ML112971527
| ML112971527 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 10/18/2011 |
| From: | NRC/SECY |
| To: | |
| References | |
| M111018 | |
| Download: ML112971527 (77) | |
Text
UNITED STATES OF AMERICA U.S. NUCLEAR REGULATORY COMMISSION BRIEFING ON BROWNS FERRY UNIT 1 OCTOBER 18, 2011 9:O0 A.M.
TRANSCRIPT OF PROCEEDINGS Public Meeting Before the U.S. Nuclear Regulatory Commission:
Gregory B. Jaczko, Chairman Kristine L. Svinicki, Commissioner George Apostolakis, Commissioner William D. Magwood, IV, Commissioner William C. Ostendorff, Commissioner
2 APPEARANCES Tennessee Valley Authority (TVA):
Preston D. Swafford Chief Nuclear Officer and Executive Vice President, Nuclear Power Group William R. (Bill) McCollum, Jr.
Chief Operating Officer Don E. Jernigan Senior Vice President, Nuclear Operations Robert J. Whalen Vice President, Nuclear Engineering Keith J. Polson Site Vice President, Browns Ferry Nuclear Plant, Units 1, 2, and 3 NRC Staff:
Bill Borchardt Executive Director for Operations Victor McCree Regional Administrator, Region II Rick Croteau Director, Division of Reactor Projects, Region II
3 1 PROCEEDINGS 2 CHAIRMAN JACZKO: Good morning, everyone. The Commission 3 meets today to discuss the safety challenges experienced by the Browns Ferry 4 Nuclear Power Plant and the steps being taken to strengthen safety at the plant.
5 In particular, in May 2004, Brown's Ferry Unit 1 was placed in Column IV of the 6 Reactor Oversight Process Action Matrix after it received a "Red" finding when a 7 reactor core cooling valve failed. Under the ROP, the NRC will place a plant in 8 Column IV only after identifying findings with high safety significance. That 9 designation triggers heightened NRC inspections to ensure that the needed 10 remedial measures are taken.
11 This is not the only significant issue the Browns Ferry plant has 12 experienced in recent years. In 2003, all units at Browns Ferry were placed in 13 Column III after receiving a "Yellow" finding for fire protection issues. Given this 14 recent history of issues, I'm sure that we can all agree that we want to see the 15 plant perform more safely. To achieve that, there needs to be a strong 16 commitment from the licensees entire organization, from its senior leadership to 17 its frontline engineers to do what needs to be done for safety.
18 Less than two weeks ago, I visited the Browns Ferry site with 19 Senator Alexander to assess the plant's progress in addressing its equipment 20 reliability issues and other challenges. As I was doing that visit, it was clear that 21 steps have been taken, and it was clear that there was still an amount of work 22 that needs to be done for the licensee to ultimately, I think, perform as we and as 23 they, I believe, want the plant to. And I had a chance when I was there to talk to 24 employees, and what I got a sense from many of them was a recognition that 25 there were things they wanted to do better and were interested in doing that; and,
4 1 in my mind, that's always a positive sign is that recognition that there are 2 challenges and the need to address them.
3 So, in the presentations from the staff and the licensees, we'll hear 4 in greater detail about exactly what steps they intend to take. But, it's always 5 important that we stay on top of this issue in order to ensure that this matter's not 6 indicative of broader issues at the plant. So, before we begin, would any of my 7 colleagues like to make any comments? Okay. I'll start with the staff 8 presentation. Bill, if you want to begin.
9 BILL BORCHARDT: Good morning. A plant that enters into 10 Column IV or the multiple, repetitive, degraded corner stone column of the 11 Reactor Oversight Program Action Matrix is of significant regulatory concern to 12 the NRC. The NRC management directive that provides guidance on the reactor 13 oversight program was revised in 2009 to ensure that, within six months of 14 entering Column IV, that the operating company briefs the Commission on their 15 plans to improve safe operation of the facility.
16 Browns Ferry Unit 1 entered Column IV of the Action Matrix in the 17 fourth quarter of 2010. The purpose of today's briefing is to brief the Commission 18 on the performance of Browns Ferry Nuclear Facility in accordance with NRC 19 management directive. Vic McCree will discuss the recent performance at 20 Browns Ferry, the staff's review and assessment of that performance, and then 21 Rick Croteau will discuss Region II's completed, on-going, and planned 22 inspection activities.
23 Slide three is the agenda for the staff's presentation. And, if you 24 could go to slide four, I'll turn the presentation over to Vic.
25 VICTOR MCCREE: Good morning, Mr. Chairman, Commissioners.
5 1 I plan to provide a brief overview of the performance of the Browns Ferry Nuclear 2 Plant and the results of our performance assessment, and Rick Croteau, as Bill 3 indicated, will then discuss the agency's actions.
4 As you know, Browns Ferry, which is operated by the Tennessee 5 Valley Authority, has three General Electric boiling water reactor units, and is 6 located near Decatur, Alabama, about 30 miles west of Huntsville, Alabama. As 7 Bill indicated, the performance of the plant is being discussed today because the 8 performance of Unit 1 was assessed as being in the multiple repetitive degraded 9 cornerstone, or Column IV, of the Reactor Oversight Process Action Matrix. Unit 10 1 was placed in this cornerstone column due to a "Red" finding in the mitigating 11 systems cornerstone. Next slide, slide five, please.
12 On October 23rd, 2010, operators of Browns Ferry Unit 1 attempted 13 to place Loop II of the residual heat removal low pressure coolant injection, or, 14 RHR LPCI system in service to support refueling activities. Although control 15 room indications show that the RHR LPCI outboard injection valve was open, no 16 flow was measured in Loop II. Shortly after recognizing this condition, operators 17 successfully placed the other loop, Loop I, of RHR LPCI in service to support 18 shut-down cooling.
19 Subsequent visual inspections of Loop II of RHR LPCI, the 20 outboard injection valve, showed that the valve had failed. The valve disc was 21 separated from the disc skirt stem assembly and lodged in the seat. The 22 inspection results also indicated that the disc was likely separated, and the valve 23 was inoperable for an extended period of time.
24 Plant staff repaired and modified the Loop II valve before Unit 1 25 was restarted. TVA also inspected and modified the Loop I valve in Unit 1 and all
6 1 four similar valves in Units 2 and 3. Based on the staff's assessment of the RHR 2 LPCI Loop II valve failure, and after holding a public meeting, regulatory 3 conference, with the Tennessee Valley Authority, I sent a letter to TVA in early 4 May of this year, identifying a violation of the Unit 1 technical specifications and a 5 "Red" finding due to the inoperable RHR subsystem.
6 Based on our assessment, TVA's performance was deficient in that 7 it failed to implement an in-service testing, or IST program, in accordance with 8 the American Society of Mechanical Engineers, which precluded the timely 9 identification of the failed valve and the inability of the Unit 1 RHR LPCI Loop II 10 subsystem to perform its safety function.
11 In addition to providing a way to cool the reactor during normal 12 shutdown cooling operations, the RHR LPCI system is counted on for core 13 cooling during certain accident scenarios. As a result, when the significance of 14 this performance deficiency was assessed, it was determined to have high safety 15 significance representing a "Red" finding because it could have led to core 16 damage had an accident involving a series of unlikely events occurred.
17 The main contributor to the risk determination for this finding was 18 the core damage frequency contribution due to fire, stemming from Browns 19 Ferry's use of the self-induced station blackout, or SISBO, approach to mitigating 20 fires. The "Red" finding resulted in Unit 1 being placed in Column IV of the NRC 21 Action Matrix. Units 2 and 3 remain in Column I and performance indicators for 22 all three units remain "Green".
23 If you would go to slide seven, please, skipping one slide. In early 24 June, TVA submitted an appeal of the "Red" finding. While acknowledging the 25 safety significance of the failed valve, TVA's letter raised several issues,
7 1 including that the Browns Ferry in-service testing program was not inadequate, 2 and that there was no performance deficiency.
3 In response, I charted an independent panel that included experts 4 from Regions III and IV, the Office of Nuclear Reactor Regulation, and the Office 5 of New Reactors, to carry out an independent review of the performance 6 deficiency, including the ASME code requirements governing in-service testing to 7 ensure valve to disc failures are detected. Using input from the independent 8 panel, I issued a final letter to TVA in mid-August that sustained the "Red" finding 9 and the violation.
10 In the letter, I informed TVA that NRC regulations require the 11 components that are important to safe operations be treated in a manner that 12 provides assurance of their performance, and that 10 CFR 50.55(a) requires 13 licensees to establish programs to assure that motor-operated valves, or MOV's, 14 can perform their safety functions.
15 In-service testing programs, MOV analyses and testing programs, 16 and corrective action programs are examples of programs that licensees use to 17 assure the operability and functionality of MOV's. We found that the inadequate 18 establishment of such programs at Browns Ferry represented a performance 19 deficiency, and that appropriate implementations of the programs would have 20 enabled TVA to promptly identify and correct the failure of the RHR LPCI Loop II 21 outboard injection valve in Unit 1.
22 If you go back to slide six, please. This slide is a chart that shows 23 the action matrix cornerstone placement of Browns Ferry Units 1 through 3 since 24 the second quarter of 2010. It shows that all three units were in Column III, as 25 the Chairman indicated, due to "Yellow" and White findings associated with
8 1 Appendix R fire protection issues. That condition, or, that placement actually 2 began in the fourth quarter of 2009. Units 2 and 3 transitioned to Column I 3 during the fourth quarter of 2010 following a successful 95002, supplemental 4 inspection for the "Yellow" and White findings. The "Red" finding for Browns 5 Ferry Unit 1, as the chart shows, began in the fourth quarter of 2010 due to the 6 identification of the failed RHR LPCI valve in late October of last year.
7 At this point, I'll turn the presentation over to Rick Croteau.
8 RICK CROTEAU: Thank you, Vic. Good morning, Mr. Chairman, 9 Commissioners. I'll provide an overview of the organizational changes in NRC 10 inspection plans to evaluate licensee's actions to address performance issues at 11 Browns Ferry.
12 To provide dedicated inspection oversight for Browns Ferry, we've 13 reorganized within the division of reactor projects in Region II. Gene Guthrie, 14 who is seated over behind Steve Burns there, was the supervisor for all three 15 Tennessee Valley Authority sites of Sequoyah, Watts Bar, and Browns Ferry.
16 Due to the issues at Browns Ferry, we split out Browns Ferry into a special 17 project, and Gene is dedicated to covering the inspection effort for solely Browns 18 Ferry. We are also utilizing experts from NRC headquarters as well as 19 inspectors from Region II and other regional offices to conduct the inspections at 20 Browns Ferry.
21 In addition, we've recently named Jimi Yerokun as a senior 22 executive team manager to oversee and facilitate coordination and execution of 23 the inspections at Browns Ferry. Browns Ferry has been challenged by a 24 number of equipment issues, as was mentioned earlier. Over the last two years, 25 there have been eight reactor scrams, four forced outages, and five significant or
9 1 urgent down powers, largely due to equipment issues. As a result, our 2 inspections focused on equipment reliability at Browns Ferry in all three units.
3 Slide 10, please.
4 Inspection procedure 95003 describes the supplemental inspection 5 activities for plants in Column IV of the NRC's Reactor Oversight Process Action 6 Matrix. The inspection procedure is publicly available to anyone who would like 7 to look at it. The objective of the inspection is to provide the NRC with 8 information to be used in deciding whether the continued operation of the facility 9 is acceptable, or whether additional regulatory actions are necessary to assure 10 public health and safety.
11 An additional objective is to evaluate the licensees third-party 12 safety culture assessment that is required as part of the actions for being in 13 Column IV of the Action Matrix. The staff has planned the supplemental 14 inspection in three parts. Part I focused on testing programs, including valve 15 testing, on all three units. The inspection was conducted in September of this 16 year by a four-person team led by Robert Orlinkowski of the NRC's Region III 17 office. Public exit was conducted on October 3rd in the vicinity of the plant.
18 The general conclusions from the inspection were that the 19 governing programmatic test procedures met regulatory requirements and were 20 generally acceptable. However, some issues were identified, and both the NRC 21 staff and the licensee are following up to ensure that the issues are addressed 22 properly.
23 Part II of the inspection will focus on maintenance due to historical 24 issues with equipment reliability. The inspection is being conducted by a five-25 member team, also headed by our Region III inspector John Jandovitz, through
10 1 December of this year. The inspection actually started a couple weeks ago and 2 will continue throughout the rest of this year. The team will look at all phases of 3 maintenance on selected safety-related equipment, again, on all three units. We 4 plan to conduct the public exit at the end of the inspection, and that will probably 5 be in the mid-January time frame of 2012.
6 Part III will complete the formal inspection procedure, the 95003 7 inspection, and it will be conducted once the licensee indicates that they are 8 ready for the inspection to ensure that TVA has completed the root cause, the 9 extent of cause, and the extent of condition investigations at Browns Ferry, and 10 also ensure that they've completed their independent safety culture assessment.
11 This inspection will evaluate maintenance, operations, engineering, 12 corrective action, and management oversight decision-making, so it doesn't just 13 focus on the issues that they've had, it goes across the board at the facility. The 14 engineering aspect of this inspection will also include the area of fire protection.
15 The inspection will be more comprehensive than the Part I and Part II inspections 16 on testing and maintenance. Following the inspection, we will make a 17 recommendation to the Regional Administrator, Director of NRR, and EDO, as to 18 whether any additional NRC actions are warranted. We expect this will be in the 19 first half of calendar year 2012.
20 I'd like to note that we did not wait for the licensee to tell us they 21 were ready for the Part I and Part II inspections. We perform these inspections 22 as soon as reasonably achievable to ensure there were not any near-term 23 immediate safety concerns at the facility.
24 Also, programmatically, after each inspection procedure 950003 25 inspection staff evaluates Lessons Learned and incorporates them into
11 1 improvements in the inspection program. There have been several updates of 2 this nature to inspection procedure 95003. As I mentioned earlier, it calls for an 3 independent safety culture assessment, and the procedure was revised in 4 January 2009 based on Lessons Learned from the inspection at Palo Verde.
5 Specifically, the revision allows the NRC to leverage the results of the licensee's 6 third-party safety culture assessment and root cause evaluation to more 7 efficiently and effectively complete the inspection. In this case, however, the 8 NRC first needs to establish confidence that the third party assessment tools are 9 valid and reliable, and we'll do that as part of our inspection at Browns Ferry.
10 In closing, we believe we have the appropriate staff, resources, and 11 inspection plans to effectively assess TVA's actions in response to the situation 12 at Browns Ferry. Now, I'd like to turn it back to Bill for the closing remarks.
13 BILL BORCHARDT: That completes the staff's presentation, and 14 we're ready to answer any questions.
15 CHAIRMAN JACZKO: Okay. We'll start with Commissioner 16 Svinicki.
17 COMMISSIONER SVINICKI: Thank you for your presentations, 18 and good morning. There are, in my understanding, there are some potential 19 generic aspects of the issues associated with this valve inoperability. Will staff 20 continue to pursue generic resolution of the ASME code testing issues separate 21 from the resolution of this finding? And, if so, what's the status of this effort?
22 BILL BORCHARDT: Yeah. This was an item that was identified 23 early on. NRR has the lead as part of the operating experience. This is one of 24 the normal inputs to the operating experience program, so NRR has this 25 underway, so I think that John --
12 1 JOHN LUBINSKI: John Lubinski from NRR. We were working with 2 the ASME co-committees, and they formed a working group to relook at the 3 requirements with respect to the inspection of these valves to determine whether 4 or not the requirements are clear and whether or not they need to be modified.
5 This was discussed at the August meeting. They have semi-annual meetings of 6 the ASME code, and the action at that meeting was for the working group to look 7 at this, to make that determination, and they will re-meet in December. NRC 8 does have members of its staff on that working group.
9 COMMISSIONER SVINICKI: Thank you. What is the staff's 10 assessment of how widespread the IST program deficiency that's been found at 11 Browns Ferry, how widespread is that at Browns Ferry? Do you have an 12 assessment of that yet, or will that be an outgrowth of your further inspections?
13 VICTOR MCCREE: I think the short answer, Commissioner, is that 14 we're still looking at it, we're still examining it. There's a recognition based on the 15 first Phase One inspection that we've done. We recognize that TVA understands 16 that it's not an isolated issue. It is a programmatic issue, and their follow-up and 17 causal analysis is treating it in that manner. But, we do have additional 18 inspections ongoing now, and we'll be able to get a better handle on that as, in 19 the Phase Two and certainly the formal 95003 inspection we do next year.
20 COMMISSIONER SVINICKI: Okay. Thank you. On another 21 potentially generic issue, TVA, as I understand it, submitted a Part 21 report on 22 the valve. Have we developed any information regarding the extent to which this 23 valve is used in the operating reactor fleet, or if other similar valves are subject to 24 the same defect?
25 RICK CROTEAU: Rani's got some information on that.
13 1 RANI FRANOVICH: Rani Franovich, NRR staff. Actually, I don't, 2 but we can get back to the Commission on that. We can find out the status of 3 Part 21 actions.
4 RICK CROTEAU: I don't know specifically about the Part 21 and 5 where NRR is at with that, but there are similar valves in some applications in 6 some other facilities, and I think there had been some previous generic 7 correspondence associated with that at other facilities, but it's not an extreme, 8 widespread item, and we'll follow up with the Part 21.
9 COMMISSIONER SVINICKI: Okay. Thank you.
10 CHAIRMAN JACZKO: And I think, let me add to it, I mean, at 11 Browns Ferry, corrective action was taken with the other valves to weld the plate, 12 the stem and plate together.
13 RICK CROTEAU: Yeah. I mean, the valve was repaired, and all 14 the other valves on the other units were repaired. So, I think it was a total of six 15 valves associated with this, and ensured that immediately that action was taken 16 to ensure that they didn't have similar problems and were corrected.
17 COMMISSIONER SVINICKI: Okay. Thank you. The latest 18 assessment letter stated that there are two substantive cross-cutting issues at 19 Browns Ferry, one pertaining to appropriate and timely corrective actions, and 20 the other to thorough evaluation of identified problems. Does the staff assess 21 that the inoperable RHR valve is a symptom of these substantive cross-cutting 22 issues?
23 RICK CROTEAU: I would say we're going to follow up on those 24 issues as part of the 95003, so it's hard to do the -- you know, exact cause and 25 effect. But, part of the, you know, after the Davis-Besse event, we changed the
14 1 reactor oversight process to incorporate some standard cross-cutting issues to 2 kind of look at the safety culture to see if there were issues associated with that; 3 and, certainly, in these cases, we think there were. TVA has folded that into their 4 safety culture assessment and their follow-up actions, and we will conduct an 5 assessment of that as part of the 95003 inspection.
6 COMMISSIONER SVINICKI: Okay. Thank you. Thank you. Mr.
7 Chairman?
8 CHAIRMAN JACZKO: Commissioner Apostolakis?
9 COMMISSIONER APOSTOLAKIS: Thank you, Mr. Chairman. The 10 "Red" finding, I think, is primarily due to the fact that they have a self-induced 11 station blackout in case of a fire.
12 So, I saw in the report that there was an estimate of the core 13 damage frequency, something like 7 times 10 to the minus 4, or thereabout. Im 14 wondering what that number includes. For example, does it include the 15 frequency of fires that would necessitate going to station blackout?
16 RICK CROTEAU: Yes, that's my understanding. Yes.
17 COMMISSIONER APOSTOLAKIS: So, the frequency of fire is 18 there. So, if there is in the 10 to the minus 4 or 7 time 10 to the minus 4. Now, 19 you also stated that in an earlier slide that they, I think it was actually Vic, shortly 20 after recognizing this condition operator successfully placed the other loop of 21 RHR in service. Now, when the Red finding was found, was that action 22 included in the calculation? In which case, you don't have a problem?
23 VICTOR MCCREE: No, sir. There were no actual consequences 24 associated with the valve failure. Approximately 90 seconds after opening the 25 outboard injection valve on Loop II, and, of course, with the RHR pump running,
15 1 the operators noticed no flow. And, after 90 seconds, they placed the other loop 2 in service. The evaluation for -- after identifying the performance deficiency, we 3 evaluated the potential significance of the valve failure, and, in doing so, when 4 you postulate that the initiating event is a fire, and it's in an area that would 5 require use of the SISBO strategy to mitigate the fire, then you would assume 6 that that other train, in this case, that would have been Loop I, that would have 7 been de-energized, and the loss of that system, for some scenarios, you know --
8 COMMISSIONER APOSTOLAKIS: So, that number, then Vic, is 9 kind of artificial. There, 7 times 10 to the minus 4 is not really a, it does not 10 represent the frequency of what might actually happen.
11 RICK CROTEAU: But, then, think there's a fire in the area, you 12 know, that other loop would not be available. It's fires in specific fire zones and 13 fire areas that would have taken out the other loop and the other equipment 14 based on their strategy to do the self-induced station blackout. So, they would 15 be relying solely on that train of low pressure coolant.
16 COMMISSIONER APOSTOLAKIS: And the frequency of fires 17 occurring in those selected areas --
18 RICK CROTEAU: Selected --
19 COMMISSIONER APOSTOLAKIS: -- is part of the calculation?
20 RICK CROTEAU: Yes, sir.
21 VICTOR MCCREE: That's correct.
22 COMMISSIONER APOSTOLAKIS: So, then, it is a realistic 23 assessment?
24 RICK CROTEAU: Yes. Correct.
25 COMMISSIONER APOSTOLAKIS: Okay. Good. One thing that is
16 1 not very clear to me is, what is it exactly that TVA did not do? Why did they end 2 up in this situation? Was it that they misinterpreted the guidance in the ASME 3 code, or they were negligent? It's not very clear to me what the situation is.
4 RICK CROTEAU: I think that's going to be part of their root cause 5 analysis that we will look at and the broader issues, with the specifics on the 6 valve, it was not in their program to -- and this is part of the generic issue, to look 7 at the stem to ensure on a two-year basis that the valve was actually moving.
8 They would go on other indications. Okay. So, that's kind of, that may be a 9 generic aspect, but the other part of it, it was not in their motor operated valve 10 testing program, which it should have been. We had had previous interaction in 11 years past on that; it was not in the program, should have been in the program, 12 and if it had been in that program, it's likely that it would have been discovered 13 and picked up earlier.
14 So, it was inadequacies with the in-service testing program, and 15 actually, as part of the Part I inspection, we did pick up that several other valves 16 were not in the in-service testing program. To TVA's credit, they had picked up 17 on that also and already had that in their corrective action program as part of the 18 previous deficiencies. So, I would say overall it was inadequacy in the in-service 19 testing program that led to that specific issue. Now, of course, TVA, and we are 20 looking at the broader issues across the plant with the culture and other 21 programs of maintenance and equipment reliability.
22 COMMISSIONER APOSTOLAKIS: So, this is what led to the 23 decision to have them reevaluate or evaluate their safety culture, that there were 24 all these root causes or cost-cutting issues? Is that correct?
25 VICTOR MCCREE: The need for TVA to perform a safety culture
17 1 assessment is driven by the fact that they are in Column IV of the Action Matrix, 2 and that's one of the requirements for a plant that's in Column IV is to perform a 3 safety culture --
4 COMMISSIONER APOSTOLAKIS: Thats how it got there.
5 VICTOR MCCREE: That's correct.
6 COMMISSIONER APOSTOLAKIS: Okay. Okay. Good. Now, 7 there was a period, again, in the report that, it's not clear for how long that 8 condition persisted, and I think there is a statement that the last time that the 9 valve was operable, it was something like March of '09?
10 VICTOR MCCREE: Correct.
11 COMMISSIONER APOSTOLAKIS: And then it was discovered 12 inoperable in June of '10 or something like that. So, we're talking about -- or, 13 October '10.
14 VICTOR MCCREE: In October of 2010.
15 COMMISSIONER APOSTOLAKIS: So, it's roughly a year and a 16 half.
17 VICTOR MCCREE: Correct.
18 COMMISSIONER APOSTOLAKIS: But, we don't really know when 19 the failure occurred. Is that correct? Somewhere in there.
20 VICTOR MCCREE: That's correct. And, of course, in evaluating 21 the significance, we only used one year. The process allows us to use the one 22 year period of exposure time.
23 COMMISSIONER APOSTOLAKIS: Right.
24 VICTOR MCCREE: But, correct. But, the last time the valve was 25 known to have operated successfully in pass/flow was in March 2009.
18 1 Subsequent surveillance testing was not done in a manner that would have 2 demonstrated that flow actually passed through the valve.
3 COMMISSIONER APOSTOLAKIS: Thank you. Thank you, Mr.
4 Chairman.
5 CHAIRMAN JACZKO: Commissioner Magwood.
6 COMMISSIONER MAGWOOD: Good morning. Thank you for 7 your presentation, and for what, I've been following this for some time, and Vic 8 and I have talked about this. I appreciate the effort the staff's put into responding 9 to this, and I appreciate the work you're doing on this.
10 A couple of questions. One is, I just wanted to react to something 11 that Rick said a few minutes ago, that you found, looking at this, that there were 12 other motor operated valves that were not captured by the, IST program? Why 13 was that? Was there a clear reason as to why some of these were not captured 14 by the program?
15 RICK CROTEAU: I think again weve got to wait. The licensee 16 hasn't finished their root cause, so we've got to let them take a look at it and do 17 their root cause, and then we'll assess the root cause evaluation.
18 COMMISSIONER MAGWOOD: Were these -- I appreciate that, 19 but were these, as a general manner, were these valves where there was a 20 reasonable question as to why they would be, whether or not they would be in an 21 IST, or -
22 RICK CROTEAU: I don't think we've drawn a conclusion on that 23 yet. The team still hasn't issued a report, and they're still kind of assessing that 24 situation.
25 COMMISSIONER MAGWOOD: Okay. And looking in, and going
19 1 through background on this, I know that part of the back and forth with TVA 2 included an assertion by TVA that, in the event of an actual accident, that the 3 valve plate would have released eventually, and the staff rejected that 4 conclusion. But, could you elaborate on that? What was the theory behind that, 5 and what was the staff, how did the staff evaluate that that was not --
6 RICK CROTEAU: Well, they had done some testing to attempt to 7 demonstrate that it would have lifted. We took a look at the testing, and we 8 weren't convinced. It didn't seem to simulate the actual conditions. And then, in 9 fact, when they ran that and tried to initiate that shut-down cooling, it ran for a 10 period of time and did not lift. And then, also, when they disassembled the valve, 11 there was quite an effort necessary to lift that seat from and remove it from the 12 valve. So, there was some difficulty in removing it there.
13 Based on all the information they provided, we didn't think that it 14 was credible, that it would have passed flow under an actual accident condition.
15 COMMISSIONER MAGWOOD: Okay. Thank you. You've talked 16 about how Browns Ferry has responded to this, but, obviously, TVA operates 17 more reactors than Browns Ferry. Has there been an effort to assess these 18 situations over the entire TVA fleet?
19 VICTOR MCCREE: Commissioner, I would, I'm sure that TVA will 20 be prepared to respond to that question in the sense that they've indicated to us 21 that they're taking this opportunity to not just deal with the specific valve failure or 22 the specific program issues at Browns Ferry, but they're looking at the 23 implications across the TVA fleet and what it may mean, in terms of what they 24 need, changes that they would need to make corporately to address performance 25 issues, and I'd be interested in their response to your question as well.
20 1 COMMISSIONER MAGWOOD: Okay. I'll make sure I ask them 2 that. Let me stay with you Vic because I'm going to ask you to draw some broad 3 conclusions you're not going to be prepared to draw at this point, but I'm going to 4 ask it anyway. You know, whenever you see multiple equipment failures, and 5 you gave a list of the sorts of events over the last two years, it's been eight 6 scrams, four forced outages, five significant urgent down powers, how much of 7 that do you believe at this stage from what you know is, how much of that -- and 8 this maybe gets a little bit to Commissioner Apostolakis' question, I think, but how 9 much of this is more of a cultural problem and programmatic problem, and how 10 much of this is age of equipment?
11 VICTOR MCCREE: As Rick has indicated several times, TVA's 12 root cause evaluations is ongoing, and we will independently evaluate that. But, 13 the indications that we've obtained thus far and has contributed to the "Red" 14 finding is that there are programmatic program issues associated specifically with 15 the motor operated valve functionality, if you would, and more broadly, as Rick 16 indicated, there have been a number of equipment reliability challenges, with 17 frontline safety systems that have been captured by TVA and its equipment 18 reliability programs. And they've not demonstrated as aggressive an effort to 19 address those issues as they have of late. I believe that's contributed to their 20 being here. And one could argue that there are some cultural aspects of that, 21 and I believe that the safety culture assessment will enable them to see those 22 things a bit more clearly.
23 So, being in Column IV and being subject to a diagnostic inspection 24 of the scope and breadth and depth of a 95003 has, based on our past 25 experience, reveals a number of opportunities to improve performance, and TVA,
21 1 I think, will have the opportunity to take advantage of that to raise the level of 2 performance at Browns Ferry and perhaps across the fleet.
3 RICK CROTEAU: If I could add on the, one of the things that Part I 4 inspection and Gene has been pointing out, and, I think, even the TVA folks will 5 tell you that it's been kind of a broke/fix mentality with equipment in the past 6 where a piece of equipment breaks, and they just fix it, and they don't go look at 7 why did that fail, and what do we need to do to prevent reoccurrence, so they're 8 back, you know, two years later or some period later, working on the same 9 equipment again, because they dont address the basic issue with the 10 equipment.
11 COMMISSIONER MAGWOOD: I appreciate that. One last 12 question for you. And this, again, asking you to draw broad conclusions you're 13 not going to be prepared to draw, but I'm going to ask it anyway. Browns Ferry is 14 actually, as we all know, a unique plant, and that's it's the first of TVA's rebuilt 15 plants. And I actually had the opportunity to tour during the rebuilding activity 16 years ago. And I remember thinking at the time that, you know, it's interesting, 17 we'll have to see in the future how well this works out as we have this plant that's 18 been idle for so long going through this rebuilding process and will we put back in 19 service; so now it's back in service and now we're seeing issues, and then just --
20 and we have more TVA plants that are on the docket to be rebuilt and put back in 21 service. Should we draw any conclusions about the rebuilding of plants in this 22 context, or is this what we see here, is this isolated from that?
23 VICTOR MCCREE: I don't know that we're in a position to draw 24 any conclusions. I think your question is a very good one, and I'm certainly 25 taking it to heart, and I hope the folks at TVA are taking it to heart as well. In
22 1 fact, the failure of this valve, the failure mode, if you would, was introduced when 2 the valve was refurbished during the Unit 1 recovery. And so there are lessons 3 to be learned, I believe, in terms of what caused that, would allow that to happen.
4 And so there's opportunity there, again, in the recovery process or completion, if 5 you would, process for Watts Bar Unit 2, as well Bellafonte Unit 1 to learn 6 lessons here.
7 COMMISSIONER MAGWOOD: That was -- actually I should have 8 asked you this first, so it did sound that you did say this valve was the original 9 equipment valve that was rebuilt or refurbished?
10 VICTOR MCCREE: Yes, there was an extensive amount of 11 refurbishment, replacement as Unit 1 was recovered, and this was one of the 12 components that was worked on.
13 COMMISSIONER MAGWOOD: Excellent. Thank you very much.
14 CHAIRMAN JACKO: Commissioner Ostendorff?
15 COMMISSIONER OSTENDORFF: Thank you, Mr. Chairman.
16 Thank you for your presentations this morning. Bill, I want to start out with you, 17 but you can defer to either Vic, or Rick, however you want to handle this, but 18 prior to the "Red" finding, and I'm looking now at the equipment reliability issues 19 that Rick had referred to on slide nine. Prior to this valve issue, had there been 20 early warning signs of declining performance by the licensee in this area?
21 BILL BORCHARDT: Well, there were discrete inspection findings 22 and Vic had the chart that showed the various columns that the individual units 23 were in, but, you know, from a nationwide perspective, I wouldn't say that the 24 Browns Ferry performance drew a lot of attention to itself. You know, we've 25 mentioned the number of scrams, you have to remember there's 3 units there' so
23 1 the numbers kind of add up a little bit if you compare it to single unit sites. So 2 from my perspective, and from my understanding of, you know, nationwide 3 operating experience, we're not seeing extraordinarily different performance from 4 the Browns Ferry units, compared to the rest of the fleet.
5 VICTOR MCCREE: The only other thing I'd add to that, 6 Commissioner and Rick alluded to it. If we were to go back as far as 2006, or 7 shortly after, when Unit 1 was restarted, there were some performance issues, 8 again, that we saw related to equipment reliability manifesting itself on Units 2 9 and 3. We did identify substantive cross-cutting issues at the time, which under 10 the reactor oversight process are early indicators, if you would, of performance 11 challenges, performance opportunities. And those types of observations 12 continued since that timeframe. As I indicated, all three units were placed in 13 Column III, in the fourth quarter of 2009, and there are and were a number of 14 front-line safety systems that were in A1 -- the maintenance rule A1. Again, 15 additional indicators of equipment challenges and a number of reactor trips and 16 down powers associated with equipment issues. So there was clear opportunity, 17 in our view, for the licensee to recognize that there were issues there that they 18 needed to get ahead of.
19 COMMISSIONER OSTENDORFF: I'm going to follow up Vic with 20 you and Rick on this question, with respect to equipment reliability, the 21 maintenance rule implementation, and so forth; outside of the in-service testing 22 program were there other aspects of the programs that deal with maintenance 23 that concern you with respect to licensing?
24 RICK CROTEAU: I think it's too soon to tell on that.
25 COMMISSIONER OSTENDORFF: We're going to ask the licensee
24 1 that; now this happened about a year ago, so you must have some initial 2 assessment; we're having the meeting today. And I'm going to pressure you on 3 this a little bit because I think it's part of NRC's job to evaluate how the licensees 4 are doing. And sometimes you need to wait until you have a report complete, but 5 you must have some initial gut feel for that.
6 RICK CROTEAU: We have completed the first week, as I 7 mentioned, of the Part 2 maintenance inspection. There were no significant 8 issues identified during that first week. But again I'll point out that just the 9 approach of the broke/fixed kind of thing, and not addressing root causes on the 10 equipment, that's kind of the early conclusion we've had in an overall 11 assessment, that there needs to be more of a getting to what caused the failure 12 rather than just fixing the individual failures at the facility.
13 COMMISSIONER OSTENDORFF: Okay, with respect to the other 14 licensees you deal with in Region 2, is this -- the comment you're just making 15 there about the broke/fixed, is that -- is this an anomaly for TVA, or do you see 16 these kinds of issues for other licensees?
17 RICK CROTEAU: I would say that most folks attempt to get to the 18 root cause of things to ensure that the conditions don't reoccur.
19 COMMISSIONER OSTENDORFF: Okay.
20 VICTOR MCCREE: And I would certainly agree with that. There 21 are opportunities, I think, that licensees have that there are individual cases 22 where they don't implement their corrective action programs in the manner that 23 they would expect, or that the program would require. What we have seen at 24 Browns Ferry, and it's the reason we're here today, is that there are challenges 25 that we've seen in the corrective action program, certainly in their in-service
25 1 testing and their maintenance program, all of which are important and part of 2 maintaining an appropriate and healthy safety culture, and in ensuring equipment 3 reliability. And a significant part of that is investing in the plant, investing in these 4 programs and that's been a challenge at Browns Ferry.
5 COMMISSIONER OSTENDORFF: Okay. That's very helpful. Let 6 me ask one last question, and Vic I'll ask both of you and Rick or I'll ask Vic, if 7 you want Rick to also respond, that's fine. Big picture, given everything that's 8 occurred to date, how do you assess the licensee's commitment to improve?
9 VICTOR MCCREE: Mr. Commissioner, I've had several meetings 10 with TVA leadership, both public meetings as well as drop-ins, and my sense is 11 that they accept our assessment of Browns Ferry's performance, and that there's 12 a commitment, both tangible and otherwise, to fixing problems at Browns Ferry.
13 But the proof is what we'll discern independently by verifying activity and action, 14 and progress at Browns Ferry. And this, the inspection that we are implementing 15 is the most probing, the most thorough type of effort we have, and it'll provide the 16 evidence that we'll need to answer that question with finality sometime in the 17 future. But my sense is that the leadership at TVA is aware of our assessment, 18 and is committed to moving forward.
19 COMMISSIONER OSTENDORFF: Thank you. Thank you, Mr.
20 Chairman.
21 CHAIRMAN JACKO: Well, I want to follow up a little bit on some of 22 Commissioner Ostendorff's questions about earlier warning signs, and I think 23 Commissioner Svinicki touched on this as well. One of the open cross-cutting 24 issues, and this is one I think that goes back, I think, four assessment periods, so 25 that would be two -- about two years, six month assessment period, I think that's
26 1 right, is in the area of our evaluation of identified problems, I think it's in the 2 problem identification resolution area. And this is from our mid-cycle 3 assessment, we were keeping this open, and of course at this point we had 4 identified the valve failure, but we were keeping this open until -- and these were 5 the conditions, a comprehensive range of actions are identified in your corrective 6 action program, your being TVA's, that effectively demonstrate you will address 7 the cross-cutting theme. So significant increase in the number of findings with 8 the cross-cutting aspect of thorough evaluation of identified problems, and 9 increased level of confidence in your ability to deal effectively with operational 10 equipment issues as related to this cross-cutting theme of thorough evaluation of 11 identified problems.
12 So -- and certainly the conditions to close this for things obviously 13 that appear to be related to what happened with the valve failure. And you know, 14 is this telling us anything that -- are we taking enough stock of the substantive 15 cross-cutting issues? Are we doing enough with them when we identify them?
16 And this was one that was open for four cycles. It almost seems like, to some 17 extent, we have them and we know that there's a problem and then we wait until 18 the equipment fails so we can get a finding so we can take some regulatory 19 action. What is this kind of saying to you, Rick or Vic, or whomever?
20 RICK CROTEAU: Well I'd just mention that we do look at that as 21 part of the end cycle, mid-cycle, and when it meets a certain threshold, we look 22 does it constitute a substantial cost-cutting issue. And then we do follow that up 23 with inspections once we think they're ready. So it is part of, you know, built into 24 the program, but we don't slide folks over in a column or anything like that 25 because of these types of issues unless, as you indicated, that they would have
27 1 a finding that would drive us in that direction. But we do do specialized 2 inspection to follow up and close out substantial cross-cutting issues.
3 VICTOR MCCREE: The ROP does allow, permit, in fact, it requires 4 us to use a graded approach when a substantive cross-cutting issue is identified 5 in any of the areas, whether it's human performance, problem identification 6 resolution, or safety conscious work environment. And you'll have to correct me, 7 John, if I get the timeframe wrong, but after the initial identification of a 8 substantive cross-cutting issue, a licensee is expected to respond, at least in 9 writing, with their plans to deal with the issue. If that substantive cross-cutting 10 issue persists after a cycle, after one year, if you would, we would hold a public 11 meeting to engage the licensee on whether they acknowledge it, and what 12 actions they're taking to deal with it. If it persists after two cycles, then we have 13 the option to consider requiring the licensee to conduct a safety culture 14 assessment to address that.
15 CHAIRMAN JACKO: In this particular case, what was your 16 determination on that?
17 VICTOR MCCREE: This would have been the cycle that we would 18 have had, however they were placed in Column IV. And I can't recall if it was 19 Papa 1 Charlie or Papa 1 Delta, the identification or the resolution, they had 20 actually taken it off and then reinserted it, but replaced the substantive cross-21 cutting issue. So there's a graded approach, and as Rick alluded to, we also 22 have the opportunity, and I'll usually take advantage of it, to rather than 23 conducting a biannual problem identification resolution inspection under 71152, 24 the procedure, we do that annually; we would move that inspection forward to get 25 additional evidence of the licensee's action and progress in these areas.
28 1 CHAIRMAN JACKO: So as you did all these things, did you -- what 2 was your gut when looking at all of this? Was the plant where you wanted it to 3 be, and so what could you do about it?
4 VICTOR MCCREE: They were not where we wanted it to be. We 5 recognize that, again, the programmatic, the performance issues, the findings 6 that we were identifying with the cross-cutting aspects and problem identification 7 resolution were indicative of continuing equipment performance issues; that's 8 where it was manifesting itself. And the findings that were identified in 2009, the 9 "Yellow" and the White was an opportunity, if you would, for TVA to address 10 even the broader issues associated with equipment reliability. But certainly now 11 that they're in Column IV, there's a requirement that they do so.
12 CHAIRMAN JACKO: And if you go back to Unit 1, and again, in 13 hindsight it's always 20/20 and everything looks crystal clear in hindsight, but if 14 you go back to when we closed out -- we had closed out the 95002, and as soon 15 as the next quarter rolled around they would have cleared all of the "Yellow" 16 findings. So, you know, if you look at the chart, which is a good chart, it gives the 17 impression that there was a continuous, but in reality from our perspective they 18 were "Green" in between, you know, there was almost an infinitesimally narrow 19 "Green" band in between the Yellow and the Red.
20 VICTOR MCCREE: Actually, Mr. Chairman, the 95002 exited on 21 October 22. The event occurred on October 23.
22 CHAIRMAN JACKO: Right, so there was this, as of, you know, 23 October 22 at say 8:00, mentally we thought they were back in Column I; 12 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> later, whatever it is, mentally then we're putting them back in Column IV.
25 So, you know, again if I look at this, and I want to look at this skeptically, there is
29 1 some extent where I would say well somehow, you know, we had to have missed 2 something. Because here clearly was a plant that had cross-cutting issues, that 3 said that we've got some challenges in this equipment reliability. We had it 4 manifest itself in a fairly significant "Yellow" and White finding. We did all our 5 inspections and we said everything's fine, and then a day later, everything's not 6 fine again. I mean, what's missing, and what's the problem?
7 VICTOR MCCREE: Mr. Chairman, I wouldn't argue that, I wouldn't 8 submit that anything's missing.
9 CHAIRMAN JACKO: Yeah.
10 VICTOR MCCREE: We know and acknowledge that licensees 11 have the primary responsibility for safety. There were sufficient indicators, I 12 believe, to TVA that an opportunity to deal with the issues at Browns Ferry 13 without having to be placed in Column IV. And what, I believe, we recognize is 14 that the licensees who have a strong safety culture and a commitment to strong 15 and excellent performance take earlier opportunities, they use a substantive 16 cross-cutting issue as a burning platform to make change, and to fix challenges.
17 CHAIRMAN JACKO: Let me ask you -- just let me ask you this for 18 a second though. And I'm not necessarily asking right now -- we'll have a chance 19 to talk to the Licensee about kind of their performance, but I'm asking a little bit 20 about our program. To what extent was there overlap between the root cause or 21 at least what appeared to be some of the causes of the valve failure and the fire 22 protection findings. I mean, was there overlap in the causes?
23 RICK CROTEAU: Could ask Gene to speak to that, I mean, Gene, 24 you are heavily involvement with both of those --
25 CHAIRMAN JACKO: Because my point here is that I'm not so
30 1 much worried about the licensees, I mean ultimately, yes, they have that 2 responsibility to ensure the safe operations. What I'm worried about is our 3 assessment. We assessed on October 22, that they had done enough corrective 4 action to address those things that led to the "Yellow" finding. That's why we 5 were ready to clear it. It wasn't the situation in which we were still believing that 6 there were problems, and that we believed that they had addressed the 7 problems, otherwise we would not have cleared the "Yellow" finding. So if there 8 are common issues between those two findings, the fire protection findings and 9 then the subsequent valve failure, somehow we said it was okay when it wasn't 10 and we missed something. And that's what I'm trying to understand, what, were 11 there common issues or not? And, its not to criticize, but this is our chance to 12 learn and figure out next time how we can do better.
13 GENE GUTHRIE: Right, I think, Gene Guthrie, I think when you 14 compare the equipment failure, you know, with the valve failure, and then if you 15 compare the fire protection issues, the fire protection issues were more focused 16 on program, program implementation and meeting the requirements, where, 17 when you look at the valve failure, it's really specific to a component failure, or a 18 piece of equipment failure.
19 CHAIRMAN JACKO: But did it have an element, I mean, their in-20 service inspection program was not functioning properly, they had not properly 21 placed the valve, the motor operated valve in the inspection program. Those 22 were programmatic challenges, not equipment problems.
23 GENE GUTHRIE: Yes, and I agree with that, but when you look at 24 what we inspected as a result of the fire protection "Yellow" findings, "Yellow" 25 and White, we were focused -- the 95002 inspection procedure is more narrow.
31 1 It focuses specifically on what that violation was, and looks at the root cause and 2 corrective actions that the licensee is going to take as a result of that. And so it 3 is -- it does tend to focus the inspection team on specifically those issues. So 4 when that 95002 inspection was performed, that's what they looked at, was the 5 fire protection program, specifically as it related to meeting the requirements of 6 the Appendix R associated with that and then --
7 CHAIRMAN JACKO: Thank you. That's helpful. And of course 8 that's then one of the issues with 95003, we have a much broader expanse. But 9 maybe that's something we need to take a look at, is maybe we should push 10 some of that broader look down toward to a 95002 level, and that may perhaps 11 have identified some of these issues a little bit earlier and given us an opportunity 12 to give the licensee an opportunity to make some improvements. Well, good, 13 well thank you.
14 BILL BORCHARDT: And Mr. Chairman, just that you raised the 15 challenge that we have on cross-cutting issues, and implementation of the 16 reactor oversight program. And not to go into a long history lesson, but before 17 the ROP, we would have, you know, a series of inspection findings; we would 18 generate this general concern. We didn't call it substantive cross-cutting issue 19 back then, but there was this general concern. And the problem we had from a 20 regulatory perspective is that the agency had a very hard time closing the issue.
21 Because, as regulators were very conservative and very cautious, and it's hard to 22 get over the threshold to say everything's okay. So the reactor oversight 23 program got to be much more discrete and specific on individual findings. We 24 retained three substantive cross cutting issues which allow us to raise a level of 25 attention to a general area. I think it's doing that, but you know
32 1 it's not perfect and that's why we're continuing to revise the reactor oversight 2 program.
3 CHAIRMAN JACZKO: Okay. Great. Commissioner Apostolakis.
4 COMMISSIONER APOSTOLAKIS: Vic, you mentioned that in one 5 quarter of '09, all three units were "Yellow". Right?
6 VICTOR MCCREE: That's correct, actually fourth quarter of 7 calendar 2009.
8 COMMISSIONER APOSTOLAKIS: I'm wondering, clearly the ROP 9 says you have to do certain things because a particular unit is "Yellow", but is 10 there a provision to do something extra, because all three are "Yellow", in other 11 words, is the ROP focus on the unit, not a multi unit site? A very fashionable 12 thing these days, multi units.
13 VICTOR MCCREE: That's a very good question. Unlike the failure 14 of the RHR LPCI outboard injection valve on Unit 1 and that finding being 15 associated with that failure. The fire protection program issues at Brown's Ferry 16 affected all three sites -- all three units; so the findings were applied to all three 17 units. Our action was the same; we conducted a single 95002 supplemental 18 inspection of that finding, which applied to all three units.
19 COMMISSIONER APOSTOLAKIS: This is because, in this 20 particular case, it happened to be the fire protection program.
21 VICTOR MCCREE: That's correct.
22 COMMISSIONER APOSTOLAKIS: Let's say it wasn't and I had 23 three units for different reasons they were all "Yellow". Would that trigger 24 something and say wait a minute; something is wrong with the site?
25 VICTOR MCCREE: No sir and in practice when we conduct
33 1 supplemental inspection and response to a greater than "Green" finding. The 2 inspection effort is applied to the site, there may be some unit specific issues that 3 the licensee is responding to but the inspection effort is a site wide effort, if you 4 would, just as even though only Unit 1 is in Column IV, our 95003 all phases are 5 affecting all three units at Browns Ferry.
6 COMMISSIONER APOSTOLAKIS: Thank you.
7 CHAIRMAN JACZKO: Any other questions. Thank you, appreciate 8 it.
9 [break]
10 CHAIRMAN JACKKO: We'll now have a presentation from TVA 11 and I'll just note that at the table we have Bill McCollum, who is Chief 12 Operating Officer, Don Jernigan who's-- did I say that right? Jernigan, 13 who is the Senior Vice President of Nuclear Operations; Robert Whalen, 14 who's Vice President for Nuclear Engineering; Keith Polson who is Site 15 Vice President at Browns Ferry and then my understanding is that the 16 presentation will come from Preston Swafford who is the Chief Nuclear 17 Officer.
18 PRESTON SWAFFORD: Yes sir, that's correct. Bill?
19 BILL MCCOLLUM: Mr. Chairman, Commissioners, Bill McCollum, 20 chief operating officer Tennessee Valley Authority, appreciate the opportunity to 21 be here today to talk about our work to improve performance at the Browns Ferry 22 Nuclear Plant. What we'd like to do is begin by talking a little bit about the some 23 of the background and our efforts to improve performance at Browns Ferry and 24 then at the end I'll make some comments about our efforts across the TVA fleet 25 and I'll ask Preston Swafford to open with our remarks.
34 1 PRESTON SWAFFORD: Thank you Bill. Mr. Chairman, 2 Commissioners. When Unit 1 shut down for a refueling outage last October the 3 operators discovered that they did not give indication of shutdown flow through 4 the Loop II division of RHR heat removal system and immediately, within about a 5 90 second period, aligned to the other loop and began injecting and shutdown 6 cooling for the refueling outage. No time during that period, was the core in 7 jeopardy and in that we did have available systems back up.
8 As a result of this problem, troubleshooting found that the valve in 9 Loop II had failed and that the valve stem specifically had separated from the 10 disc and the disc was found fully in its seat inside the valve. This particular valve 11 serves as one of the injection valves for our emergency core cooling system, 12 specifically through the LPCI injection system; so it obviously has significant 13 safety importance to TVA.
14 Since the last time this valve was successfully tested was in March 15 of 2009; we did a full flow test at that time and part of, I'm going to say, our weak 16 diagnostic issues and some other opportunities is a difference that we've -- I think 17 you've spent time this morning with the NRC is talking about the ISP Program 18 and our belief of how that system work does not necessarily guarantee that the 19 operability of a valve is sustained should you have this separation because the 20 configurations valve specifically has flow up underneath the disc and could, in 21 some occasions, actually open the valve and whatnot.
22 So I think there is a new issue that has to be resolved and has to 23 be looked at how do you verify that the intent of the ISP Program is doing what 24 it's supposed to do.
25 While the valve failure was of low safety significance, relative to the
35 1 design basis accidents such as a loss of coolant accident, Loop II of the RHR 2 system is specifically relied on for reactor core cooling in the event of a 3 significant fire in certain areas. So, like was also mentioned, we committed to 4 the SISBO or self induced station blackout methodology and what that boils 5 down to is we if we were to have a significant fire we would systematically shut 6 off switch gear to various components leaving this one train as our only available 7 train to inject and should you have a problem like we had in this valve this is the 8 only train you've left available to inject into the vessel. So we believe that 9 originally this was felt to be at least a 20 month period because of the March of 10 '09 period where we did successfully inject, we used that as the period of time for 11 the failure mode. Next slide, Page 3.
12 We do fully acknowledge the high safety significance of this valve 13 failure and the basis for that conclusion. As a result we are taking extensive 14 actions to address this issue that will be described later in this presentation.
15 We're also using this occurrence to focus even more attention on 16 the areas that need improvement at the entire Browns Ferry Plant and accelerate 17 those improvements as well, but not only that like the Regional Administrator, 18 Victor McCree had mentioned, this is an extent of a condition across the fleet, so 19 what we take away from the Browns Ferry finding will be put into our corporate 20 corrective action program and taken systematically across the entire fleet.
21 Although there are maybe some issues to specific Browns Ferry and different 22 leadership teams and different outcomes, the systemic issues that may be found 23 there could be broader in nature and we can't afford to be a myopic view and 24 only attack Browns Ferry.
25 With regard to the failed RHR valve and it's duplicate valve in the
36 1 other loop at Unit 1, the significant strengthening of the stem to disc modifications 2 were done. So we went to both Unit 2, Unit 3 and the second valve on Unit 1 3 and there was six valves that were mentioned earlier and we did a significant 4 modification to those valves. The Part 21 was a thread issue where the stem 5 was allowed to pull out of the disk and that was determined to be ultimately the 6 component root cause. What we talked about here and root cause, and part of 7 our issue of not being as broad in our root cause determination initially, we kind 8 of looked at this as a component failure and looking at the root cause around 9 that. We did some extensive review there, but the bigger picture of the 10 programmatic issues of why was this not detected earlier and those sorts of 11 issues were not part of our initial root cause. So, what weve been working on 12 now in the last several months has been a broader root cause that gets at the 13 leadership, the programmatic deficiencies, and those sorts of things that could 14 have and should have identified this in an earlier manner.
15 Weve also taken a number of steps that significantly reduce the 16 risk posed to the plant as a result of an Appendix R fire that would result from this 17 and other component failures of this type. Specifically a question asked a little bit 18 earlier in terms of the relationship Im going to say to the 002 and the 003, but 19 our decision to commit to the SISBO logic many years ago is something thats 20 been of significant importance to myself and our team for the last two and a half 21 years, almost from day one on the position weve been looking at the 22 commitment to NFPA 805, how do we build margin back into our models and do 23 the necessary modifications to the plant.
24 On top of that, should we have not had that model, our operator 25 more than likely would have had other tools at their disposal, should this one
37 1 valve had failed, and we could have easily went to other and multiple different 2 trains to get water into the vessel, but because of our commitment to SISBO, that 3 was removed. So, with the going forward with building the margin back into the 4 plant, weve already done several things that have reduced risk in fire protection 5 arena in our turbine building specifically, our cable trays, and theyre faced with 6 them, and etcetera, as well as putting direction in our procedures until we get our 7 full implementation of NFPA 805. We have actions in our procedures should we 8 have to go into our SISBO logic of protecting the plant from a severe fire, that we 9 also have direction to them should that one train not be operable, that we relied 10 on in the model, then we can empower the operators to reenergize different 11 busses, assuming that probably all of them will not be affected by the local fire, 12 and there are actually some other techniques not requiring either of those 13 busses, those safety busses, as well to get water in, but we had not provided that 14 direction nor have we trained to those alternatives and those are all part of our 15 going forward issues. So, if we were to have the same issue today, we will have 16 minimized already that risk with substantial more improvement coming as we 17 move forward with our NFPA 805 commitments.
18 On to Page 4, based on their own assessment of the safety 19 significance of this valve, we found that there was a high likelihood that either the 20 operators would have taken another non-proceduralized action to reestablish 21 core cooling or that the valve in fact itself would have functioned in particularly 22 sequence of events occurred, may have actually opened the valve, but we do 23 completely understand that based on the NRCs evaluation, these factors could 24 not be credited in determining the safety significance of the valve. If we have not 25 trained operators to go reenergize equipment or talk to them, or train them to do
38 1 these multiple other options nor have procedures to do that, then saying that that 2 is something that you can commit to actually would have happened is not in the 3 best interest of the NRC and we understand that, and concur with that.
4 We also fully agree that the basic issue in this case is that theres a 5 lack of rigor in evaluating information regarding the operation and testing of this 6 valve. This valve was pulled out of the 89-10 program. We did put in an appeal 7 in terms of specifically the IST program, because we believe a lot of the actual 8 IST testing we did was at least at a minimum consistent with how most of the 9 other industry has done it. But through the detailed root cause were executing, 10 weve not completed it at this time, but its looking like we had asked to remove 11 this valve from the 89-10 program years ago. And we do believe that if it was left 12 in the program, the detailed analysis, or MOVATS or VOTES type traces are 13 common terms in the industry, that theres a good chance we would have 14 identified that this valve has some issue internal to it much sooner. So, the fact 15 that one is not in our program and two, we removed it, is I think a contributor to 16 this issue.
17 And the next slide, Page 5, the original root cause analysis of the 18 valve failure did not go far enough and that we missed the opportunities; and I've 19 spoke to that. The detailed diagnostics, there is one point on this too is that this 20 may have failed as early as 08 and that part of our analysis that was not 21 accepted out from -- Im going to say research firms and other companies out in 22 the West Coast that we employed to do analysis for us. We do have a trace, but 23 even though it wasnt fully in the 89-10 program, we actually had a trace like an 24 89-10 that was developed in the 08 timeframe, we actually had one I think in 06 25 and this valve did inject, in 06, did inject in 08. We think there is a total of
39 1 potentially five times the valve may have injected since this thing failed. Thats 2 not a hundred percent concluded, but if you look at the traces, there is some 3 anomaly in it that were still evaluating right now that kind of led to some of the 4 false beliefs that the valve was going to do what it was supposed to do when in 5 fact it may have been separated even earlier and because we did not do 6 elaborate testing and in that diagnostic analysis we missed an opportunity to 7 have caught that.
8 So, were taking this opportunity to look beyond those issues 9 associated with the valve to broader issues across Browns Ferry, and as I 10 mentioned, also across the fleet. We are evaluating whether the proper steps 11 are taken to ensure plant equipment will have the required level of reliability, and 12 the reliability question is key in that mentioned before, some of the scrams and 13 other actions and challenges to operations over the last few year.
14 Since the startup of Unit 1, there have been numerous issues with 15 Unit 1 startup. Many of them had to do with balance of plant activity so where in 16 the restoration of the plant we didnt put QA as an example, as an oversight 17 function on some of the craftsmanship in the field, and assuming that because it 18 was not part of the safety related side of it, that that would be acceptable. One of 19 the questions going forward would be how about our Watts Bar or a Bellefonte.
20 Well, those would be an example of having extra oversight on the craft level 21 throughout the whole plant, but we also know that our programs is an issue and 22 Ill speak to that in a little -- in a minute, but specifically the rigor around the 23 program specifically tied to our safety related components, and what not, was 24 also during that time fractionated; it did not have a strong corporate governance 25 and there were other deficiencies tied to that, and Ill speak to that in just a
40 1 minute. On to Slide 6 with the safety culture.
2 There are currently two substantive cross cutting issues identified 3 by the NRC at Browns Ferry, the first being aspect Papa 1 Charlie, which is 4 thorough evaluation of identified problems and the second being at -- the second 5 aspect be Papa 1 delta, which is appropriate and timely corrective actions.
6 In its mid-cycle assessment letter of August 29, 2011, the NRC 7 expressed a concern with the scope and progress of our efforts to address these 8 issues. Because of the length of time, the Papa 1 delta substantive cross cutting 9 issue has been opened. The NRC requested in its letter that TVA address this 10 SCCI as part of our planned safety culture assessment required by NRC 11 inspection procedure 95003. We have decided to include a review of the actions 12 identified and have already taken to address both SCCIs, not just Papa 1 delta 13 as part of this third party safety culture that were now conducting. We consider 14 these SCCIs as related to the broader issues that I spoke to earlier, and the 15 issues of getting at the root causes and getting at the effective corrective actions 16 seems to be in line with the SCCIs that were mentioned both in the prior 17 discussion as well as what Im mentioning now. On Page 7.
18 As stated earlier, were investigating and analyzing how we do 19 business at Browns Ferry. As part of this, we agree with the NRCs assessment 20 that there is a culture at the plant of taking a minimalist approach to addressing 21 problems related to equipment reliability, the kind of broke-fix comment made 22 earlier. We appear to have a culture at the plant that tends to take a limited 23 approach to equipment problems rather than looking into why the problem 24 occurred and what needs to be done to preclude it from happening again. Now, 25 during the 002 in addition to that inspection, that team did look significantly at our
41 1 corrective action program and they were to a point of closing that out, but theres 2 issues in terms of depth that would be very difficult I think from even an 3 inspection module to see the completeness and thoroughness, but theres also a 4 time issue and that timeliness -- or excuse me -- that the quality of these 5 products from years ago were substantially weaker than what were doing today, 6 not to say that were doing today is still getting at all the root cause issues and 7 thoroughly getting this behind us, but I do believe theres substantial 8 improvement today from what there was several years ago. So, that 002 9 inspection has looked several years back for completeness and I think the going 10 forward one that were in right now will require even more rigor in terms of our 11 root cause implementation and review.
12 To address the issue, we need to improve teamwork and 13 engagement of the plant staff, and one of the questions that may be is, are we 14 staffed appropriately. We have 1,112 employees onsite. We have a standard 15 organization that we benchmarked heavily and we really -- because theres not 16 too many plants with three units, we came up with a standard Org of 1154; its 17 not necessarily linier from single to double unit and double unit to triple unit, but 18 we do believe its adequate and to date weve included an increased staffing in 19 targeted areas as the line has come forward with the need, and we continue to 20 look at that. Ive had very strong support from the COO and CEO, to do what it 21 takes to fully staff and coordinate this recovery effort, but also what the steady 22 state staffing would look like for a three unit site.
23 The plan also in 2012 had a capital budget, an O&M budget of 24 $434 million, so we think there are adequate resources to improve the plant. We 25 know theres a lot of people at the plant and the folks are all committed, and I
42 1 think one of the most valued comments we heard from your visit the other day is 2 the fact that the people recognize that theres a lot of things to do, but they had 3 all in all energy to actually take it on and from a safety culture standpoint and 4 what it takes to really turn around a troubled plant; it starts right there and if I had 5 that battle ahead of me this could be prolonged and protracted. I currently have 6 no concerns with adequate resources. The board of directors as well as our 7 CEO, and the COO, have essentially supported me with any requests forwarded, 8 and I believe that will be a sustaining action for me as we go forward.
9 I, as the chief nuclear officer, and the rest of the executive team 10 here, decided to use this "Red" finding as an added motivation to accelerate 11 improvements. Weve not been sitting back in our laurels for the last couple of 12 years. Weve been doing a lot of material condition improvements to the plant, 13 but the extent of the conditions, the detailed root cause as mentioned about why 14 were getting there, those are still issues that were still working through and 15 theres a great deal of work that was required a few years ago, and there still is 16 going forward, and though one of the benefits though is through governance 17 model that Ill mention in just a minute, the clarity around what needs to be done 18 is substantially stronger today than it was a few years ago, and from that its 19 more of a matter of planning and coordinating as opposed to we dont even know 20 what we need to do. And so were more in the lets go implement phase, and so 21 the ability to accelerate that is a benefit to the site vice president here, Keith, and 22 that he has a green light to even shut a unit down if thats what he needs to do; 23 albeit, we need to make sure our packages are ready to go, shutting plants down 24 with people not having work materials or parts, and those sorts of things is not 25 only not productive, its a major distraction to safe operations, but on the other
43 1 hand as we prepare and ready ourselves to do these significant material 2 condition improvements, we will do the execution of those when the time is right 3 for the plant, and the full support of the CEO, and COO to accomplish that. On to 4 Page 9.
5 There are a few improvements already in place. One of the most 6 critical elements to sustainability of this new culture and equipment reliability 7 stands with a strong corporate governance, and oversight. Specifically TVA has 8 had a corporate structure for years. Im not trying to paint that as non-existent, 9 but the model was not one of central governance. For the most part the sites 10 were allowed to be autonomous, and they kind of ran their own site, and they 11 used corporate as what we call a reference material if you will, or reference 12 players. If they needed us, they called us and if they didnt need us, they made 13 their own decisions. Well, coming from a large fleet, from a -- plant, it recognized 14 immediately that the only way to operate is by heavy benchmarking, the creation 15 of corporate functional area managers, have a central presence in making sure 16 that no single site is allowed to be reduced to the lowest common denominator.
17 So, the corporate functional areas we have are all empowered. They are the 18 decision-makers. They benchmark heavily. Theyre out and about in the 19 industry substantially and they then create central documents that all other 20 documents tier down from, thus assuring us the biggest question of sustainability.
21 We also have key metrics and processes in place. We do 22 substantial numbers of cross self-assessments from corporate and sister plants 23 coming down, and looking at these programs and processes, all of which to 24 ensure that one, we have the best industry standard in place, and two, that 25 theyre actually executing it, and were seeing some progress in that area, but
44 1 that is another part of the cultural issue, is it will take more than a quarter or two 2 to really get the behaviors around adopting this central approach. But we are not 3 at a point of just starting. Weve actually had some bricks and mortar on the 4 ground in this arena, and were starting to enjoy some of that benefit.
5 Weve also already had in place an equipment reliability program.
6 This was new also and there are many corporate SPPs we call them, or 7 procedures that give guidance to many of the programs and processes that have 8 allowed to decay, or did not exist. So with that, we had already started to 9 uncover a multitude of different program issues, but we did not complete all the 10 self-assessments nor had we identified all the problems, nor have we to this 11 date, but we do have a program. We do have assessment modules in place.
12 We also have plans and calendar dates for executing these, and they go across 13 the fleet. So, its not just a Browns Ferry issue, but if I ask myself from a 14 sustainability issue, another part with governance also has to be quality 15 programs and procedures, and processes from a central standpoint. Do they 16 exist? Are they of quality? How do you know theyre of quality and are you 17 executing them, and thats the part weve been focusing heavily on, and we 18 expect to see traction in that arena.
19 In addition, we spent about $260 million specifically at Browns 20 Ferry for equipment reliability issues. So, its not just a total O&M for bodies and 21 mandatory regulatory required issues, and those sorts of things. These are 22 targeted dollars tied to significant material condition improvements. Just a few of 23 the things done as emergency diesel generator heat exchanger, air dryers, 24 batteries, have all been replaced. But we still had turbo chargers and other 25 significant maintenance items still ahead of us on the machines, but they are in
45 1 the works and we expect to commence those shortly.
2 Significant work in our motor operated valve program.
3 Unfortunately we did wait until kind of the last minute to launch the MOV 4 program, however it is launched and in our last outage, weve had in think an 5 upwards of 19 key valves. These are not small, one inch valves, these are large 6 valves to essentially take them apart and do all the modifications that are tied to 7 the motor operated valve program from the joint owners group. And then 8 another key program we spent substantial time on is the actual upgrade and 9 getting to within frequency of PMs on major motors. Id like to say that thats also 10 been a mature program, but frankly it has not. As mentioned, when you toured 11 the other day, we have replaced two recirc motors in our last outage, for 12 example, that were seven years past OEMs recommended PM intervals on 13 those motors.
14 Weve changed already six RHR motors, just dropped and 15 swapped. We completely changed them out. We changed three RHR service 16 water pump motors and six core spray motors. So, almost all of the majority of 17 our safety related significant pumps have been upgraded with their motors, and 18 were going to continue until we get current on all of those motors.
19 We have some other issues with some pumps proper, like our RHR 20 service water pumps that have aged issues with their casings and what not, and 21 were going to be changing those out systematically as well. So, its not like 22 weve not done a thing in the last few years. Weve been actively improving and 23 that has shown up in what we call equipment related clock resets. I believe we 24 had in 09 around 27 clock resets tied to significant equipment failures and I think 25 were around 17 or so in 2010, and were on track. So, if you look at a number of
46 1 clock resets tied to equipment reliability, weve been gaining on that. The 2 number of trips in the last few years, over the last year or so we did obviously 3 have the tree trips tied to the tornado, but other than that thereve been some, Im 4 going to say, improvement potential in that, but were a long ways from out of the 5 woods. But we do have the indicators now that really track that overall 6 performance and the commitment from TVA. And our engineering staff is one of 7 excellence in equipment reliability, and thats where our primary focus is. So with 8 that Im going to turn it over to Bill for final comments.
9 BILL MCCOLLUM: Okay, thanks, Preston. So, Preston has tried 10 to go through and characterize a number of issues, some historical and bringing 11 it up to current time, and I want to put that in perspective. So, our commitment is 12 that were going to run nuclear right at TVA and that means several aspects of 13 the program have to be top notch. Preston talked a bit about the equipment 14 issues, specifically going back to the root cause of the LPCI valve failure, and 15 you heard discussion of a lot of work that went into the specific equipment failure 16 root cause, because its extremely important to us if were going to do this right, 17 that we have to have excellence in engineering. We have to understand exactly 18 when things fail, why they fail and make sure that our engineering is correct and 19 we had a good bit of back and forth with the NRC staff to gain clarity around 20 whether the engineering work that we were doing, the testing we were doing 21 made sense and explained the failure of the valve, or if there was information to 22 the contrary, that we heard that back and had that dialogue to get to clarity on the 23 work that wed done on equipment failure. Having done that and having gotten 24 the information, and gotten a clear understanding of exactly what went on inside 25 that valve with the thread manufacturing that allowed the stem to pull loose from
47 1 the disk, we have come to clarity on that. Weve moved on from that and so I 2 dont want anyone to take away from the fact that there was a lot of back and 3 forth dialogue about the specific equipment issue that we are continuing to dwell 4 on that. Thats something that needed to be brought to clarity. Its been done.
5 The discussions been had and weve moved forward, and learned from that, but 6 its important that we do the equipment work and the engineering right.
7 Likewise on the programs, you heard some discussion about 8 Appendix R, a program where we had historically not been as aggressive as we 9 needed to be to upgrade that program and we are moving ahead, not only with 10 taking actions now to reduce our probabilistic risk relative to fires under Appendix 11 R, but also moving forward to NFPA 805, which will implement as aggressively 12 as we can and we will take actions along the way to reduce and improve our risk 13 without waiting for the final resolution of all implementation of an NFPA 805 to do 14 that.
15 We talked about ASME IST, where again there was a lot of back 16 and forth dialogue with staff, and you heard about a generic issue thats been 17 referred to ASME committee, because we believed to do this right, to do these 18 programs right, we need to have clarity around the programs, the requirements, 19 how you interpret them, how you apply it to specific situations in the plant. Have 20 we always done that right? No. So, were not being defensive about that. Were 21 simply trying to make sure we have clarity about how to apply those programs 22 and make sure we do it right, and thats our commitment going forward.
23 So, we have not done as well as we want to in the program area 24 and Preston outlined a lot of issues or examples of the things that were putting in 25 place to build stronger governance across the fleet, across all of our plants to
48 1 ensure that the programs are applied correctly, theyre implemented rigorously 2 and theres oversight, and questioning of people in the implementation and 3 execution of this work so that we do the programs right. And then looking at 4 corporate and broader issues beyond just Browns Ferry; Preston talked about 5 resources that are being applied. So, we have a commitment to apply all 6 necessary financial and personnel resources to the resolution of issues at 7 Browns Ferry and across our fleet.
8 As you know, organizationally our efforts in terms of our operating 9 plants and Prestons organization are organizationally separate at TVA from our 10 efforts regarding new plants at Watts Bar 2, Bellefonte, et cetera. So, those 11 resources are not stretched in terms of trying to apply resources of one 12 organization to both sets of those efforts. Preston has the resources that he 13 needs and is free to ask for more resources, and has gotten as he mentioned, 14 substantially more resources at Browns Ferry, in terms of both O&M capital 15 expenditures, funds, personnel, not only for the teams and people who are 16 addressing these specific issues with the 95003, NFPA 805, those sorts of 17 issues, but in general and applying the maintenance resources that we need at 18 Browns Ferry. That is our top priority to improve operation at Browns Ferry and 19 apply the resources that we need, and if we need to pull resources from another 20 effort within another part of the Tennessee Valley authority outside of nuclear, 21 well certainly do that and apply those resources whenever needed.
22 So, theres also a commitment to excellence in operation and 23 Preston outlined a structured approach where we have put a management model 24 in place that provides for a rigorous oversight governance and execution and 25 support model that starts with the corporate support and resources, and the
49 1 program definition, and rigorous application down through the execution of those 2 at the plant, and provides independent benchmarking oversight, and questioning 3 of the execution to make sure that we do that right. Has that all been put into 4 place? Is it mature? Is it where we want it to be? No, but that is the model thats 5 being put in place and we have a commitment to continue to execute that. That 6 comes all the way from the board of directors at the Tennessee Valley Authority 7 and our board Nuclear Oversight Committee, through our chief executive officer, 8 my boss, and from me down to the nuclear operation organization; so we do 9 have efforts in place. We are seeing traction with those efforts. We have a lot of 10 work to continue to do to get to where we need to be, but our commitment is to 11 get there, and to get there rapidly. So, with that we will take any questions.
12 CHAIRMAN JACZKO: Well, thank you for that presentation. We'll 13 start with Commissioner Svinicki.
14 COMMISSIONER SVINICKI: Thank you for your presentations. Ill 15 start in the context of the Part 21 report TVA submitted. What, if any 16 engagement have you had with other nuclear power plant sites, manufacturers, 17 and vendors concerning this valve design and could you describe those 18 interactions?
19 PRESTON SWAFFORD: Rob, would you do that?
20 ROBERT WHALEN: Yes, Commissioner. We have submitted that 21 as mentioned in the licensee event report. We have had direct consultation with 22 General Electric and the crane valve company that is the current owner of the 23 manufacturing company that manufactured this valve, the Walworth Valve 24 Company, back in the 1960s. General Electric has issued at least some 25 documentation to all sites that they believe may have similar products and they
50 1 are following their General Electric corrective action process to our 2 understanding.
3 COMMISSIONER SVINICKI: Okay.
4 PRESTON SWAFFORD: Questions also about interaction with --
5 ROBERT WHALEN: We have done benchmarking as part of our 6 root cause with several other sites that have similar valves, not necessarily in the 7 same application, but we are working directly with those facilities.
8 COMMISSIONER SVINICKI: Okay, thank you. Could you 9 elaborate on the in-service testing interpretation issue thats being handled more 10 generically, specifically was your interpretation common to other TVA sites and 11 from what you understand, was this interpretation more common in the industry?
12 PRESTON SWAFFORD: Specifically, we do believe its common 13 in the industry, so there may be this generic issue at other locations. Theres two 14 main parts of -- I mean part of it, the testing programs also include 89-10, weve 15 already mentioned, where that was deficient in our program, but the other part of 16 actually demonstrating that the valve operated while theres quarterly 17 requirements that actually go out and ensure that the valve stem moves up and 18 down, and you get the proper light indications, and we were current with that.
19 The other part I think is once I think every two year period you have 20 to demonstrate that the valve would actually operate. Well, that was in 09 when 21 we did that program, when we did a full flow test and the valve opened. Now, it 22 may have and our analysis now says that it was probably broken even before 23 that in 08 and in fact it probably did what our other analysis from California said it 24 probably did, but in any event, we arent 100 percent sure thats a true statement, 25 yet more analysis has to roll into it. So, we were believing that we were in
51 1 compliance because we did the full flow test every couple of years and then we 2 did the quarterly operating of the valve stroke indication issue. So, we believe 3 thats what the program required and we believed we were compliant.
4 However, theres other words that I also say, that we have to -- for 5 the whole purpose of this is to assure the valve will do its safety function and 6 thats the part where the normal means in the industry of doing this full flow 7 check and the quarterly stroke test is the typical means of doing that, but I think 8 weve discovered that may not be sufficient.
9 BILL MCCOLLUM: So, in other words doing the normal practice of 10 stroking the valve, verifying that it stroked and that you got flow may in this 11 particular case not have given you the confidence that the valve and disk were 12 not separated or were intact, and thats an issue that needs to be driven through 13 in terms of okay, if in this instance that type of testing doesnt give you the 14 assurance, then what sort of testing or provisions would you need to fulfill the 15 intent?
16 COMMISSIONER SVINICKI: Thank you, I appreciate that 17 elaboration. As Victor McCree described, a safety culture assessment will now 18 be conducted. How effective would a safety culture assessment have been in 19 identifying the underlying issues at the heart of the RHR valve inoperability if a 20 safety culture assessment had been conducted prior to this issue emerging?
21 PRESTON SWAFFORD: Thats a great question. Im not sure Im 22 smart enough to answer it.
23 BILL MCCOLLUM: Yeah, so I think a couple of things we should 24 talk about, one is that we regularly do synergy surveys, safety culture surveys, 25 not as part of this 003 process, but as a routine that weve put in place and so
52 1 that work is done and theres opportunities to look at the cultural issues or 2 indicators, and relate those perhaps to execution of work in the plant.
3 Without being -- you know, I dont want to be defensive and say 4 that culture doesnt directly impact equipment operation, but I think in this very 5 specific instance of the failure, this LPCI valve, its you know, its difficult for me 6 to take culture and get it down to someone understanding the separation of this 7 disk and stem, because of an original manufacturing defect and the inadequacy 8 of the full flow testing that Preston was just talking about, to show that during an 9 in plant test. So, were going to continue that work. Were obviously -- as part of 10 the 003, well do an extensive safety culture review and draw all the threads that 11 we can from that to see how to improve our operation, but that -- making that 12 specific connection is really tough for me.
13 COMMISSIONER SVINICKI: Okay, well I appreciate that. I do not 14 interpret that as any defensiveness. I think its cautious to conclude that it would 15 be very difficult to sit here and draw a very firm line that a safety culture 16 assessment would have revealed this when again this is a very specific 17 equipment inoperability issue, and I think I asked the question from the 18 standpoint that the safety culture assessment cannot be expected or over-relied 19 upon to reveal you know, all issues. So, I appreciate your honesty in that 20 answer. I dont interpret it as defensiveness and I think it reflects that theres not 21 an over reliance on a safety culture assessment to reveal these issues. You 22 need to have, as youve described, a multi-pronged improvement approach and I 23 think youve testified to that here today.
24 Mr. Polson, I think that for you as a site vice president and any of 25 your peers, at other TVA stations and certainly your peers at other reactor sites
53 1 across the country do not want to find themselves sitting at this table, at this kind 2 of meeting. Youve heard the NRC senior management presentations. You have 3 heard your own senior leadership describe the issues at heart here and the 4 improvement plan. What would you communicate to the Commission from your 5 perspective as someone who has an undivided attention, day in and day out to 6 Browns Ferry Units 1, 2, and 3?
7 KEITH POLSON: Well, what Id like to communicate is I mean, we 8 take this very serious, not just myself, the entire site, our whole commitment is to 9 improve the plant. Its not just to get through the inspection and get out of 10 Column I; its to improve this plant forever in its sustainability. So, its a huge 11 opportunity, albeit you know, its not the greatest thing to be at a 95003 12 inspection, but its getting me the resources and everything that I need to make 13 this you know, one of the best operating plants in this country and in the world.
14 So, that is the commitment that we have for my site.
15 COMMISSIONER SVINICKI: Do you feel that youre fully 16 supported by the senior leadership of TVA and anything you need to make that 17 possible?
18 KEITH POLSON: Absolutely, and I have been in this situation 19 before at other troubled plants in the same position, and it was somewhat of a 20 battle, even though we knew we were in trouble, but to get the funding and the 21 resources. Here at TVA, anything that I need, I get.
22 COMMISSIONER SVINICKI: Okay, thank you, and a final specific 23 question for you or maybe for Preston, would you say that TVA has a clear 24 understanding of what the NRC will require of you in order to close out the 25 substantive cross-cutting issues
54 1 KEITH POLSON: Yes, I do. I mean if you look at it, its the 2 timeliness and its the thoroughness of the evaluations and its absolutely right.
3 There was a cultural issue that we have to break. I think were making progress 4 on that right now and so as issues come in and theres multiple issues at nuclear 5 power plants you know, small to large. Were handling even the smallest issue 6 with a huge sense of urgency and I think that the NRC will see what were doing 7 and then there will be a clear exit from there.
8 COMMISSIONER SVINICKI: Okay, thank you. Preston, did you 9 want to add anything to that?
10 PRESTON SWAFFORD: Well, Ill concur with that. We have a 11 ways to go, but weve also put some programmatic things in place. For example, 12 around thoroughness of root causes and corrective actions. Weve got 13 something called CARBS, or Corrective Action Review Boards, but weve also 14 instituted department level corrective action review boards. Were putting more 15 rigor in the actual tracking systems, because thats been a struggle for us and its 16 currently even a struggle in that corrective actions get illuminated into these root 17 causes and other tools, and then next thing you know we lose track of them or 18 we defer them frequently. So, part of what this is also doing is the sense of 19 urgency to drive to conclusion. So its one, is getting into the detail, knowing 20 what the root causes are, but then when you put your corrective action in place, 21 get after them and get them behind you, and given the resources necessary so 22 that the targeted part. We have a special team part of, Tim Cleary, sits behind 23 me is the vice president, is a direct report to me. Hes specifically heading up the 24 003 inspection, even though Keith has to own it, itll never work unless the site 25 VP is front and center on it, but I also need him very much to pay attention to
55 1 three operating units. So, the creation of the position for Tim is to also build the 2 necessary staff around him to ensure the sense of urgency comes through and 3 that were actually following up on all the corrective actions and the detailed level 4 around our go forward.
5 COMMISSIONER SVINICKI: Okay, thank you. Thank you.
6 CHAIRMAN JACZKO: Commissioner Apostolakis.
7 COMMISSIONER APOSTOLAKIS: Id like to continue along with 8 some or one of the questions from Commissioner Svinicki. I understand you are 9 doing now a safety cultural assessment, or you have somebody else doing that?
10 PRESTON SWAFFORD: Yes, sir.
11 COMMISSIONER APOSTOLAKIS: Is this the first time you are 12 doing -- such an assessment?
13 PRESTON SWAFFORD: We did one for the 002, but its not to this 14 scale. We had been using Synergy, which also gives a barometer of the safety 15 culture at the site and so this will be substantially more. Therell be a lot more 16 one on one discussions. The rigor in it will also get input from NRC and their 17 expertise to make sure that we only do this one time and the one time we do it is 18 effective.
19 COMMISSIONER APOSTOLAKIS: Now, this is being done by 20 some outside --
21 PRESTON SWAFFORD: By a third party, independent.
22 COMMISSIONER APOSTOLAKIS: Now what does it entail? I 23 mean do they come and ask your employees or are they looking at data also, 24 past performance? I mean there isnt such a single thing that we call safety 25 culture or a single way of doing it, and how much confidence should we place in
56 1 it?
2 PRESTON SWAFFORD: Theres a questionnaire. It has 3 substantial industry data input, so they believe it to be a highly effective predictor, 4 the third party firm that puts it together, but also for the magnitude of this, there is 5 going to be a fair amount of kind of one on one discussions to add more input to 6 the conclusions of it. I cant -- Im not the expert. Maybe Rod, Im not sure if you 7 had - this is Rod Ketcher, Vice President of Licensing.
8 ROD KETCHER: It will be as Preston said. First, we did the 9 survey, which weve just completed. Then therell be extensive interviews, and 10 then therell actually be observations made of plant staff performing their 11 activities.
12 COMMISSIONER APOSTOLAKIS: But presumably -- I mean on 13 Slide 7, you say there was a long standing culture of taking a minimalist 14 approach to problems. If I were to ask an employee are you taking the minimalist 15 approach, he would say, No. I dont think anybody would agree that theyre 16 taking the minimalist approach, so I don't know what the value of surveys is. Is 17 there something I'm missing there?
18 ROD KETCHER: I think that youre right in the sense that youre 19 not going to get the answers just from the survey. A lot of it comes from the 20 interview. So, I just had my interview and during that interview we in fact 21 discussed this issue of a minimalist approach, and so you have now people, 22 newer people who are brought into TVA, who are looking at the situation, seeing 23 it in a different light, and in that way I think theyll be able to get to a broader view 24 of --
25 COMMISSIONER APOSTOLAKIS: So there's more to it than just
57 1 surveys, yeah -- thats a good point. Now, staying with the same subject, the 2 longstanding culture, why was it longstanding? Nobody figured that there was 3 something -- a problem there or --
4 PRESTON SWAFFORD: Well, I believe it has to do with, Im going 5 to say, the autonomous site and because if you will, you drop a site vice 6 president in there, you have one person trying to change whatever the culture is 7 and at Browns Ferry because of their history and the different material condition 8 issues, I think you could conclude that that culture isnt to the highest degree and 9 highest standards that were looking for. Yet you couldnt necessarily draw that 10 same conclusion to the other sites because, again, they were autonomous, and 11 so however they started up the strength of certain vice presidents and duration 12 and those sorts of issues are all parameters. But I do know, going forward, the 13 central approach with a very strong central governance model with programs, 14 processes, and procedures starting from the hub will affect that outcome even at 15 the hardest of plants because of the degree that we do self assessments, probe 16 our morning calls every morning where the plants do more than just talk about 17 status. We talk about human performance and equipment issues, those sorts of 18 things -- are all mechanisms that the central corporate group has to their 19 disposal, if you will, to see if theyre aligning with us or if theyre drifting to a 20 different direction and Im strong enough, if you will, and perceptive enough to 21 realize those that are kind of drifting off the reservation and those that are staying 22 fully supportive. So I think the model eventually is going to turn that culture and 23 itll have it, not completely, but mostly similar to the other two sites and will be 24 one fleet in behavior.
25 COMMISSIONER APOSTOLAKIS: Thank you. On Slide 4, you
58 1 say that TVA identified a number of factors that mitigated the safety significance, 2 but the NRC did not accept those, which brings me back to my earlier question to 3 the staff. What is the number that they produce -- the significance determination 4 process produces, in this case, 7 times 10 to the minus 4, what does it 5 represent? Does this number allow only the inclusion of events that have been 6 proceduralized, and ad hoc actions are not allowed? Is that the way the SDP is 7 structured?
8 PRESTON SWAFFORD: By and large, I believe thats true.
9 COMMISSIONER APOSTOLAKIS: Now, if you were doing -- I 10 dont know, maybe you have done it already, but if you had included those 11 factors, would that 7 times 10 to the minus 4 be reduced significantly?
12 PRESTON SWAFFORD: No, it would probably have been "Green".
13 COMMISSIONER APOSTOLAKIS: It would still be "Red".
14 PRESTON SWAFFORD: No, it would have probably been "Green".
15 COMMISSIONER APOSTOLAKIS: So it would have been 16 reduced?
17 PRESTON SWAFFORD: Yes.
18 COMMISSIONER APOSTOLAKIS: By ad hoc actions, do you think 19 it would go down by --
20 PRESTON SWAFFORD: Well, I mentioned earlier, for example, 21 operator actions, the NRC could not credit us with the --
22 COMMISSIONER APOSTOLAKIS: I understand that, yeah.
23 PRESTON SWAFFORD: But you would have credited, there were 24 so many other ways to get water into the vessel that, in fact, from a PRA 25 standpoint, that value would have been substantially less risk, lets say.
59 1 COMMISSIONER APOSTOLAKIS: Rather interesting operation.
2 ROBERT WHALEN: Yes, Commissioner. The NRC significance 3 determination does really center on the operator actions that would be required 4 based on our legacy self-induced station blackout approach. And each of those 5 actions had to be treated. In their review of scenarios, a human error aspect with 6 each of those had to be summed in that process. And that really drove their 7 analysis of the issue.
8 COMMISSIONER APOSTOLAKIS: How much would you have 9 reduced it, an order of magnitude?
10 ROBERT WHALEN: It really hinges on the human error aspects of 11 all those actions and the fact that we had that SISBO approach built into our 12 procedures. And we recognize that that SISBO approach is not appropriate. We 13 are working vigorously to implement NFPA 805 and go away from the SISBO 14 approach. In fact, as Mr. Swafford has mentioned, we have taken interim actions 15 to pull forward modifications from the NFPA 805 work to reduce risk. We have 16 put in alternate pathway options into the procedures. We have also, for the 17 highest risk areas in the NRC Significance Determination being the turbine 18 buildings, we have eliminated the SISBO strategy by installing new fire barriers.
19 We have installed various modifications, circuit modifications, incipient fire 20 modifications and such as well.
21 COMMISSIONER APOSTOLAKIS: So, there are two issues that 22 come to my mind after your response. Clearly, the model one uses for 23 estimating human error probabilities would be very critical in this case.
24 ROBERT WHALEN: Yes, sir.
25 COMMISSIONER APOSTOLAKIS: And, again, there is a number
60 1 of models out there one can pick and choose. Our staff has been working on 2 trying to come up with EPRI and other organizations, to come up with a single 3 model or maybe one of two models that would be acceptable to everyone. And I 4 think this situation reinforces the point that we really have to do that. The other 5 point is when you switch to -- transition to NFPA 805, then everything I 6 understand from that point on related to fire protection would have to be risk 7 informed. And would that allow you then to use ad hoc operator actions in that 8 case? It would be different from the SDP, the Significance Determination 9 Process?
10 ROBERT WHALEN: For our NFPA 805 transition, we are right now 11 nearing completion of the fire PRA, and were following that transition process.
12 In parallel with that, we are pulling forward modifications that are indicated by 13 that transition, doing them ahead of time, if you wish, in order to reduce the risk.
14 Because we did not have a fire PRA, the NRC, in doing their significance 15 determination, had to develop a spreadsheet model and develop --
16 COMMISSIONER APOSTOLAKIS: One last question. Ive heard 17 over the years complaints that one problem with the ROP is that it is risk 18 informed in many ways but also it is in very significant ways risk-based in the 19 sense that there is a point number, a point value that is produced -- in this case, 20 7 times 10 to the minus 4, and the fact that there is uncertainty about that 21 number, it really plays no role. So in that sense -- and 7 times 10 to the minus 4 22 clearly is about the threshold of 10 to the minus 4, but what if it were 1.5 times 23 the minus 4 or 2 times 10 to the minus 4, how much confidence would one have 24 there that its "Red" versus another color? Do you think thats something that 25 needs to be corrected, that its too much based or focused on point values?
61 1 BILL MCCOLLUM: Ill say this example is probably a tough one to 2 deal with for the staff as well as licensees because, as Rob said, if you were to 3 credit some of the other actions that could have been taken, the risk doesnt just 4 change a small amount; it changes dramatically. So, youd go from "Red" to 5 "Green". And so its -- you use a -- you can use a point value or you can take 6 some opportunities or look at some opportunities that dramatically change the 7 risk. And that may be a hard one to deal with within the ROP process.
8 COMMISSIONER APOSTOLAKIS: But maybe the dramatic 9 reduction is due to the fact that were using point values. Maybe with an 10 uncertainty analysis, you wouldnt see such a dramatic shift. I dont know. I dont 11 know. Im just speculating myself, but it seems to me thats a weak point, not in 12 this particular case. But anyway, thank you, Mr. Chairman.
13 CHAIRMAN JACZKO: Commissioner Magwood?
14 COMMISSIONER MAGWOOD: Good morning. You know, Ive 15 participated in a few of these types of meetings, and Ive concluded that in large 16 respect, theyre pass/fail meetings for the licensee. And its not that hard to pass.
17 I mean, basically, all you have to do is say We understand, we get it, were 18 changing. I mean, thats pretty much all you have to do. Now, of course, you 19 have to mean it, and we have very good staff who will make sure that the 20 commitments youre making at the table today are carried out.
21 In that respect, I do appreciate the detail and the 22 comprehensiveness of your presentation Mr. Swafford. I thought you covered a 23 lot of ground and did it very well. And I appreciate both the details and also the 24 broader perspective. And I also appreciated Bill McCollums follow-up where you 25 made a reference to, I think you said the back-and-forth between TVA and the
62 1 staff on a variety of issues, but your point was that, you know, were moving 2 beyond that. We did it and, in fact, were going forward.
3 However, I was looking at your June 8, 2011 letter -- June 11, 4 excuse me -- which wasnt that long ago. And I wanted to just sort of read a few 5 things and I just ask you to, with todays perspective that youre bringing to the 6 table, sort of give us your thoughts about what youre -- about where you are 7 today with this. The letter, which I dont think is actually -- I think Mr. Swafford, 8 says, and Ill just quote a few things here. the actual cause of the failure was 9 found to be manufacturing deficiency, i.e. undersized threads in the disc skirt 10 which resulted in axial separation of disc from the disc skirt/stem assembly 11 Because TVA could not have reasonably identified the manufacturing deficiency, 12 no licensee performance deficiency existedTVA considers that Browns Ferrys 13 IST program and its implementation are in compliance with Section ISTC 4.1 of 14 the O&M code as its understood by TVA and many others in the industry, and 15 that no licensee performance deficiency related to IST was related to the valve 16 failure. And youve spoken to this a little bit, but let me give you my perspective, 17 Im going to ask you to get me your current thinking about this.
18 When I first heard about this and the staff briefed me on this, 19 obviously, there was concern, an important issue. But I was actually more 20 concerned with TVAs response to it quite frankly, and this still remains 21 somewhat concerned because, to me, what this says is it wasnt our fault. And I 22 -- I guess in a very broad sense, its my feeling that if you operate a nuclear 23 power plant, you can never say its not my fault. And I wanted to hear from you 24 today whether, you know, were ever going to hear from TVA again, whatever the 25 circumstances are, that it wasnt your fault, it was the manufacturers fault, it was
63 1 ASMEs fault, it wasnt our fault -- we only operate the plant. So let me give you 2 a chance to respond to that. Because that actually, in this whole instance was 3 the thing that concerned me most.
4 BILL MCCOLLUM: Yeah, so let me start and Ill Preston jump in, 5 too. The letter doesnt say that its not our fault. Its our responsibility to make 6 sure that the equipment operates correctly, that the programs are implemented 7 correctly, and the letter does not anywhere say that its not our responsibility or 8 not our fault. The term performance deficiency is a specific term of ardor in 9 regulatory space, has a particular meaning. And so the -- our intent, again, was 10 to make a choice between simply accepting assertions without enough dialogue 11 to make sure that we had really driven out clarity on how the staff saw the 12 specific failure causes of the LPCI valve and how the staff would see what good 13 implementation or effective implementation of the ASME IST program would look 14 like, a choice between accepting with less dialogue or pushing the envelope to 15 drive more dialogue and more clarity on those issues. And that was the choice 16 that we made. Could we have worded the letter differently and been more clear 17 about the intent and that sort of thing? Certainly we could. But our intent was 18 not to say that we didnt have responsibility. It was to say we owe it to ourselves 19 and the rest of the industry to drive this dialogue further to make sure that were 20 really clear about how we see this valve failure and how we see the 21 implementation of the testing requirements being played out. Preston?
22 PRESTON SWAFFORD: I want to add a little point is that we did 23 believe that the performance deficiency is tied to the conclusion of a "Red" 24 finding and that needing to get the proper performance deficiency nailed would 25 be critical for our success path even out of the 95003 inspection. And when we
64 1 reviewed the specific "Red" finding, the IST portion of it, we thought we were in 2 line with the rest of the industry, not that that valve hadnt separated and not that 3 the valve didnt have significant safety significance to it. Its just that before we 4 launch a whole team and move forward, plus the ramifications on the industry, 5 should that not be clarified, was a concern. And I had multiple discussions with 6 the folks around that. So that all combined was the reason that lets get clarity 7 around the performance deficiency so we can fix the right thing and also not 8 ratchet the whole industry into something that may not be germane to them but 9 you need programs like the 89-10 program is an example.
10 COMMISSIONER MAGWOOD: Okay, let me -- I understand what 11 youre saying. I understand what youre saying. But I hope you understand what 12 Im saying as well, that, you know, that what I do hear you saying however, is 13 that you are taking responsibility.
14 PRESTON SWAFFORD: Thats correct.
15 BILL MCCOLLUM: Absolutely.
16 COMMISSIONER MAGWOOD: That it seems to me that for any of 17 the operators, youre going to run into situations where youre going to have 18 manufacturing issues, youre going to have IST issues, but at the end of the day, 19 its got to be -- it has to be the people at this table that take the final 20 responsibility. And so I -- and I recognize how the process works. You know, 21 you get a letter from NRC, you have to write a letter back. You have to push 22 back. But, you know, I think that, you know, when you think about the people we 23 all serve at this table, the public, I think it would be disturbing for the public to 24 think that the operators of nuclear power plants every had situations where they 25 would sort of simply, you know, sort of pass the buck. You know, I know youre
65 1 not saying that, but let me just say thats certainly the impression one gets from 2 reading that letter.
3 PRESTON SWAFFORD: We definitely are not -- in fact, the whole 4 team, nuclear professionals dont operate well by passing the dollar. And we 5 have to own it first-person, and the chair -- or the Senator the other day asked 6 who was the head on top of the totem pole, if you will, that owns this, and it was 7 very clear that Preston Swafford does, chief nuclear officer. We dont pass the 8 dollar here.
9 COMMISSIONER MAGWOOD: I appreciate that. Let me ask a 10 more detailed question. I was talking with the staff about why the -- some of the 11 motor operator valves were left out of the IST program. Can you talk a bit about 12 that? Why were some of these valves outside the program?
13 PRESTON SWAFFORD: We -- and what were, I think, mainly 14 talking about is the 89-10 program specifically. For example, this valve was in 15 the IST program. We did the flows. Checking thee quarterly strokes, but it was 16 not in the 89-10 program. We had removed it and submitted essentially 17 documentation to the staff to get it removed from the program. Since our own 18 internal root cause and evaluation, I think some of the information we submitted 19 was not correct, so the basis for what we were concluding -- this was in 1997 --
20 to have this valve removed from the program was not based on -- Im going to 21 say quality engineering and development. So, what were looking at is those 22 valves that got pulled out, what was the justification for that, was there rigor in 23 that or not, and then taking corrective actions appropriately, not just at Browns 24 Ferry, but any potential at the other two sites as well.
25 COMMISSIONER MAGWOOD: Okay, good, so that -- this is a
66 1 fleet-wide activity.
2 PRESTON SWAFFORD: Yes, it is.
3 COMMISSIONER MAGWOOD: Great. And just finally, I heard 4 your conversation with Commissioner Apostolakis about the SISBO strategy, so 5 my understanding is that you are moving away from that. Youre relying on 6 NFPA 805 as the mechanism to get you there.
7 PRESTON SWAFFORD: Thats correct. Upon starting up Unit 1, 8 there was substantial dialogue between the Commission and TVA on that. For 9 whatever reasons, we chose not to commit to NFPA 805 within the window, if 10 you will, that in retrospect was not in our best interests. But nonetheless, thats 11 the way that went. But since two and a half years ago when we committed to 12 NFPA 805, weve been diligently working to get out of SISBO. Weve been doing 13 the plant mods and like the engineering VP had mentioned, Rob, weve already 14 done substantial enough work in the turbine building such that the SISBO logic 15 for applicability there is no longer required or wont be shortly upon completion.
16 So, the other plants have SISBO but most of them took a little bit different attack 17 in that they did detailed analysis of cabling, cabling routing, and knew the 18 outcomes of it, where we essentially just took the SISBO position and didnt do a 19 lot of that analysis, so our ability to, one, minimize operator manual actions and 20 as well as to be able to, if you will, target the utilization of the SISBO logic to a 21 much narrower band was not accomplished. And therein lies where our goal 22 forward is. And we do expect over the next year to essentially have submitted 23 our LAR and --
24 COMMISSIONER MAGWOOD: What about the other plants in the 25 fleet? Are you expecting to --
67 1 PRESTON SWAFFORD: Those plants are designed. Theyre 2 much newer. And when I was talking other SISBO plants, they're not our other 3 two plants. They are, I think, four or five other plants that have a self-induced 4 station blackout as a liable mechanism, but their programs, Im not trying to indict 5 them. They did many other things through the years that Browns Ferry did not 6 do. But our Sequoyah and Watts Bar are much newer design. They have a lot 7 more Appendix R codes fully implemented at the stations, and their manual 8 actions are substantially less. But we are still looking at NFPA 805 as a potential 9 option or some hardening, if you will, of our Appendix R actions on those plants 10 as well.
11 COMMISSIONER MAGWOOD: Okay, thank you. Thank you very 12 much.
13 CHAIRMAN JACZKO: Commissioner Ostendorff?
14 COMMISSIONER OSTENDORFF: Thank you, Mr. Chairman. I 15 appreciate the candor of your presentations today. And I want to bore down on a 16 topic that Commissioner Apostolakis broached in his questioning. Mr. Swafford, 17 that goes to Slide 7. Im really struck, I mean, thinking about this -- your slide, 18 and I appreciate the openness of it. It says long-standing culture of taking a 19 minimalist approach to problems that adversely affect equipment reliability. And 20 were all creatures of our own experiences and Im just struck by my experience 21 in the nuclear Navy. Twenty-five years ago when I was engineering an old 22 Westinghouse attack submarine, I had a very similar problem to a separated 23 stem disk assembly and a reactor plant valve. I wont go into details. Those 24 remain classified. But Im struck by the material issue here but also the broader 25 implications of your statements.
68 1 So Im going to shift away a little bit from this particular LPCI valve 2 and talk more about the overall history of the equipment reliability and 3 maintenance practices that Unit 1 or across the entire TVA fleet. And when I go 4 back to the slide, theres a long-standing culture, I have to say, well, whose 5 responsibility is it. At what level of the organization have decisions been made to 6 not properly maintain or perhaps to -- you know, you acknowledged I think Rick 7 Croteaus comment about broke-fixed, but at some level in the organization, 8 irrespective of how well your program is set up on paper or what kind of 9 resources you provide, its the execution of that program in day-to-day operations 10 or during an outage, its the execution on the deck plates that really drives the 11 equipment status of your plant.
12 So can you comment a little bit about, you know, where in the 13 organization is the culpable group or line of management or line of operators or 14 an engineering QA, site VP, I dont know. Id be interested in your perspective 15 because to me, thats a -- you made a very interesting statement here on Slide 7.
16 PRESTON SWAFFORD: Well, I -- you know, Ill just tell you that it 17 almost always starts at the top. I mean, people emulate their bosses, and you 18 cant necessarily get to that point in three months, but enough time, people will 19 emulate their bosses. They will do what they think their boss needs done. So 20 when you are bypassing excellent equipment reliability standards as terms of 21 how do we get it fixed and keep the plant up at 100 percent power or how do we 22 do whatever, people will read that and then theyll multiply it times 10, so to 23 speak, and that if I -- if the plant was ever denied an activity, we have several 24 components. For example, I mentioned some of these pumps, weve got to 25 procure, some weve already done.
69 1 But its more than that. We had traveling screens for example that 2 we send divers down and fix, right. But today the leadership is -- were tired of 3 that, right. We need to do whole hog, pull the whole screen modules out, try to 4 replace them. So it starts, I think, with the top and that they have to read from 5 me is that weve going to take the hit on this is not about just getting by anymore.
6 We have to fix it and fix it right. And then you put in place people like Don 7 Jernigan and Keith Polson who have completely signed up for that model. Now 8 these plants have been allowed in certain cases to decay. I mean, theres a lot 9 of focus on starting up Unit 1, maybe not as much focus on Unit 2 and 3. Three 10 units by themselves are a unique beast in themselves and takes a lot of extra 11 leadership, attention, and organizational strength to get through it all. But its 12 also a powerful organization that once it turns the ship and starts moving forward, 13 they can probably accelerate that recovery from that culture.
14 So it starts with the top planting a very clear picture. Were going to 15 have central governance. Were going to have the best standards. Were going 16 to have check and balance organizations in place. We have the key metrics, and 17 then were going to fully fund and staff. And then from there, were going to look 18 at performance, check and adjust as we go forward. And eventually, the culture 19 will revive to that of this is the new standard, this is what they mean, and this is 20 what we expect to have happen. So were a little bit of trust me. Were kind of 21 early in it so I cant tell you weve arrived, but I do think the foundational things 22 that have been put in place the last few years are starting to see signs.
23 Ill give you one other little tidbit of this strength of the governance 24 model, and there have been several at the station. But the one most notably is 25 these two recirc pump motors I mentioned that were seven years past their O&M
70 1 minimal. Now, maybe they would have lasted longer. I dont know. But they 2 were scheduled, and the engineering staff wanted them changed out, and the 3 site ended up, for whatever reason, deciding they wanted to defer them. But the 4 governance model went down to the corporate VP of engineering, he came in my 5 office and he says, Thats unacceptable. We cannot go another outage without 6 changing those motors and getting them back in interval. So we changed them 7 out.
8 But we also are blessed with the power service shop in Muscle 9 Shoals, Alabama that does detailed motor overhauls including recirc pump motor 10 site overhauls. And they tore that -- one of the two down for us and found that it 11 was imminent failure, right. So those standards resonating through the whole 12 site that theres a new sheriff in town and that were not going to live with and 13 tolerate these types of material condition issues has been a big boost for us.
14 COMMISSIONER OSTENDORFF: Now, let me stop you because I 15 want to make sure because you say top, I want to clarify that. Is the top the 16 CNO, is the top the site VP, is the top engineering? Does it depend upon the 17 issue? Im trying to understand what autonomy does the site have as far as 18 making a decision to defer maintenance or not. Or is this a decision thats kicked 19 up to corporate?
20 PRESTON SWAFFORD: The site can choose to do that, and they 21 have a rigorous process that they go through. But from time to time, they may 22 not make the right call, but we, for example, have a corporate outage planning 23 challenge meeting, for example. And my engineer and his staff from corporate 24 come in and they talk about all material thats in the outage and all the material 25 equipment issues that they have moved out of the outage. And so, we do a
71 1 detailed list of any work order thats not in the outage and what was their 2 rationale for choosing to push it out. So it is a barrier that we have put in place in 3 the last two years to actually look at this to help the site make the overall right 4 call. Because theres pressures on them, even though we supported them 5 adequately with resources, theres no such thing as unlimited money. So you still 6 have to prioritize. And if they end up making the decision that isnt in the best 7 interest of TVA, I feel good that weve kind of now have a plan --
8 COMMISSIONER OSTENDORFF: Im going to cut you off there. I 9 want to go to another question. I want to ask this question to Mr. Polson. I just 10 couldnt help this because of time considerations here. I want to talk about 11 monitoring of maintenance to ensure proper maintenance procedures are 12 followed quality assurance practices, proper materials certification of materials 13 that are used. Lets say youre repairing a valve or youre swapping out a circuit 14 breaker or replacing a seal ring on a pump. Can you talk a little about what 15 happens at your site with respect to ensuring that maintenance is monitored by 16 management or by other -- whether it be by your site management or by 17 corporate?
18 KEITH POLSON: Yeah, well, theres several different things that 19 we have. First of all, we have a quality assurance program. And depending on 20 which equipment youre working on, that dictates --
21 COMMISSIONER OSTENDORFF: Oh, let me refrain this real 22 quick because I have limited time. Im only talking about maintenance monitoring 23 by people who are not directly responsible. You know, usually you have a 24 worker person and then -- Im using my Navy experience -- and then a quality 25 insurance inspector. So people who are not directly responsible for doing the
72 1 work but I use the phrase command monitoring, or leadership monitoring, 2 however you want to look at it from TVAs perspective. Im interested in how do 3 you -- how do you understand as a leader of the organization that your 4 maintenance is being conducted properly?
5 KEITH POLSON: So, we have an observation program. Were 6 required to do four observations per month. And thats senior managers all the 7 way down to first-line supervisors. And then what weve also implemented over 8 about the past year and a half, we call it a day in the plant where Im required to 9 take a whole day where Id put on jeans and I go out in the plant, and theres 10 specific maintenance activities that I monitor that whole day. And then the next 11 day when we have -- we have what we call a Plant of the Day Meeting. Its a 12 senior leadership meeting. And then theres a report-out. So myself, my direct 13 reports, plant manager, direct reports all participate in that program. And thats 14 on a daily basis that we do that.
15 COMMISSIONER OSTENDORFF: Okay. And then how about the 16 corporate side now, Mr. Swafford, in the analogous-type process that you guys 17 have to kind of take the pulse of how maintenance is being performed or -- go 18 ahead.
19 ROBERT WHALEN: We now have corporate component 20 engineers in the corporate liability department. If there is a plant issue with a 21 pump, we have a pump component engineer. He gets dispatched to go be 22 hands in the field and make sure the right parts are being used, are we digging 23 into it deeply enough, similar turbine-type activities -- AOVs, MOVs, to be more 24 rigorous on troubleshooting, root cause, corrective action in the field.
25 PRESTON SWAFFORD: An example that I think is pretty powerful
73 1 here is we did put a pump, a rotating equipment component player in corporate.
2 And I believe he was instrumental in our HPSI system that was mentioned by the 3 group before us, Victors team, is that we still had some safety system 4 performance issues and weve been gaining on them, but the HPSI has been an 5 issue that weve struggled with at the site for quite some time. During the startup 6 with Unit 1, the craft, if you will, put a bearing in backwards, one-half of a bearing 7 in backwards, and the plant -- and the HPSI system has run. Its always been a 8 little bit in the alert, but with the addition of this new component engineer looking 9 at that pump performance, said somethings not right, went down to the station 10 and asked the site vice president to take it out of service because we just needed 11 to find out what was going on. And they discovered that there was an original 12 installation issue wrong with it. So thats one of some of the checks and 13 balances, but its also real-time engagement with the site and specific component 14 competency.
15 COMMISSIONER OSTENDORFF: Thank you. Thank you, Mr.
16 Chairman.
17 CHAIRMAN JACZKO: Just one comment Ill make and then I did 18 just have a question, but this issue, and I dont mean to belabor this point on the 19 risk significance. But TVA did make a comment that they believed that the risk 20 would be "Green". The staff did do a detailed analysis, and I know maybe, again, 21 at the technical level there may be disagreements, but the staff -- the conclusion 22 of the staff in the final notification on the "Red" finding did indicate that even if 23 they took into consideration the operators taking action, theyd modeled that 24 through -- well, they did sensitivity analysis, and sensitivity analysis showed that 25 the overall risk would be reduced by a factor of eight. And this is not a sufficient
74 1 enough reduction to have changed the significance of the finding.
2 In addition, they looked at control building fire scenario which had 3 not been evaluated in these -- the phase 3 risk models to get to the phase 3 after 4 they do the initial screening. And that based on that, that the using this risk 5 contributor which was not even in the original -- that would add an additional five 6 times 10 to the minus five to the overall risk impact to the valve failure. So, their 7 conclusion is based on our review and the aforementioned factors are 8 considered either collectively or individually. And those are including the control 9 building fire scenario risk and the potential for operation action to use alternate 10 cooling methods. The lower bound of risk for the valve performance deficiency 11 remained greater than one times ten to the minus four.
12 So, again, I appreciate that your position was that it was "Green",
13 but the factors that you had considered as mitigating the staff did analyze, and 14 based on the staffs analysis, it did not change the outcome nonetheless of the 15 findings. So, that was actually, as I was visiting the facility, was something that 16 was of significance to me, you know, as I recalled that. So, and I mean, this, 17 regardless, I think, was a significant event regardless of how what non-18 proceduralized actions were taken that we still would have seen something, at 19 least according to the staffs analysis, above the "Red" or at a "Red" finding.
20 The one question I wanted to ask, you know, weve talked a lot 21 about -- and there have been some good questions from my colleagues about, 22 you know, how youre managing this activity, how are you doing all this -- but one 23 of the things we havent touched on is all the things unrelated to addressing the 24 deficiencies that lead to the valve failure. For instance, theres activities with the 25 power uprates ongoing. I believe we may have finished our reviews on those.
75 1 Im not sure where we are. Im looking for somebody who might know. But I 2 believe at least for one of the units, weve completed our assessment. Have you 3 given any thought to postponing those activities, any mods or that you would 4 need to make in the plant pending kind of the get well program showing some 5 signs of progress? Or will you kind of continue with those activities as well?
6 Whats your plan for that?
7 PRESTON SWAFFORD: Two points is like the EPU is an 8 example. One of the things that Bill had mentioned on his opening remarks is 9 how we were organized and that from the beginning that it was recognized that 10 we had a lot of work to do for our fleet, specifically Browns Ferry. So major 11 projects like the EPU project was taken off of my plate and given to a counterpart 12 of mine who also is responsible for the construction of Watts Bar 2 and the steam 13 generator replacement thats coming up on Sequoyah. So these are very large 14 projects that could be very large distracters to me and have been afforded the 15 staff, if you will, to take that off, and they report directly to Bill. So the EPU is one 16 that I believe, for the most part, were on hold until the regulatory framework is 17 well enough understood so that we dont waste the energy, if you will, especially 18 the distraction to Keith and his team until that road is really cleared. But maybe 19 Bill?
20 BILL MCCOLLUM: Well, and we make a specific decision too, 21 because there were obviously regulatory issues in the timeline of the EPU was 22 uncertain. We made a decision to essentially break apart two aspects of that.
23 One is regulatory approval of an extended power uprate. The other was all the 24 equipment work that would be associated with an uprate, and we decided that it 25 made sense to proceed with the equipment work at Browns Ferry because it
76 1 helped us to deal with some of the issues that we talked about earlier, upgrading 2 pumps, upgrading equipment, gaining more margin on the secondary side of the 3 plant or the balance of the plant, that sort of -- so that seemed to be beneficial to 4 Browns Ferry in terms of dealing with equipment margin, plant operation; and we 5 funded and proceeded on with that work, independent of the licensing work to 6 raise the license power level. And so that effort is basically on hold until we do 7 more work to improve performance at Browns Ferry.
8 CHAIRMAN JACZKO: Well, yeah, and I appreciate that. And that 9 was really more my issue. You know, obviously -- well, you can separate the 10 licensing perhaps. You cant separate the plant, so to speak, and those 11 equipment changes and modifications if they werent necessarily having a direct 12 safety impact could be a distraction to maintenance, could be a distraction to 13 operators as they deal with those different issues. So, its good to hear that that 14 is a bit on hold then until some of these issues get resolved. I think that seems to 15 be a decision in the best interest of safety, so.
16 Again, I appreciate your presentations. Victor and his team, I think, 17 have done a good job of communicating to you all what our expectations are.
18 They obviously have the primary lead in working to get our kind of inspection and 19 our assessment in a place where we can give you good information and theyll 20 continue to do that as we go forward with their continued 95003. You know, I 21 certainly encourage you to work expeditiously to resolve those issues and to 22 ultimately let us wrap up that in an affirmative way. So, I know theyll continue to 23 ask all the right questions and tell you what you need to hear. And I think as long 24 as everyones committed to the same goal, which is a safer operation at Browns 25 Ferry, I think well get there. So, thank you very much for being here.
77 1 [Whereupon, the proceedings were concluded]