plant.  The staff made a presentation
           on this review to the subcommittee on thermal
           hydraulic phenomena on February 13, 2002.
                       The ANO2 uprate is the largest extended
           power uprate for PWR we have reviewed to date.  The
           staff has conducted a thorough review of the Arkansas
           plant, focusing on safety.  Reviews were conducted
           consistent with existing practices, which include the
           license arm from Main Yankee.
                       We used the Farley power uprate as a
           template for this particular review; that is, all the
           sections of Farley dictated the sections that we would
           review here.  Scope and depth were driven to some
           extent by our standard review plan for various
           sections.  We'll talk about that in greater detail
           throughout the presentations.
                       All areas affected by the power uprate
           were reviewed by the staff.  The staff has critically
           examined the methodologies in their application for
           these power uprate requests, and concluded that the
           analytical codes and methodologies used for licensing
           analysis are acceptable for these applications.
                       Without further ado, I'd like to turn it
           over to Tom Alexion.  Tom is our project manager for
           this plant and has shepherded this entire project from
           beginning to end.
                       Go ahead and get going, Tom.
                       MR. ALEXION:  Thank you, John.
                       Good afternoon.  I'm Tom Alexion.  And I'm
           the NRC project manager assigned to Arkansas.
                       By way of background, the 7.5 percent
           power uprate application by Entergy represents the
           largest PWR uprate to date, as you heard earlier.  The
           highest PWR power uprate previously approved was
           5 percent.
                       Some background into the CE designed PWR. 
           The architect engineer and constructor were BECHTEL. 
           The full power license was issued on September 1,
           1978.  And the current license maximum reactor core
           power level is 2815 megawatts thermal.  And it to has
           a large dry containment.
                       The steam generator was replaced in the
           fall of 2000.  Some of the differences between the old
           and new steam generators are shown in this slide.  The
           licensee designed the replacement steam generators to
           accommodate the increase in reactor power.
                       I would also like to note that when we're
           doing the power uprate application, the NRR staff
           relied upon analysis previously done at the uprated
           power in support of steam generator replacement.  And
           this is in the fall of 2000.
                       The NRR staff used the following power
           uprate as a guide for the scope and depth of its
           review.  To further review guidance, the standard
           review plan is utilized.  The staff have used their
           licensee's application of codes and methodologies to
           ensure that they are used within the appropriate
           restrictions and limitations, and to ensure they're
           appropriate at the higher power level.  During the
           course of the review, the staff issued many requests
           for additional information.  The licensees responded
           to all of them.
                       For the containment, the staff had a
           contractor perform independent calculations of the
           pre-containment pressures and temperatures following
           a postulated LOCA and main steamline break.  In the
           area of vessel materials, the staff performed
           independent calculations of the pressurized thermal
           shock reference temperature and end-of-life upper
           shelf energy for each reactor pressure vessel
           material, and performed independent calculations on
           the susceptibility to vessel-head penetration
           cracking.
                       In the area of dose assessment, the staff
           performed independent calculations of the atmospheric
           dispersion for the exclusionary boundary and low
           population zone, and the dose assessments for the
           LOCA, steam generator tube rupture, CEA ejection, and
           fuel-handling accidents.
                       In the area of risk assessment, the staff
           audited the licensees risk evaluation for power
           uprate, which included manipulating various parameter
           in the human reliability analysis spreadsheet, and did
           an independent calculation to gain a perspective of
           the seismic risk.
                       The principal areas of review are the NSSS
           and accident analyses, evaluation of structure,
           systems and components, BOP systems, human factors,
           radiological analyses, and risk assessment.
                       But for today, the order of presentation
           is as shown.  We plan to present these four areas. 
           And we're also going to show -- we have some examples
           where the staff focused this review.
                       When they were issued the draft safety
           evaluation, the only open items were in the
           radiological assessment area.  But these items have
           been resolved.  So, therefore, the NRR staff has no
           open items.
                       And with that, those are my opening
           remarks.  We can move to reactor systems, unless there
           are any questions.
                       MR. ZWOLINSKY:  Frank Akstulewicz is our
           section chief responsible for this area.  Chu Li Yang
           is senior staff reviewer.
                       MR. AKSTULEWICZ:  Thank you.  My name is
           Frank Akstulewicz.  I'm the section chief in the PWR
           section of reactor systems.  And to my right is Chu li
           Yang, who is the lead reviewer for this particular
           power uprate.
                       What I'd like to do is jump to Slide 2. 
           Slide 2 identifies in general terms the areas of
           review that we focused on, and I'd like to make a few
           remarks about each of the bullets.
                       The first bullet specifically looked at
           the design operating characteristics and requirements
           for reactor coolant system ECCS and shut-down systems. 
           And as you've heard today, there were very few
           modifications, if any, other than the steam
           generators, to these systems in order to support the
           power uprate.  So our effort here principally was
           examining what the operating requirements were,
           verifying that the analyses supported those operating
           requirements, and confirming that the analysis was
           done using acceptable methods.
                       The second area, fuel system design. 
           Again, this particular power uprate does not use a new
           or different fuel type.  It's the standard CE 16 x 16
           array.  The only thing different here is the poison. 
           In this particular case, you've heard the licensee
           that particular effort.  Thermohydraulically, it's no
           different than anything else that's used in other CE
           plants of higher power level.  And analytically, we've
           done a number of accident evaluations using this fuel
           and have found no problems.
                       The last area, the LOCA and transient
           area, again, principally here we look at the specific
           initial conditions and assumptions used to assess the
           accidents.  We look to make sure that the codes that
           are being used to assess those accidents are
           appropriate for application, and whatever the terms
           and restrictions are in those codes have been
           satisfactorily either resolved or complied with.  Then
           we look at the results to make sure that from our
           experience and familiarity with how these transients
           should occur, whether the results are anomalous or
           not.  And depending on the outcome there, we either
           pursue further information from the licensees or we
           verify that it satisfies the acceptance criteria
           that's established for that particular transient, and
           approve the safety evaluation.
                       The two examples on the bottom will be
           more specific as two the actual nature of the review
           and some example -- maybe to the level of detail that
           we went into some of the assessments.
                       So with that, Chu will take over.
                       MR. YANG:  My name is Chu Li Yang.  I'm
           the reviewer for the Arkansas Unit 2 Power Uprate. 
           And I'm going to discuss the staff review of feedwater
           line break and LSS performed by the licensee to
           support its power uprate. 
                       As a part of power uprate, the licensee
           revised it's feedwater line break and LSS methodology. 
           This slide presents some of the changes to the
           methodology and initial conditions and assumptions to
           perform it's power uprate reanalysis.  However, the
           principal changes to the methodology
           involves -- proposed the use of low-level water trips
           at point associated with affected steam generator in
           their new analysis.  And the previous low-level
           analysis -- low level trip of in tact steam generators
           was used instead of the affected steam generators.
                       And this methodology calculates the
           limiting feedwater break size by concurrent high
           pressurizer, pressure trip and the low steam
           generator -- what level trip affects the steam
           generator in the new analysis.
                       The change of the methodology slight
           resulted in a reduction in margin.  And also, the
           reanalysis assumed uprated power level.  The changes
           also in the areas of initial conditions and
           assumptions, such as a high initial pressurizer
           larger, in mill steam safety of tolerance and early
           mill steam isolation.  And those conservative
           assumptions were added to provide safety margin in the
           new analysis.
                       For review of changes in methodology, we
           accept everything of the changes and will be discussed
           next.
                       The acceptability of the revised
           methodology used in the new feedwater line break
           analysis is reviewed in the following steps.
                       First we consult INC staff regarding
           accuracy of the low-level trip set point on affected
           steam generator in the new analysis.  INC staff
           concludes that the instrumentation of certainty
           calculations were acceptable for this application. 
           Also, we look at the documentation for the NOTRUMP
           computer code, and find that the code was initially
           reviewed with ability to evaluate the steam generator
           water level behavior and stability and damping
           predictions during feedwater line break dynamic
           conditions.  And the staff concluded, NOTRUMP is
           acceptable for those specific areas of calculation. 
           And inputs found in NOTRUMP computer code from the
           simulator steam generator -- and provide input to
           system transient code for primary system response
           simulation.
                       Finally, the approach used to taking
           credit for low-level trip affected steam generator is
           currently used in Westinghouse plants.  And this
           approach has been approved in WCAP-9230 for
           Westinghouse steam generators.  And based on those
           facts, we conclude that the approach of new level
           water trip in affected steam generator to giving
           credit for feedwater line break is acceptable for ANO
           Unit 2.
                       We would like to discuss the impact of the
           revised methodology.
                       The first bullet of this slide lists the
           major impacts found in the revised methodology.  In
           the new analysis, the licensee indicated that the
           limited break size is slightly reduced from
           approximately .17 square feet to approximately
           .15 square feet.  And the reactor trip react early
           during the transient.  In the steam generator, the
           water inventory is increased at the time of the
           reactor trip.  And those changes result in slightly a
           reduction in margin.  But the calculated peak
           transient primary and secondary pressures are slightly
           reduced.  It's reduced to 2647 PSIA, and the previous
           analysis was 50 points higher.
                       The result of this analysis met all
           acceptance criteria specified in the SRP.  And the
           peak primary and secondary pressures remained below
           10 percent of the line pressure.  The pressure lines
           would not go solid, and the DMB is not a concern for
           this event.
                       Next, we'd like to discuss the staff
           review of control or the withdrawal from subcritical
           conditions.  This event is classified as AOO.  And the
           staff acceptance criteria for this event does not
           allow fuel damage.  The safety limit in existing text
           specs is the peak linear hit rate limit, less than
           21 kilowatts per foot.
                       The licensee's power uprate analysis shows
           the transient linear hit rate approximately
           40 kilowatts per feet, which is about the existing
           text specs.  However, the impact of this high linear
           hit rate limit is very limited by a short transient
           duration of less than two seconds.  And the calculated
           peak fuel center line temperature is approximately
           2800 degrees.  And the results of the analysis shows
           all SRP acceptance criteria are satisfied with respect
           to fuel performance, fuel pressure and fuel center
           line temperature.  And the licensee has revised the
           text specs to remove linear hit rate limit and include
           a fuel center line temperature limit value adjusted
           for fuel burn, which is roughly -- 
                       MEMBER POWERS:  Would you say that again,
           please?
                       MR. YANG:  The text specs have been
           revised.   And the existing text specs, the linear hit
           rate limit is eliminated, and instead, the fuel center
           line temperature is defined as a limit for this event. 
           It's consistent with SRP.
                       MEMBER POWERS:  How does it change with
           burn up?
                       MR. YANG:  It's adjusted for fuel burn up.
                       MR. AKSTULEWICZ:  The fuel
           adjustment -- the temperature is actually decreased
           with burn up.  It declines -- I think -- well, there's
           a proprietary restriction on actual number for CE. 
           But I can say that for Westinghouse plants, it's
           approximately 50 degrees per 10,000 megawatt days per
           ton.
                       MEMBER POWERS:  Why do we think that's an
           adequate thing?
                       MR. AKSTULEWICZ:  It defines the point at
           which the fuel centerline actually will begin to melt
           for this particular -- for these kind of power
           insertion events.  It's a calculated value that's part
           of the design basis.
                       MEMBER POWERS:  How do they calculate the
           melting point of the fuel?
                       MR. AKSTULEWICZ:  It looks at the rate of
           reactivity insertion and the energy deposition within
           the fuel itself, and then does a temperature
           calculation, looks at the heat up of the fuel.
                       MEMBER POWERS:  Yeah.  But when does it
           melt?  I mean, how do we know when it melts?
                       MR. AKSTULEWICZ:  The -- it's assumed to
           melt when it reaches a certain temperature.  And that
           temperature is based on experimental data that the
           fuel vendors have.
                       MEMBER BONACA:  This is a bank withdrawal,
           right?  Not a single rod.
                       MR. AKSTULEWICZ:  No, this is single rod
           withdrawal.
                       MEMBER BONACA:  A single rod.
                       MEMBER SIEBER  You mean a single rod out
           of its bank configuration, right?
                       MR. AKSTULEWICZ:  Yes.  This is a single
           rod being looped.
                       MEMBER SIEBER  Otherwise, you can't
           go -- a single rod by itself won't do anything.
                       MR. AKSTULEWICZ:  That's correct.
                       MR. ALEXION:  Okay.  If there's no further
           questions, we'll move on to the plant systems branch
           with Dave Cullison and Rich Lobel.
                       MR. CULLISON:  Good afternoon.  I'm Dave
           Cullison from Plant Systems Branch.  With me is Rich
           Lobel also from the Plant Systems Branch.  I perform
           the majority of the reviews of the power uprate.  Rich
           did the containment reviews that were done as part of
           the replacement steam generator and containment uprate
           of the project.
                       My two slides I want to discuss just show
           the SRP sections we used in the performance, we used
           as guidance for completeness and accuracy.  We
           determined in all our reviews that there's no
           significant impact on the system operations through
           the power uprate.  And this is just the continuation
           slide.
                       Rich is going to discuss the independent
           confirmatory analysis done for the containment
           response to the power uprate.
                       MR. LOBEL:  Richard Lobel from Plant
           Systems Branch.  As part of the replacement steam
           generator review, we contracted with Los Alamos
           National Laboratory to do a
           calculation -- confirmatory analysis of the
           calculations done by the licensee for the peak
           temperature and pressure for both a LOCA and a
           steamline break.  They used the MELCOR code to do the
           calculation. But it was a designed basis calculation,
           so it didn't really exercise most of the models in
           MELCOR.
                       The analysis looked at, like I say, both
           the LOCA and the steamline break, and in general
           agreed with the licensee's analysis.  The one area
           where there was a large discrepancy between the
           analysis was in the case of the steamline break, the
           licensee calculated a much more conservative
           temperature than we did.  And after discussing it with
           the licensee, the licensee suggested that it might be
           an assumption they made for containment spray.  They
           assumed a very low efficiency, very low heat transfer
           from the atmosphere to the spray.  And MELCOR used
           pretty much a physical model of the spray.  We went
           back and adjusted the spray model and got fairly good
           agreement with the licensee's calculations.
                       When I talked to the subcommittee, I said
           that the report on this was available in ADAMS, and
           everybody laughed.  So let me just say now that it's
           in ADAMS.
                       That's all I have, unless there's any
           questions.
                       MR. ALEXION:  Okay.  We'll move on to the
           Materials and Chemical Engineering Branch, and Barry
           Elliott will be the presenter.
                       MEMBER SIEBER  Before we get to that, I'd
           like to ask what the ultimate heat sync is at -- is it
           a lake or river or -- 
                       MR. CULLISON:  They have two.  They have
           a pond, which is their -- and they also have the
           Dardinel Reservoir.
                       MEMBER SIEBER  Okay.
                       MR. CULLISON:  The one with -- that Rich
           reviewed, ultimately heat sync evaluations as far as
           steam generator replacement in the pond.
                       MEMBER SIEBER  Okay.  Thank you.
                       MR. ELLIOTT:  I'm Barry Elliott with
           Materials and Chemical Engineering Branch.  This slide
           shows all the areas within our branch that we review. 
           The first six items I'm not going to go over today. 
           I'm going to go over the last three, which I think are
           the most significant, which is the reactor vessel
           integrity, steam generator tube integrity, and the
           Alloy 600 Program.
                       Before I go on, are there any questions
           about the first six items?  No.
                       The Alloy 600 Program is intended to take
           the primary water stress corrosion cracking of
           Alloy 600 and Alloy 182 wells and the reactor pool and
           piping, the pressurizer and vessel head penetrations. 
           Cracking in vessel head penetrations were the subject
           in NRC Bulletin 2000 and '01.  PWRs were ranked by
           their MRP, according to the operating time and
           temperature, and effective full power years required
           for the plant to reach the effective time and
           temperature corresponding to the Oconee 2 event, where
           they had crackings -- circumferential cracking in
           their Alloy 600 head penetrations.
                       Plants with high susceptibility to primary
           water stress corrosion cracking are those which are
           predicted to have a ranking of less than five
           effective full power years from the Oconee 3
           condition.  Plants with a moderate susceptibility to
           primary water stress corrosion cracking are those
           which are predicted to have a ranking of more than
           five effective full power years and less than 30 full
           power years from the Oconee 3 condition.  Depending on
           which ranking you are determines which inspection
           program you're involved in.
                       In the case ANO2, before the uprate, they
           were in the moderate category, and after the uprate,
           they're still in that category.  The uprate increases
           the T-hot temperature from 604 to 609.  Increase in
           T-hot will not substantially increase primary water
           stress corrosion initiation and growth rate; however,
           it does affect the ranking somewhat.
                       Potential for primary water stress
           corrosion cracking developing in Alloy 600 nozzles
           will not be significantly affected by the power
           uprate, and, therefore, there is no change in the
           Alloy 600 and the vessel head penetration inspection
           program as a result of the power uprate.
                       MEMBER POWERS:  Somehow this uprate will
           increase T-hot form 604 to 609, and then say that
           won't increase the primary water stress corrosion
           cracking initiation and growth rate didn't strike me
           as quite what you mean here.
                       Don't you mean that, though they have a
           T-hot going from 604 to 609, that's not what the
           temperatures of the head -- 
                       MR. ELLIOTT:  There's two issues here. 
           There's a head issue, and then there's a piping issue.
                       MEMBER SIEBER  They're different.
                       MR. ELLIOTT:  The intent of that lip was
           the piping and pressurizer issue.
                       MEMBER POWERS:  Oh, okay.
                       MR. ELLIOTT:  The head is -- it has a
           lower temperature than the head -- than the piping and
           the pressurizer.
                       MEMBER FORD:  I've got no quarrel at all
           with what you put down there, except that it is, as
           Dana intimated, fairly qualitative.  And although
           you're quite right, it still remains in the moderate
           range, that temperature time, erraneous type metric
           that is being used is pretty rough.  The times are
           still fairly short in absolute terms -- 5, 15
           years -- compared with license-renewal time schedules.
                       During your thought on this -- during your
           analyses of this -- was there any quantification along
           these lines?
                       MR. ELLIOTT:  Well, the quantification
           is -- the purpose of the Bulletin 2000 and '01 is to
           determine the inspections that are going to be
           occurring at the next refueling outage.
                       MEMBER FORD:  Correct.
                       MR. ELLIOTT:  So the whole point of it is,
           is to get how susceptible your plant was to decipher
           cracking.  If you were very susceptible, then you had
           to do some more inspection.  And it was just -- based
           upon the models that were developed as part of the
           MRP, you were put into different categories.  And that
           was the intent, to determine what kind of inspection
           is required at the next refueling outage.  The model
           itself was developed from data of material crack
           growth.
                       MEMBER FORD:  Yeah.  But pretty well,
           every plant which is in the first category has, in
           fact, shown cracking.
                       MR. ELLIOTT:  Right.
                       MEMBER FORD:  So can we expect cracking on
           this plant within the next three years?
                       MR. ELLIOTT:  Well, according to our
           model, it won't be.
                       MEMBER SHACK:  Well, we have cracking at
           Millstone, right, at 14 years.
                       MEMBER FORD:  Right.
                       MR. ELLIOTT:  It could.  I mean -- when
           they do the inspection -- 
                       MEMBER SHACK:  But they're going to do the
           inspection.
                       MR. ELLIOTT:  -- we'll find out.  They're
           going to do a volumetric inspection, which should be
           able to detect these cracks.
                       MEMBER FORD:  As part of a process, I'm
           asking, this plant will crack.  And it will crack
           before the end of its life.
                       During your reasoning, does that come at
           all into your arguments?
                       MR. ELLIOTT:  You mean that the plant will
           eventually crack?
                       MEMBER FORD:  Yeah.  I mean, is it a thing
           that comes into your -- 
                       MR. ELLIOTT:  I think the issue is -- as
           you say, it will eventually crack -- 
                       MEMBER FORD:  Sure.
                       MR. ELLIOTT:  -- and it will crack before
           the end of 40 years probably.  But that becomes -- as
           long as we have an inspection program that is capable
           of detecting the cracks before they become critical
           and affects the integrity of the reactor coolant
           system, that's all we're looking for.  We're looking
           to make sure that's there.
                       MEMBER FORD:  But that important fact is
           not set out there.  And that's reassuring, your saying
           that.  Again, for the public confidence aspect, it's
           useful to have that enunciated.
                       MR. ELLIOTT:  Well, we're relying on an
           inspection program to detecting these cracks before
           they become critical.
                       MEMBER FORD:  Right.
                       MR. ELLIOTT:  And that's what the model is
           intended to do, to lay out what we suspect to be the
           worst plants, and that they need more inspection than
           the less susceptible.
                       However, this plant, even though they're
           in the moderate category, is still doing a volumetric,
           which is very good.
                       The next slide deals with reactor vessel
           integrity.  Just a quick background for you who are
           not knowledgeable.
                       10 CFR 50 establishes a Scharpey
           upper-shelf screening criteria.  And 10 CFR 50.61
           establishes RTpts screening criteria for pressurized
           thermal shock.
                       The licensee has made evaluations of the
           upper-shelf energy and the RTpts values, and they're
           done in accordance to Reg Guide 1.99, Rev 2.  For this
           plant, the materials have a low rate of brittlement. 
           The upper-shelf energy is predicted to drop even with
           a power uprate of only 60 foot pounds.  And the RTpts
           value is around 120 only, which is 150 degrees below
           the screening criteria in the pts rule.
                       The staff reviewed these calculations.  I
           want to point out also, we also reviewed in the
           previous slide the Alloy 600.  We did our own
           susceptibility calculations.
                       We did the calculations here for the
           upper-shelf energy and the RTpts values.  In addition,
           Appendix G requires pressure temperature limits.  And
           from those pressure temperature limits, low
           temperature over-pressure set points are determined. 
           These limits in set points were provided in a separate
           application and are being reviewed by the staff to
           ensure that they meet all regulatory requirements. 
           Based on these analyses, the reactor vessel meets all
           regulatory requirements.
                       As far as steam generator integrity, the
           Alloy 690 tubes are more resistant to stress corrosion
           cracking than the Alloy 600 tubes.  Degradation of
           tubes resulting from the deposition of copper was
           eliminated by removing copper from the secondary side. 
           We've done analysis of vibration or frequency
           responses of antivibration bars, minimized wear.  Reg
           Guide 1.121 analyses were performed to ensure
           structural integrity.  And based upon this analysis
           and the changes in the system, there is no change in
           the tube inspection program required at this time.
                       That completes my presentation today.
                       MR. ZWOLINSKY:  Thank you, Barry.
                       MEMBER POWERS:  When you say there's no
           need to change the tube inspection program, you mean
           that there's no need to increase it, right?  That's
           all you looked at.
                       MR. ELLIOTT:  I -- 
                       MEMBER POWERS:  You need to look at the
           possibility -- 
                       MR. ELLIOTT:  The inspection program is a
           text spec item, and is a certain program they have to
           follow.  This will not change that.
                       MS. LUND:  Right.
                       MEMBER POWERS:  You didn't look at the
           possibility that they could increase or decrease their
           inspection.
                       MS. LUND:  It wasn't considered under just
           the power uprate situation.  We're evaluating that
           separately under the NEI-97-06.  And we're still -- as
           you know, we're still evaluating that.
                       MEMBER POWERS:  Okay.
                       MR. BOEHNERT:  Can you identify yourself
           for the record, please?
                       MS. LUND:  Oh, I'm sorry.  It's Louise
           Lund of Component Integrity and Chemical Engineering
           section.
                       MR. BOEHNERT:  Thank you.
                       MR. ZWOLINSKY:  If I might play off your
           interest in the bulletin that Barry alluded to.  We
           continue to receive information from licensees
           conducting inspections.  They are finding cracks.  And
           our challenge going forward are our next steps.  And
           this program matures over the next couple of
           years -- you're probably aware, many licensees have
           committed to head replacements.  And the concept or
           thought of inspecting at every cycle seems to be not
           the best answer.  So we still have our challenges
           before us.  But as we go forward through the spring
           outages, it may be appropriate to come back to the
           committee and give you a status report essentially one
           year later, so to speak, with the fall outages having
           taken place.
                       MEMBER POWERS:  An issue I'd like to know
           more about is what is the risk importance described in
           the vessel head.
                       MR. ZWOLINSKY:  The vessel head or the
           independent CRDMs?
                       MEMBER POWERS:  Either one or both.
                       MR. ZWOLINSKY:  Part of the basis of the
           bulletin when it was developed was the lost of one of
           the CRDMs.
                       MEMBER POWERS:  Yeah, I understand the
           bulletin.  I guess I'm asking the probablists in this,
           if I tried to guide a risk importance parameter for
           the vessel head -- who are the CRDMs housings from a
           PRA -- what number would I get?
                       MR. BARRETT:  This is Richard Barrett. 
           I'm with NRR staff.
                       We have been looking at this question of
           the risk significance of the CRDM cracking issue.  And
           clearly there are two important questions.  One is,
           for any given situation, for any given head at any
           given time, what's the probability that it would
           result in a LOCA.  And I think we're talking about a
           medium LOCA.  And then the second question is what is
           the conditional probability that that LOCA would then
           lead to a core damage accident, and then possibly only
           to a LERF, large early release.
                       The second part of the equation is the
           easier part.  You can look that up in most PRAs, and
           it's of the order of conditional probabilities of 1 in
           1,000.  The first part, however, is much more
           difficult to assess.  And it has to do with your
           perceptions as to the initial conditions of the head,
           of a particular CRDM, in terms of the probability that
           a crack exists, the size of the crack, the depth of
           the crack, and then the crack growth rate.  And the
           type of analysis that is required is not that
           different from the kind of analyses that we've been
           talking about in the context of 97-06 for the steam
           generator tubes.
                       In the fall of this year, we went through
           a lot of what I'll call qualitative analysis in trying
           to resolve -- make our regulatory decisions with
           regard to the operation of the high susceptibility
           plants, and proposals that were made by various
           licensees as to the schedule for when they wanted to
           shut down.
                       But I think as we go forward, we need to
           get a better handle on this.  And we're working with
           our Office of Research who are developing and refining
           models for crack initiation, crack growth, and how
           that relates to the probability of a catastrophic
           failure.  It's not an easy question to answer, but
           we're working on it.
                       MEMBER POWERS:  Good.
                       MR. ZWOLINSKY:  Okay.
                       MR. HARRISON:  Good afternoon.  I'm Donny
           Harrison.  I was the lead for the PRA part of the
           review.
                       We can just move to the second slide. 
           This slide just identifies the -- I think you've heard
           this before a number of different times, primarily
           with BWRs, but we look at the internal events,
           external events, shut-down operations.  And we look do
           a look at their PRA quality.  We do that to see if
           there's any insights and just to confirm that there's
           no new vulnerabilities being created as part of a
           power uprate.
                       MEMBER POWERS:  Let me ask you what the
           significance of looking at the IPEs and the IEEEs for
           this plant is.  The previous speaker told us that he
           modified his plant, and PRA all over the place.  So
           why would you bother to look at the IPE?
                       MR. HARRISON:  Often times you'll see in
           IPE and IPEEE either a statement -- an example of that
           would be the seismic area for Arkansas.  They do a
           seismic margins analysis.  In the process of doing
           that analysis they make assumptions that they've fixed
           things.  We come back, and I take a look at that, and
           I then send a request for additional information to
           the licensee and say, did you fix it?
                       The thing we found out at Dresden was, in
           one area, no.  That's worth knowing.  For Arkansas,
           the answer was yes.  Everything we took credit for
           that we used in that analysis we've now fixed, and we
           fixed it the way we said we were going to fix it.  And
           it meets the assumptions of the IPEEE, so it gives you
           really some confidence that the IPEEE now actually
           reflects the plant that's there.
                       MEMBER POWERS:  But here we know that the
           IPE does not reflect the plant that's there.
                       MR. HARRISON:  Right.  The IPE even still
           may say during a technical evaluation, the staff found
           weaknesses in initiating event frequencies.  I think
           one of the comments that was made on Clinton was that
           it was a new plant, and they didn't have a whole lot
           of plant-specific data.  So you can look and see what
           has the plant done in response to what the IPE or
           IPEEE found.
                       In a way, it's kind of a way to check to
           make sure that plants are improving their analysis and
           not just using the same old analysis and staying with
           it, not changing.
                       CHAIRMAN APOSTOLAKIS:  You said the magic
           words, improving the analysis.  I think -- I mean, you
           are not responsible for people's models and so on. 
           But, unfortunately, your silence may be misunderstood.
                       I see here in Section 8 a fairly detailed
           analysis of the operator actions that affect it.  And
           that's the safety evaluation.
                       MR. HARRISON:  Right.
                       CHAIRMAN APOSTOLAKIS:  And the licensee
           says that they used three EPRI reports to come up with
           human error probabilities.  And you have a table here
           where, for example, for failure to reenergize such and
           such and such from SD2, the pre-power uprate available
           time was 42 minutes, and the HEP was .19, and the
           post-power uprate available time was 39
           minutes -- three minutes down -- and the HEP was
           2.9 x 10-1.  And then you go on and have a very nice
           discussion of how you really wanted to make sure that
           there were no other operator actions that were left
           out and not evaluated, and I think that's very good. 
           The thing that bothers me, though, is that I don't
           think there is a model anywhere in the world that can
           tell the difference between 42 minutes and 39 minutes
           and produce a number like 2.9 x 10-1.
                       Now you are very carefully here saying,
           the staff finds, based on the information provided by
           the licensee and the staff site review, that the
           licensee's human reliability analysis application is
           consistent with their identified methodologies-- a
           beautiful statement.  It says nothing.  Right?
                       But then you go on and say, and that the
           assumed increases in the HEP values for the identified
           operator actions reasonably reflect the reductions in
           the times available for the operators to perform the
           necessary actions.
                       Now, I don't know how you've gotten it. 
           I suspect you're right.  But you didn't get it from
           the EPRI methodologies.  Now, a minor reduction in
           time tells me that the performance of the operators
           are expected to be more or less the same as it was
           before.  But to say in a table that the number went
           from 1.9 x 10-1 to 2.9 x 10-1, I mean, is an illusion.
                       MR. HARRISON:  Right.
                       CHAIRMAN APOSTOLAKIS:  And I would expect
           you to say that this methodology -- I mean, find nice
           words -- that these methodologies are not widely
           acceptable; they have not been approved by the NRC. 
           You know, something to that effect.  Because, frankly,
           they are not widely acceptable.  That's why this
           agency has spent a lot of money trying to develop
           ATHENA.  That's why the French are spending a lot of
           money developing MERMOS, the Fins are spending a lot
           of money developing something else.  If EPRI had done
           it, we wouldn't be doing this. 
                       So I think your silence on this may be
           misconstrued by other people.  Now, I realize it is
           not your job to evaluate human reliability models, but
           you should not accept uncritically results such as
           this one.
                       Now your sentence here is really
           beautiful, but I would expect it to say something more
           than that.  The fact that something is consistent with
           some methodology, the numbers, I mean, what does that
           tell me?  Not much.  Although, the ultimate
           conclusion -- I mean, this is the day where the
           conclusions seem to be reasonable, but the models that
           led to them are terrible.  Not terrible.  Not
           terrible.  You know, they're still in evolution.
                       I think your conclusion is okay, that the
           times probably are not affected that much, and the
           human error probabilities are probably the same as
           they were before.  But to go ahead and produce a delta
           CDF of 3 x 10-6, I just don't believe that.  If the
           major input of this calculation is these human error
           probabilities, I don't believe it.
                       Now, is it much larger than that?  I don't
           believe that either.  Should you deny their request? 
           Based on this, no.  I'm not saying that either.  Okay? 
           And what perplexes me is that this is not a
           risk-informed application.  So whatever you're
           presenting here really does nothing, does it?
                       But I just can't let it go.  This is a
           difficult situation here.  I don't think the licensee
           should be penalized for this.  But, you know -- 
                       MR. HARRISON:  I'm glad you bring it up. 
           Because just as an analyst, I get concerned when we
           focus too much on the numbers, and we don't sit back
           and say what did the plant learn from all this.  If
           we're just focused on did the number go from .1 to
           .2 -- 
                       CHAIRMAN APOSTOLAKIS:  Well, if you had
           written it that way, I would be much happier.  Because
           I really appreciate the difficulty that you're in. 
           Your job is not to evaluate at-risk models or whoever
           models.  But if somebody says, I used these models,
           and here are my numbers, and you say nothing, then, I
           mean, we have a problem there.
                       MEMBER KRESS:  But 1.174 says you have to
           come up with a number.
                       CHAIRMAN APOSTOLAKIS:  Well, I'm sorry. 
           But that's not the number.
                       MEMBER KRESS:  How would you have come up
           with a number is my question.
                       CHAIRMAN APOSTOLAKIS:  I couldn't.  I
           mean, if you don't have a model, why should you come
           up with a number no matter what?  You just don't have
           it.  Maybe you can give a bounding value, change the
           attitude completely and say, look, I don't have model,
           but I don't think that such and such and such.  But to
           say I use this model because -- 
                       MEMBER SHACK:  But isn't that what the
           result is saying, is it didn't change all that much?
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MEMBER SHACK:  Maybe you don't believe
           either number or the notion that it didn't change all
           that much, is what you're -- 
                       MR. HARRISON:  And it becomes a relative
           decision, not an absolute.
                       CHAIRMAN APOSTOLAKIS:  But my problem is
           that, if this is not in there, the next guy will say,
           oh, they  used the EPRI methodology; that's pretty
           good.  The staff didn't say anything.
                       MEMBER SHACK:  But now you know -- 
                       CHAIRMAN APOSTOLAKIS:  What?
                       MEMBER SHACK:  Now you know why none of
           these applications are ever risk -- 
                       CHAIRMAN APOSTOLAKIS:  Why don't we just
           eliminate all the risk references?  I don't know what
           all this means.
                       MEMBER BONACA:  But it's remarkable.  You
           go from 122 minutes to 113 minutes, and they have a
           distinct difference in number.  How you figured that
           out, I don't know. 
                       CHAIRMAN APOSTOLAKIS:  Yes.
                       MR. HARRISON:  That's just an
           analytical -- it's an analytical exercise.
                       CHAIRMAN APOSTOLAKIS:  It's not use of the
           concept of model.
                       MR. HARRISON:  All right.
                       CHAIRMAN APOSTOLAKIS:  So I don't know
           what to say.  On the one hand it doesn't matter; on
           the other hand, you know, it's a document of the
           agency.
                       MEMBER KRESS:  Well, when you have a
           LERF -- 
                       CHAIRMAN APOSTOLAKIS:  Tell me.  I mean,
           why is this agency spending all this money developing
           ATHENA if one can pick up the EPRI reports and do
           this?  Why?  Because there's a different group?
                       MR. HARRISON:  We already took care of
           ATHENA.
                       CHAIRMAN APOSTOLAKIS:  I'm completely
           confused now.  I mean, we spent more than a million
           dollars.
                       MR. HARRISON:  We already took care of
           ATHENA.
                       CHAIRMAN APOSTOLAKIS:  Huh?
                       MR. HARRISON:  We already took care of
           ATHENA.
                       CHAIRMAN APOSTOLAKIS:  Because of this.
                       Anyway, you understand where I'm coming
           from.  I mean, I'm not criticizing you, because that's
           not your job.  Well, maybe a little bit I am.  Better
           words.
                       I mean, I thought this was brilliant. 
           "The licensee's human reliability analysis application
           is consistent with the identified methodologies." 
           Brilliant.
                       MR. HARRISON:  And that's about all I can
           say.
                       CHAIRMAN APOSTOLAKIS:  It sounds good, and
           it says nothing.
                       MR. HARRISON:  Okay, enough.
                       MEMBER SIEBER  Yes, why don't we move on.
                       MR. HARRISON:  Okay.
                       The bottom line, though, to answer your
           question, is as our review, the only -- if you want to
           say the only value is, is it's a negative review of
           looking for is there an issue out there that's going
           to come up on some plant down the road -- it didn't
           happen here -- that puts us into an adequate
           protection question.
                       CHAIRMAN APOSTOLAKIS:  And I think this is
           a very good point.
                       MR. HARRISON:  And at that point -- and I
           would say, if a plant like Turkey Point came in that
           did the five methodology too and got a real high
           number, and they've got a high IPE value -- I don't
           know what their PRA number is now -- we'd want to look
           at that.
                       CHAIRMAN APOSTOLAKIS:  Actually, the part
           that you did where you really questioned whether there
           were additional operator actions that the licensee did
           not address and so on, that was really nice.  That was
           really nice.  I think you did a good job there.  It's
           the quantification that bothers me.
                       MEMBER KRESS:  Well, in terms of
           quantification, the fact that the LERF, whether you
           believe the bottom-line number or not, is around 10-7,
           tells me that you've got a pretty good plant here.
                       CHAIRMAN APOSTOLAKIS:  I agree with that
           too.  Because even if you increase it by a factor of
           100 -- 
                       MEMBER KRESS:  That's right.
                       CHAIRMAN APOSTOLAKIS:  But I would much
           rather see something like that than saying, is EPRI
           such and such.
                       MEMBER KRESS:  So I didn't pay much
           attention -- 
                       CHAIRMAN APOSTOLAKIS:  Well, I am.  I am
           paying attention.
                       MR. HARRISON:  No, I appreciate the input. 
           Because, again, like I said, one of the concerns I
           have as an analyst is an overfocus on trying to get
           the precise number and worrying about did the CDF go
           up by 1 percent, when the ultimate answer is adequate
           protection, and am I up at 10-3.
                       With that, actually, I really won't bother
           to go on.
                       CHAIRMAN APOSTOLAKIS:  I'm sorry that I
           had to say all these things.
                       MR. HARRISON:  Oh, that's okay.
                       CHAIRMAN APOSTOLAKIS:  It wasn't you.
                       MR. ALEXION:  That concludes this staff's
           technical presentation.  I just have one last slide
           I'd like to show.  And that is our conclusion.  We
           felt we've done a thorough review, they're extensive. 
           We spent a lot of time on RAIs, a lot of information's
           been communicated.  We don't have any open items.  We
           feel the application meets applicable regulations. 
           And the NRR staff recommends approval of the power
           uprate application.
                       MR. ZWOLINSKY:  And I'd like to also take
           just a minute to thank the committee for this
           opportunity to present our review of the Arkansas
           extended power uprate.
                       As you've heard, the vast number of
           sections and the review areas that the staff has
           addressed and the independent analysis performed is to
           me quite impressive.  And I trust the committee finds
           it the same way.  I'd certainly recommend approval for
           this particular power uprate.  Thank you so very much.
                       MEMBER SIEBER  Thank you and members of
           your staff.  I read the SER more than once, and I
           found that it was pretty well organized, which I think
           in part is because of the existence of the Farley SER
           in the work that have been done by the applicant.  And
           it was pretty easy to read.  And I thought that it was
           important to tell us about confirmatory calculations
           and the analysis that you did so that we can
           appreciate that the SER is not a rubber stamp; that
           it's actually an independent analysis and confirmatory
           calculations.  And to us that's important.  It allows
           us to be able to see what the basis is when you say
           that this plant is satisfactory or the requested
           amendment is satisfactory.
                       So if there are no questions from the
           members at this time, Mr. Chairman, I give it back to
           you.
                       CHAIRMAN APOSTOLAKIS:  Thank you very
           much, Jack.
                       We'll recess until 3:40.
                                   (Whereupon, the foregoing matter went off
                       the record at 3:27 p.m.)
           
           
           
           
	 
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