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Joint Subcommittees on Plant Operations and Fire Protection - June 28, 2001

 

            
                Official Transcript of Proceedings

                  NUCLEAR REGULATORY COMMISSION



Title:                    Advisory Committee on Reactor Safeguards
                               Subcommittees on Plant Operation and
                               Fire Protection Joint Meeting


Docket Number:  (not applicable)



Location:                 Arlington, Texas



Date:                     Thursday, June 28, 2001







Work Order No.: NRC-298                               Pages 1-265





                   NEAL R. GROSS AND CO., INC.
                 Court Reporters and Transcribers
                  1323 Rhode Island Avenue, N.W.
                     Washington, D.C.  20005
                          (202) 234-4433                         UNITED STATES OF AMERICA
                       NUCLEAR REGULATORY COMMISSION
                                 + + + + +
                         JOINT MEETING OF THE ACRS
                     SUBCOMMITTEES ON PLANT OPERATIONS
                            AND FIRE PROTECTION
                                 + + + + +
                          THURSDAY, JUNE 28, 2001
                                 + + + + +
                             ARLINGTON, TEXAS
                                 + + + + +
                 The committee met at the Nuclear Regulatory
           Commission, 611 Ryan Plaza Drive, at 8:30 a.m., Jack
           Sieber, Chairman, presiding.
           
           COMMITTEE MEMBERS PRESENT:
           JACK SIEBER, Chairman
           GEORGE APOSTOLAKIS, Member
           DANA POWERS, Member
           GRAHAM LEITCH, Member
           ROBERT UHRIG, Member
           
           
           
           
           ALSO PRESENT:
           Dr. John Larkins, Executive Director, ACRS
           Maggalean Weston, ACRS Staff
           Howard Larson, ACRS Staff
           Isabelle Schoenfeld, EDO Staff
           Amarjit Singh
           Pat Gwynn
           Ken Brockman
           Jeff Clark
           Art Howell
           Troy Pruett
           Alberto Garcia, MIT
           Eddie Horus Texas A&M University
           Brandon Kennedy, Oklahoma Christian University
           Brian Tindle, Oklahoma Christian University
           Jeff Moreno
           
           
           
           
           
           
           
           
                                           A-G-E-N-D-A
           Opening Remarks. . . . . . . . . . . . . . . . . . 4
           Region IV Organizational . . . . . . . . . . . . .17
                 Responsibilities/Accomplishments
           Reactor Oversight Program Implementation . . . . .23
           Senior Reactor Analyst Role in Risk. . . . . . . .92
                 Assessment Significance Determination 
                 Process Implementation in Region IV
           Plant Operations
                 Experience in IV . . . . . . . . . . . . . 133
                 Scam Trends. . . . . . . . . . . . . . . . 135
                 Callaway ALARA . . . . . . . . . . . . . . 146
                 Callaway Grid Experience . . . . . . . . . 173
           Plant Experience in Region IV (Continued)
                 California Grid. . . . . . . . . . . . . . 193
                 Electrical Design and Operations . . . . . 194
                 Issues at Cooper
           Fire Protection Experience in Region IV. . . . . 210
                 SONGS Electrical Fire
           Region IV Responsibilities Under   . . . . . . . 248
                 COOP/COG
           Closing Remarks. . . . . . . . . . . . . . . . . 264
           
           
                                      P-R-O-C-E-E-D-I-N-G-S
                       CHAIRMAN SIEBER:  Good morning.  This is
           a public meeting of the ACRS and so we conduct it
           under the rules published in the Federal Register, but
           before we begin I'd like to thank Region IV
           headquarters personnel for hosting this meeting.  
                       These meetings are important to us, and
           every year we try to go to at least once licensee and
           one regional headquarters.  This is intended to be a
           two-way meeting, and we are very much interested in
           your opinions, your candid opinions about how regional
           operations are taking place, the problems that you
           have, the successes that you're having, and what you
           think the ACRS could or should do to help improve the
           regulatory system not only at headquarters but also in
           the regions.
                       So with that I would like to read our
           formal statement to begin the meetings. 
                       This is a meeting of the ACRS Joint
           Subcommittees on plant operation and fire protection. 
           I'm Jack Sieber.  I'm chairman of both subcommittees
           for plant operations and fire protections at this
           time.  The ACRS members in attendance are George
           Apostolakis, Dana Powers, Graham Leitch, and Robert
           Uhrig.  Also, Dr. Larkins, Maggalean Weston, and
           Howard Larson from the ACRS and Isabelle Schoenfeld
           from the EDO staff are present with us today.
                       The purpose of this meeting is for the
           subcommittee to discuss Region IV activities and other
           items of mutual interest, including significant
           operating events and fire protection issues.  The
           subcommittee will gather information, analyze relevant
           issues and facts, and formulate proposed positions and
           actions as appropriate for deliberation by the full
           committee.  
                       Amarjit Singh is the Cognizant ACRS staff
           engineer for this meeting.  The rules for
           participation in today's meeting have been announced
           as part of the notice of this meeting previously
           published in the Federal Register on June 11, 2001. 
           A transcript of this meeting is being kept and will be
           made available as stated in the Federal Register
           notice.  It is requested that speakers first identify
           themselves and speak with sufficient clarity and
           volume so that they may be readily heard.
                       We have received no written comments or
           requests for time to make oral statements from members
           of the public, so we will now proceed with the
           meeting.  But before we do I'd like to have each of
           the members and/or staff introduce themselves so you
           get a feel as to who we are, what we have done, and
           what our experience is.  
                       And as I said before, my name is Jack
           Sieber.  My background is basically with utilities in
           the Navy.  I worked at -- I've been in this field for
           40 years and have retired twice.  The third time is a
           charm.  Shipping port, Beaver Valley, Perry, Surry,
           North Anna 1 and LaSalle are plants that I worked at,
           and I've been two years on the ACRS.
                       George.
                       MEMBER APOSTOLAKIS:  Thank you, Jack.
                       I'm George Apostolakis, chairman of the
           committee.  I'm a professor at MIT, and the area of
           interest to me is probably risk assessment.
                       MEMBER POWERS:  I'm Dana Powers.  I guess
           I'm the old man here.  I have seven years on the ACRS. 
           I was formerly chairman of the power protection
           subcommittee.  Now my current focus of interest are in
           the areas of fuel and human factors.
                       MEMBER LEITCH:  I'm Graham Leitch.  I've
           been on the ACRS for about six months, and my
           background is primarily nuclear power plant
           operations.  I was the site vice president of Limerick
           during the startup period, and later the vice
           president at Nang Yaki.
                       MEMBER UHRIG:  I'm Bob Uhrig.  I'm a
           professor at the University of Tennessee and also work
           at Oak Ridge National Laboratory.  Previously I spent
           13 years with Florida Power and Light, where I was
           vice president for advance systems and technology.
                       MR. LARKINS:  I'm John Larkins, the
           executive director for the Advisory Committee on
           Reactor Safeguards and the Advisory Committee on
           Nuclear Waste.  My responsibility is to provide
           administrative and technical support to the committee
           in addition to a bunch of other things.  
                       I know some of you -- I started as the
           project director for Region IV in NRR, so somewhat
           familiar with what you do.  I've been with the agency
           for 30 plus years and been in research, NRR,
           chairman's office, OP, so I've been around for a
           while.
                       I'd like to add to Jack's opening comments
           our appreciation for Region IV hosting this meeting. 
           I realize it takes -- it does have a resource impact
           and takes time to get prepared for these meetings, so
           we certainly appreciate it, but it is a valuable part
           of the committee's information gathering activities. 
           We hear a lot about programs being implemented in NRR
           and other parts of the agency, and it's important for
           the committee to see how these activities are actually
           being carried out in the regions and other areas.
                       One of the key requests from the
           commission this year is an assessment of the revised
           reaction oversight program, so it will be useful for
           us to hear your candid insights on that program and
           other activities. And again, we appreciate your
           hosting us here today.
                       MR. LARSON:  I'm Howard Larson.  I work
           for John Larkins so that's why I was glad he talked
           first.  I'm special assistant for the ACRS and the
           ACNW, so I work with both committees.
                       MS. SCHOENFELD:  I'm Isabelle Schoenfeld,
           16 years with NRC, four years with NRR, and 12 years
           with research, and currently I'm working as a
           coordinator -- the EDO's coordinator with ACRS and
           ACNW and the Office of Research.
                       MR. SINGH:  My name is Amarjit Singh.  I'm
           with the ACRS for the last seven years.  Prior to that
           I was NRR inspector here with Region IV.
                       MR. GWYNN:  We're proud of the fact that
           Jit helped us for quite some time in very important
           areas, including fire protection, and he continues to
           help the committee in outstanding fashion.
                       MEMBER POWERS:  If you're responsible for
           any of this training you're doing good.
                       MR. SINGH:  Thank you, Pat.
                       MS. WESTON:  I'm Maggalean Weston, senior
           staff engineer for ACRS and responsible for the plant
           operations subcommittee where I have South Texas
           Project and the reactor oversight process.  I'm
           formerly with the tech specs branch and technical
           assistance to the director of NRR.
                       MR. GWYNN:  Chairman Sieber, would you
           desire for us to provide background information about
           our employees that are going to present?  They are
           just introductions.
                       CHAIRMAN SIEBER:  I think it would be
           helpful if we had a little bit of background.
                       MR. GWYNN:  My name is Pat Gwynn.  I'm the
           deputy regional administrator for NRC Region IV, and
           I'd like to welcome the committee to our offices. 
           We're pleased to have you back again.
                       I began my career in the nuclear arena in
           1969 when I joined the United States Navy.  I was a
           reactor operator and electronics technician until I
           went to Purdue University, got my bachelor's degree in
           nuclear engineering and joined the Bettis Atomic Power
           Laboratory where I worked for a period of time as a
           Bettis physicist and test engineer.  
                       After that I joined the Nuclear Regulatory
           Commission in 1980.  I was a resident and senior
           resident inspector in Region III at Zimmer and at the
           Clinton Power  Stations.  I joined the staff of
           Chairman Lando Zech in 1987, where I served until
           1989.  During that period I had the distinct pleasure
           of accompanying him and a group of 19 nuclear safety
           government professionals who went to the former Soviet
           Union and established a joint coordinating committee
           on nuclear reactor safety.  During that time I also
           had the pleasure of working with John Larkins, and I'm
           pleased to have John here with us today.
                       Since Chairman Zech's term expired I've
           been assigned here in Region IV, first as a deputy
           director of the Division of Reactor Projects and then
           as director, Division of Reactor Safety, director
           Division of Reactor Projects, and now as deputy
           regional administrator.
                       I have with me today Ken Brockman, who's
           the director of our Division of Reactor Projects, and
           Ken is uniquely positioned to provide you insights
           about the initial implementation of the NRC's Reactor
           Oversight Program given that not only has he been
           leading that program here in Region IV but he was also
           an important member and contributor to the agency's
           PACA panel, the IIEP that provided advice and
           recommendations to the agency on that program.
                       Ken, would you like to give a little
           background about yourself?
                       MR. BROCKMAN:  Probably even more unique
           about me is I'm not Navy.  I'm a graduate of the
           military academy at West Point, which puts me very
           much in the club because I'm so much out of the club,
           but I was eleven years in the military duty there, the
           last part spent with Armor H Airborne in research and
           development activities for weapons systems.  When I
           left the Army I went to work for Westinghouse, so not
           only am I an Army person I'm Navy qualified on
           reactors by working for Bettis Atomic Power
           Laboratories.
                       I've got experience in the utilities side. 
           I worked for Detroit Edison Company during their final
           stages of construction and initial startup as a member
           of their management team, their training department
           out there.  I've been with the agency since 1984 at
           Region II as a license examiner and as an inspector
           out of that regional office.  I was up at headquarters
           for about five years, worked on the staff of EDO, was
           a technical assistant for Chairman Selling.  
                       I was also in charge of the incident
           response organization up there now at the time they
           built out the new facility, made the transfer, had the
           opportunity to work with the Russian Federation and
           the Ukranian Republic as part of our USA IDG7
           initiatives in establishing emergency response
           capability in those two countries, which many people
           don't know that they had absolutely no nuclear
           emergency response capability at all.
                       Then in Region IV now for six years in the
           Division of Reactor Safety, and now as a director in
           the Division of Reactor Projects.
                       MR. GWYNN:  And to his right we have Jeff
           Clark, who's our senior resident inspector at the
           Cooper Nuclear Station.  Jeff, would you like to give
           a little background about yourself?
                       MR. CLARK:  Sure.  Good morning.  I
           started out my nuclear career -- nuclear Navy.  I had
           nine years active duty in the Nuclear Navy Program. 
           Subsequent to that I worked for 14 years for the
           Baltimore Gas and Electric Company.  There I was
           maintenance supervision, planning and scheduling, and
           my last functions at Baltimore Gas and Electric was as
           a senior project engineer in capital improvements
           area.
                       After that I joined the NRC in 1996.  I
           was in Region III.  After a short period of time in
           the Division of Reactor Safety I was the resident at
           Perry, and I moved on from resident at Perry to the
           senior resident at Cooper Nuclear Station in 1999.  I
           came on board there just about the same time that the
           Revised Reactor Oversight Process was beginning, the
           pilot process at Cooper, so what I'm planning to do
           today is share some of those insights and dialog with
           you on what those insights are from that perspective
           of a pilot plant and going into the Revised Reactor
           Oversight.
                       MR. GWYNN:  To Jeff's right is Art Howell,
           director of reactor safety in Region IV.
                       MR. HOWELL:  Good morning.  I also started
           my career in the Nuclear Navy.  I spent five years on
           active duty nuclear powered submarine on the West
           Coast, worked briefly at Rancho Seco Nuclear
           Generating Station, which is near Sacramento,
           California before it was permanently shut down. 
           Joined the NRC in 1985 in the former office of
           inspection and enforcement, spent my time primarily
           conducting safety system functional inspections, and
           then also in the former office of AAOD performing
           diagnostic evaluations before coming to the region in
           1988.
                       And since that time I was a senior project
           engineer, resident inspector at Comanche Peak Unit 1
           during the startup testing of that unit, section chief
           in the Division of Reactor Projects for South Texas
           Project in Wolf Creek, and also the deputy directors
           of both the divisions of reactor safety and projects,
           and then for the last four years the Division of
           Reactor Safety.  
                       I too, like Ken, have spent a lot of time
           working with the Russians and Ukrainians with respect
           to the Lisbon Nuclear Safety Initiative.  I was a co-
           team leader with some Russian counterparts at a fairly
           extensive team inspection at the Balakovo Nuclear
           Power Plant in 1995, and we've done a lot of work in
           hosting Russian and Ukranian regulators in this region
           over the years in both divisions, and I'm going to be
           sharing with you our experiences with respect to the
           new fire protection inspection program as well as some
           risk insights and how we incorporate risk into day to
           day regional operations.
                       Thank you.
                       MR. GWYNN:  On my left is Mr. Troy Pruett,
           who is one of our senior reactor analysts here in
           Region IV.
                       Troy.
                       MR. PRUETT:  Good morning.  My name's Troy
           Pruett.  I'm a senior reactor analyst.  
                       I started off in the Nuclear Navy as well. 
           I was an enlisted plant operator and staff instructor
           at the New York prototypes.  After leaving the Navy I
           went to work at D.C. Cook as an instructor in their
           training department, and then joined the NRC in 1992
           as a health physicist inspector in Region V in the
           materials group.  
                       With the consolidation of Region V and IV
           I took a slot as a resident inspector at Waterford,
           spent three years down there, took a senior resident
           slot at the Clinton Power Plant in Illinois, and once
           we got them back on line I decided I needed to go back
           to a warmer climate and took the senior resident slot
           at the River Bend Station, and I was done there for
           about two years and I'm currently filling the senior
           reactor analyst slot now.
                       MR. GWYNN:  Thank you, Troy.
                       We have a number of other staff members
           that will be making presentations throughout the day,
           and I think that we need to move forward with our
           presentation.  However, I would like to recognize five
           special people that we have in the room today. 
           Alberto Garcia is with us from the Massachusetts
           Institute of Technology, Eddie Horus from Texas A&M
           University, Brandon Kennedy and Brian Tindle, both
           from Oklahoma Christian University, and Jeff Moreno
           from Oklahoma State University.  They are five
           engineering associates who are working in our offices
           this summer and learning about the NRC, and they're
           here for training purposes.
                       Welcome, this morning.
                       I also wanted to express the regrets of
           our regional administrator, Mr. Merschoff.  He
           unfortunately was unable to be here today.  I'm sure
           you're aware that the agency's first meeting of the
           agency action review is being undertaken right now in
           Atlanta, Georgia, and for that reason he was unable to
           be here.  He recalls that the last time you were here
           that was his first year in Region IV, and he also was
           unable to attend, and --
                       MEMBER POWERS:  I hope that everyone
           congratulates him on his presidential award for
           meritorious service to the agency.
                       MR. GWYNN:  Thank you.  I'll pass that
           along to him.
                       I believe we have an interesting agenda
           today, and in addition we have arranged for some of
           the best Texas barbecue to be served at lunch, and
           that will give us an opportunity perhaps to have some
           more informal discussions, and we've asked additional
           members of the Region IV management team and the staff
           to come and join us for that luncheon.
                       Does everybody have a copy of my handout,
           because you can see the colors from the handout, and
           I'll be referring to the colors.
                       The Region IV organization is consistent
           with the organizational structure found in the other
           three regional offices of the Nuclear Regulatory
           Commission.  The only major differences are the lack
           of deputy division directors in two of the three
           technical divisions, and that difference exists
           because of our relatively small size.
                       At the top of the organization chart
           you'll see Mr. Merschoff and myself, the regional
           administrator and his deputy.  We're responsible for
           the day to day operation of the region, which includes
           this office, 14 resident inspector offices,
           approximately 160 staff members, and a budget of about
           $4.3 million this year.  The majority of our budget
           goes to office rent and travel expenses, but this year
           there's a substantial additional amount in our budget
           to provide for the upgrading of our incident response
           center for continuity of operations and continuity of
           government functions, and Mr. Andrews, our emergency
           response coordinator, will talk a little bit more
           about that this afternoon.
                       To the left of Mr. Merschoff is a dotted
           line going to Mr. Lynn Williamson, who's the director
           of the Office of Investigation field office that's co-
           located with us here in Arlington, Texas.  The Office
           of Investigation's field office is responsible for
           investigating allegations of wrongdoing by NRC
           licensed entities and their contractors.
                       The gray boxes below myself and Mr.
           Merschoff are the regional administrator staff
           including our allegation coordination and enforcement
           staff, our emergency response coordinator, our state
           liaison officer, our regional counsel, and our public
           affairs officer, who actually reports to the Office of
           Public Affairs in headquarters, Mr. Bill Beeacher.
                       From time to time some of the regional
           administrator staff members will be joining us today,
           and right now Mr. Charles Hackney, our state liaison
           officer, is sitting behind you, and Mr. Breck
           Henderson, who's our public affairs officer, is also
           here in the room.  
                       We have three technical safety divisions
           represented by the blue, green, and yellow boxes that
           you see below the regional administrator's staff.  Two
           of these divisions, the Division of Reactor Projects
           and the Division of Reactor Safety, are involved in
           the implementation of NRC's power reactor inspection
           program.  The Division of Reactor Projects or DRP is
           composed of the resident inspector's staff, their
           supervisors, and regional support functions.  They are
           the eyes and ears of the NRC at every operating
           nuclear reactor in the region.
                       The resident inspectors are generalists
           who live in the vicinity of their assigned plants. 
           They monitor the overall safe operation of their
           assigned facilities.  They're the first to respond to
           events at the plant, and they are the primary NRC
           spokesman for the NRC in the local community.
                       The Division of Reactor Safety or DRS is
           composed of specialists, inspectors, and reactor
           operator license examiners that are all based here in
           Arlington.  They include specialists in plant
           operations, maintenance, physical security, radiation
           protection, emergency preparedness, and engineering
           disciplines to name a few.  These inspectors travel to
           all of the power reactors in the region performing
           scheduled inspections in their areas of expertise.
                       Mr. Brockman will talk more about the
           implementation of our power reactor inspection program
           in a few minutes.
                       The Division of Nuclear Materials Safety,
           or DNMS, which is in the yellow, is composed of
           inspectors and license reviewers who implement all
           aspects of NRC's nuclear materials licensing and
           inspection program within the region except for those
           licensing and inspection activities that are
           specifically delegated to the states that have
           agreement state programs.  Those agreement state
           programs are overseen by two agreement state officers
           that report to the director, Division of Nuclear
           Material Safety.
                       DNMS licenses and inspects nuclear
           medicine programs in hospitals, radiographers, nuclear
           gate users, and well loggers.  they also inspect
           uranium mines and mills, a fuel cycle facility, and
           power reactor independent spent fuel storage and
           decommissioning activities within the region.  The
           materials inspectors in Region IV have a particularly
           large challenge, since even though they're only on the
           order of 625 materials licenses and 25 uranium
           recovery facilities they're spread over large
           distances, including the North Slope of Alaska and
           Guam in the Western Pacific.
                       Finally, our Division of Resource
           Management and Administration, or DRMA, which is shown
           in the pink, is the administrative unit supporting our
           technical safety mission.  They handle such activities
           as travel, budget, human resources, mail, information
           technology support, and a host of other service
           functions that keep the technical safety organizations
           functioning smoothly, and we're proud of the high
           level of service that our DRMA organization provides
           to our inspection and licensing staff.
                       We have a very large region
           geographically, as you will see on my next slide.  Our
           travel office issues more airline tickets than any
           other NRC region and almost as many as our
           headquarters offices.  Kathleen Hamill, who's the
           director of the Division of Resource Management
           Administration, is here in the room with us today.
                       The next slide, which is my last slide,
           depicts Region IV.  It identifies the 21 states in the
           region and the location of the 21 power reactors and
           the 14 power reactor sites in Region IV.  You'll
           notice that two of our power reactor sites, the
           Callaway Plant in Missouri and the Grand Gulf Plant in
           Mississippi, are physically located in states where
           the use of nuclear materials is regulated by a
           different NRC region.  This action was taken in 1994
           as we consolidated NRC Regions IV and V to more evenly
           distribute the power reactor inspection work load
           across the regions and to place all the plants that
           were then operated by Entergy Operations Incorporated
           in a single NRC region.
                       If you look at the map that's in front of
           you you'll see a purple triangle in Missouri.  That's
           Callaway.  And a purple triangle in Mississippi, and
           that's Grand Gulf.  Grand Gulf is one of the four
           Entergy plants that are located in NRC Region IV.
                       This slide also shows that 15 of the 21
           states in the region are agreement states.  The dark
           purple and the middle purple shades are the agreement
           states in Region IV.  Notice that both Alaska and
           Hawaii as well as the Pacific Trust territories are
           included in the six states that are not agreement
           states in Region IV, and those are the lightest shaded
           states on the map.
                       What the map doesn't show clearly is the
           important work we in Region IV are doing to bring a
           higher level of radiation safety to work being
           performed on offshore oil platforms and on pipeline
           barges in federal waters in the Gulf of Mexico.  It
           also doesn't make clear that our regulatory arms reach
           to Johnston Atoll and Guam located on either side of
           the International Date Line.  As a result of this
           circumstance we were able to state on December 1, 1999
           that Y2K both began and ended in Region IV.
                       With that, I'm prepared to answer any
           questions that you have about the region overall
           before we go to the next presentation.
                       (No response.)
                       MR. GWYNN:  If there are no questions I'll
           turn it over to Ken Brockman, the director, Division
           Reactor Projects.
                       Ken.
                       MR. BROCKMAN:  Thank you very much, Pat. 
           I have a strange feeling that I won't be quite as
           lucky on the lack of questions in my presentation. 
           I'm passing around a set of slides I copied for
           everyone.  
                       Over the next 45 minutes or so I'm hoping
           to have a very -- an opportunity for a good
           interactive discussion as to the insights that we've
           seen in Region IV with respect to the revised
           oversight process and also the insights that we've
           been able to gain from it.  As Pat mentioned earlier,
           we've been very active over the last 18 months in the
           process.  I've been a member of the pilot program
           evaluation panel and the implementation evaluation
           panel, which has given me an appreciation for FACA
           rules that I did not previously have.
                       And Jeff has been involved with it since
           the very beginning, as he has said.  The presentation
           that we're going to give you is basically going along
           these lines where we're going to talk about the
           process overview.  We'll go with the time line as to
           how it's proceeded, inspection assessment process, how
           it's worked in the region, the insights we've got from
           there, specifically the results that we've seen in
           Region IV, and how we think that that has rolled into
           our assessment of licensee performance.  
                       Is the process working?  Does it appear to
           be getting us to the places?  Does the gut match what
           your head says with respect to this.  Certainly
           conclusions at the end.  We've got questions and
           answers listed at the end.  I would encourage I think
           however that at any time you've got something that you
           want to interject to keep the presentation more free
           flowing as opposed to in that manner.  We have the
           capability to fill up any block of time that we are
           given with the presentation, and that may  not get to
           all your needs, so feel free to interrupt.
                       MEMBER POWERS:  Ken, you're not going to
           discuss the significance of the determination process?
                       MR. BROCKMAN:  No.  Per se, we would
           discuss it only that we go through it.  I think with
           the SRAs and what have you we've got that -- a more
           in-depth discussion on that later on.  Some of the
           successes of it, some of the challenges of it. We will
           be sharing -- generally has it worked with an example
           there, but not the details for this presentation.
                       Okay.  We'll go with our next slide then,
           and I'm probably going to start off with my old
           teaching type of philosophy with the infamous
           rhetorical question, do we need to go through a
           discussion of the ROP process:  performance
           indicators, inspection findings, how they come
           together.  Would that be of benefit as a refresher to
           everyone or is everyone here fairly familiar with
           that?
                       MR. LARKINS:  I think we can go fairly
           expeditiously --
                       MR. BROCKMAN:  Okay.  Then we'll really
           cover -- at the 30,000 foot level.  New program,
           performance indicators provided by the licensees in
           several different areas, inspection still an essential
           part of the program.  We can't forget how that's come
           together.  We have baseline inspection similar to the
           previous concept of a core inspection.  Now there are
           criteria by when you would either do supplemental
           inspection based upon performance deficiencies.  That
           can escalate in its level, be a low performance issue,
           be a higher -- be a very significant type of
           supplemental inspection.
                       MEMBER POWERS:  The first question that
           comes up in this comparison between core and baseline
           is that now the region's locked into a baseline
           whereas in the past they could adjust for a round in
           response to the needs of particular sites.
                       MR. BROCKMAN:  We can flip back to our
           member of ours -- and let me refer you to a chart
           that's further within your packet.
                       MEMBER POWERS:  If we're going to get to
           it I can wait.
                       MR. BROCKMAN:  I'll get there.  Yes,
           without a doubt the new program still allows us the
           capability to respond to changes in performance.  It's
           just a criteria or a little more defined now, more
           predictable than they used to be.  That's one of the
           insights that we have seen is anything that we have
           felt we need to inspect we can get to.
                       MEMBER POWERS:  Well, you know, when give
           him a licensee, is this, what -- under the old
           program, I was doing good and I had X number of
           inspection hours, and I haven't really changed and now
           I've got X plus delta inspection hours.  I'm getting
           more inspections under this, and my performance is
           about the same.
                       MR. GWYNN:  I'd like -- a few things on
           this subject, because this was one of my concerns when
           we first proposed having this new program, and it's an
           interesting result.  But under the core program we had
           a minimum inspection program that we did at every
           facility.  That was the core.  We had core
           inspections, regional initiative inspections, and
           reactive inspections, and we couldn't change the core,
           so the baseline is like the core but the baseline
           includes all of the inspection that we plan to do at
           the facility, whereas the regional initiatives -- some
           of that was planned.  Some of it was added as a result
           of performance insights that occurred during the
           assessment period, and of course reactive inspection
           only took place as a result of events.
                       And so for licensees that were high
           performing licensees under the core inspection
           program, that got very little regional initiative
           inspection and essentially no reactive inspection
           because there were no events at their plants, and as
           a result they essentially got the core inspection
           program.
                       Now we in Region IV had a relatively high
           number of plants that were performing at a high level,
           and as a result the majority of the plants in Region
           IV were on core or reduced inspection programs, and so
           when the baseline inspection program began its
           implementation here they did experience an increase in
           the total number of inspection hours.  But as you can
           see from Ken's chart, the increases weren't that
           great.
                       MEMBER POWERS:  The problem I see is that
           when they put in this new reactor oversight they
           didn't say, Tom, here's 16 more FTEs to help you carry
           out this additional inspection.  I'm very certain they
           didn't do that.  So it looks to me like you must have
           the same problem that the licensee is facing in that
           you did have a lot of high performing plants.  Now
           you're doing more inspections with the same number of
           people.  Something's got to give some place.  What's
           giving?
                       MR. BROCKMAN:  It's a good insight, and we
           might as well -- I'm going to stay free flowing in the
           presentation, so you've got this chart in your package
           about two-thirds of the way back.
                       What you can see off this chart right here
           is a look at -- right here is the last year -- this
           light colored bar -- it's the last year of the old
           program.  Now, that's not the year right before the
           new one, because that was a transitional year.  I've
           gone back to '99 when the old program was solid in its
           implementation and then compared that with the dark
           line against the first year of the new program. 
           You're going to see some a little more, some a little
           less.  
                       Why is the variance in the different
           plants?  Remember, we've got some procedures -- big
           team inspections that are done biannually.  Some are
           done triennially.  So the first year you haven't
           gotten all of the program done anywhere, and we
           haven't tried to normalize the data here.  So you're
           getting the actual raw data that was conducted, and
           you can see, some above, some below.
                       Now --
                       CHAIRMAN SIEBER:  I think that question
           then needs to be extended a little further because if
           you increase the baseline inspection basically for all
           plants then reactive investigatory inspections have to
           decline because you have fixed manpower, and because
           of that do you feel that you lose some versatility for
           those plants that don't perform as well as the average
           plant to gain appropriate insights into the failures
           of that plant?
                       MR. BROCKMAN:  What's happened because
           of -- we have to visually try to capture this a little
           bit.  We had several plants before.  We had everybody
           who was  all South Point, and they'd get a small
           amount of inspection.  Then we had those who may have
           had three 1s and a 2, two 2s and two 1s.  What we've
           done now is about everything from three 2s and a 1 on
           up have been all brought together with the new
           criteria to where you're at.  That's about the number
           of plants we're talking about.  Right now we've got
           about 85 plants in America who are all in the all
           green arena, the licensee response arena.
                       Therefore, the amount of inspection that
           you need to have to maintain your comfort that that
           performance level is now based on the lowest person of
           that 85, not the highest person of that 85 -- my
           gradations are different now.  That's why plants that
           were very good performers are now seeing more.  My
           inspection program was verified with comfort the lower
           level of performance.  That addresses I think the
           utilities issue as to why they're seeing more
           inspection.
                       What they're seeing less of is less
           regional initiative.  I've got an itch that needs to
           get scratched. Everybody's getting that itch scratched
           on a baseline now in that aspect of verifying, so have
           I lost that flexibility?  No.  That flexibility is now
           built into the baseline program.  
                       Your reactive question is a superb
           question.  It was one of my big concerns going in
           there is our capability to respond to events as they
           arise.  We're going to talk about a couple of those
           and where they've gone.  The criteria now are very
           much more prescribed.  Management directive 8.3
           certainly gives us definitive criteria at which time
           you start considering a special inspection, an AIT, an
           augmented inspection team, an incident investigation
           team.  We use those criteria and they're based on
           risk -- as an entry point into the decision-making
           process.
                       We've got overlap where deterministic --
           your gut comes into play on it -- yes, I could.  No,
           I couldn't -- so we've got some overlap.  The way I
           describe it is PRA number gets me to the ballpark and
           then my gut tells me what position I'm going to play
           out there, whether I go or not.  
                       So we put that together and what we've
           been able to find now is under the baseline program if
           I have an event that occurs -- we're going to talk
           about two events today.  If we've got an activity that
           goes on there is a baseline module called event
           response that I go out there with, and the purpose of
           that module is to identify what is the risk
           significance of this occurrence?  Get me to the
           ballpark.  Am I at the ballpark, am I not at the
           ballpark?  
                       And then I can use one of two options to
           inspect -- or one of three options to inspect it.  A,
           I can pass.  Risk number didn't get me to the
           ballpark.  It's not worth the investment of the
           issues.  I will follow up.  I leave it in the
           licensee's domain and I will follow up with problem
           identification and resolution inspection later on to
           see did -- verify that they addressed it properly. 
           That's one option.
                       The second option I  have is the other end
           of the spectrum.  I'm there.  It requires a special
           type of inspection, so that's inspection AIT, IIT. 
           The instincts are there and we will, based upon the
           risk insights, the deterministic insights, we will
           launch a unique activity outside the baseline program
           to do that.
                       The third option that you have then is I
           am going to use this to define the samples that I want
           to do under the baseline program.  I have identified
           a risk significant sample set.  It's time -- I'm
           supposed to evaluate emergent work activities.  Well,
           I have a potential transformer that has exploded that
           doesn't have a risk number, but boy the licensee's
           scrambling about.  They're doing things that have
           impact on the plant operations.  How are they dealing
           with it?  It's a wonderfully appropriate sample to be
           using right now, and the insight gets me there, and
           the baseline program lets me inspect that in a real
           time method.
                       As I said, we have not found a thing that
           we want to inspect that one of these three legs of the
           program will not let us get to.  We've been able to go
           out and inspect everything we want.  One of the
           insights we do have with respect to resources though
           is they are very tight.  We have our people scheduled
           out to the week, and Art's impacted by this even more
           than I -- 18 months in advance.  We know when our
           people's leaves are going to be taken.
                       MEMBER POWERS:  I don't understand whether
           that's an acceptable situation.  That really does
           impact your flexibility.
                       MR. BROCKMAN:  One of the lessons I think
           we learned nationally is in Region I with IP2.  The
           initial estimate for an activity -- if you get an
           activity that turns up red and goes into our large
           scale supplemental inspection, the 95003 inspection,
           I think they would tell you the initial resource
           estimates associated with that were not nearly what it
           winds up becoming.
                       MEMBER POWERS:  It expands like --
                       MR. BROCKMAN:  We have been blessed in
           that we haven't been challenged with one of those
           activities.  We would really have to do some
           significant resource decisions with respect to what
           we've got to do.  We've been challenged with a couple
           of things ANO this year.  I had -- in one year I've
           got the new program, steam generator replacements, and
           license renewal.  Steam generator replacements and
           license renewal are not part of the baseline
           inspection program.
                       Now, many of the activities that went on
           as part of our inspection for those things were
           appropriate risk informed samples to put into the
           baseline program.  They're doing plant modification --
           major plant modification going on with steam generator
           replacement.  What better modification to look at
           during this year's inspection than the replacement of
           steam generators?  I gain great insights there.  I can
           take credit for that under the baseline inspection
           program while we're inspecting the steam generator
           replacements.  This makes sense.
                       Were we type at ANO?  Yes.  We're type. 
           One of the insights I've seen is here in the regional
           office I have two project engineers which support each
           one of my branches.  Their inspection time is fully up
           to in the neighborhood of 30 percent on the road
           inspection time.  Every region-based inspection -- we
           don't call them a DRS inspection, a DRP inspection. 
           DRS and DRP share the inspection program.  Some of the
           modules are resident based.  Some of them are region
           based.  The region based inspection -- many DRP people
           support those.
                       We have a schedule worked out where I've
           got a resident who is leased on one region-based
           inspection a year.  Every resident is.  Every one of
           my project engineers are.  So you have these
           scheduling dilemmas much more a part of the branch
           chief's job, and they schedule those much further out
           than they did in the past.
                       MR. GWYNN:  I have a couple of comments
           that I'd like to make.  
                       One of the major thrusts of the new
           inspection program was to provide consistency across
           all licensees and across all regions, and I think that
           goal has been advanced substantially by the new
           baseline program.  Ken used the term if we have an
           itch that needs to be scratched.  That's now the
           agency's itch.  When I was leading the Division of
           Reactor Projects if we saw an area that we thought
           needed to be looked at more closely across the entire
           fleet of plants in our region we would go and do that. 
           But the agency wouldn't do that, and so three other
           regions didn't receive that inspection.  
                       Now those decisions are made nationally
           and if in fact that itch needs to be scratched it's
           scratched at every plant in the country, and I think
           that's a significant improvement in the conduct of our
           inspection program.
                       We had a different threshold for event
           response.  Now if the licensee has a good corrective
           program and they're in the licensee response band we
           typically don't respond to a low-level events that
           occur at their plants.  And so the things that we were
           doing in the past we're not doing now that were unique
           to this region, but we're applying additional
           resources at plants in areas that have been deemed by
           the agency to be of risk significance, and as a result
           of that we've had some excellent findings that we
           would not have achieved under the previous inspection
           program, and that's focused attention for all of the
           utilities in the countries in areas that it hasn't
           been focused in before.
                       so I think that the new program has
           brought a lot of value to the agency and has advanced
           a number of goals, including the goal of consistency
           across the regions.
                       CHAIRMAN SIEBER:  I'm going to ask another
           question which probably will take you beyond where you
           are in your talk right now, and if that's the case
           then just remember it and when you get there you can
           address it.  But we are about to introduce as an
           agency the performance indicators, and it's purported
           that these performance indicators will allow a
           reduction in baseline inspections. 
                       Do you feel that there is an equivalency
           between performance indicators and reductions in
           inspections such that the combination of the two will
           result in an adequate regulatory program, or do you
           have other views?  And you can address this now or
           later on.
                       MR. BROCKMAN:  You've looked at my
           presentation notes.  Bear with me.  That's a major
           topic we're going to talk about in just a couple of
           minutes.
                       CHAIRMAN SIEBER:  All right.
                       MR. BROCKMAN:  It's a great segue.  Let's
           move -- everybody understands how we're organized now
           under cornerstones, that concept, cornerstones come
           together under reactor safety, radiation safety, or a
           safeguards application.  Performance indicators feed
           a cornerstone.  Inspection findings feed a
           cornerstone.  
                       And, Jack, we will be getting to bring
           those together.
                       Let's very quickly move to the time line
           that we're talking about so everybody is together
           there.  The pilot program for the ROP started in June
           of '99.  There were feedback lessons learned
           associated with that commission meeting on that.  SECY
           paper went up and what have you.  We implemented the
           initial year on April 2, 2000.  That went on for a 12-
           month period.  We've changed our basic planning cycle
           now to an annual planning cycle as opposed to the old
           South methodology, which was 18 plus or minus your
           comfort factor.
                       And that's -- another point Pat brought
           up, to be consistent.  We are now it looks like going
           to transition and get that annual cycle on a calendar
           year basis.  That's one of the things you'll see
           coming up -- a recommendation is to right now play the
           next nine months as another transitional period and
           get this on a calendar basis.  That's an efficiency
           issue with respect to the agency to be able to do
           that.  So there's the basic time frames we're talking
           about.
                       If you'll look at the next slide we've got
           here real quick you can see in the initial year the
           pilot program -- there are the sites that were
           involved in the pilot program.  In Region IV that was
           the Fort Calhoun Station and the Cooper Station, and
           as we've mentioned Jeff was the senior resident
           through all of that.  He's been one of my key people
           who's been involved as we have made that transition.
                       What we're going to do now is talk about
           out of this -- and we're going to start moving, Jack,
           right to where you want to go.
                       The next slide takes us to the end of the
           first year.  Where are we?  What has this program told
           us?  This is off the web page.  It's currently there
           right now.  The column on the left is the licensee
           response column, and there is about 85 plants that are
           in that column --
                       MR. CLARK:  This chart would actually
           continue down.  This is just a representative --
                       MR. BROCKMAN:  Yes.  But even though a lot
           of information that's been heard is the performance
           indicators, the findings, we've only gotten 2 percent
           of the performance indicators that are not green. 
           When they come together, when the synergism of the
           process comes together if you look at the regulatory
           response column --
                       MEMBER APOSTOLAKIS:  These columns are
           from the action matrix.  Right?
                       MR. BROCKMAN:  This is what comes out of
           the action matrix.  This is what differentiates the
           performance that we've got now.  This is equivalent to
           the old south in the aspect of here's your ones with
           a couple of twos.  The next one -- here's the ones
           that probably got a three or so in there, and there is
           no correlation.  I'm just trying to give you a visual
           picture of where it goes.  So even though the
           individual data has 5 percent of the performance
           indicators, 5 percent of the findings aren't white. 
           When you put them together you get a differentiation
           of performance on plants.
                       And in fact it's greater than 5 percent. 
           We've got 15 plants out of 103 that are in the
           regulatory response column, three in the degraded
           cornerstone column, one in the multiple repetitive
           degraded cornerstone column, each one of these being
           a more significant level of performance deficiencies.
                       MEMBER POWERS:  I guess I agree with you
           that if you'd asked me before this matrix was done
           about what the distribution would be this is about the
           distribution we would have thought.  Right?
                       MR. BROCKMAN:  It's probably not far off. 
                       MEMBER POWERS:  Maybe one or two were up
           in the multiple response region, but not many more in
           the regulatory response.
                       MR. BROCKMAN:  No.  That's -- there may
           even be a couple more here than we'd have gotten, but
           as you're beginning to see a distribution of
           performance come about.
                       One of the things with the new process is
           it takes a little time.  You've got to let this play
           out.  When you get into the risk consideration of
           issues and you put all this together the processing of
           the issue takes a little longer than the old process
           did.  Very deterministic in the past.  Did you comply
           or did you not comply with the regulation? 
           Significant non-compliance -- you could get to an
           escalated enforcement decision fairly quickly.
                       It is a little longer process now to
           really put a an appropriate risk perspective on the
           issue, and Troy will be able to talk to that probably
           in more detail later on when we get into talking about
           the SDP and where that goes.  Art's probably got some
           insights that he'll be sharing too.  But it gets you
           there.
                       MEMBER LEITCH:  A question about Calvert
           Cliffs, for example, where you're dealing with two
           almost identical units, one in -- Unit 2 is in column
           one and Unit 1 is in column two.  I suspect that
           what's driven Unit 1 to column two might be the fact
           that it had three SCRAMs in a fairly short period of
           time, but one was as I recall was a lightning strike. 
           Another one was a failure in an electronic component,
           which could have just as easily occurred on the other
           unit.  It doesn't represent a different program or
           different level of management attention.  It's the
           same management team. 
                       And I just wondered does this indicate
           that your level of inspection would actually be
           different on Unit 1 for example than Unit 2?
                       MR. BROCKMAN:  What you would immediately
           get out of this would be Unit 2 would get what we call
           the 95001 inspection -- excuse me.   Unit 1 would get
           the first level of investigatory inspection.  This is
           approximately one inspector for a week, and that
           inspector goes out there and says, Okay.  What is
           behind here?  I have a performance indicator that
           threshold's been crossed, or I have this type of
           insight that is not very low significance, but it's
           not big.  Let's go out there -- and this inspection is
           to put that in the context, and it may be just what
           you say.  I've had a piece of equipment that had a
           random failure to it, could not have been predicted,
           caused the threshold to be crossed.  The licensee's
           dealing with it aggressively.  That's the extent of
           additional inspection they received.
                       MEMBER LEITCH:  But that additional
           inspection in this case would actually focus on Unit
           1 as compared to --
                       MR. BROCKMAN:  Yes.  It would focus on
           Unit 1 to put that insight into context and then
           identify what's the right response that there should
           be.  Maybe there is something that is broader and I
           have an extent of condition of vulnerability in Unit
           2 that is appropriate to follow up on when I do the
           problem identification and resolution inspection. 
           Maybe it's not.
                       Maybe I have got a unit-specific --
           something that's going on here.  If I had looked at
           ANO, which is our site where I've got two different
           vendors and the organization is very common in some
           areas.  In some areas it's not quite so common.  Maybe
           I determine it is something unique or maybe it's more
           cross-cutting on the different units.
                       MEMBER LEITCH:  Okay.
                       MR. BROCKMAN:  That's the beauty of this
           program. 
                       MR. GWYNN:  I think that it's particularly
           insightful that the plant that's at the top of the
           degraded cornerstone column which we do know about --
           in a way we're not very familiar with Calvert Cliffs,
           but we do know about that plant, and the things that
           contributed to that situation are I think important
           outcomes of this new baseline program and its focus on
           risk important activities at the plants.  We'll be
           talking about a couple of those as a part of the
           agenda later today.
                       And that plant was a category one
           performer under a reduced inspection program for a
           very long period of time, both when it was part of the
           Region III oversight and then as a part of Region IV's
           oversight, so this new baseline program has made a
           difference at that facility.
                       CHAIRMAN SIEBER:  Let me ask the question,
           let's assume for the minute that the new reactor
           oversight program is effective in coming up with a
           distribution of performance across the fleet of
           plants.  However, under the old process there was a
           different kind of response from the NRC that has to do
           with significance determination to a great extent
           where civil penalties were enacted, pressure releases
           occurred when you've got a level three finding,
           sometimes a public meeting in a local community, and
           as a senior -- former senior vice president and chief
           nuclear officer I can tell you those are attention
           getters for the licensee.
                       So my question is now that civil penalties
           are down and you don't have a lot of this fanfare do
           you feel that the licensee's attention is just as high
           under the new process as it was under the old process?
                       MR. BROCKMAN:  Let me address that.  I
           would challenge one premise --
                       CHAIRMAN SIEBER:  Okay.
                       MR. BROCKMAN:  -- that you're presenting. 
           The fanfare is not down.  In fact, the fanfare is
           more.  The only thing that's different is right to
           check.  If you go to the action matrix, which we've
           got a copy of in your handout here back -- action
           matrix right here --
                       CHAIRMAN SIEBER:  Right.
                       MR. BROCKMAN:  -- when we have one of
           these issues -- and now it's done real time in a
           supplemental inspection -- you're going to get
           regulatory conference, and depending upon it it will
           be in the local area, and you're going to get the
           press releases associated with the white issue.  
                       One of the things we do in Region IV,
           we've gone to quarterly integrated inspection reports. 
           By that I mean for a given facility on a quarterly
           basis the resident report is combined with all of the
           small level region-based activities, the one, the two-
           person inspections.  We would give an exit
           presentation if it's a DRS an HP inspector.  They
           would give an exit when they left.  But the written
           part of their report would come in at the end of the
           quarter.
                       What are the differences for those? 
           Exceptions would be major team inspections.  I've got
           an engineering team out there.  That report doesn't
           wait for a quarter.  It's a big activity.  We cull
           that out.  It gets a separate report.  Problem
           identification resolution, any major activity that
           we've got going on gets a separate report.  Any
           inspection that looks like it's going to have a white
           finding or above we don't wait until the quarter. 
           That is culled out right now.  It gets its own unique
           inspection report number and comes out.
                       So it's addressed very contemporaneously
           and we go right into the process:  public meetings,
           that regulatory meeting, the press release that goes
           along with it.  All of the other as you described
           fanfare that went on is still fully there under the
           new process.  The only thing that's not is the change
           in the enforcement policy for writing the check.
                       CHAIRMAN SIEBER:  Let me follow up just a
           little bit.  If you ask the average member of the
           public in the old days they understood $50,000 or
           $10,000 pretty easily because it related to things
           that they do, and when you say they had a violation,
           they paid this civil penalty, they admitted that they
           did wrong, that was pretty clear as far as the public
           was concerned as to what actually happened there.  But
           if you tell the public that you went from a green to
           a white perhaps there's some head scratching.
                       And I know that the NRC has spent a lot of
           time in public meetings trying to explain the process,
           but I don't think the public has as clear a notion as
           to what is going on now with the grade of performance
           as it used to be when it was pretty clear.  The fact
           that there were violations found, penalties being
           enacted, and so forth.
                       Do you have any insight to that as to how
           the public perceives the new process?  
                       MR. CLARK:  Kenny, can I address that?  
                       MR. BROCKMAN:  Jeff can probably do it
           very well because he's at a site that's had several of
           these change issues.  
                       CHAIRMAN SIEBER:  Right.
                       MR. CLARK:  To address it let me go back
           and talk about going into the pilot process and going
           into the revised reactor oversight process.
                       As the senior resident at Cooper, Cooper
           had performance problems going into this process.  I
           dealt very closely with the senior resident at Fort
           Calhoun, and we dialogued throughout this process and
           we saw big differences throughout this.  I also
           dialogued with the public a lot.  We had several
           public meetings.  I live in Southeast Nebraska. 
           Everybody knows what your neighbor does, so --
                       CHAIRMAN SIEBER:  Well, there aren't too
           many neighbors.
                       MR. CLARK:  I can see one house from my
           house, so -- 
                       VOICE:  Is it occupied?
                       MR. CLARK:  No.  So you go to the grocery
           store and you go to a church meeting and you will get
           dialogue about what is happening at Cooper, and I saw
           in the transition phase they were still asking about
           are they going to get fined for this thing that just
           happened last week?  Are they going to get fined for
           this?  And it took some discussion up front, but we
           said, No.  The new process is doing this by channeling
           through the action matrix what type of response we
           take, and it's going to have indicators.  We explained
           the indicators to them.  That was a little fuzzy, but
           I think the public is, at least in the vicinity of the
           plants, coming onboard with what these indicators
           mean.
                       And I'm going to say that from the
           standpoint of we just had a number of performance
           issues in the emergency response arena in emergency
           preparedness at Cooper, and I have the public asking
           me, How many whites did it have to get?  So now
           they're on board.  They know what the indicators are,
           they know how we respond now, and I think they're
           becoming more aware of what risk was.
                       If I could turn the tables a little bit as
           a resident under the old inspection program it was
           sometimes difficult for me to defend the agency's
           position on why these particular actions resulted in
           this type of penalty. When we were looking at it as
           combined significance or not being risk informed it
           was sometimes difficult to defend what those actions
           were.  Conglomerating actions, conglomerating some
           inspection findings to get an escalated issue with the
           licensee was sometimes harder to explain to the public
           than it is to say that we're going to put these into
           these arenas, into these cornerstones.  As you see the
           performance match out it's going to come out.
                       And as we've seen and we'll discuss later,
           we're seeing over a period of time that we're getting
           the distribution, we're getting those colors, and
           we're getting the response from the plants that we
           somewhat predicted.
                       MR. GWYNN:  I'd like to add to what Jeff
           just said, and my perspective is a little different
           from his.  I was in the position that he's in back
           when we were first starting to implement the
           systematic assessment of licensee performance.
                       Number one, we still issue significant
           notices of violation and impose civil penalties on
           licensees for significant violations of NRC
           regulations.  I think that Jeff just explained that we
           have a better threshold for determining the
           significance of those violations now than perhaps what
           we did in the past so the public can better understand
           why we consider the issues significant.  
                       I can tell you that making a number of
           public presentations of SOWP under the early stages of
           the program the public didn't have a clue what we were
           saying, and we did very little to educate them as to
           what SOWP was and what it meant.  For this new
           baseline inspection program we've had significant
           public outreach, lots and lots of communication as
           Jeff just indicated with the local community to
           educate them as to what the program is, how it works.
                       They're learning over time, and as we
           continue to hold these public meetings, as we continue
           to gain experience with the program I think that the
           public will become much more educated and much better
           able to understand the agency's decision-making
           process.
                       Now, an interesting side light from this,
           there were times in the past, for example, the
           Waterford steam-electric station that you just
           visited, where it was like somebody turned a switch. 
           They went from being all SOWP category I to having a
           category III in engineering and almost being on NRC's
           watch list essentially overnight.
                       How does that happen?  Under the new
           program it doesn't.  We have our action matrix. 
           People watch over time.  As our inspection findings
           and as the performance indicators build leading to
           increased agency attention and more significant agency
           actions up to and including major inspections,
           commission attention, and perhaps even a plant
           shutdown.  And so I think that our process under this
           new baseline program, which was one of the major
           desires at the outset, is much more scrutable by the
           industry and by the public.  
                       They can understand where we've been,
           where we're going, and why we're doing what we're
           doing much better under this program than what they
           could under the previous program, and so even though
           I was not a major proponent of the program at its
           outset I've become a major believer in the program as
           I've seen it work.
                       CHAIRMAN SIEBER:  Maybe I can comment on
           the answers so far.  First of all, I would
           congratulate the agency and the region for the
           outreach that's occurred, and I think that's the prime
           reason why you're getting some degree of public
           acceptance and understanding of what's going on, and
           had that been done in the old system to the same
           extent you might have had a different result under the
           old system.  But the resident still says -- the first
           question they ask me is will they get fined for this? 
           So that's the expectation of the public, just like
           going 30 miles an hour in a 25 mile zone.  In
           Pennsylvania where I live that's $141.  I understand
           that.
                       On the other hand, that's what the public
           expects, and so it takes some explanation to explain
           what this new system is, and probably it's a better
           system, and I'll leave it at that.  
                       On the other hand, you did mention, Pat,
           one aspect that intrigues me when you talked about
           Waterford where you said they went from a SOWP I to a
           SOWP III instantaneously, and that wouldn't have
           happened under the new system which tells me then that
           you believe that it's predictive to some extent, and
           I would be interested in knowing whether it truly is
           predictive or the same thing could happen under a
           baseline --
                       MR. BROCKMAN:  The same thing can happen.
                       CHAIRMAN SIEBER:  Okay.
                       MR. BROCKMAN:  You cannot -- it is not
           going to be the rule.  The premise is that you're
           going to see gradual degradation that would occur, but
           you can't -- for example, there's nothing I can go
           against stupid, and that could happen somewhere that
           you've got someone out there who intentionally does
           something and puts it into a vulnerability.  You get
           a catastrophic piece of equipment failure that has
           implications.  We did not have -- IP2 did not have
           some whites, going to yellows and then proceeded on
           into red.  They had the catastrophic failure and it
           had the significance that it had.
                       The system is not a 100 percent that can't
           happen.  It can happen.  But --
                       CHAIRMAN SIEBER:  So it's a mixture?
                       MR. BROCKMAN:  -- it will be an exception.
                       CHAIRMAN SIEBER:  It will be a mixture,
           much less likely --
                       MR. BROCKMAN:  Much less likely.  We are
           seeing with plants that in our old system seemed to be
           the ones that continually had performance problems,
           and as the data is building up we are seeing the
           things coming together in the performance issues and
           in performance indicators not so much, but the
           performance issues coming together along those
           lines -- let me answer a different question you had
           earlier now that I've touched on that.
                       The next couple of slides show you a
           couple of printouts off the web page, which I know
           everyone here is intimately familiar with, being able
           to get all the data.  You see performance indicators
           and inspection findings.  I have emphasized the fact
           that the new program consists of performance
           indicators and inspection findings.  If you look at
           that chart that we had up there with all the plants
           you can pretty well -- I haven't looked at all the
           region specific data, but I would guess I could pretty
           well predict which one of these plants are in the
           regulatory response based upon performance indicators
           and which ones are on inspection findings, and all the
           ones that are one site out of multiple unit sites my
           first question would be I'm going to guess that's a
           performance indicator problem that got them there.
                       Without a doubt all the ones where I've
           got both Quad Cities 1 and 2 and what have you, most
           likely those are coming out of inspection findings. 
           Our experience here in Region IV is the inspection
           findings are without a doubt still the driving
           component of this program.  You cannot give away the
           inspection findings.  The performance indicators are
           a good insight but the thresholds are such that
           without the inspection findings that predictivity
           you're talking about, Jack, in being there would not
           be there nearly as comfortably as we want it to be.
                       MEMBER APOSTOLAKIS:  What's wrong with
           the -- can you elaborate on that?
                       MR. BROCKMAN:  I'll give you an example. 
           We're recently seen the agency received a
           communication from Mr. Lochbaum talking about the
           threshold on reactor trips and how we don't gain
           insights on crossing reactor trip threshold III or V
           or whatever it is.  The risk threshold for reactor
           trips to go from green to white 19.  We're not going
           to set up 18 trips to have in a year is okay.  
                       The absolute risk part of it doesn't
           necessarily go in with your gut, and certainly from
           what the history is and what the performance of the
           industry is from where they're at doesn't go into the
           match up what you should have as your deterministic,
           and once again, the risk number gets me to the
           ballpark.  What position am I playing?  My gut says
           I'm behind the plate.  Five trips is enough, thank you
           very much.  And you've got to bring that together.  If
           this thing becomes risk based then the difference in
           the PRAs at the different plants -- you've got to then
           bring all of the data into a perfectly common playing
           field, and we've got to have total confidence in its
           absolute accuracy.
                       The industry and PRA is not there yet. 
           That's why we need to maintain the deterministic part
           of it.
                       MEMBER APOSTOLAKIS:  So the green-white
           threshold for initiators is the three.  That's not
           unreasonable, is it?  I understand that the red is --
                       MR. BROCKMAN:  But if I did it on nothing
           but risk -- the initial number that came up on risk
           when we were developing this would have been -- it was
           a humongous number.  I want to say 19 -- 25 I think
           was -- it was a crazy number.
                       MEMBER APOSTOLAKIS:  That has to do with
           how these numbers are derived and stop already because
           every such program --
                       MR. BROCKMAN:  Yes, sir. 
                       MEMBER APOSTOLAKIS:  But I'm trying to
           understand.  Let's say we had the right numbers.  Do
           you think that the inspections give you insights that
           the performance indicator will never give you?
                       MR. BROCKMAN:  Absolutely.  The
           performance indicator gives me insights in one aspect. 
           The inspection gets to things we don't have
           performance indicators for, and the overlap is my
           verification.  The inspection also does some
           verification that the performance indicator is being
           properly reported, appropriately focused, so that's my
           overlap on my vin, but the inspection definitely looks
           at parts that we don't have performance indicators
           for.  There's not a good way that we've been able to
           identify yet to gain that indication off a
           quantifiable, reportable data.
                       Problem identification resolution's a
           great example.  I don't have a number that gets
           calculated to say how good a licensee's corrective
           action program is, and we all know that's the basis
           upon which this entire new program is premised.  I
           think one of the key things out of the IIEP report was
           the executive summary.  If you read anything on that
           report read the executive summary, because it takes
           the data and actually takes a step back and tries to
           start drawing some conclusions about what it's telling
           you:  the difference between risk informed,
           deterministic applications.  
                       There is a difference.  It's a
           philosophical difference.  It's changing the way in
           which the public looks at things.  It's very easy. 
           You're going to get a fine.  I understand that. 
           $55,000.  Wow.  I look at my budget.  That's a hell of
           a fine.  I look at the licensee's budget.  No.  That
           press release caused much more concern than that
           $55,000 check did in the overall scheme of things at
           the level we're talking about for a licensee.
                       But that --
                       MEMBER APOSTOLAKIS:  But it seems though
           that we have again a conflict here, because it
           appears -- I agree with you that an inspection gives
           you a better picture of what's going on.  At the same
           time the agency wants to go the performance-based
           route, so --
                       MR. BROCKMAN:  I'll challenge that.  Yes. 
           Performance based, risk informed.  Yes, sir.  
                       MEMBER APOSTOLAKIS:  You're challenging
           what, that the agency wants to go that way or that
           it's a good idea to go that way?
                       MR. BROCKMAN:  No, no.  I misspoke.  I've
           had so many discussions with other people.  The first
           thing I hear is risk based and that's not what you
           said.  You said performance based.  So, yes, I'm with
           you.  Performance based.
                       MEMBER APOSTOLAKIS:  So it seems to me
           that the performance indicators are consistent with
           this philosophical approach, and you might say that
           maybe we could have a first screening based on the
           performance indicators, and then if you find that the
           numbers are disturbing then you go and do a more
           detailed inspection.  Would that be a better --
                       MR. BROCKMAN:  That's exactly what we do.
                       MR. CLARK:  Let me address that.
                       MEMBER APOSTOLAKIS:  Well, the baseline
           inspection is independent of --
                       MR. CLARK:  I see it from the other
           perspective.  As an inspector I see it as the
           performance indicators are overall view of the
           performance of the plant, and those are the roll-up
           perspectives of the plant.  The insights that you get
           from the individual inspection items will be the
           precursors to those initiating events or those things
           that get you into the performance indicators.
                       So we're being somewhat predictive, but
           also if you actually look in the details of what the
           inspection attachments that we do are -- let me step
           back and say when we initially went into this in the
           pilot process -- I speak somewhat for many of the
           inspectors throughout the region and throughout the
           country -- we were skeptical, because we said we're
           moving from a process where you follow your nose after
           something you don't like to you fill the bins, going
           out there and getting inspectable areas accomplished,
           and we said we are not going to be able to follow what
           we feel is risk significant.
                       Well, I can tell you -- I have some risk
           background -- I misunderstood what risk significant
           was.  After going through the process for a period of
           time, having findings, placing them through the
           significance determination processes Troy and Kriss
           will talk about a little bit later, we gained some
           very valuable insights as to what the precursors to
           these events are, what the precursors to performance
           indicators are.  We're seeing those come out,
           particularly at my facility at Cooper.  We're seeing
           now connect the dots between some of these inspectable
           areas then going into performance indicators.  
                       Performance indicators haven't tripped
           I'll say as yet, but you're actually seeing some
           degradation in those areas, and I think with the
           inspection findings we can go back and say this is
           why, because they don't understand design basis.  They
           don't understand the performance of their operators.
                       MEMBER APOSTOLAKIS:  I think that raises
           another interest in philosophical question.  This
           business of leading indicators and trying to predict
           what's going to happen.  Again, you can say I have the
           initiating events cornerstone and I would like to have
           inspections before that to figure out when that
           indicator of initiating events will go over the first
           threshold.  
                       Then you may stop and ask yourself why
           would I want to do that? The initiating event
           cornerstone is itself a leading indicator for core
           melt, so there is no end to this.  At some point you
           have to draw the line and say enough is enough.  I
           don't really want to know that the plant is going this
           way and eventually the initiating event cornerstone
           will go over to white, because that by itself is
           telling me something about the risk, and to say no, if
           I do something else I will be able to tell in advance
           when the initiating event cornerstone will go to
           white, why would you want to do that?  That was
           against the performance based approach, was it not?
                       MR. BROCKMAN:  Absolutely.
                       MEMBER APOSTOLAKIS:  So where do you draw
           the line?  I understand the desire to know, but the
           licensee on the other hand says, wait a minute.  This
           was supposed to be performance based.
                       MR. BROCKMAN:  Let me put a different spin
           on it, and I think you and I are very much cut from
           the same cloth on this.
                       There's not a performance indicator,
           there's not an inspection finding out there that's
           predictive.  Everything they've reported or we find
           has already happened.
                       MEMBER APOSTOLAKIS:  That's right.
                       MR. BROCKMAN:  It's reactive.
                       MEMBER APOSTOLAKIS:  Right.
                       MR. BROCKMAN:  And we need to admit that
           up front.  It is reactive.
                       Now, the thresholds we set try to get us
           to the point of saying it's becoming more than
           coincidence.  The licensee is not controlling their
           destiny to the way they need to be.  We need to get
           interactive and provide assistance, provide more
           oversight.  That's the predictivity of it.  It's not
           that I'm going to predict when it happens.  I'm not
           going to do that.  It's the level of interaction that
           needs to be done to try to assuage a problem that's
           moving from going further down the line.  I think
           that's very good for the individual items.  
                       We've got the other thing that we
           haven't -- the magic word we haven't talked about yet,
           and I guess it's time we throw it on the table, cross-
           cutting issues.
                       MEMBER POWERS:  We're going to get to it.
                       MR. BROCKMAN:  That might be the one that
           has a bit of predictivity.  And once again, as you've
           told -- I talk with a little picture, and let me throw
           my view of cross-cutting issues here.  I have a house
           sitting on stilts by the ocean.  Each one of these
           cornerstones is a stilt.  When I have a degraded
           cornerstone I've broken a stilt.  My house tips a
           little bit.  If I break another cornerstone it tips
           more.  If I break enough and you get into degraded
           multiple the house slips off and it falls down in the
           ocean.  We have a problem.
                       The cross-cutting issues -- I've got
           somebody out there who's taking nibbles out of all of
           my stilts.  I get to the point finally where I have
           not had a single stilt break, but the stilts as a
           whole will not hold the weight of the house, and the
           house catastrophically comes down, and I didn't have
           the cornerstone fault beforehand.  That's what cross-
           cutting issues are trying to address, taking a bite
           out of each stilt.  
                       Typically in the licensee's corrective
           action capabilities, human performance initiatives,
           those are the areas that manifest themselves
           throughout plant operations as we all know.  That's
           the concept of cross-cutting.
                       MEMBER POWERS:  And your analogy is nice,
           because we understand gravity.  Now come to the real
           situation.  What's the phenomenalogical consideration
           that leads me to believe that I can tell people who
           are having the bites taken out of their human
           performance activities and I can tell that because of
           one of the performance indicators.
                       MR. BROCKMAN:  I personally believe that
           the cross-cutting issues we identify I'm finding more
           out of the inspection findings.  I've got to go into
           the whys are these happening.  I don't have a human
           performance indicator --
                       MEMBER POWERS:  It's really coming out of
           your root cause analysis.
                       MR. BROCKMAN:  You've got to -- and it
           keeps on going back to their corrective action
           program.  Are they effectively managing -- have they
           identified it?  Are they dealing with it?  Then I back
           off.
                       MEMBER POWERS:  But the trouble is are you
           looking -- well, the question is are you looking at
           the root cause analyses for all the non-cited, non-
           written up kinds of inspection findings?
                       MR. BROCKMAN:  We sample.  There is a
           sampling, and Art can probably speak very well.  The
           leadership for our corrective action inspection
           problem identification resolutions under his domain --
           you may want to share --
                       MR. HOWELL:  Right.  First of all, we do
           try to identify those things that are potentially the
           most significant to understand better the nature of
           the extended condition and why they happen, and we use
           not only the docket but we also use licensee records
           to do that, and we get all that information.
                       So to answer your question directly, yes. 
           We look at issues that are not in the docket that we
           have not necessarily already inspected and put into
           our inspection reports. We try to assess trends and
           patterns from our review of information and to make
           some judgments about how effective a particular part
           of the program is working.
                       The difficulty is what do you do with all
           that?  How significant is all those minor issues or
           issues that don't trip an SDP threshold.  So you have
           a collection of insights that perhaps you can share
           with a licensee but it's not at all clear what that's
           telling you about performance given that we're only
           sampling to a very small rate.  A very small
           percentage of issues ever get looked at in the form of
           our reviews.  We try to do the best we can.
                       MR. GWYNN:  I have a question if you don't
           mind.  While you were at Waterford did the licensee
           share with you its internal performance indicators --
                       MEMBER POWERS:  Yes.
                       MR. GWYNN:  -- the indicators they used to
           manage their facility?
                       MEMBER POWERS:  Well, they shared with us
           some set of them and --
                       MR. GWYNN:  Typically what I see is that
           they have very different thresholds than what we use,
           and it's appropriate.  It's their -- they're in the
           control bin.  And I think significantly all of the
           licensees that I'm aware of monitor human performance
           and have human performance indicators that they rely
           on to get them clues that things are not going in the
           right direction at their plants.  
                       That's perhaps the closest thing that I've
           seen to a predictive indicator that licensees use, but
           they're very -- there's a lot of variability.  Every
           organization has a different approach, and there's a
           lot of unreliability in the data systems, and so we
           wouldn't adopt those for the agency's use.
                       MEMBER POWERS:  Yes.  They can't. 
           Certainly Waterford -- they've identified human
           performance as one of their concerns, whereas if it's
           one of your concerns about Waterford it's not one of
           your high level concerns, but it is for them, and
           they've also looked at safety culture, which I don't
           think you would ever try to look at.  They probably
           are looking at management philosophy, which I hope you
           wouldn't look at.
                       Clearly they have a different set.
                       CHAIRMAN SIEBER:  I think the tools that
           they use are management tools and not regulatory
           tools, and you can't use one for the other, and
           actually the Waterford system is pretty common.  I can
           name you a dozen other plants that use basically the
           same system.  Wherever that steward went that system
           went with him.  Look at Palo Verde and --
                       MEMBER APOSTOLAKIS:  We will discuss the
           cross-cutting issues later.
                       CHAIRMAN SIEBER:  Yes.  One of the things
           I would point --
                       MR. BROCKMAN:  If it's a topic and you're
           not tied to the agenda this would be the time to talk
           about it.
                       CHAIRMAN SIEBER:  Okay.  One thing I would
           point out -- and I think this has been a great
           conversation because we're finding out the things that
           we needed to learn to do our jobs from you, and that's
           a great benefit for us.  On the other hand, I keep
           looking at the schedule and my airplane ticket, and I
           would like to move on.
                       MEMBER APOSTOLAKIS:  The cross-cutting
           issues though -- if there is a place to discuss them
           then we should.  Otherwise we do it now.
                       CHAIRMAN SIEBER:  Yes.  It's important.
                       MR. BROCKMAN:  This would be where we
           would do it.  Now, also if it's an individual thing
           we've got the entire noon hour if you would like to
           talk about that.  I'm not trying to suggest -- however
           you all want to do it we're here to support you.
                       MEMBER APOSTOLAKIS:  The thing about the
           indicators that we saw at Waterford yesterday when it
           comes to human performance I don't know how much
           they're telling you, because there is an implicit
           assumption there that -- when they plot the human
           error rates these are during normal conditions. 
           Right?  In fact, they told us that every morning they
           have a senior management meeting where they evaluate
           what happened and they declare something as being a
           human error.  I think that's a reasonable thing to do
           because it's obvious what is a human error.
                       But these human errors are found to occur
           during normal operations, and there is an assumption
           there that if you're doing well in that respect then
           if you actually have an initiating event you will also
           do well.  And it's so clear to me that that's the
           case, that if you're doing well with respect to
           routine maintenance then if there is a need to decide
           to go to bleed and feed it will do equally well.  I
           don't see that --
                       MR. BROCKMAN:  In fact, you can build the
           argument it could take you in either direction.  The
           higher sensitivity and the urgency makes people more
           focused, they'll do better, and the other side is is
           the infrequently performed activity and the stress
           will come up as they perform less efficiently.
                       MEMBER APOSTOLAKIS:  That's right. 
           Exactly.  So again, I'm not arguing that you shouldn't
           be doing well because you don't know.  I'm not saying
           that.  But I think to feel comfortable that one was
           switched to this -- when the initiating event occurs
           you have a very different culture perhaps, so if that
           doesn't help me that the human error rate goes down
           what does?  It seems to me that I have to do
           inspections and evaluate what is happening and maybe
           also use questionnaires because now the issue of
           safety culture in my mind becomes much more important.
                       Now, at the same time I know that the
           commission has cooled to the idea of the agency
           looking into safety culture issues, so they're clear
           it's a problem, because if they say don't do it you
           don't do it.  But we have this problem it seems to
           me -- and maybe -- first of all, I would like to know
           what your reaction is to these thoughts and second,
           perhaps we should try to sensitize the commission to
           these issues.
                       But I just don't see how normal indicators
           help me understand what the operators are going to do
           under extreme time pressure in a critical situation.
                       MR. BROCKMAN:  Let me give you my
           thoughts, and I want to ask Troy to inject a point too
           here based upon your November finding over at River
           Bend where you made the cross-cutting issue finding.
                       MR. PRUETT:  Okay.
                       MR. BROCKMAN:  One thing that I would say
           with respect to human performance if they can't do it
           well under normal conditions I have no faith they'll
           do it right under stressful ones.
                       MEMBER APOSTOLAKIS:  And I think that's a
           very good point.
                       MR. BROCKMAN:  It establishes that's why
           we're looking at it from the normal.  At least it
           says -- I have not lost confidence.  I can't say I've
           got it, but if they don't do it right under normal
           then I have lost my confidence they'll be able to do
           it under more exigent conditions.  So I think that's
           the value that brings.  It answers that question.  Not
           the other side of the coin.
                       Now, Troy was my senior resident out of
           River Bend, just recently has come into the site.  He
           mentioned that to you.  One of the things that he has
           done -- the new program allows us as part of the
           normal inspection program to try to identify cross-
           cutting issues in this area, and he's one of the few
           who's been able to put together logic and have a
           respected inspection finding in this area nationally,
           and I'd like him to be able to share what his logic
           was on going about that last fall.
                       MR. PRUETT:  Essentially we've developed
           a human performance cross-cutting issue in the
           operations area which involved questioning attitude
           and operator awareness of plant conditions, and
           initially that started with -- we looked at
           performance indicators associated with the risk
           significant systems of the plant. None of those
           performance indicators had crossed a threshold over
           into the white band, but we were seeing an increase in
           hours in plant unavailability on selected systems,
           mainly service, water, and some diesel generator
           systems.
                       With that we decided to take a multiprong
           approach and look at -- implement the baseline
           inspection program by -- we used a maintenance rule
           procedure to look at those systems to see if they were
           accounting those unavailability hours correctly, if
           they classified the deficiencies properly and
           implemented the appropriate corrective actions.  
                       We also went after post-maintenance
           testing in those areas as well as surveillance in
           those areas, and our op evals inspection focused on
           those same systems, and what we were able to come up
           with was a number of deficiencies involving each of
           those inspection modules on those systems, and as it
           turned out there were inappropriate engineering
           evaluations with inappropriate operator reviews
           associated with those that involved a lack of
           understanding of the system or a lack of awareness of
           plant indications associated with that issue, or
           inappropriate post-maintenance test methodology which
           was due to a lack of operator or engineering or
           maintenance craft understanding.
                       And eventually we developed a trend of
           approximately 20 to 30 findings associated with some
           type of poor or inadequate human performance aspect
           with each of those inspection modules, and we rolled
           those up together and termed it a cross-cutting issue.
                       And it gets to what Ken was pointing out
           earlier.  There's a lot of stilts out there, and what
           we were seeing was bites being taken out of a half a
           dozen or ten different areas.
                       MR. BROCKMAN:  The key thing is what do
           you do with that?  We brought it forward as a finding. 
           The licensee in fact embraced the finding.  They
           didn't necessarily like it being documented.  That's
           a different issue.  But they had no disagreement at
           all with the insight, with the assessment, with the
           finding being brought forward.  And they have
           initiated corrective actions to be dealing with that
           within the licensee response arena, and that's what we
           did.  We brought it forward and then we sat back and
           watched the licensee deal with it.
                       You would notice from our annual
           assessment letter that came at the end we see they are
           making progress.  They are doing what you would expect
           a licensee to do in the licensee response man, and
           that was not a conceptual problem with respect to our
           annual assessment.  We didn't carry it on as an annual
           level concern because they were dealing with it in a
           manner that was responsive to try to improve and make
           that problem go away.
                       CHAIRMAN SIEBER:  The big question here
           though is -- obviously, Troy, you've done a really
           good job.  The question is do the other 12 resident
           offices in your region -- can they do the same kind of
           job and can they do it nationwide to gather together
           these insights to make it work?
                       MR. PRUETT:  There's only one of me.  We
           don't have --
                       MR. BROCKMAN:  There is no pride in Troy's
           family.  He has garnered it all in his --
                       MEMBER APOSTOLAKIS:  But that was my next
           question is very much related to what Jack said. 
           Let's say the commission said go ahead and do
           something about safety cultures and work environment. 
           Do you --
                       VOICE:  And they will say that eventually.
                       MEMBER APOSTOLAKIS:  But do you think that
           it is possible to identify a number of indicators that
           will tell me something about the safety culture,
           because this is the argument right now.  In fact,
           Commissioner Diaz came to me and we asked why do you
           feel that we shouldn't be looking into this?  He says,
           You can't measure it so leave it alone.  Essentially
           that's what he said.
                       So is it -- measuring it probably is a
           very ambitious thing to do, but at least can we
           identify if your indicators say if I look at A, B, C,
           D then I can tell something.  Now, my colleagues with
           the utility experience sometimes tell me that the
           moment you walk into a plant within a minute you know
           whether the culture is good.  Right?  And if they talk
           about Coca-Cola cans being left --
                       VOICE:  In the ventilator ducts.
                       MEMBER APOSTOLAKIS:  Yes.
                       MR. PRUETT:  I think you can take some of
           the performance indicators we have right now, the
           SCRAMs or the safety systems or BSF actuation type
           indicators and look at those and provided there's not
           a single issue with -- where you take fault exposure
           hours that put you into that threshold, but if you
           have multiple instances of where you're increasing
           your unavailability numbers and you actually look at
           the data, that's an insight I believe into human
           performance.
                       MEMBER APOSTOLAKIS:  So it's the
           repetitiveness --
                       MR. PRUETT:  I think so.  
                       MEMBER APOSTOLAKIS:  -- because it points
           towards an underlying cause.
                       MR. PRUETT:  That's right.  And you have
           to use the inspection program to go find out what that
           underlying cause is.
                       CHAIRMAN SIEBER:  It's not performance
           indicators that's doing this though.  It's analysis.
                       MR. PRUETT:  Right.
                       MR. BROCKMAN:  Absolutely.  And the
           challenge is going to be how thin do you want to slice
           this?  How good do you want it to be?  We're going to
           talk later on today about some things we're doing with
           California plants.  PG&E right now has declared
           protection under Chapter 11.  We know that.  I have
           specific things that the residents are following up on
           on basically a daily basis as part of plant status
           reporting that gives us indications that the safety
           culture that I'm talking now at 30,000 feet is being
           properly focused, that we're not losing it.
                       Yes.  I can come up with something at that
           level pretty good.  Now, if you want to know do I have
           the ultimate confidence that everybody's going to
           record every single issue no matter what and bring it
           in, that's a much thinner slice and becomes much more
           difficult to do.  So the answer is where we want to
           set that threshold to be able to do that.
                       MEMBER APOSTOLAKIS:  So to close this
           subject so Mr. Sieber will not have a heart attack or
           high blood pressure --
                       CHAIRMAN SIEBER:  No.  I already have
           that.
                       MEMBER APOSTOLAKIS:  -- you would not
           discourage the ACRS from pursuing this issue and
           coming back -- going back to the commission and saying
           this is something we have to look into?  Look into it
           doesn't mean establishing a regulation tomorrow,
           because that's a common misunderstanding sometimes
           among the licensees, but understand it a little
           better.  What do we mean by safety culture, and maybe
           are there any insights one can draw by looking at
           certain things and saying something about it?  Would
           you discourage us from doing that?
                       MR. GWYNN:  I think this is a very
           difficult subject.  When you're talking about true
           safety culture you're talking about are the operators
           sleeping in the control room?  Are the operators and
           the maintainers performing their duties by the book so
           that you have confidence that the surveillance tests
           have really been performed, that they've really met
           their acceptance criteria, that the logs in the
           control room haven't been tampered with, that the
           strip charts from the control room recorders haven't
           been flushed down the toilet.  That's very difficult
           to get at from the outside.  I think that it's almost
           impossible to get at from the outside.
                       And so I don't know and I don't have a
           clue as to what this agency might be able to do to get
           at that type of safety culture issues that are I think
           at the root of what the industry and the public ought
           to be concerned about.  I know from inside the
           organization you can get at those problems.
                       VOICE:  Yes, you can.
                       MR. GWYNN:  But from our position it would
           be extremely difficult if not impossible in my view to
           be able to deal with and identify safety culture
           problems.  That's just a personal opinion.
                       MR. BROCKMAN:  -- morally I can't argue
           with that.  Your premise has the moral high ground
           totally captured.  The difficulties of implementing an
           inspection program in this area though are
           significant, especially with no rules or regulations
           to fall back on.  You have to -- and this program does
           more to get there than anything else because it's
           performance based.
                       We make findings now -- we've made
           findings in the first year that under the old program
           would have not even been documented that have been in
           observation, and we've got white findings out there
           now.  It's a performance finding.  It was not a
           violation.  You did not violate the rules, but your
           performance is of such significance that it's white. 
                       We've got other ones on the other arena. 
           I think those issues go very much toward the aspect of
           the safety culture there.  
                       MR. GWYNN:  I think that we -- if the
           agency did put together an inspection program to deal
           with safety culture we could do it, but I think that
           we would be fooling ourselves that it had any
           meaningful results in terms of evaluating the true
           safety culture at the facility.
                       MEMBER APOSTOLAKIS:  But there is a later
           question.  Maybe I agree with you that this would be
           very difficult for us to do, but there is also another
           side, that what we do intentionally or unintentionally
           does affect the safety culture of the plant, does it
           not?  Should we try to understand then our impact on
           the safety culture of the plant?  Would that be easier
           to do in terms of the inspections we do, in terms of
           other things we do?
                       There was this report in England where
           they had as an example of an overly prescriptive
           system that had a negative impact on the safety
           culture of the licensees, the American system.  Now,
           should that tell us something that we should be doing
           something about it, or no, they don't know what
           they're talking about, because that's something we are
           doing now.  It's not that we're trying to evaluate
           what the licensees' processes are.  We are doing that
           to them.  Do we understand enough to do that or is
           that a hopeless thing or maybe shouldn't be very high
           on the priority list?
                       MR. BROCKMAN:  Our processes -- put
           yourself in the laboratory with yourself being the
           professor.  I now have a process going on that has
           10,000 input variables to it, and I want to identify
           what's the impact of this one, and it has both
           positive and negative impacts and I want to determine
           are the negatives greater than the positives.  It's
           easy to do as long as I can separate out the other
           9,999, and that's what I don't know how to do.
                       MEMBER APOSTOLAKIS:  Okay.  I think I've
           got basically -- you will be out there fighting with
           us.
                       MR. BROCKMAN:  The other thing that would
           cause me a concern is the further we get down this
           path the greater the expectation by external
           stakeholders that we could be totally predictive on a
           step change would never occur.  You won't -- if you
           can do this you'll never go from green to yellow. 
           That can still happen no matter how much of a handle
           we've got on their safety culture --
                       MEMBER APOSTOLAKIS:  All right.
                       MR. BROCKMAN:  -- and I would be concerned
           about that.
                       MEMBER POWERS:  It seems to me the insight
           that Ken -- that I need to spend more time thinking
           about with respect to safety culture is the
           examination of the corrective action program and the
           root cause analysis.  I think if what I have is a
           great deal of confidence that there are a number of
           licensees that know exactly what they mean by safety
           culture.  I see documentation that they have
           identified deficient safety culture, they've sat about
           correcting it.  
                       Those corrections that they have
           documented, written down in magazines say we address
           these things are to my mind safety culture issues, and
           they seem to have gotten better performance by their
           metrics.  
                       Their metrics are a little more sensitive. 
           They're a little more comprehensive than yours, but
           they're their metrics and they did well. 
                       It seems to me Ken's offered us an insight
           here that we can get an appreciation appropriate for
           the regulatory program by looking at how they handle
           the root cause analyses in their corrective action
           programs, and that might be a better way to pursue it
           than looking for performance indicators and things
           like that.  
                       MEMBER APOSTOLAKIS:  And again, by safety
           culture -- maybe we should have said that much
           earlier -- I don't just mean the attitudes of people. 
           It's the totality of how they do business which
           includes the organizational issues, how certain
           analysis are done, and these are more tangible in my
           view.  I agree with Dana that it would be easier to
           see what would you do -- how would you do the root
           cause analysis here rather than trying to figure out
           what the attitudes of people are, which is really a
           hopeless task?
                       So I think I got your input --
                       CHAIRMAN SIEBER:  Enough to write your
           report?
                       MEMBER APOSTOLAKIS:  Well -- 
                       CHAIRMAN SIEBER:  Why don't we move on?  
                       MEMBER LEITCH:  Another question about the
           reactor oversight process.  There seems to be some
           confusion regarding the difference in the meaning of
           the green color between performance indicators and
           inspection findings.  Does that difference cause any
           confusion in the agency?  It causes us a little bit of
           confusion.  We see green meaning one thing in
           performance indicators and green meaning something
           different in the inspection finding areas.
                       MR. BROCKMAN:  Green means the same thing
           in both.  Green as -- but let me -- as has been
           defined, green means the issue of significance such
           that it is in the licensee's control bin.  That's what
           green means.
                       However, the American public does not see
           green that way, and we as engineers can define it all
           we want to and they don't accept that definition, and
           that's Dr. Lippoti's argument is you call it green,
           you've told me what it is.  That's very nice but I'm
           sorry.  I forget about that ten seconds after you tell
           me and green is good, and in performance indicators
           green is good, and all my residents have a sign out
           there at their resident's office, green is not equal
           to good when it comes to inspection findings.  It's
           still an issue.
                       MEMBER APOSTOLAKIS:  So it doesn't mean
           the same thing.
                       MR. BROCKMAN:  And that's the dilemma you
           get to is we as engineers can define it all we want,
           which we've done in this program, and it is a
           continual challenge to put that in perspective.  More
           and more that it's out there the more people are
           understanding what we're saying.
                       There was a point that Jeff brought up
           earlier where he -- everybody is understanding what's
           going on at Cooper, in the neighborhood of Cooper.  I
           can promise you at Fort Calhoun the public does not
           have an understanding of white issues and how they're
           dealing to the degree they do at Cooper.  Why?  They
           haven't had any.  And until you get this being played
           out in the local arenas and they see one and have to
           deal with it there's going to be confusion out there.
                       Art, your thoughts?
                       MR. HOWELL:  No.  They clearly are
           different.  Licensees strive to maintain themselves in
           the green band for PIs and they strive very hard not
           to have any green inspection findings or any other
           inspection findings for that matter.
                       MEMBER LEITCH:  I have another question
           about the reactor oversight program.  It seems to me
           that there are apparently different weights
           unconsciously applied to the different cornerstones. 
           For example, there was one plant in Region IV that we
           read about in our briefing material -- I think it was
           Callaway -- that had three radiation protection
           issues, and so they had three white findings in
           radiation protection.  There was another plant, San
           Onofre, that had a major operational event, switch
           gear fire, wound up melting the turbine bearings down
           and grinding to a stop, and that got a non-sited green
           violation.  At least that's the way I read it.
                       VOICE:  You're accurate.
                       MEMBER LEITCH:  I think -- and it seems to
           me that those are just disproportionate.  I'm not
           questioning the significant determination process if
           the blanket was properly followed and correctly led
           you to those conclusions, but do you find in your mind
           that there's something disproportionate about those
           two findings?
                       MR. HOWELL:  Really, one of the challenges
           that we have is how to deal with issues that don't
           lend themselves to PRA analysis, and that's really
           what we're talking about.  And we've made an effort to
           define deterministically what's important and what
           isn't in this first year, and as we've gone along
           we've found as Pat indicated that issues heretofore
           that perhaps we wouldn't have considered to be
           particularly important or spend a whole lot of time
           looking at have been elevated in importance vis a vis
           the new process, and certainly that's also true in the
           other direction.
                       And the question is are we in the right
           place yet, and I think there's still a number of
           questions out there and a number of these
           deterministic SDPs where the results are getting us to
           the right place.  Are we truly treating -- is it truly
           appropriate for example to have ALARA findings cross
           a green-white threshold or a white-yellow threshold
           for that matter when on the other hand you can have a
           fire at a plant melt your turbine, challenge the
           operators, put them under stress, et cetera, and so
           it's very difficult to make comparisons in terms of
           significance.
                       MR. GWYNN:  I'd like to just make a
           comment at this point that I think helped me to put
           the ALARA findings at Callaway into good perspective
           from a safety standpoint.  I was visiting the Palo
           Verde plant with Commissioner Merrifield not too long
           ago and as we were being briefed they raised the issue
           of the Callaway white findings in ALARA, but right
           behind the head of the vice president at the plant
           were their ALARA statistics, and for three very large
           power reactor units their total dose to their
           operating staff was less than the dose to the
           operating staff at Callaway for one smaller unit.
                       And how can you say that we're not putting
           our attention in the right place at Callaway by
           focusing on ALARA when in fact they have those types
           of results at their facility?  On the other hand at
           San Onofre there were no safety systems that were
           challenged as a result of the fire and explosion that
           occurred.  And so I think from a risk standpoint the
           program is taking us in the right direction at both of
           these facilities.  It's just -- I may be wrong, but
           that's my belief.
                       MEMBER LEITCH:  I don't mean to down play
           in any sense the Callaway incident.  In fact radiation
           safety is a critical part of our business.  That's not
           where I'm going.  What I'm trying to say is did the
           process -- and I believe the process was properly
           applied as per the process, but my question really is
           did the process lead us to reasonable conclusions?  
                       MR. BROCKMAN:  We asked the same question
           when we were processing the Callaway aspect.  There
           was a lot of debate going back here -- three whites as
           to where this is going.  It was a great deal of
           exactly what you're saying.  Is this taking us to the
           right point?
                       One of the things we used to reach our
           decision was we're going to follow the process in the
           first year and then we're going to identify that as
           part of the feedback process, this needs to be looked
           at.  We're not going to set off down the path and in
           the first year, which is the initial implementation
           year, say first time we come across a bump in the road
           we throw away the process.  What credibility do we
           have with our stakeholders if the first time we hit a
           bump in the road we abandon the process?  We chose not
           to.
                       If that in fact had not been given as one
           of the issues to be looked at at the end of the year
           of lessons learned -- and it was if you remember, and
           the internal working groups and the external working
           groups, the SDP for ALARA was one of the issues that
           needed to be looked at to see is it coming up in the
           right spot and if in fact it's being looked at and
           there are revisions coming out.  
                       So I would say your concern is one a lot
           of people had and there are certainly some marginal
           adjustments that are being made to it that may
           preclude such an imbalance in the future.  I'm not
           sure exactly where it's at at the moment, but I know
           it's something that's definitely being looked at
           because it just didn't pass the initial wow test.
                       CHAIRMAN SIEBER:  When I looked at that I
           didn't come to the same conclusion because in my
           opinion the regulator's job and the licensees' job are
           the same, which is protection of the public health and
           safety, protection of the health and safety of their
           workers, which is Part 20 and the protection of the
           reactor and cone system pressure boundary and your
           mitigating systems and so forth, but if you melt a
           turbine bearing that's dollars and outage time, not
           safety related, so that tells me the whole
           significance determination process one way or another
           worked in this case to distinguish between what is
           important from a regulatory standpoint from those
           things even though they may be costly are not safety
           significant, and so that's what I got out of that. 
           That's the way I would have looked at it.
                       MEMBER LEITCH:  But it wasn't just the

           main unit though.  There were other aspects of fire --
           failure to identify precursors that could have led
           them to the --
                       MR. BROCKMAN:  Yes.  And there's a lot
           there, and I can go into that, but very much all of
           that was in the power generation side of the house. 
           And what it really becomes is appropriately
           communicating that to all the concerned stakeholders,
           because that's what we're talking about.  Three whites
           versus one white.  Will that define the action that we
           took?  And we were questioning not whether it was a
           white issue.  It was how many.
                       The other part of it very much though is
           to us doing our job in communicating that, generating
           confidence in our external stakeholders that we're
           appropriately regulating the industry, making sure the
           industry is appropriately focused on the corrective
           actions in addressing embracing issues, addressing
           them, correcting them.  Those are where you get out on
           some of the other parts of it.  And it's an
           interesting dilemma at the moment when everything is
           not perfectly risk informed.
                       CHAIRMAN SIEBER:  But that's what safety
           culture is, is being able to make these decisions
           between what is significant from the standpoint of
           human beings and the safety of the plant versus what
           is significant as far as being commercially viable is
           concerned, and that is something that has to be taught
           by the agency.
                       MR. GWYNN:  We have both of these issues
           on the agenda for today, and --
                       CHAIRMAN SIEBER:  We may have covered
           them.
                       MEMBER POWERS:  I think there's a lot more
           that we want to go into in a couple of those issues,
           but they follow this track.
                       MR. GWYNN:  Yes, and I would like to note
           that Gail Good, who's the branch chief for our
           emergency preparedness health physics and safeguards
           inspections here in Region IV has joined us in the
           room, and she will be presenting the Callaway ALARA
           experience a little bit later this morning.  And we
           have the SONGS electrical fire on the agenda for this
           afternoon.
                       VOICE:  So what's next?
                       CHAIRMAN SIEBER:  Let me suggest at this
           time since we are a few minutes behind, if you are
           finished, which it appears that we are, maybe we can
           take a 15 minute break at this point.
                       (Whereupon, a short recess was taken.)
                       CHAIRMAN SIEBER:  The next presentation
           we're going to listen to is the significance
           determination process as it's implemented here in
           Region IV, and I think after that we'll break for
           lunch because lunch is a hot lunch, and if we don't
           break then it will not be a hot lunch.  And so let's
           move briskly through the SDP.
                       MR. GWYNN:  Our two senior reactor
           analysts, Kriss Kennedy and Troy Pruett, will be
           making this presentation.  I've asked Kriss, the
           primary presenter, to try to skip through some of the
           information and maximize the time focus on areas that
           might be of interest to the committee.
                       Kriss?
                       MR. KENNEDY:  Good morning.  My name's
           Kriss Kennedy.  I was selected as SRA, started the job
           in November of 2000, started the training in December,
           and I'm still in the qualification process as is Troy,
           who you met earlier.  My background is I started out
           in the agency as an operator licensee examiner.  I've
           been the resident inspector at Comanche Peak and the
           senior resident inspector at Arkansas Nuclear 1.  
                       The senior reactor analysts in Region IV
           are assigned to Division of Reactor Safety.  Art
           Howell is our boss and we are the focal point for risk
           informed activities in the region.  In addition to
           Troy and myself we have a branch chief in the Division
           of Reactor Projects that was previously qualified as
           an SRA, and we also have three staff members that are
           going through the advanced risk training that some of
           the regions are sending their people through.  In
           fact, they're in their second week of training this
           week, so those are the resources we have available in
           Region IV.
                       We're going to go ahead and skip the next
           couple of slides where I was prepared the discuss the
           SRA functions in Region IV, the various tasks that we
           perform, and we'll go directly to the slide entitled
           status of risk tools.  I think that may get us more
           into some of the discussion areas that you are
           interested in.
                       CHAIRMAN SIEBER:  One quick question which
           would prompt a yes or no answer --
                       MR. KENNEDY:  Okay.
                       CHAIRMAN SIEBER:  -- you said that these
           are the resources available to Region IV to conduct
           these functions.  Are those resources in your opinion
           adequate, two people?  Yes or no?
                       MR. KENNEDY:  Yes or no.  
                       CHAIRMAN SIEBER:  Everyone is ready to
           take notes.  
                       VOICE:  You will be quoted.
                       MR. KENNEDY:  Yes.  I think right now they
           are.  If the process goes where the program office
           wants it to go it will be enough also.  There -- I
           guess I'm not going to give you a yes or no answer.  
                       CHAIRMAN SIEBER:  I accept that.
                       MR. KENNEDY:  During the first year of --
                       CHAIRMAN SIEBER:  You've already said
           enough.
                       MR. KENNEDY:  During the first year of
           implementation and during even into the second year of
           implementation there's a lot of startup costs with
           using the new process.  The phase two worksheets which
           we'll talk about more are just coming out, inspectors
           are learning how to use them -- actually using them
           and so we're pretty busy.
                       CHAIRMAN SIEBER:  I imagine.
                       MR. GWYNN:  I'd like to just make a
           parenthetical note here that Region IV management made
           a decision early on in the process that we were going
           on select the very best people that we could to be
           senior reactor analysts in the region because they
           were such critical positions, and as a result those
           people are also very promotable.  We had two of the
           very most talented senior reactor analysts that were
           available to the agency.  Both of them were promoted
           to branch chief positions and that's why both of our
           SRAs at this point in time are in training.
                       But we have two highly talented SRAs in
           training.  Their work load will go down as soon as
           they complete their training, and I think that we'll
           be back in a more normal mode of operations and then
           Kriss might have been able to answer yes to your
           question emphatically.
                       CHAIRMAN SIEBER:  Thank you.
                       MR. KENNEDY:  And Troy didn't get an input
           either, so Troy may have --
                       MEMBER POWERS:  I guess the question goes
           on.  It will probably get into it as you go through
           your presentation, but I note one of the slides that
           you skipped over is the development of comprehensive
           risk informed resources, and I'm going to be anxious
           to know what kind of risk resources that you have in
           the area of fire risk, shutdown risk, and seismic
           risk.
                       MR. KENNEDY:  You haven't looked at the
           last slide.  Those are actually listed as challenges
           that we'll get into.
                       MEMBER POWERS:  If the resources are
           adequate then why is what we have adequate?
                       MR. KENNEDY:  If we could go on to a
           couple of slides I'll hold that as a question and
           we'll go on to that.
                       This portion I wanted to discuss the
           status of the risk tools that we have available to us,
           and primarily these risk tools come out of manual
           chapter 609, significance determination process for
           the first part.  The risk informed inspection
           notebooks also known as the SDP phase two
           worksheets -- in Region IV NRR has issued eleven of
           the 15 worksheets for Region IV plants.  We're at 73
           percent there.  NRR has also has a processing program
           to go out and benchmark those phase two worksheets,
           make a site visit, sit down with the licensees, PRA
           folks, and go through system by system, compare the
           results that the licensees get with their models,
           compare the results that we get with the worksheets,
           and identify any changes or errors that we need to
           correct on the worksheets.
                       MEMBER POWERS:  I take it this has not
           been done with Waterford?
                       MR. KENNEDY:  It has not been done with
           Waterford.  No.
                       MEMBER POWERS:  Because they were wincing. 
           I mean, they feel left out.  They feel hurt and
           unloved and unwanted.
                       MR. KENNEDY:  Well, they shouldn't. 
           There's only been four benchmarking trips to date. 
           Three of them have been in Region IV, so it's a
           process that's ongoing and will continue at least
           through -- to completion, which may be the end of next
           fiscal year, so some plants will wait -- will have to
           wait.
                       The other risk tool -- one of the other
           risk tools that we use is the standardized plant
           analysis risk models, the SPAR models.  Those were
           developed by INEL.  They've come out with revision
           three for some plants.  In Region IV we have eight of
           15 revision three models out, and of those eight none
           have been QA.  None have gone through a site QA
           process.
                       MEMBER POWERS:  What is the meaning of QA? 
           They've presumably complied with the NRC's mandates on
           software QA.
                       MR. KENNEDY:  By QA I really mean similar
           to a benchmark trip where they go out to the site with
           the model, compare the results of the SPAR model to
           the results of the licensee's model and identify where
           the differences are.
                       MEMBER POWERS:  So it's really a
           verification then?
                       MR. KENNEDY:  Yes.  The term QA comes from
           the revision two models where they issued a
           revision -- what they called 2I and then after the QA
           process they would call it revision 2QA, so we're at
           revision 3I for these plants and once they're QA'd
           they'll be a rev3QA.
                       CHAIRMAN SIEBER:  Quick question.  When
           you make a benchmark trip to a licensee's facility
           you're comparing the results of the SPAR model against
           a licensee's PRA.  What criteria if any do you use to
           judge the quality of the licensee's PRA?
                       MR. KENNEDY:  We're not really there to
           review the quality of licensees' PRAs.  That's the
           first part.  But what we do is when we identify
           significant differences in the results of the
           worksheets and the results of the licensee's model
           then we start asking questions, figure out what they
           have in their model, why they're getting different
           results, and if we're looking specifically at that
           area and there's a specific problem with the
           licensee's model in that area -- although that's not
           the norm.  It's typically a problem with the
           worksheet -- then we'll point that out.
                       And we had one example of that at South
           Texas I believe where they -- we identified an error
           in their model.  It was a minor error with the steam
           generator PRBs, and --
                       MR. PRUETT:  The PRBs.  They assumed they
           only needed one PRB for an accident.  In reality, we
           challenged that, and I believe they needed to have a
           minimum of four.
                       MEMBER POWERS:  This is not a trivial
           mistake.
                       MR. KENNEDY:  Well, in the overall impact
           on the PRA it was not a large significant error.
                       CHAIRMAN SIEBER:  Now, if you're using the
           SDP process for enforcement for example or to evaluate
           a licensee application to NRR even though NRR will
           probably do that examination, or ask CENED-ED-EH to do
           it, as they have in the past, would you do some
           different kind of evaluation of the licensee's PRA?
                       MR. KENNEDY:  The SDP is designed to
           evaluate inspection findings, performance issues that
           are identified at the plant.  So for in the case of
           amendment requests where a risk analysis is done that
           is done using standard risk analysis techniques and is
           done by headquarters or other contractors.
                       CHAIRMAN SIEBER:  Okay.
                       MR. GWYNN:  When we get into the
           enforcement arena and we're talking about the risk
           significance of an issue, then typically that is
           extensively discussed at the enforcement conference
           with the licensee and differences between our results
           and their results are determined as a part of that
           pre-decisional enforcement conference.
                       MR. BROCKMAN:  But if it's a regular
           conference which is what the new process has, as
           opposed to the old pre-decisional enforcement
           conference, those same rules apply.  Significant
           discussion on the risk insights that they gain.  In
           fact, we've recently had one with Cooper and there was
           a lot of subsequent submission of material back and
           forth because of inadequacies we found in their
           presentation on their risk assessment.
                       MEMBER APOSTOLAKIS:  A related question --
           I noticed in the -- in attachment two of our notebook
           here, which is the attachment to the letter you
           transmitted to Mr. Ray of Southern California Edison. 
           It says somewhere here that the team concluded that
           the risk assessment was conservative.  Using the
           current leading probablistic risk assessment model in
           the San Onofre office safety monitor in Unit 3
           condition of core damage probability for the event was
           calculated as 1.4 x to the minus four, and the team
           noted that the assessment did not take that into
           account.
                       Now, the thing is it seems that you are
           using additional risk tools in addition to SPAR and
           the SDP --
                       MR. KENNEDY:  Right.
                       MEMBER APOSTOLAKIS:  -- worksheets, and in
           this case it was a safety monitor signing off.  Now,
           has anyone from the agency reviewed this safety
           monitor to know what's in it and that it does a good
           job calculating core damage probabilities?
                       MR. KENNEDY:  I don't know that there's
           been any formal review of that particular tool at San
           Onofre, although just to note -- and we'll get into
           this -- we also used the safety monitor when we did
           the benchmarking trip at San Onofre and compared those
           results too.  But as far as a formal review of their
           safety monitor, I don't believe that's been done.
                       MEMBER APOSTOLAKIS:  But the South Texas
           Project PRA has an excellent reputation in the
           community, and we were just told -- 
                       MEMBER POWERS:  They couldn't even get
           their success criteria right.
                       MEMBER APOSTOLAKIS:  So, I mean, just
           because they have television screens in every room at
           San Onofre that doesn't mean that their underlying
           models are meaningful.
                       MR. KENNEDY:  And we agree 100 percent
           with you, and that's why we don't rely solely on the
           licensee's models and tools and information to come up
           with a risk assessment.  We --
                       MEMBER APOSTOLAKIS:  So in this case you
           also did your own calculations, because it says the
           core damage probability was calculated at San Onofre?
                       MR. KENNEDY:  Yes.  
                       MR. BROCKMAN:  We did.  In fact, we used
           the -- actually I was only here for the very beginning
           of this event and then I was in training the next
           week, but we did run this on this SPAR model.
                       MEMBER APOSTOLAKIS:  You did?
                       MR. BROCKMAN:  Yes.  In fact, if my memory
           serves me correctly, Jack Shackelford had that -- ran
           that particular -- was our SRA who did that.  Our
           process would be -- is any time on a daily basis that
           we identify an issue -- an operational issue we get
           the SRAs involved with it very early, and for
           something like this, a regulatory conference, we would
           have our SRAs running their independent analysis.  We
           would have that being confirmed with insight from
           headquarters, research, IIPB, the NRR risk insights so
           that we would have a relatively consistent position as
           an agency.
                       This statement here then would be made
           because there was a reasonable agreement between the
           two numbers.
                       MEMBER POWERS:  I guess I'm curious what
           you mean by you ran it on the SPAR model.  A SPAR
           model's not a fire model.  It doesn't have a fire
           growth model in it.  It doesn't have a smoke model in
           it.  So what does it mean that you ran this problem?
                       MR. KENNEDY:  Essentially we input the
           transient into the SPAR model.
                       MEMBER POWERS:  Yes.  But that doesn't --
                       MR. KENNEDY:  The transient that was
           caused by the fire.
                       MEMBER POWERS:  That doesn't explore what
           the fire could do.  That wasn't even questioned.
                       MR. KENNEDY:  It did not explore what the
           fire could have done.  We evaluated what actually
           happened.  The transient that resulted from the fire
           is what was evaluated.
                       MR. GWYNN:  And that's our typical
           approach, including the typical approach of involving
           both NRR PRA experts and research PRA experts in
           validating our results for those significant events
           that they were contemplating to respond to as a result
           of our risk assessments.
                       MR. BROCKMAN:  And this is an essential
           difference.  An event under the new program is
           evaluated for what happened, whereas an identified
           condition is identified for what could happen.
                       MEMBER POWERS:  We'll come back to that I
           suspect.  For instance, in one of your findings was
           that there were unqualified fire barrier penetration
           seals --
                       MR. KENNEDY:  Right.
                       MEMBER POWERS:  -- and a conclusion was
           reached that that was not risk significant based on
           ignition frequency.  I don't really understand
           ignition frequencies myself, but when I say I look at
           risk significance on a penetration barrier I really
           should be looking at the ignition frequencies on two
           sides of the barrier, and I should be looking at the
           probability if the barrier fails, none of which show
           up in most fire protection models and certainly don't
           show up in a SPAR model.
                       MR. KENNEDY:  That's correct.  A SPAR
           model does not model fires, external events, and most
           of the fire studies done at the plant are really
           screening type studies and not risk studies.
                       MEMBER POWERS:  And most of them assume
           100 percent liability of fire bearing penetration
           seals.
                       MR. KENNEDY:  Right.  That's true.  
                       MEMBER POWERS:  And so when you're looking
           at the risk significance of a penetration seal it's
           going to come up zip.
                       MR. KENNEDY:  It depends on the issue.  In
           the event where the inspector has identified that a
           fire wrap around a cable in a room is degraded or is
           not in accordance with the tested configuration --
                       MEMBER POWERS:  I can do that one by hand. 
           But a penetration -- that's a real risk item.  I'm
           sure I can do that one by hand.
                       CHAIRMAN SIEBER:  Well, that tells us as
           we said in our research report we need to do more work
           as an agency on fire, because there's a lot of stuff
           that isn't --
                       MEMBER APOSTOLAKIS:  It's not just fire. 
           It's also a bigger issue here.  We've got to move into
           risk information inspection processes of the
           regulations in general.  It seems to me that we are
           not spending or paying enough attention to the tools
           that we will be using --
                       CHAIRMAN SIEBER:  That's right.
                       MEMBER APOSTOLAKIS:  -- to make these
           assessments, and even the SPAR models there is an
           underlying computer problem which has never really
           undergone any kind of review.
                       Now of course the situation is not very
           bad because you have independent assessments.  You use
           SPAR.  They use -- the licensee uses his own model and
           so on, but here is a safety monitor -- people have
           been talking about the San Onofre safety monitor for
           a long time now, and pretty soon it will be accepted
           because we've been talking about it.  It's like a
           celebrity.  You're well known for being well known.
                       MEMBER POWERS:  The other problem --
           inconsistency that I see is we plow down through these
           thermohydraulic codes worrying about every twitch in
           the computer language, and make arguments for
           compensating errors and things like that to the third
           decimal point --
                       MEMBER APOSTOLAKIS:  That's right.
                       MEMBER POWERS:  -- and then in the risk
           assessment tools we say, Well, we use SPAR for a fire
           problem.
                       MEMBER APOSTOLAKIS:  There is a reason for
           that, because the risk guys are better than the
           thermohydraulic system.
                       MEMBER POWERS:  Granted.  
                       CHAIRMAN SIEBER:  Let us move on.  
                       MR. GWYNN:  I'd like to just mention that
           this is a risk informed program.  We have very smart
           people.  We pay them a lot of money to be smart.
                       MEMBER APOSTOLAKIS:  Do they agree?
                       MR. GWYNN:  If in fact there was a
           significant potential associated with a fire
           protection feature at a plant that could have and
           would have significantly adversely contributed to an
           event had some circumstance not occurred, some
           unplanned and undesigned circumstance not occurred
           then we would pay close attention to that, and we can
           make regulatory decisions even though the risk numbers
           don't quite get us there.
                       MR. BROCKMAN:  That's a good point.  All
           I want the risk number to do is get me to the
           ballpark, and I want it to bring me to the ballpark on
           several nights when the game's going to be rained out
           too.
                       MEMBER POWERS:  But I think -- I'll accept
           that argument.  I even like that argument, but here
           I'm wondering if it gets you to the entirety of a
           ballpark or are you only looking at first base, and
           when you've got a tool that you're jerry-rigging to
           work on one kind of a problem because you don't have
           a real suitable tool for that -- it's not your fault.
           You only have the tools that people are willing to
           produce for you, but it seems to me that you've got to
           squat. 
                       It's the squeaky wheel that gets the
           grease in a time of limited resources, which is the
           problem the agency has.   They've only got so many
           guys to generate models that here's an area that what
           your challenges -- it's really important.  This
           affects the way you do your job.  This is a front line
           problem the agency -- there's nothing the agency
           shouldn't be pulling out to address for the guys that
           are out on the line doing things.  If this is what
           they see as a challenge address it.  Don't put it off
           and say we don't need to do this.  If you guys need
           these tools you need these tools.
                       MR. KENNEDY:  Let me comment on something
           you said earlier.  I agree with I think everything you
           said.  We rely on licensee IPEs that have been
           reviewed but not QA'd.  We don't get -- necessarily
           licensees don't submit updates to their IPEs to us,
           and our tools don't -- are not very good, and we'll
           get into this more on considering external events.  I
           think Troy and I agree with you 100 percent.
                       MR. HOWELL:  But I would add that the
           exercising of the tools we do have has put the
           spotlight on some of these questions.
                       MEMBER POWERS:  Don't get me wrong.  My
           that goes off to you guys.  I think you do a fantastic
           job with the tools you have.  I just think that
           getting you better tools needs to have a higher
           priority in the agency and plowing down through
           thermohydraulic codes to the fifth decimal point --
           it's a useful exercise.  Don't get me wrong.  And it
           may be important, but right now you've got a problem
           now, today.  Future licensing actions that had to do
           with realistic assessments of thermohydraulics are
           things that can be put off.
                       MR. KENNEDY:  This slide -- 
                       MEMBER POWERS:  Not to mention the risk
           analysts are better than the thermohydraulics --
                       MR. KENNEDY:  This slide is a summary of
           the results of our first three benchmarking trips in
           Region IV, and as it turns out the first three in the
           country.  The only one that has a final report out is
           the Diablo Canyon one, but at SONGS -- let me go
           through what these mean.
                       Rev zero indicates the worksheets that we
           had issued when we arrived onsite, and we did a
           comparison between those rev zero worksheets and the
           licensee's model, and by non-conservative I mean that
           the SDP came out with a lower color than what the
           licensee's model would have indicated, and so 13
           percent were a lower color than they should have been. 
           Twenty-two percent were a higher color than they
           should have been, and 65 percent were the same
           results.  We identified some corrections to be made to
           the worksheets, and you can see the final numbers
           there, 4 percent non-conservative, 9 percent
           conservative, and 87 percent same results.
                       Keep in mind that the process when we --
           if we get a white or greater color we're going to do
           a phase three evaluation, so this tool tells us when
           we need to go on and do a more detailed evaluation. 
                       The SPAR model --
                       CHAIRMAN SIEBER:  Looks like that is the
           worst of the bunch --
                       MEMBER APOSTOLAKIS:  It's very bad.
                       MR. KENNEDY:  Not plant specific.
                       MEMBER APOSTOLAKIS:  Not plant specific --
                       MR. KENNEDY:  It's supposed to be -- they
           take aspects of the plant model or the plant
           configuration and they put it into the SPAR model, so
           it's supposed to be a --
                       MEMBER APOSTOLAKIS:  Well, they have done
           30 plant specific -- they developed 30 plant specified
           models.  Is San Onofre one of them?
                       MR. KENNEDY:  Yes, sir.  That's a Rev 3I
           no QA done on that model yet.
                       MEMBER APOSTOLAKIS:  Sixty-four percent?
                       MR. KENNEDY:  Yes.
                       CHAIRMAN SIEBER:  Non-conservative.
                       MEMBER APOSTOLAKIS:  That means it may not
           be accurately non-conservative.  Just disagrees with
           the licensee's assessment?
                       MR. KENNEDY:  Yes.  
                       MEMBER APOSTOLAKIS:  And it's not that
           much better for Diablo.
                       MR. KENNEDY:  Well, it actually is
           significantly better.
                       MEMBER APOSTOLAKIS:  Twenty-nine percent
           non-conservative.  My goodness.  
                       MR. PRUETT:  That's non-conservative to
           the licensee's model or to the notebook?
                       MR. KENNEDY:  Non-conservative to the
           licensee's model.
                       MR. PRUETT:  Okay.  
                       MR. GWYNN:  Before you go on to Diablo
           Canyon I think it would be of interest to hear whether
           this site visit identified any anomalies with the
           licensee's  model as the South Texas facility.
                       MR. KENNEDY:  None jump out.  I don't
           remember that there were any.  Of course, they use the
           PLG model, so it's very difficult to find problems
           with those large event models, so --
                       CHAIRMAN SIEBER:  Right.  They've got a
           lot of chains.
                       MR. KENNEDY:  But in SONGS' case I don't
           think we identified anything where the licensee said,
           Oh, yes, this is an error in our model that we need to
           do something about.
                       In the Diablo Canyon case you can see the
           numbers there.  The SPAR results were a little better. 
           The -- and the final results with the fixes were very
           similar.
                       CHAIRMAN SIEBER:  Who's their PRA vendor?
                       MR. KENNEDY:  PLG also.
                       CHAIRMAN SIEBER:  PLG?
                       MR. KENNEDY:  Yes.  The first three were
           all -- San Onofre is not.  Right.  So Diablo and South
           Texas were PLG.  
                       CHAIRMAN SIEBER:  Who was San Onofre, do
           you know?
                       MR. KENNEDY:  They used -- I don't know
           who their vendor was, but they used the typical small
           event tree, large -- see the numbers for Diablo
           Canyon?  The other thing we looked at that was
           beneficial was San Onofre, Diablo, and South Texas --
           their models all purport to include some aspect of
           external events.  And at Diablo Canyon we found that
           the affects of fire, flood, and seismic initiators in
           some cases increased the results by one order of
           magnitude, so for some scenarios, not all, the SDP
           would give results that were one order of magnitude
           lower than the licensee's model when you considered
           external events.
                       MEMBER APOSTOLAKIS:  So Diablo doesn't
           have external events?
                       MR. KENNEDY:  Diablo does.
                       MEMBER APOSTOLAKIS:  Does?
                       MR. KENNEDY:  Yes.  It does have, and
           that's --
                       MEMBER APOSTOLAKIS:  So the 29 percent
           refers to -- the licensee did it with external events?
                       MR. KENNEDY:  Yes.  No.  I'm sorry.  Let
           me go back.  The numbers that you see are internal
           events only.
                       MEMBER APOSTOLAKIS:  For Diablo?
                       MR. KENNEDY:  For Diablo.
                       MEMBER APOSTOLAKIS:  And the South Texas?
                       MR. KENNEDY:  And -- well, South Texas is
           two numbers, but at Diablo the external results are
           not listed but the words there indicate that it's kind
           of a summary that -- for those -- we found up to an
           order of magnitude difference when you considered
           external events.
                       MEMBER APOSTOLAKIS:  I was always under
           the impression that by using the worksheets you would
           be getting very crude results and that you should be
           using PRA models, but this SPAR thing now --
                       CHAIRMAN SIEBER:  It's the other way.
                       MEMBER APOSTOLAKIS:  It's the other way.
                       CHAIRMAN SIEBER:  That's the way it looks.
                       MEMBER APOSTOLAKIS:  And both for Diablo
           and San Onofre I would rather go with the sheets.
                       MR. KENNEDY:  Yes.  A couple of things
           about the SPAR model though.  They -- we don't rely on
           them too much right now for this reason, because we
           don't really trust the numbers that we're getting, and
           so --
                       MEMBER APOSTOLAKIS:  But the worksheets
           are also based on SPAR, aren't they?
                       MR. KENNEDY:  No.  The worksheets are
           based on the licensees' IPEs.
                       MR. BROCKMAN:  One thing to look at
           here -- let's look at the worksheets revenues with the
           fixes.  At SONGS we would basically be saying that 91
           percent of the time -- that's the 87 plus the 4, the
           regulatory posture -- 87 percent of the time the
           regulatory posture that we would propose off the
           worksheets would be what we would anticipate would be
           the licensee agreeing to for the reg conference.
                       The key thing -- look at Diablo.  SDP is
           conservative.  Thirty-six percent of the time the
           results of our regulatory conference would be to
           decrease the significance of the issue.  Now, that's
           great from the aspect that we're looking at
           everything.  It certainly can result in a public
           relations challenge.
                       MR. HOWELL:  Which it's why it's important
           to do more than just exercise the worksheets before
           you ever get to that point.
                       MR. KENNEDY:  What we typically do is when
           we -- and typically we haven't done a lot of these,
           but if we come out with some results greater than
           green on the worksheets the first place I don't go to
           is -- I don't go to SPAR the first thing.  I go to the
           licensee's IPE and make sure I have enough data at IPE
           and I'm looking at the systems they have and what
           their risk achievements are for those systems and --
                       MEMBER APOSTOLAKIS:  But why when the
           office of research comes to us and they advertise SPAR
           as a major achievement they never tell us this?
                       MR. KENNEDY:  I think they use SPAR -- I
           don't want to be put in the position to defend
           research, but I'll provide some defense.  
                       When they use these SPAR models they use
           them for accent sequence precursor evaluations, and
           they are much more skilled in going into the model and
           making changes to the model than most SRAs are, so
           they actually get into the model and do a lot more
           manipulation, do a lot of research to determine the
           proper way to model whatever they're trying to model
           and use it for that.
                       MEMBER POWERS:  I come back to my
           thermohydraulics.  We don't let people do that in the
           thermohydraulics code.  That code -- you can't change
           anything once it's been approved, and it doesn't do
           you -- it doesn't help you to get a model that has to
           be tweaked to get the right answer.
                       MR. KENNEDY:  We would agree.
                       MR. PRUETT:  We agree.  Kriss can speak
           for himself, but from my perspective I'd like to see
           more time spent on developing the SPAR models,
           improving the end-user interface so that I don't have
           to make significant manipulations to the model.  I can
           point and click on certain basic events and initiating
           event categories and get a reliable answer.  Right now
           I can't do that.
                       MEMBER POWERS:  You've got a full-time
           just interpreting the results.
                       MR. PRUETT:  That's right.
                       MEMBER APOSTOLAKIS:  Now, why shouldn't
           the agency demand that every licensee do a complete
           level to PRA?  How much is it?  Is it the million
           dollars?  Big deal.  Look at the --
                       VOICE:  Level two?
                       VOICE:  Big deal to you.
                       MEMBER APOSTOLAKIS:  Well, look at all the
           uses.  We have to fight and try SPAR, and there is
           nothing and do this and do that.  If we're going to
           have risk informed regulations we should have good
           risk assessment tools.
                       CHAIRMAN SIEBER:  The risk informed
           regulations is optional for the licensee.
                       MEMBER APOSTOLAKIS:  Right.
                       CHAIRMAN SIEBER:  And so you can't make
           him do something that's optional.
                       MEMBER APOSTOLAKIS:  Speaking of optional,
           can they tell you do not use the revised oversight
           process when you inspect us, oversee us? Can they tell
           you that?  So it's not optional.
                       MR. BROCKMAN:  Yes, they can.
                       MEMBER APOSTOLAKIS:  They can?
                       MR. BROCKMAN:  They could do that.  
                       MEMBER APOSTOLAKIS:  But has anyone done
           it?  No.
                       MR. BROCKMAN:  The only thing that was
           done Cook as they were coming up said we're not quite
           ready yet.  We don't have the data.  They were
           captured in O-3 process, that we need to get our
           baseline going and they wanted about a six-month delay
           in getting into it because of the lack of
           historical --
                       MEMBER APOSTOLAKIS:  First of all, it's
           not a million dollars because they've already done the
           IB.  We're talking about documenting the IB, having a
           serious review of it, and then all these issues are --
                       MEMBER POWERS:  If you're talking about a
           level two.
                       MEMBER APOSTOLAKIS:  That's what we're
           using.
                       MEMBER POWERS:  I don't think you can get
           a level two done for a million dollars, and you
           certainly can't get one that anybody would agree with.
                       MEMBER APOSTOLAKIS:  You can get a full
           level three for a million and a half, so --
                       MEMBER POWERS:  You can't get one that
           anybody will agree with.
                       MEMBER APOSTOLAKIS:  What, because of the
           nature of the severe accident -- those are you guys.
                       MEMBER POWERS:  But --
                       MR. GWYNN:  The South Texas Project folks
           tell me that they spend about a quarter of a million
           dollars a year just maintaining their PRA, and so the
           initial cost is not the entire picture.  But whether
           or not the licensees are required to have level two
           PRAs is a matter of policy that we don't have -- it's
           not our decision, and so --
                       MEMBER APOSTOLAKIS:  I understand that. 
           Sometimes these simple questions come to you and you
           say, Gee, why didn't I think of that?  Here we're risk
           informing a lot of things, and yet we are willing to
           leave with models that have not been reviewed, that
           are incomplete, and everybody knows that, and the
           question is why?  I can see a reporter asking that
           question if there is a nuclear incident some place. 
           You're doing all this and you don't have the
           underlying tools.
                       CHAIRMAN SIEBER:  Well, this is why it's
           risk informed instead of risk determined. 
                       MEMBER APOSTOLAKIS:  It seems to me if
           it's risk informed you should be able to assess the
           risk to the best of your ability.
                       MR. GWYNN:  If you look at the nuclear
           power industry historically when we first started down
           this road we would never have built the first power
           reactor if we took the approach that it's got to be
           perfect before you build the first one, and so these
           tools are being improved over time.  The question is
           whether or not they're adequate for the thing that
           we're using them for today.  And I think that
           they've -- based on the results that we've achieved
           over what we had before and what we have now I think
           that we've seen an improvement as a result of
           implementing this tool --
                       MEMBER APOSTOLAKIS:  There's no question
           that there's an improvement.  It's just it's kind of
           odd we don't have the right tools.
                       CHAIRMAN SIEBER:  Well, we know that, and
           we have determined that we don't know how much they
           cost.
                       MEMBER APOSTOLAKIS:  No, no.  We know very
           well.  
                       MR. KENNEDY:  Not to add fuel to the fire,
           if you look at South Texas, when we -- this was the
           third visit made in the country.  We showed up in
           South Texas with the rev zero worksheets and found
           that there was a fatal flaw in the worksheets.  They
           considered -- the worksheets contained a mitigation
           strategy for high pressure recirculation that South
           Texas doesn't do, so we couldn't run through the
           samples using the worksheets as --
                       MEMBER APOSTOLAKIS:  Wait a minute.  The
           worksheets we were told come from the IP.
                       MR. KENNEDY:  Yes.
                       MEMBER APOSTOLAKIS:  And the IP for South
           Texas is really a PRA, so how come there -- the PRA
           itself had this flaw?
                       MR. KENNEDY:  No.  
                       MEMBER APOSTOLAKIS:  It was in the
           translation?
                       MR. KENNEDY:  It was in the translation. 
           Yes.  So we did run a revision zero, but that was a
           fairly easy fix.  We did it onsite and corrected the
           worksheet and ran the examples through.  The number in
           parentheses compared the results considering external
           events to the worksheets, and that's what those
           numbers are.
                       CHAIRMAN SIEBER:  Well, I guess I have a
           question then.  It would appear that we got better
           results for South Texas than other places.  It also --
                       MR. KENNEDY:  Well, in what area? 
                       CHAIRMAN SIEBER:  Well, in comparison
           between worksheets and their PRA.
                       MR. KENNEDY:  Okay.  But keep in mind the
           South Texas -- the only numbers we have for South
           Texas are the final numbers.  Those are after the
           changes were made onsite.
                       MR. PRUETT:  Yes.  The high pressure re-
           cert was not the only change made.
                       MR. KENNEDY:  Right.
                       CHAIRMAN SIEBER:  Okay.
                       MR. PRUETT:  There were several that we
           made as we made a high pressure re-cert change.
                       MR. KENNEDY:  Right.  And so what we're
           missing is the rev zero which would have been just
           terrible.
                       MEMBER APOSTOLAKIS:  Diablo looks very
           good.  Read the fixes.
                       MR. KENNEDY:  Yes.  Diablo looks good, and
           SONGS doesn't look too bad.
                       MEMBER APOSTOLAKIS:  Tom told us earlier
           that SDP conservative means that you go into
           conference with the licensee and you find that 36
           percent of the time for Diablo for example you back
           off.  You were conservative.
                       MR. KENNEDY:  Well --
                       VOICE:  Maybe.
                       MEMBER APOSTOLAKIS:  So 15 percent of the
           time then the licensee tells you, No, Mr. Regulator,
           you are not conservative enough so you have to give us
           a white instead of a green?
                       MR. KENNEDY:  No.
                       MEMBER APOSTOLAKIS:  Is that what it
           means?
                       MR. BROCKMAN:  No.  In fact that's really
           the type error that we need.  Our goal has to be to
           get that to zero, because --
                       MEMBER APOSTOLAKIS:  No.  But what does it
           mean?
                       MR. BROCKMAN:  -- the potential exists
           there that I am not going to pursue a white issue
           because I come up with a green determination.  My goal
           on that has to be to get that number to zero, and
           that's the challenge.  I never want to have an issue
           that I don't pursue because I have underclassified it.
                       I need to get that to zero but on the
           contrary my public relations dilemma is the other side
           of the coin.  I don't want to have too many times
           where it looks like all I do is back off, and I get
           the reputation of not being an effective regulator. 
           I cut deals in dark, smoke-filled rooms.  And there
           are certain people out there right now who make those
           accusations.
                       MEMBER POWERS:  Then they've got type one
           and type two errors.
                       MR. BROCKMAN:  That's it.  Type one-type
           two errors traditional.
                       MEMBER APOSTOLAKIS:  But you actually find
           out if the licensee's assessment was worse -- the
           result was worse than yours?
                       MR. KENNEDY:  No.  Let's step back a
           minute.  The only thing we're really concerned about
           is do we come up with a green on the worksheet that is
           really white?
                       MEMBER APOSTOLAKIS:  What do you mean,
           really white?  There isn't such a thing as really.
                       MR. KENNEDY:  Well --
                       MEMBER APOSTOLAKIS:  Somebody else's
           assessment is white?
                       MR. KENNEDY:  Yes.
                       MEMBER APOSTOLAKIS:  Okay.
                       MR. KENNEDY:  The worksheets are
           underestimated the risk, the actual risk --
                       MEMBER APOSTOLAKIS:  Right.
                       MR. KENNEDY:  -- and so the results of the
           worksheets are a green, and in our process we don't do
           anything.  We do some other things, but we don't go to
           a reg conference.  We don't engage on further risk
           analysis.
                       But right now if we do come up with
           something greater than green, a white, yellow, or red,
           we don't go straight to the reg conference based on
           the results of the worksheet.  We engage their risk
           analysts onsite and do a phase three type analysis to
           determine what the risk really is.  So we would avoid
           this 36 percent downgrade in the color even before we
           went to the reg conference because we're doing that
           phase three analysis.
                       MR. PRUETT:  Right now I'd say about half
           of that 36 percent that Kriss is talking about is due
           to the way we implement the county rule in the
           significance determination process, so if we have
           three greens adjacent to a white block we're going to
           call that  white finding.  In reality it may really be
           a green finding, but for the purposes of the phase two
           analysis we're going to call that white.
                       MEMBER APOSTOLAKIS:  So you're referring
           to the action matrix?
                       MR. PRUETT:  That's correct.
                       MR. KENNEDY:  No --
                       MR. PRUETT:  Not the action matrix.  
                       VOICE:  The SDP --
                       MEMBER APOSTOLAKIS:  That takes you to the
           headings of the action matrix.  Isn't that the same
           thing?
                       MR. PRUETT:  Well, no.  You've got the
           greens next to whites.  You're right.  The output from
           that would take you as to where you start going in
           the --
                       MEMBER APOSTOLAKIS:  Are you happy with
           the headings?  I think they're very arbitrary, but two
           whites or three greens or -- do these make sense?  And
           then all of a sudden the last one -- this is changing
           the subject a little bit, but I don't think we
           discussed it at all.  
                       MR. BROCKMAN:  Well, there was --
                       MEMBER APOSTOLAKIS:  What's the basis?
                       MR. BROCKMAN:  The one thing with three
           greens next to a white was to try to prevent the error
           of missing one.  It's too close and we know there's
           uncertainty in our tool, and if we come up with three
           greens next to a white we say we're going to pursue
           further.  It's like a performance indicator.  I don't
           know there's a problem but I need to look further
           because I'm in my uncertainty band, and that's where
           we're trying to -- should it be three next to a white? 
           Should it be two next to white?  We started with
           three.
                       MEMBER APOSTOLAKIS:  All right.  
                       MR. KENNEDY:  If you go to the next slide,
           Troy, I think we've discussed almost all the
           challenges that I have listed here.  By challenges I
           think these are challenges that Troy and I faced that
           regional management faces and the inspectors face out
           in the field, and that is the accuracy of the SDP
           phase two worksheets.  
                       We have to sit down -- the inspectors
           implement the phase two worksheets.  They fill they
           out, and they have to sit across the table from the
           licensee, and if there's errors in those worksheets
           that the licensees are pointing out to them that's not
           desirable.  And the second one, availability and
           accuracy of the SPAR models, we've discussed that.  
                       And to get on the question that you asked
           earlier, Dr. Powers, the tools that we have for fire
           protection shutdown operations and containment
           integrity, in the case of the last two those are
           really under construction.  There's procedures out
           there, but what you -- they're really screening
           procedures that you end up going back to NRR whenever
           you have some issue, and the fire protection SDP is
           probably harder than it needs to be.
                       MEMBER POWERS:  I don't even understand
           it.  You come in here and you say, Okay.  Is the
           manual fire question capability degraded a little bit,
           half way, a bunch.  I have no idea, but having made
           that determination then I start -- I get an exact
           number.
                       MR. KENNEDY:  Right.
                       MEMBER POWERS:  That turns out to be an
           exponential.  Now, there's a numerical error in it,
           but that's okay.  We get these numbers out.  I have no
           idea how to do that.
                       MR. KENNEDY:  We share the same
           frustration.
                       MEMBER POWERS:  I don't even know where
           the exponential numbers are.  I know exactly where
           they come from.  They come from five, but that doesn't
           help me.  Where did five get them?  
                       MR. KENNEDY:  And the numbers that you get
           from five are screening values and they don't really --
                       MEMBER POWERS:  And they did things that
           I think are obnoxious in fire protection modeling.
                       MEMBER APOSTOLAKIS:  That's another
           mystery to me, again, and it has to do with these
           simple questions I mentioned earlier.  Why did most of
           the licensees choose to do a screening analysis for
           fires when we have all this risk informed regulatory

           system facing us?  Very useless.  You just screen
           things out and say they're not important.  How does
           that help me implement a significance determination --
           I don't understand these things.
                       MEMBER POWERS:  Whenever they have an
           inspection finding you tell them it's green because it
           got screened.
                       MEMBER APOSTOLAKIS:  It got screened out.
                       MEMBER POWERS:  It doesn't matter if the
           fire protection seals all fail and it's going to be a
           roaring inferno in there in the event of a fire, but
           that's -- it's screened.
                       MEMBER APOSTOLAKIS:  Okay.
                       MEMBER POWERS:  The fire's smart.  It
           knows.  It goes around those --
                       MR. KENNEDY:  But in all these -- in these
           three areas in particular NRR does have some projects
           going on to further develop the shutdown SDP, the
           containment integrity SDP --
                       MEMBER POWERS:  Right.
                       MR. KENNEDY:  -- and I'll be honest with
           you.  Their efforts on the appendix F improvements --
           I'm not sure they're headed in the right direction,
           but they are trying to do something with it.  From
           what I've heard it doesn't simplify the process
           though.  I think it goes from 60 pages to 100 pages,
           but --
                       MEMBER POWERS:  -- as long as I'm just
           rolling dice and guessing at a number to begin with.
                       CHAIRMAN SIEBER:  It seems to me these are
           areas where we have to pay a little closer attention.
                       MEMBER POWERS:  There's no question about
           it.  We're getting the same story from both sides of
           this coin, and -- all apologies, Kriss.  You're not
           the first to tell us this.
                       MR. KENNEDY:  I'm glad.  I didn't think I
           was.
                       MEMBER POWERS:  And so when we prepare our
           September report to the commission -- they've got to
           understand what's going on, and I like this.  It's
           challenges to the one guy -- one set of people that I
           really don't want to throw any more challenges to, and
           that's the guys that are out in the front line dealing
           with the plants, and then they should go in with a
           measure of confidence that what they're doing has a
           good technical, sound foundation, that the
           uncertainties in it have been examined fairly closely.
                       I don't think it's a fatal flaw, but I
           think it's an issue of priorities.
                       CHAIRMAN SIEBER:  Do any other members
           have questions?
                       (No response.)
                       CHAIRMAN SIEBER:  Well, thank you, Kriss,
           for your discussion and I would point out that even
           though this has been more dialogue than presentation
           so far, this method is important to us to get a really
           good insight in a short period of time as to what your
           problems are and how do you perceive the operation of
           the agency.
                       What I'd like to do is we are on schedule
           if we ignore the fact that we have not covered topic
           five.  What I'd like to do is perhaps go until 12:15
           rather than 12:30 for lunch.  We can gain at least 15
           minutes in the process and so I would suggest we break
           for lunch right now.
                       MR. GWYNN:  If I could I'd like to ask the
           Region IV staff to allow our guests to go first for
           lunch, and the lunch is in our executive conference
           room just around the corner here.  We'll go in, pick
           up our lunch, then come back and eat it here if that's
           all right.
                       CHAIRMAN SIEBER:  Fine.
                       (Whereupon, a short recess was taken.)
                     A F T E R N O O N  S E S S I O N
                                      (12:20 p.m.)
                       CHAIRMAN SIEBER:  I think in the plant
           operations area I think a number of us have
           questions about the general topic of Callaway grid
           experience and how that impacts other plants.  We're
           aware the information notice that was published in
           the incident in 1999, but you may want to give us
           some insights as to what your expectations are for
           the future under the burn energy situation and what
           it is Region IV is doing about it.
                       And so with that I will turn it back to
           regional management for their next presentation.
                       MR. BROCKMAN:  Thank you, sir.
                       We're really in what I'll call our segue
           transitional part here of moving along and focusing
           on the electrical part and then we'll be moving into
           the fire protection part.  The first thing we want
           to do is share with you a little on the SCRAM
           trends.  This will be very quickly.  This is a
           transitional issue.
                       As we've looked over the last couple of
           years as to what have been the trends that we have
           seen in our SCRAM data and what have you and the
           insights we're getting and how that's trying to
           focus us in different areas, and you're going to see
           it's going to lead us right into this afternoon's
           topic.
                       So with that, Bill Johnson, who is my
           chief of the Branch B in reactor projects which just
           happens to be where Callaway resides -- 
                       MR. JOHNSON:  This is some data that was
           put together by regional personnel on total SCRAMs
           across the nation for years 1998, '99, and 2000.  I
           don't see any distinct trends from this presentation
           of the short-term SCRAM data.  I did notice one
           interesting point that the number of manual SCRAMs
           in year 2000, 33, was the same as the number of
           manual SCRAMs in here 1999, also 33, which indicates
           that the new performance indicator which counts both
           manual and automatic SCRAMs might not have had much
           of an effect on the number of manual SCRAMs.  It's a
           good sign.
                       Since we noted that a number of the
           SCRAMs in Region IV were caused by electrical
           systems a further review was performed, and later on
           the agenda Mr. Pruett will summarize the results of
           that review.  
                       CHAIRMAN SIEBER:  Just a quick question. 
           Licensees complain that including manual SCRAMs
           prevents or induces an operator to try to wait it
           out as opposed to taking a safety protective action
           before an automatic action occurs, which potentially
           might not occur as we would like it.  In view of
           that is there any consideration or any thoughts that
           you would have about counting manual SCRAMs and the
           total number of scams as an unintended consequence
           or an unintended driver to rely more on the
           automatic action rather than the operator's
           intuition?
                       MR. BROCKMAN:  In fact, I think an
           accurate characterization is is there were two or
           three individuals placed in the industry who
           expressed a personal concern that this could be an
           unintended consequence.  Across the board in all of
           the trips that I think we have taken out to our
           licensees they have unequivocally stated, No.  This
           performance indicator would have absolutely no
           impact on the intent of their operators and the
           actions of their operators.
                       It was a couple of people who said this.
                       MR. GWYNN:  Every licensed operator that
           I've spoken with in a control room and asked that
           question of has said, I'm going to follow my license
           requirements and my boss is going to be very upset
           with me if this thing goes out automatically when I
           should have punched it out manually, and it has --
           the performance indicator had no bearing on their
           thinking in that arena, and the data that Bill just
           put up I think supports, at least during the first
           year of initial implementation that there hasn't
           been an impact.
                       MR. BROCKMAN:  But with that said, NRR
           is revising the performance indicators to preclude
           that.  There's activities going on to revise it and
           get it into an arena where that potential supposedly
           could not even exist.
                       CHAIRMAN SIEBER:  Another quick
           question.  Are there any other performance
           indicators that come to your mind like the counting
           of outage hours and certain risk conditions that
           might have an unintended consequence?
                       MR. BROCKMAN:  Yes.  Probably the one
           that comes to my mind most easily is unplanned power
           reductions.
                       CHAIRMAN SIEBER:  Okay.
                       MR. BROCKMAN:  Currently there is -- it
           was the old AEOD performance indicator that had
           absolutely no risk association to it but was without
           a doubt the highest correlation factor toward those
           plants that degraded in the NRC's overall
           assessment. 
                       For plants that had unintended power
           changes, unplanned power changes, the more they
           occurred it wound up being that those were the
           plants of concern.  Not anything to do with risk. 
           This was brought forward in the new program. 
           Without a doubt you have the what is an unplanned
           power change?  Are you talking about an automatic
           run back?  Are you talking about a condition evolves
           and I've got to take action within the next six to
           eight hours to reduce the power to make that happen?
                       In the old AEOD performance indicator
           that would have been an unintended power change,
           doing it within that time, but currently the way the
           performance indicator is done is any power change
           done within 72 hours is an unplanned power change. 
           Give you adequate time to get all your things
           together, plan the activity, prep your people, and
           embedded into more of your normal processes.  If
           you're a utility and you've got the choice of doing
           this at hour 68 or at hour 73 it's a no-brainer. 
           You're going to do it at hour 73.
                       CHAIRMAN SIEBER:  If I have a --
                       MR. BROCKMAN:  We have seen indications
           where decisions are being made -- now, they're being
           risk considered into it, but if risk is not an issue
           and they have a choice of doing it in less than 72
           hours or quicker or after 72 hours, they're doing it
           in longer than 72 hours so they don't take the PI
           hit.
                       CHAIRMAN SIEBER:  So if I have a small,
           below tech specs reactor cooling system leak in a
           joint, which is allowable, I should allow it to leak
           for 72 hours before I go in and do something about
           it?
                       MR. BROCKMAN:  I'm not sure that they
           would take it at that particular point, but we've
           had -- and your memory is always better on these
           things than mine where once again, if risk isn't an
           issue, if the tech specs aren't an issue, and if
           I've got reactor cooling system leakage I'm going to
           be in a short action statement there, but if it's a
           valve packing leakage, which we know is right there,
           and I've got a choice of reducing the plant down
           tomorrow night or waiting until Saturday night to do
           it, they'll probably figure two things with respect
           to that, and that's going to be with the load, the
           system load is requesting on -- they'll factor that
           in there, and then they'll look at that outage time
           too on the hit for the PI.
                       CHAIRMAN SIEBER:  Yes.  Well --
                       MR. BROCKMAN:  And if they don't think
           it changes their risk profile they'll wait.
                       CHAIRMAN SIEBER:  The reason why you do
           it is for ALARA, and the reason why you don't want
           the leak to stay there for 72 hours is because leaks
           never get better.  They always get worse.
                       MS. WESTON:  Are there any plans to
           change that possible consequence?
                       MR. BROCKMAN:  They're looking at that
           one, but I don't know what --
                       VOICE:  That's one that's being
           reviewed.  The power reduction is being reviewed. 
           I'm not sure whether there's a work force on it. 
           I'm not sure exactly --
                       VOICE:  That one could be manipulated
           two ways.  One is a 72 hour and the other is whether
           or not you go to 81 percent or 79 percent, because
           the cutoff is 80.
                       MR. BROCKMAN:  And that becomes an ALARA
           consideration too, and that's one thing they used to
           take it down to 75 and say, If I've got no
           additional ALARA --
                       CHAIRMAN SIEBER:  Okay.  Thank you very
           much.  You may go on.
                       MR. JOHNSON:  I pulled a couple of
           trends graphs out of SECY-01.0111 just because I
           thought they were interesting and probably worth a
           quick demonstration.  And overall there aren't any
           industry trends that seem to be heading in the wrong
           direction.
                       For ASP program results there were no
           significant precursors in fiscal year 2000, and it
           looks like an overall downward trend in the overall
           number of the precursors.  
                       Looking quickly at some of the ex-AEOD
           indicators the one for automatic SCRAMs overall
           trend of course is still down.  We've noted on this
           one as well as on the first slide in 1999 there was
           an increase.  I don't know exactly what that means,
           but it still fits within the expected boundaries. 
           Safety system actuations also down.
                       Looking at a couple of the raw
           performance indicators I wanted to look at unplanned
           SCRAMs per 7,000 annual critical hours.  Don't see
           much of a trend on that, but this is short-term data
           and you couldn't draw a very firm conclusion from
           it.  Scrams with loss of normal heat removal -- I
           still don't see a trend there either, but it will be
           interesting to see this data accumulate for a few
           years and see if it tells us anything.  
                       And the other one I wanted to look at is
           safety system failures.  I do think I see a trend
           there, even though it's short term.  That's for
           PWRs.  And the similar curve for boiling water
           reactors -- there's a similar possible trend that a
           statistician could figure out.  
                       And that's the ones that caught my
           interest.  We're open to questions if you have any,
           sir.
                       (No response.)
                       MR. JOHNSON:  Okay.  Thank you very
           much.
                       MEMBER POWERS:  It seems to me that the
           question that arises, especially when we look at
           what the risk significant thresholds for PIs are
           that we've really chosen PIs that are too limited. 
           It's really combinations of things together that are
           really the PIs that we want.  Unplanned SCRAMs --
           that frequency combined with frequency of something
           else is really the indicator that we want to have.
                       Do you have any thoughts on that?
                       MR. JOHNSON:  I'm not well versed on
           that, but I do know that the unplanned SCRAMs in
           itself does not have a lot of risk significance, but
           the unplanned SCRAMs with loss of heat removal might
           well have serious significance, and that might be
           one to watch more closely.
                       MEMBER POWERS:  I'm wondering about more
           complicated combinations.   When you go through and
           you come out and you find out I've got to have 19 or
           something like that unplanned SCRAMs to get to a red
           level, you know that's never going to happen. It's
           just looking at the wrong thing, because that
           particular measure is just in itself not risk
           significant, but it's some unplanned scams -- a
           couple is something else -- where having one might
           get you certainly to a white.
                       Is there --
                       MR. HOWELL:  That's why we look at every
           one to see --
                       MEMBER APOSTOLAKIS:  If we had a good
           safety monitor and calculated the core damage
           frequency every time we have something happening
           then that would be a good indicator, would it not,
           because then you could set it at levels of CDF, and
           you don't care how you got there.  It could be a
           combination of ten things.
                       MR. HOWELL:  And that's why -- 
                       MR. BROCKMAN:  True.  That's why we look
           at it on the front end.
                       MR. HOWELL:  Yes.  Our inspection
           threshold looks at the CDP that comes up there that
           instant.  Basically, that instantaneous
           probability --
                       MEMBER APOSTOLAKIS:  No, because when
           you do the SDP and performance indicators really the
           thresholds are such that the change in that
           indicator would cause a level CDF greater than some
           threshold.  Not a combination.
                       MR. HOWELL:  Correct, but we do look at
           that on the front end for events, and even
           conditions too.  So Kriss and Troy, they do that,
           using the tools that we have we talk to the
           licensees and we'll ask San Onofre, What does your
           monitor indicate, and if it trips the threshold
           the --
                       MEMBER POWERS:  Then you didn't believe
           him.
                       MR. HOWELL:  You have to get the
           information the best you have.
                       MEMBER POWERS:  Well, they came back
           with 1.4 times ten to the minus four, and you said,
           We don't believe that.  That's way too conservative.
                       MR. HOWELL:  But we still did a special
           inspection though.  We sure did.
                       MR. BROCKMAN:  You've got two different
           things.  What you bring up here is very interesting
           to the performance indicator, but as I tried to say
           earlier, the inspection is without a doubt still a
           critical component, and we'll look at exactly that
           for an event or condition that occurs.  
                       And this weekend you saw the 5072s where
           the potential transformer at San Onofre that
           disassociated itself all over the Pacific Coast
           Highway, and we also had one at Cooper.  
                       So we took -- the risk guys looked at
           that right away.  Where are we at on that thing --
           the startup transformers lining out out at Cooper. 
           Well, it becomes a risk interesting issue if that
           startup transformer is out five days.  They're at
           about two and a half.  Are we monitoring that as
           we're correcting?  
                       We're inspecting right now on it, and if
           they get up to five days with the other issues that
           identify themselves in some other areas there we'll
           definitely be looking at changing that inspection
           threshold, which then gives us an additional vehicle
           to identify the issues that we've been talking about
           corrective actions and things so we can get those
           insights.
                       MEMBER POWERS:  I know what I want to do
           for sport on the 4th of July.  I want to get an
           inspector proponent like Ken, lock him in a room
           with a risk guy like George, and see who comes out
           alive.  I've had numerous discussions with some of
           the staff risk guys.
                       MEMBER APOSTOLAKIS:  If the safety
           monitor could be trusted that would be the best
           method, really, to core damage treatment, the
           condition of core damage probability, but
           unfortunately, we can't trust it.
                       MR. KENNEDY:  But there's also a
           deterministic aspect to the threshold that's been
           picked for SCRAMs, and that is it's a pretty good
           indicator irrespective of risk that if you have too
           many there's a problem at that site, and --
                       MEMBER APOSTOLAKIS:  So what do I care
           if it's an element of risk?  Ultimately it has to be
           connected to risk.  Right, because we are
           regulating -- protecting public health and safety. 
           If they want to lose money, that's their business.
                       MR. KENNEDY:  There's a lot of
           deterministic SDPs out there though, and several of
           the SDPs are deterministic.
                       MEMBER APOSTOLAKIS:  Well, there
           wouldn't be if you had a very good reliable safety
           monitor.
                       MEMBER POWERS:  Well, don't get over
           enamored with this risk analysis.  There are other
           issues.
                       MEMBER APOSTOLAKIS:  Like?
                       MEMBER POWERS:  Like sabotage, site
           security that you can invest in that, and there are
           elements not only of the regulations but of the
           oversight program that address those things.  And as
           I often say to you when we discuss defense in depth
           even if the probability of event is low if it occurs
           I'd really like something between me and the bad
           stuff.
                       MR. BROCKMAN:  My residents will all
           echo that.  
                       I think next up is Ms. Good, who is our
           plant support branch chief, to talk about the
           Callaway ALARA issue which we agreed to wait until
           now to discuss.
                       MS. GOOD:  Thank you.
                       Good afternoon.  My name is Gail Good. 
           I'm the chief of the plant support branch here in
           Region IV.  I am responsible for reactor inspections
           in the area of security, emergency preparedness, and
           radiation protection, and my presentation this
           afternoon will focus on the radiation protection
           area and specifically on some problems that were
           identified at the Callaway Plant in Fulton, Missouri
           that involved their ability to implement their ALARA
           program.  And ALARA stands for as low as reasonably
           achievable.
                       My presentation will cover the findings
           that were identified during the initial inspection,
           the specific performance problems that were
           associated with the findings, the NRC's assessment
           of the findings, and that would be the significance
           using occupational radiation safety significance
           determination process and any enforcement issues. 
           It will cover the licensee's response to the
           decisions that we made and then the NRC's actions to
           address the licensees' appeals, and then finally
           I'll discuss the special follow-up with the
           supplemental inspection that we conducted.
                       In August of 2000 Region IV conducted a
           baseline routine inspection of the licensee's ALARA
           program.  That inspection focused on a review of
           jobs that were completed during refueling outage ten
           that was in 1999.  Specifically we reviewed those
           jobs where the actual job doses exceeded the
           projected job dose by greater than 50 percent and
           accrued more than five person rem, and based on that
           review we identified six jobs that exceeded that
           criteria.
                       CHAIRMAN SIEBER:  Just a real quick
           question.
                       MS. GOOD:  Yes.
                       CHAIRMAN SIEBER:  If I were the RCM at a
           plant and I knew you were going to operate this way
           why would I not fudge the estimates so that I
           couldn't miss?  Do you have a way of looking at
           absolute values?
                       MS. GOOD:  We have a way of looking at
           their justifications for the projected doses that
           they're assigning, and if we see a significant
           increase from doing a similar job in a previous
           outage we might question why they were saying there
           would be an increase in the projected dose for this
           particular job.  So we would be reviewing their
           justifications.
                       CHAIRMAN SIEBER:  But you would be on a
           different kind of philosophical framework that way,
           saying, I don't really have great confidence in the
           way you're doing your estimates, as opposed to the
           numerical issue of you're double what you said you
           were going to be.
                       MS. GOOD:  It's a concern that we have.
                       CHAIRMAN SIEBER:  Thanks.
                       MS. GOOD:  And so with respect to the
           six jobs, the six jobs included all of the
           scaffolding work that was done in the reactor
           building.  That was all considered to be one job,
           and the actual dose for that job was 46 person rem. 
           The second job was the removal and installation of
           the steam generator manway covers and inserts, and
           the actual dose for that job was 8.5 person rem.
                       MEMBER LEITCH:  My question here is are
           we talking about bad estimates or bad performance?
                       MS. GOOD:  Bad performance.
                       MR. GWYNN:  As a matter of fact, there's
           a screening criterion that says that if these
           conditions exist but the overall ALARA results for
           the facility are good then we don't pursue them. 
           Correct?
                       MS. GOOD:  We would expect that there
           would be a performance problem.  Our initial look at
           it is for those jobs that are greater than five rem
           and where they exceeded the projected dose by
           greater than 50 percent, and we're using that
           greater than 50 percent as a filter to say we need
           to go out and take a look at these jobs to determine
           if there is a performance problem associated with
           it.
                       MEMBER LEITCH:  So it's just not that
           the job proceeded along an unexpected course but
           there were some performance deficiencies --
                       MS. GOOD:  Yes.  There were performance
           deficiencies.  
                       CHAIRMAN SIEBER:  It also would seem to
           me though in the process of estimating -- and I'm
           thinking like a licensee now -- if I would project,
           for example, scaffolding erection to be 20 man rem I
           would automatically have at least six jobs called
           scaffolding erection.  Okay.  And --
                       MS. GOOD:  They actually had -- I think
           it was about 160 individual scaffolding tasks.
                       CHAIRMAN SIEBER:  At one job.
                       MS. GOOD:  But they considered it to be
           one job and the ALARA planning and controls were
           done at that higher level, and that was one argument
           that the licensee tried to make when we had the
           regulatory conference was that we really should have
           been looking at the individual scaffolding work
           tasks.
                       CHAIRMAN SIEBER:  The licensee should
           have been planning at the lower level.
                       MS. GOOD:  And that was the argument we
           made, that there weren't sufficient ALARA planning
           and controls established at the level they wanted us
           to look at.
                       CHAIRMAN SIEBER:  Right.  Thank you.  
                       MEMBER POWERS:  Will you give me a
           feeling for the context?  This is all part of one
           refueling outage?
                       MS. GOOD:  Yes, it was.
                       MEMBER POWERS:  And what was the
           duration of that refueling outage?
                       MS. GOOD:  I don't know.
                       CHAIRMAN SIEBER:  Roughly?  
                       VOICE:  About 35, 40 days.
                       MS. GOOD:  About -- 
                       VOICE:  It was a little bit longer,
           right, because of the -- went over -- 40, 50 days.
                       MEMBER POWERS:  We see a lot of this I'm
           going to set the record for outage for this kind of
           plant, or I'm going to break my current record,
           things like that.  We've got a whole dose of it at
           Waterford.  This is -- I'm happy for them to have
           good planning and do their outages quickly, but this
           setting record business is going to lead to this
           kind of problem.
                       CHAIRMAN SIEBER:  But generally when the
           outages get shorter the man rem expenditures get
           lesser.
                       MR. HOWELL:  Yes.  But that didn't
           happen in this case.
                       MS. GOOD:  In some cases.
                       MR. HOWELL:  But that was one of the
           arguments that they said.  We took into account as
           part of our planning.  We want to have a shorter
           outage.  We'll do the hotter work early in the
           outage and then we'll get done quicker and the
           overall cumulative dose will be less, but that's not
           what happened.
                       CHAIRMAN SIEBER:  This is one of the
           snupps plants?
                       MR. HOWELL:  Yes.  
                       CHAIRMAN SIEBER:  Did they use the hot
           boron injection to try and get the source turned
           down?
                       MS. GOOD:  I'm not sure they did.
                       MR. HOWELL:  I think so, but they
           were -- I don't know, but they were doing work
           before they cleaned up the RCS.  They were erecting
           scaffolding before they cleaned up the RCS.  They
           were -- 
                       CHAIRMAN SIEBER:  That sort of explains
           it.
                       MR. HOWELL:  Right.  
                       VOICE:  And their source terms was
           complicated by the anomaly that they had --
                       MR. HOWELL:  And they were trying out
           electrosleeving of the steam generator tubes for the
           first time, new technology here in the states, and
           it had complications which contributed to some of
           this.
                       CHAIRMAN SIEBER:  But none of those were
           scaffolding, and scaffolding was 40 something man
           rem?
                       MR. HOWELL:  Yes.
                       CHAIRMAN SIEBER:  Okay.
                       MR. HOWELL:  A lot.
                       CHAIRMAN SIEBER:  That's a lot.  That's
           two outages.
                       MR. HOWELL:  Steal some of Gail's
           thunder -- to cut to the chase, they went from 305
           man rem in refuel ten to 100 in refuel eleven as a
           result of corrective actions --
                       MS. GOOD:  So they can do it.  It can be
           done.
                       CHAIRMAN SIEBER:  I apologize for
           interrupting.
                       MS. GOOD:  All right.  Moving along with
           the jobs, the third job that I have listed here is
           the eddy current testing, the robotic plugging, the
           stabilizing, the electrosleeving, and that job
           actually was the highest, and it accrued a 58 person
           rem.
                       MEMBER UHRIG:  How much of that was
           electrosleeving were normal procedures?
                       MS. GOOD:  I don't have that figure off
           the top of my head because they lumped all of that
           together under one job, under one RWP, and I can
           attempt to get that but I don't have that answer for
           you right now.
                       The fourth job was the health physics
           support for the primary and secondary steam
           generator activities, and the actual dose for that
           job was 5.6 person rem.  Fifth job was the foreign
           object search and retrieval, and the actual dose for
           that job was 6.4 person rem --
                       CHAIRMAN SIEBER:  That was one steam
           generator?
                       MR. HOWELL:  I think it may have been a
           couple of objects that they dropped in --
                       CHAIRMAN SIEBER:  But they went in
           through the -- where the flow blocking device is? 
           Most of that was probably extremity.  Right?
                       MS. GOOD:  I don't --
                       MR. HOWELL:  We'll have to get the
           report.  It may have actually --
                       MS. GOOD:  I think we had that --
                       MR. HOWELL:  -- been during refueling. 
           I don't know if it was necessarily the steam
           generator.  It may have been the --
                       CHAIRMAN SIEBER:  It must have been
           extremity dose?
                       MR. HOWELL:  I can get you the report.
                       MS. GOOD:  I'll move along then.  
                       As I mentioned, the sixth job was the
           reactor coolant pump seal removal and replacement,
           and the actual job dose for that was 13 person rem. 
           And again, I'd like to point out that all six of
           these jobs exceeded that filter that we use for
           focusing our inspection activities, that they were
           all over five person rem and they all exceeded the
           dose projection by greater than 50 percent.
                       CHAIRMAN SIEBER:  Industry experience is
           mockups for coolant pump seal replacement are
           invaluable.  Did they use mockups in their -- did
           they have a mockup seal?
                       MS. GOOD:  Some but not enough.  That
           was one of the areas that was a performance issue
           was the lack of the use of mockups.
                       MEMBER UHRIG:  On an object search and
           retrieval is not a normal part. That's sort of an
           accident?  Did somebody drop something?
                       MR. HOWELL:  Yes.  Right.
                       MEMBER UHRIG:  So this is just simply
           the fact that it went over five rem, because
           normally that would be zero.
                       MS. GOOD:  Well, they planned to do this
           job and they said, We think it's going to take this
           much dose to do this work --
                       MEMBER UHRIG:  Right.
                       MS. GOOD:  -- and they went over that by
           greater than 50 percent, so it was work that they
           planned to do.
                       Getting into the performance problems,
           the licensee conducted post job reviews and had
           prepared an outage report, and the licensee actually
           identified five performance problems that caused the
           higher than predicted doses.  And those problems
           were the maintenance activities were conducted in
           the vicinity of the reactor coolant system during a
           time soon after shutdown when area dose rates were
           temporarily elevated by a chemical cleaning process
           and without taking any additional protective
           measures for personnel.
                       The second performance problem --
           maintenance activities were conducted in the
           vicinity of the steam generators before the steam
           generator bowl drains were flushed resulting in
           higher than normal dose rates, and again, without
           taking any additional protective measures for
           personnel.  Third, the maintenance activities were
           conducted on the reactor coolant pumps and the steam
           generators without the secondary sides filled with
           water resulting in higher than normal dose rates,
           again, without taking additional protective
           measures.
                       The fourth performance problem was that
           maintenance activities were conducted without
           sufficient practice training to familiarize
           worker -- contract workers with plant equipment, the
           use of tools, and techniques to effectively reduce
           the dose that they would receive.  And then the last
           performance problem, maintenance activities were
           performed with ineffective communications between
           radiation protection personnel and the primary
           contractor, which resulted in additional worker
           exposure due to ineffective planning and the
           sequencing of work activities.
                       Now, in addition to these performance
           problems the NRC was aware that high collective dose
           was a problem at the plant.  The collective doses
           had increased between 1997 and 1999 and exceeded the
           135 person rem which is the industry median for
           pressurized water reactors.  They were -- at the
           time we did this they were at about 178 person rem,
           and there was only one other PWR that had a greater
           person rem, and that was Indian Point 2.
                       MEMBER LEITCH:  Were there any concerns
           with individual exposures?
                       MS. GOOD:  No.  There were no
           overexposures.
                       MEMBER LEITCH:  Do you know if any of
           the licensee's administrative limits were violated
           for individual exposures?
                       MS. GOOD:  I don't believe they were.
                       MEMBER LEITCH:  Okay.  Thanks.
                       MEMBER APOSTOLAKIS:  What exactly is
           ineffective communication?  What does that mean?
                       MS. GOOD:  They didn't -- some
           individuals, some groups didn't know when other
           groups were planning to do work.  They didn't have
           good briefing so they weren't able to plan things
           out so it could be done in the most efficient way to
           reduce the doses.  So it just -- not confusion, but
           it took more time for them to figure out what was
           going to happen next.
                       CHAIRMAN SIEBER:  This plant's been
           running since the 1980s?
                       VOICE:  Yes.
                       CHAIRMAN SIEBER:  So it's not lack of
           experience.  
                       MR. HOWELL:  She's going to touch on
           that.  They did a root cause analysis.
                       CHAIRMAN SIEBER:  All right.
                       MS. GOOD:  After conducting a regulatory
           conference with the licensee in November of 2000,
           reviewing the supplemental information that the
           licensee provided and conducting a series of
           significance and enforcement review panels -- and
           those included regional personnel, NRR, Office of
           Enforcement, the Office of General Counsel, and the
           inspection program branch the region then issued its
           final significance determination and violation, and
           we issued that in January of 2001.
                       Now, our letter indicated that we had
           identified three white findings, and in the reactor
           oversight process those are findings with low to
           moderate safety significance.  Now, the two jobs
           that accrued greater than 25 percent rem were
           determined to be individual white findings using the
           occupational radiation safety significance
           determination process.  And again, those were the
           scaffolding jobs and the eddy current and
           electrosleeving that I discussed earlier.
                       Now, the other jobs -- and I won't go
           over that list again -- were all grouped together to
           make the third white finding, and the significance
           determination process assigns a white significance
           if there are greater than two jobs that exceed the
           five person rem and the greater than 50 percent dose
           projection.  You get over 25 person rem it's a stand
           alone finding.
                       MEMBER UHRIG:  Had they not mis-
           estimated the exposure here, just the fact that it
           was greater than 25 person rem would have been
           sufficient to get the white rating?
                       MS. GOOD:  No.
                       MEMBER UHRIG:  It would not?
                       MS. GOOD:  They would have had to have
           exceeded the projection --
                       MEMBER UHRIG:  By 50 percent?
                       MS. GOOD:  By 50 percent.  That's right.
                       MEMBER UHRIG:  Okay.
                       MS. GOOD:  And then lastly we issued a
           violation for failure to use to the extent practical
           procedures and engineering controls based on sound
           radiation protection principles to achieve
           occupational doses and doses to members of the
           public that are ALARA, and I've got the citation
           list in there.  
                       MR. GWYNN:  This was a precedent-setting
           notice of violation for a power reactor.  There had
           only been, to my knowledge, one other before that,
           and it was a 4 that was not reviewed by the program
           office before it was issued in Region II, so this
           was a precedent-setting notice of violation, and I
           believe it was at the right plant at the right time.
                       CHAIRMAN SIEBER:  That's a lot.
                       MS. GOOD:  Yes, it is. 
                       CHAIRMAN SIEBER:  -- for a plant of that
           size and age.
                       MR. GWYNN:  Right.
                       MS. GOOD:  So in response to our January
           2001 letter, the licensee submitted two separate
           appeals that covered four areas.  I have the first
           one here.  First they asserted that the NRC had
           imposed a regulatory staff position that is new or
           different from a previously applicable staff
           position; in other words, a backfit.  Second, they
           denied the violation; third, they asserted that our
           significance determination process creates a new
           regulatory burden and that it's fatally flawed and
           should be suspended; and finally, they appealed the
           staff's determination of the three white findings. 
           But other than that they were really happy with the
           letter.
                       MEMBER POWERS:  This is the classic my
           dog didn't bite you, my dog doesn't bite, I don't
           even own a dog approach.
                       MS. GOOD:  So after a great deal of
           careful review by a significance determination
           appeal panel, a backfit panel, and evaluation of
           each of the licensee's arguments -- and this again
           was a small army of people that again included the
           region, somebody from another region as an
           independent evaluator on the appeal panel, members
           from NRR, OGC, OE, Inspection Program Branch, the
           NRC issued a response to the licensee's appeals in
           May of 2001.
                       CHAIRMAN SIEBER:  This seems to be a
           licensee's response and your response seemed to
           involve legal issues.  I presume they had their
           attorney and you had yours?
                       MS. GOOD:  Yes.
                       MR. GWYNN:  Like I said, it was a
           precedent-setting enforcement action.
                       CHAIRMAN SIEBER:  Did anybody
           participate besides NRC and the licensee, like NEI?
                       MR. GWYNN:  No, but there was --
                       MR. BROCKMAN:  On the stage, no.  Behind
           the scenes, yes.
                       MR. GWYNN:  And there were interested
           members of the public from the State of Missouri
           who --
                       CHAIRMAN SIEBER:  Very interesting.
                       MS. GOOD:  So we issued our response to
           their appeals and our response said we determined
           that there was no backfit, and that applied to both
           the significance determination and the violation. 
           We determined that the violation occurred as
           described in our notice of violation, and that the
           occupational radiation safety significance
           determination process is fundamentally sound even
           though there are some areas that could be enhanced,
           and currently the NRC is working with NEI to work
           through those specific issues.  
                       And then lastly the significance
           determination process appeal panel concluded that
           there were no significant discrepancies in how the
           staff had applied the significance determination
           process, so in accordance with the reactor oversight
           program -- and the region conducted a supplemental
           inspection, and we did that to provide assurance
           that the root causes and the contributing causes are
           understood for the performance issues to
           independently assess whether the root causes for the
           performance issues affected other plant processes or
           human performance, otherwise known as extent of
           condition; and three, to provide assurance that the
           corrective actions for the performance issues are
           sufficient to address the root and contributing
           causes and to prevent recurrence of the performance
           issues.
                       CHAIRMAN SIEBER:  The licensee did not
           go to or consider the appeal board?
                       MS. GOOD:  We understood that formally
           the only appeal that existed at that point was to
           appeal the backfit, and we've not heard whether they
           intend to do that or not, and certainly there are
           some informal processes that they could use.  And
           we've not gotten an indication at this point that
           they plan to appeal anything.  We've gotten a sense
           that they may just let the NEI and the agency work
           through the issues with an occupational rep safety
           SDP.
                       CHAIRMAN SIEBER:  Thanks.
                       MEMBER UHRIG:  What if the next time
           they came in and estimated these at a hundred person
           rem and you said that's unreasonable, what's going
           to happen then?
                       MS. GOOD:  I don't know.  We've not gone
           down that path.  Obviously we're going to be looking
           carefully, and we will in fact be looking because as
           Art mentioned this most recent outage that they had
           their total dose for the outage was 100 person rem. 
           Well, they had estimated -- if you added up the sum
           of all their radiation work permits it came out to
           160 person rem.  We haven't done an inspection yet
           to really discover why there is this big difference,
           so we would just have to look and see if they have
           good reason.  If they don't have a good reason we're
           going to have to pursue it and see where we end up.
                       MEMBER UHRIG:  Are you going to adjust
           their estimates?
                       MS. GOOD:  Are we going to adjust their
           estimates?  No.  We would just ask them why they
           adjusted their own estimates and what was their
           justification for doing it.  So we would -- then
           it's going to be our opinion against theirs if we
           don't agree with their justification.
                       MR. HOWELL:  We've seen one or two
           examples of inflated dose estimates we believe. 
           It's -- they're more modest in nature.  They're not
           100 rem.  They're --
                       MEMBER UHRIG:  I think the one you
           alluded to was at Turkey Point in the steam
           generator change out.  I remember it involved that
           one.  
                       MS. GOOD:  We've seen a couple of other
           instances at plants in Region IV since this action
           occurred where we at least had some questions, but
           at this point we felt that everybody has had a good
           answer when we've asked those types of questions, so
           far, the plants in our region.
                       MR. LARKINS:  Let me ask you a quick
           question.  You said that NEI and NRR are working
           together to work out some of the nuances in the
           significance determination process for this area. 
           Did the region find any -- take any issues with the
           SDP process as currently constituted for handling
           this type of problem?
                       MS. GOOD:  I think initially we felt it
           ought to be just one white finding because these
           were based on activities that occurred in one
           outage, and we questioned whether they were really
           the same problem rather than multiple different
           problems.  But I think what we arrived at was --
           what we have here is really a programmatic breakdown
           in the area of ALARA.  Everything in the ALARA
           program was broken, and so from that standpoint I
           think we did feel that three whites and the actions
           we would take based on three whites was really the
           appropriate thing for the region to do.
                       MR. BROCKMAN:  That's the key issue when
           you go to the action matrix was the actions that
           were responsive to this particular problem with
           ALARA that we would send out a couple of person team
           inspection to follow up on this with their root
           cause analysis, and I think we thought that was
           right on where we should be.  If it's less I've got
           one person out there for two or three days or  Art's
           got one person out there for two or three days which
           wasn't the right type of response to be able to
           address the issue.
                       So you've really got to look at the
           action matrix and where it puts you.
                       MS. GOOD:  I'll go on then and go into
           the root causes.  They identified several root
           causes.  First they identified that it was
           management's failure to establish expectations for
           keeping doses ALARA, management's failure to
           communicate a priority for keeping doses ALARA, a
           culture that did not support an ALARA concept, and
           then finally administrative controls that didn't
           assure that documented ALARA concerns would receive
           proper priority, appropriate consideration, and
           comprehensive resolution.  
                       MEMBER APOSTOLAKIS:  How did they decide
           that the culture did not support the ALARA concept? 
           I thought we can't say anything about culture.
                       MR. HOWELL:  Those are their words.
                       VOICE:  That's their finding.
                       MEMBER APOSTOLAKIS:  Their as the
           licensee?
                       MS. GOOD:  Yes.  
                       VOICE:  That's not ours.
                       MS. GOOD:  This was what came out as
           their root cause analysis.
                       MEMBER APOSTOLAKIS:  So our guys doing a
           supplemental inspection --
                       MS. GOOD:  Yes.  We looked at their root
           causes and their extent of condition to determine
           whether we agreed with them and whether they took
           appropriate corrective actions to address those root
           causes.
                       MR. BROCKMAN:  We can't say it but we
           can endorse them saying it.
                       MS. GOOD:  So after conducting our
           inspection, looking at what they provided to us on
           their root causes and their corrective action, we
           concluded that the licensee had conducted a thorough
           evaluation of the causes and had correctly
           identified the extent of condition and had
           implemented appropriate corrective actions.
                       We found that some corrective actions
           were not completed before they started the most
           recent outage.  They were actually in an outage when
           we did our supplemental inspection, so that was good
           timing for us, and that some corrective actions had
           not been institutionalized, and by that I mean that
           they hadn't been incorporated into procedures and
           processes to ensure that the lessons learned would
           be lasting.
                       So that ends my presentation on ALARA. 
           I don't know if there are any further questions for
           me.
                       VOICE:  I think you've heard from the
           presentation that we learned something with respect
           to the initial implementation of the oversight
           process through this, that it can become very
           burdensome in terms of staff hours to address these
           controversial issues where the licensee took issue
           with virtually everything that we found but
           subsequently agreed they had a major problem that
           needed to be fixed.
                       CHAIRMAN SIEBER:  I would think -- and
           I'm not speaking on behalf of the agency but more on
           my experience as a licensee that if you had dose
           rates like that to your people you would be
           concerned right off the bat.  You would be concerned
           before you --
                       MR. HOWELL:  That was our sense too,
           that clearly some of these things that they did not
           do during that outage were lessons they had already
           learned because of those dose rates and they chose
           for various reasons not to implement --
                       CHAIRMAN SIEBER:  Well, the industry has
           moved way beyond this point.  This is 15-20 years
           ago behaviors.
                       MR. HOWELL:  Yes.
                       MR. GWYNN:  And I think that's why it
           was easy for them to come to the conclusion about
           the safety culture because there were such glaring
           examples where the culture should not have allowed
           the activities to progress to where they did.
                       CHAIRMAN SIEBER:  Do you believe that
           cultural issues as would reflect itself in one
           technical area spread to other areas in the plant?
                       MS. GOOD:  That's part of what we looked
           at, what they had to do when they looked at the
           extent of condition, and the only area where they
           felt that there was some involvement in other areas
           was administrative controls.  The issue having to do
           with the administrative controls did apply to other
           areas and not just the ALARA area.
                       CHAIRMAN SIEBER:  And did you all agree
           with that conclusion of the licensee?
                       MS. GOOD:  Yes, we did.
                       MS. SCHOENFELD:  Did a contractor do
           their assessment or did they do it?
                       MS. GOOD:  Do you mean provide their
           response to us?
                       MS. SCHOENFELD:  No.  Do their root
           cause --
                       MS. GOOD:  I don't know the answer to
           that.
                       MS. SCHOENFELD:  -- to identify these
           root cause findings.
                       MS. GOOD:  I don't know if they used a
           contractor to do that.  I can get that answer for
           you but I don't believe that they did, but I'd like
           to check on it.
                       MEMBER POWERS:  The thing that interests
           me is the decision to make it three findings instead
           of one in order to get it into what you felt was the
           appropriate place in the action matrix.
                       MR. HOWELL:  We applied the SDP as --
           literally as it was developed, and that's the
           outcomes, three white findings.  It's clear.  To go
           to anything else would have been a manipulation of
           the SDP.  Now, you can argue about whether that's
           right and certainly they did, but we implemented it
           and that's what you get.  You get separate findings
           for each of those categories.
                       CHAIRMAN SIEBER:  Any further questions?
                       MEMBER APOSTOLAKIS:  Yes.  Why are you
           the only one using Power Point?
                       MS. GOOD:  I think there's going to be
           someone else this afternoon.  
                       CHAIRMAN SIEBER:  Well, thank you very
           much.  That was a very good presentation.
                       MS. GOOD:  Thank you.
                       And with that I'd like to introduce Troy
           Pruett.  Troy is going to cover the Callaway grid
           experience.
                       MR. PRUETT:  Once again, my name's Troy
           Pruett.  I'm a senior reactor analyst in Region IV. 
           Today I plan to discuss an overview of the Callaway
           plant trip that occurred in August of 1999, and at
           the tail end of that I'll go through a review we did
           of electrical related SCRAMs and ESF actuations
           occurring in Region IV since 1995.
                       Kriss didn't get a chance to mention
           some of the functions that the SRAs performed, but
           one of the things we do is an independent review of
           operational events as they occur and then again when
           the LERs make it into the region.  And during one of
           these independent reviews a senior reactor analyst
           had identified a potential concern involving
           switchyard voltages being below the tech spec
           requirements following a reactor trip at the
           Callaway plant.
                       Based on that concern the NRC initiated
           an inspection activity which involved the senior
           reactor analyst that initially identified the issue
           as well as a resident inspector from the Diablo
           Canyon plant.  
                       There were three general issues of
           concern that the inspectors took with them.  One was
           a plant trip that results in a loss of offsite power
           condition.  A second concern was a plant trip which
           results in a potential for double sequencing of
           safety-related equipment, and then the third concern
           would be a plant trip that would result in a partial
           actuation of safety-related equipment.  
                       And then we're also going to talk about
           specific areas of concern that were identified as a
           result of the inspection that involved operator and
           dispatch center awareness of the degraded voltage
           condition, and I'll get into the specific inspection
           issues.
                       The first one --
                       CHAIRMAN SIEBER:  Let me ask a couple of
           general questions first.
                       MR. PRUETT:  Okay.
                       CHAIRMAN SIEBER:  The inspection report
           talked about high inner system loads.  Was that
           reactive or real power delivery?  You can get a lot
           of current going and no power going.
                       MR. BROCKMAN:  You were running in a
           large demand in the Chicago area --
                       MR. PRUETT:  No.  There was a load
           demand in the north because of cold weather, very
           high demand in the south, and very high demand in
           the grid area that the power is being wheeled
           through.
                       CHAIRMAN SIEBER:  Okay.
                       MR. PRUETT:  Callaway's function during
           this time frame was to provide grid support in the
           form of reactive loading.  They had boosted the VAR
           output of the generator.
                       CHAIRMAN SIEBER:  So they were pumping
           VARs as opposed to delivering energy.
                       MR. BROCKMAN:  But the grid itself --
           and it was a freight train with power going through
           it.
                       CHAIRMAN SIEBER:  Now, did they have
           automatic tap changers or manual tap changers?
                       MR. PRUETT:  At the time they just had
           the standard transformers.  After the event --
                       CHAIRMAN SIEBER:  No tap changers?
                       MR. PRUETT:  No.  After the event they
           installed automatic load tap change transformers.
                       CHAIRMAN SIEBER:  And they are the kind
           that will change taps under load?
                       MR. PRUETT:  That's correct.
                       CHAIRMAN SIEBER:  Because there's two

           different kinds, one of which does you no good.
                       Thank you.  That helps me to understand
           a little better.
                       MR. PRUETT:  I was going to explain the
           phenomena with that slide right there.  I don't have
           to address that now other than to say that as a
           result of the event and the inspection findings the
           plant revised procedures to limit the amount of VAR
           output that they could put out through their grid.
                       The next slide -- the licensee's
           procedures for verifying offsite power did not
           account for post trip voltages or instrument
           uncertainties.  In this case the dispatch center
           uses a post-contingency computer model to determine
           what the grid condition would be for several
           hypothesized transmission failures.  In the event
           that the computer model detects a potential low
           voltage condition it's supposed to activate an
           alarm.  They in turn were supposed to contact the
           Callaway plant and inform them of that alarm
           condition.
                       CHAIRMAN SIEBER:  And this occurs before
           any actuations of protected devices occur on the
           system?
                       MR. PRUETT:  This is all hypothetical.
                       CHAIRMAN SIEBER:  Right.  This is in
           advance.
                       MR. PRUETT:  In advance.  
                       CHAIRMAN SIEBER:  So this is a real load
           flow calculation?
                       MR. PRUETT:  Right.  That's correct.  
                       Some of the deficiencies involved in
           that communication process and some of the computer
           alarm setpoints -- the inspectors identified that
           the computer point alarm setpoints were non-
           conservative, and that was both at the plant end and
           at the dispatch center end.  On the plant end the
           maintenance personnel incorrectly set the alarm
           setpoint on the plant computer associated with grid
           voltage.
                       Even had they set it correctly the
           setpoint was non-conservative in that it did not
           account for instrument uncertainties associated with
           monitoring switchyard voltage.
                       On the dispatch center end they didn't
           have an appreciation for what the tech spec allowed
           value was for voltage, and consequently their
           predictor model alarm setpoint was set too high, so
           even though an actual low voltage condition existed
           their predictor model did not detect it, provide the
           appropriate alarm, and consequently the plant wasn't
           notified.
                       CHAIRMAN SIEBER:  Now, this issue went
           back to the early 1980s industry wide?
                       MR. PRUETT:  As far as --
                       CHAIRMAN SIEBER:  Low voltage --
                       MR. PRUETT:  Low voltage condition?
                       CHAIRMAN SIEBER:  Low voltage and low
           flows.  It goes back a long ways.
                       MR. PRUETT:  Long ways.
                       MR. BROCKMAN:  But it's really raised
           its head back up now when you're looking at all the
           implications with the wheeling that's being done and
           the artificial support.
                       CHAIRMAN SIEBER:  That's my question. 
           There is an information that was published about
           this one and four or five incidents like this
           over -- from '97 to '99 I think it was.  What is
           going on now in Region IV since this condition is
           getting worse day by day as the energy situation
           does not improve would be a good way to say it that
           would make other plants vulnerable to the same kinds
           of things?  Has somebody gone in and said, Do you
           have tap changers?  Have you had a load flow -- a
           recent load flow that tells you what these settings
           are?  What happens if -- what happens otherwise?
                       MR. PRUETT:  You mentioned one
           information notice that came out directly after this
           event.  There is also a regulatory information
           summary that came out --
                       CHAIRMAN SIEBER:  Right.
                       MR. PRUETT:  -- and in that summary,
           essentially it acknowledges that NEI committed to
           communicate these grid reliability concerns to the
           industry.  Out of that NPO is also conducting a
           review of grid reliability concerns that's supposed
           to be completed in 2002, and my recent discussions
           with the NRR folks indicates that the NRC may
           initiate a review of those implementations to
           resolve grid reliability concerns following the NPO
           review depending on the findings that come out of
           that.
                       CHAIRMAN SIEBER:  So the answer is no?
                       MR. PRUETT:  Well, that's long term
           plans.  In the near term several utilities reacted
           in response to those information notices and
           improved their communications with their dispatch
           centers.  Most of the utilities in Region IV have
           agreements with the dispatch centers and those
           dispatch centers use a post-contingency type of
           model to predict grid voltage conditions for those
           plants.
                       There's only -- I think there's only one
           that I came across, Cooper, that does not have a
           post-contingency model for a predictor.  All of the
           other sites that I've talked to did have such an
           agreement and model in place.  On top of that,
           specifically for the Entergy plants, since I'm most
           familiar with that, they will have no touch days. I
           know the west coast plants have no touch days based
           on loading on the grid, and at that point that's
           communicated through the plant status aspects of the
           inspections that the residents do, and the residents
           follow up on the onsite contingency plans associated
           with those.
                       MR. HOWELL:  And as you indicated, this
           is not a new issue, and we've had -- dealt with
           similar problems at some of our specific facilities
           in the past, Arkansas.
                       MR. BROCKMAN:  But to bring it up, we've
           got several less formal channels that have been
           used.  We have many regional utility group --
           engineering, licensing managers, plant managers and
           what have you that typically all the executive
           management whenever they have a meeting participates
           in.  This has been a topic of continual drum beating
           by us, and these forms bring it to their attention
           and to drive on there.  It's become an area of focus
           for my resident inspectors out there especially with
           respect to VAR loading, whereas they're doing plant
           status -- we really pay a new type of attention to
           that now as opposed to in the past.  
                       We don't just look at the spider graph. 
           If you get 200 or above we start inquiring as to
           what's going on, because it's getting in the realm
           of a concern, could start coming up with artificial
           holding out.
                       CHAIRMAN SIEBER:  Let me just ask one
           more simple question, and hopefully not engender a
           complex answer.  But I would be concerned about the
           west coast area network and the rolling blackouts
           and whether or not there have been load flows
           performed for calculations prior to deciding what
           they're going to black out and when, because that
           really changes the flow in the grid, changes the
           amount of VARs that get pumped around, changes the
           voltages at the substations of all these stations,
           and you can figure this out in advance.  Has anybody
           done that?
                       MR. BROCKMAN:  There's been a lot done
           on that area.  We've got one or two down where we're
           going to talk about California and I think we can
           get into that quite a bit.
                       CHAIRMAN SIEBER:  Thank you.
                       MR. PRUETT:  I just wanted to touch on
           some of the corrective actions that were taken.
                       MR. GWYNN:  Just as a matter of going
           back to our focus on the initial implementation of
           the reactor oversight program, in the past with this
           type of a learning experience in Region IV we very
           well may have initiated a regional initiative
           inspection where we would go to all 14 sites in
           Region IV and look at this, but we have not done
           that.  The agency is determining what the agency is
           going to do across the entire industry, and so
           that's why we don't have substantive inspection
           activities that we can say we've gone out and looked
           at this at every plant in the region.  We are
           waiting for program office to make decisions about
           those types of inspections.
                       CHAIRMAN SIEBER:  As an administrative
           process do you consider that to be timely and
           responsive to an evolving situation, or would you
           feel more comfortable just going and doing it
           yourself if you had the resources to do it?
                       MEMBER POWERS:  The other thing I worry
           about is if it's a western problem and headquarters
           weights it with --
                       CHAIRMAN SIEBER:  Eastern problems.
                       MEMBER POWERS:  -- eastern problems
           maybe it doesn't come out with the weighting that it
           deserves in this region.
                       MR. BROCKMAN:  A little bit of a dilemma
           that you get into here is the licensees have
           certainly been put on notice that they have to have
           the appropriate management controls and technical
           controls in place to ensure they're in compliance
           with their license, and that's what basically --
           what they've got to do is have a reliable grid to
           operate under.  We feel very comfortable we've
           communicated that to them.
                       Now, with the new program I have no
           reason at the moment to follow up in that area when
           they have all assured to me that is going to happen. 
           We are monitoring some of the indicators.  We think
           that if they start violating for example VAR loading
           and what have you that we would follow up on that.  
                       We'll be able to share with you in
           California's case we're doing a little more.  We've
           taken some additional steps on looking and
           challenging and staying interactive on there because
           of its exceptional vulnerability and the high public
           interest.  We're really back into the discussion we
           had before, and one of the points that got brought
           up in the IIEP corrective action is the
           differentiation now between having a responsive
           inspection program versus a predictive inspection
           program, and what you would be suggesting here would
           certainly be predictive type of inspection. 
                       CHAIRMAN SIEBER:  Anticipatory.
                       MR. BROCKMAN:  Anticipatory, yes.  A
           better word than predictive, but I think we're
           sharing the same vision, and the new program doesn't
           put us into that arena.
                       CHAIRMAN SIEBER:  I guess I look at some
           of these things a little differently too.  If you
           say here's your tech specs and here's all the
           setpoints and here's all your procedures and so
           forth, and you, Mr. Licensee, are responsible for
           maintaining this plan inside that envelope that's
           one thing.  On the other hand all these other things
           are happening from the outside in, and the licensee
           may not have control over it.  System operator now
           is running stuff as opposed to individual
           dispatchers, and --
                       MR. HOWELL:  And they were in full
           compliance with their tech specs.
                       CHAIRMAN SIEBER:  Absolutely.  
                       MR. HOWELL:  They passed all the
           surveillances for offsite power availability.
                       CHAIRMAN SIEBER:  Yes, sir.
                       Well, those are my concerns.
                       MR. HOWELL:  We understand.
                       MR. PRUETT:  I'm going to move on to the
           fourth item, which was the plant operators did not
           detect the low voltage condition following the SCRAM
           and additionally, the plant operators were not aware
           of the operability requirements associated with
           offsite power.  
                       Now, once they identified the moisture
           intrusion issue at the power supply for the alarm
           set point they dispatched maintenance personnel to
           correct that.  The next day they again had low
           voltage conditions in the switchyard, picked up the
           alarm set point on the plant computer, but the plant
           operators didn't recognize that that alarm had
           activated and consequently didn't take any actions.
                       Secondly, when interviewed the plant
           operators indicated that even if the dispatch center
           called and said the predictor model showed voltages
           would be below their minimum requirements following
           a plant trip they would not consider the offsite
           power source inoperable, and licensee management
           revised procedures and instituted some guidance to
           have the operators consider offsite power
           inoperable.  The predictor model showed voltages
           would be insufficient.
                       The next slide the inspectors identified
           if there was no agreement related to switchyard
           voltage between the Callaway plant and the energy
           supply operations personnel.  Following the
           inspection the licensee implemented an agreement
           between themselves and the transmission provider,
           and procedures were revised on both ends to notify
           Callaway of changes in grid system characteristics
           and to notify the plant 15 minutes before an
           anticipated out of range condition.
                       MEMBER POWERS:  When you look at this
           the immediate question is is this the only area
           where they needed to have an agreement between
           themselves and their electrical supply center.  Is
           it the only topic where they didn't have an
           agreement they needed one, or are there other areas?
                       MR. PRUETT:  Between them and the
           dispatch center?
                       MEMBER POWERS:  Right.
                       MR. PRUETT:  I don't know the full
           details of what that agreement involved.
                       MEMBER POWERS:  It may be the only one.
                       MR. BROCKMAN:  I'm hard pressed to think
           of another area.
                       MEMBER POWERS:  Nothing came to mind.
                       MR. BROCKMAN:  -- grids going to be
           jeopardized we've got an agreement.  I'm trying to
           figure out a different area that the load dispatch
           center and the plant would be involved with.  I know
           we had a major thunderstorm three or four months
           later after this and was on a Sunday afternoon, and
           various parts of the grid came crashing down over
           there, and this was weather induced, and we didn't
           have the problem at that stage of the game.
                       Some of the interim corrective actions
           they had implemented seemed to work on that weekend.
                       MR. HOWELL:  I know that the NRR does
           have grid reliability coordinators, and they have
           been making visits to these operators and
           understanding the agreements and interfaces, and
           that's the only thing that's come out of it so far.
                       MEMBER POWERS:  When you read the
           writeup on this -- that's the first question that
           emerges in this discussion.  Is this the beginning
           and the end of it or is there something else, and we
           just have to wait for another incident to come along
           to discover that something else.
                       MR. BROCKMAN:  We were left with no
           incident --
                       MEMBER POWERS:  Nothing comes to my mind
           either.
                       MR. PRUETT:  Kriss has the next slide
           up.  The load flow analysis underestimated the
           system loading conditions.  Specifically the load
           flow analysis was modeled on peak winter loading
           with an additional 5 percent conservatism.  In
           actuality the peak load conditions of the Callaway
           plant occurred in the summer of '99 and 2000.  
                       The corrective actions that came out of
           that were to update the load flow analysis
           following -- prior to each peak season, and also to
           include the sensitivity due to system transfers
           through their grid system.
                       CHAIRMAN SIEBER:  There are some systems
           that have on time, real time line loss and load flow
           programs to manage the system, and I don't know if
           you have any of those in your region but that
           capability is there to some extent, and that really
           helps.
                       MR. PRUETT:  Something else Callaway
           did, we mentioned that they installed the automatic
           load tap changing transformers following this event. 
           They also installed capacitor banks to support a
           block start if needed.
                       The next side there -- the information
           notices weren't dispositioned in accordance with
           licensee procedures.  Specifically there was a
           IN9807 offsite power reliability challenges from
           industry deregulation was reviewed by the facility
           and closed with no further action required.  That
           prompted them to review all the information notices
           issued since 1996, and there were additional
           corrective actions that came out of INs that weren't
           appropriately dispositioned.
                       CHAIRMAN SIEBER:  Going back to the
           capacitor banks, these are switchable banks?  Switch
           them in, switch them out.
                       MR. PRUETT:  I don't have the full
           knowledge on that.
                       CHAIRMAN SIEBER:  The other question is
           are they onsite or are they someplace else?
                       MR. PRUETT:  No.  They're onsite.
                       MEMBER UHRIG:  They're probably
           switchable but they're onsite.
                       CHAIRMAN SIEBER:  I imagine because it's
           either that or change to the field --
                       MEMBER UHRIG:  Yes.
                       CHAIRMAN SIEBER:  -- and you can't do
           that without getting into instability sometimes.
                       MEMBER LEITCH:  Concerning other areas
           of potential interface that may be required with the
           dispatcher as was Dr. Powers question, I have run
           into some situations where the dispatcher has
           certain understandings as far as off normal
           frequency operations, that is when you trip the unit
           and so forth in 61 cycles or 59 cycles, and some of
           those are not necessarily consistent with the best
           practices.  Some manufacturers of large turbines
           recommend against operating at power other than 60
           cycles right as is normally done because those --
           particularly those large last-stage buckets are so
           carefully tuned that the operation at other than 60
           cycles at full power may cause the blades to fail
           and there could be nuclear safety implications
           associated with turbine missiles and that type of
           thing.
                       So I guess that's a little bit of a
           stretch, but it might just be an interesting area to
           consider; that is, what is the relationship between
           frequency -- that is are these large nuclear units
           allowed by the practices with the dispatch office,
           are they allowed to operate for extended period of
           times at other than 60 cycles.
                       MR. PRUETT:  Okay.
                       MS. WESTON:  I have a question.  That
           information notice issued in March of 2000 indicates
           that there was a similar problem in '89 and '01, in
           '91 Millstone, in '93 Palo Verde, in '95 Diablo
           Canyon in '95.  What was being done in the interim
           to deal with this problem since obviously there were
           a number of related issues?  Was there anything done
           prior to now with regard to this issue?
                       MR. PRUETT:  That predates my tenure in
           the --
                       VOICE:  It's a binary answer.
                       VOICE:  Done from what perspective?  The
           licensee's perspective, or the NRC's?
                       MS. WESTON:  The NRC.
                       VOICE:  You know, I know at ANO, ANO
           addressed their specific issues, but --
                       MS. WESTON:  NRC.
                       VOICE:  Right.  In the early '90s.  Yes. 
           There's no direct inspection of this area.  There
           was previous information notices as the issues were
           emerging. 
                       In the case of Callaway the previous
           occurrence was not known until the investigation was
           conducted for the '99 events, so in every case it
           wasn't known necessarily that those occurrences
           occurred at that time.
                       CHAIRMAN SIEBER:  My memory isn't too
           great, but back in the 1980s I seem to recall a
           round of questions coming out on this subject which
           we did line losses and load flows and ended up
           putting in tap changers and changing bus
           configurations and especially if you change out a --
           I mean, a transformer and the impedance of the new
           one is a little different than the old one you end
           up with a whole host of different problem, because
           you may end up with surges too big that your circuit
           breakers will hold together when they trip, you
           know, and you could end up blowing out the breaker
           here and there.
                       So there's a lot goes into these
           calculations, and we modified the plant in the 1980s
           for that issue.
                       MR. BROCKMAN:  But the process would
           have been with the TI or incorporating something
           into the old core inspection program --
                       CHAIRMAN SIEBER:  Right.
                       MR. BROCKMAN:  -- during that time
           frame, and it wasn't either.
                       CHAIRMAN SIEBER:  It was NRC initiated
           that.
                       MR. HOWELL:  But there were -- as you
           may recall the electrical distribution system
           functional inspections made.
                       CHAIRMAN SIEBER:  Right.
                       MR. PRUETT:  Lastly, there were some
           generic communications that were issued following
           the Callaway event, and we touched on those already
           as well as NEI's involvement with NPO and NRR.
                       That's all I was going to talk about as
           far as the Callaway event is concerned, unless
           there's other questions.
                       CHAIRMAN SIEBER:  I think if would be
           good if we could move on to California grid.
                       MR. GWYNN:  We're far enough behind
           schedule that I'd like ask if you'd be agreeable to
           our just eliminating the discussion of the
           electrical design operations issues at Cooper from
           the planned agenda.
                       CHAIRMAN SIEBER:  I think we could.
                       MR. BROCKMAN:  Or let's just put it at
           the very end.  If we want to -- recovering all the
           time at the end of the day we'll come back to it,
           which I'm doubtful of, but --
                       CHAIRMAN SIEBER:  Another area that we
           may be able to cut back on to some extent is the San
           Onofre electrical fire because we have a lot of
           materials and pictures of that, along with --
                       MEMBER LEITCH:  We have a very short
           presentation if you have a very few questions.  One
           thing I'd like to hear if someone's up to date on it
           is apparently I believe there was a fire at Cooper
           earlier this week, and I'd like to be briefed very
           quickly on the events there.  Evidently they're a
           single loop operation.  I'm not sure if that was
           related to the fire.
                       MR. GWYNN:  Both San Onofre and Cooper
           on the same day experienced potential transformer
           explosions that affected the plants. The Cooper
           effect was much greater than what it was at San
           Onofre, but essentially the same event.
                       MR. BROCKMAN:  And David is acting as
           the branch chief for the branch that owns both of
           those plants, and he was also the regional duty
           officer for those two nights.
                       VOICE:  Why don't we go with California
           and then come back and touch on that briefly?
                       MR. LOVELESS:  As Ken told you, I'm
           David Loveless, currently acting as the branch chief
           with responsibility for Cooper, Fort Calhoun, and
           San Onofre, and I'm here to talk about some of the
           things that San Onofre and Diablo Canyon were seeing
           in California.  I guess if you've read any
           newspapers or watched the news you know that the
           people in California aren't really happy right now
           and that they have a lot of problems going on with
           their electric deregulation.
                       While we empathize with those
           individuals we basically are concerned that the
           plants continue to operate in a safe manner and that
           the financial conditions of the utilities aren't
           affecting that safe operations, and that's what I
           wanted to talk about today.  A couple of things that
           I will cover here is a little bit of history of the
           electric grid in California and how it got to where
           they are, what the current situation is under
           deregulation, what our response is to our concerns
           at the plant based on that condition, and then I'll
           provide a brief summary of where I think we are.
                       So California has for some time been an
           importer of power.  The last numbers that I heard
           ranged on the 20 percent range on the average, so
           they import a lot of power.  They don't have the
           resources to produce all the power they're using.
                       Another of the problems that set them up
           for this was the BANANA principle, which is build
           absolutely nothing anywhere near anybody, and that's
           been in existence for about ten years at least in
           California.  They have legal restrictions to
           building their plants.  They don't want them in
           their back yard.  They don't want any that burn coal
           or gas because they have emissions.  They don't want
           nuclear because they're scared of it, and so the
           bottom line is they just haven't been building new
           plants.  
                       But at the same time they've had
           significant electric power growth.  No one even
           began to understand how much power the internet and
           Silicon Valley was going to take, but it's using a
           lot.
                       The current situation -- this number I
           got from an Enron report that they've been
           collecting an average -- and this is averaged over
           night when it's real cheap and the peaks when it's
           real high -- $138 a megawatt wholesale power rates. 
           Well, our two major utilities, Pacific Gas and
           Electric and Southern California Edison, have a
           regulatory cap retail of $60 a megawatt hour, so
           where does that lead?  Well, Pacific Gas and
           Electric is in Chapter 11 bankruptcy, and Southern
           California Edison is working on a memorandum of
           understanding that they have developed with the
           State of California that will make substantial
           changes to their business, but they are hoping will
           bail them out and keep them from going bankrupt.
                       Now, Pacific Gas and Electric is the
           owner-operator of Diablo Canyon, and Southern
           California Edison is the primary owner and operator
           of San Onofre, so both of these companies are having
           significant financial difficulties right now.
                       What are we doing about it?  We
           developed a list of what we call financial impact
           observables.  I'll talk about those in just a
           minute, but we have basically a punch list that our
           resident inspectors go out on a weekly basis and
           keep in the back of their mind as they're doing
           their routine job, and they look at these
           performance indicators with a goal of determining
           early on that the financial situation of the
           utilities is affecting safe operations.
                       We have senior management visit both the
           sites once a month.  We've been doing that since
           January, and we talk with senior people out there. 
           We have retained shorter inspection report periods
           and we're including more details in the scope of
           those inspections in our inspection reports to
           assist the public and other interested members in
           understanding what we're doing out there to ensure
           that plants remain safe throughout this evolution.
                       We've had additional public meetings
           specifically tied to bankruptcy and the financial
           conditions, plus we've taken every opportunity we
           could to have meetings where the public was
           available and have press conferences associated with
           some of those meetings.  Senior management in the
           region has meetings weekly.  We have a call with
           both of the senior resident inspectors and discuss
           these observables.  I'm going to talk about other
           impacts:  morale, what the public's doing, all kinds
           of things.
                       We also have biweekly meetings with
           utility managers.  They've supported those to the
           point that we get senior managers in the corporate
           office and senior managers at the plant on the phone
           that specifically discuss their financial condition,
           things that they wouldn't be willing to discuss
           under any other circumstances, or not publicly, so
           we're getting as much information as we can to help
           us understand what they're doing.
                       The items that we've asked the resident
           staff to take a look at -- one of them is staffing. 
           We are looking at just their basic level of staffing
           at the plant with the assumption that one of two
           things might happen that could affect safety.  One
           is the better employees start to realize that the
           company is going down and look for other jobs and
           leave, and they start losing people that way. 
           Another would be -- excuse me.
                       MEMBER APOSTOLAKIS:  I think it's
           happening at Southern California.
                       MR. LOVELESS:  They haven't seen any
           increased attrition right now.  They are watching
           that closely as you might guess, but their staffing
           levels are staying fairly steady.  They're dropping
           a little bit but they're dropping along the line of
           a gap review that they did a couple of years ago and
           have had in place for quite some time.  And so
           currently we're not seeing anything there but we are
           definitely looking on a routine basis.
                       We're looking at plant maintenance.  We
           look at the backlogs in corrective maintenance.  Are
           they creeping up?  If they do go up we look for why. 
           Is it because suppliers won't provide the parts
           because they're afraid of not getting paid?  Is it
           because they don't have the money to buy things,
           that sort of thing.  That's the type of thought.  
                       So far, again, we've seen nothing. 
           We're seeing the normal ups and downs -- the
           corrective action process in that maintenance area.
                       We also looked at the preventive
           maintenance to make sure they're continually in full
           force, and so far they have been.  We're looking at
           outage in plant modifications.  Are they changing
           the scope of any outages?  Have they canceled or
           postponed any risk significant modifications? 
           Again, so far we've seen nothing here.  In fact, the
           unit 3 outage at SONGS we took some additional time
           in that outage to do some things that would make
           them more reliable in order to stay online
           throughout the summer, which is where the demand's
           going to be.
                       We've looked at a number of things in
           emergency preparedness.  We looked at training, make
           sure they're continuing to provide training to
           people, that they aren't trying to cut back in that
           area.  We look at the facilities, make sure they're
           ready.  We've looked at the emergency sirens, make
           sure that as they go into blackouts that they're not
           blacking out the emergency sirens so they wouldn't
           be available, and we actually found a couple of
           sirens that they had in blackout zones, and they've
           gone back and blocked those out so that they won't
           be -- so they won't lose power during an emergency
           if they're needed.
                       Also as Troy was talking, we're looking
           at grid stability.  The primary indicator of that is
           the VARs plan we've been looking, and they're pretty
           much staying at their historical levels.  We also --
           we looked at the ISO's responsibilities with respect
           to their emergencies and the licensees have asked
           the ISO to go back and look at grid stability, and
           they've actually recently changed their threshold
           for entering a stage three and going into blackouts,
           because they decided under certain conditions they
           wouldn't be as stable as they'd like to be at that
           point, so they're doing it earlier than they were
           back in January.
                       MEMBER UHRIG:  What authority if any
           does the utilities have over the ISOs?
                       MR. LOVELESS:  The utility has no
           specific authority.  They have agreements
           contractually for certain powers to --
                       MEMBER UHRIG:  When they gave up the
           grid they had lost all control of it.
                       MR. LOVELESS:  Pretty much, except that
           they are part owners in it, but, yes.  They don't
           operate the grid.
                       MEMBER UHRIG:  But the grid can impact
           the plant.
                       MR. LOVELESS:  That's true.  
                       MR. BROCKMAN:  And so they have
           agreements associated with them for the operability. 
           Yes.
                       MR. LOVELESS:  Also, the way the ISO
           works in California they don't black out
           transmission trunks.  They tell the utilities what
           their share of the blackout is and it's the
           utility's responsibility to select the blocks that
           they're going to black out and how.  So they're
           blacked out at a distribution level so that the
           transmission and the stability of that grid
           throughout remains there.
                       MR. BROCKMAN:  And all of the thresholds
           that you're hearing there are premised for the
           blackouts and everything to maintain the stability
           of the grid, not in response to instabilities.  All
           of those blackout activities of when you get to a
           certain level is to make sure you maintain an
           adequate margin, so that's a key philosophical
           application to understand.
                       MR. LOVELESS:  And it's also --
           actually, you could look at it as a benefit, because
           the ISO's responsibility and primary concern is the
           maintenance of that grid.  That's how they make
           their money, the transmission network, staying up
           and stay -- where the utilities want to sell power,
           and so the ISO being independent can direct
           blackouts in times that the utilities might have
           tried to push it.  I'm not saying they would.  I'm
           just telling you that having that independence has
           some benefits too.
                       MEMBER UHRIG:  You say they changed
           their threshold recently?  I assume you meant the
           trigger a blackout sooner?
                       MR. LOVELESS:  Yes.  That's correct. 
           They changed -- they were at 3 percent.  What's the
           new -- 5 percent.  Five percent's being reserved.  
                       MR. MARSCHALL:  Five percent total
           reserves.
                       MR. BROCKMAN:  The speaker is Charles
           Marschall.
                       CHAIRMAN SIEBER:  Actually, the hardware
           and the procedures for doing this came out of the
           failure at Big Alice in New York many years ago, and
           I think across the nation those procedures and
           equipment are in place to block shed distribution
           centers as opposed to transmission lines, and so
           that's the way you respond to an undergeneration
           issue.
                       MR. BROCKMAN:  It also lets them
           localize it very much, let's them do this several
           small areas for a period of time and be able to
           rotate that around and not get a large metropolitan
           area covered and what have you.
                       The interesting part is the need to
           coordinate this with the local law enforcement. 
           Everybody says, Well, why don't you just put out --
           if we go to blackouts today here's the areas that
           are going to get a blackout, and everybody knows
           between 4:00 and 5:00 I don't want to be on an
           elevator.  And the working agreements with the local
           law enforcement authorities are we can't do that. 
           Every crook in California will be in that
           distribution area between 4:00 and 5:00.
                       And so you get very much a security
           aspect that goes along with this where you have to
           have those types of considerations that you wouldn't
           necessarily think of right off the bat when you're
           looking at the philosophy.
                       MEMBER LEITCH:  Does your observation of
           staffing levels include not only the utility
           personnel but the contract?
                       MR. LOVELESS:  Total station numbers is
           what we've been looking at.
                       MEMBER UHRIG:  Does that include ISOs?
                       MR. MARSCHALL:  Charles Marschall again. 
           But the financial situation doesn't really affect
           the ISO.  It affects the utilities could have a
           shortfall because of the fact that they can't
           collect their costs, and so the ISOs are affected
           and the chances are that staffing really isn't a
           concern for the ISO.
                       MEMBER UHRIG:  Most of the staff came
           from the utilities anyhow that had the transmission
           lines before.  When they created the ISOs they
           didn't start out restaffing them from scratch.  They
           took the people who were there and --
                       MR. BROCKMAN:  But it came from the
           large wire part of the utility, not the plant
           operation staff.
                       MEMBER UHRIG:  Yes.  You're correct on
           that.
                       MR. LOVELESS:  So where does that leave
           us?  The current safety impacts that we've seen at
           the plants are none.  Both plants report having
           large enough cash supplies to continue to operate
           the plants in a safe manner, and the fact that long-
           term success of these companies depends on those
           plants continuing to run safely.
                       The utilities are working with the
           bankruptcy judge and with the state on a memorandum
           of understanding for SCE, and we are keeping close
           eye on that to make sure that none of the decisions
           made at those levels will impact the safe operations
           of these two plants.
                       MR. BROCKMAN:  The Department of Justice
           in fact has the responsibility to represent us as an
           interested party in this and is actively pursuing
           that responsibility in all of the proceedings.
                       MR. LOVELESS:  And so we as a region
           realize that we need to continue our vigilance, not
           relax in California because we have to ensure that
           they maintain safety at those plants, and we also
           have a very real role in public confidence through
           this crisis if you will, so --
                       MEMBER POWERS:  You raised this issue of
           the Department of Justice.  Without impugning my
           legal friends too much their skills in the area of
           reactor safety sometimes are less than optimal. 
           They have an adequate understanding of the financial
           requirements to maintain safety to represent
           adequately?
                       MR. BROCKMAN:  Yes.  I feel pretty good
           on this.  Larry Chandler is our representative in
           OJC interacting with them, and he and I have talked
           on numerous occasions, so while DOJ has that
           representational authority the communications
           channels are very good and all of the right people
           even down to us to provide that information back
           on -- allow the good information flow.  If there's
           any question that would come up and we would need to
           actively participate in it they would be calling on
           the right technical people to go up with them.
                       We're not caught with the hoitiness
           here.  This is our job.  Stay away.
                       MEMBER UHRIG:  I assume the solicitor
           general is the government's lawyer so to speak, and
           they're the ones that have to act on this, and I
           assume that they're coordinated in that Department
           of Justice very carefully?
                       MR. BROCKMAN:  I'm not sure on that.  I
           think this is all being done in state -- it's all
           right there.
                       Now, one final thing with respect to
           David's public confidence issue.  It is amazing how
           quickly we forget.  I was just out there last week
           at Diablo Canyon making -- we had a wonderful public
           meeting afterwards with placards and chants and all
           manner of people there, and there haven't been any
           of the blackout applications in several weeks in
           California, and everyone was willing again --
           everyone was out there, Yes.  We'll hang out laundry
           out on the lines.  Close down Diablo Canyon.  And
           the intervener organizations were just a couple of
           weeks ago quoted in the press as saying this is a
           very important part of our energy mix.  We're glad
           they're here and we need them.
                       So the public -- a lot of what we're
           doing there is really trying to make sure the public
           understands that we are being attentive to
           monitoring the activities and that right now while
           we don't see an actual consequence we're paying
           attention to this and if it would start going down a
           path we will be very active in it, and that's the
           level of confidence we're trying to provide them, is
           just it is being monitored.  It's being looked at.  
                       CHAIRMAN SIEBER:  I would prefer to see
           the agency acting in that role as opposed to
           responding to events, and so I hope you keep up the
           good work.
                       MR. BROCKMAN:  I have the schedule
           through December for all the monthly visits out
           there if anyone's looking for a trip.
                       CHAIRMAN SIEBER:  Are there any more
           questions on this topic?
                       (No response.)
                       CHAIRMAN SIEBER:  I think since we're
           going to try to roll on as far as we can it might be
           a good idea to take a ten minute break and come back
           at two o'clock.
                       (Whereupon, a short recess was taken.)
                       CHAIRMAN SIEBER:  At this time we'll
           resume the meeting.
                       MR. GWYNN:  I believe that we had a
           couple of questions that we needed to respond to. 
           David, there was a question about the transformer
           explosion that occurred at Cooper Nuclear Station.
                       MR. LOVELESS:  Sure.  
                       MR. GWYNN:  Did we answer that question?
                       MR. LOVELESS:  I answered it during the
           break.
                       MR. GWYNN:  Okay.  In that case I'd like
           to turn the meeting over to Art Howell, who will
           present the fire protection experience in Region IV.
                       Art.
                       MR. HOWELL:  Good afternoon.  Once again
           I am Art Howell, the director of the Division of
           Reactor Safety.  What I'd like to do is share with
           you the results and experiences that we've had with
           implementing the new fire protection inspection
           program, and the last slide in your package is a bar
           chart, but before I get there I thought a little
           background would be appropriate.
                       The new baseline inspection program --
           I'm on page 2 of the slides -- resulted in a
           significant increase in the inspection level of
           effort compared to the old program.  It's
           approximately a tenfold increase.  If you look at
           the old program it was roughly 25 to 30 hours every
           other SOWP cycle, so every three years, and the new
           program is one team inspection performed every three
           years at about 200 hours of effort plus another 33
           hours spread out over four quarters by the resident
           inspector, so when you annualize that it comes out
           to about a hundred hours, so it's about a tenfold
           increase.
                       MEMBER POWERS:  It's a big increase
           relative to what was in the past.  The question is
           is that big enough?
                       MR. HOWELL:  Our experience has
           indicated that based on what we know, yes.  And so
           far as the number of risk significant fire areas
           it's fairly limited, and so if your premise is that
           you can get to all those in a reasonable period of
           time on a sampling basis is the level of effort
           enough.  And Rebecca, who is one of our team
           leaders, Rebecca Neece, has been heavily involved in
           this, and I'd say overall from an overall
           perspective it is, but we have been challenged
           during individual inspections to get everything done
           in the inspection procedure.
                       And in particular what we have found is
           that it takes quite a bit of effort to exercise the
           fire protection and significance determination
           process, and oftentimes that has to be done after we
           get back from the site and so I don't think that was
           envisioned in the process, but it's recognized, but
           we are getting the inspections done.  So from that
           standpoint, yes, do we need to work on streamlining
           for the inspectors the use of the SDP?  That is true
           too.
                       CHAIRMAN SIEBER:  I guess the question
           is is the size and scope of the inspection geared to
           the FTEs available to perform, or is it geared to
           the actual risk in the plant?
                       MR. HOWELL:  It is risk informed in the
           sense that the goal of the inspection is to focus on
           the most risk significant fires.  During a pilot the
           level of effort for this inspection was half of what
           it is right now --
                       CHAIRMAN SIEBER:  Right.
                       MR. HOWELL:  -- and it was recognized
           that that clearly was not enough to accomplish the
           individual inspection objectives associated with the
           inspection.  
                       Now, at that time there was two elements
           of the inspection during the pilot that we're not
           implementing now, and yet we've doubled the level of
           effort.  And so whereas it's a challenge to perhaps
           get everything done and look at the extreme limit of
           the sample, which is five fire areas -- it's three
           to five fire areas -- we are getting that done.  The
           impact in on the tail end, not on the front end.
                       MEMBER POWERS:  Well, you're getting it
           done, but quite frankly, you're essentially giving
           everybody a bye on the associated circuits analysis.
                       MR. HOWELL:  That's correct. 
                       MEMBER POWERS:  And that is a non-
           trivial inspection.
                       MR. HOWELL:  That's correct.  That's
           true.
                       MEMBER POWERS:  That would be a big
           effort.
                       MR. HOWELL:  Right.  And in fact, when
           we get to the results our first pilot was Fort
           Calhoun, and at that time we were still doing
           associated circuits, and Rebecca Neece was the team
           leader.  She had to go back out to the site and it
           took several weeks of SRA involvement to disposition
           the inspection findings.  
                       And it was partly because of that
           experience that the program office increased the
           level of effort when we went into the initial year
           of implementation, and quite frankly, the other
           regions were experiencing similar outcomes and so
           that's why the level of effort was doubled, but it's
           still challenging.  It is challenging.
                       CHAIRMAN SIEBER:  I would imagine though
           that the moratorium on associated circuits
           inspections is going to end some time.
                       MEMBER POWERS:  It depends on how long
           NEI can string it out.
                       MR. HOWELL:  I know the testing -- that
           some testing has been completed and the results are
           being reviewed by the expert panels, and we have a
           number of open issues in that area that we can't
           disposition that we're waiting for guidance, but
           you're right.
                       Also one of the things that we were
           supposed to be looking at that we really couldn't do
           was reactor coolant pump lube oil collection
           systems, and you really can't look at those at
           power, and we don't do team inspections during
           outages, at least routine team inspections, and
           we've had issues in that area in the past that we've
           identified.  In the case of one plant they actually
           had a fire from leaking lube oil that wasn't
           collected that soaked some lagging, and because the
           wicking had started a fire in the containment, and I
           believe Kriss Kennedy responded to that event, and
           we've had others.
                       So we're not looking at that.  We're not
           looking at associated circuits.
                       CHAIRMAN SIEBER:  The point I was trying
           to make was if you look at the overall risk of fire
           based on IAPEEEs or level threes it's about equal to
           the risk of operating the plant.
                       MEMBER POWERS:  I can find plants,
           especially among the population of boiling water
           reactors, where fire outstrips the normal operating
           events.  If you do that split we'll all be fire
           protection engineers.
                       CHAIRMAN SIEBER:  I guess the point is
           on a real risk basis if you were scheduling based on
           risk there would be more effort put in.
                       MR. HOWELL:  Right.  But the point I
           was -- and I understand that.  The point I was
           trying to make is that there are only a limited
           number of risk significant fire areas, and how often
           do you have to look at them before you gain some
           confidence in how they're being maintained, how the
           engineering features are being controlled, et
           cetera.
                       MEMBER POWERS:  It really boils down to
           the transient combustible issues as far as frequency
           it seems to me.
                       MR. HOWELL:  We've had issues with
           transient combustibles, and I believe every time
           that we've looked at them using the tools that we
           have that they haven't had a significant impact on
           the fire loading in the particular fire areas. 
           We've had a number of them.  We've had some under
           the old program, and in fact, the old inspection
           program was primarily focused in looking at the day
           to day operating-maintenance testing transient
           combustible implementation of the program, so we had
           those issues.
                       Slide three -- the inspection is broken
           down into two areas of responsibility.  One is
           performed by the resident inspectors on a quarterly
           basis, as I indicated.  They are looking at the same
           types of things that we principally looked at under
           the old core program which was performed by the
           region based inspectors, so that's really the only
           significant difference.  And the level of effort is
           higher.  It's 33 hours a year instead of 25 hours
           every three years, and then once a year they observe
           a fire drill.
                       Slide four -- the region based
           inspection is more focused on achievement and
           maintenance of safe shutdown and everything that
           goes with it.  I touched on the areas that aren't
           inspected, associated circuits being a major
           omission until that's straightened out.  I already
           talked about the comparison to the old program on
           slide five, so we skip over that.
                       Going on to slide seven, results of the
           team inspections, we are finding instances of
           failure to meet separation requirements,
           inadequacies with passive barriers, inadequate
           emergency lighting, problems with suppression and
           detection not meeting code commitments that they're
           committed to, you name it.  Everything except -- we
           haven't really had many if any findings associated
           with manual actions of operators to achieve either
           safe shutdown or ultimate shutdown, which is
           somewhat surprising given that a number of our
           licensees do rely on manual actions, and many of
           them are time critical.  I would have thought just
           as an inspector that that's an area that might be
           potentially weak.
                       MEMBER POWERS:  How many plants in your
           reviewing have self-induced station blackouts?
                       MR. HOWELL:  I'll have to get back to
           you on that.
                       MR. SINGH:  What was your question?
                       MEMBER POWERS:  How many plants in this
           region use self-induced station blackout?
                       MR. HOWELL:  She just mentioned Arkansas
           Nuclear 1.
                       MR. SINGH:  There's only one that I know
           of.  Even they abandoned that if I remember.
                       MS. NEECE:  I'm Rebecca Neece.  I was
           the team leader for the recent Arkansas inspection. 
           We just got off the site from performing the
           Arkansas fire protection inspection, and one of the
           areas we looked at had a number of manual actions
           they had to take credit for because they decided not
           to wrap or protect one train of redundant safe
           shutdown equipment.  
                       And in listing the number of items that
           could happen all these things that could happen, we
           ran across one where they assume a loss of ISET
           power but they could also lose DC power which means
           that they could also lose service water to the
           diesels, which mean they would have to -- the
           actions are to trip the diesel.
                       At the same time if they didn't have DC
           power they would be in a station blackout for a
           certain amount of time before they could get the
           diesels back up.  And it's not exactly a self-
           imposed station blackout but it is in response to
           some spurious actuation that could happen in an
           area.  It was a short period of time.  I think 7-1/2
           minutes.
                       MR. HOWELL:  One of the things that we
           did note during the inspection was that just prior
           to us coming out there they had spent a lot of time
           on operator training and making sure that they could
           meet the time lines that they had established, and
           so it's not at all clear that until they did that
           that they would have achieved those time lines.
                       We have completed -- on slide eight
           you'll notice the number of triennial fire
           protection team inspections we've completed.  We've
           completed eight.  Rebecca mentioned ANO.  That one's
           not listed because it's not completed yet.
                       On the next slide, which is also
           reflected by the chart up there is a breakdown of
           the findings by type for the eight baseline
           inspections, the team inspections, as well as the
           findings from the resident portion of the inspection
           procedure.  With respect to the team inspections we
           found findings at six of eight sites, the two
           exceptions, Palo Verde and River Bend.  
                       I think it's interesting to note River
           Bend is a plant that has had chronic fire protection
           issues throughout the '80s and '90s.  Jake himself
           has been responsible for finding some significant
           issues in the early '90s that resulted in escalated
           enforcement.  This is the plant that started the
           thermo-lag issue.  They also received a fire
           protection functional inspection in 1997, a number
           of issues there with associated circuits.
                       And so we went out there just recently
           last month I believe and we had no significant
           findings, and my read on that it's a testament that
           after all this time they've finally implemented some
           corrective actions to address issues in the fire
           protection area.
                       As you can see, we have issues in
           separation, which also includes passive barriers,
           and that's really the only major trend if you will
           or pattern.  A few issues in detection and
           suppression, emergency lighting, transient
           combustibles, and fire watch training.  I talked
           about some of the conspicuous absence of findings,
           lube oil collection system findings because we don't
           inspect those any more under this procedure, and
           associated circuits.  We have about a half a dozen
           unresolved items, apparent violations on associated
           circuits at both BWRs and PWRs that we are waiting
           to disposition.  
                       Just looking at the groupings, in the
           separation area this represents a gamut of unlatched
           on inoperable fire doors, degraded fire wrap, holes
           in ceilings that separate fire rooms or fire areas,
           degraded seals in one case, intervening
           combustibles, and lack of cable separation either
           not meeting the 20 feet in 3G2 or not meeting what
           they said in their exemption requests.
                       CHAIRMAN SIEBER:  Fire dampers -- are
           they continuing to be a problem or don't you know?
                       MR. HOWELL:  I believe we may have,
           what, one issue involving unqualified fire dampers
           in these 19 findings.
                       MS. NEECE:  There might have been one. 
           It was a resident --
                       MR. HOWELL:  Right.  In detection and
           suppression -- this is primarily involving not
           placing detectors per the NEPA code, or in one case
           there were sprinklers that they changed the diameter
           of the sprinkler head holes without evaluation. 
           Emergency lighting, inadequate corrective actions
           for unreliable DC batteries for some of the
           emergency lightings at one plant, and in one case
           inadequate lighting for an operator to implement a
           manual action to open the service water valve which
           supplied reactor equipment cooling to the
           hypercooling injection system, and that was at
           Cooper Nuclear Station.
                       Transient combustibles include either
           not being on the permit or not being in the program,
           just overlooked it totally, and then fire watch --
           one instance in which members were conducting fire
           watch duties and they hadn't been trained.
                       All these issues were green per the fire
           protection SDPs.  We had two that were borderline
           white and were ultimately dispositioned before we
           got to a regulatory conference.  One of those
           involved cable separation issues at Fort Calhoun
           Station.  
                       They -- in one particular fire area they
           had only about three feet of separation in between
           redundant trains and safe shutdown, and in this
           particular fire area it had cabling that fed almost
           all their accident mitigation motor-driven pumps,
           and this was a case that was complicated by the fact
           that they had submitted an exemption request in the
           mid-80s indicating that we don't meet the 20 feet
           but we have ten feet and we have suppression and
           detection.  So the staff granted the exemption based
           on having a little bit of basically 3GA and B and C.
                       And when we went out Rebecca was the
           team leader, went out, did the inspection.  We found
           that no, they didn't even meet the ten feet that
           they said they had in the exemption request.  They
           had three feet in some cases.  That one was
           borderline.  it ultimately -- correct me if I'm
           wrong -- it hinged on whether or not automatic
           suppression would extinguish the fire before the
           cabling that fed the fire water pumps was in fact
           damaged, which also went through the same room.  
                       That one took a lot of time because it
           wasn't real clear to us that the licensee had a good
           handle on what cabling powered what equipment.  It
           took quite a while to identify the equipment list,
           which also complicates exercising the fire
           protection SDP, and so it took a number of weeks
           before we dispositioned that issue.
                       The other one was more straightforward. 
           It was actually a three-hour rated fire door at ANO
           separated, both violates the switch gear rooms and
           it turns out in that case they had a -- although it
           wasn't really documented and they weren't taking
           logs they did have an ineffective roving fire watch
           that was going through there, so they had a comp
           measure in place.
                       Again, no obvious trends or patterns
           with the exception that most of the findings or
           certainly the significant portion of the findings
           are in the separation area, which is not unexpected
           given the focus of the inspection.  But again,
           what's a little bit troubling is that there are
           three or four examples here in which exemptions were
           granted and either the original plant configuration
           that formed the basis for the exemption was never
           met, or it was changed as a result of modifications
           that occurred and was not detected over the years.
                       That's a summary of the findings.  We
           touched on the challenges.  I mentioned some of
           them.  One is -- this was a new area for us, and it
           was a significant increase in level of effort, and
           so we enter this new program with some trepidation
           in the fire protection area, and through the use of
           the short-term formal training with Brookhaven and
           the reliance on contractors in part and OJT we've
           been able to implement the program, and quite
           successfully I think.  
                       We're finding issues that we clearly
           would not have found under the old program, but then
           the question is how significant are they given the
           tools that we have?  There's still some questions
           about implementing the fire SDP, which we talked
           about earlier.
                       MEMBER POWERS:  Several of the findings
           come out as green based on ignition frequency
           arguments.  How do you make those arguments?
                       MS. NEECE:  Several of the findings come
           out green because of the ignition frequencies are so
           low.  What we found in running the SDP from the site
           you run a phase two SDP, and it's a simplified
           version.  You're not taking into account the
           probability of a spurious actuation, a probability
           of fire affecting this area.  If they don't provide
           the requisite level of protection you assume a
           credible fire but you -- because we don't take into
           account the probability of spurious actuations or
           the probability the fire might not reach to a
           certain point you basically assume everything in
           there that's not protected is consumed by the fire.
                       We have found that if we have a
           degradation in suppression that seems to be more
           significant than the ignition frequencies.  The
           ignition frequencies for the areas that we choose
           usually run around 1e to the minus three, 1e to the
           minus four.  They're all about the same.  The
           differences in the ones that are borderline white
           and ones that are clearly green have to do with the
           degradation we give them for suppression, and that
           makes sense if the fire can be suppressed to the
           point that they fire brigade can respond in 15
           minutes and there not that much damage.  Then it
           makes sense for it to be a green issue rather than a
           white issue, so that's been my experience so far.  
                       Again, another concern that I would have
           is relying on the ignition frequencies we get from
           the IPEEE.  The IPEEE is not required to be revised
           or a control document, and as changes go along in
           the plant I'm -- we have to use that ignition
           frequency in the phase two, and it's developed by
           the licensees and it's not revised as the plant is
           modified or changed.
                       MR. HOWELL:  Isn't it our experience
           that some of those are actually conservative because
           if one considers a credible fire as opposed to any

           and all fires in a particular fire area the
           frequency may be less?
                       MS. NEECE:  Yes.  That's correct.  
                       Did I answer your question?
                       MEMBER POWERS:  Maybe.
                       MS. NEECE:  Do you have another one?
                       MR. HOWELL:  You made an earlier point
           earlier in the day about it all boils down to how
           much credit one gets for automatic suppression, et
           cetera.  Yes, and there's a lot of latitude there,
           and ultimately that has affected some outcomes.  I
           believe Forth Calhoun was initially three greens
           next to a white, or was a white --
                       MS. NEECE:  It was a white.
                       MR. HOWELL:  -- until we came to the
           conclusion that suppression would extinguish this
           fire before the fire water pumps were put out of
           commission.
                       MEMBER POWERS:  How do you decide on the
           response time of the fire brigades?
                       MS. NEECE:  How do we decide on the
           response time of the fire brigade?
                       MEMBER POWERS:  Right.  You've got a
           fire in a particular fire area.  I may or may not
           have automatic suppression.  I certainly can't count
           on that to put the fire out, so I need the
           firefighters to get to that to respond and put out
           the fire.  How do I estimate how long it takes them
           to do that?
                       MR. HOWELL:  To the extent that that
           information is available, which it may not be in
           every case, we would consider it, but clearly it
           isn't available and so we have to fall back to
           what's been our experience in observing the fire
           brigades over time and have we identified
           performance problems.  And essentially -- correct me
           if I'm wrong -- if there have been no documented
           issues and there's no time line that we can verify
           in terms of response time we default to giving them
           maximum credit under the fire protection SDP.
                       MEMBER POWERS:  You give them maximum
           credit?
                       MR. HOWELL:  Yes.  Right.
                       MS. NEECE:  Normal operating --
                       MR. HOWELL:  Yes.  If there's no
           performance deficiencies based on observations of
           the drills and absent any other negative information
           they get credit.
                       MEMBER POWERS:  So you really don't have
           a database to draw upon in general?
                       MR. HOWELL:  True.  And -- but as you
           noted or as I noted, we do now have at least
           provisions to monitor fire brigades, although it's
           not particularly frequent.  We have an opportunity
           to build that database with time through
           observation.
                       MEMBER POWERS:  We'll certainly discuss
           San Onofre, discuss the barriers to effective
           firefighter response and communications with the
           control room.
                       MR. GWYNN:  And Clyde Osterholtz is
           here.  He's the senior resident inspector at San
           Onofre.  He led the team that responded to the fire
           at San Onofre.  At that time he was not yet assigned
           at San Onofre, but if you'd like I'd like to ask
           Clyde to go ahead and make his presentation on the
           San Onofre fire.
                       MR. OSTERHOLTZ:  It's a great lead in. 
           Thank you, Pat.  I'm going to try to make this as
           brief as possible because I know we're a little bit
           behind.  
                       What we had here at San Onofre is
           essentially a secondary breaker failure that had
           complications which made a resultant reactor trip
           and a complicated recovery.  DC lube oil pump for
           the turbine didn't start when it was supposed to, so
           the turbine had to -- had grinded down in about two
           minutes when it should have gone down in about 2.5
           hours, so they were down for a significant period of
           time preparing that turbine work.  I think everybody
           is aware that I had some pictures but I think you
           mentioned that most folks have seen those.
                       So just briefly, the plant was at 39
           percent power on February 3 when they were going to
           switch from the reserve auxiliary transformers to
           the unit auxiliary transformers, and as most of you
           are aware this is a normal practice to get your
           house loads on your turbine generator instead of
           depending on offsite power.  When that happened in
           bus 3A07 breaker 12 developed a fault where the
           phase Charlie portion of it partially closed but
           didn't fully close, and that was determined to be
           caused by increased resistance in the breaker
           contacting mechanism.  
                       That was one possible explanation, or
           the other likely explanation was that there's a
           fiberglass pusher in side that breaker that may have
           had a crack and failed.
                       MEMBER POWERS:  Now, that one I didn't
           know about.
                       MR. OSTERHOLTZ:  That's not in the
           report.  That is in their root cause analysis and
           it's something they're still looking at now. 
           They'll never I don't believe --
                       MEMBER POWERS:  Well, it's fried. 
           You'll never find out --
                       MR. OSTERHOLTZ:  Right.  A definitive
           root cause analysis to this problem.  
                       MEMBER POWERS:  Is the manufacturer
           looking at it?
                       MR. OSTERHOLTZ:  Vendors are involved,
           and they're looking at it as well.  They're also
           looking at increasing the frequency of how often
           they look at these breakers, do refurbishments, and
           perform inspections on them.  
                       The big complication here was the
           breaker that attaches to the reserve auxiliary
           transformers is only two cubicles down, and although
           its mechanism to not reshut back onto the reserve
           auxiliary transformers functioned correctly, it
           arced from the ionizing gases developed from the
           fire in the 12 breaker.  That subsequently forced
           the reserve auxiliary transformers to trip, and as
           you can see at the bottom of your handout I've
           divided out into the 6.9KV reactor coolant pump
           buses, the vital buses, and the non-vital.  
                       So at this stage of the game, since
           you've got the RATs seeing the fault, you've got the
           unit AT seeing the fault, everything goes to unit 3
           as far as the 6.9 and the 4KV vital are concerned,
           and you lose the secondary buses, and that
           subsequently meant that you lost your AC lube oil
           pump for the turbine and the DC lube oil pump didn't
           start.
                       CHAIRMAN SIEBER:  Someplace I either
           remember or am mistaken that -- were the dividing
           metal shields from one cubicle to another in place
           when this failure occurred or were they missing? 
           You know how you put metal-clad switchgears broken
           up into cubicles?  There's metal shields between
           them.
                       MR. OSTERHOLTZ:  The metal -- as far
           as -- our inspection determined that everything was
           in place that should have been there in between
           those two breakers.
                       CHAIRMAN SIEBER:  I'm probably mistaken
           then.
                       MR. OSTERHOLTZ:  Okay.
                       MEMBER POWERS:  The magnitude of the
           fire is such that the shields wouldn't have made any
           difference.  
                       MR. OSTERHOLTZ:  Right.  And I know you
           are all interested in automatic fire mitigation
           equipment.  This secondary switch gear room had
           none, but it did have fire detection equipment.  I
           offer that out for you as well.
                       In addition to all of those problems
           this fault caused DC grounds about 800 amps worth
           between the secondary battery and ground, which was
           just enough to give you a significant problem but we
           not enough to trip open your protective breakers, so
           therefore they lost control room annunciators.
                       MEMBER POWERS:  There must be some sort
           of rule that that's what's going to happen.
                       MR. OSTERHOLTZ:  So they had a
           distribution panel in the control room that fed
           power to the control room annunciators and tried to
           reset that breaker.  It retripped, so they
           subsequently just stripped the bus, shut that
           distribution panel breaker and were able to restore
           control room annunciators in about 14 minutes.  So
           we gave them a thumbs up for that, because we
           thought that was above average.
                       They did enter an unusual event based on
           a fire that could have or was adjacent to areas that
           had safety-related equipment in it.  In retrospect
           they believe they never really had to enter the
           emergency plant at all because of the location of
           the fire and the fact that it didn't affect any
           safety-related equipment.  And their emergency plan
           is structured such that they have a specific list of
           what is the definition of when you have to enter an
           unusual event what equipment is affected, and none
           of it was subsequently involved.
                       MR. LARKINS:  Would the loss of the
           control room annunciators have driven them to
           that -- to an emergency plan --
                       MR. OSTERHOLTZ:  We looked very closely
           at that.  Loss of control room annunciators gets you
           into an unusual event if you lose them for 15
           minutes --
                       MR. LARKINS:  Okay.
                       MR. OSTERHOLTZ:  -- and their logs had
           them down --
                       MR. BROCKMAN:  Now, this is an
           interesting point because you're getting into a lot
           of legalistic things here with respect to do you
           have a violation?  Do I have to make an appropriate
           report within X amount of time, and not into the
           aspect of is the right thing to do to utilize some
           of the facilities for marshaling people and
           controlling and what have you, and that's why they
           get so particular on some of these issues, and
           you're really getting into the legalisms of
           enforcement.
                       CHAIRMAN SIEBER:  The more interesting
           thing comes later.  
                       MR. OSTERHOLTZ:  I wasn't really clear
           on that though.  The answer to your question is the
           loss of annunciators automatically gets you into an
           unusual event, so that did apply.  If you get into
           loss of annunciators for more than 15 minutes it
           goes to an alert from an unusual event.  I just want
           to make that clarification.  
                       And subsequent recovery -- we had a five
           man fire department team show up at the scene.  San
           Onofre is different than every other plant I've seen
           where they don't have a dedicated fire brigade made
           out of control room or licensed operators, security
           personnel, et cetera. This is a dedicated fire
           department, and it showed up.  Had a fire chief who
           is the fire chief for the site who happened to be
           there on time.  In fact, most of their senior folks
           happened to be there because they were in this
           evolution of starting the plant up after an outage.
                       MEMBER POWERS:  You realize that they
           were about to host the fire protection forum in San
           Diego the next morning.
                       MR. OSTERHOLTZ:  In any case, when the
           firefighters got to the cubicle in question there
           was heavy, thick smoke.  They began ventilating. 
           They used haylon PKP portable fire extinguishers.  I
           think they exhausted between 22 and 24 total
           canisters.  They had the fire under control.  There
           was some communications problems between the shift
           manager and the fire chief at the scene because they
           had a liaison who was an operator -- licensed
           reactor operator transferring information.  
                       There was a little bit of confusion. 
           The fire chief reported no flames visible.  That was
           translated to the control room as the fire was out,
           when actually the fire was under control but the
           cubicle door was still closed and they just kept
           flashing it with powder, and then every time they
           opened the door it would reflash.  They'd hit it
           with more powder and keep the door shut.
                       And we estimated there was about a 16
           minute delay in getting water put on the fire
           because the shift manager was reluctant to give that
           authorization even though the fire chief -- once the
           fire chief spoke to him personally the shift manager
           was convinced, the door was opened, and the fire was
           completely extinguished using water.
                       MEMBER APOSTOLAKIS:  I thought that
           issue of using water had been settled after Browns
           Ferry.  We still have this hesitation?
                       MR. GWYNN:  We saw the exact same
           characteristics at Waterford during a significant
           fire very similar to this --
                       MEMBER APOSTOLAKIS:  So there's still a
           reluctance to use water?
                       MR. GWYNN:  Yes.  And it depends on how
           the people have been trained, and in particular the
           control room folks, whether they came through the
           Navy program, whether they've been trained
           subsequent to that.  The Navy trains people you
           never put water on an electrical fire, but in fact
           the industry knows that you can safely use water on
           an electrical fire under controlled circumstances,
           and so it was a training issue at Waterford.  We saw
           remnants of that here --
                       MEMBER POWERS:  It's a training issue
           here as well.
                       MR. GWYNN:  -- where the fire brigade
           knew the criteria and knew the approaches, but the
           person who was in charge in the control room was
           reluctant. 
                       MEMBER APOSTOLAKIS:  He was from the
           Navy?
                       MR. OSTERHOLTZ:  As most of their
           control room operators are.
                       MEMBER POWERS:  I think it's a training
           issue here as well.  I think these people were just
           not familiar with the process.
                       MR. OSTERHOLTZ:  That was one of the
           things that we brought up to them. The licensed
           operators since they are not involved in fire
           brigade activities don't receive training on
           advanced firefighting techniques such as using water
           on energized equipment.  I think that added to some
           of the confusion.  The licensee saw it more as a
           command and control issue where they're going to
           make sure the shift manager understands the fire
           chief is the expert.  He's the one in charge.  Take
           his advice when you're in these situations.
                       MEMBER POWERS:  What do you do when the
           fire chief isn't -- just doesn't happen to be there?
                       MR. OSTERHOLTZ:  Then there's a
           designated incident commander assigned to the fire
           department to perform that function.
                       MEMBER APOSTOLAKIS:  Now, this
           reflushing when the portable fire extinguishers were
           used, is that something that's common?
                       VOICE:  Yes.  Any time you've got a fire
           in a cabinet --
                       MR. OSTERHOLTZ:  Yes.  You have a medium
           that takes the fire and puts it out, but then when
           it's dispersed as oxygen you come back into the
           area.
                       MEMBER APOSTOLAKIS:  So it just tries to
           starve the fire?
                       MR. OSTERHOLTZ:  That's correct.
                       MEMBER APOSTOLAKIS:  So why are we using
           them at all?
                       MEMBER POWERS:  These dry chemicals are
           simply oxygen displacement devices, and they in fact
           what they act is a nice insulator to assure the
           stuff is nice and hot, so as soon as oxygen comes
           back to it it flashes.  It happens all the time
           in --
                       MR. OSTERHOLTZ:  And although we noted
           that there was those 16 minutes delay in using the
           water we did conclude that it really didn't have any
           effect on the outcome of the event because they had
           the fire totally under control, isolated, and it was
           completely away from any of the safety --
                       CHAIRMAN SIEBER:  Completely away may be
           a little strong, isn't it?
                       MR. OSTERHOLTZ:  When I say completely
           away we felt that it was far enough away where the
           fire could not affect safety related equipment.
                       CHAIRMAN SIEBER:  With that amount of
           control on it.  Had the activities been delayed
           substantially then it would have been a worse fire. 
           I don't fault your report.  I think the report's
           right, but -- in fact I enjoyed your report.
                       MR. OSTERHOLTZ:  Thank you.
                       And that's it in brief.  It took them
           some time to recover because of the significant
           turbine damage.  However, just in ending I'll tell
           you we were very impressed on their startup because
           of this -- there's eleven journal bearings in this
           turbine.  They're all different sized now because
           they had to lay the thing down because of the damage
           done to the shaft, but when they started up they
           expected to have to come back down to do rebalancing
           work, and they started up and went completely up
           without having to do any of that, and their
           vibrations are consistent with what they have on
           unit 2.  
                       So that was -- we were pleased with the
           quality of the work that went into that turbine.
                       CHAIRMAN SIEBER:  Now, they changed out
           the old English electric turbines there?  They
           replaced their turbines.  Right?
                       MR. OSTERHOLTZ:  They're still the
           English electric design.
                       CHAIRMAN SIEBER:  Are they?
                       MR. OSTERHOLTZ:  Yes.  In fact, they're
           the only ones left.  I think Fermi was the last
           other plant that --
                       CHAIRMAN SIEBER:  They aren't too
           smooth.
                       MR. BROCKMAN:  In fact, the station
           management as part of their recovery operations
           visited England to see some of the work that was
           being done and wasn't happy that their plant wasn't
           operating and the Brits were taking the weekend off.
                       MEMBER LEITCH:  The loss of the DC lube
           oil pumps to the turbine I guess because that's not
           safety related you didn't go down that road?
                       MR. OSTERHOLTZ:  We looked at it.  It
           was not something that we spent significant time on,
           because although the destruction of the turbine was
           a significant financial loss for them it really
           didn't impact the event safety wise -- rector safety
           wise on our end.
                       However, I will let you know that part
           of that corrective action is they're now going to
           have two redundant DC lube oil pumps for each
           turbine so if this ever happened again they would
           have a backup.
                       MEMBER LEITCH:  But the loss of that DC
           I believe was related to the miscalibration of the
           DC breaker.
                       MR. OSTERHOLTZ:  An over current
           breaker.  It was more of a mispositioning after
           calibration.  You have a low to high. They did a
           bunch of testing in the lower range and they thought
           they were leaving it in the high range but they
           actually went too far around and now we're at the
           bottom of the low range again.
                       MEMBER LEITCH:  Did you take a look at
           whether that was generic?  Although that was the
           balance of the plant did that -- could that kind of
           an error have occurred in the safety related
           equipment?
                       MR. OSTERHOLTZ:  Yes.  The breaker
           specialist did look at that and determined that it
           was an isolated problem to that maintenance
           activity.  
                       MEMBER LEITCH:  Because it sounds as
           though it may be generic to that type of breaker I
           guess, and that was not the case?
                       MR. OSTERHOLTZ:  Not the case.
                       MEMBER LEITCH:  Okay.
                       MR. OSTERHOLTZ:  In fact, one of the
           other things they're looking at is getting rid of
           that overcurrent device completely for this
           equipment, because their view is who cares if you
           burn this pump up?  You let it supply lube oil to
           the turbine as long as possible.
                       MEMBER LEITCH:  Right.  
                       CHAIRMAN SIEBER:  Save the pump and lose
           the turbine?
                       MR. OSTERHOLTZ:  That's what happened
           unfortunately in the case in February --
                       CHAIRMAN SIEBER:  Did they damage
           anything else besides the bearings, the shaft, and
           perhaps seals?
                       MR. OSTERHOLTZ:  Exciter had significant
           damage, had to be shipped --
                       CHAIRMAN SIEBER:  Okay.
                       MR. OSTERHOLTZ:  -- by airplane to
           Virginia I think.  It was a horrendous expense.
                       MR. BROCKMAN:  The front thrust bearing
           when I was out there was really something to see. 
           Imagine stopping your car from 90 miles an hour with
           no brake pads and what your discs would look like
           and the coloring and the striations and everything. 
           That's exactly what happened.  From 1,800 RPMs the
           front thrust bearing was the spindle brake, and it
           looked it.
                       CHAIRMAN SIEBER:  Okay.  Any other
           questions?
                       MR. LARKINS:  So the violation here was
           one non-cited green?
                       MR. OSTERHOLTZ:  One non-cited green.  I
           didn't get into that because it really didn't affect
           the fire, but they did overfill a condensate storage
           tank inadvertently because of a difference between
           unit 2 and unit 3.  A fill value for unit 3 fails
           open on a loss of power.  The fill valve on unit 2
           fails shut.  So the operators were thinking unit 2
           and inadvertently left water going to the condensate
           storage tanks.  
                       It overflowed and it's in a vault that's
           seismically qualified.  It got up to about 12 feet
           in the vault and at the bottom of this vault are
           valves that will cross connect the main tank to its
           backup tank in case that tank empties to give it
           seismically qualified water, and that tank was
           effectively rendered inoperable because you couldn't
           get to the valves because they were 12 feet
           underwater.
                       CHAIRMAN SIEBER:  Did it float the tank?
                       MR. OSTERHOLTZ:  There was a nitrogen
           blanket at the top of the tank that did burst.  Yes.
                       CHAIRMAN SIEBER:  But it didn't float
           the tank off its structure?
                       MR. OSTERHOLTZ:  No.  It did not.
                       CHAIRMAN SIEBER:  Okay.
                       MEMBER LEITCH:  Absent that event there
           would have been no violation at all then?  Is that
           correct?
                       MR. OSTERHOLTZ:  Had they realized that
           valve was opened and shut it and controlled the
           condensate storage tank level there would have been
           no findings of color.
                       MR. GWYNN:  So I stand corrected on my
           statement earlier.  There were some safety
           implications --
                       MEMBER POWERS:  The most significant
           thing is just this communication from control room
           to fire brigade issue, and I guess you feel like
           they've handled that issue?
                       MR. OSTERHOLTZ:  They've embraced it. 
           It's in their corrective action program.  It may be
           too early to say definitively that they have
           completely resolved that problem.
                       MR. SINGH:  How do you correct it?
                       CHAIRMAN SIEBER:  It's a fact that fog
           nozzles can be used on electrical fires provided
           it's not saltwater.
                       VOICE:  It sounds like they've gone
           policy wise here.
                       MS. NEECE:  Yes.  Can I make a comment?
                       VOICE:  Policy training, and we'll
           observe it during drills and what have you and see
           if they test it, and other people say, Yes.  I
           understand you're in control.  You say water, go
           with water.  That's the way it will have to be --
                       MR. SINGH:  I was going to make comment. 
           After the Waterford fire, when they pour water on
           the -- there was a counterpart meeting and the
           gentlemen from SONGS were there, he was sitting next
           to me at NEI conference when this happened.  Anyway,
           they have already administrative procedures in place
           to tell the fire brigade what to do or what not to
           do, so I don't know if he was familiar with the
           procedures or not or what happened.  I have no idea. 
           But they were in place at that time.
                       MR. GWYNN:  Yes.  It was a matter of
           this one individual in the control room who was in
           charge who was reluctant to have the fire brigade do
           what it knew it was supposed to do.
                       MR. OSTERHOLTZ:  We've got to be careful
           about getting into the mode of calling it a fire
           brigade, because I got into that -- was making that
           mistake and I was confusing some folks because it's
           not -- when you say fire brigade people think of
           operators and security people.  It's a dedicated
           fire department.
                       CHAIRMAN SIEBER:  All right.  I think we
           have time to finish our last topic here.
                       VOICE:  And in fact if Mr. Andrews and
           Mr. Pellet would come up and -- 
                       MR. GWYNN:  And while they're doing that
           there was a question that was asked earlier
           concerning the Callaway capacitors.  Those
           capacitors are in fact connected at all times. 
           They're basically a UPS.  You'd expect them to be. 
           They can take them off for maintenance if need be,
           but they can take them off for testing and
           maintenance, but normally they are engaged and on at
           all times.
                       For this topic, the Region IV
           responsibilities under continuity of operations and
           continuity of government we have Mr. Tom Andrews,
           who's our emergency response coordinator here in
           Region IV.  Tom, would you hold up your hand. And
           Mr. John Pellet, who's the chief of our information
           resources management branch in the division of
           resource management and administration, and they're
           going to share some information with you about
           Region IV's unique role as the backup to
           headquarters for continuity of government,
           continuity of operations.
                       Tom.
                       MR. ANDREWS:  Good afternoon.  I want to
           make sure your understanding of our continuity of
           operations plan, the idea that we have implemented
           ties back to some time ago somebody realized that we
           might lost headquarters.  An event occurred up the
           road here in Oklahoma City, for example.  
                       Several years ago there was an incident
           in Oklahoma City that received a lot of notoriety
           and demonstrated that an act of terrorism could
           adversely affect a large structure, and from that
           time on there's been a lot of focus on continuity of
           operations and continuity of government.  When you
           hear the term COOP and COG you can now know that
           COOP stands for continuity of operations.  COG
           stands for continuity of government.  Under the NRC
           continuity of operations plan we view continuity of
           government as a type of continuity of operations
           event.
                       In our plan we talk about our critical
           functions.  Each federal agency had to go through
           and identify what they consider to be their critical
           functions and describe what mechanisms they were
           going to put into place to protect them.  In the NRC
           we have one thing, and if we only do one thing in
           life then we will survive as an agency.  If we
           respond to events we're going to protect the health
           and safety of the public.  Everything else we do
           that makes sure that we don't ever have to get into
           the situation of having to respond to events.  It
           helps to make sure that licensees are doing the
           right things up front, but things still happen.
                       Emergency response covers a lot of
           territory, and when you try to decide what covers
           the emergency response function -- I'll give you an
           example of what that includes.  That includes the
           receipt of the event notification, whether it be
           from the licensee or resident inspector, member of
           the public, or another federal agency.  Performing a
           screening type assessment of the information
           provided and then determining what forms of internal
           notifications need to be made, and then going from
           that to determine if there needs to be some elevated
           form of response.  Do we need to activate our
           instant response plan?
                       We might need to call in people, staff a
           center to perform assessments and monitoring of the
           conditions, licensees' actions, et cetera,
           communicating with state and other federal agencies
           regarding the event, assessing licensees' ongoing
           actions and any protective action recommendations
           that they may be giving to state and local agencies
           so that they can protect the public, and
           coordinating the technical response from the federal
           government.  
                       The primary resources that we use to do
           this is communication.  The NRC does not have a lot
           of physical resources that we take to the field for
           emergency response.  We don't have -- like other
           agencies we don't have trucks and helicopters and
           satellites and things to deploy.  The thing we bring
           to any emergency response is brainpower, and the way
           we engage that is you have to feed it, and that's
           through communications.
                       So we have a lot of very diverse means
           of communication paths.  We have our federal
           telecommunications service system.  We have
           commercial telephone systems.  We have satellite
           telephones at the reactor sites as well as in our
           response centers.  We've got cell phones.  We've got
           network for e-mail, et cetera.  So we have a very
           diverse set of communication path that we can use.
                       We have evolved our response process to
           the point where we use a lot of this equipment in
           focused centers.  Many of you have probably toured
           the headquarters operations center and realized that
           is a very robust response center.  It has a lot of
           capability.  But if something were to happen such
           that headquarters could not operate or could not be
           used or it was no longer there how would the NRC
           deal with some form of event like that?  So we want
           to protect our critical function, and that's why we
           have continuity of operations plan.
                       Region IV was selected as the backup for
           headquarters.  In the continuity of operations plan
           we're referred to as the default region. 
           Technically any of the regions can stand in the role
           of headquarters as far as event response and being
           able to staff a center and coordinate how we're
           responding to events and communicating with other
           agencies.  The difference for Region IV is at
           headquarters we have a headquarters operations
           officer, a person that's on shift 24 hours a day to
           receive that first phone call to initiate the
           response.  They would call the appropriate region,
           get decision makers on the phone, and kick off the
           response.
                       If something were to happen to
           headquarters we would be picking up that role.
                       Why was Region IV selected as a backup? 
           Well, it ties into some lessons that we learned from
           Y2K.  In preparing for Y2K which in itself could
           have been a continuity of operations type of event,
           we selected Region IV as the backup for headquarters
           for that purpose, and the reason being was we're a
           long ways from DC.  It takes a real big event if
           it's a weather type of event or some other type of
           disaster that affects DC to also us.  We're
           typically in a different weather pattern and we're
           on a different electrical grid.
                       I know you've been talking about grids,
           and in the case of the United States there's three
           main electrical interties.  There's the eastern
           interconnection, which you can see would cover
           Regions I, II, and III, as well as headquarters, so
           if you had a massive blackout that cascaded across
           the whole interconnection it would take out all of
           those offices, or it would impact all of those
           offices.
                       Texas is pretty much its own grid to
           itself.  Not only is it entirely within Texas, it
           doesn't go outside of Texas, but there's different
           types of connections between the ERCOT grid and the
           interties and what you find inside.  It has to go
           across a DC connection to get into the ERCOT grid or
           out of ERCOT grid.  
                       MR. GWYNN:  That situation with Texas is
           consistent with the state constitution that says
           that they can secede from the union at any time
           without prior notification, so the ability to
           disconnect from the electrical grid in the rest of
           the United States is an important part of that.
                       MR. ANDREWS:  And the advantage of
           having that DC type --
                       MEMBER POWERS:  How does that impact
           your ability to serve as a backup for headquarters
           if they decide to secede?
                       MR. ANDREWS:  It promotes international
           relations.  We'll have a field office in their
           country.
                       MEMBER POWERS:  Will you be citizens of
           their country?
                       VOICE:  If they secede does the
           president have to resign?
                       VOICE:  He's left.  He don't live here
           no more.
                       MR. PELLET:  It was actually a FERC
           issue and the two major Texas utilities prefer not
           to cross interstate boundaries in transmission of
           electricity.
                       MEMBER UHRIG:  They refuse to serve
           beyond their boundaries until something is settled.
                       MR. ANDREWS:  The good thing about the
           DC type interties is that if there is a disturbance
           on either the western grid or the eastern grid it
           doesn't propagate into the ERCOT grid.
                       Just like I pointed out earlier, if
           something happened on the eastern grid where it
           affected Regions I, II, and III as well as
           headquarters but not Region IV, likewise if
           something happened on the ERCOT grid it wouldn't
           propagate out.  The reason for that statement is to
           tell you that being a backup doesn't mean we're
           bullet proof.
                       Now, I've told you about the
           communications that we have and we use, and they've
           focused in our response centers.  We've got some
           other equipment that we use that is considered to
           support our critical function, but not necessarily
           critical that we operate.  If the NRC had to operate
           for a longer period of time, more than just a couple
           of days, we would need to have means to communicate
           internally as well as externally and have means of
           accessing the internet.  The internet has become a
           very important part of being able to conduct
           business.
                       Now, I'll mention that the local and
           wide area network is primarily our internal computer
           system.  The e-mail is between the offices, between
           various regions, the sites, and headquarters,
           whereas the external internet access is our ability
           to go out and look for information on the internet. 
           One of the things that we may lose for a period of
           time is we may lose our web page, but that's not
           necessarily considered to be vital for our
           operation.
                       CHAIRMAN SIEBER:  Is Adams vital to your
           operation?
                       MR. PELLET:  The answer to that is no.
                       CHAIRMAN SIEBER:  I'm not surprised.
                       MR. PELLET:  Adams was not a required
           support function under a COOP-COG activation.
                       CHAIRMAN SIEBER:  Okay.
                       MR. PELLET:  Neither is Star Fire, Pay
           Pers --
                       CHAIRMAN SIEBER:  I understand that.
                       MR. ANDREWS:  I'm going to let John talk
           about this diagram.
                       MR. PELLET:  This is a busy slide.  
                       For those of you who didn't hear, I'm
           John Pellet, chief of the Information Resource
           Management Branch in the region.  If it has an
           electron or a piece of paper attached to it it falls
           within our purview.  
                       And basically all this slide is
           attempting to tell you is these little yellow lines
           are what's being added to our computer
           infrastructure for COOP.  Right now all of the
           agencies' infrastructure outside of the office,
           outside of Region IV, outside of Region I, outside
           of Region II goes through White Flint.  If White
           Flint goes away we can't talk to Region I today in
           terms of computer support.
                       Under a COOP environment we need to have
           redundancy to where we can bypass the headquarters
           infrastructure.  This is going to involve a series
           of hardware-software changes to the agency's
           network, a lot of -- from my perspective a lot of
           money being spent.  From any other federal agency's
           perspective probably not a whole lot, but
           essentially we're going to add several racks of
           computer equipment into our space.  We're going to
           add considerably more network connections across
           between offices.  In essence, we're going to double
           our existing bandwidth to offices by having a
           redundant pipe that goes around headquarters.
                       Region I is actually the backup backup
           facility.  If we were to be lost and still have a
           COOP scenario Region I will have some capability to
           come back, but basically the wide area network
           connection outside of each office probably would be
           lost if we were to be lost with headquarters
           infrastructure wise.
                       Of course, this is focusing on
           computers.  There's a lot of telephone
           infrastructure changes required to support us being
           able to redirect and handle emergency phone traffic
           for the agency.  As we've demonstrated before,
           that's not something a region is normally prepared
           or configured or has the infrastructure to do, but
           that's something that's being added as part of COOP,
           and it's something we're testing and implementing as
           we go.
                       Basic time line for COOP -- of course
           the agency is fully COOP functional now.  The
           computer infrastructures and the telephone
           infrastructure stuff will be done across most likely
           the remainder of this year.  We're going to have
           some facility changes in the region to better
           support a COOP environment in a more smooth manner,
           and all that's under current development.
                       But the thing I would say take away from
           this is two things.  One, we're operational in a
           COOP context now.  We hope to make it much easier
           with infrastructure changes in the near future. 
           They're being worked between all the regions, OCIO,
           IRO, Region IV.  Tom and I are on a regular calls
           every week about COOP infrastructure requirements.  
                       Anything about infrastructure?
                       MEMBER LEITCH:  Are these yellow lines
           shown on your diagram -- I'm trying to visualize
           what they represent.  Is that hard wire or what is
           that?
                       MR. PELLET:  In today's infrastructure
           world what that really -- this is not going to
           involve a new wire coming into our building.  We
           actually have a piece of fiber cable that comes in
           from MCI that's capable of carrying more than enough
           to do all of this.  It's actually called a DS3 cable
           connection into our router but it's provisioned into
           these separate virtual circuits.
                       MEMBER LEITCH:  Okay.
                       MR. PELLET:  And so we haven't fully
           negotiated with MCI, the local carrier, which is
           Southwestern Bell, and the building exactly how
           we're going to bring this new data bandwidth into
           the office.  It could be a whole new pipe wire.  It
           could be just an additional speed down the wire we
           have.  It could actually be three new wires.  That's
           a contractual issue and a local telecom
           infrastructure compatibility issue that we don't
           have fully worked out and is somewhat dependent on
           whether we end up renewing our lease in this
           building or moving.  
                       We can't quite finish all of that
           negotiation until our lease negotiations are
           complete and we know we're staying here, because
           obviously there are capital investment requirements
           to increase the size with the building and the local
           carrier and the FTS 2001 carrier.
                       So the answer to your question is I
           think it's going to be in the one pipe we've got. 
           COOP is not intended to be redundant.  It was a
           design decision made long ago.  If you notice if we
           lose this box right here, which is an actual box
           sitting behind that wall, we can't activate the COOP
           computer infrastructure part of COOP.  COOP is not
           intended to be single failure proof throughout the
           industry.
                       It's not intended to be.  It is very
           robust.  We have two potential paths.  One's in 2
           White Flint and one is in 1 White Flint.  We can
           lose one building in White Flint and not have a
           computer infrastructure COOP problem.  It will
           automatically auctioneer back and forth. So with the
           redundancy we have to harm our COOP function we
           would have to lose both of these plus this.
                       MR. GWYNN:  John, did you mention the
           red boxes?
                       MR. PELLET:  The red boxes are
           essentially internet connections.  One of the things
           we're going to do -- obviously we think COOP
           decision agency and staff decided being able to
           access information on the internet was an essential
           part of our event response.  Therefore, since we
           currently have one pipe to the internet through NIH
           we're going to be adding a second pipe in standby
           mode from here, and the red boxes are firewalls, and
           we've got fire in this again.  
                       So that's the function of these external
           connections, and of course each region connects out
           to each of its sites through its own equipment. 
           That's also -- in fact we have 14 sites, each with a
           data pipe going out.  They're all coming into that
           same MCI Worldcomm FTS 2001 pipe.  It looks like
           individual pipes if you look at it from a schematic,
           but from the electrical standpoint it's one piece of
           fiber.
                       MR. GWYNN:  Tom, we are essentially out
           of time.  Could you show the IRC plan very briefly
           and then we'll conclude the presentation?
                       MR. ANDREWS:  As John mentioned we are
           spending a fair amount of money, at least for us. 
           We don't usually see that much money come through
           here. 
                       One of things we're doing is we're going
           to be remodeling our instant response center.  The
           idea being when we responded for Y2K we put about
           35-40 people here in the office to respond to Y2K. 
           Although our response to Y2K was quite successful it
           was not pretty.  We had to use offices outside of
           the center in trying to keep in touch with everybody
           and make sure everything stayed coordinated was not
           easy.
                       So what we've done is we've talked with
           admin and we're going to be ripping out the walls
           and making a lot of changes to more efficiently use
           the space that we have.  So what you see here is
           what we're looking at.  To give you an idea, our
           center has not been really upgraded since around the
           1990 time frame.  It's a very low tech center right
           now, and we're going to be adding some things to it
           to make it more usable and to help us more
           efficiently use the space.
                       MR. GWYNN:  And primarily the key COOP-
           COG changes being made is to include in the design
           two headquarters operations officer consuls so that
           the WHO function can be transferred quickly to
           Region IV.  We would pick that up essentially
           instantaneously.  We'll have a computer here which
           will be monitoring headquarters availability.  If
           the computer loses connection with headquarters for
           more than a preset period of time then we
           automatically go into COOP operations and our people
           respond to the incident response center and initiate
           COOP function until that -- the individuals from
           headquarters could be restationed here.
                       MR. ANDREWS:  The next slide just
           basically tells how we would kick of the continuity
           of operations process here in the region.
                       Do you have any questions about COOP or
           COG?
                       (No response.)
                       MR. ANDREWS:  Okay.  
                       CHAIRMAN SIEBER:  Thank you.  We
           appreciate the presentation, and it looks like we
           made it all the way through the schedule.  
                       I would like to express on behalf of the
           ACRS and our staff our appreciation for the work
           that you went through to put on these presentations. 
           I particularly liked the free flow of information
           and our ability to ask questions and get a better
           understanding of issues that we think are important
           to us performing our function.  
                       And so my congratulations to you, Pat,
           and to all of the staff here at Region IV for your
           hospitality and cooperation.  I'm curious -- if this
           ACRS meeting differs from what your expectations
           that it would have been prior to our arrival.  Did
           you expect this kind of a meeting or interchange, or
           did you expect something different?
                       MR. GWYNN:  Based on my previous
           experience observing ACRS meetings at headquarters
           and the last meeting that we held here in Region IV
           I think that it was pretty much what I expected.
                       CHAIRMAN SIEBER:  Okay.
                       MR. GWYNN:  I know that when the ACRS
           asks you a question you need to get an answer, and
           so this forum was perfect for that purpose.  I
           thought that it was extremely valuable to have this
           dialogue.
                       CHAIRMAN SIEBER:  Well, one of the
           important things for us is that one of our roles is
           to advise the commission or the executive director
           as to the policies and the technical issues that
           ought to be pursued and some prioritization and a
           sense of direction, and you really can't do all that
           stuff from Rockpit.
                       So these sessions with the regions and
           with licensees are extremely valuable to us, and
           that's why we want to come here from time to time,
           and we consider this a very important part of our
           function, and for that I offer you the thanks of the
           ACRS and the members here.
                       And since we do have some airplanes to
           catch I think -- John?
                       MR. LARKINS:  I just wanted to thank the
           administrative staff also for their outstanding
           support.
                       CHAIRMAN SIEBER:  I would remind the
           members if they want to ship materials back as
           opposed to using it as ballast in their suitcases
           there's a box on this table.  You can put your name
           on it and put it in the box and it will --
           guaranteed to go somewhere.  
                       And with that, again, my thanks to the
           staff in Region IV.  We enjoyed our visit.  It was
           valuable to us.  And with that I would adjourn this
           meeting.
                       (Whereupon, at 3:15 p.m., the meeting
           was adjourned.)
Page Last Reviewed/Updated Wednesday, February 12, 2014