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{{Adams
{{Adams
| number = ML080320562
| number = ML081230561
| issue date = 02/01/2008
| issue date = 04/30/2008
| title = IR 05000528-07-012, 05000529-07-012, 05000530-07-012; 04/03/07 - 12/19/07; Palo Verde Nuclear Generating Station, Units 1, 2, and 3; Inspection Procedure 95003, Supplemental Inspection for Repetitive Degraded Cornerstones, Multiple Degraded
| title = IR 05000528-07-012, 05000529-07-012, and 05000530-07-012, Palo Verde Nuclear Generating Station, Units 1, 2, and 3, Final Significance Determination for a Preliminary White Finding
| author name = Collins E E
| author name = Caniano R
| author affiliation = NRC/RGN-IV/ORA
| author affiliation = NRC/RGN-IV/DRS
| addressee name = Edington R K
| addressee name = Edington R
| addressee affiliation = Arizona Public Service Co
| addressee affiliation = Arizona Public Service Co
| docket = 05000528, 05000529, 05000530
| docket = 05000528, 05000529, 05000530
| license number = NPF-041, NPF-051, NPF-074
| license number = NPF-041, NPF-051, NPF-074
| contact person =  
| contact person =  
| case reference number = EA-08-003
| document report number = IR-07-012
| document report number = IR-07-012
| document type = Letter
| document type = Letter
| page count = 162
| page count = 6
}}
}}


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=Text=
=Text=
{{#Wiki_filter:
{{#Wiki_filter:April 30, 2008
[[Issue date::February 1, 2008]]


Randall K. Edington, Executive Vice President Nuclear
==SUBJECT:==
 
PALO VERDE NUCLEAR GENERATING STATION, UNITS 1, 2, AND 3 - NRC INSPECTION REPORT 05000528/2007012, 05000529/2007012, AND 05000530/2007012, FINAL SIGNIFICANCE DETERMINATION FOR A PRELIMINARY WHITE FINDING
and Chief Nuclear Officer
 
Arizona Public Service Company P.O. Box 52034 Phoenix, AZ 85072-2034
 
SUBJECT: PALO VERDE NUCLEAR GENERATING STATION - NRC SUPPLEMENTAL 95003 INSPECTION REPORT 05000528/2007012, 05000529/2007012, AND  
 
05000530/2007012


==Dear Mr. Edington:==
==Dear Mr. Edington:==
On December 19, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palo Verde Nuclear Generating Station (PVNGS), Units 1, 2, and 3, facility. The inspection
The purpose of this letter is to provide you the final results of our significance determination of the preliminary White finding identified in the subject inspection report (ADAMS accession number ML080320562) and by letter dated February 1, 2008 (ADAMS accession number ML080320590). The inspection finding was preliminarily characterized as White (i.e., a finding with low to moderate increased importance to safety that may require additional U. S.
 
was conducted in accordance with the guidance contained in NRC Inspection Manual Chapter (IMC) 0305, "Operating Reactor Assessment Program" and Inspection Procedure (IP) 95003,
"Supplemental Inspection for Repetitive Degraded Cornerstones, Multiple Degraded Cornerstones, Multiple Yellow Inputs, or One Red Input," and was performed in response to your facility's designation as having a Repetitive Degraded Cornerstone, as defined by the NRC's reactor oversight process. The enclosed report documents the inspection findings, which were discussed on December 19, 2007, with you and other members of your staff.
 
In our Annual Assessment Letter dated March 2, 2007, we informed you that PVNGS Unit 3 was
 
placed in the Multiple/Repetitive Degraded Cornerstone Column (Column IV) of the NRC's Action Matrix. In accordance with IMC 0305, this decision was made on the basis of two separate safety significant inspection findings (one Yellow and one White) in the Mitigating Systems cornerstone. The Yellow finding, open since the fourth quarter 2004, involved a significant section of containment sump safety injection piping that was void of water at all three PVNGS units. The White finding, open since the fourth quarter 2006, involved two failures of the Unit 3, Train A emergency diesel generator. This inspection evaluated the extent of condition of the performance issues, and the
 
adequacy of the safety culture at PVNGS.
 
The results of our inspection indicate that your facility is being operated safely. However, the team identified numerous performance deficiencies that were additional examples of the organizational and programmatic weaknesses that the NRC had previously identified. Despite previous attempts, PVNGS had been unsuccessful in implementing changes that result in sustained improvement in safety system reliability, human performance, problem identification and resolution, the quality of engineering work products, and oversight of station activities by operations personnel. The inspection and recent PVNGS safety culture self-assessment activities also identified degradations in the safety culture of the facility. The team identified weaknesses in organizational characteristics
 
and attitudes associated with ten of the NRC's thirteen safety culture components. The Arizona Public Service Company weaknesses were apparent across several functional groups at the site. This is of concern because it indicates that, as an overriding priority, nuclear plant safety issues had not always received the attention warranted by their significance.


The team validated that the root and contributing causes for the performance deficiencies at Palo Verde included: (1) leaders did not establish, communicate, and enforce standards and expectations for performance or hold individuals accountable to those standards; (2) the corrective action program, operating experience, self assessments, and benchmarking did not drive individual and station performance improvement; (3) responsibility, accountability, and authority for nuclear safety were not well defined or understood; (4) individual behaviors that demonstrate nuclear safety principles were not consistently applied; (5) management was not receptive to organizational issues identified during investigations; (6) change management activities did not anticipate unintended consequences and did not clearly define and communicate changes to station personnel; and (7) oversight groups did not provide specific and meaningful interventions to correct declining
Nuclear Regulatory Commission (NRC) inspections) using Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process. This preliminary White finding, and associated apparent violation of NRC requirements, involved the failure of the Palo Verde Nuclear Generating Station personnel to correct an identified weakness in the performance of senior reactor operators. Specifically, when evaluated during training evolutions beginning in May 2007, a high percentage of senior operators incorrectly classified a general emergency for simulated plant conditions that required a site area emergency declaration, and corrective actions were not completed until October 2007.


performance.
At your request, a Regulatory Conference was held on March 25, 2008, to further discuss your views on this issue. A copy of the presentation you provided at this meeting is attached to the Regulatory Conference Meeting Summary dated April 10, 2008 (ADAMS accession number ML081020348). During the meeting, your staff described your assessment of the significance of the findings and detailed corrective actions to address the failure to correct the weakness in senior reactor operator performance. Specifically,


As stated in the June 21, 2007, Confirmatory Ac tion Letter, and subsequently revised with NRC approval by your letter dated November 28, 2007, you submitted an improvement plan to the NRC
UNITED STATES NUCLEAR REGULATORY COMMISSION R E GI ON I V 611 RYAN PLAZA DRIV E, SUITE 400 ARLINGTON, TEXAS 76011-4005


on December 31, 2007. Following the NRC's review of the plan, we will issue a revised Confirmatory Action Letter including the minimum actions believed necessary to improve performance and sustain performance improvement. The NRC will also conduct periodic performance improvement public meetings and inspections until PVNGS demonstrates sustained performance improvement.
Arizona Public Service Company
- 2 -
*
You agreed that beginning on May 2, 2007, Palo Verde Nuclear Generating Station personnel identified a knowledge deficiency among senior operators regarding their evaluation of the reactor coolant fission product barrier and knowledge of the definition of prolonged release, that the station corrective action program was not effectively used when the knowledge deficiency was identified, and that the knowledge deficiency was not corrected until October 25, 2007.
* You discussed your analysis of the job performance measure that identified the knowledge deficiency, and concluded that the job performance measure was incomplete and technically flawed.
* You discussed your view that the failure by Palo Verde Nuclear Generating Station personnel to promptly correct the identified knowledge deficiency had very low safety significance because the knowledge deficiency could not result in an incorrect emergency classification during an actual plant event involving a steam generator tube rupture and use of the atmospheric dump valves for reactor coolant temperature control.
* You discussed corrective actions that included requiring the operations training department to enter errors discovered in operator examination materials and operator failures on examinations and job performance measures into the corrective action program, initiating routine trending of weaknesses in operator performance during training, and requiring the concurrence of the emergency preparedness department on examinations and job performance measures used to test operator knowledge of emergency preparedness topics.
* Following the conference you provided additional information (ADAMS accession number ML081130231), in response to our request, describing the simulator scenarios that formed the basis for your determination that the knowledge deficiency could not result in an incorrect classification during a steam generator tube rupture event.


The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your licenses.
After considering the information you provided during and following the conference, the NRC has concluded that the knowledge deficiency identified among senior operators would not likely result in an incorrect emergency classification during a steam generator tube rupture event.


The team reviewed selected procedures and records, observed activities, and interviewed personnel. A listing of the documents requested by the team for review during the inspection is available electronically in the NRC's document system (ADAMS) as ML080250295.
Specifically, the NRC concluded that, given the identified knowledge weakness, an incorrect classification of a steam generator tube rupture event with atmospheric dump valves in operation can only occur with a concurrent potential loss of the fuel clad barrier, and that under these conditions all credible scenarios resulting in potential losses of the fuel clad barrier also cause loss of the reactor coolant barrier. The combination of a potential loss of the fuel clad barrier, loss of reactor coolant barrier, and the loss of containment barrier which results from operating the atmospheric dump valves, results in a general emergency condition, irrespective of the operators knowledge of whether a prolonged release is occurring. The NRC has determined your analysis of steam generator tube rupture events reasonably bounds the possible scenarios leading to a potential loss of the fuel clad barrier.


The report documents numerous performance deficiencies resulting in 18 NRC identified findings. The findings represent performance deficiencies in all 7 inspection cornerstones and 10 of the 13 safety culture components. Sixteen of these findings were evaluated under the significance determination process as having very low safety significance (Green). One finding involving the failure to update the Final Safety Analysis Report impacted the regulatory process and was assessed in accordance with the NRC Enforcement Policy. Because of the very low safety significance of these violations and because they were entered into your corrective action program, the NRC is treating these findings as noncited violations consistent with Section VI.A of the NRC Enforcement Policy. The significance of one finding (failure to implement corrective actions for a risk significant planning standard in the emergency preparedness cornerstone) is being separately evaluated by the NRC. Additionally, licensee-identified violations which were determined to be of very low safety significance are listed in this report. If you contest these noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for
Arizona Public Service Company
- 3 -  


your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Arizona Public Service Company Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at the Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility.
Because the identified knowledge deficiency among senior operators would not likely result in an incorrect emergency classification during an actual plant event, the NRC has concluded the significance of the inspection finding is appropriately characterized as Green (i.e., a finding of very low safety significance).


In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
The NRC has also determined the failure to correct an identified weakness in emergency preparedness performance with a promptness appropriate to its risk significance is a violation of 10 CFR 50.54(q) and 10 CFR Part 50, Appendix E, IV(F)(2)(g). The circumstances surrounding the violation are described in detail in the subject inspection report. This violation is being treated as a Non-Cited Violation (NCV), consistent with Section VI of the NRC Enforcement Policy. Therefore, no response to this letter is necessary. However, if you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this letter, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-001, with copies to; (1) the Regional Administrator, Region IV; (2) the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; and (3) the NRC Resident Inspector at Palo Verde.


Sincerely,/RA/
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosures, and your response, if you choose to provide one, will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be made available to the Public without redaction.
Elmo E. Collins Regional Administrator Dockets: 50-528 50-529 50-530


Licenses: NPF-41 NPF-51 NPF-74
Sincerely,
/RA/


===Enclosure:===
Roy Caniano, Director
NRC Inspection Report 05000528/2007012, 05000529/2007012, and 05000530/2007012


===w/Attachment:===
Division of Reactor Safety
Supplemental Information cc w/


===Enclosure:===
Dockets: 50-528; 50-529; 50-530 Licenses: NPF-41; NPF-51; NPF-74
Steve Olea


Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 Douglas K. Porter, Senior Counsel
cc:
Steve Olea Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007  


Southern California Edison Company Law Department, Generation Resources P.O. Box 800 Rosemead, CA 91770 Chairman Maricopa County Board of Supervisors 301 W. Jefferson, 10th Floor Phoenix, AZ 85003
Arizona Public Service Company  
- 4 -


Arizona Public Service Company Aubrey V. Godwin, Director Arizona Radiation Regulatory Agency 4814 South 40 Street Phoenix, AZ 85040
Douglas K. Porter, Senior Counsel Southern California Edison Company Law Department, Generation Resources P.O. Box 800 Rosemead, CA 91770


Scott Bauer, Director
Chairman Maricopa County Board of Supervisors 301 W. Jefferson, 10th Floor Phoenix, AZ 85003


Regulatory Affairs Palo Verde Nuclear Generating Station Mail Station 7636 P.O. Box 52034 Phoenix, AZ 85072-2034
Aubrey V. Godwin, Director Arizona Radiation Regulatory Agency 4814 South 40 Street Phoenix, AZ 85040


Mr. Dwight C. Mims Vice President, Regulatory Affairs and Performance Improvement
Scott Bauer, Director Regulatory Affairs Palo Verde Nuclear Generating Station Mail Station 7636 P.O. Box 52034 Phoenix, AZ 85072-2034


Palo Verde Nuclear Generating Station  
Mr. Dwight C. Mims Vice President, Regulatory Affairs and Performance Improvement Palo Verde Nuclear Generating Station Mail Station 7605 P.O. Box 52034 Phoenix, AZ 85072-2034


Mail Station 7636 P.O. Box 52034 Phoenix, AZ 85072-2034
Jeffrey T. Weikert Assistant General Counsel El Paso Electric Company Mail Location 167 123 W. Mills El Paso, TX 79901


Jeffrey T. Weikert Assistant General Counsel
Eric J. Tharp Los Angeles Department of Water & Power Southern California Public Power Authority P.O. Box 51111, Room 1255-C Los Angeles, CA 90051-0100


El Paso Electric Company Mail Location 167 123 W. Mills El Paso, TX 79901
Arizona Public Service Company  
- 5 -


Eric J. Tharp Director of Generation Los Angeles Department of Water & Power Southern California Public Power Authority P.O. Box 51111, Room 1255 Los Angeles, CA 90051-5700 John Taylor Public Service Company of New Mexico 2401 Aztec NE, MS Z110 Albuquerque, NM 87107-4224  
James Ray Public Service Company of New Mexico 2401 Aztec NE, MS Z110 Albuquerque, NM 87107-4224  


Geoffrey M. Cook Southern California Edison Company 5000 Pacific Coast Hwy, Bldg. D21 San Clemente, CA 92672  
Geoffrey M. Cook Southern California Edison Company 5000 Pacific Coast Hwy, Bldg. D21 San Clemente, CA 92672  
Line 105: Line 93:
Robert Henry Salt River Project 6504 East Thomas Road Scottsdale, AZ 85251  
Robert Henry Salt River Project 6504 East Thomas Road Scottsdale, AZ 85251  


Arizona Public Service Company Brian Almon Public Utility Commission William B. Travis Building P.O. Box 13326  
Brian Almon Public Utility Commission William B. Travis Building P.O. Box 13326 1701 North Congress Avenue Austin, TX 78701-3326  
 
1701 North Congress Avenue Austin, TX 78701-3326  


Karen O' Regan Environmental Program Manager City of Phoenix Office of Environmental Programs 200 West Washington Street Phoenix, AZ 85003  
Karen O' Regan Environmental Program Manager City of Phoenix Office of Environmental Programs 200 West Washington Street Phoenix, AZ 85003  


Matthew Benac Assistant Vice President  
Matthew Benac Assistant Vice President Nuclear & Generation Services El Paso Electric Company 340 East Palm Lane, Suite 310 Phoenix, AZ 85004  
 
Nuclear & Generation Services El Paso Electric Company 340 East Palm Lane, Suite 310 Phoenix, AZ 85004  
 
Chief, Radiological Emergency Preparedness Section National Preparedness Directorate Technological Hazards Division Department of Homeland Security 1111 Broadway, Suite 1200
 
Oakland, CA 94607-4052
 
Arizona Public Service Company Electronic distribution by RIV:
Regional Administrator (EEC) DRP Director (DDC) DRS Director (RJC1) DRS Deputy Director (ACC) Senior Resident Inspector (GXW2) Branch Chief, DRP/D (TWP)
Senior Project Engineer, DRP/D (GEW) Team Leader, DRP/TSS (CJP) RITS Coordinator (MSH3) DRS STA (DAP) V. Dricks, PAO (VLD) D. Pelton, OEDO RIV Coordinator (DLP1) ROPreports PV Site Secretary (PRC)
 
SUNSI Review Completed:
TWP ADAMS: X Yes No Initials:
TWP X Publicly Available Non-Publicly Available Sensitive X Non-Sensitive
 
R:\_REACTORS\_PV\2007\PV2007-012RP-TWP.doc RI:SRA RIV:RI RIII:RE RI:SRI RII:SHP RIII:RI CGCahill MPCatts BJose SMSchneider HJGepford RLSmith E-TWP /RA/ E-TWP /RA/
E-TWP /RA/E-TWP /RA/ E-TWP /RA/ E-TWP /RA/
12/26/07 12/19/07 12/20/07 12/19/07 01/03/08 12/20/07 RIII:RI RIV:SRI RIV:SRI RII:SRI RIII:PE RIV:RE MAWilk JFDrake SDCochrum SAWalker ARBarker MRBloodgood E-TWP /RA/ E-TWP /RA/
E-TWP /RA/E-TWP /RA/ E-TWP /RA/ E-TWP /RA/
12/18/07 01/07/08 12/20/07 12/19/07 12/21/07 12/26/07 NRR:SHFA RI:OE NRR:HFS OE:ES NRR:SHFA RIV:SRI VBarnes BCHaagensen MJKeefe JCai DRDesaulniers CCOsterholtz E-TWP /RA/ E-TWP /RA/
E-TWP /RA/E-TWP /RA/ E-TWP /RA/ E-TWP /RA/
12/24/07 12/27/07 12/20/07 12/20/07 01/04/08 12/24/07 RIV:EPI:DRS NSIR NSIR RIV:SPE:DRP/D RIV:C:DRP/D RIV:DD:DRP PJElkmann REKahler KWilliams GEWerner TWPruett AVegel E-TWP /RA/ E-TWP /RA/
T-TWP /RA/E-TWP /RA/
/RA/ /RA/ 01/09/08 01/09/08 01/09/08 12/26/07 01/25/08 01/26/08 RIV:D:DRP RIV:RA DDChamberlain EECollins
/RA/ /RA/ 01/25/08 02/01/08 OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax U.S. NUCLEAR REGULATORY COMMISSION REGION IV Dockets: 50-528, 50-529, 50-530 Licenses:
NPF-41, NPF-51, NPF-74 Report: 05000528/2007012, 05000529/2007012, 05000530/2007012 Licensee:
Arizona Public Service Company Facility: Palo Verde Nuclear Generating Station, Units 1, 2, and 3 Location:
5951 S. Wintersburg Road Tonopah, Arizona Dates: April 3 through December 19, 2007 Team Members: T. Pruett, IP 95003 Team Leader; Chief, Project Branch D Division of Reactor Projects, Region IV G. Werner, IP 95003 Assistant Team Leader; Senior Project Engineer, Region IV S. Gillum, Secretary, Region IV Substantive Crosscutting Issues Group M. Schneider, IP 95003 Group Leader; Senior Resident Inspector, Region I H. Gepford, Senior Health Physicist, Region II M. Wilk, Resident Inspector, Region III R. Smith, Resident Inspector, Region III J. Drake, Senior Reactor Inspector, Region IV R. Kahler, Team Leader, Office of Nuclear Security and Incident
 
Response P. Elkmann, Emergency Preparedness Inspector, Region IV
 
Maintenance and Testing Group S. Cochrum, IP 95003 Group Leader; Senior Resident Inspector,
 
Region IV A. Barker, Project Engineer, Region III S. Walker, Senior Reactor Inspector, Region II
 
M. Bloodgood, Reactor Engineer, Region IV
 
Engineering Group C. Cahill, IP 95003 Group Leader; Senior Reactor Analyst, Region I B. Jose, Reactor Engineer, Region III M. Catts, Resident Inspector, Region IV M. Villaran, Brookhaven National Laboratory, Contractor
 
Enclosure - 1 -
Safety Culture Group V. Barnes, IP 95003 Group Leader; Senior Human Factors Analyst, Office of Nuclear Regulatory Research V. Mehrhoff, Secretary, Las Vegas Site Office J. Cai, Enforcement Specialist, Office of Enforcement M. Keefe, Human Factors Specialist, Office of New Reactors C. Osterholtz, Senior Resident Inspector, Region IV B. Haagensen, Operations Engineer, Region I Accompanied By: D. Desaulniers, Senior Human Factors Specialist, Office of Nuclear Reactor Regulation K. Martin, Human Factors Engineer, Office of Nuclear Reactor Regulation M. Barrientos, Nuclear Safety Council, Spain Approved By: Dwight Chamberlain, Director Division of Reactor Projects Enclosure - 2 -
 
=SUMMARY OF FINDINGS=
IR 05000528/2007012, 05000529/2007012, 05000530/2007012; 04/03/07 - 12/19/07; Palo Verde Nuclear Generating Station, Units 1, 2, and 3; Inspection Procedure 95003,
 
"Supplemental Inspection for Repetitive Degraded Cornerstones, Multiple Degraded Cornerstones, Multiple Yellow Inputs, or One Red Input."
 
This report covered a 9-month period of inspection by personnel in all four NRC Regional Offices and from Headquarters, one contractor, and an observer from the Spanish Nuclear Safety Council. The inspection identified numerous performance deficiencies that resulted in 15 noncited violations, 1 finding, 1 Severity Level IV violation, and 1 apparent violation with significance to be determined. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination Process."  Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management's review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.
 
Initiating Events
: '''Green.'''
The team identified a noncited violation of Technical Specification 5.4.1.d for the failure of fire protection personnel to follow Procedure 14DP-0FP33, "Control of Transient Combustibles," Revision 15. Specifically, the team identified that on the 70' elevation of the Auxiliary Building (Radiation Protection Remote Monitoring Station) and in the Unit 3 containment, there were transient combustibles being stored without the proper evaluation and required permits. This issue was entered into the corrective action program as Palo Verde Action Request 3071785.
 
The finding is considered more than minor because storing unanalyzed material could result in the potential to exceed combustible limits and is associated with an increase in the likelihood of an initiating event. Using Inspection Manual Chapter 0609, "Significance Determination Process," Appendix F, "Fire Protection Significance Determination Process," this issue affected the Fire Prevention and Administrative Controls Category. In this case the stored materials required a permit per the licensee's procedure; however, the area was attended, fire detection and suppression was available, and the amounts did not exceed the loading calculation to the point of changing the loading classification. Therefore, this finding is considered of Low Degradation and had very low safety significance. The cause of this finding has crosscutting aspects associated with work practices in the human performance area because:  (1) the licensee failed to communicate human error prevention techniques such that work activities were performed safely (H.4.(a)), and (2) the licensee did not effectively communicate expectations regarding procedural compliance (H.4.(b)). The cause of this finding is also related to the safety culture component of accountability in that fire protection personnel failed to demonstrate a proper safety focus and reinforce safety principles among their peers (O.1.(c)).  (Section 5.6.2.b.1)
: '''Green.'''
The team identified a noncited violation of 10 CFR 50.65(a)(4) for the failure to adequately assess the increase in risk and effectively implement risk mitigation actions for maintenance activities in the switchyard. Specifically, the switchyard was not being protected by controlling access and movement as required and the risk modeling did not include all work being performed. The Unit 1 shift manager and the switchyard coordinator were unaware of the movement of multiple vehicles and pieces of equipment in or near restricted areas and not all maintenance was included in the schedule provided to the switchyard coordinator for risk review. This issue was entered into the licensee's corrective action program as Palo Verde Action Request 3078392.
 
This finding is greater than minor because the licensee's risk assessment failed to consider maintenance activities that could increase the likelihood of initiating events such as work in the switchyard and failed to effectively manage compensatory measures. Inspection Manual Chapter 0609, "Significance Determination Process," Appendix K, "Maintenance Risk Assessment and Risk Management Significance Determination Process," was used to assess the significance. Using data from the licensee's probabilistic risk assessment, a NRC Region IV senior reactor analyst calculated the risk deficit. Based on the magnitude of the calculated risk deficit being less than 1E-6/year, this finding is determined to be of very low safety significance. The cause of this finding has crosscutting aspects associated with work control of the human performance area in that the licensee did not appropriately coordinate switchyard activities incorporating risk insights (H.3.(a)) and did not communicate with each other during activities in which coordination is necessary to assure plant and human performance (H.3.(b)).  (Section 5.6.3.b.1)
Mitigating Systems
: '''Green.'''
The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," with eight examples for the failure of the licensee to adequately evaluate degraded and unanalyzed conditions to support operability decision making between May 2006 and October 26, 2007. The team noted a significant number of weak or non-existent operability evaluations of degraded conditions affecting safety-related equipment. There was a lack of understanding of the need to assess operability for some conditions adverse to quality and a lack of k nowledge or skills necessary to conduct quality operability assessments. The examples of the violation involved two instances of conditions adverse to quality documented in databases outside of the corrective action program, missile hazards near the essential spray pond, two issues effecting essential cooling water system heat exchangers, 480V and 4160V motor terminations, oil leaks on the emergency diesel generators, and high lead content in a Unit 3 low pressure safety injection pump.
 
Each of the individual technical issues was entered into the licensee's corrective action program.
 
The examples associated with this finding are greater than minor because they were associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the examples associated with this finding are determined to have very low safety significance since they only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The causes of the examples of this finding have crosscutting aspects associated with decision making of the human performance area in that operations and engineering personnel:  (1) did not make safety significant decisions using a systematic process (H.1.(a)), and (2) failed to use conservative assumptions for operability decision-making when evaluating degraded and nonconforming conditions (H.1.(b)). The causes of the examples of this finding also have crosscutting aspects associated with evaluation and corrective action of the problem identification and resolution area in that licensee personnel:
(1) did not assess conditions adverse to quality for impacts to the operability of safety-
 
related equipment (P.1.(c), and (2) did not address safety issues in a timely manner P.1.(d)). The causes of the examples of this finding also related to the safety culture component of accountability in that workers and managers faile d to demonstrate a proper safety focus and reinforce safety principles (O.1.(b) and O.1.(c)).  (Multiple Sections)
: '''Green.'''
The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," with six examples for the failure of the licensee to identify, evaluate, or correct conditions adverse to quality between 1988 and October 10, 2007. The corrective actions implemented by the licensee to address the substantive human performance and problem identification and resolution crosscutting issues were ineffective in sustaining performance improvement as noted by licensee self assessments, external industry reviews, and NRC inspections. The team also identified several examples of poor and inconsistent implementation of corrective action program behaviors. The examples of the violation involved not entering the use of unqualified tape in containment in the corrective action process, evaluating the condition, or taking timely actions to remove the tape from all three units; not identifying, evaluating, or implementing timely corrective actions associated with operating experience applicable to the auxiliary feedwater pump trip and throttle valve; not implementing timely corrective actions for water intrusion and flooding of underground manholes and cable vaults; inadequate evaluation for nonconforming Target Rock reed switches; not evaluating and correcting a degraded condition with post accident monitoring instrument chart recorders, and not correcting a degraded/nonconforming condition associated with 3 inch Borg-Warner check valves. Each of the individual technical issues was entered into the licensee's corrective action program.
 
The examples associated with this finding are greater than minor because they were associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the examples associated with this finding are determined to have very low safety significance since they only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The causes of the examples of this finding have crosscutting aspects associated with decision making of the human performance area in that operations and engineering personnel failed to use conservative assumptions for operability decision-making when evaluating degraded and nonconforming conditions (H.1.(b)). The causes of the examples of this finding have crosscutting aspects associated with:  (1) corrective actions of the problem identification and resolution area because the licensee failed to evaluate previous issues such that resolutions addressed all conditions affecting operability (P.1.(c)), (2) operating experience of the problem identification and resolution area in that engineering personnel failed to ensure implementation and institutionalization of operating experience through changes to station processes, procedures, equipment, and training programs (P.2.(b)), and (3) self assessment of the problem identification and resolution area in that the licensee did not follow their benchmarking and self assessment guide to ensure findings were evaluated in their corrective action program (P.3.(c)). The causes of the examples of this finding also related to the safety culture component of accountability in that workforce and management  personnel failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(b) and O.1.(c)).  (Multiple Sections)
: '''Green.'''
The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for the failure to translate design basis requirements into procedures to ensure the plant is operated within its design basis. Specifically, between 1985 and
 
October 2007, the maximum condensate storage tank temperature requirements did not include the effect of recirculated hot condensate water from the main condenser. The issue was entered into the corrective action program as Palo Verde Action Request 3073243.
 
This finding is greater than minor because it was associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding has crosscutting aspects associated with corrective action of the problem identification and resolution area in that engineering personnel did not assess conditions adverse to quality for impacts to the operability of safety related equipment (P.1.(c)).  (Section 5.2.b.1)
: '''Green.'''
The team identified a noncited violation of License Condition 2.C(6) for the failure to install sprinkler heads in accordance with the fire protection program. Specifically, on October 2, 2007, the team identified several upright fire sprinkler heads in the auxiliary building that were incorrectly installed in a downward orientation. This issue was entered into the corrective action program as Palo Verde Action Request 3073824.
 
This finding is greater than minor because it was associated with the mitigating systems cornerstone attribute of external factors and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to require additional evaluation under Inspection Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process," because it was associated with the suppression element of defense-in-depth. Since the installed configuration of the sprinkler heads represented a low degradation of the fire suppression system, in accordance with Section 1.3.1, of Inspection Manual Chapter 0609, Appendix F, the issue was determined to have very low safety significance.  (Section 5.2.b.2)
: '''Green.'''
The team identified a noncited violation of 10 CFR 50.65(a)(2) for the failure of maintenance rule and engineering personnel to demonstrate that the performance or condition of structures, systems, or components was being effectively controlled through appropriate preventive maintenance to ensure systems or components remained capable of performing their intended function. Specifically, between April and October 2007, an inadequate evaluation of maintenance rule performance criteria was performed and, even though the Unit 2 auxiliary feedwater Train A had exceeded its maintenance rule 10 CFR 50.65(a)(2) performance criteria, no goal setting and monitoring was performed as required by 10 CFR 50.65(a)(1) of the maintenance rule. This issue was entered into the corrective action program as Palo Verde Action Request 3075907.
 
This finding is greater than minor because it was associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding has crosscutting aspects associated with self assessments of the problem identification and resolution area in that maintenance rule and engineering personnel failed to perform self assessments that were comprehensive, appropriately objective, and self-critical (P.3.(a)). The cause of this finding has crosscutting aspects associated with decision-making of the human performance area in that engineering personnel failed to make safety-significant or risk-significant decisions using a systematic process (H.1.(a)). The cause of this finding is also related to the safety culture component of accountability in that management did not reinforce safety standards and display behaviors that reflected safety as an overriding priority (O.1.(b)). 
(Section 5.5.b.1)
: '''Green.'''
The team identified a finding for the failure of maintenance personnel to install emergency lighting in containment in support of the refueling outage per repetitive maintenance work Order 2935399 and work Instruction WSL 24436
. As a result, work began in the Unit 3 containment with no emergency lighting installed and no egress contingency plan for a loss of containment lighting. This issue was entered into the corrective action program as Palo Verde Action Request 3070783.
 
This finding is considered more than minor because if left uncorrected, a failure to install emergency lighting could hamper emergency response activities in the containment or complicate emergency egress from the containment. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Appendix M, "Significance Determination Process Using Qualitative Criteria," the fi nding is determined to be of very low safety significance because emergency lighting was necessary for personnel safety and personnel were expected to carry flashlights when responding to events. The cause of the finding has crosscutting aspects associated with work control of the human performance area in that maintenance personnel failed to properly plan the emergency lighting installation work by incorporating contingencies in case the work was not completed in the appropriate timeframe (H.3.(a)). The cause of this finding is also related to the safety culture component of accountability in that management personnel failed to reinforce safety standards and display behaviors that reflected safety as an overriding priority (O.1.(b)).  (Section 5.6.2.b.2)
: '''Green.'''
The team identified a noncited violation of Technical Specification 5.4.1.a for the failure of radiation protection personnel to follow procedures for installing temporary shielding at the 87 foot elevation of the auxiliary building west penetration room. Specifically, temporary shielding (Package A-87-10) was installed in direct contact and across the Train A low pressure safety injection pressure instrument sensing line. However, a piping stress analysis was not performed as required by Procedure 75RP-9RP25,
"Temporary Shielding," Revision 9. This issue was entered into the corrective action program as Palo Verde Action Requests 3071468 and 3072224.
 
This finding is greater than minor because it was associated with the mitigating systems cornerstone attribute of configuration control and affected the cornerstone objective to ensure the availability and capability of systems to respond to initiating events. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, this finding is determined to be of very low safety significance because the condition did not result in an actual loss of safety function, and did not screen as risk significant or contribute to external event initiated core damage sequences since it did not involve a loss or degradation of equipment designed to mitigate a seismic event. This finding has crosscutting aspects associated with the work practices component of the human performance area because the licensee did not effectively use human error prevention techniques such as self checking and proper documentation of activities for the shielding installation (H.4.(a)).  (Section 5.6.2.b.3)
: '''Green.'''
The team identified a noncited violation of 10 CFR 50.65, for the failure of engineering personnel to establish goals and monitor the performance of the safety injection system. Specifically, on March 22, 2007, engineering personnel failed to establish goals to properly monitor system performance, or provide a technical justification to demonstrate that monitoring under 10 CFR 50.65(a)(1) was not required for the safety injection system following the system changing status from 10 CFR 50.65(a)(2) to 10 CFR 50.65(a)(1). This issue was entered into the corrective action program as Palo Verde Action Requests 3074255 and 3076699.
 
This finding is greater than minor because it was associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance since there was no loss of safety function. The cause of this finding has crosscutting aspects associated with:  (1) corrective actions of the problem identification and resolution area in that engineering personnel failed to take appropriate actions to address safety issues and adverse trends in a timely manner (P.1.(d)), and (2) self assessment of the problem identification and resolution area in that engineering personnel did not perform self assessments that were comprehensive, objective, and self critical (P.3.(a)). 
(Section 5.6.9.b.1)
: '''Green.'''
The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," for the failure of maintenance and engineering personnel to maintain proper configuration of the support brackets for the pressurizer condensate pots in accordance with design drawings. Specifically, on October 2, 2007, the team identified that the support bracket U-bolts were not tight against the condensate pot piping, jam nuts were not installed on the U-bolts, and jacking bolts were not in full contact with the pressurizer vessel. The support brackets minimize lateral motion during a seismic event. This issue was entered into the corrective action program as Palo Verde Action Requests PVAR 3070805 and 3075704.
 
This finding is greater than minor because it was associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. This finding has crosscutting aspects associated with the work practices component of the human performance area because maintenance personnel did not effectively use human error prevention techniques such as self checking and proper documentation of activities for the installation of the support bracket (H.4.(a)).  (Section 5.6.7.b.1)
 
Barrier Integrity
: '''Green.'''
The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure of maintenance personnel to properly rig the Unit 3 100 foot elevation inner personnel airlock door in accordance with engineering drawings. Specifically, the suspended rigging was completed with the inappropriate placement of wire rope slings over two locking pins resulting in an unanalyzed force being applied to the door's operating mechanism. This issue was entered into the corrective action program as Palo Verde Action Request 3086057.
 
The finding is greater than minor because it could become a more significant safety concern if left uncorrected in that the applied suspended force on the bronze bushing and the door's operating mechanism, which were not designed for vertical loading, could degrade the personnel airlock door sealing capability. This finding can not be evaluated by the significance determination process because Inspection Manual Chapter 0609, "Significance Determination Process," Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations," and Appendix G, "Shutdown Operations Significance Determination Process," do not apply to the door for the plant conditions that existed during the event. This finding affects the barrier integrity cornerstone and is determined to be of very low safety significance by NRC management review using Inspection Manual Chapter 0609, Appendix M, "Significance Determination Process Using Qualitative Criteria," because it was a deficiency that did not result in the actual breach of the containment barrier. The cause of this finding has crosscutting aspects associated with the work practices aspect of the human performance area in that maintenance personnel failed to provide adequate oversight of work activities (H.4.(c)).  (Section 5.6.4.b.1)
: '''Green.'''
The team identified a noncited violation of Technical Specification Surveillance Requirement 3.6.6.6, for the failure to verify that each containment spray nozzle was unobstructed. Specifically, the last completed surveillance test conducted on each unit, identified that one nozzle in each unit was obstructed and that the nozzles were not retested  in accordance with the approved retest requirement. This issue was entered into the corrective action program as Palo Verde Action Requests 3075026, 3075059, 3068647 and, 3048511.
 
The finding is more than minor because it affected the configuration control attribute of the barrier integrity cornerstone, and affected the associated cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to be of very low safety significance because it did not involve an actual reduction in defense-in-depth for the atmospheric pressure control function of the reactor containment.  (Section 5.5.b.3)
: '''Green.'''
The team identified a noncited violation of Technical Specification Surveillance Requirement 3.0.3 for the failure of operations personnel to conduct an assessment and manage the risk for a missed surveillance test. On September 27, 2007, the team identified that the requirements for testing the containment spray nozzles in Units 1, 2, and, 3 did not meet Technical Specifications Surveillance Requirement 3.6.6.6. Operations personnel did not enter Technical Specification Surveillance Requirement 3.0.3 until prompted by the team on October 30, 2007. This issue was entered into the corrective action program as Palo
 
Verde Action Request 3085708.
 
The finding is determined to be more than minor because it affected the configuration control attribute of the barrier integrity cornerstone, and affected the associated cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.
 
Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance because it did not involve an actual reduction in defense-in-depth for the atmospheric pressure control function of the reactor containment. The cause of this finding has crosscutting aspects associated with work practices of the human performance area in that operations personnel failed to ensure supervisory and management oversight of work activities that resulted in a missed Technical Specification surveillance requirement (H.4(c)). The cause of this finding is also related to the safety culture component of accountability in that operations personnel failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)). (Section 6.2.b.1)
Emergency Preparedness TBD. The team identified an apparent violation of 10 CFR 50.54(q) and 10 CFR Part 50, Appendix E.IV.F.2.g, with the significance yet to be determined, for the licensee's failure to correct an identified risk significant planning standard weakness between May 2, 2007 and October 28, 2007. Specifically, the licensee failed to implement adequate corrective actions for identified weaknesses in the ability to correctly make a Site Area Emergency declaration for a steam generator tube rupture event. This issue was entered into the licensee's correction action program as Palo Verde Action Request 3083911.
 
The team determined that the inability to consistently implement an Emergency Action Level was a performance deficiency within the licensee's control. This finding is more than minor because it was associated with the Emergency Preparedness attribute of emergency response organization performance and affected the cornerstone objective to implement adequate measures to protect the health and safety of the public because the inability to properly recognize and classify an emergency condition affects the licensee's ability to implement adequate protective measures. This finding was evaluated using the Emergency Preparedness Significance Determination Process and was preliminarily determined to be of low to moderate safety significance because it was a failure to comply with NRC requirements; it was an issue associated with the requirements of Appendix E of 10 CFR Part 50; it was not an issue with a risk significant planning standard as described in Manual Chapter 0609, "Significance Determination Process," Appendix B, "Emergency Preparedness Significance Determination Process," Section 2.0; and it was a functional failure of the requirements of Appendix E IV.F.2.g because the licensee failed to correct a weakness associated with Risk Significant Planning Standard 10 CFR 50.47(b)(4). The cause of this finding has crosscutting aspects associated with the corrective action aspect of the problem identification and resolution area in that the licensee failed to thoroughly evaluate problems such that resolutions ensured correcting problems (P.1.(c)). The cause of this finding was also related to the safety culture component of accountability in that the licensee failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)).  (Section 5.7.b.1)
: '''Green.'''
The team identified a Green noncited violation of 10 CFR 50.54(q) and §50.47(b)(4), for the failure of the licensee to be able to implement Emergency Action Levels 3-12 and 7-1. Specifically, area radiation Moni tor RU-18 could not be utilized in the vicinity of the remote shutdown panels and therefore, the emergency classification associated with Emergency Action Level 3-12 could not be declared at the Alert level as required in Procedure EPIP-99, "EPIP Standard Appendices."  In addition, the licensee improperly overclassified Emergency Action Level 7-1 as an Alert when presented conditions warranting a classification of a Notification of Unusual Event. Specifically, the licensee did not develop a procedure to enable personnel to differentiate between an aircraft and an airliner and therefore, the proper emergency classifications could not be consistently determined. This finding was entered into the licensee's corrective action program as Condition Report Disposition Requests 3071570, 3071572, and 3085175.
 
The team determined that the inability to implement Emergency Action Levels was a performance deficiency. The finding was more than minor because it was associated with the Emergency Preparedness attribute of procedure quality and could affect the cornerstone objective associated with the licensee's ability to correctly classify an emergency condition which would affect the licensee's ability to implement adequate measures to protect the health and safety of the public. Using the Manual Chapter 0609, "Significance Determination Process," Appendix B, "Emergency Preparedness Significance Determination Process," the finding was determined to have very low safety significance because the licensee would be unable to declare one Emergency Action Level at the Alert and one Emergency Action Level at the Notification of Unusual Event level. The cause of this finding had crosscutting aspects associated with the corrective action of the problem identification and resolution area in that the licensee had previous opportunities to identify the deficiencies (P.1.(a)).  (Section 5.7.b.2)
 
Occupational Radiation Safety
: '''Green.'''
The team identified a noncited violation of 10 CFR 19.12, "Instructions to Workers," for the failure of radiation protection personnel to provide adequate information regarding radiological conditions and precautions to minimize exposure during pre-job briefs.
 
Specifically, on October 1 and 3, 2007, radiation protection personnel did not adequately inform workers of radiological conditions and precautions to minimize exposure during radiological briefings. This issue was entered into the corrective action program as Palo Verde Action Request 3070507 and 3071940.
 
The finding is greater than minor because it is associated with the Occupational Radiation Safety Cornerstone attribute of programs and process and affected the cornerstone objective of ensuring the adequate protection of the workers health and safety from exposure to radiation during routine operations. Using Inspection Manual Chapter 0609, "Significance Determination Process," A ppendix C, "Occupational Radiation Safety Significance Determination Process," the finding was determined to be of very low safety significance because it was not an as low as is reasonably achievable issue, there was not an overexposure or substantial potential for an overexposure, and the ability to assess dose was not compromised. The cause of this finding has crosscutting aspects associated with decision making in the human performance area in that radiation protection personnel failed to communicate decisions, and the basis for decisions, to personnel who had a need to know the information (H.1.(c)). This finding also has a safety culture component aspect of accountability in that radiation protection personnel did not demonstrate a proper safety focus or reinforce safety principles among peers when conducting pre-job briefings (O.1.(c)).  (Section 6.1.b.1)
 
Public Radiation Safety SLIV. The team identified a Severity Level IV noncited violation of 10 CFR 50.71(e) for the failure of the licensee to periodically update the Final Safety Analysis Report (UFSAR) with all changes made in the facility or procedures. Specifically, in 2002, radiation protection and operations personnel changed the operation of the total dissolved solids holdup tanks from that described in the Updated Final Safety Analysis Report (UFSAR) and did not submit an update to the NRC. This issue was entered into the licensee's corrective action program as Palo Verde Action Request 3075089.
 
This issue is being treated as traditional enforcement because the failure to update the Final Safety Analysis Report has the potential to impact the NRC's ability to perform its regulatory function. The finding is characterized as a Severity Level IV violation because the erroneous information was not used to make an unacceptable change to the facility or procedures. The finding is of very low safety significance because the change in operation of the total dissolved solids holdup tanks did not result in an increase in the likelihood of a release of radioactive material. The cause of this finding has a crosscutting aspect associated with resources in the human performance area in that the licensee failed to ensure that personnel and equipment were available and adequate to maintain radiological safety by minimization of long-standing equipment issues (H.2.(a)).  (Section 6.2.b.1)
 
Physical Protection N/A. The team identified a minor violation of the Palo Verde Physical Security Plan, associated with the calculation of group work hours. This issue was entered into the licensee's corrective action program as Palo Verde Action Request 3078227. The details of the finding can be found in Inspection Report 05000528; 05000529; 05000530/2007402.
 
Miscellaneous N/A. The team noted that the licensee had not completed corrective actions and effectiveness reviews associated with the root and contributing causes for the July 2004,
Yellow finding involving the voiding of emergency core cooling system piping in all three units. The cause of the failure to implement effective corrective actions was related to the safety culture component of organizational change management in that, licensee personnel ceased to implement corrective actions and effectiveness reviews when the existing management team members assumed that the activities would be integrated into other station processes following the arrival of a new senior management team.  (Section 9.0)
 
N/A. The team identified continuing human performance issues at Palo Verde consistent with previously identified issues discussed in End-of-Cycle and Mid-cycle letters since 2005.
 
Specifically, human performance concerns observed during this inspection included weaknesses in implementing the operability determination process, failures to follow procedures, failures to implement human performance tools, and inadequate procedures. In addition, a number of engineering issues reflected a lack of technical rigor in resolving complex issues. The team noted a lack of adherence to basic radiological work practices and inconsistent implementation of control room behaviors. The team also identified that the licensee's training department had been inconsistent in supporting site improvement. Although a human performance root cause investigation had been conducted, corrective actions were not effective in sustaining performance improvement.  (Multiple Sections)
 
N/A. Multiple substantive crosscutting aspects associated with problem identification and resolution (PI&R) have existed since 2004. Corrective actions continue to remain ineffective in sustaining improving performance as noted by effectiveness reviews, external industry reviews, and NRC inspections. The licensee's corrective action program was complicated and cumbersome. Licensee personnel recognized the attributes of problem identification, evaluation, and resolution when interviewed; however, the knowledge and understanding was not consistently demonstrated to the NRC during the inspection.  (Multiple Sections)
N/A. The team noted that the licensee's third-party safety culture assessment was adequate to provide the licensee with the information necessary to develop appropriate corrective actions for safety cu lture weaknesses. The results of the NRC's independent safety culture assessment validated the results of the licensee's third-party safety culture assessment.
 
The team identified weaknesses in organizational characteristics and attitudes associated with 10 of the NRC's 13 safety culture components, as detailed in Section 06.07 of Inspection Manual Chapter 0305 "Operating Reactor Assessment Program."  The most significant weaknesses were identified in the safety culture components of accountability, the corrective action program, decision-making, resources, self assessments, and work practices. The team noted that these weaknesses were widespread among functional groups across the organization. Organizational characteristics and attitudes were adequate in the safety culture components of safety policies; the environment for raising concerns; and preventing, detecting, and mitigating perceptions of retaliation.  (Sections 8.1 and 8.2)
 
===
Licensee-Identified Violations===
 
Violations of very low safety significance which were identified by the licensee have been reviewed by the team. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. These violations and corrective actions are listed in Section 11 of this report.
 
=REPORT DETAILS=
 
1 PERFORMANCE HISTORY On March 2, 2007, the NRC issued the Annual Assessment Letter, which documented the results of the annual performance review for the Palo Verde Nuclear Generating Station (PVNGS), including the decision to perform a supplemental inspection at PVNGS, using Inspection Procedure (IP) 95003, "Supplemental Inspection for Repetitive Degraded Cornerstones, Multiple Degraded Cornerstones, Multiple Yellow Inputs, or One Red Input."  PVNGS Unit 3 was placed in the Multiple/Repetitive Degraded Cornerstone column (Column 4) of the NRC's Action Matrix, effective in the fourth Quarter 2006. In accordance with NRC Inspection Manual Chapter (IMC) 0305, "Operating Reactor Assessment Program," the decision to place Unit 3 in Column 4 was made on the basis of the definition of a Repetitive Degraded Cornerstone in that there were two separate safety significant inspection findings (one Yellow and one White) in the Mitigating Systems cornerstone and the cornerstone had been degraded for more than four quarters.
 
Unit 3 was placed in Column 4 based on two findings:
: (1) a White finding (issued
 
February 21, 2007) for inadequate maintenance and corrective actions involving the K-1 electrical relay on a Unit 3 emergency diesel generator (EDG); and
: (2) a Yellow finding (issued April 8, 2005) involving voiding in the suction line for the emergency core cooling system (ECCS) pumps in all three units.
 
As a result of the Yellow finding, the NRC completed the IP 95002, "Inspection For One Degraded Cornerstone Or Any Three White Inputs In a Strategic Performance Area," supplemental inspection in December 2005. The associated inspection report dated January 27, 2006, closed the Severity Level III violation of 10 CFR 50.59 and kept the Yellow finding open. The Yellow finding remained open because the licensee's corrective actions were not fully developed, were narrowly focused, and their implementation was not effective. In August 2006, the NRC complet ed a second IP 95002 supplemental inspection. The associated report dated November 11, 2006, documented that the Yellow finding could not be closed because the corrective actions to address problems with questioning attitude, technical rigor, and operability determinations (ODs) were not fully effective. In addition, measures and metrics to monitor performance improvement had not been developed and the licensee did not have an effective program for using operating experience (OE).
 
Throughout 2006, the licensee continued to have performance problems that challenged the operation of all three units in the following areas:
: (1) equipment reliability;
: (2) human performance; and
: (3) problem identification and resolution (PI&R). Two special inspections were conducted in June and September of 2006. The June 2006 special inspection reviewed concerns regarding spray pond chemistry control and a reduction in heat exchanger performance for key safety systems. This inspection resulted in the issuance of five noncited violations of very low risk significance (Green). The September 2006 special inspection reviewed concerns with the failure of the K-1 electrical relay on the Unit 3 Train A EDG. This inspection resulted in the issuance of a White finding. The causes for the findings associated with both of these inspections were similar to the programmatic issues associated with the 2005 Yellow finding and included:  a lack of technical rigor in performing evaluations and incomplete consideration of the extent of problems when they were identified.
 
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The licensee's performance also warranted the issuance of several substantive crosscutting PI&R and human performance aspects in March 2005. The substantive crosscutting aspects continue to remain open because of a failure to implement changes that would result in sustainable performance improvement.
 
The licensee initiated an integrated performance improvement plan in the fourth quarter of 2005. Their improvement plan was ineffe ctive and performance problems continued throughout 2006 and into 2007. Factors associated with the lack of performance improvement included:
Fixing symptoms and not addressing the root causes of problems,  Not performing a thorough review of issues,  Accepting incomplete answers and actions,  Failing to question the impact of actions,  Incomplete ODs, and  Inadequate corrective action program (CAP) implementation.
 
On June 21, 2007, the NRC issued Confirmatory Action Letter (CAL) 4-07-004, which required PVNGS to perform additional actions to address their decline in performance.
 
Specifically, the licensee was required to:
1. Complete actions to address the root and contributing causes identified in evaluations for the Yellow finding associated with the voided containment sump suction piping for all three units, and the White finding associated with the Unit 3 Train A emergency diesel generator electrical relay problems.
 
2. Complete corrective actions that will result in sustained improved performance in the crosscutting areas of human performance and PI&R.
 
3. Complete an independent (third party) safety culture assessment by September 15, 2007.
 
4. Incorporate the results of their in-depth evaluations and their safety culture assessment described in Item 3 above into a modified improvement plan.
 
5. Submit the portions of the modified improvement plan that impact the Reactor Safety strategic performance area, including safety culture improvement initiatives by November 30, 2007.
 
On September 4, 2007, the licensee subm itted a letter to the NRC indicating the independent safety culture assessment had been completed. The NRC's review of the safety culture assessment is documented in Section 8.1.
 
On November 28, 2007, the licensee submitted a letter to the NRC requesting an extension to the submittal date of the modified improvement plan. The plan was being developed during the IP 95003 inspection, and was therefore only partially reviewed in October 2007.
 
The licensee submitted the plan to the NRC on December 31, 2007.
 
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2 SITE INTEGRATED BUSINESS PLAN (SIBP) AND SITE INTEGRATED IMPROVEMENT PLAN (SIIP)
Overview  Because the improvement plan was not complete at the time of the IP 95003 inspection, the appropriateness, timeliness, and effectiveness of the corrective actions to address the root and contributing causes, as well as other identified problems, could not be fully evaluated.
 
The team determined that additional NRC inspections of the modified improvement plan will need to be conducted before an assessment can be completed.
 
====a. Inspection Scope====
The team performed a review of the SIBP and SIIP in accordance with IP 95003, Sections 02.02.a - 02.02.e. This assessment of the improvement plan was accomplished by reviewing numerous documents including, in part, root cause evaluations, apparent cause evaluations, self assessments, condition report/disposition requests (CRDRs), Palo Verde Action Requests (PVARs), condition report action items (CRAIs), problem development statements (PDSs), fundamental overall problems (FOPs), effectiveness reviews, the improvement plan database, and the Improved Performance and Cultural Transformation (ImPACT) database. The team:
: (1) reviewed the procedures for completing the ImPACT project and improvement plan;
: (2) assessed the scope of the ImPACT project;
: (3) reviewed PVARs generated as a result of ImPACT activities;
: (4) assessed the ability to cross reference data between the various
 
documents used to develop the improvement plan;
: (5) reviewed PDSs for adequacy and for outstanding technical issues;
: (6) sampled completed improvement plan corrective actions to determine timeliness, completion of actions, and measures of effectiveness;
: (7) determined if corrective actions identified in ImPACT documents were included in the improvement plan and the CAP at the appropriate priority level;
: (8) assessed the resource loading of the improvement plan;
: (9) assessed the significance of overdue action items; and
: (10) reviewed various background documents for areas that were not included in the improvement plan.
 
====b. Observations and Findings====
 
=====Introduction.=====
The team identified several observations associated with the development of the improvement plan. Since the licensee did not submit the improvement plan to the NRC before the IP 95003 inspection commenced, the team only reviewed a draft version of the SIBP/SIIP.
 
=====Description.=====
The SIBP and SIIP were developed and controlled by Procedure 01DP-0AC06, "Site Integrated Business Plan (SIBP)/Site Integrated Improvement Plan (SIIP) Process," Revision 1. Revision 0 of this procedure was issued in September 2007, which was well after the May 2007 start of the improvement plan efforts. The SIBP plan is a database program that was developed using Microsoft Access. This database was designed to track the implementation and completion of actions contained within the SIBP. The actual corrective actions associated with the improvement plan, which were CRAIs, were contained in the Site Work Management System (SWMS) database that is used to track CAP documents. The SIBP included a subset of corrective actions known as the SIIP. The SIIP contains corrective actions associated with the ImPACT process, NRC CAL, PVNGS safety culture assessment, IP
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95001 issues (White finding for inadequate maintenance and corrective actions involving the K-1 electrical relay on a Unit 3 EDG), IP 95002 issues (Yellow finding involving voiding in the suction line for the ECCS pumps in all three units), and the substantive crosscutting issues for human performance and PI&R. The SIIP is expected to be the modified improvement plan described in Item 5 of the CAL.
 
The ImPACT process (see figure below) consisted of a series of assessment steps including ImPACT procedures, checklist findings, PDSs, and FOPs. Checklists were used to document the results of ImPACT assessments. PDSs were used to collate related findings from individual assessment activities and then those findings were grouped into FOPs. After developing the FOPs, the licensee used one or more of the following tools to identify casual factors by conducting root cause evaluations, apparent cause evaluations, self-assessments, or effectiveness reviews. Action plans were then developed, analyzed, prioritized, and incorporated into the SIBP and SIIP. The team concluded that the ImPACT process successfully identified the performance concerns at Palo Verde in need of corrective actions.
 
95003 Inspection Module andMOREFeedbackSite Integrated Improvement PlanImPACTAssessment PlanCHECKLISTS-KART -IA &CPD-Focused AssessmentsRoll-UpProcessPVARs PDSsMultipleCollectiveEvaluation SA EFRRCAPVARsInput CAs, CAPRs&EffectivenessReviewsHistorical Data ReviewData BaseFault Codes FOPsFundamental Overall ProblemsTopical AreasSelected95003 Inspection Module andMOREFeedbackSite Integrated Improvement PlanImPACTAssessment PlanCHECKLISTS-KART -IA &CPD-Focused AssessmentsRoll-UpProcessPVARs PDSsMultipleCollectiveEvaluation SA EFRRCAPVARsInput CAs, CAPRs&EffectivenessReviewsHistorical Data ReviewData BaseFault Codes FOPsFundamental Overall ProblemsTopical AreasSelected      Enclosure  - 24 -
The ImPACT process reviewed the following seven areas:
Historical Data Review:  reviewed and analyzed over 4000 documents since 2001 including, in part, significant internal and external assessments of performance at PVNGS, NRC inspection reports, NRC asse ssment letters, licensee event reports (LERs), maintenance rule functional failures, trends, various corrective action documents, and unplanned downpowers.
 
Key Attribute Review Team (KART):  evaluated the emergency diesel generator (EDG) and safety injection systems while focusing on the adequacy of programs and processes for design, human performance, procedure quality, equipment performance, configuration control, and emergency response organization readiness. The Key Attribute Review also included the inspection attributes of NRC IP 95003.
 
Identifying, Assessing, and Correcting Performance Deficiencies Review:
evaluated the effectiveness of corrective actions associated with significant performance deficiencies, audits and assessments, resource allocation, performance goals, employee concerns program, technical resolution programs (e.g., differing professional opinions), and use of industry information.
 
Focused Assessments Review:  evaluated specific areas of known weaknesses and significant change for the 1989 NRC Diagnostic Assessment, the licensee's re-engineering program, PI&R crosscutting assessment, human performance crosscutting assessment, and performance improvement plan effectiveness assessment.
 
Safety Culture Assessment Review:  utilized two independent third party teams that reviewed the safety culture for the site. This item met the safety culture requirements of NRC IP 95003 and the NRC Confirmatory Action Letter.
 
Recirculation Actuation System and K-1 Relay Review:  assessed the root causes, appropriateness of corrective actions, effectiveness of corrective actions, and measurements of success.
 
Collective Evaluation and Action Plans Development:  performed an evaluation of the failures and deficiencies associated with the above six evaluations. This final process was done to identify the causes for the performance problems and then develop corrective actions necessary to improve performance.
 
As of October 1, 2007, the SIBP consisted of 20 building blocks with 5 building blocks that were designed to always be included in the business plan. These five building blocks include plant equipment, people, CAP, safety, and knowledge/training. The other 15 building blocks can change as progress and improvement is made on an individual block and other issues arise which require improvement and corrective action. These blocks are depicted in the above figure and include, in part, oversight, work management, programs/processes, procedures, and emergency preparedness. Within each building block there were one or more initiatives, with a total of 152 initiatives. Each initiative contained numerous tasks. At the time of the inspection, there were 1609 tasks (each task had a CRAI) in the SIBP, of which 357 were a part of the SIIP.
 
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As of November 1, 2007, there were 339 tasks (CRAIs) closed in SWMS, with only 12 tasks having completed improvement plan closure packages. Procedure 01DP-0AC06, required that each task be closed and that the closure review process use a graded approach based on the category of the task or priority of the CRAI. The team observed a Closure Review Board meeting on October 31, 2007, and reviewed the October 24, 2007, Closure Review
 
Board meeting minutes. During the October 31, 2007, meeting, only two tasks were reviewed and both were rejected because objective evidence of the actions being completed and sustainability of the actions were not demonstrated or included as part of the package.
 
The meeting minutes described seven tasks being reviewed for closure of which five were closed, one was rejected, and one was tabled (supporting information was not included with the closure package). The team determined that the closure review of the individual tasks was in accordance with Procedure 01DP-0AC06. The team did note that the contractors who attended the meeting were driving the Closure Review Board members to higher levels of accountability and making sure the process was followed; however, the Closure Review Board was still in the process of establishing repeatable standards.
 
The team identified the following observations associated with the development of the SIIP:
The root and contributing causes for each of the FOP root causes were attributed to a lack of management oversight, leadership, and accountability. Many of the improvement plan tasks contained little or no detail as to how the specific tasks were to be implemented. No additional details were available on the criteria/goals that the tasks should meet,the development schedule, or the resource needs. For example:
 
===1. The root cause for CRDR 3048835, "Operational Focus," attributed the problems to senior management not establishing and enforcing expectations. The evaluation did ===
 
not investigate the operations' department ability to lead and the appropriateness and implementation of the current standards of conduct.
 
2. CRAI 3064362 was initiated to develop a leadership model that established a vision, mission, values, and behaviors. This corrective action was the main action in numerous root cause evaluations that was designed to prevent recurrence of various performance problems that resulted in PVNGS being placed into Column 4 of the NRC Action Matrix. The description contained in the improvement plan and SWMS for CRAI 3064362 stated, "Benchmark and develop a leadership/management model that establishes the vision, mission, values and expected behaviors for each of the problem areas identified by the ImPACT team and the additional areas noted above.
 
Additionally, the management model should address ownership, the Palo Verde core fundamental areas (Plant Equipment, People, CAP, Safety, and Knowledge/Training), a mechanism for continuous monitoring and improvement, and metrics to measure effectiveness."  This CRAI, with a due date of June 2008, contained no further details as to how to achieve this corrective action.
 
3. CRAIs 3063852, 3075713, and 3075649, identified corrective actions that were not specific or measurable as stated in Section 17 of "Root Cause Investigation Manual for Significant CRDRs."  The three CRAIs discussed corrective actions to implement a Management Review Meeting process, develop and implement a leadership/management model, and establish a site-wide emphasis and alignment on the core mission and on the core fundamental focus areas. However, the CRAIs did not include specific details and/or measurable actions.
 
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The team determined that for most cases, actions were included in both the CAP and the SIIP. However, two items were not found in the improvement plan:  1) CRAI 3076878, "Develop, coordinate, and implement a campaign to establish and reinforce the position that Engineering is the design authority of the site-," was one of the
 
corrective actions to address CRDR 3048865, "Design Control and Configuration Management Weaknesses;" and 2) from the independent safety culture assessment, CRAI 3090979 was an action to include safety conscious work environment (SCWE)expectations in the contracts for PVNGS contractors.
 
Most of the initiatives contained tasks to either develop or modify existing metrics in order to measure progress. However, most of the new or modified metrics that the team reviewed were not fully developed. As with corrective actions to address the root causes, the actions to develop metrics were high level and contained few details. It was unclear how CRAI 3064372, "Develop and utilize metrics to ensure Palo Verde uses the CAP, training, operating experience, self-assessments/benchmarking, and independent oversight activities to establish a continuous learning environment," will address the contributing cause of ineffective implementation of those programs to drive improvements in individual and station performance as described in the CRDR 3048836, "Organizational Effectiveness" root cause report.
 
Effectiveness review descriptions were broad, and the criteria provided ambiguous information on acceptability. For example, CRAIs 3064491 and 3075832 stated that the interim and final effectiveness reviews can be closed once the following are met:  1) site performance indicators reflected acceptable performance or overall site improvement; 2) the independent assessment determined that actions were effective, specifically that Palo Verde had established, communicated, and reinforced standards specific to each of the focus areas in the leadership/management model and that accountability is adequately addressed; and 3) overall responses fr om the safety culture survey indicated an improving trend. The team did not identify specific criteria that will be used to determine the effectiveness of the corrective actions (e.g., what constitutes overall site improvement or an improving trend).
 
CRAIs 3063112, develop and implement a site-wide communication strategy, and 3063852, implement a Management Review Meeting process, were coded as Priority 3; however, the improvement plan had the CRAIs listed as corrective actions to prevent recurrence which should have been coded Priority 2 as specified by Procedure 01DP-0AC06. Licensee personnel indicated that they were already aware of these two examples and had documented these differences, as well as other differences for CRAI due dates, priorities, and text descriptions on PVAR 3083805, dated October 26, 2007. As of November 2, 2007, the licensee had identified 35 CRAIs whose priority codes did not match the improvement plan classification.
 
As of November 2, 2007, the licensee had not resource loaded the SIBP/SIIP. Nevertheless, over 1100 of the 1609 tasks (from November 2007 to December 2008) were scheduled to be completed by December 31, 2008. This schedule did not appear to be achievable based on the large number of tasks that have to be closed over the next 12 months along with the large backlog of work activities that currently exist.
 
Numerous issues with corrective action due dates were identified by the team, including:   
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1. CRAIs associated with CRDR 3048835, operational focus root cause, had out of sequence due dates. CRAI 3065021, which was to develop a site indicator for operational focus, had a due date of January 31, 2008. CRAIs 3062174, 3062184 and 3062188 were written to train leaders on the establishment and proper use of performance indicators; however, this action had a due date of October 27, 2008, well after the development of the operational focus indicator.
 
===2. CRAI 3038014 was to conduct a site wide stand-down in order to communicate CAP fundamentals to all PVNGS personnel. This corrective action item was initiated on ===
 
July 9, 2007, and had a due date of December 28, 2007. The team determined that this action was untimely considering that the Unit 3 outage started September 29, 2007, and the continuation of CAP weaknesses demonstrated at PVNGS.
 
===3. The PI&R root cause in CRAI 3037453 initiated on July 6, 2007, was to conduct a self-assessment of the OD program by June 30, 2008. The team considered this action untimely given the continued problems with the implementation of this ===
 
program for the past several years, as well as numerous OD issues identified during this inspection.
 
===4. The SIIP contained actions that had due dates significantly different from what was initially specified for the root and contributing cause corrective actions. The team ===
 
was concerned that the corrective actions were untimely, especially for the substantive crosscutting areas of hum an performance and PI&R, where performance had not appreciably improved. After incorporation into the SIIP, all of the following CRAIs had their due dates extended for more than a year from the originally scheduled completion date:  1) CRAI 3015013, "Facilitate implementation of programmatic actions to improve procedure use and adherence, as well as improve procedure quality-," had the due date changed from October 1, 2007, to October 1, 2008; 2) CRAI 2936516 was written to evaluate human performance integration with key work processes. This CRAI was due to be completed December 31, 2007, but was changed to March 15, 2009; 3) CRAI 2941720 was written to develop a process to add operating experience to work packages. This CRAI was due to be completed by June 1, 2007, but was changed to December 31, 2008; 4) CRAI 2941718 was written to make operating experience search engines more available and easier to use. This CRAI was due to be completed by June 1, 2007, but was changed to December 28, 2008; and 5) CRAI 3038038 was a corrective action to provide training for all advocates in their responsibilities for quality CAP implementation with a due date of November 30, 2007. When the action was incorporated into the SIBP as Task 3.3.3.d, the action was changed to "Establish a process to provide training for all Advocates-" with the same due date. Actual training of the advocates is in Action 6.3.1.b (CRAI 3032702) with a due date of March 15, 2009.
 
Limited reviews were completed by the licensee on past work products to look for mistakes that could have a potential impact on plant equipment and a corresponding reduction in safety. The team was concerned that a historical review of most programs/processes work products, including the CAP, had not been conducted and was not included as an action in the SIIP.
 
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Observations associated with the incorporation of safety culture insights into the improvement plan are referenced in Section 8.1, under the heading titled, "Licensee Analysis and Corrective Actions."  The observations included weaknesses in resource/staffing levels, a lack of links between corrective actions associated with safety culture and the SIIP, and ongoing incorporation of safety culture assessment findings and recommendations into the SIIP.
 
3 COLLECTIVE SIGNIFICANCE REVIEW
 
Collective Review of Root and Contributing Causes The team compared the results from the inspection to the root cause analyses performed by the licensee and information docketed from previous NRC inspections. The team concluded that the licensee's root and contributing causes bounded the performance deficiencies identified during the ImPACT review and the NRC IP 95003 inspection. The licensee identified numerous root and contributing causes for the performance deficiencies. The following is a summation of the key root and contributing causes applicable to most of the licensee's investigations:
: (1) leaders did not establish, communicate, and enforce standards and expectations for performance or hold individuals accountable to those standards;
: (2) the corrective action program, operating experience, self assessments, and benchmarking did not drive individual and station performance improvement;
: (3) responsibility, accountability, and authority for nuclear safety were not well defined or understood;
: (4) individual behaviors that demonstrate nuclear safety principles were not consistently applied;
: (5) management was not receptive to organizational issues identified during investigations;
: (6) change management activities did not anticipate unintended consequences and did not clearly define and communicate changes to station personnel; and
: (7) Oversight groups did not provide specific and meaningful interventions to correct declining performance.
 
Collective Review of Risk
 
The team completed an assessment of the collective risk associated with the IP 95003 findings. The team was supported by senior reactor analysts from NRC Region IV and headquarters during the risk assessment. Three methods were used:
: (1) an adjustment to the human error probabilities in the Palo Verde Standardized Plant Analysis Risk (SPAR)model, Revision 3.31,
: (2) assignment of risk results to each finding screened as having very low safety significance, and
: (3) a qualitative assessment using the NRC IMC 0305, "Operating Reactor Assessment Program," criteria for determining if oversight of a licensee should be performed under NRC Manual Chapter 0350, "Oversight of Reactor Facilities in Shutdown Condition due to Significant Performance and/or Operational Concerns."  The team concluded that Palo Verde was safe for continued operation even though a degradation in safety performance had occurred and there were several longstanding performance concerns.
 
Palo Verde SPAR Model Palo Verde had documented substantive cro sscutting issues in human performance and PI&R since March 2005 NRC Annual Assessment Letter. Given the duration of the substantive crosscutting issues, the analyst used approved significance determination tools to estimate the effect that this condition had on the risk of operating the plant. The primary source document used in this effort was the SPAR-H Human Reliability Analysis Method, NUREG/CR-6883 (SPAR-H).
 
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The analyst used the Palo Verde SPAR model, Revision 3.31, dated June 18, 2007. The model was updated to correct errors where the SPAR-H calculator did not account for dependencies when three or more negative performance shaping factors (PSFs) were judged to affect the human error probability (HEP) for a human action basic event. This had the effect of lowering some of the HEPs in the base model.
 
The analyst assumed that the condition of poor work practices existed for at least one year, consistent with the exposure time limits of the significance determination process, and that the condition affected all of the human actions included in the SPAR model equally, with the exception of offsite power recovery actions (which were deemed to be controlled mostly by outside influences). Using the SPAR-H Worksheets for action steps at power, a PSF penalty for "poor" work practices was assumed, which assigns a multiplier of 5.0 for the likelihood of failure. For basic events where there were less than 3 negative PSFs, this resulted in the HEP being increased by a factor of 5.0. For cases where three or more PSFs existed, the factor of increase was less than 5.0. Although offsite power recovery actions were left unchanged, the non-recovery probabilities for recovery of a diesel generator, which
 
use actuarial data in lieu of the SPAR-H method, were increased by a factor of 10 percent.
 
The base core damage frequency (CDF) was 8.989E-6/year. Application of the 5.0 PSF for poor work practices resulted in a total CDF of 4.605E-5/year, or a delta-CDF of 3.706E-5/year.
 
This result accounts only for internal initiating events and does not consider the additional risk associated with seismic, fire, or other external initiators, nor does it account for the risk associated with shutdown conditions. Typically, external initiating events approximately equal the risk associated with internal initiators. Using the above results, and assuming that poor work practices would affect the recovery from external initiators to the same extent as for internal initiators, the total baseline CDF would be 1.798E-5/year. The total CDF associated with poor work practices would be 9.210E-5/year, and the delta-CDF would be 7.412E-5/year.
 
In accordance with IMC 0609, Appendix H, "Containment Integrity Significance Determination Process," for a large, dry containment, the large early release frequency (LERF) is significant only with respect to steam generator tube ruptures and intersystem loss of coolant accidents (ISLOCAs). Employing the same assumptions used in the CDF calculation for the effect of poor work practices, the results for ISLOCAs and steam generator tube ruptures are as follows:
 
Base CDF = 5.025E-7/year Work Practices CDF = 5.371E-6/year
 
Delta CDF = 4.868E-6/year The LERF fraction for both ISLOCAs and steam generator tube ruptures is 1.0. Therefore the delta LERF is also equal to 4.868E-6/year. The significance bands for LERF are one order of magnitude lower than those corresponding to CDF. Consequently, for the case of poor work practices, the LERF significance is the same as the CDF significance.
 
The result is below the Regulatory Guide 1.174, "An Approach to Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis,"
limitations for a maximum total plant CDF. Regulatory Guide 1.174 makes use of the NRC's Safety Goal Policy Statement in evaluating increases in CDF and LERF. The safety goals
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define an acceptable level of risk that is a small fraction (0.1 percent) of the other risks to which the public is exposed. Regulatory Guide 1.174 specified that, if there is an indication that the total CDF may be considerably higher than 1E-4/year or 1E-5/year for LERF, the focus should be on finding ways to decrease the risk. The team noted that the total collective risk did not exceed the Regulatory Guide 1.174 upper limits.
 
Several defense in depth layers of protection are provided to protect the public and the environment from potential events. These include the integrity of the physical structure of the plant and its systems, the automatic initiation capabilities of the safety-related systems, the proceduralized operator manual actions to start equipment and initiate systems, and the ability of plant operators and technicians to restore, repair, or replace equipment as necessary. Poor work practices can degrade any of these defense-in-depth layers of protection, but would mostly cause a loss of efficiency and precision in the operators ability to take important manual actions, as well as the ability of the plant staff to restore non-functioning equipment. The team determined that there had been a reduction in defense in depth features because of the degradation of the CAP and human performance safety culture concerns; however, the reduction was not sufficient to result in an unsafe condition.
 
Collective Assessment of IP 95003 Findings Inspection Manual Chapter 0609, "Significance Determination Process," utilizes a counting rule to assess the significance of a performance deficiency. Using the Phase 2 plant specific worksheets, core damage sequences are assigned a range of numeric values.
 
Three sequences with the same numeric result are treated with the next lower value (e.g., three sequences with an "8" would be treated as one "7"). For the purpose of the collective review, the team assigned a significance determination process result of "8" for all findings screened as Green during the Phase 1 process. The counting rule was then used to determine the collective risk. This result was combined with any numerical results obtained as part of a Phase 3 SDP evaluation for an inspection finding. The emergency preparedness finding was assigned a value of 3.3E-6. Fifteen examples of findings were screened as Green during the Phase 1 SDP process (this included findings screened using IMC 0609, "Significant Determination Process," Appendix M, "Significance Determination Process using Qualitative Criteria"). Using the counting rule, this equates to a result of one "5". The team applied a CDF value of 3.3E-5/year from the counting rule result. The results from the Phase 3 SDP evaluation for the switchyard finding was 5.0E-7/year. The combined result was a CDF of 3.68E-5/year.
 
If all of the significant findings since 2004 were included, the total result would be between a range of 4.69E-5/year to 8.79E-5/year. This includes a range of 5.7E-6/year to 4.6E-5/year for the Yellow finding and 10 CFR 50.59 Severity Level III violation, an assigned value of 3.3E-6/year for the Emergency Preparedness Plan Change Severity Level III violation, and a range of 1.1E-6/year to 1.8E-6/year for the White finding. Both cases are below the Regulatory Guide 1.174 limitations for a maximum total plant CDF.
 
Qualitative Assessment Using Manual Chapter 0305 Criteria
 
Manual Chapter 0305 uses three criteria to assess the applicability of Manual Chapter 0350. The team's assessment of the Manual Chapter 0305 criteria are as follows:
1. Multiple significant violations of the facility's license, Technical Specifications, regulations, or orders.
 
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Multiple significant violations (greater than green for SDP findings or greater than Severity Level IV for non-SDP findings) have not recently occurred. Specifically, a Severity Level III violation of 10 CFR 50.59 and a Yellow finding related to the containment sump voiding issue occurred in 2004; a Severity Level III violation for the failure to obtain prior NRC approval for an emergency plan change was issued in 2005; and a White finding for the failure of an emergency diesel generator was issued in 2006.
 
In consideration of this attribute, the team reviewed significant violations identified since 2004, as well as the potentially significant emergency preparedness and overtime findings identified during the IP 95003 inspection. The team concluded that while there had been multiple significant findings dating back to 2004, the current assessment cycle did not have any significant findings. If the emergency preparedness and overtime findings are determined to be greater than Green (significant), they will be the only significant items identified during 2007. As such, this criterion would still not be met.
 
2. Loss of confidence in the licensee's ability to maintain and operate the facility in accordance with the design basis (e.g., multiple safety significant examples where the facility was determined to be outside of its design basis, either due to inappropriate modifications, the unavailability of design basis information, inadequate configuration management, or the demonstrated lack of an effective problem identification and resolution program).
 
The team determined that while the licensee's CAP is complicated and cumbersome, the CAP contained the basic elements of an effective program. Licensee personnel recognized the attributes of problem identification, evaluation, and resolution when interviewed; however, the knowledge and understanding was not consistently demonstrated to the NRC during the IP 95003 inspection. Nevertheless, multiple significant examples of problems with the design basis have not been identified; therefore, this criterion was not met.
 
3. A pattern of failure of licensee management controls to effectively address previous significant concerns to prevent recurrence.
 
A substantial degradation of the CAP has occurred. There have been repetitive failures in management controls to improve human performance and problem identification and resolution. There have also been several repetitive occurrences of risk important
 
equipment failures (auxiliary feedwater Target Rock steam admission valves, emergency diesel generator fuel and lube oil filters, safety injection system check valves, and essential cooling water heat exchanger fouling). The licensee has not had a recurrence of voided piping or emergency diesel generator K-1 relay failures following the issuance of the Yellow and White findings. Because the repetitive occurrences were determined to be of very low safety significance, this criterion was not met.
 
4 NRC METHODOLOGY AND DIAGNOSTIC ASSESSMENT 
 
The intent of IP 95003 is to allow the NRC to obtain a comprehensive understanding of the depth and breadth of safety, organizational, and performance issues at facilities where data indicate the potential for serious performance degradation. The objectives of the IP 95003 inspection are to: 
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: (1) provide additional information to be used in deciding whether the continued operation of the facility is acceptable and whether additional regulatory actions are necessary to arrest declining performance;
: (2) provide an independent assessment of the extent of risk significant issues to aid in the NRC's current assessment that an acceptable margin of safety exists;
: (3) independently evaluate the adequacy of facility programs and processes used to identify, evaluate, and correct performance issues;
: (4) independently evaluate the adequacy of programs and processes in the affected strategic performance areas;
: (5) provide insight into the overall root and contributing causes of identified performance deficiencies;
: (6) determine if the NRC oversight process provided sufficient warning of significant reductions in safety; and
: (7) independently assess the licensee safety culture and assess their evaluation of safety culture. A multi-disciplinary team conducted the inspection over the course of approximately nine months, with a total of five weeks of onsite inspection effort. The inspection implemented the applicable portions of IP 95003 necessary to assess the extent of performance problems that led to the licensee's entry into Column 4 of the NRC's Action Matrix, including the safety culture contributions to the performance problems, as well as the licensee's corrective action plan. The team performed an independent diagnostic review of numerous programs and processes with an emphasis on the reactor safety strategic performance areas. This provided the NRC with a comprehensive understanding of the depth and breadth of safety, organizational, and performance issues at PVNGS, in addition to the insights already gained from the IP 95002 inspections conducted in 2005 and 2006.
 
The team selected the containment spray syst em and the turbine driven auxiliary feedwater pump, high pressure safety injection pump, low pressure safety injection pump, and essential spray pond pumps. The selection of these components was based on the impact of component failure on large early release frequency and the completion of a detailed design review being completed by the licensee as part of their component design basis review. The team performed a review of the work performed on these components which involved multiple licensee organizations, including operations, maintenance, engineering, quality assurance, and management. With respect to these components, the team review included, as applicable, permanent and temporary design modifications (including implemented, planned, and cancelled modifications), procedure and drawing changes, ODs, operator work arounds, configuration control, maintenance, root and apparent cause evaluations, and various corrective action documents. Additionally, the team reviewed PVNGS programs and processes associated with human performance and PI&R.
 
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==REACTOR SAFETY==
STRATEGIC PERFORMANCE AREA 5.1 Licensee Controls for Identifying, Assessing, and Correcting Performance Deficiencies The licensee had multiple substantive crosscutting aspects associated with human performance and PI&R. Since 2004, the corrective actions implemented by the licensee had yet to sustain performance improvement as noted by licensee self assessments, external industry reviews, and NRC inspections. The team noted that licensee personnel often recognized appropriate CAP fundamentals and expected behaviors when interviewed; however, this knowledge and understanding of the program expectations was not consistently demonstrated. The team noted several examples of poor and inconsistent implementation of safety culture aspects associated with PI&R. Specifically:
* Licensee personnel did not recognize the need to initiate a PVAR, the licensee's corrective action document form, when a degraded condition was identified by the team. This particular behavior improved during the conduct of the inspection in response to the team's repeated questioning of licensee personnel on whether a PVAR was appropriate for NRC identified issues. The team noted that consistent re-
 
enforcement of expectations was needed to ensure PVARs would continue to be initiated following the team's departure.
* The team noted that a licensee component design basis review (CDBR) team (consisting largely of contractor personnel) was documenting issues that challenged the design basis at an appropriately low threshold. In contrast, Palo Verde engineering personnel considered these issues below the PVAR threshold or that the problems entered were not issues at all. This demonstrated a continuing lack of understanding on the part of Palo Verde engineering personnel of the level at which conditions adverse to quality should be documented in the CAP.
* The team noted a significant number of weak or non-existent operability determinations of degraded conditions affecting safety-related equipment, indicating an apparent lack of understanding of the need to assess operability for conditions adverse to quality and a lack of knowledge or skills necessary to conduct an operability assessment. This is a continuing weakness in the implementation of the CAP at Palo Verde and had a direct impact on maintaining nuclear safety margins. The inability to consistently perform ODs formed part of the NRC's basis for leaving open the Yellow finding involving voiding of the ECCS suction piping in all three units. Improvement in the operations and engineering departments are required for Palo Verde to effectively evaluate degraded conditions affecting safe plant operation.
* The team noted that a significant backlog review was required due to the large number of databases (at least 37) that existed outside of the corrective action process. The team identified that at least two databases existing outside of the recognized CAP contained conditions adverse to quality that had not been assessed for operability.
 
The Action Tracking System (ACT) database and the Bechtel non-conformance
 
reporting (NCR) database both contained conditions adverse to quality that were not evaluated for operability impacts until prompted by the team. Licensee personnel subsequently reviewed the databases and additional conditions adverse to quality that required operability assessments were identified. The placement of conditions adverse to quality in systems outside the CAP hindered the ability of operations
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personnel to assess challenges to the operability of structures, systems, and components (SSCs).
* The team identified that when conditions adverse to quality were recognized or evaluated within the CAP, the need to evaluate the extent of condition or impact to the other units was not always recognized.
* The team concluded that self-assessments completed by Palo Verde personnel lacked depth and did not effectively specify or implement corrective actions. As a result, the self-assessment program seldom resulted in improved organizational performance. The team did note one training self-assessment that had been recently conducted which had more depth and contained insightful observations. The team noted that this self-assessment was conducted by a mix of Palo Verde and non-Palo Verde personnel which may have led to the more meaningful self-assessment.
* The team's evaluation of root cause analyses determined that the analyses of problems did not consistently specify complete or adequate corrective actions, or establish timely corrective actions for significant conditions adverse to quality.
* The team identified that the licensee had difficulty determining the status or completion of corrective actions taken in response to significant issues. This was most apparent when licensee personnel could not effectively respond to a team request to communicate the status of corrective actions related to the Yellow finding for voiding of ECCS suction piping. The licensee could not effectively determine the completion status of these corrective actions nor had the actions been effectively evaluated for resolution of the issues. The licensee's IP 95002 Readiness/Effectiveness Report stated that the 95002 focus areas, "Seem to have been administratively forgotten."  In addition, the team noted that an ImPACT Checklist intending to evaluate the status of the Yellow finding, identified several problems; however, not all of the problems had
 
CAP actions written to address the identified issues.
* Licensee personnel were assigned corrective actions for significant conditions adverse to quality; however, processes were not consistently implemented to ensure corrective actions were completed or that effectiveness reviews of these actions were completed. The team identified that corrective actions taken in response to significant conditions adverse to quality were sometimes closed prior to completion of the corrective action.
 
This sometimes occurred when a significant action was closed to another document, which was subsequently closed prior to the completion of the action. In the past, the licensee used an unsuccessful approach t hat relied on individual management team members to verify significant corrective actions were complete and to evaluate their
 
effectiveness. More recently, the licensee instituted a Closure Review Board process to assess completion of significant corrective actions and to assess their effectiveness.
 
The team acknowledged that a management team review could be more successful in assuring the completion and effectiveness of corrective actions.
 
====a. Inspection Scope====
The team evaluated whether the licensee's CAP was sufficient to prevent further declines in safety that could result in unsafe operation. Specifically, the team reviewed:
: (1) licensee investigations, evaluations, and corrective actions taken in response to significant conditions adverse to quality;
: (2) audits and assessments
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conducted by the Nuclear Assurance Department, self-assessments by organizations, and external evaluations and assessments;
: (3) the effectiveness of the licensee's use of operating experience and industry information for previously documented performance issues;
: (4) historical and current resource allocations, as well as the current backlog and existing operator work-arounds;
: (5) the business plan to determine if licensee performance goals were congruent with corrective actions needed to address performance issues;
: (6) the employee concerns program as well as a significant number of focus group discussions with a cross-section of the licensee's workforce; and
: (7) the licensee's programs and processes in place to support improvement suggestions by employees and to provide employees feedback on issues they had identified.
 
====b. Findings and Observations====
b.1 Failure to Implement Operability Determination Process for Bechtel Nonconformance Reports 
 
=====Introduction.=====
The team identified an example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," for the failure of the licensee to follow procedures to evaluate conditions adverse to quality for impacts on the operability of safety-related
 
equipment.
 
=====Description.=====
On October 4, 2007, the team met with the licensee to discuss the quality assurance program requirements agreed to between the licensee and Bechtel for the conduct of the Unit 3 steam generator replacement outage, and how Bechtel nonconformance reports (NCR's) generated during this activity were reviewed by the licensee. The discussion was held in response to the team's identification of a condition adverse to quality associated with the rigging of the containment personnel airlock (PAL) door.
 
On October 6, 2007, the team questioned the CAP manager on how Bechtel NCRs were reviewed by the licensee for potential impacts to the operability of safety-related equipment. The team noted that a formal process to review NCRs for immediate operability did not exist. As a result of the team's questioning, the CAP manager initiated actions to review the NCR database. As a result, two NCRs were identified which documented conditions adverse to quality that affected safety-related equipment. Specifically, a piping support affecting shutdown cooling heat exchanger Train A had been inadvertently removed by Bechtel and an NCR was written to document the problem. No PVAR was generated and as a result, no operability assessment of the degraded condition was conducted. Shutdown cooling heat exchanger Train A was declared inoperable until an engineering evaluation determined the missing support did
 
not affect operability. A second Bechtel NCR was then identified that documented the inadvertent removal of steam generator weldment. This condition was subsequently determined not to affect operability of safety-related
 
equipment.
 
On October 8, 2007, the licensee generated a night order that required all NCRs generated by Bechtel to have PVARs written to assure operability assessments of conditions adverse to quality were conducted.
 
- 36 -
 
=====Analysis.=====
The failure to implement the OD process for conditions adverse to quality identified in the Bechtel NCR database was a performance deficiency. The finding is greater than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process,"
Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) because it only affected the mitigating systems cornerstone, and did not result in the loss of safety function. The cause of this finding had crosscutting aspects associated with decision-making of the human performance area in that licensee personnel did not make safety-significant or risk-significant decisions using a systematic process (H.1.(a)). This finding also had a safety culture component aspect in the area of accountability in that management did not reinforce safety standards associated with the need to perform operability assessments (O.1.(b)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires that activities affecting quality be prescribed by instructions, procedures, or drawings, and be accomplished in accordance with those instructions, procedures, and drawings. The assessment of operability of safety-related equipment needed to mitigate accidents was an activity affecting quality and was implemented by Procedure 40DP-9OP26, "Operability Determination and Functional Assessment," Revision 18. Procedure 40DP-9OP26, Step 3.1.1, stated the OD process was entered upon discovery of circumstances where operability of any SSC described in the Technical Specifications was called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition. Contrary to the above, between October 4 and 6, 2007, licensee personnel failed to enter the OD process upon discovery of circumstances where the operability of a component described in the Technical Specifications was called into question. Specifically, the removal of a shutdown cooling heat exchanger support and the removal of steam generator weldment were not evaluated for operability impacts to safety-related equipment. Because this finding is of very low safety significance and had been entered into the CAP as PVAR 3072732, this violation is being treated as an NCV, consistent with Section VI.A of the Enforcement Policy:  NCV 05000528, 05000529, 05000530/2007012-01, eight examples of the "Failure to Implement Operability Determination Process."  This was the first of eight examples associated with the licensee's failure to properly implement the OD program.
 
b.2 Failure to Implement Operability Determination Process for ACTs
 
=====Introduction.=====
The team identified a second example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," for the failure of licensee personnel to follow procedures to evaluate conditions adverse to quality for degraded or non-conforming conditions that required ODs or FAs.
 
=====Description.=====
On June 22, 2007, the Palo Verde ImPACT team documented that the ACT database contained conditions adverse to quality and that the, "Entire
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ACT database needed to be scrubbed to identify all discrepancies."  On August 29, 2007, the team requested the status of the ACT database "scrub," to determine whether additional conditions adverse to quality were identified in the ACT database since the June 22, 2007, roll-up, and whether these and the previous conditions identified on June 22, 2007, had been evaluated by a licensed senior reactor operator (SRO) for degraded or non-conforming conditions that would require ODs or FAs. The ImPACT team determined that additional conditions adverse to quality had been identified and that a PVAR had been generated; however, neither the previously identified ACT issues nor the more recently identified ACT issues had been assessed individually for OD or FA requirements as discussed in Procedure 01DP-0AP12, "Palo Verde Action Request Processing," Revision 3. An SRO evaluated the initial PVAR documenting the ACTs and determined that no impact to plant safety existed, but did not complete a review of each individual ACT in question. Subsequent to the team's questioning, an SRO reviewed each ACT that documented a condition adverse to quality. The ImPACT team subsequently informed the NRC team on September 4, 2007, that none of the conditions adverse to quality identified in the ACT database required further evaluation.
 
=====Analysis.=====
The failure to implement the PVAR process for conditions adverse to quality identified in the ACT database was a performance deficiency. The finding is greater than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable circumstances. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) because it only affected the mitigating systems cornerstone and each of the ACT database conditions adverse to quality were subsequently determined not to result in a loss of safety function. The cause of this finding had crosscutting aspects associated with decision-making of the human performance area in that licensee personnel did not make safety-significant or risk-significant decisions using a systematic process (H.1.(a)). The cause of the finding is also related to the safety culture component of accountability in that management failed to reinforce safety standards and display behavior that reflect safety as an overriding priority (O.1.(b)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires that activities affecting quality be prescribed by instructions, procedures, or drawings, and be accomplished in accordance with those instructions, procedures, and drawings. The evaluation of the need to forward degraded or non-conforming conditions documented in PVARs to the control room for OD or FAs was an activity affecting quality implemented by Procedure 01DP-0AP12. Procedure 01DP-0AP12 required that a SRO evaluate PVAR issues to determine whether a degraded or non-conforming condition exists in an SSC subject to the OD or FA process. Contrary to the above, between June 22 and September 4, 2007, licensee personnel did not assess individual conditions adverse to quality documented in ACTs and attached to a PVAR for the need to conduct an OD or FA.
 
This example is of very low safety significance and had been entered into the CAP as PVAR 3057126 and CRDR
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3058751. This was the second of eight examples associated with the licensee's failure to properly implement the OD program.
 
b.3 Failure to Implement Operability Determination Process for Spray Pond Missile Hazards
 
=====Introduction.=====
The team identified a third example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure of licensee personnel to follow procedures to evaluate conditions adverse to quality for impacts on the operability of safety-related equipment.
 
=====Description.=====
On August 29, 2007, the team conducted an external walkdown of Unit 1 with licensee personnel and identified approximately 20 unsecured metal bars (severe weather missile hazards) near the Unit 1 essential spray pond (ESP). Following prompting by the team, the licensee generated PVAR 3057285 on August 30, 2007, to address this condition.
 
The ESPs function as the ultimate heat sink. Spray headers, located above the surface of the ESPs, are used to maintain design temperature within safety analysis assumptions. There are no missile hazard ESP design features to protect the spray headers from airborne missiles and, as a result, they are vulnerable to airborne missiles generated during a high wind event. Procedure 81DP-0ZY01, "Control of Potential Tornado Borne Missiles in the Outside Areas," Revision 2, Section 1.1 stated the purpose of the procedure was to establish administrative controls for using and storing items in outside areas so the risk of losing the ESPs was within acceptable limits. Procedure 81DP-0ZY01, Appendix E, "Tornado Missile Density Criteria (Zones 1-14)," identified the average density limit at four missiles per 10,000 square feet (sqft) within a defined area around the ESP. The unsecured transient missiles identified by the team were within this defined area.
 
On August 30, 2007, a civil engineer conducted a tour of the area. PVAR 3057285 stated that the engineer determined that there was no operational impact on the spray pond headers because the condition did not exceed the operability basis of  4 missiles/sqft. This PVAR incorrectly referenced the guidance from Procedure 81DP-0ZY01, did not address the fact that there were more than 4 missiles, and contained no operations shift manager assessment of
 
the impact to the Unit 1 ESPs.
 
Procedure 40DP-9OP26, Revision 18, "Operability Determination and Functional Assessment," Section 3.1.1 stated that the OD process was entered upon discovery of circumstances where operability of any SSC described in the Technical Specifications was called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition. The team noted that the licensee did not enter the OD process on August 29, 2007, upon discovery of an unanalyzed condition (unsecured, transient missiles near the Unit 1 ESP).
 
Procedure 40DP-9OP26, Section 1.3 stated that the immediate OD was performed based on the best information available to on-shift personnel within a relatively short time, typically on the order of two hours. In this case, neither
- 39 -
engineering nor operations personnel notified the control room of the condition when PVAR 3057285 was generated. Instead a work control SRO reviewed PVAR 3057285 on August 31, 2007, and determined that a degraded condition no longer existed because PVAR 3057285 stated the 20 transient missiles were being removed and an analysis was completed satisfactorily.
 
Procedure 40DP-9OP26, Section 2.1 stated that the shift manager (SM) was responsible for the OD decision. In this case, the Unit 1 SM was not notified of the condition. PVAR 3057285 noted that the Unit 1 shift technical advisor, a non-licensed operator, was notified of the civil engineering evaluation completed on August 30, 2007, and that the 20 unsecured transient missiles would be removed by August 31, 2007. However, the shift manager was not informed and no assessment of operability was conducted.
 
=====Analysis.=====
The failure to implement the OD process to assess the impact of the unsecured, transient missiles on the operability of the Unit 1 ESP was a performance deficiency. The finding is greater than minor because it is associated with the external factors attribute of the mitigating systems cornerstone, and impacted the cornerstone objective of ensuring the availability, reliability, and capability of the ultimate heat sink to respond to initiating events. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) because the finding did not involve the loss of a safety function due to a severe weather initiating event. The cause of this finding had crosscutting aspects associated with decision making in the human performance area in that operations and engineering personnel failed to use conservative assumptions for operability decision-making when evaluating degraded and nonconforming conditions (H.1.(b)). This finding also had a safety culture component aspect associated with accountability in that workforce did not demonstrate a proper safety focus and reinforce safety principles among peers (O.1.(c)). 
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires that activities affecting quality be prescribed by instructions, procedures, or drawings, and be accomplished in accordance with those instructions, procedures, or drawings. The assessment of operability of the Unit 1 ESP was an activity affecting quality and implemented by Procedure 40DP-9OP26. Procedure 40DP-90P26, Step 3.1.1 stated the OD process was entered upon discovery of circumstances where operability of any SSC described in the Technical Specifications was called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition. Contrary to the above, between August 29 and 31, 2007, licensee personnel failed to enter the OD process upon discovery of circumstances where the operability of a component described in the Technical Specifications was called into question.
 
Specifically, operations personnel did not implement the OD process described in Procedure 40DP-9OP26 during the period from discovery of the issue to the removal of the missiles from the ESP area. This was the third of eight examples of the NCV associated with the failure to implement the OD program. This example was of very low safety significance (Green) and documented in the licensee's CAP as PVAR 3057285.
 
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b.4 Failure to Evaluate Abnormally High Lead Levels in Low Pressure Safety Injection Pump Bearing Oil
 
=====Introduction.=====
The team identified a fourth example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure of engineering personnel to determine the cause of an abnormally high lead content in the Unit 3 low pressure safety injection (LPSI)
Pump Train B upper motor coupling bearing oil, to establish periodic monitoring requirements, or to establish a lead content threshold upon which to take further action on a degrading condition.
 
=====Description.=====
On October 10, 2007, the team reviewed the OD associated with the Unit 3 Train B LPSI Pump high lead levels (258 parts per million (ppm)),
which had existed in the upper motor coupling bearing oil since May 2006. This coupling bearing was installed on all six LPSI pumps between 1995 and 2000. The other five LPSI pumps at the site had not exhibited this condition and had oil sample results of less than 1 ppm lead. The OD for this issue was documented in CRDR 2896417.
 
During the initial investigation in May 2006, the Unit 3 Train B LPSI Pump bearing oil was drained, flushed, and refilled with oil from a separate source. The oil samples from the upper motor coupling bearing continued to show abnormally high levels (242 ppm) of lead. The engineering evaluation concluded that there should be no component materials in the pump assembly that contain lead.
 
Maintenance personnel determined that the parts used during the modification were of the same type used for the other 5 LPSI pump modifications, whose current oil samples showed lead levels to be less than 1 ppm. Oil chemistry analysis determined that the lead particulates were relatively small and did not detect any abnormal bearing wear metals. Also, the LPSI Pump Train B vibration data remained within normal limits. On this basis, the licensee concluded the Train B LPSI pump was operable and discontinued their investigation into the cause of the high lead condition. Engineering personnel determined that the expected lead content for the motor coupling oil should be less than 1 ppm. The industry standard used in determining precursor failure criteria assumed the oil environment contained less than 10 ppm of lead content. The actual condition of the Unit 3 Train B LPSI pump upper motor coupling bearing was approximately 242 ppm following the drain, flush, and refill of the oil reservoir.
 
Procedure 40DP-9OP26, Revision 18, Section 1.3 stated that if a condition was determined operable but degraded/nonconforming, then a PVAR will pursue the appropriate corrective actions. The OD performed in May 2006 did not determine a cause for this existing condition, did not develop a monitoring plan, and did not develop a plan to take actions at predetermined thresholds in the event of a further degradation in lead levels. In response to the team's questions, the licensee initiated CRDR 3079670 on October 19, 2007, to determine the source of the lead particles in the Unit 3 Train B LPSI upper motor coupling bearing oil.
 
- 41 -
 
=====Analysis.=====
The failure to take measures to evaluate conditions adverse to quality, to establish a monitoring program, or to establish a threshold of when to take actions for a degrading condition was a performance deficiency. The finding is greater than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone, and impacted the cornerstone objective of ensuring the availability, reliability, and capability of the LPSI system to respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) because the finding did not result in an actual loss of Technical Specification equipment for greater than the allowed outage time. The cause of this finding had crosscutting aspects associated with corrective actions of the PI&R area because the licensee failed to take appropriate corrective actions to address safety issues and adverse trends in a timely manner (P.1.(d)). The cause of the finding was also related to the safety culture component of accountability in that management failed to reinforce safety standards and display behavior that reflected safety as an
 
overriding priority (O.1.(b)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires that activities affecting quality shall be prescribed by instructions, procedures, or drawings, and shall be accomplished in accordance with those instructions, procedures, and drawings. The assessment of operability of safety-related equipment needed to mitigate accidents was an activity affecting quality, and was implemented by Procedure 40DP-9OP26. Section 1.3 stated that if a condition was determined operable but degraded/nonconforming, then a PVAR will pursue the appropriate corrective actions. Contrary to this, between May 2006 and October 19, 2007, the licensee did not initiate a PVAR or CRDR to pursue the appropriate actions for a high lead content in the Unit 3 train B LPSI pump. Specifically, the licensee had not determined the cause of abnormally high lead levels in the Unit 3 Train B LPSI motor coupling bearing oil, did not establish a monitoring plan, and did not establish thresholds to take additional actions upon a degrading condition. This was the fourth of eight examples associated with the NCV involving inadequate implementation of the OD program. Thi s example was of very low safety significance (Green) and was documented in the licensee's CAP as PVAR
 
3075442.
 
b.5 Failure to Implement the Operability Determination Process on Unit 2 Essential Cooling Water Heat Exchanger A Sleeve Adhesive
 
=====Introduction.=====
The team identified a fifth example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure of operations and engineering personnel to adequately evaluate degraded and unanalyzed conditions to support operability decision making associated with the Unit 2 essential cooling water (EW) Heat Exchanger Train A epoxy sleeve adhesive degradation and leak. Specifically, on October 23, 2007, operations and engineering personnel failed to consider all relevant information to perform an adequate OD when evaluating Unit 2 EW Heat Exchanger Train A sleeve adhesive under chemistry conditions associated with the ESP system fouling identified in 2006.
 
- 42 -
 
=====Description.=====
The Unit 2 Train A EW Heat Exchanger developed a leak as noted by elevated chlorides from the ESP into the EW system on June 27, 2007. During a short notice outage on October 16, 2007, eddy current tests were performed to determine and repair the source of the leak. Three tubes were identified to be leaking, with location Row 2, Tube 26, found to have a leak underneath the tube sleeve. After the source of the leak was identified, operations and engineering personnel failed to validate the qualification of the epoxy with respect to chemistry conditions associated with ESP fouling identified in 2006. The epoxy was used to seal the EW heat exchanger tube sleeves into the heat exchanger. All of the Unit 2 EW Heat Exchanger Train A tubes were sleeved using the epoxy adhesive under limited design change package 2LM-EW-036. Unit 2 was the only unit to have sleeves inserted into the EW heat exchanger tubes.
 
The leak was determined to be underneath the tube sleeve. The sleeve adhesive was used to seal the sleeves to the heat exchanger tubes and to prevent potentially corrosive water from causing leaks under the tube sleeves. In response to the team's questions, the licensee initiated CRAI 3081800 on October 23, 2007, to determine whether the sleeve adhesive was a potential leak path under the Unit 2 EW Heat Exchanger Train A tube sleeves. However; no OD of the condition was conducted.
 
The team reviewed Design Change Package 2LM-EW-036 and Combustion Engineering Report TR-MCC-315, and determined the adhesive was tested under design assumptions indicative of 1993 plant conditions. The adhesive was not verified to perform under the chemistry conditions associated with the ESP fouling concerns identified in 2006. ESP fouling came to the NRC's attention as a result of unusual temperatures noted during a surveillance test of EDG 2B conducted on May 17, 2006. The NRC's review was documented in NRC Inspection Report 05000528, 05000529, 05000530/2006011. Significant CRDR 2897810 documented changes made to ESP chemistry after the fouling was identified, but no evaluation was documented on the potential effects of ESP
 
chemistry on the adhesive.
 
Procedure 40DP-9OP26, Step 3.1.1, stated that the OD process was entered upon discovery of circumstances where operability of any SSCs described in Technical Specifications was called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition. Since a CRAI was written without identification that a degraded or unanalyzed condition existed, the adhesive concern did not receive an OD as required by Procedure 40DP-9OP26. Per Procedure 01DP-0AP12, "Palo Verde Action Request Processing," Revision 1, if additional work mechanisms changed the original degraded/non-conforming evaluation, then the PVAR should be amended so that another degraded/non-
 
conforming evaluation can be performed.
 
After the team further questioned operations and engineering personnel, PVAR 3083892 was initiated on October 26, 2007, and an immediate OD was completed. The immediate OD evaluated the qualification of the adhesive used to seal the U2 EW heat exchangers with respect to ESP fouling chemistry conditions. Operations determined a reas onable expectation of operability of the EW heat exchangers existed based on testing of the adhesive, no existing leaks
- 43 -
under the remaining tube sleeves, and chemistry samples confirming no current ESP leakage into the EW system.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of operations and engineering personnel to adequately evaluate degraded and unanalyzed conditions to support operability decision making associated with the Unit 2 EW Heat Exchanger Train A epoxy sleeve adhesive degradation and leak.
 
This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affects the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had crosscutting aspects associated with decision making of the human performance area in that operations and engineering personnel failed to use conservative assumptions for operability decision-making when evaluating degraded and nonconforming conditions (H.1.(b)). The cause of this finding was also related to the safety culture component of accountability in that operations and engineering personnel failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," requires that activities affecting quality shall be prescribed by instructions, procedures, or drawings, and shall be accomplished in accordance with those instructions, procedures, and drawings. The assessment of operability of safety-related equipment needed to mitigate accidents was an activity affecting quality, and was implemented by Procedure 40DP-9OP26. Procedure 40DP-9OP26, Step 3.1.1, stated the OD process was entered upon discovery of circumstances where the operability of any SSCs described in Technical Specifications was called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition.
 
Contrary to the above, between October 23 and 26, 2007, operations and engineering personnel failed to enter the OD process upon the discovery of circumstances where the operability of a component described in Technical Specifications was called into question. Specifically, operations and engineering personnel failed to consider all relevant information to perform an adequate OD when evaluating the Unit 2 EW Heat Exchanger Train A sleeve adhesive under chemistry conditions associated with ESP fouling identified in 2006. This was the fifth of eight examples of the NCV associated with inadequate OD program implementation. This example was of very low safety significance and had been entered into the CAP as PVAR 3083892.
 
b.6 Failure to Implement the Operability Determination Process on the Unit 2 Essential Cooling Water Heat Exchanger A Tube Leak
 
=====Introduction.=====
The team identified a sixth example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure of operations and engineering personnel to adequately evaluate degraded and nonconforming conditions associated with a Unit 2 EW
- 44 -
Heat Exchanger Train A tube leak. Specifically, between June 27 and October 4, 2007, operations and engineering personnel failed to consider all
 
relevant information to perform an adequate OD when evaluating the Unit 2 EW Heat Exchanger Train A tube leak.
 
=====Description.=====
Unit 2 EW Heat Exchanger Train A developed a leak as seen by elevated chloride concentrations in the EW system from the ESP system. PVAR 3033604 was initiated on June 27, 2007. A control room review was performed and the Unit 2 EW Heat Exchanger Train A tube leak was determined to be bounded for leak rate and chloride concentration by a similar condition that occurred on the Unit 3 EW Heat Exchanger Train B on June 28, 2001, where operations personnel determined the condition did not impact operability.
 
A prompt OD was performed on June 29, 2007, in PVAR 3033604. The prompt OD determined there was no impact on operability based on the heat exchanger having adequate structural integrity, thermal performance, and spray pond inventory. Thermal performance was determined to not be impacted by the leak since Calculation 13-MC-SP-0307, "SP/EW System Thermal Performance Design Bases Analysis," Revision 8, assumed up to 257 of the 2575 tubes could be plugged and only 30 tubes were currently plugged.
 
The team reviewed Calculation 13-MC-SP-0307 and determined that the calculation assumed zero leakage of the heat exchanger tubes. Further, the team determined the control room review and prompt OD only evaluated chemistry concerns with respect to chloride concentrations. The team reviewed Specification 74DP-9CY04, "Systems Chemistry Specifications," Revision 51, and determined that other chemical constituents that are usually in the ESP system were not evaluated for their effects on the EW system. These constituents included dispersant, calcium hardness, and phosphate. The team also noted that the prompt OD did not have acceptance criteria for when leakage or chemistry parameters would render the Unit 2 EW Heat Exchanger Train A inoperable.
 
The team determined operations personnel should have performed an immediate OD on October 4, 2007, when the team questioned the validity of the initial OD.
 
Procedure 40DP-9OP26, Step 3.1.1, stated that the OD process was entered upon discovery of circumstances where operability of any SSC described in the Technical Specifications was called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition.
 
After questioning by the team, PVAR 3033604 was redirected to the control room for another immediate OD review on October 4, 2007. The immediate OD and subsequent evaluation determined the current leak rate was 2.6 gallons per hour and established a maximum acceptable leak rate of 3.3 gallons per hour, to ensure chemistry parameters remained within specification in the EW system.
 
The evaluation also determined that the leak rate would not affect the structural integrity or the heat removal design function based on the small size of the leak. On October 16, 2007, the licensee plugged the leaking tubes.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of operations and engineering personnel to adequately evaluate degraded and
- 45 -
nonconforming conditions to support operability decision making associated with the Unit 2 EW Heat Exchanger Train A tube leak. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had crosscutting aspects associated with decision making in the human performance area in that operations and engineering personnel failed to use conservative assumptions for operability decision-making when evaluating degraded and nonconforming conditions (H.1.(b)). The cause of this finding was also related to the safety culture component of accountability in that operations and engineering personnel failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," requires that activities affecting quality be prescribed by instructions, procedures, or drawings, and be accomplished in accordance with those instructions, procedures, and drawings. The assessment of operability of safety-related equipment needed to mitigate accidents was an activity affecting quality, and was implemented by Procedure 40DP-9OP26, Revision 18. Procedure 40DP-9OP26, Step 3.1.1, stated the OD process was entered upon discovery of circumstances where operability of any SSC described in the Technical Specifications was called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition. Contrary to the above, between June 27 and October 4, 2007, operations and engineering personnel failed to enter the OD process upon discovery of circumstances where the operability of a component described in the Technical Specifications was called into question. Specifically, operations and engineering personnel failed to consider all relevant information to perform an adequate OD when evaluating the Unit 2 EW Heat Exchanger Train A tube leak. This was the sixth of eight examples associated with the NCV involving inadequate implementation of the OD program. This example was of very low safety significance and had been entered into the CAP as PVAR 3033604.
 
b.7 Observations and Minor Noncited Violations Involving Licensee Controls for Identifying, Assessing, and Correcting Performance Deficiencies b.7.1 Corrective Action Program Implementation
 
=====Description:=====
The team reviewed CAP implementation and identified the following minor issues/observations:
 
During the week of October 2, 2007, the team noted that licensee personnel consistently failed to reco gnize conditions under which a PVAR would be required to document an adverse condition. Licensee personnel believed they needed to ensure that a degraded condition was a condition adverse to quality before they would consider initiating a PVAR. Throughout the inspection, the team continued to prompt the
- 46 -
licensee on initiating PVARs. The team noted improved performance by licensee personnel late in the inspection. However, the team could not conclude whether this was an artifact of the team being onsite or whether this would result in sustained improvement.
 
The team noted that the CDBR team documented issues at an appropriate threshold. However, the team also noted that engineering personnel incorrectly considered that the CDBR team was entering issues into the PVAR process that they considered below threshold or not worthy of review.
 
The team reviewed the quality of ODs to evaluate the effect of degraded conditions on safety-related equipment. The team also reviewed degraded and nonconforming conditions for which the licensee had not conducted any assessment of operability. In addition to the examples discussed on ODs in this report, the team noted a generally poor understanding of the insights necessary to conduct operability assessments of degraded conditions and a failure to recognize the need to conduct an operability evaluation. The team also noted failures to recognize the need to conduct an extent of condition review for identified degraded conditions. Poor operability assessments and program implementation have been a longstanding concern at Palo Verde.
 
The team identified that corrective actions for conditions adverse to quality were not always timely or were not completed. For example, the team identified that corrective actions to train personnel on apparent cause evaluations, which was a concern during the December 2006 NRC PI&R inspection, were still not completed in November of 2007. The licensee believed corrective actions to conduct 10 CFR 50.59 training for chemistry personnel were completed in November of 2006. However, the team determined that some chemistry personnel had not attended the required training and even though CRAI 2942350 was closed.
 
On October 4 and 9, 2007, the team observed Corrective Action Review Board (CARB) meetings and noted the following observations; the CARB meeting was frequently interrupted, management personnel did not appear prepared for or dedicated to the CARB meeting and frequently left the meeting to answer cell phone and pager calls, the quorum was lost when the minimum number of managers required was not maintained as personnel left the meeting, and the meeting was cut short or cancelled due to the number of distractions or due to other meetings considered to have a higher priority. The team noted that the CARB members did not challenge the disruptive behaviors and did not hold themselves accountable for their participation in the meeting.
 
b.7.2 Problem Identification and Resolution Root Cause Report
 
=====Description:=====
The team reviewed the PI&R Root Cause Report issued in August 2007. The team noted the following weaknesses in the PI&R
 
report:
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On July 9, 2007, the licensee initiated CRAI 3038014, a corrective action to prevent recurrence (CAPR), for the root cause of the failure to correct continued poor accountability behaviors with implementation of the CAP.
 
As of November 2, 2007, CRAI 3038014 was not completed. The PI&R root cause CAPR was to conduct a site wide stand-down in order to communicate CAP fundamentals to station personnel, managers, and supervisors. The PI&R root cause report CAPR defined the fundamentals that needed to be communicated and specified the forum in which to communicate the fundamentals (site wide stand-down); however, the assigned CAPR completion date was December 28, 2007. The team noted that this action was untimely considering that the Unit 3 refueling outage was scheduled to start in October 2007. The team did note that limited CAP discussions were conducted by site senior management during weekly video presentations leading up to the Unit 3 refueling outage; however, the discussions did not include all of the CAP fundamentals described in the PI&R root cause.
 
The team noted that the PI&R root cause report discussed the lack of Specific, Measurable, Achievable, Reasonable, and Timely (SMART) corrective action criteria in CAP procedures and prior root cause reports. The team recognized that the PI&R root cause report contained CRAI 3038040 to identify SMART criteria in the condition reporting procedure and in the root cause evaluation manual. However, the team's review of the corrective actions identified in the PI&R root cause report noted a similar lack of SMART criteria (CRDR 3071645) in the PI&R root cause report corrective actions. In general, the team noted that the PI&R root cause report corrective actions (e.g., communication of CAP standards and fundamentals) were not timely in consideration of the existing weaknesses in the CAP. Also, the team noted that the continuing problems identified with the OD process that have been identified by the NRC over the last several years, and which continued to occur during this inspection, were not discussed in any great detail in the PI&R root cause.
 
The only PI&R root cause report corrective action related to this program was to conduct a self-assessment of the OD program by June 30, 2008. The team did not consider this action timely given the problems identified with the implementation of the OD process.
 
The team noted that the PI&R root cause report described the CAP as
 
comprising the PVAR, CRDR, corrective maintenance program, engineering deficiency work process, OD and FA evaluations, and the warehouse discrepancy notice program. However, the PI&R root cause report did not recognize that the exis tence of this many tracking systems had contributed to the complexity of the licensee's CAP; thereby, creating vulnerabilities to CAP implementation. This is consistent with the results of interviews conducted during the inspection which identified that licensee personnel did not see a difference between their multiple database process and the more prevalent nuclear industry one form process. In addition, the PI&R root cause did not recognize the existence of other tracking systems (such as the ACT and Bechtel NCR databases)which potentially included multiple unrecognized conditions adverse to quality outside of the defined CAP.
 
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In March 2005, Palo Verde initiated significant CRDR 2780286 to perform a root cause investigation of the substantive crosscutting issues in PI&R.
 
The identified root cause was management behaviors, in that they did not hold themselves and others to high standards relative to the CAP. The CAP substantive crosscutting area self assessment performed in preparation for the ImPACT in 2007 determined that a new root cause analysis did not need to be conducted, primarily because significant CRDR 3015327 was already in progress to determine why the corrective actions from CRDR 2780286 had not been effective. The identified root cause in CRDR 3015327 was inadequate personnel and organizational accountability. The evaluation determined that many of the CAPRs and corrective actions implemented by CRDR 2780286 were conceptual, poorly conceived, and did not follow the SMART model. Consequently, they were not effectively implemented. Examples included CRAI 2828390 (revise the Palo Verde Business Plan to reflect the CAP as a strategic focus area), CRAI 2828392 (develop improved CAP metrics),
and CRAI 2828404 (revise the Palo Verde expectations and standards booklet to include the CAP). The team determined that the ineffective corrective actions from CRDR 2780286 had not been incorporated into the SIBP/SIIP. The team reviewed the SIBP/SIIP and determined that the corrective actions for CRDR 3015327 had been incorporated. Because the SIBP/SIIP was in draft form, and many of the proposed actions had not yet been implemented, the team was unable to evaluate whether the actions will be effective in correcting the PI&R issues the site is
 
experiencing.
 
The team reviewed a number of other root cause reports and noted similar issues including; the failure to identify all contributing causes, the failure to specify SMART corrective actions, a lack of timely corrective actions, an inability to track the completion of or determine the status of corrective actions taken in response to significant conditions adverse to quality, and the closure of corrective actions taken in response to significant conditions adverse to quality that had not been implemented or
 
completed.
 
b.7.3 Action Request Review Committee
 
=====Description:=====
The team attended several Action Request Review Committee (ARRC) meetings. The ARRC was established following the implementation of the PVAR process to review and disposition each
 
PVAR to implement an effective CAP. The team noted the following weaknesses in the conduct of the ARRC activities:
The team noted that the ARRC members frequently debated whether a given condition documented in a PVAR was actually an adverse condition. One ARRC member commented that if the subject condition was considered adverse, "Then we would have hundreds of adverse conditions."  The team noted that an adverse condition should be judged as adverse based on its characteristics, not whether it would subsequently result in a high number of adverse conditions being documented.
 
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The team observed that ARRC members would call personnel in the field to resolve a degraded conditi on and would then close the PVAR to actions taken. The team noted that this had the appearance of the ARRC acting as first line supervisors to correct conditions adverse to quality rather than as a multi-discipline team to review and disposition PVARs for corrective actions by responsible organizations.
 
ARRC members were observed to be rewriting PVARS rather than returning them to the initiating organization. This prevented the initiating organization from learning from the lack of a complete PVAR description and precluded the originating organization (i.e., the organization "in the know") from providing the most accurate information regarding the condition.
 
An ARRC member was observed to be overly biased against a PVAR that he considered should not have been written and stated to the group that he would handle this particular PVAR, and that he would tell the originator that this was not a problem. It was apparent to the team that the originator would receive negative feedback on the generation of this PVAR from the ARRC member rather than allowing the PVAR process to evaluate and resolve the condition. The team also noted that the other ARRC members did not intercede, allowing this negative behavior to continue.
 
The ARRC could determine no correctiv e actions were necessary by designating a "Review" CRDR with no actions needed. The ARRC also appeared to be conducting evaluations and specifying corrective actions for PVAR issues. The team noted that this could put the ARRC in the position of specifying corrective actions rather than dispositioning PVARs to the responsible organization for review and created a vulnerability to bypassing organizational processes for evaluating conditions adverse to quality.
 
The team determined that the management oversight provided to the ARRC, a relatively new review co mmittee, was insufficient given the number and depth of NRC observed concerns. The team discussed these ARRC observations with the Performance Improvement and CAP managers. In response to these concerns, the licensee initiated PVAR 3072299 and an ARRC improvement strategy was generated. The ARRC Charter was revised, some ARRC members were reassigned, new
 
members were designated, and briefings were conducted with ARRC members on the vision and expectations of the ARRC. The team noted some improvement following these actions; however, the team also noted some of the poor behaviors were repeated during subsequent ARRC sessions.
 
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b.7.4 Backlog Review
 
=====Description:=====
The team reviewed the licensee's efforts in defining and evaluating the existing backlog and had the following observations: 
 
The team noted that there were over 250 OD backlog entries. The characterization of this many ODs as part of a backlog could be confusing since open ODs generally documented current degraded or nonconforming equipment conditions that had been evaluated as not affecting the ability of equipment to meet intended safety functions, but that had not yet been corrected. At Palo Verde, ODs were kept open, even if full qualification was restored, until all associated corrective actions had been completed. The team noted that this approach may dilute the significance of how issues documented under the OD process were viewed and could confuse the organization and impact the ability to effectively evaluate the aggregate impact of degraded and nonconforming conditions on plant equipment.
 
The licensee's backlog review team identified that items in the activity tracking (AT) database had a low priority review need because ATs, "did not perform physical work."  The team identified that some AT entries appeared to perform physical work, such as AT work order (WO) 220774, which required vibration readings to be taken on plant equipment.
 
Following the team's observations, the backlog review team reassessed their decision not to review ATs. On October 31, 2007, the licensee identified approximately 54 out of 3901 AT WOs that appeared to perform physical work. The licensee determined that several of the items should
 
not have been entered into the AT database. No degraded or non-conforming conditions were identified which would have affected safety-related or other plant equipment. The team noted that the decision to not review ATs assumed proper implementation of licensee programs and processes and that prior decisions were valid. The apparent unwillingness of licensee personnel to question decisions made during a period of declining performance was a significant vulnerability for the licensee. As noted during the SIBP/SIIP review, the licensee had not developed any actions to evaluate the legitimacy of past decisions. PVAR 3074083, CRDR 3079482, and CRAI 3079483 were generated to document this issue.
 
The team discussed the status of the ACT database review with the backlog review team. The backlog review team indicated that they were nearing completion and that they were verifying whether the ACTs of concern were in fact conditions adverse to quality. The team noted that the backlog review team appeared to be spending an inordinate amount of time verifying whether they considered a given ACT concern to be an issue adverse to quality rather than initiating a PVAR and letting the CAP determine the significance and required corrective actions.
 
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b.7.5 Self Assessments
 
=====Description:=====
The team reviewed a number of self-assessments and had the following observations:
A significant number of self-assessments conducted by Palo Verde personnel lacked depth and did not challenge the assessed organization.
 
The recommendation for the November 2006 decision-making self-assessment was vague because it only requested an Operational Decision Making Instruction (ODMI) review and provided no further details on current ODMI weaknesses. The only recommendation from the December 2005 Operational Decision Making self-assessment was to combine two procedures. The March 2007 work management self-assessment concluded that the assessment needed to be re-performed later in 2007 and provided no other insights. The self-assessment of the maintenance rule program did not recognize that unavailability and reliability performance criteria could not be validated and that numerous systems had non-conservative performance criteria.
 
Self-assessment corrective actions were not always tracked nor did they always have PVARs written to document the expected corrective actions. The December 2006 leadership self-assessment recommended the initiation of a mentoring program that was later postponed several months. The decision was influenced by the upcoming change in senior management. Deficiencies described in the assessment of the safety injection system and environmental qualification assessments were not entered into the CAP.
 
In one case, the team noted that a recent training assessment appeared to be more probing and insightful. The team observed that the makeup of the training self-assessment team included a mix of licensee and industry personnel which may have led to the better assessment product when the
 
experiences of industry personnel were used.
 
5.2 Design Weak engineering program and process implementation had been a continuing problem at Palo Verde. The team noted numerous instances of design errors and omissions, and an overall lack of technical rigor. Specifically:
The team noted that the CDBR effort was effective in identifying design issues. The composition of the group included both site engineering and contractor support. The success of this effort could be attributed to the broader perspective that the group had due to the external contractor support. Although the CDBR effort had identified issues at the appropriate threshold, the team noted instances in which issues entered into the CAP were not appropriately addressed. The team also noted that a cumulative impact review of all of the CDBR issues for a particular system or component could further reduce the available margin.
 
The team noted several design documents had inadequate or unverified design assumptions. For example, Calculation13-MC-SP-306, "MINET Hydraulic Analysis of
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SP System," Revision 4, stated values for essential spray pond net positive suction head and submergence requirements to prevent vortexing, but the values were for generic pump design and did not ensure operation under the specific PVNGS design basis conditions, such as worst case ESP temperature.
 
The team noted that the engineering organization lacked a consistent questioning attitude. Reviews and evaluations often addressed the simplest or primary causes only. Extent of condition reviews, operability evaluations, and conditions dealing with off-normal operations were frequently not well documented. When questioned by the team, engineering personnel needed to perform further evaluation and documentation to support the technical position.
 
====a. Inspection Scope====
The team reviewed licensing and design basis documents for safety injection, ESP, and auxiliary feedwater (AF) systems, including the UFSAR, calculations, engineering analyses, system descriptions, CDBR reports, and self assessments to determine the functional requirements of the systems for normal, abnormal, and accident conditions.
 
The team reviewed a sample of risk-significant plant modifications for the selected systems, including those that involved vendor supplied products and services to determine whether the changes had an adverse impact on the ability of the systems to perform their design basis functions and determine whether the changes would result in an unexpected initiating event. During this review, the team evaluated the effectiveness of the licensee in controlling design and licensing information, in providing necessary calculations to support plant changes, and in developing and implementing thorough post-modification testing procedures. The team assessed the adequacy of the license's engineering products in evaluating applicable system and support system design attributes and regulatory requirements.
 
The team conducted general walkdowns of the selected systems and components.
 
Recent changes to plant maintenance and operating procedures were reviewed to ensure that they did not result in inadvertent design changes to the systems. For procedures that involved design changes, the team ensured that the change was subjected to the appropriate design change processes, including a review in accordance with 10 CFR 50.59, "Changes, Tests, and Experiments."  The team also reviewed a sample of PVARs to assess the effectiveness of corrective actions for deficiencies involving design activities. Additionally, the team reviewed a sample of engineering training programs to verify that training programs were consistent with the current design.
 
====b. Findings and Observations====
b.1 Failure to Implement Adequate Design Controls for Condensate Storage Tank Temperature
 
=====Introduction.=====
The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for the failure of engineering personnel to translate design basis maximum condensate storage tank (CST) temperature requirements into procedures to ensure the plant is operated within its design basis.
 
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=====Description.=====
On October 4, 2007, the team questioned engineering personnel with regards to the control of the maximum CST temperature. A CST maximum temperature of 120°F was used in Calculation 13-MC-CT-0205, "Condensate Storage Tank," Revision 4, Calculation 13-MC-CT-0307, "CST Minimum Level Setpoint," Revision 4, and Calculation 13-MC-AF-0309, "AF Hydraulic Calculation for Q-Trains," Revision 7, to ensure sufficient CST volume and net positive suction head for the AF pumps during a design basis accident. Neither operations nor maintenance and testing personnel took routine recordings of CST temperature, the parameter was not monitored by Technical Specifications, and no alarm existed for high CST temperature to ensure operation within the design basis maximum temperature of 120°F.
 
The 120°F CST maximum temperature was based on summertime ambient weather conditions affecting water temperature. The team noted that hotwell condensate from the main condenser was rejected to the CST during startup, shutdown, and on a high hotwell level. When the hotwell was rejected to the CST, the potential existed to exceed the 120°F maximum temperature limit because the condensate average temperature during July and August 2007 was
 
130°F.
 
Following the team's questions on control of CST temperature, engineering
 
personnel initiated PVAR 3073243. Operations personnel determined this condition was not a degraded or nonconforming condition, and an immediate OD was not performed due to current ambient temperatures being significantly lower than the maximum tank temperature, and due to establishing compensatory measures through a night order on October 11, 2007. The night order identified the deficiencies in monitoring CST temperature and directed operations personnel to take CST temperature readings once per shift, and contact system engineering personnel if temperature exc eeded a lower administrative limit of 110°F. On November 13, 2006, PVAR 2949167 was written to evaluate how AF pump heat load contributions were not considered in determining maximum CST temperature. The team determined that the failure to consider other inputs that could raise CST temperature during the licensee's review of PVAR 2949167 was a missed opportunity.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of engineering personnel to adequately translate the design basis CST maximum temperature requirements into applicable procedures. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had crosscutting aspects associated with corrective action of the PI&R area in that engineering personnel failed to thoroughly evaluate problems such that resolutions ensured that the problems were resolved. (P.1.(c)).
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=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that the design basis for SSCs be translated into specifications, drawings, procedures, and instructions. Contrary to the above, since 1985, engineering personnel failed to correctly translate design basis information into specifications, drawings, procedures, and instructions. Specifically, engineering personnel failed to translate design basis maximum CST temperature requirements into procedures to ensure the plant is operated within its design basis. This example was of very low safety significance and was entered into the CAP as PVAR 3073243, this violation was treated as an NCV consistent with Section VI.A of the Enforcement Policy:  NCV 05000528, 05000529, 5000530/2007012-02, "Failure to Implement Adequate Design Controls."
 
b.2 Inadequate Installation of Fire Sprinklers 
 
=====Introduction.=====
The team identified a Green NCV of License Condition 2.C(6) for the failure to install sprinkler heads in accordance with the FP program.
 
Specifically, on October 2, 2007, the team identified several upright fire sprinkler heads in the auxiliary building that were incorrectly installed in a pendent or downward orientation.
 
=====Description.=====
During walkdowns of the Unit 3 auxiliary building high pressure safety injection Train A pump room, the team identified that a FP sprinkler was installed in the wrong orientation. The sprinkler was located in a drop line for coverage below a heating ventilation and air conditioning unit and above cable Tray 3EZACCATCBA. The sprinkler head was an upright style; however, the sprinkler head was installed in a downward orientation. The team also identified that the sprinkler head in an alcove area on the 40 foot elevation of the LPSI pump room was installed in the incorrect orientation.
 
The team questioned engineering personnel on the orientation of these sprinkler heads. License Condition 2.C(6), "Fire Protection Program," stated that the licensee shall implement and maintain in effect all provisions of the approved FP program as described in the UFSAR for the facility, as supplemented and amended, and as approved in the Safety Evaluation Report (SER) through Supplement 11, subject to the following provision: the licensee may make changes to the approved FP program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.
 
UFSAR Section 9.5.1.2.1.F stated that automatic preaction sprinklers, hydraulically designed using National Fire Protection Association (NFPA) Pamphlet No. 13 (1976) as guidance, are provided to protect the areas so indicated in Table 9.5-1. Each automatic preaction system contains piping supervised by service air and fusible link sprinkler heads arranged such that flow densities meet the guidelines of the American Nuclear Insurer, and also NFPA Pamphlet No. 13 (1976). NFPA Pamphlet No. 13 (1976) Section 3-15.2.2 stated that the character of the discharge of sprinklers is such that it is necessary to use two distinct designs, one approved for the upright and the other approved for the pendent position.
 
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The team determined the three listed upright type sprinkler heads were found installed in a downward position. In the installed configuration, there was no testing to demonstrate that sprinklers would be capable of achieving the required flow or densities. Engineering personnel initiated PVAR 3073824 to address these issues.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure to install sprinkler heads in accordance with the FP program. This finding is greater than minor because it was associated with the mitigating systems cornerstone attribute of external factors and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding was determined to require additional evaluation under Manual Chapter 0609, Appendix F, "Fire Protection Significant Determination Process," because it was associated with the suppression element of defense-in-depth. Since the installation of the sprinkler heads represented a low degradation of the fire suppression system, in accordance with Section 1.3.1 of IMC 0609, Appendix F, the finding is determined to have very low safety significance.
 
=====Enforcement.=====
License Condition 2.C(6), "Fire Protection Program," stated that the licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility, as supplemented and amended, and as approved in the safety evaluation
 
report through Supplement 11, subject to t he following provision:  the licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. UFSAR Section 9.5.1.2.1.F stated that automatic preaction sprinklers, hydraulically designed using NFPA Pamphlet No. 13 (1976) as guidance, are provided to protect the areas so indicated in Table 9.5-1. Each automatic preaction system contains piping supervised by service air and fusible link sprinkler heads arranged such that flow densities meet the guidelines of the American Nuclear Insurer, and also NFPA Pamphlet No. 13 (1976). NFPA Pamphlet No. 13 (1976) Section 3-15.2.2 stated that the character of the discharge of sprinklers is such that it is necessary to use two distinct designs, one approved for the upright and the other approved for the pendent position. Contrary to the above, as of October 2, 2007, three listed upright type sprinkler heads were found in the untested pendent position. Because the finding was of very low safety significance and was entered into the CAP as PVAR 3072557, this violation was treated as an NCV, consistent with Section VI.A of the Enforcement Policy: NCV 05000530/2007012-03, "Inadequate Installation of Fire Sprinklers."
 
b.3 Failure to Enter Environmental Qualification (EQ) Self Assessment Deficiencies into the Corrective Action Program 
 
=====Introduction.=====
The team identified an example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure of engineering personnel to promptly identify and correct a significant condition adverse to quality described in an environmental qualification self assessment
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report. Specifically, the licensee had not evaluated or removed unqualified tape used to repair Anaconda conduit from the containment buildings.
 
=====Description.=====
EQ Self Assessment No. 2957427, issued July 2, 2007, found that Engineering Change Evaluation (ECE), ECE-ZZ-A143, "Anaconda Degraded Sealtite Repair Material, Scotch 33 Tape, Revision 1," was used as a basis for the prompt OD for degraded Anaconda "Sealtite" flexible conduit (CRDRs 2940338, 2940354, and 2940359). The ECE did not address the worst-case in-containment radiation dose. Under the worst case radiation levels, the tape was calculated to be exposed to the combined normal, accident gamma, and accident beta of over 300 Mrad. However, the ECE only evaluated the tape up to radiation levels of 100 Mrad. Although the condition was identified in the self assessment, it was not entered into the CAP and evaluated as a condition adverse to quality. Based on concerns raised by the team, PVAR 3073528 was written to evaluate why an adverse condition was not dispositioned properly in the CAP and to evaluate the extent of condition for other issues in the EQ self assessment.
 
The team was also concerned that the failure of the tape during an accident could also result in the failure of the repaired flexible conduit. The additional debris caused by this condition would contribute to containment sump loading. In response, engineering personnel initiated PVAR 3071831, to evaluate the potential impact of the additional tape and conduit sheathing loading on the containment sump. Since Unit 3 was in a refueling outage at the time of discovery and not impacted by the condition, engineering personnel evaluated the impact of current operability on Units 1 and 2. Approximately six months prior to the NRC team identifying the concern, Palo Verde replaced the Unit 1 sump strainers. The new Unit 1 strainers size was increased from 210 square feet to 3142 square feet. Since Unit 2 was still configured with the smaller strainers, engineering personnel evaluated this as the bounding condition. In their evaluation, engineering personnel estimated that there would be approximately 45 square feet of additional loading on the containment sump strainers and concluded that there was still adequate margin for operation.
 
Subsequent to this evaluation, Unit 1 experienced a forced outage. On October 26, 2007, as part of work Order 3034098, the licensee conducted a containment walkdown to quantify and remove susceptible tape and flexible conduit in containment. The licensee estimated that there was in excess of 600 square feet of combined tape and conduit that had not been accounted for in the sump loading analysis and initiated PVAR 3083224, to evaluate the condition.
 
The licensee concluded that with the larger strainers, the additional loading would have little impact.
 
The licensee conducted additional analyses to evaluate the past operability of the strainers in the Unit 1 containment. The licensee evaluated the realistic radiation dose that the 639 square feet of tape and conduit outside the bio-shield wall would be exposed to and determined that it was substantially below the qualified rating of 100 Mrads. Specifically, the realistic accident total integrated dose (TID) within containment (wetted or dry but not submerged) during a loss-of-coolant-accident was calculated to be approximately one-fifth of the TID values reported in the bounding calculation of record 13-NC-ZC-105, Revision 9, or 58 Mrads.
 
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The 148 square feet of tape and flex conduit material found within the bio-shield in Unit 1 also exceeded previous estimates. Generally, material within this zone was more of a concern for containment sump strainer loading because it was assumed that all material within the high energy break zone of influence would be destroyed and potentially transported to the sump. Consistent with the approach used for assessment of other potential debris source terms, engineering personnel conducted a review of the tape's physical properties and established that the specific gravity for the tape was approximately 1.3.
 
Therefore, the debris generated within the bio-shield wall may be transported out of the steam generator compartment, but would have sufficient time to settle prior to realignment of the ECCS pump suctions to the containment sump. Additionally, most, if not all, of the material deposited outside the steam generator compartment would remain submerged and in place since the maximum flow velocities in and around this area were below the minimum velocity required for incipient motion of the debris.
 
The team determined that since the actual TID was less than the qualification rating for the tape outside the bio-shield wall, it would likely maintain its integrity and not fail as a result of realistic radiation exposure. In addition, for conditions in which the additional materials could be susceptible to high energy line break effects, the specific characteristics of the material, transport velocities, and actual location precluded any significant challenge to the containment sump loading assumptions.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure to enter a condition adverse to quality into the CAP. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had crosscutting aspects associated with self assessment of the PI&R area in that the licensee did not follow their benchmarking and self assessment guide to ensure findings were evaluated in the CAP (P.3(c)). The cause of the finding was also related to the safety culture component of accountability in that management failed to reinforce safety standards and display behavior that reflected safety as an overriding priority (O.1.(b)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires that measures be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, between July 2 and October 4, 2007, the licensee did not assure that conditions adverse to quality were promptly identified and corrected. Specifically, conditions adverse to quality identified in EQ Self Assessment No. 2957427 were not entered into the CAP or corrected in a timely manner. Because the finding was of very low safety significance and was entered into the CAP as PVARs 3073528, 3071831, and 3083224, this violation was treated as an NCV, consistent with Section VI.A of the Enforcement Policy:  NCV:  05000528, 05000529, 05000530/2007012-04, "Six Examples of the Failure to Implement Corrective Action Program
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Requirements."  This was the first of six examples of the failure to implement the corrective action program requirements.
 
b.4 Failure to Implement Corrective Actions for Operating Experience Involving the Turbine Driven Auxiliary Feedwater Pump Trip and Throttle Valve 
 
=====Introduction.=====
The team identified a second example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure of engineering personnel to identify, evaluate, and correct degraded and nonconforming conditions associated with OE applicable to the AF pump trip and throttle valve (T&TV). Specifically, between February 8 and October 2, 2007, engineering personnel did not enter applicable OE on the mechanical overspeed trip mechanism for the AF turbine T&TV into the CAP.
 
=====Description.=====
On February 8, 2007, system engineering reviewed industry OE from South Texas (OE24167) and Saint Lucie (OE24002) in order to determine the applicability to Palo Verde. The OE described failures of the turbine driven AF pump T&TV's mechanical overspeed trip mechanism to trip on demand due to rust forming on mating surfaces between the trip-hook and latch-up lever. System engineering determined this OE was applicable to PVNGS and that current preventative maintenance (PM) tests would not detect this failure.
 
On February 8, 2007, engineering personnel initiated ACT 3046427 to incorporate force measurements needed to trip the T&TV into the existing overspeed trip linkage PM tests. The OE review was documented in the January to June 2007, AF system health report. The team determined engineering personnel should have entered Procedure 65DP-0QQ01, "Industry Operating Experience Review," Revision 13, which stated that ACTs can be used to track industry OE when related actions are not corrective or adverse in nature. The team questioned whether OE that was determined to be applicable to the site and where current PMs could not detect the failure should be entered into the CAP, not the ACT process. After further review by engineering personnel, the licensee determined that a PVAR should have been written instead of an ACT, and an OD should have been performed.
 
The assessment of operability of safety-related equipment needed to mitigate accidents was an activity affecting quality, and was implemented by Procedure 40DP-9OP26, "Operability Determination and Functional Assessment," Revision 18. Procedure 40DP-9OP26, Step 3.1.1, stated that the OD process is entered upon discovery of circumstances where operability of any SSCs described in Technical Specifications is called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition. Since an ACT was written instead of a PVAR, the OE on the AF Pumps T&TVs did not receive an OD as required by Procedure 40DP-9OP26.
 
In response to the team's observations, on October 2, 2007, engineering initiated PVAR 3070597 to address the potential for the turbine driven AF pump T&TV's mechanical overspeed trip mechanism to fail to trip on demand due to rust forming on mating surfaces between the trip-hook and latch-up lever. Operations personnel performed an immediate OD and noted that a reasonable expectation of operability existed because the T&TVs were in a less harsh environment than
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Saint Lucie and South Texas and had not experienced the rust problems seen at those facilities. The licensee changed ACT 3046427 to CRAI 3072364 to ensure the item was entered into the CAP. CRAI 3072364 was initiated to include steps in work order WSL245709 to ensure the T&TV trip levers trip at a value less than 25 pounds force, as specified in (EPRI) Manual, "Terry Turbine Maintenance Guide AFW Application."  Engineering management also provided additional training to engineering personnel on the differences between when to initiate an ACT and when to initiate a PVAR.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of engineering personnel to adequately evaluate degraded and nonconforming conditions to support operability decision making associated with OE applicable to AF Pump T&TV. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affects the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences.
 
Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had crosscutting aspects associated with OE of the PI&R area in that engineering personnel failed to ensure implementation and institutionalization of OE through changes to station processes, procedures, equipment, and training programs (P.2.(b)). The cause of this finding was also related to the safety culture component of accountability in that engineering personnel failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that measures be established to ensure that conditions adverse to quality are promptly identified and corrected. Contrary to this, between February 8 and October 2, 2007, engineering personnel failed to ensure that conditions adverse to quality were promptly identified and corrected. Specifically, engineering personnel failed to enter applicable OE on the mechanical overspeed trip mechanism for the AF pump T&TV into the CAP. As a result, testing to demonstrate the functionality of the overspeed trip mechanism was not performed and an operability assessment of the degraded and nonconforming condition was not completed. This was the second example of the NCV involving failure to implement the CAP requirements. This finding was of very low safety significance and was entered into the CAP as PVAR 3070597.
 
b.5 Observations and Minor Violations Involving Design b.5.1 High Pressure Safety Injection Pump Bearing Modification
 
=====Description.=====
The team identified an observation associated with a lack of technical rigor during the development of a modification associated with the high pressure safety injection (HPSI) pumps. Work Order (WO)2972259 consisted of a temporary modification to lower the oiler height on the Unit 3 HPSI pump bearings. As a result of this modification, the pump bearing was no longer in a constant oil bath during long periods of shutdown, when the residual oil in the bearing may drain away. WO
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2972259, HPSI Bubbler, Attachment 1, stated that for the new oil configuration, "With the absence of the flooded condition and the presence of the residual oil within the bearing, Flowserve did not anticipate any significant bearing degradation resulting from idle periods of up to and including three months."  The team questioned how this configuration constraint was incorporated into operating procedures. As a result of the team's questioning, the licensee conducted a review of procedures and found that they did not incorporate any guidance or precautions dealing with the pumps being idle for up to three months. The review for the temporary modification did not specify any concerns in this area and did not resolve the concern of a pump being idle for more than three months. The licensee entered this issue into their CAP as PVAR 3069219.
 
5.3 Human Performance The team identified continuing human performance issues at Palo Verde consistent with previously identified issues discussed in End of Cycle and Mid-cycle letters since 2005.
 
Specifically, human performance concerns observed during this inspection included weaknesses in implementing the OD process, failures to follow procedures, failures to implement human performance tools, and inadequate procedures. In addition, a significant number of engineering issues reflected a lack of technical rigor in resolving complex issues. The team noted a lack of adherence to basic radiological work practices
 
and inconsistent implementation of control room behaviors. The team identified that the licensee's training department had been inconsistent in supporting site improvement. Although a human performance root cause investigation had been conducted, corrective actions to date had not been effective in improving human performance. These continuing human performance deficiencies indicated that corrective actions to resolve the substantive crosscutting issues had not been successful in sustaining performance improvement.
 
====a. Inspection Scope====
The team evaluated the effectiveness of how Palo Verde personnel identified, evaluated, and corrected deficiencies involving human performance. The team evaluated training by reviewing instructional procedures and material, conducting interviews with training department personnel, observing classes, and job performance measure (JPM) evaluations, reviewing nuclear assurance department audits, and reviewing training department self assessments. The team evaluated the work control process by reviewing procedures, conducting interviews with work control personnel and work control SROs, and observing outage control center and online work control center activities. The team conducted a review of substantive human performance crosscutting aspects and a review of the human performance crosscutting aspects identified in the findings discussed in this report. Finally, the team conducted emergency planning performance drills with a sampling of SRO, Technical Support Center, and Emergency Operations Facility Emergency Directors to assess their ability to implement the Emergency Plan (EP).
 
====b. Findings and Observations====
b.1 Observations and Minor Violations Involving Human Performance
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b.1.1 Human Performance Root Cause Report
 
=====Description:=====
The team reviewed the human performance root cause report issued in September 2005 and effectiveness reviews completed in August 2007. The team noted the following weaknesses:
The September 2005 human performance root cause report identified that the Palo Verde organization did not demonstrate ownership and leadership of the human performance culture. The root cause report stated, "Palo Verde Management does not emphasize that excellence in human performance will result in excellence in plant performance," and "Leaders sometimes model behaviors inconsistent with site expectations."  These statements indicated that the Palo Verde management team may not have understood what behaviors contributed to an excellent human performance culture. Also, the August 2007 effectiveness review of CRAI 2830264 for decision making stated, "The evaluation concluded that there is a lack of an organizational definition on what constitutes a decision making error and the behaviors of questioning attitude and technical rigor are not well defined or understood."  The team noted that understanding and defining the expected behaviors that contribute to an excellent human performance culture were needed to achieve the desired culture change.
 
In March 2005, the licensee initiated CRDR 2780273 to perform a root cause investigation of the substantive crosscutting issues in human performance. Although the August - September 2007 human performance self-assessment performed in preparation for the ImPACT review in 2007 determined that the root cause initiated in CRDR 2780273 was ineffective in identifying the root cause, a subsequent effectiveness review performed under CRAI 3033705 in August 2007, determined that the root cause (i.e., the Palo Verde organization does not demonstrate ownership and leadership of the human performance culture) was corre ctly identified. The licensee supported this conclusion based on subsequent CRDR evaluations that used streaming analyses, fault tree analyses, common cause analyses, and human performance models. The effectiveness review also concluded that a new root cause determination was not necessary because the root causes had been correctly identified, and common cause analyses and/or streaming analyses had been recently performed for industrial safety, clock reset events, and decision making errors. Additionally, Building Block 6, "Human Performance/Continuous Learning," for the SIBP/SIIP had been developed. The effectiveness review concluded that the corrective actions for CRDR 2780273 were not well-defined and there were no actions for implementation, monitoring, reinforcement, adjustment, or transfer of human performance ownership change. Furthermore, the corrective actions were either not fully implemented or not implemented as intended. During review of the SIBP/SIIP, the team noted that none of these corrective actions for CRDR 2780273 had been incorporated into Building Block 6.
 
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The team reviewed apparent cause and root cause evaluations addressing human performance issues to determine whether the licensee's conclusion that the root cause analysis for CRDR 2780273 was correct. These included CRDR 2994589 (Human Performance Department Clock Reset Events ACE Report), CRDR 2994593 (Continuous and Reference Procedure Use and Adherence Department Clock Resets ACE Report), CRDR 2936096 (2006 Site Clock Reset and Significant Event Stream Analysis), CRDR 3011305 (Industrial Safety Events Common Cause Analysis), CRDR 3008308 (Decision Making Errors from 1/1/06-3/30/07 ACE Report), CRDR 3031159 (2007 Human Performance Site clock Reset Events ACE Report), and Significant CRDR 3048800 (Industrial Safety Performance Weakness). The identified causes for CRDRs 2994589, 2994593, and 3031159 were the same; failures in human performance tool use, leadership oversight, knowledge/skills, and procedure quality. Of these causes, only leadership oversight and procedure quality were addressed by CRDR 2780273. Because the identified contributing causes in CRDR 2780273 included management not setting/reinforcing clear standards and expectations, the team concluded that the workforce was unfamiliar with the use of, and expectation to use, human performance tools such as stopping when unsure. Discussions with licensee personnel involved in the apparent cause analyses of department clock resets revealed that it was common for workers to not be aware of an expectation to stop before proceeding when procedure quality problems were encountered. The team verified that corrective actions from these additionally reviewed CRDRs related to human performance had been incorporated into the SIBP/SIIP. The team also reviewed CRDR 2928806 which was initiated to track actions in the human performance crosscutting issue closure plan. CRDR 2928806 contained 75 actions which were included in Building Block 6 of the SIBP/SIIP. Because the SIBP/SIIP was still in draft form, and many of the proposed actions had not yet been implemented, the team was unable to evaluate whether the actions will be effective in correcting the human performance issues the site was experiencing.
 
b.1.2 Main Control Room Observations
 
=====Description:=====
The team conducted control room observations in all three units. The team observed Unit 3 for 28 hours (October 4 and 5), Unit 1
 
for 16 hours (October 9), and Unit 2 for 12 hours (October 11). During these observations the team observed turnovers between crews, control room briefs, response to control room alarms, and performance of control room duties. The team noted the following weaknesses in
 
control room behaviors:
On October 4, 2007, the team observed the off going and oncoming shift managers (SMs) conducting turnover in the Unit 3 Control Room. The oncoming SM did not use the SM turnover sheet and there was no discussion between the two SMs of a new night order
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concerning an Emergency Action Level clarification issued the previous evening. The team waited until completion of the turnover to inquire if there were any new night orders. At that point, the off going SM provided a turnover of the new night order.
 
Operations personnel were inconsistent in the use of 3-way communications. The third part of the 3-way communications was either not performed or was conducted by body language. Certain crews demonstrated a higher standard than others. This demonstrated inconsistency across the operations organization in the use of 3-way communications.
 
Control room personnel did not demonstrate a consistent manner in declaring expected alarms. Site procedures allowed expected alarms not to be declared if it is agreed to prior to the test/evolution.
 
When this methodology was agreed upon, it was not followed consistently by the control room operators.
 
The team noted that there was no methodology in place to identify who was assigned as the Control Room Supervisor (CRS). On October 4, 2007, during a turnover brief, the CRS was announced, but during other briefs this was not done. The team also noted the lack of a formal announcement by the CRS when leaving the "at the controls" (ATC) area and the lack of a formal turnover to another on shift SRO for control room oversight. On October 9, 2007, the team observed that while the SM was out of the control room, the CRS stepped out of the ATC area and the CRS did not inform the control room of his whereabouts. The team noted this was in compliance with Procedure 40DP-9OP02, "Conduct of Shift Operations,"
requirements which defined the control room as the entire 140' level
 
of the auxiliary building. During this time, there was no command SRO in the ATC area. This did not provide effective SRO oversight of control room activities and did not promote a high standard for control room oversight.
 
Crew briefs were not consistently announced by the briefer, nor did all attendees respond by stating, "Ready," as described by site procedure. Some briefs were interrupted by plant manipulation requests and in one case a medical emergency. During these interruptions, the briefs continued while a reactor operator and the CRS responded to the requests.
 
In reviewing control room logs for October 4 and 5, 2007, the team noted that the Unit 3 shutdown cooling (SDC) Train A inoperability issue was in two different control room logs used by the SM and the CRS. One log was used for Limiting Condition for Operations entries and the other for ODs. The Unit 3 SDC Train A inoperability times contained in each log were different, which made it difficult to
 
recover the event timeline.
 
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During the Unit 1 observation on October 11, 2007, the team determined that the control room was unaware that utility vehicles were conducting work within the onsite Salt River Project (SRP)switchyard. The licensee did not track switchyard work in the
 
respective control room nor did they routinely apply risk management features to their risk profile.
 
Peer checking was inconsistent. On October 4, 2007, the team noted that a peer checker was not paying attention (eyes diverted in another direction) as he was providing a peer check to an operator performing system manipulations. In another example, the peer checker did not respond verbally about equipment being started.
 
The licensee used jumpers to achieve a black board status (a state in which there are no lighted false or non-impacting alarms on the control room panels). The licensee had approximately eight jumpers installed between all 3 units for greater than a year that had been used to achieve black board status.
 
5.4 Procedure Quality Poor procedure quality has been a continuing problem at Palo Verde. The root cause analysis for the substantive crosscutting issues in human performance documented in CRDR 2780273 identified that non-conservative decisions were made because of inadequate procedural guidance and/or poor anticipation of system and human interaction during procedure and document development. The root cause report also identified that cognitive decisions were made to not follow procedures because personnel were not able to follow the procedure as written. During this inspection, the team noted continuing examples of poor procedure quality indicating that prior corrective actions had not been
 
completely effective.
 
====a. Inspection Scope====
The team reviewed a sampling of procedures to determine whether inadequate procedures contribute to initiating events, improper mitigating system operation, poor maintenance or testing, or inadequate emergency and abnormal operations response. Specifically, the team assessed the effectiveness of corrective actions taken for procedure quality issues, evaluated the adequacy of the procedure development and revision processes, and reviewed a sampling of Emergency Planning Implementing Procedure (EPIP) changes to determine if the EPIP change process was adequate to correct EPIP related deficiencies and maintain EP commitments.
 
====b. Findings and Observations====
b.1 Observations and Minor Violations Involving Procedure Quality b.1.1 Procedure Issues
 
=====Description:=====
The team noted examples of poor procedure quality during this inspection, including:
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Emergency Operating Procedures (EOPs) written for the operation of AF allowed operation outside of the design basis. For example, the procedure for using AF for cold shutdown allowed a cooldown rate of 100°F per hour; however, the design basis for AF limits the cooldown
 
rate to 70°F per hour.
 
The team noted that a procedure used to set the limit switch on the polar crane was based on handwritten engineering notes that did not have a second verification performed. Furthermore, the notes were not attached to the procedure. Since the WO was incorrectly annotated as a non-quality package, it was not maintained and all the information, including the engineering notes, were discarded after completion of the work. The licensee subsequently requested copies of the documents from the team to recreate the record.
 
The team noted that the head lift procedure included handwritten calculations and email communications, but did not include references to the drawings used to verify proper heights and that no tolerances were specified for the height measurements. In addition, a sign-off step involving a cautionary statement was located two steps after the caution was applicable.
 
The team noted numerous weaknesses in EPIPs. For example, EPIP-03, "Technical Support Center Actions," did not provide direction on appropriate actions to implement when radiation Monitor RU-13A was out of service. This radiation monitor was used to evaluate the habitability of the Technical Support Center. Other examples of emergency preparedness procedure weaknesses are discussed in  Section 5.7 of this report.
 
5.5 Equipment Performance Long standing equipment performance issues have challenged the site. Engineering programs and processes required to reliably track and trend systems important to safety and reliable operations were often weak. Specifically:
The team noted that system engineers generally did not understand the implementing requirements of the maintenance rule (MR) program. Specifically, system trending was not consistent, establishment and maintenance of performance criteria was not well understood, and the training of system engineers was not sufficient to ensure that the program was consistently implemented.
 
The team noted weaknesses in the evaluation of operating experience relied upon to maintain adequate plant performance. For example, since 1988, engineering personnel had not adequately evaluated and inspected pre-1983 Target Rock reed switches in response to OE. Consequently, the licensee was unaware of a pre-1983 reed switch, that did not conform to requirements, had been installed in Unit 2 safety-related solenoid operated valve (SOV) 2JRCEHV0403 (Reactor Vessel Seal Drain Valve to Reactor Drain Tank).
 
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The team identified on September 27, 2007, that the requirements for testing the CS nozzles in Units 1, 2, and, 3 did not meet TSSR 3.6.6.6. Operations personnel did not enter TSSR 3.0.3 until prompted by the team on October 30, 2007.
 
The team noted that several long standing degraded conditions were not aggressively pursued by the licensee. Noteworthy examples include cable vault flooding, ESP material condition, AF system performance, and safety injection system performance.
 
====a. Inspection Scope====
The team reviewed various engineering related issues for the selected systems (containment spray, turbine driven AF pump, ESP pumps, HPSI pumps, and LPSI pumps) to evaluate the licensee's effectiveness in identifying the causes and extent of equipment problems, as well as developing and implementing corrective actions.
 
Additionally, a review of the implementation of the EQ program was conducted. The team reviewed equipment performance related documents, observed inspection activities, and conducted plant tours to assess the effectiveness of the licensee in entering equipment performance issues into the CAP. The team also reviewed open PVARs and corrective maintenance WOs for the selected systems to assess their potential impact on operability.
 
The team reviewed surveillance and post-maintenance tests to assess the effectiveness of the licensee in specifying appropriate acceptance criteria and to determine whether the licensee's controls to restore equipment to operation following testing and maintenance were effective. For example, the team reviewed the licensee's program and procedures used to test containment sump butterfly valves to ensure that the ECCS piping was filled with water as required by Technical Specifications.
 
The team reviewed selected EQ preventive maintenance activities for the selected systems to assess program adequacy and to determine whether the design document, vendor manual, and generic communication information were appropriately incorporated into the maintenance program.
 
The team conducted interviews with licensee personnel, including engineering and procurement personnel, who had an input into maintenance-related activities, to determine how the system was operated, whether that operation conflicted with the intended safety function, and whether engineering input was at an appropriate level to ensure safe and reliable plant operation.
 
The team evaluated line organization, quality assurance, external audits, and assessments to determine whether the licensee had demonstrated the capability to identify performance issues before they resulted in actual events of undesired consequence. The team reviewed the licensee's management support to the audit and assessment process, as evidenced by staffing of the quality assurance organization, responsiveness to audit and assessment findings, and contributions of the quality organization to improvements in licensee activities.
 
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====b. Observations and Findings====
b.1 Failure to Evaluate Performance Monitoring Criteria for Auxiliary Feedwater System
 
=====Introduction.=====
The team identified a Green NCV of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," for the failure of MR and engineering personnel to demonstrate that the performance or condition of SSCs was being effectively controlled through the performance of appropriate preventive maintenance to ensure the SSCs remain capable of performing their intended function. Specifically, between April and October 2007, an inadequate evaluation of MR performance criteria (PC) was performed. As a result, Unit 2 AF Train A exceeded the 10 CFR 50.65(a)(2) PC, and goal setting, and monitoring was not performed as required by 10 CFR 50.65(a)(1).
 
=====Description.=====
The team reviewed the MR PC for the AF system to verify that the performance and condition of SSCs was being controlled through the performance of appropriate preventive maintenance to ensure the AF system was capable of performing its intended function.
 
The team questioned MR and engineering personnel on the establishment and evaluation of MR unavailability and reliability PC for the AF system. Maintenance Rule and engineering personnel discussed the AF system health report for January 1, 2007 through June 30, 2007, which provided unavailability and
 
reliability PC for the AF system. During interviews with MR and system engineering personnel, the team was unable to identify the roles and responsibilities, as well as the ownership of establishing and maintaining PC for the AF, CS, and ESP systems. Further, no documentation existed to validate that unavailability and reliability were appropriately balanced through the establishment of accurate PC.
 
The team reviewed Procedure 70DP-0MR01, "Maintenance Rule," Revision 16.
 
Step 3.3.2.4 stated that, "Performance criteria will be established such that there would not be an unacceptable increase in plant risk as measured by Core Damage Frequency (CDF) when SSC performance is at or near the performance criteria limit."  The team questioned MR personnel to determine what an acceptable increase in plant risk would be to establish PC. MR personnel determined an increase in CDF of 1E-6 per year from the baseline CDF, as described in Study 13-NS-C025R004, "Risk-Informed Performance Criteria,"
Revision 4, would be appropriate for establishing PC. However, Step 3.3.2.4 did not provide explicit direction to consider this CDF criterion.
 
The team requested PC data for unavailability and reliability of the AF system considering the change in CDF criteria from Study 13-NS-C025R004. The allowed unavailability PC used in the AF system health report for January 1, 2007, through June 30, 2007, was 1.60 percent while the change in CDF criteria from Study 13-NS-C025R004 would have only allowed an unavailability PC of 1.16 percent.
 
The team questioned MR personnel as to the validity of the PC in the AF system health report. On October 12, 2007, MR personnel initiated PVAR 3075907 to
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evaluate the AF system unavailability and reliability PC. PVAR 3075907 created an action plan to reconstitute the PC for any system where the PC was greater than the value documented in Study 13-NS-C025R004. Maintenance Rule personnel reevaluated the PC in a white paper attached to PVAR 3075907 and determined that 22 systems had non-conservative PC for either unavailability or reliability or both.
 
Procedure 70DP-0MR01, Step 3.5.2.3, also stated that if goal setting is determined to be necessary, then the SSC will be moved from 10 CFR 50.65(a)(2) to 10 CFR 50.65(a)(1), PC will be monitored, goal setting will be established, and management attention will be focused on the poorly performing SSC. Maintenance Rule and engineering personnel failed to move Unit 2 AF Train A from 10 CFR 50.65(a)(2) to 10 CFR 50.65(a)(1) status in April 2007, to ensure heightened monitoring and goal setting for the system. In accordance with the new PC, Unit 2 AF Train A should have been moved from 10 CFR 50.65(a)(2) status to 10 CFR 50.65(a)(1) status due to exceeding unavailability criteria. The MR expert panel met on October 12, 2007, and determined Unit 2 AF Train A should have been placed in 10 CFR 50.65(a)(1)status in April 2007 when unavailability exceeded 1.16 percent.
 
On October 10, 2007, MR personnel initiated PVAR 3074255 to evaluate the adequacy of Procedure 70DP-0MR01 with regard to determining PC.
 
Maintenance Rule personnel also initiated PVAR 3076699 on October 15, 2007, to reiterate an understanding of the ownership and responsibilities of system engineers with respect to managing the MR PC.
 
The team reviewed the Palo Verde "Periodic Assessment of Maintenance Rule Program," July 2005 through December 2006, assessment. Maintenance Rule personnel reviewed system engineering inputs to the periodic assessments including a review of 10 CFR 50.65(a)(2) systems performance criteria. This periodic assessment did not identify any problems with PC exceeding the values documented in Study 13-NS-C025R004. The team determined that the annual assessment was a missed opportunity to identify the non-conservative
 
performance criteria.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of MR and engineering personnel to demonstrate that the performance or condition of SSCs was being effectively controlled through the performance of appropriate preventive maintenance for Unit 2 AF Train A. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affects the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had crosscutting aspects associated with self assessments of the PI&R area in that MR and engineering personnel failed to perform self assessments that were co mprehensive, appropriately objective, and self-critical (P.3.(a)). The cause of this finding had crosscutting aspects associated with decision-making of the human performance area in that
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engineering personnel failed to make safety-significant or risk-significant decisions using a systematic process (H.1.(a)). The cause of the finding was also related to the safety culture component of accountability in that management failed to reinforce safety standards and display behavior that reflected safety as an overriding priority (O.1.(b)).
 
=====Enforcement.=====
10 CFR 50.65(a)(1) requires, in part, that the licensee monitor the performance or condition of SSCs against licensee-established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions. 10 CFR 50.65(a)(2) requires, that monitoring as specified in 10 CFR 50.65(a)(1) is not required where it has been demonstrated that the performance or condition of a SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended function. Contrary to the above, from April to October 2007, MR and engineering personnel failed to demonstrate that performance of Unit 2 AF Train A was being effectively controlled through appropriate scheduled maintenance. Specifically, an inadequate evaluation of MR performance criteria was performed and, as a result, Unit 2 AF Train A exceeded its 10 CFR 50.65(a)(2) PC and goal setting and monitoring was not performed as required by 10 CFR 50.65(a)(1). Because the finding was of very low safety significance and was entered into the CAP as PVAR 3075907, this violation was treated as a NCV, consistent with Section VI.A of the Enforcement Policy: NCV 05000529/2007012-05, "Failure to Implement Maintenance Rule Requirements for Auxiliary Feedwater."
 
b.2 Failure to Control Nonconforming Target Rock Reed Switches 
 
=====Introduction.=====
The team identified a third example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure of engineering personnel to evaluate and correct the installation of nonconforming Target Rock reed switches. Between 1988 and October 10, 2007, engineering personnel had not adequately evaluated and inspected pre-1983 Target Rock reed switches in response to OE. Consequently, the licensee was unaware that a pre-1983 reed switch, that did not conform to requirements, had been installed in Unit 2 safety-related solenoid operated valve (SOV) 2JRCEHV0403 (reactor vessel seal drain valve to reactor drain tank).
 
=====Description.=====
Operating Experience (OE) on Target Rock reed switches, manufactured before 1983 with Part Number 100967-1, was originally reviewed at PVNGS in 1988 to determine if any of these reed switches were installed in the plant. The reed switches had deterioration of the lead wire insulation, that cracked when the wires were flexed during maintenance or handling. Some of the cracks occurred at the terminal blocks while tensioning the terminal block fasteners. This degradation can cause a short to ground of the exposed wires resulting in dual position indication, blown fuses, or inadvertent opening of the
 
valves.
 
The original disposition closed the OE to the PVNGS Generic Letter 91-15, "Operating Experience Feedback Report, Solenoid-Operated Valve Problems at U.S. Reactors," SOV Program. During a review by the CDBR, the licensee determined that a formal SOV program did not exist, and the OE had been
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closed without a thorough evaluation. The CDBR team wrote PVAR 2959880 on January 12, 2007, and determined no degraded or non-conforming condition existed without performing a review to determine if any of these reed switches were installed in the plant.
 
CRAI 2960705 was initiated on January 19, 2007, to evaluate the availability and current use of the reed switches. The CRAI determined no pre-1983 Target Rock reed switches were available or in use in the plant and no further action on the OE was required. However, CRAI 2960705 also determined that six reed switches were installed in the plant that had not been inspected, reworked, or replaced. Three of the six were located inside containment, with one being safety related and two being quality augmented. The other three were located in the auxiliary building.
 
The team questioned engineering personnel about the conclusion of the CRAI that no pre-1983 reed switches were installed in the plant and that no further action was required. The team also questioned the CRAI 2960705 conclusion that none of these reed switches were installed in the plant since the CDBR evaluation stated one safety related reed switch had not been inspected, reworked, or replaced. After further review by the licensee, it was determined that one Target Rock reed switch, made before 1983, was installed in safety-related Valve SOV 2JRCEHV0403. Valve SOV 2JRCEHV0403 provides isolation for the reactor vessel o-ring to maintain a boundary to fission product
 
release.
 
On October 10, 2007, PVAR 2959880 was redirected to the control room for an immediate OD/FA. Operations personnel determined that all other pre-1983 Target Rock reed switches had been inspected or had no design basis safety function. Engineering personnel determined Valve SOV 2JRCEHV0403 remained functional because the length of time in service with no failures indicated Valve SOV 2JRCEHV0403 was not susceptible to cracking and that no cracking had occurred. In addition, Valve SOV 2JRCEHV0403 had no history of being reworked, replaced, or inspected, so the integrity of the reed switch had not been challenged. A corrective maintenance WO was generated per PVAR 2959880 to inspect Valve SOV 2JRCEHV0403.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of engineering personnel to evaluate and correct a condition adverse to quality involving the installation of nonconforming Target Rock reed switches. The finding is greater than minor because it is associated with the equipment performance cornerstone attribute of the initiating event cornerstone and affects the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) because assuming the worst case degradation, the finding would not result in exceeding the Technical Specification limit for reactor coolant system leakage because a redundant valve existed in series with SOV 2JRCEHV0403. The cause of this finding had crosscutting aspects associated with OE of the PI&R area in that operations and engineering personnel failed to ensure implementation and institutionalization of OE through
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changes to station processes, procedures, equipment, and training programs (P.2.(b)). The cause of this finding was also related to the safety culture component of accountability in that operations and engineering personnel failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that measures be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, between 1988 and October 10, 2007, engineering personnel failed to ensure that conditions adverse to quality were promptly identified and corrected. Specifically, in response to OE issued in 1988, the licensee did not identify and correct the installation of a pre-1983 Target Rock reed switch in Unit 2 safety-related SOV 2JRCEHV0403. This was the third example of the NCV involving the failure to implement CAP requirements. This finding was of very low safety significance and was entered into the CAP as PVAR 2959880.
 
b.3 Failure to Meet the Requirements of Technical Specifications Surveillance Requirement 3.6.6.6
 
=====Introduction.=====
The team identified a Green NCV of Technical Specification Surveillance Requirement (TSSR) 3.6.6.6 for the failure of operations personnel to verify that each containment spray (CS) nozzle was unobstructed.
 
Specifically, the last completed surveillance test conducted on each unit identified that one nozzle in each unit was obstructed and that the nozzles were not tested in accordance with the approved retest requirement.
 
=====Description.=====
The team reviewed Procedure 73ST-9SI02, "Containment Spray Nozzle Air Test," Revision 5, completed on Unit 3 in April 27, 2000, to verify that the CS nozzles were not obstructed. The surveillance test aligns warmed compressed air to the spray headers and then verifies that the nozzles are unobstructed either through use of an infrared camera to observe the nozzles or by visually observing movement of streamers attached to the nozzle. If a nozzle is determined to be obstructed, Section 10.1 of 73ST-9SI02, stated that corrective actions must be taken and the nozzle retested to verify flow prior to entry into Mode 4. During the test on Unit 3, Nozzle 3PSIAL429 was found to be obstructed. CRDR 117284 was initiated to evaluate the condition and clear the blockage. The surveillance test log indicates that the blockage was cleared; however, there was no evidence to indicate that the nozzle was retested in accordance with the surveillance test requirement.
 
As a follow-up to the extent of condition, the team also reviewed the surveillance test results for Units 1 and 2. Procedure 73ST-9SI02, Revision 5, was partially completed for Unit 1 on July 12, 2001. During that test, Nozzle 1PSIAL433 was plugged. Work Order 2380383 was initiated to clear the blockage. Upon review of the test results the licensee determined that two additional nozzles were not tested. These two nozzles were later retested on October 21, 2002. However, there is no evidence to indicate that blocked Nozzle 1PSIAL433 was retested in accordance with the surveillance test requirement. Procedure 73ST-9SI02, Revision 6, was completed for Unit 2 on April 12, 2002. The test discovered that Nozzle 2PSIBL419 was obstructed. Work Order 2797713 was initiated to clean 
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and replace the nozzle. Again, there was no evidence to indicate that the blocked nozzle was retested in accordance with the surveillance test
 
requirement.
 
Following the team's questioning, PVARs 3075026, 3075059 and 3068647 were initiated to document that during performance of Procedure 73ST-9SI02 in Units 1, 2 and 3 respectively, corrective maintenance was performed to clean a nozzle that was observed to be obstructed. In each case, a WO was written to inspect and clean the nozzle. Based on this the licensee concluded that there was no immediate impact on operability.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure to meet the requirements of TSSR 3.6.6.6. The finding is determined to be more than minor because it affected the configuration control attribute of the barrier integrity cornerstone, and affected the associated cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) because it did not involve an actual reduction in defense-in-depth for the atmospheric pressure control function of the reactor containment.
 
=====Enforcement.=====
TSSR 3.6.6.6 required that the CS nozzles be verified free of obstructions. Contrary to the above, as of April 11, 2000, for Unit 3, March 22, 2002, for Unit 2, and April 13, 2001, for Unit 1, the licensee did not verify CS nozzles were free of obstructions through the conduct of surveillance testing. Specifically, Units 1, 2, and 3 each had a blocked CS nozzle during the performance of Procedure 73ST-9SI02; however, retests were not conducted following corrective maintenance. Because of the very low safety significance of
 
the issue and because the issue was ent ered into the licensee's CAP as PVARs 3075026, 3075059, 3068647, and 3048511, the issue was treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy:  NCV 05000528, 05000529, 05000530/2007012-06, "Failure to Meet the Requirements of Technical Specification Surveillance Requirement 3.6.6.6."
 
b.4 Failure to Meet the Requirements of Technical Specifications Surveillance Requirement 3.0.3
 
=====Introduction.=====
The team identified a Green NCV of TSSR 3.0.3 for the failure of operations personnel to conduct an assessment and manage the risk for a missed surveillance test. Specifically, on September 27, 2007, the team identified that the requirements for testing the CS nozzles in Units 1, 2, and, 3 did not meet TSSR 3.6.6.6. Operations personnel did not enter TSSR 3.0.3 until
 
prompted by the team on October 30, 2007.
 
=====Description.=====
On September 27, 2007, the team identified that the requirements for testing the CS nozzles (described above) in Units 1, 2, and, 3 did not meet TSSR 3.6.6.6. The licensee initially entered the condition into their CAP as PVAR 3068647. On October 18, 2007, the licensee was pursuing approval from the Plant Review Committee to credit the work orders that removed the blockage from the nozzles as equivalent to the retest specified Procedure 73ST-9SI02, Enclosure  - 73 -
"Containment Spray Nozzle Air Test," Revision 5, Section 10.1. Although the Plant Review Committee did not act on this request, they had the opportunity to recognize that the surveillance requirements had not been met and the requirement for a missed surveillance test had not been invoked.
 
Upon further prompting by the team, the licensee entered TSSR 3.0.3 for Units 1 and 2 on October 30, 2007. Since Unit 3 was shutdown, the requirements of TSSR 3.6.6.6 were not applicable and therefore TSSR 3.0.3 was not required to be entered. Engineering personnel initiated PVAR 3085708 to address these issues.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of operations personnel to conduct an assessment and manage the risk for a missed surveillance test in accordance with TSSR 3.0.3. The finding is determined to be more than minor because it affected the configuration control attribute of the barrier integrity cornerstone, and affected the associated cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance because it did not involve an actual reduction in defense-in-depth for the atmospheric pressure control function of the reactor containment. The cause of this finding had crosscutting aspects associated with work practices of the human performance area in that operations personnel failed to ensure supervisory and management oversight of work activities that resulted in a missed TSSR (H.4.(c)). The cause of this finding was also related to the safety culture component of accountability in that operations personnel failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)).
 
=====Enforcement.=====
TSSR 3.0.3, requires that a risk evaluation be performed for any surveillance delayed greater than 24 hours and the risk impact be managed.
 
Contrary to the above, between September 27, 2007, and October 30, 2007, operations personnel failed to perform a risk evaluation and manage the impact of risk for a delayed surveillance test. Specifically, the team identified that the requirements for testing the CS nozzles in Units 1, 2, and, 3 did not meet TSSR 3.6.6.6. Operations personnel did not enter TSSR 3.0.3 for Units 1 and 2 until prompted by the team on October 30, 2007. Because of the very low safety significance of the issue and because the issue was entered into the CAP as PVAR 3085708, the issue was treated as an NCV, consistent with Section VI.A of the Enforcement Policy: NCV 05000528, 05000529/2007012-07, "Failure to Meet the Requirements of Technical Specifications Surveillance Requirement 3.0.3."  b.5 Untimely Corrective Actions for Submerged Safety Related Cables
 
=====Introduction.=====
The team identified a fourth example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure of operations and engineering personnel to take timely corrective actions for conditions adverse to quality involving water intrusion and flooding of underground manholes and cable vaults. Specifically, since 1996, water 
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intrusion and flooding of underground manholes and cable vaults had been a recurrent problem affecting electric cables and cable splices for safety-related, non-safety-related, and security systems.
 
=====Description.=====
Since 1996, water intrusion and flooding of underground manholes and cable vaults had been a recurrent problem affecting electric cables and cable splices for safety-related, non-safety-related, and security systems. Operations and engineering personnel initiated CRDR 2407009, CRDR 2784074, and CRAI 2800511 to address these issues.
 
In October 2007, the team observed the pump-out and inspection of non-safety related manhole (KMA07) that contained a faulted power cable affecting security equipment. The cable had been submerged when it failed. Approximately 15 feet of water was pumped from the manhole in order to allow access to the damaged cable. The team noted that duct banks connecting to adjacent manholes were approximately 6 feet from the bottom of the manhole vault and could have served as a potential conduit for the water intrusion. The team observed water dripping from the ends of a splice on another cable in the manhole that had been repaired from a previous failure. The team noted that neither safety related nor non-safety related electric cables and cable splices, in these underground cable runs, were qualified for continuous submergence.
 
The team reviewed repeated efforts to address the extent and cause of water intrusion into underground vaults described in CRAI 2425879, CRAI 2429470, CRDR 2882166, and CRAI 2919409. The team also reviewed the root cause investigation, documented in CRDR 2784074, for the Unit 1 spray pond degraded cable splice failure on March 23, 2005. The team determined that the root cause analyses failed to address that power cables, not just cable splices, are susceptible to degradation and failure when submerged for extended periods.
 
The team also determined that past corrective actions have not been effective in eliminating underground manhole and cable vault flooding, or cable failures due to submergence.
 
The team reviewed a standing order that required the inspection of manholes that are susceptible to water intrusion following a rainfall of greater than 0.3 inches within a 24 hour period. The team determined there were no formal administrative controls in place to initiate this inspection. The inspection was not incorporated into station procedures to assure that the process was reviewed, documented, approved and, administratively controlled.
 
The team also determined that the OD for Unit 1 Spray Pond Pump 1MSPB01, documented in CRDR 2784074, relied on inspection of manhole 1EZV06BKEM04 after a rainfall of greater than 0.3 inches to ensure that the power cable splice stayed dry. The 0.3 inch rainfall number was arbitrarily chosen by examining rainfall history at the site and selecting a value that would result in about 4 to 5 rainfall-based inspections per year. The team determined that there was no technical data or root cause analysis that indicated excessive rainfall was the primary cause of the flooding problem in the electrical manholes and underground cable systems, and not water from another source.
 
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The team noted that, in addition to site specific experiences, a substantial amount of external OE had been provided to the station. The licensee's evaluation of Generic Letter (GL) 2007-01, "Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients," was not technically rigorous nor comprehensive since it did not address failures associated with cable splices. Additionally Information Notice 2002-12, "Submerged Safety-Related Electrical Cables," was closed on March 29, 2002, by reference to CRDR 2407009. CRDR 2407009 evaluated cables in manholes in response to a 2001 manhole flooding and cable submergence event and established a long term plan to deal with water intrusion. CRDR 2407009 remained open and had not been effective in addressing the root causes of the manhole water intrusion problem nor in implementing effective corrective action as evidenced by the U1 Spray Pond B degraded cable splice failure on March 23, 2005, and the non-safety manhole flooding and 12.5kV cable failure observed during this inspection.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of operations and engineering personnel to take timely corrective action for conditions adverse to quality involving water intrusion and flooding of underground manholes and cable vaults. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affects the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had crosscutting aspects associated with decision making of the human performance area in that operations and engineering personnel failed to use conservative assumptions for operability decision-making when evaluating degraded and nonconforming conditions (H.1.(b)). The cause of the finding was also related to the safety culture component of accountability in that management failed to reinforce safety standards and display behavior that reflected safety as an
 
overriding priority (O.1.(b)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires in part, that measures shall be established to ensure that conditions
 
adverse to quality are promptly identified and corrected. Contrary to the above, since 1996, operations and engineering personnel failed to take timely corrective actions for conditions adverse to quality involving water intrusion and flooding of underground manholes and cable vaults. Specifically, water intrusion and flooding of underground manholes and cable vaults had been a recurrent problem affecting electric cables and cable splices for safety-related, non-safety-related, and security systems. This was the fourth example involving the failure to implement the CAP. This example was of very low safety significance and was entered into the CAP as PVAR 3072557.
 
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b.6 Failure to Properly Evaluate the Extent of Condition of 4160 V and 480 V Motor Issues
 
=====Introduction.=====
The team identified a seventh example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure of operations and engineering personnel to adequately evaluate degraded and unanalyzed conditions to support ODs associated with CS and LPSI motor lug issues. Specifically, since April 2005, CRDR 2841653 noted that the extent of condition review required by CRDR 2790388, was complete for the CS and LPSI motor issues, but identified that the condition may be transportable to other 4160V and 480V motors. However, no evaluation of additional 4160V and 480V motors was conducted.
 
=====Description.=====
Between April and October 2005, there were several CRDRs documenting loose lugs, improper crimping, and broken motor lead strands on the CS and LPSI pumps on all three units. The licensee performed technical and operability evaluations associated with these conditions in CRDR 2968639. On February 8, 2007, the licensee initiated CRDR 2973072 to address several process issues associated with the disposition of the CS and LPSI motor lug issue.
 
On October 25, 2005, the licensee init iated CRDR 2841653, which identified that loose lugs, improper crimping, and broken motor lead strands may be
 
transportable to other 4160V and 480V motors. The evaluation in CRDR
 
2973072, stated that although the originator of the CRDR believed the issues were transportable to other 4160V and 480V motors, it was impractical to open the terminations on each and every 4160V and 480V motors. Engineering and operations personnel decided to address the rest of the station's motor terminations as they were removed and re-terminated as part of regularly scheduled maintenance. No specific corrective action or work-tracking mechanism was specified to ensure that the inspections were performed.
 
The team determined operations should have entered Procedure 40DP-9OP26, "Operability Determinations and Functional Assessment," Revision 18.
 
Procedure 40DP-9OP26, Step 3.3.5 stated that if other plant conditions or disassembly is required, then the extent of condition should be addressed by the CAP, where work mechanisms can be developed and scheduled as appropriate based on the safety significance. Operations personnel failed to schedule work mechanisms to ensure the extent of condition on other 4160V and 480V motors was addressed. On October 24, 2007, engineering personnel initiated PVAR 3082645 to address this issue.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of operations and engineering personnel to adequately evaluate degraded and unanalyzed conditions to support operability decision making associated with CS and LPSI motor issues. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affects the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process,"
Phase 1 Worksheets, the finding is determined to have very low safety
- 77 -
significance (Green) since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had crosscutting aspects associated with corrective actions of the PI&R area in that operations and engineering personnel failed to take corrective actions to address safety issues and adverse conditions in a timely manner (P.1.(d)). The cause of the finding was also related to the safety culture component of accountability in that management failed to reinforce safety standards and display behavior that reflected safety as an overriding priority (O.1.(b)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," requires that activities affecting quality be prescribed by instructions, procedures, or drawings, and be accomplished in accordance with those instructions, procedures, and drawings. The assessment of operability of safety-related equipment needed to mitigate accidents was an activity affecting quality and was implemented by Procedure 40DP-9OP26, "Operability Determination and Functional Assessment," Revision 18. Step 3.3.5 stated that if other plant conditions or disassembly is required, then the extent of condition should be addressed by the CAP, where work mechanisms can be developed and scheduled as appropriate based on the safety significance. Contrary to the above, since April 2005, engineering personnel failed to ensure work mechanisms were developed and scheduled to determine the extent of condition of motor termination degradations. Specifically, operations and engineering personnel failed to adequately evaluate the extent of condition for 4160 V and 480 V motor lug issues, including loose lugs, improper crimping, and broken motor lead strands. This is the seventh of 8 examples associated with the NCV involving failure to implement the OD program. This example was of very low safety significance and was entered into the CAP as PVAR 3082645.
 
b.7 Observations and Minor Violations Involving Equipment Performance b.7.1 Environmental Qualification Program
 
=====Description.=====
The existing EQ group responsibility is focused on the EQ requirements of 10 CFR 50.49 for electrical equipment important to safety in harsh environments and seismic qualification. Responsibility for EQ requirements outside of these areas falls upon procurement engineering, the warehouse and supply chain group, maintenance engineering, and design engineering. When interviewed, these groups stated several of their members had previous EQ experience, but that their personnel did not receive any formal EQ training. Consequently, there was no single group with overall responsibility for the full range of environmental and seismic qualification requirements.
 
The formal mechanical EQ program was deleted from the EQ program based on a position paper entitled, "The Elimination Of The Mechanical EQ Program," prepared by Tenera in 1994. This study stated that continued compliance with 10 CFR Part 50, Appendix A, Criterion 4, "Environmental and Dynamic Effects Design Basis," will be maintained by the procurement program, that had in place detailed and sophisticated controls of all materials in mechanical equipment to confirm the ability of equipment and components to perform their required functions in harsh
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environments; and the maintenance program, that will monitor, trend, and correct equipment aging for mechanical equipment. However, as mentioned previously, these groups stated that although several of their members had previous EQ experience, their personnel do not receive any formal EQ training.
 
The fragmented approach to the various aspects of EQ requirements relied heavily on the EQ awareness and knowledge of the persons in the groups responsible for implementing the EQ requirements of 10 CFR 50.49 and 10 CFR Part 50, Appendix A, Criterion 4. Examples of how this EQ program approach and the lack of formal training in groups required to implement EQ requirements led to problems in the EQ area included the following:
During a Unit 3 plant walkdown the team identified minor discrepancies in the installation configuration of ASCO solenoid valves on the Unit 3 atmospheric dump valves. The configuration discrepancy had no impact on the function of the components. In their investigation of the discrepancies, the licensee identified that there was no existing design control in place for mechanical components requiring EQ (PVAR 3079739).
 
During a July 1, 2005, review of preventive maintenance for charging pump motors, the licensee noted that EQ-required lubrication activities had been stopped in 1998. The condition was documented in CRDR 2811528 on June 27, 2005, and the activities were re-verified. Although the condition did not impact the ability of the equipment to function, this illustrated a lack of communication and coordination between various site organizations and the EQ program.
 
During a Unit 3 containment walkdown, the team observed that the outer polymer sheath covering for flexible conduit connectors in numerous equipment locations was cracked, split, and separating away from the underlying flexible metal conduit. Three different types of repairs were performed on several degraded flexible conduit sheaths: wrapping with black electrical tape, application of room temperature vulcanization sealant at the ends of the sheath that remained on the flex conduit after other sections had broken away, and wrapping with a fiberglass tape. As a result of this observation, the licensee initiated PVAR 3079739 to evaluate this deficiency in the design control process.
 
Water intrusion and flooding of underground manholes and cable vaults had been a recurrent problem affecting electric cables and cable splices for safety-related, non-safety-related, and security systems. Electric cables and cable splices in these underground cable runs were not qualified for continuous submergence.
 
During an October 26, 2006, review of the routine tasks associated with the EQ requirements for the GL 89-10, "Safety Related Motor
- 79 -
Operated Valve Testing and Surveillance," motor operated valves, the licensee identified that repetitive tasks did not reflect the correct frequency and initiated CRDR 2936445. Specifically, the work descriptions for the maintenance activities did not adequately note the EQ requirements.
 
The team reviewed the results of Self Assessment No. 2957427, "Equipment Qualification Program," and CRDR 3048870, "Engineering Programs," Appendix B, "Equipment EQ Program Review," and found that the reviews generally identified performance issues at the appropriate level. However, the team found that lax procedural ties to other plant organizations were symptomatic of the fragmentation and organizational weakness in the treatment of the full range of EQ issues.
 
In summary, EQ program weaknesses were attributed to: insufficient staffing; a fragmented approach to the EQ program implementation with no single group with overall responsibility for the full range of environmental and seismic qualification requirements; and no formal EQ training for groups responsible for implementing the EQ requirements of 10 CFR 50.49 and NRC general design criteria.
 
5.6 Configuration Control 5.6.1  Effectiveness of Corrective Actions
 
The team concluded that corrective actions to address adverse conditions regarding configuration control were generally effective. The team reviewed a sample of planned and installed modifications, as well as unapproved and cancelled modifications, to ensure that changes to equipment were effectively controlled and implemented. The team noted the licensee's program was adequate in implementing corrective actions related to changes in the plant. However, there were some weaknesses identified with modifications that were tracked in the licensee's database. The potential existed for scheduled modifications to inadvertently appear on the cancelled or unapproved list. This caused confusion in determining the status of a specific modification. The team also identified weaknesses in the thoroughness of performing evaluations regarding changes, or modifications to the plant that may be outside of the licensing and design bases.
 
====a. Inspection Scope====
The team assessed whether corrective actions which affected configuration control were effective because the loss of configuration control of risk-significant systems or equipment could lead to the initiation of a reactor transient and/or compromise mitigation capability. The team reviewed several corrective action documents, WOs, system health reports, assessments, and audits, as well as conducted interviews of licensee personnel, in order to adequately assess the effectiveness of corrective actions for deficiencies involving configuration control. The team reviewed selected ODs and modifications to verify if a loss of configuration control of risk-significant systems or equipment which led, or potentially led, to the initiation of a reactor transient and/or compromised the systems' mitigation capability.
 
- 80 -
 
====b. Observations and Findings====
b.1 Failure to Implement Corrective Actions for Borg-Warner Check Valves
 
=====Introduction.=====
The team identified a fifth example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure of maintenance and engineering personnel to promptly correct a degraded/nonconforming condition associated with a Part 21 notification related to 3 inch Borg-Warner check valves. Specifically, the licensee did not perform a disassembly and inspection of Valve 1PSIEV123, HPSI header containment penetration check valve, during the Unit 1 R13 refueling outage for a 2001 Part 21 corrective action. The failure to perform the maintenance resulted in the failure of 1PSIEV123 in July 2007, and the continued degradation of additional safety injection system check valves.
 
=====Description.=====
On August 23, 2001, the licensee received Part 21 2001-27-0 on Borg-Warner Flowserve check valves which expanded the scope of the original Part 21 notification issued in 1993 to include all 3 and 4 inch Borg-Warner swing check valves of any pressure class. The condition described in the original Part 21 report was a potential failure of Borg-Warner valves to go fully closed due to the valve disk becoming lodged under the lip of the valves seat. The licensee assumed that CRDR 2332280 initiated on October 23, 2000, already performed the required evaluations for this issue and thus no action was taken.
 
On January 26, 2007, mechanical engineering determined that not all Borg-Warner check valves had been evaluated by CRDR 2332280 and generated PVAR 2963565, coded as degraded/nonconforming, to address the 2001 Borg-Warner Part 21 notification. This PVAR identified valves that were more critical due to the potential for having a nonconformance issue, and the last reassembly being implemented before Procedure 31MT-9ZZ17, "Borg-Warner Check Valve Disassembly and Assembly," was dev eloped. This list included Valve 1PSIEV123. On February 2, 2007, the ARRC initiated CRDR 2965988 to complete the necessary action for the 2001 Part 21 notification. CRDR 2965988 was closed after addressing the 2001 Part 21 evaluation without any action taken to address the degraded/nonconforming conditions of the check valves.
 
On May 2, 2007, Significant CRDR 2930774, "Failure of LPSI Injection Check Valve 1PSIEV134," was issued following the failure of another Borg-Warner check valve. The valve failed because of excessive friction in the disc to seat landing zone, spherical bearing and swing arm bore, and the spherical bearing and disc/stud raised weld. This corrective action document was issued to change the extent of cause to apply to the weld size, gap measurements and stiffness issues to all Borg-Warner valves, including the 3 and 4 inch valves, and
 
revise Procedure 31MT-9ZZ17, "Borg-Warner Check Valve Disassembly and Assembly," to incorporate new Borg-Warner assembly information and clearances.
 
On May 19, 2007, the licensee did not perform Procedure 73ST-9SI05, "Leak Test of HPSI/LPSI Containment Isolation Check Valves," Section 8.2, Revision 21, on 1PSIEV123. Procedure 73ST-9SI05,  Section 7.6, stated, in part, that a typical refueling outage involves performance of Sections 8.1 through 8.4 during
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plant shutdown, and then retest of individual valves during the startup if work was performed on any valve during the outage. However, during the Unit 1 R13 refueling outage the licensee did not perform the leak tests during the plant shutdown. This was further affected by the maintenance on Valve 1PSIEV123 being removed from the outage schedule on June 24, 2007, because of a perceived parts issue by supply chain services. The parts required for the maintenance were actually staged on May 24, 2007. The licensee failed to properly code the WO as degraded/nonconforming which allowed for the maintenance to be cancelled without an OD or FA. Completion of the scheduled maintenance would have provided another chance to identify the degraded/nonconforming condition.
 
On July 5, 2007, Valve 1PSIEV123 failed during performance of Procedure 73ST-9SI05, "Leak Test of HPSI/LPSI Containment Isolation Check Valves," Revision 21, and was declared inoperable. The valve failure was because of binding in the spherical bearing due to excessive wear between the hinge arm and spherical bearing. The valve also exhibited excessive washer to hinge arm gap and indications of disc to stud weld interference.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of maintenance and engineering personnel to promptly correct a degraded/nonconforming condition associated with a Part 21 notification related to 3 inch Borg-Warner check valves. The finding is more than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) because the condition only affected the mitigating systems cornerstone and did not result in the actual loss of safety function to any component, train, or system. The cause of this finding had crosscutting aspects associated with OE of the PI&R area in that maintenance and engineering personnel failed to ensure implementation and institutionalization of OE through changes to station processes, procedures, equipment, and training programs (P.2.(b)). The cause of the finding was also related to the safety culture component of accountability in that management failed to reinforce safety standards and display behavior that reflected safety as an overriding priority (O.1.(b)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," states, in part, that measure shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, the licensee failed to promptly correct a degraded/nonconforming condition associated with a Part 21 notification related to 3 inch Borg-Warner check valves and site specific OE, resulting in the failure of Valve 1PSIEV123 while in Mode 3 on July 5, 2007. This was the fifth example of the NCV involving the failure to implement the CAP. This example is of very low safety significance and was entered into the CAP as CRDR 3038601.
 
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5.6.2  Selected System Walkdown The team determined that the LPSI and CS systems were in good material condition, and system components were found in the expected positions. Equipment labels, hangers and supports, and environmental conditions were adequately maintained. There were no observed system leakage points that woul d degrade the system function. General housekeeping practices were found to be adequate; however, the team did identify several issues regarding a lack of control of transient combustibles. No significant deficiencies with regards to configuration control for the selected systems were identified. The team did identify several examples that demonstrated a weakness with the licensee maintaining an adequate condition of less risk significant systems, incorrectly installed scaffolding, equipment tagging, and fire protection features.
 
====a. Inspection Scope====
The team performed a walkdown of general plant areas, and accessible portions of the LPSI and the CS systems for Units 1 and 2, in order to verify the licensee maintained adequate configuration control of risk significant systems. The team reviewed design documents, plant drawings, and system procedures to verify actual plant conditions were consistent with as-built requirements. In addition, the team reviewed applicable temporary modifications to ensure proper installation in accordance with the design
 
information. The team also performed observations of components and surrounding plant areas for the selected systems to identify additional equipment conditions and items that might degrade system performance.
 
====b. Observations and Findings====
b.1 Failure to Maintain Control of Transient Combustibles 
 
=====Introduction.=====
The team identified two examples of a Green NCV of Technical Specification 5.4.1.d for the failure of Fire Protection (FP) personnel to follow procedures for the control of transient combustibles. Specifically, the team identified that on the 70 foot elevation of the auxiliary building (radiation protection (RP) remote monitoring station) and in the Unit 3 containment building, there were transient combustibles being stored without a proper evaluation or the
 
required permits.
 
=====Description.=====
During a walkdown of auxiliary building 70 foot elevation (RP remote monitoring station) on October 1, 2007, the team noted a large amount of transient combustibles (rolls of large plastic bags, large rolls of paper, etc-)
being stored in the area. The team requested the transient combustible control permit (TCCP) for the stored materials. Upon further inspection, the team determined that the licensee did not evaluate the mass quantities of material that were being stored in the area per Procedure 14DP-0FP33, "Control of Transient Combustibles," Revision 15, and that the licensee did not have a TCCP for the additional combustibles. The team noted that the excess combustible material should have been identified during fire watch walkdowns when verifying the requirements for the RP remote monitoring station TCCP were being met.
 
During a walkdown of the Unit 3 containment building on October 2, 2007, the team noted a large amount of transient combustibles being stored in the area.
 
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The team requested the TCCP for the stored materials. During interviews with the program owners, the team was inform ed that containment was exempt from the TCCP program. The team was provided a licensee evaluation that stated issuing permits during the refueling outage for the containment would, "Create a bottleneck and impact work scheduling."  Upon further review of the TCCP program, the team identified that licensee procedures did not exempt containment from the TCCP program. Specifically, Procedure 14DP-0FP33, "Control of Transient Combustibles," Revision 15, stated that all levels and all areas of the containment building required permits for transient materials, including treated wood scaffolding.
 
=====Analysis.=====
The failure to control transient combustibles in accordance with the FP program requirements was a performance deficiency. The finding is more than minor because storing unanalyzed combustibles results in the potential to exceed combustible limits and may increase in the likelihood of an initiating event. Additionally, this finding represented degradation in the FP defense-in-depth strategy in that the licensee did not recognize that bulk materials were being stored in the area in support of the outage. Without proper evaluation, this storage increased the likelihood of a transient fire. Using the Manual Chapter 0609, "Significance Determination Process," Appendix F, "Fire Protection Significance Determination Process," this issue affected the Fire Prevention and Administrative Controls Category. The stored materials required a permit per the licensee's procedure; however, the area was attended, fire detection and suppression was available, and the amounts did not exceed the loading calculation to the point of changing loading classification. Therefore, this finding is considered of low degradation and is determined to have very low safety significance (Green). The cause of this finding had crosscutting aspects associated with work practices of the human performance area in that the licensee failed to communicate human error prevention techniques such that work activities were performed safely (H.4.(a)). The cause of this finding had crosscutting aspects associated with work practices of the human performance area in that the licensee did not effectively communicate expectations regarding procedural compliance (H.4(b)). The cause of this finding was also related to the safety culture component of accountability in that FP personnel failed to demonstrate a proper safety focus and reinforce safety principles among their peers (O.1.(c)).
 
=====Enforcement.=====
Technical Specification 5.4.1.d, states, in part, that written procedures shall be established, implemented, and maintained for FP program implementation. Procedure 14DP-0FP33, "Control of Transient Combustibles," Revision 15, stated in part that transient combustibles being stored in the Auxiliary Building and Containment Building in support of maintenance (outage) activities are required to have a permit. Contrary to the above, between August 23, 2007, and October 5, 2007, the licensee failed to have a proper permit for all of the stored materials in the RP remote monitoring station.
 
Specifically, Fire Area 37A had transient combustibles stored with no associated permit. Additionally, between September 29, 2007, and October 10, 2007, the licensee failed to have a proper permit for all of the stored transient materials in the containment building. Specifically, Fire Areas 63, 66, and 67 had transient combustibles stored with no associated permit. Because this finding was of very low safety significance and was entered into the CAP as PVARs 3071785, Enclosure  - 84 -
3072224, and 3072260, this violation was treated as a NCV, consistent with section VI.A of the NRC Enforcement Policy: NCV 05000530/2007012-08, "Two Examples of a Failure to Maintain Control of Transient Combustibles."  b.2 Failure to Install Emergency Lighting in Containment 
 
=====Introduction.=====
The team identified a Green finding for the failure of maintenance personnel to install emergency lighting in containment in support of the Unit 3 refueling outage per repetitive maintenance WO 2935399 and work instruction WSL 24436. As a result, work began in the Unit 3 containment with no emergency lighting installed and no egress contingency plan for a loss of containment lighting.
 
=====Description.=====
During a walkdown of the Unit 3 containment on October 2, 2007, the team identified that emergency lighting units did not have the batteries installed. Upon further research, the team found the licensee removed emergency lighting batteries in containment while at power to preserve the availability and reliability of the batteries. The batteries were to be reinstalled for outage support; however, the licensee's work instructions did not prescribe when the batteries needed to be re-installed (prior to commencing work). As a result of the inadequate procedural guidance, work commenced in the Unit 3 containment building on September 29, 2007, without having completed the emergency lighting battery installation. Additionally, the licensee did not have a contingency plan for personnel in the event normal power to containment lighting was lost.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of maintenance personnel to have an adequate procedure for installing emergency lighting in containment and not including appropriate acceptance criteria for determining that the activity had been satisfactorily accomplished.
 
This finding is considered more than minor because it is associated with the Mitigating Systems Cornerstone attribute of procedural quality and if left uncorrected, a failure to install emergency lighting could hamper emergency response activities in the containment or complicate emergency egress from the containment. Using the IMC 0609, "Significance Determination Process,"
Appendix M, "Significance Determination Process Using Qualitative Criteria," the finding is determined to have very low safety significance because emergency lighting was necessary for personnel safety and personnel were expected to carry flashlights when responding to events. The cause of the finding has crosscutting aspects associated with work control of the human performance area in that maintenance personnel failed to properly plan the emergency lighting installation work by incorporating contingencies in case the work was not completed in the appropriate timeframe (H.3.(a)). The cause of this finding was also related to the safety culture component of accountability in that management personnel failed to reinforce safety standards and display behavior that reflected
 
safety as an overriding priority (O.1.(b)).
 
=====Enforcement.=====
No violation of regulatory requirements occurred. The team determined that the finding did not represent a noncompliance, because the failure to install the emergency lighting or adequately evaluate the condition occurred on a non-safety-related system. The finding was of very low safety significance and the issue was entered into the CAP under PVAR 3070783.
 
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FIN: 05000530/2007012-09, "Failure to Install Emergency Lighting in Containment Prior to Work Commencement."
 
b.3 Incorrect Installation of Temporary Shielding
 
=====Introduction.=====
The team identified a Green NCV of TS 5.4.1a for the failure of RP personnel to follow procedures for installing temporary shielding in the 87 foot auxiliary building west penetration room.
 
=====Description.=====
During a walkdown of the auxiliary building 87 foot elevation on October 3, 2007, the team observed temporary shielding Package  A-87-10 installed near Train A LPSI piping. Upon further inspection, it was noted that the shielding was in direct contact and installed across the Train A LPSI instrument sensing line. The shielding had been erected per WO 2955341on September 5, 2007, to reduce dose during the Unit 3 refueling outage.
 
Procedure 75RP-9RP25, "Temporary Shielding," Revision 9, stated, in part, that if shielding is to be installed on piping systems which are declared operable, a piping stress analysis must be performed and cited in Specification 13-CN-0211, "Installation Specification for Temporary Shielding for the Palo Verde Nuclear Generation Station Units 1, 2, & 3," Revision 9. Temporary shielding Evaluation 07-017 and installation Specification 13-CN-0211 had evaluated the shielding installation near large bore LPSI piping with no evaluations or operability concerns noted. WO 2955341 stated that the shielding was installed per specification requirements. However, neither the temporary shielding evaluation, the temporary shielding package, nor the installation specification addressed or evaluated the shielding installed in contact with and over the LPSI instrument sensing line.
 
After reviewing the procedures for temporary shielding installation, the team contacted RP personnel and questioned the seismic qualification of the LPSI pressure instrument sensing line. The licensee immediately rearranged the shielding blankets to eliminate the contact with the instrument line. Engineering concluded that the condition could have caused the line to fail during a postulated design basis seismic event. No loss of safety function occurred since the other LPSI train was not affected.
 
=====Analysis.=====
The team determined that the licensee's failure to correctly install temporary shielding was a performance deficiency. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of configuration control and affected the cornerstone objective to ensure availability and capability of systems to respond to initiating events. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, this finding is determined to have very low safety significance (Green) because the condition did not result in an actual loss of safety function and did not screen as risk significant or contribute to external event initiated core damage sequences since it did not involve a loss or degradation of equipment designed to mitigate a seismic event. The cause of this finding had a crosscutting aspect associated with work practices of the human performance area in that the licensee did not effectively use human error prevention techniques such as self checking and proper documentation of activities for the shielding installation (H.4.(a)).
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=====Enforcement.=====
Technical Specification 5.4.1.a requires that written procedures be established, implemented, and maintained covering the activities specified in Appendix A, "Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," of Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operations)," dated February 1978. Regulatory Guide 1.33, Appendix A, Section 9a, requires maintenance that can affect safety-related equipment be properly preplanned and performed in accordance with written instructions appropriate to the circumstances. Procedure 75RP-9RP25, "Temporary Shielding," Revision 9, stated in part, that if shielding is to be installed on piping systems which are declared operable, a piping stress analysis must be performed and cited in Specification 13-CN-0211, "Installation Specification for Temporary Shielding for the Palo Verde Nuclear Generation Station Units 1, 2, & 3."  Contrary to this, between September 5, 2007, and October 3, 2007, the licensee installed temporary shielding in contact with the Train A LPSI instrument sensing line, and a piping stress analysis was not performed. Because the finding was of very low safety significance and was entered into the CAP as PVARs 3071468 and 3072224, this violation was treated as an NCV, consistent with Section VI.A of the Enforcement Policy: NCV 05000530/2007012-10, "Failure to Follow Procedures for Temporary Shielding Installation."  b.4 Observations and Minor Violations Involving Selected System Walkdown b.4.1 Inadequate Seismic Scaffolding Procedures Technical Specification 5.4.1.a requires that written procedures be established, implemented, and maintained covering the activities specified in Appendix A, "Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors" of Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operations)," dated February 1978. Regulatory Guide 1.33, Appendix A, Section 9a, requires maintenance that can affect safety-related equipment be properly preplanned and performed in accordance with written instructions appropriate to the circumstances. Contrary to this, as of October 8, 2007, the licensee did not have adequate procedures or written instructions for maintenance that affects safety related equipment. Specifically, Procedure 30DP-9WP11, "Scaffolding Instructions," Revision 18, did not specify clearance requirements for scaffolding installed near risk important non-safety
 
components that have a potential to impact safety related equipment.
 
Scaffolding was erected with an approximately one half inch clearance between the CS pump room Train A flooding level switch. A failure of the level switch could impact the operability of the CS system during a room flooding event. The finding is determined to be minor because the inadequate procedure did not have any actual safety significance. The finding was of very low safety significance and was entered into the CAP as PVARs 3073777 and 3071468. This performance deficiency is being documented because of the insights associated with inadequate procedures and recurring scaffolding concerns.
 
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5.6.3  Work Control Process The team identified several weaknesses involving the licensee's work control process, including the following areas: adequate risk management of maintenance activities, effective control of main control room deficiencies, prioritization of work with consideration to environmental qualification, adherence to and effectiveness of controls for transient combustibles and hot work, and thoroughness of pre-job briefings. Specifically:
The team observed several control room and work control activities to verify the licensee's controls for independent verification were adequate, including the EDG standby readiness testing and an EW system tagout. No significant discrepancies were observed during these activities. The team did note an event on October 26, 2007, when an incorrect breaker was manipulated because the workers were at the wrong unit. The individuals recognized the mistake and returned the breaker to the as-found position; however, did not immediately notify the control room.
 
Once the control room became aware of t he event, all site wide maintenance work was stopped to reinforce independent verification practices and expectations.
 
The team identified several examples of inadequate risk management regarding shutdown activities and switchyard activities. The team identified a lack of effective communication between the switchyard owners, Salt River Project, and the licensee.
 
Maintenance activities in the switchyard, which could increase the risk of an initiating event, were not thoroughly scheduled and integrated with on-site work activities. In response to the team's findings, the licensee implemented immediate and long term corrective actions to address risk management of switchyard maintenance activities.
 
The team also observed two minor examples of inadequate shutdown risk assessments performed by the licensee which further demonstrated a weakness with the licensee's understanding of risk management.
 
The team noted there were several means of tracking control room deficiencies including: control room deficiency log, jumpered alarm log, lit annunciator log, and multiple operator workaround logs. The team identified that the pens were removed on some strip charts required for post accident monitoring instrumentation. The charts were tagged as being degraded and requiring maintenance; however, it was not recognized by the control room operators that this rendered the instrumentation inoperable.
 
The team inspected the prioritization of maintenance activities as it relates to EQ to verify if equipment was being effectively maintained and not subject to environmental degradation. The team identified an inability of the licensee to maintain the cable vaults void of water and the use of unqualified tape in containment.
 
There were several incidents during the Unit 3 refueling outage involving hot work. The licensee conducted two stand-downs in response to multiple small fires caused by hot work activities. None of the fires were significant enough to warrant an emergency declaration; however, the incidents supported the team's assessment that there appeared to be lack of effective control and communication of expectations regarding administrative controls for hot work and the control of transient combustibles. The licensee did not consistently adhere to the procedures in place for controlling and evaluating temporary and long term storage of transient combustibles throughout the
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plant. Ownership and accountability responsibilities for the control of transient materials was fragmented between FP engineers, operations, and the site fire
 
department.
 
====a. Inspection Scope====
The team conducted a review of the backlog of corrective and preventive maintenance activities to determine if the work control process used risk-insights during planning and scheduling of maintenance and surveillance testing activities and the control of emergent work. The team conducted interviews of licensee personnel, reviewed work packages, and work control and maintenance procedures in order to assess the adequacy of the licensee's efforts to integrate maintenance to minimize equipment unavailability, establish effective communication and coordination, and address plant performance deficiencies. The team reviewed the licensee's policies to assess if the licensee adequately considered the need for planned contingencies, compensatory actions, and abort criteria when scheduling and executing work. The team reviewed the performance history for selected systems and components and compared it to the design basis to verify the licensee made conservative assumptions when scheduling and performing work. The team also reviewed the following: long-term (typically greater than six months) tagouts, caution and danger tags, disabled control room annunciators and instruments, control room deficiencies, operator work-arounds and other equipment deficiency tracking systems, to assess the significance of these
 
conditions.
 
====b. Observations and Findings====
b.1 Failure to Adequately Manage Risk for Switchyard Activities
 
=====Introduction.=====
The team identified a Green NCV of 10 CFR 50.65(a)(4) for the failure to adequately assess the increase in risk and effectively implement risk mitigation actions for maintenance activities in the switchyard (SWYD).
 
=====Description.=====
On October 11, 2007, the team observed several personnel and pieces of equipment moving about the switchyard and noticed postings that stated, in part, to contact the Unit 1 shift manager (SM) for entry into the SWYD.
 
While the activities appeared to be positioning of materials and equipment, the team was unable to determine if any work was being conducted. The team contacted the Unit 1 SM who stated that he was not aware of work in the SWYD and that no one had contacted him for entry into the SWYD. The team then contacted the SWYD coordinator and was informed that work on PL-942 and PL-928 525kV breakers was being performed but he had failed to inform the Unit 1 SM. The team reviewed the risk assessment for the SWYD work and noted it was revised to include the breaker work being performed. During discussions with the licensee's risk analyst and SWYD coordinator about the control and modeling of work in the SWYD, it was noted that the risk model only accounts for certain breakers and relays, and does not independently model equipment or personnel traffic in the SWYD since that was considered in the modeling of the work. It was also noted that routine relay planned maintenance (PM) and equipment movement is not included on the schedule provided to the coordinator and may not be included in the risk assessment. The SWYD coordinator stated that equipment traffic was communicated to him and that the risk was managed
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by scheduling the work, controlling access to the SWYD via the Unit 1 SM, and restricting equipment to designated lanes and areas in the SWYD.
 
On October 24, 2007, the team, accompanied by the SWYD coordinator and a Transmission/Generation Operations (TGO) SWYD foreman, performed a walkdown of the SWYD to observe breaker work. The team noticed multiple trucks, pieces of equipment, and personnel moving around the SWYD that were not involved with the breaker work. The team asked the TGO SWYD foreman about the additional traffic, he stated that this was considered normal and that his crew of 3-10 personnel works almost every day in the SWYD performing maintenance. Procedure 40DP-9OP34, "Switchyard Administrative Control," Revision 16, Step 2.7 stated, in part, that all personnel entering the switchyard shall notify the Unit 1 Shift Manager. When asked about contacting the Unit 1 SM prior to entering the SWYD, he stated that his supervisor coordinated any work with the SWYD coordinator but was not aware of the need to contact the Unit 1 SM for access to the SWYD. During the walkdown, the team also observed a truck outside the designated traffic lanes and noted multiple tire tracks and a man lift inside a restricted access area were no work was being performed. The SWYD coordinator stated he was unaware of all of the equipment traffic occurring in the SWYD.
 
The team noted that the SWYD was not being protected by controlling access and movement as required and that the risk modeling did not include all work being performed. The Unit 1 SM and SWYD coordinator were unaware of the movement of multiple vehicles and pieces of equipment in or near restricted areas nor is this included in the risk model. Additionally, routine relay PM's and maintenance was not included on the schedule provided to the SWYD coordinator for risk review.
 
The team noted that OE existed related to switchyard work, including vehicles in the switchyard, potential impact of switchyard work on offsite power, and taking into consideration all switchyard work when calculating risk in accordance with 10 CFR 50.65. Based on the amount of OE and the importance of offsite power in relation to risk, the licensee should have incorporated more controls to manage work in the switchyard and factored that work into the risk assessment process. In particular:
Information Notice 90-25, "Loss of Vital AC Power with Subsequent Reactor Coolant System Heat-up," described an event that occurred when a truck backed into a support column for a feeder line in the switchyard resulting in a loss of power to the vital buses.
 
Regulatory Issue Summary 2004-005, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power," describes calculating risk associated with 10 CFR 50.65(a)(4), including the impact of switchyard maintenance on the operability of offsite power sources.
 
Temporary Instructions 2515/156, "Offsite Power System Operational Readiness," and 2515/163, "Operational Readiness of Offsite Power," both described the potential impact of switchyard maintenance on offsite power
 
sources.
 
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Generic Letter 2006-02, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power," describes the need for effective coordination of switchyard maintenance and the need to assess risk for switchyard activities.
 
=====Analysis.=====
The failure to integrate all SWYD work into the risk assessment and implement effective risk management actions to assess and manage the risk was a performance deficiency. This finding is greater than minor because the licensee's risk assessment failed to consider maintenance activities that could increase the likelihood of initiating events such as work in the SWYD and failed to effectively manage compensatory measures. Inspection Manual Chapter 0609, Appendix K, "Maintenance Risk Assessment and Risk Management Significance Determination Process," was used to assess the significance. The senior risk analyst made the following assumptions: 
 
===1. In accordance with IMC 0609, Appendix K, the significance of this finding was numerically equal to the incremental core damage probability deficit (ICDPD), or the difference between the ICCDP calculated by the licensee and the ICCDP that would have been calculated had the SWYD work been properly incorporated within the on-line risk monitor.===
 
2. The exposure period for the finding was one year. The finding included both at-power and shutdown conditions.
 
3. Three initiating events were postulated to be caused by human error associated with general work in the SWYD:  loss of offsite power (LOOP),
partial loss of offsite power, and turbine trip/reactor trip.
 
4. There was insufficient data at Palo Verde to estimate the frequency of switchyard-centered LOOPs (none have occurred in the 20 years of operation). Therefore, industry data were used to estimate this value.
 
5. The frequency of LOOP events caus ed by SWYD human error events was derived from NUREG/CR6890, "Reevaluation of Station Blackout Risk at Nuclear Power Stations, Analysis of Loss of Offsite Power Events:
 
1986-2004."
 
A bounding assumption was made that the baseline LOOP and transient initiating event frequencies in the licensee's risk monitor do not include consideration of data related to human error in the SWYD. Although this was not the actual situation, it simplified the analysis and produces a result that can be used to define an upper bound to the significance (which could be refined later if necessary). Therefore, based on this assumption, the baseline was zero and the risk deficit was equal to the expected rate of events caused by SWYD work multiplied by the conditional core da mage probability (CCDP) of the event as quantified in the Palo Verde SPAR model, Revision 3.31. The CCDP of a LOOP event was determined to be 4.332E-5. Using industry data, LOOP event frequencies caused by SWYD work were determined to be 0.0016/year for at-power and 0.0042/year for shutdown conditions during a typical calendar year. The at-power frequency was doubled to account for an increased presence of workers in the Palo Verde SWYD. The average CCDP for a shutdown LOOP was determined by doubling the at-power CCDP. The resulting delta-CDF was
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5.0E-7/year. The risk effect of partial LOOPs and transients caused by SWYD work was determined to be insignificant for this analysis. Neither external events nor large early release contributed to the risk of the finding. Based on the magnitude of the calculated risk being less than 1E-6/year, this finding is determined to have very low safety significance (Green). The cause of this finding had crosscutting aspects associated with work control of the human performance area in that the licensee failed to plan work activities incorporating risk insights (H.3.(a)). The cause of this finding had crosscutting aspects associated with work control of the human performance area in that the licensee failed to appropriately communicate work activities (H.3.(b)).
 
=====Enforcement.=====
10 CFR Part 50.65(a)(4), states in part, that before performing maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to this, between October 11 and 24, 2007, the licensee failed to adequately assess and manage the increase in risk.
 
Specifically, the licensee failed to include all work being performed in the risk assessment and fully implement risk management actions to protect the SWYD. Because the finding was of very low safety significance and was entered into the CAP as PVAR 3078392, this violation was treated as an NCV, consistent with Section VI.A of the Enforcement Policy: NCV 05000528, 05000529, 05000530/2007012-11, "Inadequate Implementation of Risk Management Actions and Risk Assessment for the Switchyard."
 
b.2 Observations and Minor Violations Involving Work Control Processes b.2.1 Failure to Properly Document Temporary Modifications The team identified a minor violation of Technical Specification 5.4.1.a for the failure of operations and maintenance personnel to follow Procedure 81DP-0DC17, "Temporary Modification Control," Revision 20. Procedure 81DP-0DC17 required, in part, that:  1) upon completion of the installation, a copy of the temporary modification procedure/work order pages shall be given to the control ro om, and 2) upon receiving a copy of the procedure/work order, the SM, control room supervisor, or authorized designee shall log the temporary modification into a temporary modification book or computer spread sheet. Contrary to this, on October 15, 2007, the team identified that temporary modifications installed to support the Class 1E Bus E-PBA-S03 and Non Class 1E Bus NAN-S02 outages on Unit 3, were not accounted for in the temporary modification book and the procedures/work orders were not being given to the control room in accordance with procedural guidance. This finding
 
was entered into the licensee's CAP as PVAR 3076979. Using IMC 0612, Appendix E, "Examples of Minor Issues," this finding was determined to be minor because this was an insignificant procedural error and there were no safety consequences. This performance deficiency is being documented because of insights associated with procedure compliance and conduct of operations.
 
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b.2.2 Inadequate Shutdown Risk Assessments The team identified two minor examples of improperly performed shutdown risk assessments for Units 2 and 3 performed by the shift technical advisors (STAs).
 
At 6:58 p.m. on October 4, 2007, the site entered a severe thunder storm warning. The STA was called back to the Unit 3 control room to re-evaluate the risk assessment due to this emergent condition. The STA used the control room posted risk assessment as a tool to determine if the risk to the current plant conditions had changed due to the severe weather. The STA incorrectly determined that part two of the shutdown risk assessment identified severe weather as a high risk to electrical resources and inventory control. The STA then marked the two identified areas as increased risk to yellow from green. When questioned by the team as to why inventory control risk had increased as well as electrical resources, the STA acknowledged he had made an error and inventory control should not have been increased to yellow risk. The STA corrected the error for inventory control and downgraded the risk to green. The licensee generated PVAR 3072733 to document this issue.
 
The Unit 2 SM declared the Train A EDG available at 5:58 a.m. on October 11, 2007. The team noted that the shutdown risk assessment did not include the availability of the Train A EDG in the shutdown risk assessment. The shutdown risk assessment was evaluated as the EDG being unavailable placing the unit in the incorrect yellow risk category for electrical resources. When the team questioned the STA about the Train A EDG status; the STA was not aware the SM had declared the EDG available. Procedure 70DP-0RA01, "Shutdown Risk Assessment," Section 3.1 required the STA to provide actual plant conditions for determining the plant shutdown risk profile. Contrary to this, the STA failed to correctly evaluate risk for the electrical resources and placed the Unit in a yellow risk status when it should have been in a green risk status. A contributing cause to this incorrect shutdown risk assessment was the lack of timely information being made available to all control room staff members in reference to the status of the Train A EDG.
 
Using IMC 0612, Appendix E, "Examples of Minor Issues," these examples were determined to be minor because they were an insignificant procedural error and there were no safety consequences.
 
The performance deficiencies are being documented because of insights associated with control room behaviors and maintenance rule implementation.
 
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5.6.4  Control of Fission Barriers The team determined that the programs outlining configuration control of components and equipment related to fission product barriers were adequate. During a walkdown of containment, the team noted discrepancies with rigging of the personnel air lock (PAL)door that had the potential to impact the functionality of the PAL door.
 
====a. Inspection Scope====
The team observed a selected portion of the containment isolation lineup to independently verify whether valves, dampers, and airlock doors were being properly controlled in accordance with the licensing and design bases. The team reviewed plant drawings and system procedures to verify that selected components were in their required positions. The team conducted interviews and reviewed the licensee's policies to assess whether the programs and c ontrols (tracking systems) in place for maintaining knowledge of the configuration of the fission product barriers including:
containment leakage monitoring and tracking, containment isolation device operability (valves, blank flanges), and reactor coolant leak-rate calculation and monitoring were adequate. The team also observed selected containment isolation tests to independently verify whether the valves were being properly controlled in accordance with 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," and local leak rate testing programs.
 
b. Observation and Findings b.1 Incorrect Rigging for Personnel Air Lock Door 
 
=====Introduction.=====
The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure of maintenance personnel to follow procedures to rig the Unit 3 100 foot elevation inner PAL door. Specifically, the suspended rigging was completed with the inappropriate placement of the wire rope slings over two of the locking pins resulting in an unanalyzed force being applied to the door's operating
 
mechanism.
 
=====Description.=====
On October 2, 2007, during a walk down of the Unit 3 containment, an inappropriate rigging configuration of the Unit 3 100 foot elevation inner PAL door was identified. The team questioned the Bechtel rigging engineer on the placement of the wire rope slings over the locking pins of the door. The Bechtel rigging engineer explained the tension forces developed for the basket rigging configuration of the door, but did not provide any additional supporting information to address the team's questions. On October 2, 2007, Bechtel generated NCR 25030-U3-035 to document that the rigging configuration was not completed in accordance with Bechtel Drawing U3-FSK-C-022. Specifically, the shackles shown on drawing Section D-D, Item 9, were installed inverted and the slings shown on drawing Section D-D, Item 11, were installed over the existing door closure pin instead of behind the pin. The licensee generated PVAR 3070843 to document that the PAL door rigging installation was in error.
 
The team's review of Procedure VTD-T966-0001, Section XIII, "Maintenance," on lubrication, identified that the door latch pin guides each have bronze bushings.
 
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The bronze bushing in the door latch pin guide was not a fixed support. The identification of a bushing that was not designed for vertical loading invalidated the Bechtel engineering evaluation bounding assumption that the configuration was in cantilever loading. The licensee generated PVAR 3086057 to document that the PVAR 3070843 and NCR 25030-U3-035 responses were not adequate, and that there was potential bushing damage.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of maintenance personnel to rig the Unit 3 100 foot elevation inner PAL door in accordance with WO 2688885, and the subsequent failure to adequately evaluate any potential impacts from the unanalyzed rigging configuration. The finding is greater than minor because it would become a more significant safety concern if left uncorrected in that the applied suspended force on the bronze bushing and the door's operating mechanism, which were not designed for vertical loading, could degrade the PAL door sealing capability. This finding could not be evaluated by the significance determination process because IMC 0609, "Significance Determination Process," Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations," and Appendix G, "Shutdown Operations Significance Determination Process," did not apply to the PAL door for the plant conditions that existed during the event. This finding affects the barrier integrity cornerstone and is determined to have very low safety significance (Green) by NRC management review using the IMC 0609, "Significance Determination Process," Appendix M, "Significance Determination Process Using Qualitative Criteria," because it is a deficiency that did not result in the actual breach of the containment barrier. The cause of this finding had crosscutting aspects associated with work practices of the human performance area in that maintenance personnel failed to provide adequate oversight of work activities, including contractors, such that nuclear safety was supported (H.4.(c)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," requires, in part, that activities affecting quality shall be accomplished in accordance with prescribed instructions, procedures, and drawings. Contrary to the above, Bechtel construction workers failed to rig the
 
Unit 3 100 foot elevation inner personnel air lock door per Bechtel Drawing U3-FSK-C-022 and Work Order 2688885. Specifically, the suspended rigging was completed with the inappropriate placement of the wire rope slings over two of the locking pins resulting in an unanalyzed force being applied to the door's operating mechanism. The slings were required to be placed under the locking pins, not over. Because this violation was of very low safety significance and was entered into the corrective action program as PVAR 3086057, the issue was treated as a NCV consistent with Section VI.A.1 of the NRC Enforcement Policy NCV 05000530/2007012-12, "Incorrect Rigging for Personnel Air Lock Door."
 
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5.6.5  Review of Individual Plant Examination
 
====a. Inspection Scope====
The inspection team reviewed the results of the plant specific Individual Plant Examination relative to selected systems to determine if the Individual Plant Examination is being maintained to reflect actual system conditions regarding system capability and reliability.
 
====b. Observations and Findings====
No findings or observations were identified.
 
5.6.6  Human Performance
 
====a. Inspection Scope====
The team observed several maintenance related work activities to determine if Palo Verde personnel effectively identified, evaluated, and corrected deficiencies involving human performance. The team observed pre-job briefings, clearance order activities, and work performance.
 
====b. Findings and Observations====
b.1 Observations and Minor Violations Involving Human Performance b.1.1 Inadequate Procedure for Adjustment of Polar Crane Limit Switch Technical Specification 5.4.1.a, requires, in part, that written procedures be established, implemented, and maintained covering the activities specified in Appendix A, "Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," of Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operations)," dated February 1978. Regulatory Guide 1.33, Appendix A, Section 9a, requires maintenance that can affect safety-related equipment be properly preplanned and performed in accordance with written instructions, documented instructions and drawings appropriate to the circumstances. Contrary to this, on October 9, 2007, the licensee performed maintenance without the appropriate instructions and drawings resulting in a failure to retain quality related documents and an incorrect evaluation of maintenance results.
 
Specifically, on October 10, 2007, the team identified that WO 3068693 did not contain appropriate direction for the setting of the 18 foot maximum limit switch position for the Unit 3 polar crane main hoist resulting in the electrical technicians documenting a height of 18 foot 0.375 inches when the actual height was 17 foot 6.375 inches. Using IMC 0612, Appendix E, "Examples of Minor Issues," this finding was determined to be minor because this was an insignificant procedural error and there were no safety consequences. This finding was of very low safety significance and was entered into the CAP as PVARs 3073911, 3074132 and 3086770. This performance deficiency is being documented because of insights associated with inadequate procedures.
 
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5.6.7  Design
 
====a. Inspection Scope====
The team conducted general walkdowns of the containment and auxiliary buildings and reviewed current component configuration, material condition, and equipment status. The team also reviewed a sample of PVARs and CRDRs to assess the effectiveness of corrective actions for deficiencies involving design activities. During the walkdown and review the team noted discrepancies with pressurizer instrument brackets and breaker modifications.
 
====b. Observations and Findings====
b.1 Failure to Maintain Configuration Control of Pressurizer Instrument Condensing Pot Support Brackets
 
=====Introduction.=====
The team identified a NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," for the failure of maintenance and engineering personnel to maintain proper configuration of the support brackets for the pressurizer condensate pots in accordance with design drawings. Specifically, on October 2, 2007, the team identified that the support bracket U-bolts were not tight against the condensate pot piping, jam nuts were not installed on the U-bolts, and jacking bolts were not in full contact with the pressurizer vessel. The support brackets minimize lateral motion during a seismic event.
 
=====Description.=====
On October 11, 2007, the team conducted a containment walkdown and observed that the support brackets for Valves 3PRCCV204 and
 
3PRCAV206, (pressurizer instrumentation root valves), had different configurations. The licensee evaluated the brackets and determined that they were not configured in accordance with design Drawings 13-J-ZZS-0080, "Condensing Pot Support Details," and 13-J-ZZS-0081, "Condensing Pot Support Details Pressurizer."  The design drawings stated to field tighten the jacking bolt stud to the pressurizer vessel hand tight, then add jam nuts; and the U-bolts to be field tightened to obtain zero clearance around the pipe, then secured with a jam nut. The bracket for Valve 3PRCCV204 had both U-bolts in full contact with the pipe and 3 of the 4 jack bolt studs in contact with the pressurizer vessel. The bracket for Valve 3PRCAV206 had 1 of 2 U-bolts in full contact with the pipe and 3 of the 4 jack bolt studs in contact with the pressurizer vessel. The licensee entered the issue into the CAP as PVAR 3075704 and generated CRDR 3078397 and corrective maintenance WO 3076022 to resolve the deficiency.
 
On October 13, 2007, the licensee performed an OD which determined that based on Calculation 13-MC-ZZ-0037, "Evaluation of Double U-Bolts Used as an Anchor Restraint," only 1 of 2 U-bolts was required to maintain the design function of the support; and Calculation 13-MC-RC-501, "RCS - Pressurizer Surge Line," indicated that there was margin in the design to transfer the load to the remaining jack bolt studs. Civil engineering determined that the incorrect support configuration was acceptable without an adverse effect on the subject pipe stresses and pipe support design. PVAR 3075704 identified a need to
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review the potential transportability to the other units and similar valves around the pressurizer using this hanger design.
 
On October 30, 2007, the team visually inspected the support brackets for Pressurizer Instrument Root Valves 3PRCDV205 and 3PRCBV207. The team identified that 2 of 4 jack bolts on Valves 3PRCDV205 and 3PRCBV207 were not in contact with the pressurizer vessel in accordance with design Drawings 13-J-ZZS-0080 and 13-J-ZZS-0081. The team noted that the original immediate OD stated that there was a margin in the design to transfer the load to the remaining 3 of 4 jack bolts still in contact with the pressurizer vessel, not when 2 of 4 jack bolts were not in contact. Civil engineering personnel evaluated the effect of 2 jack bolts not being in contact with the pressurizer vessel and determined that this condition was acceptable without an adverse affect to the subject pipe stresses and pipe support design/evaluation.
 
On November 5, 2007, the licensee completed WO 3076022 to correct the deficiencies identified in the support brackets associated with Valves 3PRCCV204, 3PRCDV205, 3PRCAV206, and 3PRCBV207, restoring the support brackets in accordance with design drawings.
 
On November 6, 2007, the team visually inspected the support brackets for Valve 3PRCDV205 and 3PRCBV207 and identified that the bracket for Valve 3PRCDV205 was missing the jam nuts for the U-bolt farthest from the pressurizer vessel. WO 3076022 indicated that the bracket U-bolts were restored to the appropriate configuration and verified by civil engineering on November 3, 2007. This issue was entered into the CAP as PVAR 3089364.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of maintenance and engineering personnel to maintain proper configuration of the support brackets on Valves 3PRCCV204, 3PRCDV205, 3PRCAV206, and 3PRCBV207 in accordance with the design drawings. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. This finding had crosscutting aspects associated with the work practices component of the human performance area because maintenance personnel did not effectively use human error prevention techniques such as self checking and proper documentation of activities for the installation of the support bracket (H.4.(a)).
 
=====Enforcement.=====
10 CFR Part 50, Criterion V, "Instructions, Procedures and Drawings," requires, in part, that activi ties affecting quality shall be prescribed by documented instructions, procedures, or drawings and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to this, since 2003, maintenance personnel did not ensure that Unit 3's support brackets for Valves 3PRCCV204, 3PRCDV205, 3PRCAV206 and 3PRCBV207 were configured and maintained in accordance with design drawings 13-J-ZZS-080
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and 13-J-ZZS-081. Specifically, the support bracket U-bolts were not tight against the pipe, jam nuts were not installed on the U-bolts, and jacking bolts were not in full contact with the pressurizer vessel. Because the finding was of very low safety significance and was entered into the CAP as PVAR 3070805 and 3075704, this violation was treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000530/2007012-13, "Failure to Maintain Configuration Control of Pressurizer Instrument Condensing Pot Support
 
Brackets."  b.2 Observations and Minor Violations Involving Design b.2.1 Lack of Design Control for Breaker Modification The team identified a minor finding for the failure of engineering personnel to maintain design control measures for a temporary electrical power modification per Procedure 01DP-0CC01, "Configuration Control,"
Revision 0. The team identified that a modification to install 70 amp breakers in place of 60 amp breakers for temporary power used during the outage to power instrument air and breathing air was placed on the cancelled modifications list. After questioning engineering personnel, the team determined the modification was cancelled before full implementation. Plant drawings were updated for Unit 3 to reflect a 70 amp breaker installation. No changes to drawings were made for Units 1 and 2. During a plant walkdown, the team discovered all 60 amp breakers were installed in each of the three units. The licensee was unaware the modification was on the cancelled modifications list and records indicated the modification had been completed in October 1993.
 
This finding was determined to be of very low safety significance because the cancelled modification was for temporary power for instrument air and breathing air and did not affect any safety related equipment. The licensee placed the issue into their CAP as PVAR 3068451.
 
5.6.8  Problem Identification & Resolution
 
====a. Inspection Scope====
The team conducted general walkdowns of the containment and auxiliary buildings. The team reviewed current component configuration, material condition, and equipment status. The team also reviewed a sample of PVARs and CRDRs to assess the effectiveness of corrective actions for degraded and unanalyzed conditions. The team ensured that licensee evaluations of, and corrective actions to, significant performance deficiencies have been sufficient to correct the deficiencies and prevent recurrence.
 
====b. Observations and Findings====
b.1 Failure to Evaluate Adverse Condition for the Emergency Diesel Generators 
 
=====Introduction.=====
The team identified an eighth example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and 
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Drawings," for the failure of operations and engineering personnel to adequately evaluate degraded and unanalyzed conditions to support operability decision making associated with EDG leaks.
 
=====Description.=====
On October 2, 2007, the team conducted a walk down of the Unit 3 EDGs. During the walk down, several puddles of oil and surfaces wet with fluids were identified. The observations were shared with the licensee who stated that CRDR 2914886 initiated August 1, 2006, addressed the issue of lube oil leaks.
 
In response to the team's observations, maintenance personnel conducted additional walk downs of the Unit 3 EDGs to make an assessment of any new leaks.
 
The team reviewed the evaluation for CRDR 2914886 which stated that, "Engineering, operations, and maintenance were aware of the several small oil leaks but no program existed to quanti fy the leakage, nor had an evaluation of the aggregate impact been performed."  The team also reviewed CRAI 2979205 completed on June 6, 2007, that contained an engineering evaluation of the maximum allowable leak rate for diesel lube oil of 0.5 gallons per hour (gph) was acceptable. This was based on the lube oil burn rate of 1.0 gph such that a total net lube oil consumption rate of 1.5 gph for seven days would not exceed the Technical Specification bases. Additionally, the team reviewed engineering white paper, "EDG Fluid Leakage and Operability," issued December 1, 2006. The white paper listed several areas that were known to leak and gave some general guidance on leak locations that would be of operational concern. The guidance also listed several leak locations that were considered nuisance leaks and that minor drips or weeps were not an operability concern. However, no definition of what quantity of leakage would be considered minor or nuisance was provided.
 
The team reviewed the EDG fluid leakage database used to track leaks that are being monitored. The database listed the source, WO's written, and internal engineering severity rankings. Engineering classified all of the identified leaks as minor with varying severity rankings. The licensee concluded that none of the individual leaks would challenge the operability of the EDGs. Concerned that the total aggregate of all of the leaks may exceed the allowed leak rate, the team questioned operability based on the number and location of leaks.
 
Procedure 40DP-9OP26, "Operability Determination and Functional Assessment," Revision 18, Step 3.1.1, stated, in part, that the OD process is entered upon discovery of circumstances where operability of any SSCs described in Technical Specifications is called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition. However, engineering personnel stated that only individual leaks greater than 0.5 gph would be of concern for operability and performing a quantitative evaluation or aggregating all the oil leaks would be too difficult. Engineering personnel acknowledged that it would be beneficial to determine if the total oil leak rate
 
exceeded 0.5 gph.
 
The team performed walkdowns to determine if additional leaks existed. Based on transportability of oil and poor EDG housekeeping, the team was unable to determine if leaks, other than the leaks listed in the EDG fluid leakage database, existed. While none of the individual leaks identified were determined to challenge the operability of the EDGs (each was less than 0.5 gph), the team
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expressed their concern about the adequacy of the licensee's program to identify individual leak rates and track the aggregate leak rates of the EDGs to ensure that material condition issues would not create a challenge to operability.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of operations and engineering personnel to adequately evaluate degraded and unanalyzed conditions to support operability decision making. This finding is greater than minor because it would become a more significant safety concern if left uncorrected in that unanalyzed conditions could challenge the operability of the EDGs. The finding affected the mitigating systems cornerstone. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) because the finding did not result in the actual loss of safety function. The cause of this finding had a crosscutting aspect associated with corrective action of the PI&R area in that the licensee did not thoroughly evaluate previous EDG leaks such that the resolutions addressed all conditions affecting operability (P.1.(c)).
 
=====Enforcement.=====
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," requires that activities affecting quality shall be prescribed by instructions, procedures, or drawings, and shall be accomplished in accordance with those instructions, procedures, and drawings. The assessment of operability of safety-related equipment needed to mitigate accidents was an activity affecting quality, and was implemented by Procedure 40DP-9OP26, "Operability Determination and Functional Assessment," Revision 18. Procedure 40DP-9OP26, Step 3.1.1, stated, in part, that the OD process is entered upon discovery of circumstances where operability of any SSC described in the Technical Specifications is called into question upon discovery of a degraded, nonconforming, or credible unanalyzed condition. Contrary to the above, between August 1, 2006 and October 2, 2007, operations and engineering personnel failed to enter the OD process upon discovery of circumstances where the operability of a component was called into question. Specifically, operations and engineering personnel failed to consider all relevant information to perform an adequate OD when evaluating aggregate EDG lube oil leaks. This was the eighth example of the NCV involving the failure to implement the OD program. This example was of very low safety significance and was entered into the licensee's CAP as PVAR 3073559.
 
b.2 Failure to Identify and Correct a Non-Conforming Condition of Post-Accident Monitoring Instrumentation Recorders 
 
=====Introduction.=====
The team identified a sixth example of the Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure to promptly correct a nonconforming condition that resulted in the inoperability of several post accident monitoring (PAM) chart recorders.
 
=====Description.=====
On October 10, 2007, the team conducted a Unit 3 control room walk down and observed that several PAM chart recorders had significant ink bleeding on the paper roll and that pens had been removed from several instruments. Operations personnel stated that this was normal due to the design of the pens, that the bleeding rendered the affected chart recorders unusable for historical trending, and that if the bleeding was severe enough they would pull
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the pen from the chart recorder. The team questioned the operability of the PAM chart recorders if the trend plots were unusable or if the pens were pulled. The team was referred to CRDR 2629437, initiated on August 8, 2003, that indicated there were no immediate operability concerns, even with the trend data not usable, because the paper scales of the chart recorders were not calibrated.
 
During the review of CRDR 2629437, the team noted that the evaluation stated that no cause could be determined and that the only corrective action was to track the cause determination and solution implementation. No corrective actions were identified for removing the pens from the PAM chart recorders. Based on this cause evaluation, the licensee initiated CRAI 2637936 on September 28, 2003, to replace the instruments.
 
On March 9, 2005, during procurement engineering's review of the issue, an engineer questioned the original operability determination contained in CRDR 2629437, stating that UFSAR Table 1.8-1, "PVNGS Compliance with Regulatory Guide 1.97 (Revision 2) Requirements," listed chart recorders that are required for compliance with Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident,"  Revision 2. Regulatory Guide 1.97 states, in part, where direct and immediate trend or transient information is essential for operator information or action, recording should be continuously available on dedicated recorders. CRAI 2790230 was issued to perform another operability evaluation of the chart recorders. However, this action was not taken until April 11, 2005, approximately 21 months after the initial concern and over a month after procurement engineering questioned the original operability evaluation. Again, this second operability evaluation determined that no immediate operability concerns existed since there were no surveillance requirements for the recorders and the Technical Specification basis did not specifically address the recorder as part of a required PAM channel. The team noted that both operability evaluations failed to address the UFSAR requirements for compliance with Regulatory Guide 1.97.
 
On October 24, 2007, the team conducted additional walk downs of the Units 1 and 2 control rooms. The Unit 1 control room had several recorders with moderate chart bleeding and two with pens removed. The team noted that the Unit 2 control room had two recorders with moderate ink bleeding. The team again questioned the licensee about PAM instrument operability based on the UFSAR Table 1.8-1 listing of chart recorders that are required for compliance with Regulatory Guide 1.97. Operations again provided the basis contained in CRAI 2790230 for continued operability of the chart recorders.
 
On October 29, 2007, after additional discussions about operability with PVNGS senior management, the licensee recognized that two chart recorders in the Unit 1 control room had pens removed. Senior management immediately directed operations personnel to install the pens and made operations aware of the requirements to maintain pens in the recorders. During the Unit 2 walk down, senior management discovered that operations personnel had minimized the ink bleeding on the chart recorders by removing about half of the ink from the pens.
 
This interim corrective action was not shared with the other units or documented
 
in the CAP.
 
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On October 29, 2007, the licensee initiated PVAR 3086251. PVAR 3086251 indicated that the recorders were required for trending and recording. All the recorders were verified to have pens installed and a night order was written to alert operations personnel about this condition. The night order required operations personnel to declare the PAM instrument channel inoperable if the recording function was not available for any reason (including blotching or
 
bleeding).
 
The inspectors concluded that the licensee had failed to review the licensing basis for the PAM chart recorders and failed to implement corrective actions to maintain the functionality of the instruments. This condition involved multiple safety and non-safety related recorders that were in a non-conforming condition for an unspecified period with no controls or compensatory actions in place.
 
=====Analysis.=====
The performance deficiency associated with this finding involved the failure to identify an inadequate operability evaluation and the failure to promptly correct a non-conforming condition that resulted in the inoperability of PAM chart recorders. The finding is greater than minor because it would become a more significant safety concern if left uncorrected in that safety-related equipment that was not maintained in a qualified condition may not be available to perform its safety function under certain accident conditions. The finding affected the mitigating systems cornerstone. Using the IMC 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance because it did not result in a complete loss of system safety function. The cause of this finding had crosscutting aspects associated with corrective actions of the PI&R area in that the licensee did not thoroughly evaluate previous issues such that the resolutions addressed all conditions affecting operability (P.1.(c)). The cause of the finding was also related to the safety culture component of accountability in that management failed to reinforce
 
safety standards and display behavior that reflected safety as an overriding priority (O.1.(b)).
 
=====Enforcement.=====
10 CFR Part 50, Criterion XVI, "Corrective Action," requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformance, are promptly identified and corrected. Contrary to this, from August 8, 2003, to October 29, 2007, operations personnel did not promptly identify and correct conditions adverse to quality. Specifically, licensee personnel unknowingly rendered chart recorders for PAM instrumentation inoperable by removing the ink pens and failed to take prompt corrective actions to restore operability of PAM instrument chart recorders. This was the sixth example of the failure to implement the CAP. This example was of very low safety significance and was entered into the CAP as CRDR 3088033.
 
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5.6.9  Equipment Performance
 
====a. Inspection Scope====
The team reviewed the operational performance of selected safety systems to verify their capability of performing the intended safety functions. The team assessed the effectiveness of corrective actions for deficiencies involving equipment performance, including equipment designated for increased monitoring via implementation of the Maintenance Rule. The team also ensured that the licensee has effectively implemented programs for control and evaluation of surveillance testing, calibration, and post-maintenance testing.
 
====b. Observations and Findings====
b.1 Failure to Establish Maintenance Rule Goals for the Safety Injection System 
 
=====Introduction.=====
The team identified a Green NCV of 10 CFR 50.65 for the failure of engineering personnel to establish goals and monitor the performance of the safety injection system. Specifically, as of March 22, 2007, engineering personnel failed to establish goals to properly monitor system performance, or provide a technical justification to demonstrate that monitoring under 10 CFR 50.65(a)(1) was not required for the safety injection system following the system changing status from 10 CFR 50.65(a)(2) to 10 CFR 50.65(a)(1).
 
=====Description.=====
On October 25, 2007, following the team's request for 10 CFR 50.65(a)(1) action plans for several risk significant systems, it was discovered that the licensee had reclassified the safety injection system from 10 CFR 50.65(a)(2) status to 10 CFR 50.65(a)(1) status because of  unacceptable unavailability. Specifically, the HPSI pumps had experienced unavailability issues and sporadic reliability issues for the last three years. However, engineering personnel did not establish goals to properly monitor system performance, or provide a technical justification to demonstrate that monitoring under 10 CFR 50.65(a)(1) was not required. As a result of the team's questions, the licensee initiated actions to establish goals and monitoring for the safety injection system. The team noted that this concern was not identified during the licensee's annual maintenance rule program assessment.
 
=====Analysis.=====
The performance deficiency associated with this finding was the failure of engineering personnel to properly establish goals and monitor system performance; and provide technical justification for not establishing goals for the safety injection system. This finding is greater than minor because it was associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, "Significance Determination Process,"
Phase 1 Worksheets, the team concluded the finding is of very low safety significance (Green) because there was no design deficiency, and the finding did not represent an actual loss of a safety function. The cause of this finding had crosscutting aspects associated with corrective action of PI&R area in that engineering personnel failed to take appropriate actions to address safety issues and adverse trends in a timely manner (P.1.(d)). The cause of this finding had
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crosscutting aspects associated with self assessments of the PI&R area in that engineering personnel failed to perform self assessments that were comprehensive, appropriately objective, and self-critical (P.3.(a)).
 
=====Enforcement.=====
10 CFR 50.65(a)(1) states, in part, that the performance or condition of systems shall be monitored against established goals, to provide reasonable assurance that the systems are capable of performing their intended functions. 10 CFR 50.65(a)(2) requires, in part, that monitoring as specified in paragraph 10 CFR 50.65(a)(1) is not required where it had been demonstrated that the performance or condition of a system was being effectively controlled through the performance of appropriate preventive maintenance such that the system remained capable of performing its intended function. Contrary to the above, Between March 22 and October 25, 2007, the licensee failed to establish goals and monitor the performance of the safety injection system to provide reasonable assurance that the system was capable of performing its intended function. Specifically, the licensee determined that the performance of the safety injection system was such that it was necessary to monitor system performance against established goals under 10 CFR 50.65(a)(1), yet failed to establish goals and/or monitor the performance of the system against such goals. Because this finding is of very low safety significance and had been entered into the CAP as PVARs 3074255 and 3076699, this violation is being treated as an NCV, consistent with Section V1.A of the Enforcement Policy:  NCV 05000528; 05000529; 05000530/2007012-14, "Failure to Implement Maintenance Rule Requirements for the High Pressure Safety Injection System."
 
5.7 Emergency Preparedness and Response The team had not originally planned an in-depth review of the Emergency Response Strategic Performance Area. However, between October 1 and 12, 2007, the team identified significant issues with the licensee's ability to correctly classify an emergency condition and/or determine a Protective Action Recommendation (PAR). Between October 29 and November 2, 2007, emergency planning specialists from both NRC Region IV and Headquarters were added to the team to conduct a more detailed emergency response assessment. Further review by the team noted significant knowledge gaps associated with emergency classifications and PARs, and a failure to correct identified weaknesses. On October 28, 2007, in response to the problems identified by the team, the licensee instituted corrective actions to augment the emergency response organization (ERO) by assigning 6 managers, specially trained on EAL classification, to the shift rotation until additional training could be provided to the remaining ERO members. The team determined that this interim measure should be effective in improving EAL implementation. Nevertheless, significant improvement in emergency response program knowledge, and correction of emergency plan weaknesses was warranted.
 
====a. Inspection Scope====
The team conducted a limited assessment of the ability of licensee personnel to activate the ERO augmentation of on-shift personnel. The team assessed the effectiveness of prior corrective actions involving ERO deficiencies. Although, no ERO drills were conducted or reviewed during this evaluation, the team reviewed emergency response facilities, planned on-shift emergency response, and augmented
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emergency response staffing. The team selected 10 members of the ERO and tested their ability to implement EAL event classifications. Since the Emergency Preparedness Cornerstone was not degraded, IP Attachment 95003.01, "Emergency Preparedness," was not conducted.
 
====b. Observations and Findings====
b.1 Failure to Correct a Risk Significant Planning Standard 
 
=====Introduction:=====
The team identified an apparent violation with the significance to be determined for the licensee's failure to correct an identified risk significant planning standard weakness from May 2, 2007, through October 28, 2007. The finding had a potential safety significance of White.
 
=====Description:=====
10 CFR Part 50, Appendix E.IV.F.2.g., requires, in part, that any deficiencies identified as a result of training, exercises, or drills be corrected. Between May 2 and October 28, 2007, the licensee failed to implement adequate corrective actions for identified deficiencies which impacted a risk significant planning standard associated with the ability to make EAL declarations.
 
Background:
For a steam generator tube rupture (SGTR), with a 200 gpm primary/secondary leak, valid reactor vessel level monitoring system (RVLMS) level < 21 percent plenum level, and the use of automatic depressurization valves (ADVs) with the secondary plant stabilized, EPIP-99, "EPIP Standard Appendices," Table 1, "Fission Product Barrier Reference (Modes 1-4)," specified the following EAL classification.
 
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FUEL CLAD BARRIER RCS BARRIER CONTAINMENT BARRIER POTENTIAL LOSS POTENTIAL LOSS LOSS LOSS Valid RVLMS currently or previously < 21 percent plenum (EAL 1-2)
SGTR > 44
 
gpm  (EAL 1-7) SGTR >132 gpm with a prolonged release of contaminated
 
secondary coolant occurring from the
 
ruptured S/G to the environment (See Limitations in
 
Section 1) 
(EAL 1-7)
Release of
 
contaminated secondary side to atmosphere (i.e., S/G
 
safety or ADV) with
 
S/G primary to
 
secondary leakage > Technical Specification allowable limits (EAL 1-14) APPLY THE CRITERIA ABOVE TO THE CONDITIONS BELOW UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY Any loss OR
 
any potential
 
loss of containment Any loss OR any potential loss of either
 
fuel clad or reactor coolant system (RCS)
 
Loss of both fuel
 
clad and RCS
 
Or Potential loss of both fuel clad and RCS Or Potential loss of
 
either fuel clad or RCS and loss of any additional barrier Loss of any two barriers And Potential loss of a third barrier  EPIP-99, Section 1, "Precautions and Limitations," Step 1.7, stated, "Used in the context of a steam generator tube rupture as stated in the Fission Product Barrier EAL [1-7], a "prolonged release of contaminated secondary coolant" encompasses a main steam line break, feedwater line break, stuck open steam generator safety and/or atmospheric dump valve(s), and plant cooldown (i.e., to Mode 5) while steaming the affected steam generator to atmosphere."  The team noted that for the associated EAL JPM's, the licensee was using the ADVs to stabilize the secondary plant (a plant cooldown was not in progress). The correct emergency classification was a Site Area Emergency based on the following conditions:  SGTR >44 gpm resulting in a potential loss of the RCS barrier; RVLMS <21 percent resulting in a potential loss of the fuel clad barrier; and a release of contaminated secondary side to atmosphere through the ADVs with primary to secondary leakage exceeding Technical Specification limits resulting
 
in a loss of containment barrier.
 
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Training Requirement:
Licensed Operator Continuing Training (LOCT) Program Description, Revision 31, required SROs responsible to fill ERO positions to maintain emergency preparedness proficiency by receiving annual training to meet EP training requirements as specified in Section 8.1.1.2, "Specialized Training for Key Emergency Organization Personnel," of EPIP-59, "Emergency Planning Training Program
 
=====Description.=====
"  EPIP 59 further defined the necessary training to maintain emergency preparedness proficiency for onshift emergency coordinators, which included all of the control room supervisors and SMs.
 
PVNGS Emergency Plan, Revision 36, Section 3.0 stated, in part, that, the Emergency Plan was based upon NRC and Federal Emergency Management Agency (FEMA) guidance as contained in NUREG-0654 (FEMA-REP-1), "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," Revision 1. NUREG-0654, Section N, stated, in part, that, periodic drills will be conducted to develop and maintain key skills, and deficiencies identified as a result of drills will be corrected. NUREG-0654 further defined a drill as a supervised instruction period aimed at testing, developing, and maintaining skills.
 
Operator Licensing Requalification Program EP Classification Failures:
As part of LOCT Cycle 3 (April 3 - May 4, 2007), the licensee included JPM EP009-CR-002, "Direct the Emergency Response as the Emergency Coordinator," as part of their training to maintain emergency preparedness readiness. This JPM consisted of a SGTR event with the following conditions:
200 gpm primary/secondary leakage, valid RVLMS level < 21 percent plenum level, and the use of automatic depressurization valves to control steam generator pressure. The evaluation standard (expected trainee response), which was incorrect for this event, was a General Emergency based on, "Loss of any two barriers AND Potential Loss of a third barrier."  The incorrect classification resulted from the misapplication of EPIP-99, Section 1, "Precautions and Limitations," Step 1.7. JPM EP009-CR-002 identified the EAL classification as a General Emergency because of an incorrect assumption that under the described conditions a "prolonged release" was occurring, when the definition of "prolonged release" did not apply (see above description).
 
From April 4 through May 2, 2007, 10 SROs were given this JPM and were asked to identify the EAL classification. Nine of 10 SROs classified a General Emergency, while one classified a Site Area Emergency. On May 2, the SRO who classified the event as a Site Area Emergency identified that the evaluation standard was incorrect because under the presented conditions only one barrier
 
was lost (Containment, use of automatic depressurization valves) and two potentially lost barriers (RVLMS level < 21 percent plenum, SGTR > 44 gpm).
 
Under these conditions the correct classification was a Site Area Emergency (see above table). After discussing this with the emergency planning personnel, the instructors determined that this event should have been classified as a Site Area Emergency and the 9 SROs that classified the event as a General Emergency were given immediate remedial training (per the Training Supervisor). However, the licensee failed to enter the incorrect evaluation
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standard into either the CAP or the training deficiency program and no additional training was given to the other ERO personnel responsible for classifying events.
 
The licensee did not remove JPM EP009-CR-002 from the training bank or make any corrections to the JPM.
 
Initial Exam EP Classification Failures:
JPM SA-5 (identical to JPM-EP009-CR-002) was administered during an initial license examination on July 27, 2007. The evaluation criteria incorrectly specified the classification as a General Emergency. Two of the five SRO candidates classified the event as a Site Area Emergency, while the other three classified the event as a General Emergency. An evaluation of the JPM was conducted that day by training personnel. An EPIP training instructor recognized that the misclassification issue involved the same concern from the JPM that was given in LOCT Cycle 3. On July 27, 2007, the licensee entered the misclassification issue into the CAP as CRDR 3046233, "Incorrect Interpretation of Event Conditions During the Creation of and Administration of an NRC Exam JPM," and conducted an apparent cause evaluation. The apparent cause evaluation was completed on August 31, 2007. As of October 5, 2007, no training had been conducted on what constituted a prolonged release and the proper classification for SGTR events. The team noted that training on this particular SGTR event was not scheduled to be completed until November 30, 2007. The licensee identified three apparent causes of the performance deficiency:
: (1) a lack of knowledge/understanding on the specific conditions of EAL 1-7;
: (2) insufficient use of the Limitations in Section 1 referenced in the EAL 1-7 description box in Table 1 of EPIP-99; and
: (3) insufficient use of the technical bases in Appendix P of EPIP-99. The team determined these apparent causes stemmed from inadequate training, in that SROs were given generalized initial and continuing training on EALs and were not provided systematic training on the entry conditions and basis for individual EALs to ensure their understanding of entry conditions.
 
IP 95003 Emergency Plan (EP) Classification Failures:
As a result of the incorrect EAL classifications during the operator licensing initial exam in July 2007, the team selected JPM EP009-CR-002 to test the ability of ERO personnel to properly classify a SGTR event and to verify that the licensee had taken actions to correct the knowledge deficiencies associated with the SGTR EAL classification. The team was unaware of the additional failures associated with this JPM during LOCT Cycle 3 training. The team administered JPM EP009-CR-002, to one SRO. The JPM contained the exact same conditions as described above:  200 gpm primary/secondary leak, valid RVLMS level < 21 percent plenum level, and the use of ADVs to control steam generator pressure. The SRO incorrectly classified the event as a General Emergency verses a Site Area Emergency.
 
Due to this additional failure, the licensee implemented immediate corrective actions to provide intensive training to six managers and assigned them to shift rotations, beginning on October 28, 2007, to assist ERO personnel in making
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EAL declarations. These six managers were to remain on-shift until the licensee completed their review of the other EALs and provided training to the remainder of the applicable ERO positions. Between October 9 and November 16, 2007, the licensee did provide specific training on EAL 1-7 to the applicable ERO positions.
 
=====Analysis:=====
The team determined that the failure to correct an identified risk significant planning standard weakness was a performance deficiency. This finding was more than minor because it was associated with the Emergency Preparedness attribute of response organization performance and could affect the cornerstone objective to implement adequate measures to protect the health and safety of the public because of the licensee's inability to properly classify an emergency condition. This finding was evaluated using the Emergency Preparedness SDP and was preliminarily determined to be of low to moderate safety significance because it was a failure to comply with NRC requirements; it was an issue associated with the requirements of Appendix E of 10 CFR Part 50; it was not an issue with a risk significant planning standard as described in Manual Chapter 0609, Appendix B, Section 2.0; and it was a functional failure of the requirements of Appendix E IV.F.2.g because the licensee failed to correct a weakness associated with Risk Significant Planning Standard 10 CFR 50.47(b)(4). The cause of this finding had crosscutting aspects associated with corrective action of the PI&R area in that the licensee failed to thoroughly evaluate problems such that resolutions ensured that the problems were resolved (P.1.(c)). The cause of this finding was also related to the safety culture component of accountability in that the licensee failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)).
 
=====Enforcement:=====
10 CFR 50.54(q) states in part, that, a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in &sect;50.47(b) and the requirements in 10 CFR Part 50, Appendix E. 10 CFR Part 50, Appendix E, Section IV.F.2.g, states, in part, that all training shall provide formal critiques in order to identify deficient areas. Any deficiencies that are identified shall be corrected.
 
Contrary to the above, between May 2, 2007, and October 28, 2007, the licensee failed to correct identified deficiencies pertaining to the ability to correctly implement EALs for one Site Area Emergency classification associated with a SGTR event. Specifically, the deficiency involved licensee personnel being unable to consistently implement EAL 1-7 associated with a SGTR which resulted in an over classification of a Site Area Emergency as a General Emergency. The issue associated with EAL implementation was entered into the licensee's correction action program as PVAR 3083911. Pending determination of the finding's final safety significance, this finding was identified as Apparent Violation (AV) 05000528, 05000529, 0500030/2007012-15, "Failure to Correct a Risk Significant Planning Standard."
 
b.2 Inability to Implement Emergency Action Levels (EALs)
 
=====Introduction:=====
The team identified a Green NCV for the failure to correctly implement two EALs as required by 10 CFR 50.54(q) and 10 CFR 50.47(b)(4).
 
Specifically, between January 2006 and October 2007 the licensee was not able
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to implement one EAL at the Alert level and over-classified one Notification of Unusual Event EAL at the Alert level.
 
=====Description:=====
The team identified a performance deficiency related to the licensee's inability to ensure implementation of EALs associated with an aircraft/airliner attack threat and remote shutdown panel area high radiation
 
levels.
 
Aircraft/Airliner Threat In January 2006 the licensee added EAL 7-1 in response to NRC Bulletin 2005-002, dated July 18, 2005. The EAL was associated with an aircraft and airliner attack threat. The EAL action was defined as follows:
EAL 7-1 required declaration of an Unusual Event when the NRC notified PVNGS of an aircraft threat greater than 30 minutes away.
 
On October 4 and 5, 2007, the team administered one JPM associated with the aircraft and airliner attack threat, EAL 7-1, to two licensee ECs. The first EC classified the postulated conditions as an Alert, when the correct classification for the JPM condition was a Notification of Unusual Event. Licensee management informed the NRC staff that they would not evaluate the EC for the application of EAL 7-1 when the JPM was administered to the second EC because they recognized that they were unable to implement the EAL with existing procedures and guidance available to the ECs. The team determined that the licensee would be unable to properly classify this EAL during an actual threat because the licensee failed to develop implementing procedures for classifying an aircraft/airliner attack threat.
 
Procedure EPIP-99, "EPIP Standard Appendices," Appendix P, "Emergency Action Level Technical Bases," Revision 15, stated in part, that an airliner was based on the size of aircraft as defined in the site-specific procedure developed for response to airborne threats. The team noted that EPIP-99, Revision 15, did not define an airliner. In response to the team's observation, the licensee issued EPIP-99, Appendix P, Revision 16, on October 11, 2007, to include the definition of an airliner as a large aircraft with the potential for causing significant damage to the plant. The licensee documented the aircraft/airliner EAL classification findings in PVAR 3070849.
 
Remote Shutdown Panels Procedure EPIP-99, "EPIP Standard Appendices," Revision 15, EAL 3-12 required an Alert to be declared when radiation levels at the remote shutdown panels exceeded 5000 mrem/hr as indicated on area radiation Monitor RU-18. The purpose of this EAL was to identify conditions that could impede the operation of systems required to establish and/or maintain cold shutdown plant conditions. The team determined that area radiation Monitor RU-18 was located inside the control room envelope, on the 140 foot elevation, while the remote shutdown panels are located one level below, on the 100 foot elevation. The team determined that area radiation monitors were not installed in the vicinity of the remote shutdown panels and that area radiation Monitor RU-18 could not be
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monitored from and did not represent the radiological conditions at the remote shutdown panels. Therefore, the licensee could not determine the radiation levels at the remote shutdown panels with radiation Monitor RU-18 and could not properly classify an Alert condition based on high radiation levels in the area. On July 13, 1994, this EAL was modified to meet guidance contained within NUMARC/NESP-007, "Methodology for Development of Emergency Action Levels," Revision 2, and at that time, EAL 3-12 was added to include radiation readings at the remote shutdown panel. The licensee documented the inability to declare an Alert based on EAL 3-12 in PVAR 3073229.
 
=====Analysis:=====
The team determined that the inability to implement EALs was a performance deficiency within the licensee's ability to foresee and control. The finding was more than minor because it was associated with the Emergency Preparedness attribute of procedure quality, and could affect the cornerstone objective of implementing adequate measures to protect the health and safety of the public, if the licensee cannot promptly recognize an emergency condition.
 
Using the IMC 0609, "Significance Determination Process," Appendix B, "Emergency Preparedness Significance Determination Process," the finding was determined to have a very low safety significance (Green) because the licensee could be unable to declare one EAL at the Alert and one EAL at the Notification of Unusual Event level. The cause of this finding had crosscutting aspects associated with the corrective action of the PI&R area in that the licensee had previous opportunities to identify the deficiencies (P.1.(a)).
 
=====Enforcement:=====
10 CFR 50.54(q) states, in part, that a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in &sect;50.47(b) and the requirements in 10 CFR Part 50, Appendix E. Risk Significant Planning Standard &sect;50.47(b)(4),
states, in part, that a standard emergency classification and action level scheme shall be used. 10 CFR Part 50, Appendix E, IV(B), states, in part, that the means for determining the magnitude of and assessing the impact of the release of radioactive materials shall be described and the EALs shall be based on in-plant conditions and instrumentation. Cont rary to the above, from July 1994 until October 2007, the licensee failed to have the ability to implement EAL 3-12 at the
 
Alert level. Specifically, area radiation Monitor RU-18 could not be monitored from the remote shutdown panels and therefore, the emergency classification could not be declared as required in Procedure EPIP-99. In addition, from January 2006 until October 2007, the licensee failed to have the ability to implement EAL 7-1 resulting in the over-classification of a Notification of Unusual Event. Specifically, the licensee did not develop a procedure to enable personnel to define an airliner and therefore, the proper emergency classifications could not be declared. Because this finding was of very low safety significance and was entered into the CAP as PVARs 3073229 and 3070849, this violation was treated as an NCV, consistent with Section VI.A of the Enforcement Policy:  NCV 05000528, 05000529, 0500030/2007012-16, "Inability to Implement Emergency Action Levels."
 
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b.3 Observations and Minor Violations Involving Emergency Response and Preparedness b.3.1 Failure to Notify Offsite Agencies of Emergency Action Level (EAL)
Changes  The team identified a minor violation of 10 CFR 50.54(q) which requires in part, that, licensees follow and maintain emergency plans which meet the standards in &sect;50.47(b) and Appendix E. Palo Verde's Emergency Plan, Section 5.1, Revision 37, stated in part, that, EAL changes would be discussed and agreed upon with state and county governmental authorities. Contrary to the above, between January 2005 and October 2007, the licensee made changes to the EALs without discussing and obtaining the prior approval of state and county governmental authorities. The team determined that following a change to 10 CFR Part 50, Appendix E, IV(B), which permitted a licensee to discontinue the practice of obtaining the prior approval of offsite agencies for EAL changes under the authority of 10 CFR 50.54(q), the licensee implemented the change, without changing the requirements of the Emergency Plan. Using IMC 0612, Appendix E, "Examples of Minor Issues," this finding was determined to be minor because it was similar to Example 2.d. in that there was no regulatory requirement requiring approval of EAL changes from offsite agencies and there was no impact on public health and safety. The performance deficiency was entered into the licensee's corrective action system as PVAR 3085397. This performance deficiency is being documented because of insights associated with emergency preparedness concerns.
 
b.3.2 Failure to Train Emergency Planners 10 CFR 50.54(q) states, in part, that a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in &sect;50.47(b).
 
10 CFR 50.47(b)(16) states in part, that, responsibilities for plan development and review and for distribution of emergency plans be established, and planners are properly trained. EPIP-59, "Emergency Planning Training Program Description," Section 1.7.1, stated, "Training for PVNGS Emergency Planning staff is conducted via the completion of a required reading list and/or other training and includes participation in industry sponsored emergency planning symposia and workshops."
 
Contrary to the above, prior to October 2007, not all emergency planners participated in industry symposia and workshops. Specifically, for one emergency planner, the licensee was unable to provide documentation or determine that the individual had ever attended symposia or workshops.
 
Using IMC 0612, Appendix E, "Examples of Minor Issues," this performance deficiency was determined to be minor since it was similar to the Example 4.h. in that there were other planners whose qualifications were current. The performance deficiency was entered into the licensee's corrective action system as PVAR 3086481. This performance deficiency is being documented because of insights associated with emergency
 
preparedness concerns.
 
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==RADIATION SAFETY==
STRATEGIC PERFORMANCE AREA 6.1 Occupational Radiation Safety A review of radiological work practices was conducted in conjunction with other site activities that were reviewed in more detail. A number of observations were noted which identified failures to implement radiological worker expectations and failures to follow radiological procedures. Areas of note included:  the failure to conduct personal
 
contamination monitoring by radiological workers in the presence of posted signs, out-of-date surveys, using out-of-date survey information to conduct briefings, and incomplete radiological briefings. Though this was not a significant focus of the team's activities, the number of adverse observati ons indicate improvement is warranted in implementation of the occupational radiation safety program at Palo Verde.
 
====a. Inspection Scope====
:
The team did not conduct an in-depth review of the occupational radiation safety
 
program; however, observations relevant to this Radiation Safety Strategic Performance Area were collected and assessed to provide insights into Palo Verde's performance. Work site observations and the results of plant tours, including radiologically controlled areas, were evaluated to determine if applicable radiological program procedures were adequately implemented, including worker radiation exposure controls, radiation work permits, implementation of as low as reasonably achievable (ALARA) concepts, and effectiveness of work planning, coordination, implementation, and lessons learned. In addition, the team reviewed a sample of radiological facilities, equipment, and radiation monitoring instrumentation. Information relevant to this area was collected during tours of shutdown and operating units including tours of radiologically controlled areas, the Unit 3 containment, and other plant areas that contained radioactive material storage areas. Interviews with radiological protection managers, supervisors, and workers were conducted to provide additional insights into this performance area. Finally, the contribution of radiological worker human performance issues identified over the course of this inspection were assessed to determine if these issues were adequately investigated, evaluated, and
 
resolved.
 
====b. Observations and Findings====
:
b.1 Inadequate Briefings on Radiological Conditions
 
=====Introduction.=====
The team identified a Green NCV of 10 CFR 19.12 for the failure of RP personnel to provide adequate information regarding radiological conditions and precautions to minimize exposure during pre-job briefs.
 
=====Description.=====
During select pre-job briefs performed between October 1 and October 3, 2007, RP personnel failed to provide accurate information regarding the radiological conditions commensurate with the hazard. For a Unit 3 containment entry briefing that did not involve entry into high radiation areas on October 1, 2007, dose rate information was communicated by RP personnel using elevation drawings and pointing to different locations and verbally stating Aless than 2 mrem/hr," "elevated" (with no actual dose rates specified), or A HRA [high radiation area], which your REP [radiation exposure permit] does not allow.
 
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The elevation drawings used for the briefing were not radiological surveys and contained no dose rate data. In addition, the expected contamination levels were
 
not reviewed and the RP person giving the briefing did not know if the 80 foot elevation had been released. Furthermore, although it was the first entry for the radiological workers, the expected response to dose and dose rate alarms was not discussed, the expectation to check the electronic dosimeter every 15 minutes was not mentioned, and the electronic dosimeter setpoints were not
 
reviewed.
 
During a briefing at the RP control point on the 70 foot elevation of the Unit 3 auxiliary building on October 1, 2007, it was stated there were no high radiation areas in the Train A CS room, based on information contained in the posted radiation survey. While performing a walkdown of the room, the team identified a posted and barricaded high radiation area. Subsequently, the team noted that a number of the radiation survey maps at the 70 foot RP control point used for the briefing were out of date, including the survey for the Train A CS room. The licensee initiated PVAR 3070507 with the action to replace the survey maps with the most recent version. However, the posted survey maps at the RP control point for the Train A charging pump room and the 140 foot hot lab were out of date when used for a briefing on October 3, 2007.
 
=====Analysis.=====
The failure of RP personnel to adequately inform workers of the radiological conditions in the Unit 3 containment and auxiliary building was determined to be a performance deficiency. This finding is greater than minor because it is associated with the Occupational Radiation Safety Cornerstone attribute of program and process and affected the cornerstone objective of ensuring the adequate protection of the worker health and safety from exposure to radiation during routine operations. The finding was determined to be of very low safety significance (Green) because it was not an ALARA issue, there was not an overexposure or substantial potential for an overexposure, and the ability to assess dose was not compromised. The cause of the finding had crosscutting aspects associated with decision making of the human performance area in that RP personnel performing briefings failed to communicate decisions, and the basis for decisions, to personnel who had need to know the information to perform work safely (H.1.(c)). The cause of this finding was also related to the safety culture component of accountability in that RP personnel failed to demonstrate a proper safety focus and reinforce safety principles (O.1.(c)).
 
=====Enforcement.=====
10 CFR 19.12 requires, in part, that all individuals who in the course of employment are likely to receive in a year an occupational dose in excess of 100 mrem be kept informed of the transfer or use of radioactive material and in precautions to minimize exposure. Contrary to these requirements, on October 1 and 3, 2007, RP personnel did not adequately inform workers of radiological conditions and precautions to minimize exposure during radiological briefings. Specifically, RP personnel failed to adequately inform workers of the radiological conditions and precautions/procedures to minimize
 
exposure in the Unit 3 containment and auxiliary building so that the workers could take the necessary precautions to minimize exposure. Because the finding was of very low safety significance and had been entered into the licensee's CAP 
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as PVARs 3070507 and 3071940, this violation was treated as an NCV consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000530/2007012-17, "Inadequate Briefings on Radiological Conditions."
 
b.2 Observations and Minor Violations Involving Occupational Radiation Safety b.2.1 Failure to Conduct Appropriate Radiological Surveys      The team identified a minor violation of 10 CFR 20.1501(a) which requires, in part, that each licensee make or cause to be made surveys that may be necessary to comply with regulations in this part, and are reasonable under the circumstances to evaluate the magnitude and extent of radiation levels, concentration/quantities of radioactive material, and the potential radiological hazards. Contrary to the above, on October 1 and 2, 2007, licensee personnel failed to make or cause to be made surveys to ensure compliance with 10 CFR 20.1201. Specifically, the team observed radiological workers failing to complete personnel contamination monitoring surveys in Unit 3 and the 70 foot auxiliary building and 140 foot fuel building, as specified by signs posted adjacent to the respective monitoring stations. Using IMC 0612, Appendix B, "Issue Screening," this finding was minor because the survey was an administrative requirement and there was no unexpected contamination.
 
The performance deficiency was entered into the CAP as PVARs 3070009 and 3072066. This performance deficiency is being documented because of insights associated with implementation of RP program and accountability of management personnel.
 
6.2 Public Radiation Safety Selected aspects of the public radiation safety program were reviewed including;
: (1) a sampling of plant facilities, equipment, and  instrumentation for radioactive effluent monitoring,
: (2) a sampling of procedures affecting the processing, control and discharge of radioactive effluents, and
: (3) a sampling of training and qualifications of personnel involved in radioactive waste and effluent processing. Performance issues identified in this area related to failures to operate liquid radiological waste tanks in accordance with station procedures and the UFSAR.
 
====a. Inspection Scope====
The team did not conduct an in-depth review of the Public Radiation Safety program; however, a sampling of program effluent monitoring equipment and radioactive material controls was evaluated. Unit 3 radiological waste systems were walked down and valve alignments were compared to system drawing requirements; observations during site tours and radiological work activities were evaluated against program requirements. Interviews with managers, supervisors, engineers, and radiological workers were conducted. Radiological waste system procedures, applicable sections of the UFSAR, the Offsite Dose Calculation Manual, the Radiological Environmental Monitoring Report, the 2006 Annual Radioactive Effluent Release Report, radiation protection self-assessments, and CAP documents were reviewed. In addition, the Units 1, 2, and 3 radiological waste tank farms were walked down and the operation of radiological waste systems (total dissolved solids and recycle monitor tanks) were
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evaluated. The above activities provided insight into the assessment of plant facilities, equipment, and radiological instrumentation intended for public radiation safety. In addition, the team used feedback from these activities to evaluate the implementation of public radiation safety programs and processes, and to evaluate how any observed human performance issues affected the public radiation safety area.
 
====b. Observations and Findings====
b.1 Failure to Periodically Update the Final Safety Analysis Report 
 
=====Introduction:=====
The team identified a Severity Level IV NCV of 10 CFR 50.71(e) for the failure of the licensee to periodically update the UFSAR with all changes made in the facility or procedures.
 
=====Description:=====
While conducting a review of the Unit 2 liquid radiological waste system, the team found that the system was not being operated in accordance with the description provided in the UFSAR. Specifically, evaporator concentrate was being pumped to one of the high total dissolved solids (TDS) holdup tanks rather than the concentrate monitor tanks as specified in Section 11.2.2 of the UFSAR.
 
The licensee stated that the Unit 2 concentrate monitor system had been out of service since 2002. The team's review of corrective action documents related to the system determined that the concentrate monitor tanks were not being used because of equipment/maintenance issues with the concentrate monitor system. The UFSAR stated in Section 11.2.2.4.1.2, that flow from the high TDS holdup tank can be terminated or diverted to an alternate path by operator action based on evaporator or holdup pump malfunction, high-pressure drop across the adsorption bed or ion exchangers, an exhausted resin bed, or when the radiological waste section leader determines it is necessary. The UFSAR did not specify the alternate flow path nor the allowed duration. The team concluded that operating outside of the UFSAR design basis for approximately 5 years was not the intent of UFSAR Section 11.2.2.4.1.2.
 
=====Analysis:=====
The team determined that the failure to update the UFSAR to reflect changes made to the facility was a performance deficiency. This issue was subject to traditional enforcement because it had the potential for impacting the NRC's ability to perform its regulatory function. The finding is characterized as a Severity Level IV violation because the erroneous information in the UFSAR was not used to make an unacceptable change to the facility or procedures. The cause of this finding had a crosscutting aspect associated with resources of the human performance area in that the licensee failed to ensure that personnel and equipment were available and adequate to maintain radiological safety by minimization of long-standing equipment issues (H.2.(a)).
 
=====Enforcement:=====
10 CFR 50.71(e) requires that the licensee periodically update the USFAR with all changes made in the facility or procedures. Contrary to the above, in 2002 the licensee made a change to the facility and procedures as described in the UFSAR and failed to update the UFSAR. Specifically, the licensee began operating the Unit 2 liquid radiological waste system in a manner different than that specified by UFSAR when they commenced pumping
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evaporator concentrate to the high TDS holdup tanks rather than the concentrate monitor tanks as specified in UFSAR Section 11.2.2. The failure to update the UFSAR was characterized as a Severity Level IV violation. The finding was of very low safety significance because the change in operation of the total dissolved solids holdup tanks did not result in an increase in the likelihood of a release of radioactive material. This issue was entered in the licensee's CAP as PVAR 3075089. This violation was treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000529/2007012-18, "Failure to Periodically Update the Updated Final Safety Analysis Report."
 
==SAFEGUARDS==
STRATEGIC PERFORMANCE AREA 7.1 Safeguards Strategic Performance Area The team did not conduct an in-depth review of the Safeguards Strategic Performance Area; however, the team conducted tours of site physical protection areas and evaluated their attributes and performed spot checks of security equipment. In addition, the team interviewed security personnel to determine if latent organizational or security equipment issues exist at Palo Verde. The team also observed the owner controlled area and protected area access control process. One finding associated with the calculation of group work hours was identified. The finding is discussed in NRC Inspection Report 05000528, 05000529, 05000530/2007402.
 
8 SAFETY CULTURE
 
8.1 Evaluation of the Licensee's Independent Safety Culture Assessment The team determined that the licensee's third-party safety culture assessment was adequate to provide the licensee with the information necessary to develop appropriate corrective actions for safety culture weaknesses, although limitations in the interpretability of the survey tool decreased its usefulness to the licensee. Without the many write-in comments provided by the survey participants, the licensee may not have been able to use the survey results to develop specific corrective action plans. The results of the NRC's independent safety culture assessment validated the results of the licensee's third-party safety culture assessment.
 
====a. Inspection Scope====
Consistent with inspection requirements in Section 02.07 of IP 95003, the team evaluated the licensee's safety culture assessment to determine whether:
: (1) the assessment was comprehensive,
: (2) the assessment team members were independent and qualified,
: (3) the assessment was methodologically sound,
: (4) the data collected supported the conclusions derived from the assessment, and
: (5) the licensee's corrective actions in response to the assessment findings were likely to be
 
effective.
 
The team met with licensee representatives and one of the licensee's safety culture assessment contractors (Synergy) at NRC Headquarters in Rockville, Maryland, on March 14, 2007, to discuss the independent safety culture assessment. The team also reviewed the licensee's plans for conducting the safety culture assessment, the resumes of the personnel who conducted the assessment and analyzed the data, and
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the survey instrument and interview guides. Team members and the NRC resident inspectors observed the administration of the survey on six different occasions between April 15 - 25, 2007, to verify that the instructions provided to survey participants were consistent and did not introduce the potential for response biases. During the week of June 18-21, 2007, the team completed an onsite review of the preliminary results from the safety culture assessment and conducted interviews with licensee personnel and members of the assessment team to better understand their methods to aid in interpreting the preliminary results. In addition, conference calls with the licensee and Synergy were held on June 27, 2007, and July 26, 2007, to discuss the measurement properties of the survey instrument and the statistical analyses of the survey data. During the weeks of October 1-12, 2007, and October 29-November 2, 2007, the team solicited feedback on the safety culture assessment during individual and group interviews with site personnel and evaluated the licensee's corrective action plans for addressing identified safety culture weaknesses.
 
b. Observations Comprehensiveness The team concluded that the safety culture assessment provided the licensee with the information necessary to:
: (1) develop appropriate corrective actions for the identified safety culture weaknesses and
: (2) take actions to maintain the site's safety culture
 
strengths.
 
Two teams with different areas of emphasis, using complementary methods, conducted the assessment. One team, the Independent Safety Culture Performance Evaluation Team (ISCPET), focused on the effectiveness of the site's policies, programs, processes, and procedures in establishing that nuclear plant safety issues receive the attention warranted by their significance. This team conducted interviews, document reviews, and behavioral observations to obtain information. A second team focused on the site workforce's attitudes and perceptions related to the extent to which nuclear plant safety issues receive attention. This team, Synergy, collected information for the assessment by administering a site-wide safety culture survey augmented by follow-up interviews with site personnel. The combined activities of the assessment teams addressed all levels of site and corporate management, obtained safety culture survey responses from approximately 80 percent of the Palo Verde workforce including contractors, and sampled organizational characteristics and attitudes related to each of the 13 safety culture components identified in Section 06.07 of NRC IMC 0305, "Operating Reactor Assessment Program."
 
Independence and Qualifications
 
The team concluded that the licensee's safety culture assessment was conducted independently and that the assessment teams' members were qualified. Although licensee personnel administered the safety culture survey, the NRC team's observations of survey administration and focus group interviews with Palo Verde staff indicated that the independence of the effort was not compromised. Licensee personnel administering the survey followed the instructions provided by the assessment team and implemented adequate methods for collecting completed surveys to ensure participants believed their responses would remain anonymous and confidential.
 
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The NRC team verified that the licensee' s safety culture assessment teams had unrestricted access to information and opportunities to interview the individuals necessary to complete the assessment.
 
The NRC team verified that the assessment teams were composed of individuals with a knowledge of nuclear safety culture and the topics they were assigned to assess.
 
The licensee ensured that Synergy subcontracted with an independent professional survey research firm, Westat, to assist in analyzing the statistical properties of the survey instrument and the survey results. The additional analyses performed by Westat enhanced the interpretability of the survey portion of the safety culture assessment.
 
Assessment Methods The team concluded that the methods used to perform the assessment were appropriate, although some weaknesses in the safety culture survey were identified.
 
Multi-method approach. The NRC team verified that the assessment teams applied a multi-method approach to conduct the safety culture assessment, including a survey, behavioral observations, interviews, and document reviews. Sample sizes for applying each method obtained representative information, and the teams' behavioral observation and interview guides did not bias the assessment results. The teams performed their assessment activities in parallel, but compared, contrasted, and reconciled their findings to ensure they provided integrated assessment results to the licensee. The NRC team's review of the preliminary results from the teams confirmed that the large majority of their results were consistent and required little additional data gathering to reconcile contrasting results.
 
Survey tool. The team concluded that the safety culture survey appropriately screened for workforce attitudes and that the most useful information was contained in the write-in comments provided by the participants. Over half of those participating in the survey provided write-in comments. The write-in comments provided more detailed information related to safety culture strengths and weaknesses at the site, and
 
enhanced the overall usefulness of the results. The NRC team verified that Synergy had appropriately grouped the write-in comments to identify the recurring safety culture
 
themes.
 
Site personnel who participated in the survey and were interviewed by the NRC team believed that the anonymity of their responses had been maintained and that the survey gave them an opportunity to express their views on impor tant issues at the site. None of the participants interviewed reported feeling any pressure to respond to the survey questions.
 
Survey participants interviewed by the NRC expressed reservations about the length of the survey (i.e., they perceived it to be too long and repetitive) and indicated that the construction of some survey items made it difficult to respond. For example, some items asked participants to respond with respect to both their "managers and supervisors."  Interviewees stated they had difficulty in responding to these items because their perceptions of their supervisors differed from perceptions of their
 
managers. The team identified additional examples of survey items that addressed multiple topics within a single item, which is inconsistent with standard survey design
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techniques described in IP 95003, Enclosure F, "Guidance for Evaluating Safety Culture Surveys."  Licensee personnel who were developing improvement plans also reported similar interpretation difficulties. Synergy indicated that they did not pilot-test the safety culture survey on a representative sample of Palo Verde survey participants before the survey was administered. The team concluded that the licensee may have been able to make better use of the results had these items been addressed before administering the survey.
 
The team noted a low response rate from security personnel on the survey  (approximately 40 percent participated), compared to other functional groups at the site. Synergy indicated that this response rate is characteristic of security groups at other sites and results from
: (1) a perception among security personnel that the survey items are less relevant to their jobs than to other jobs at nuclear facilities and
: (2) typical difficulties in arranging to administer the survey to security personnel because of shift schedules. The team noted that shift scheduling issues did not
 
adversely affect response rates from other functional groups, such as operations, and verified that all security personnel had an opportunity to participate. During focus groups, the NRC verified that security pers onnel who took the survey believed the items were more relevant to the crafts, consistent with Synergy's experience at other sites. Interviews indicated that security personnel believed the effort of taking the survey would not be worthwhile because it would not result in positive changes related to staffing and overtime. The team determined that the failure to include items directly relevant to the security function or adjust existing items to be more clearly relevant to the security function was a weakness in the survey tool. The team noted that Synergy and licensee personnel followed-up on the low response rate with individual interviews to more clearly understand the security group's safety culture concerns.
 
Survey analyses. Based on the NRC team's review of the statistical analyses of the survey data performed by Westat, the team concluded that the survey results were of limited effectiveness in differentiating between functional groups at the site that may have localized safety culture issues. Statistically significant differences were found only between the functional group with the most positive responses on the survey and the group with the most negative results. Therefore, Synergy relied more heavily on the write-in comments and interview results to discriminate among functional groups.
 
Based on their review, Synergy identified 12 priority groups in need of particular attention. The NRC team determined that the recommendation to focus on these 12 groups may be narrowly focused given the similarities in the safety culture issues raised in the write-in comments from all of the groups.
 
The NRC team reviewed the survey data analyses performed by Westat and determined that the survey met standard survey design requirements for internal consistency. The write-in comments, the results of Synergy's and the licensee's follow-up interviews, the ISCPET review, and the NRC's independent safety culture assessment indicated that the survey tool provided adequate information related to safety culture attitudes at Palo Verde.
 
Third-party assessment conclusions
 
The team concluded that the results and conclusions of the assessment were consistent with the data collected. The team also noted that the themes identified from the assessment were very similar to the results of licensee safety culture assessments
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performed in 2004 and 2005. Responses to the 2007 survey items were more negative than responses to the 2005 survey, and write-in comments on the 2007 survey were both more extensive and more negative in tone than the write-in comments from 2005. The issues raised by site personnel in each of these assessments were consistent and were discussed by site personnel in progressively stronger terms. This trend suggests that corrective actions were not effective in sustaining improvement following the 2004 and 2005 safety culture assessments.
 
Licensee analysis and corrective actions
 
The team concluded that individual findings and recommendations from the safety culture assessment were appropriately reviewed by the licensee to identify corrective actions. The licensee had not finished developing corrective actions at the time of the inspection; therefore, the team could not evaluate the completeness and effectiveness of the planned corrective actions.
 
The licensee addressed the results of the safety culture assessment using several methods. These methods included Employee Concerns Program (ECP) actions to respond to some write-in comments, establishment of a Safety Culture Team (SCT), development of safety culture improvement plans for the 12 functional groups identified by Synergy, and efforts to develop site-wide safety culture improvement plans.
 
ECP actions. ECP staff reviewed the write-in comments from the survey for any instances in which a comment implied or reported perceptions of retaliation for raising concerns. Using information collected from the survey, the ECP identified the work groups of approximately 9 cases, but made no attempt to identify individuals who had submitted the comments in order to maintain their anonymity and confidentiality. The ECP manager provided an overview to the team of how each case was investigated and dispositioned. The team concluded that the handling of the comments was appropriate.
 
SCT actions. The licensee established the SCT to facilitate the development, communication, and implementation of actions to improve safety culture. The SCT tasked the managers of the 12 functional groups to develop improvement plans. The SCT provided the managers their groups' survey scores, write-in comments, and other relevant information from the assessment, and directed the managers to communicate the survey results and develop improvement plans. The SCT worked with the managers to plan their communications with their groups, provided individual and organizational consulting to the managers in developing their improvement plans, and were responsible for tracking implementation and effectiveness of the plans. Senior management met with each manager to review the improvement plans. The NRC team also reviewed the improvement plans, observed meetings between senior management and the managers, and conducted individual interviews with the managers to obtain their views of the process. The team concluded that the safety culture improvement plans for the 12 groups were appropriate.
 
The SCT also provided safety culture assessment results to other managers at the site in September 2007, with a request for the managers to meet with staff to discuss the results, and develop any necessary improvement plans. In addition, the SCT requested the managers review the results for their work groups and determine
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whether any immediate improvement actions were necessary before the start of the Unit 3 steam generator replacement outage. The SCT requested the managers complete their meetings by the end of October 2007, but did not require that any improvement plans be entered into the CAP for tracking to completion. At the time of the inspection, the SCT did not plan to monitor implementation of the managers' dissemination of the assessment results or development of improvement plans.
 
This approach for non-priority groups was consistent with the licensee's process for responding to the results from the 2005 safety culture assessment. About half of the frontline participants in the NRC's focus groups had not yet met with managers to receive detailed information about the assessment results or participate in developing improvement plans. The team noted that a failure to communicate specific results from a survey and develop improvement plans may discourage personnel from participating in future surveys. In addition, because the statistical differences between functional groups on the survey responses were not significant, this approach may not ensure improvement in other groups that could have safety culture issues.
 
Site-wide actions. The SCT informed the team that they intended to address safety culture weaknesses identified through the assessment with site-wide improvement actions. The SCT performed streaming analyses on:
: (1) the areas for improvement identified by the Synergy survey and follow-up interviews;
: (2) the summary of the write-in comments from the survey; and
: (3) the areas for improvement identified by the ISCPET. The analyses identified "drivers" and contributing causes for each of the areas, which were then consolidated into a set of overall key drivers. These key drivers were:
: (1) individual accountability and ownership;
: (2) clarity and communication of overall priorities and strategies;
: (3) quality of leadership and management;
: (4) receptivity to employee input;
: (5) change management, and
: (6) site programs and processes. The NRC team determined that the key drivers captured the issues from the licensee's safety culture assessment.
 
The licensee's corrective actions to address the safety culture drivers were primarily high-level actions referenced from several ImPACT Root Cause Evaluations. For example, to address individual accountability and ownership, the SCT corrective actions referenced actions being taken under the Organizational Effectiveness Root Cause Evaluation, including developing an accountability model (CRAI 3075803),
implementing a management review meet ing process (CRAI 3063852), developing a leadership/management model (CRAI 3082328), and developing a site-wide communication strategy (CRAI 3063112). The corrective actions from the ImPACT Root Cause Evaluations were either recorded in the Site Integrated Business Plan (SIBP) or were in the process of being added at the time of the inspection. The SCT also described plans to establish mechanisms for tracking, measuring, and assessing the effectiveness of the corrective actions to address the key drivers. Based on the level of detail available, the NRC team was unable to assess the effectiveness of the corrective actions or the SCT's plans.
 
Verification of completeness. The SCT performed a detailed review of the findings, recommendations, and write-in comments from the safety culture assessment teams and compared them with SIBP tasks and existing CAP items. For issues that were not in the SIBP or CAP, the SCT initiated additional actions. For example, one of the findings from the ISCPET and Fundamental Overall Problem 9, "Organizational 
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Effectiveness," was a need to establish safety conscious work environment (SCWE) expectations for contractors and incorporate them into their contracts. The SCT initiated CRAI 3090979 on November 9, 2007, to address this action.
 
In addition, for actions that were described at a general level in the SIBP or CAP, the SCT issued or planned to take additional actions to ensure findings and recommendations from the safety culture assessment were addressed. For example, the SCT initiated CRAI 3082328 to verify that the communication strategy being developed under CRAI 3063112 (related CRDR 3048836, "Organizational Effectiveness" root cause) included actions to motivate site personnel to understand and take responsibility for improving current levels of performance. Another example was CRAI 3082469, which was to verify that the formal process for change management being developed under CRAI 3064376 (related CRDR 3048836),
required solicitation of employee input in appropriate cases. The SCT identified several issues from the licensee's safety culture assessment that were not addressed by existing actions, and planned to enter those into the CAP.
 
The NRC team noted that the actions that were referenced in the CRAIs owned by the SCT did not have a link back to the safety culture improvement efforts. For example, CRAI 3082469 to develop the process for change management, which was in the SIBP, did not have a link back to CRAI 3082469 to ensure the change management process solicits input from employees as appropriate. With this structure, the SCT had the responsibility to communicate with the action owner, initiate involvement, and ensure the products met the specifics stated. The action owner, however, did not have
 
any responsibility to ensure the product addressed specific findings from the safety culture assessment. This one-way linkage created the potential for the action owners to not fully consider the safety culture assessment findings when developing and implementing corrective actions.
 
8.2 NRC Independent Safety Culture Assessment The team identified weaknesses in organizational characteristics and attitudes associated with 10 of the NRC's 13 safety culture components, as detailed in Section 06.07 of Inspection Manual Chapter (IMC) 0305, "Operating Reactor Assessment Program."
 
The most notable weaknesses were identified in the safety culture components related to decision-making, organizational change management, resources, the licensee's corrective action program, accountability, operational experience, self assessments, and work practices. The observed weaknesses were widespread among functional groups across the organization, involving operations, engineering, maintenance, radiation protection, and corrective action program personnel. Organizational characteristics and attitudes were acceptable in the safety culture components of safety policies; the environment for raising concerns; and preventing, detecting, and mitigating perceptions of retaliation. The team concluded that although the safety culture has degraded at the site, Palo Verde's existing safety culture supports continued safe operation.
 
====a. Inspection Scope====
Consistent with the inspection requirements in Sections 02.08 and 02.09 of IP 95003, the team conducted an independent assessment of the licensee's safety culture. The 
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purposes of this assessment were to
: (1) inform the NRC's assessment of the contributors to degraded performance in the affected Strategic Performance Areas and
: (2) validate the licensee's third-party safety culture assessment.
 
The team relied on document reviews, individual and group interviews, and behavioral observations to conduct the assessment. The team assessed safety culture attitudes by conducting 125 individual interviews and 34 focus groups with an average of 8 participants in each group, for an approximate total of 400 safety culture-specific interviews over the course of the inspection. These interviews involved personnel from the majority of functional groups at the site and at each management level affecting the organization, including Arizona Pub lic Service (APS) corporate and owner personnel, former senior site managers, and an Arizona Corporate Commission (ACC)staff member. The team also assessed safety culture-related behaviors during plant tours, system walkdowns, control room and outage control center observations, and observations of site meetings and pre-job briefings. The team assessed the licensee's organizational characteristics with respect to each safety culture component using at least two data-collection methods. The data-collection methods were implemented by at least two inspectors. The team also integrated the safety culture insights from the inspection findings into the overall assessment of the safety culture at Palo Verde.
 
====b. Observations and Findings====
b.1 Decision-making The team identified past decisions that continue to adversely affect site performance as well as ongoing weaknesses in some site decision-making processes. Results of the NRC's safety culture assessment indicated that the majority of Palo Verde personnel interviewed perceived that cost reduction efforts inadvertently created an environment in which nuclear safety was degraded. Most of the site personnel interviewed described decision-making as being primarily governed by the goals of reducing costs in preparation for deregulation and cost containment, unless the decisions involved meeting new regulatory requirements or ensuring continued production (e.g., steam generator replacements). Site personnel provided numerous examples of decisions related to the erosion of nuclear and industrial safety margins; failures to maintain adequate levels of qualified staff to implement programs, processes and procedures; failures to replace or upgrade out-dated or degrading equipment; a lack of preventative maintenance; and untimely repairs.
 
Impact of Deregulation. During the early 1990s, the ACC determined that APS should deregulate its generation assets, including Palo Verde, and separate these assets to enter into a commercially competitive retail electricity market. In anticipation of a deregulated retail market, APS implemented cost reductions with a goal of decreasing retail rates by approximately 30 percent. The cost reductions were implemented by reducing staffing levels through reductions in force and an extended hiring freeze, and by cutting operations and maintenance (O&M) budgets by 10 percent per year across the board. Senior management believed that this reduction could be completed without degrading nuclear safety by eliminating the inefficiencies in processes and workflow. By 1998, total expenditures (O&M + capital) at Palo Verde had been cut by 35 percent from 1992 levels.
 
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The consequences of the cost reductions combined with the effects of plant aging, contributed to an increase in unplanned outage time and equipment failures. In 2000, after nine consecutive years of across-the-board O&M cost reductions, O&M expenditures began increasing. By 2006, O&M costs had increased by 64 percent from their low point in 2000 and were 21 percent higher than 1992 baseline levels.
 
Palo Verde replaced steam generators and initiated plans to replace the reactor vessel pressure heads in all three units. This caused capital expenditures to increase by a factor of 5 from 1996 to 2005. The increase in combined O&M and capital expenditures between 1998 and 2005 was 85 percent and was attributable to both capital expenditures on major improvement projects as well as increased O&M costs associated with declining performance.
 
Interviews with site personnel and document reviews indicated that during the period of 2000 to 2007, cost-containment pressure increased. Licensee personnel stated high priority modifications were cancelled or deferred, the backlog of preventive maintenance deferrals increased, aging equipment was not replaced, tools and equipment needed to perform simple tasks were not repaired or replaced, training staff was reduced, training materials were not updated, benchmarking efforts and external training opportunities were curtailed, and procedures were not updated or maintained. These cumulative reductions contributed to the increase in equipment failures, plant events, and other
 
performance problems at the site.
 
The licensee continued to lose qualified staff in the line organizations (e.g., operations, engineering, maintenance) during this period as Palo Verde's workforce began to retire or personnel took other jobs. Further, experienced people were shifted to support large capital projects, such as the main turbine and steam generator replacements, or the improvement projects necessitated by Palo Verde's declining performance. These personnel were not replaced in the line organizations, which exacerbated the lack of support for operations, maintenance, engineering work, and improvement projects at the station.
 
During interviews, corporate personnel stated that they had lost touch with site operations over the five years preceding Palo Verde's entrance into Column 4 of the NRC's action matrix, and were unaware that cost-containment efforts were adversely affecting performance. A complicating factor was that corporate management allowed multiple lines of communication with the site to be closed off. Virtually all significant non-financial assessments of site performance flowed to the corporate organization through a single communication channel at the site.
 
From the corporate perspective, APS wa s appropriately investing a steadily increasing amount of resources to protect the Palo Verde asset. Senior onsite management believed that the site had to become more efficient and more productive in order to establish competitive rates and maintain safety. The site leadership was determined to avoid problems with cyclic performance by maintaining sustainable budgets while addressing latent problems.
 
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In 2005, the ACC reversed the original decision to deregulate. In April 2007, the ACC approved the first APS base rate increase in 14 years and implemented a process whereby APS was reimbursed for increased fuel costs.
 
Licensee response. Management at the most senior corporate levels has taken steps to enhance decision-making processes affecting nuclear safety at Palo Verde. For example, to ensure that Board and owner decision-making is more fully informed, the composition of Palo Verde's off-site safety review committee has been changed and the committee has an avenue to report directly to the Board of APS rather than to the site vice president/chief nuclear officer (SVP/CNO). Additionally, the Nuclear Oversight Committee provides a second source of information by directly reporting to the Board and APS corporate executives. At the time of the inspection, Board members were making more frequent visits to the site to meet with frontline and other personnel, and owner representatives were regularly observing site decision-making meetings.
 
During the first quarter of 2007, APS hired a new SVP/CNO who has a clear focus on nuclear safety and is knowledgeable of current industry practices and standards. The new SVP/CNO assembled a team of similarly knowledgeable and experienced managers in key senior management positions to improve site decision-making and performance. During NRC safety culture interviews, station personnel cited examples of visible decisions made by the new senior management team within the past few mont hs that they perceived as initial indications of an increased emphasis on nuclear safety. These decisions included the development and scheduling of departmental "top 10 lists" of equipment repairs, extending a refueling outage to correct some longstanding equipment deficiencies, and authorization to hire new staff or contractors.
 
APS has increased the current O&M budget to address the backlog of issues.
 
Corporate and site management indicated that the resources needed to sustain improvement at Palo Verde will be provided.
 
Continuing challenges. With the exception of operations personnel and some mid-level managers who have been interacting with members of the new senior management team, most site personnel interviewed by the NRC reported that they had yet to see or experience a significant change in the decision-making patterns that affected their individual work groups.
 
Consistent with this perception were the NRC team's observations that decision-making at lower levels in the organization had not yet become fully aligned with station management's expectations. Although corrective actions have been formulated and some were beginning to be implemented to enhance station decision-making, the licensee did not consistently make safety-significant or risk-significant decisions using a systematic process that ensured safety is maintained. For example, as previously discussed, the licensee's process for making operability determinations has not ensured that
: (1) all degraded equipment conditions that may require an operability determination are identified,
: (2) SROs are provided the technical information necessary to make timely operability determinations, and
: (3) the technical information that is provided is sufficiently rigorous to support decisions that ensure safety is maintained.
 
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Licensee safety culture assessment. The team determined that the licensee's third-party safety culture assessment had adequately captured these issues.
 
b.2 Organizational Change Management 
 
Results of the NRC's safety culture assessment indicated that
: (1) the licensee was continuing to experience adverse consequences from previous poorly managed change efforts and
: (2) organizational change management continues to be a significant challenge.
 
A key organizational change that impacted Palo Verde's performance was the site's "reengineering" effort in the early 1990's, which focused on streamlining work processes, reducing staff to reduce O&M costs, and allocating decision-making authority to those closest to the work (Checklist #FA-4, Reengineering Checklist). Palo Verde management undertook the reengineering effort to position the organization for the anticipated deregulation. Reengineering was a popular and successful management approach undertaken by other companies during this time period. This effort was based on a best-selling book by Hammer and Champy entitled Reengineering the Corporation published in 1993.
 
Fundamental to this approach was the premise that productivity gains will naturally follow as processes are streamlined and wasteful steps are eliminated. The productivity gains should translate directly to cost reductions. However, budget and staff reductions first require a commensurate increase in worker productivity in order to match the estimated resource supply and demand.
 
The actions taken to reduce staff and costs from 1992 to 1998 enhanced cost competitiveness in response to the pending deregulation. However, the reengineering effort did not sustain the desired productivity and performance improvements. The goal to achieve sustained cost reductions was not met because of several factors, including flaws in how the reengineering effort was implemented, failures to recognize unanticipated consequences, and failures to make adjustments when unintended consequences occurred.
 
Productivity methods and tools. The licensee focused on cost reductions without a commensurate effort to provide the workforce with productivity-enhancing methods and tools. Interviewees perceived that past senior management did not want to invest current resources to save future resources. Interviewees believed that past senior management approached the productivity problem by first cutting staff and budgets, and then demanding that middle management find new and creative ways of enhancing productivity. This approach did not include investing in the processes or technology that might have enabled the desired productivity improvements.
 
For example, the CAP was structured around SWMS, a commercial software database. Palo Verde procured this software application but did not also purchase the optional interfacing application package that was more intuitive and would have more readily facilitated linking of CRDRs, CRAIs and other related CAP documents. As a result, gaining proficiency with the SWMS database required extensive training and effort to master the software. The consensus from interviews and focus groups was that many of the workers had not spent the
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time to become proficient because SWMS was too complex. As a result, personnel continued using multiple problem identification and corrective action tracking databases they had developed before SWMS was implemented and that were tailored to their unique needs. The team noted that there were at least 37 separate problem identification and action tracking databases in use at the site at the time of the inspection. Fragmenting the action tracking systems into separate databases that were not linked prevented site management from being able to monitor problems effectively and trend the status of corrective actions. This
 
fragmentation masked the true extent of the backlogs and made cross-department prioritization of corrective actions difficult and time consuming.
 
Palo Verde financial management processes also did not support productivity improvements, such as effective planning to fund emergent work. A consistent theme from interviews with mid-management personnel was that department budgets were considered to be inviolate (i.e., department budgets could not be overrun and unbudgeted emergent work generally had to be funded from existing line items). Specifically, when important equipment failed, middle management was required to find the funds to repair the equipment from within their own departmental budgets. These unplanned repairs often required that other key department projects had to be deferred, reduced in scope, or cancelled in order to fund the emergent repairs. Important projects in one department would be delayed due to emergent work while other less important projects in other departments were executed because they were funded under a different
 
department or group budget.
 
This weakness in financial management processes contributed to the increase in the station's backlog. The lack of integration of budget priorities allowed some low priority projects to be executed while higher priority projects were cancelled or deferred. Some managers reportedly resorted to padding their budgets to fund emergent work while others attempted to accurately estimate each budget line item. Those who padded their budgets had the funds to support both planned and emergent work, while those who attempted to comply with the spirit of the formal budgeting process ran short of funds to complete planned work by the end of the year.
 
Streamlining. The effort to streamline processes and procedures at the site was initially effective, as indicated by the decade during which Palo Verde received
 
favorable NRC and industry assessments. Interviewees described many examples of efficiencies that were achieved from reducing the number of management levels in different functional groups and empowering individuals and teams at lower levels of the organization to solve problems.
 
The streamlining effort also resulted in the elimination of clear lines of authority, roles, and responsibilities for programs and processes, which were replaced by
 
informal, and typically undocumented or poorly documented, methods of decision-making. Interviewees described the streamlined processes as relying on "expert power."  They believed they were effective because of the knowledge and skills of the staff, many of whom had joined the organization during construction and start-up. When technical knowledge was required to make a decision or solve a problem, personnel knew who on the staff had the necessary
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expertise and could access it with a phone call. One interviewee described the resulting methods of accomplishing work as "management by friendship."
 
The site's streamlined processes began to falter as qualified personnel left the site or were moved into other positions. Experienced personnel who left a work group took their knowledge with them. Their expertise was not systematically captured in site documentation or training programs with the result that overall organizational effectiveness was reduced.
 
Staff reductions and reassignments. Middle management and frontline personnel interviewed by the team consistently reported that the loss or reassignment of qualified staff from the line organizations (e.g., operations, engineering, and maintenance) contributed to the site's declining safety performance. Attrition actually reduced staff to approximately 2000 full-time licensee personnel by 2001. An internal licensee staffing study in 2002 recommended increased hiring of operations and engineering personnel. The study showed that this action was necessary because of projected workforce attrition from retirements, job migration, and the length of time required for new hires to become fully qualified. The study recommended that the effort to hire and train new personnel should begin no later than 2004 to preclude significant shortages of qualified staff. The licensee initiated the "Legacy Engineer" program to recruit and train recently graduated engineering personnel, but did not otherwise implement the recommended aggressive hiring strategy.
 
Reductions in standards and technical rigor. Interviewees indicated that the reduced availability of qualified personnel in the line organizations, the loss of organizational formality and expert knowledge, and increased cost-containment pressure, as both the workload and annual expenditures (both O&M and capital)began to increase combined to influence site personnel to reduce standards and the technical rigor of their work. Interviewees reported finding new ways to meet management expectations to expedite or defer work in order to contain costs. However, when it was not possible to find ways to complete necessary work more productively, interviewees reported that they sometimes resorted to cutting corners, reducing technical rigor, and reducing the total effort spent on jobs.
 
Consequently, technical standards in some groups began to slip and quality suffered. Interviewees also indicated that management accepted less technical rigor or a lack of product quality as a necessary compromise to meet deadlines or keep equipment operating. According to site personnel, the site's "streamlined" processes were inadequate barriers to prevent such compromises and over time, the organization's standards degraded as compromises became
 
more common.
 
Licensee response. The team concluded that the new senior management understands the extent of the changes required to reverse the adverse effects of the past reengineering and cost-containment efforts and has appropriately prioritized the necessary changes. The team noted that the licensee was revising the site's financial planning processes; planned to enhance the SWMS interface; had published and disseminated standards to clarify expectations for technical rigor and quality work to the line organizations; had begun to implement 
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a program for funding and expediting minor modifications and repairs at the time of the inspection; and was taking steps to recruit new staff and enhance training programs to qualify the new hires.
 
Continuing challenges. The team observed that management's efforts to engage the workforce in implementing the needed changes were not yet fully effective.
 
Frontline personnel interviewed by the team were not aware of many of the changes that management was planning or had made, which, over time, would resolve some of the staff's more significant concerns, particularly with respect to hiring and training new personnel.
 
In addition, the large majority of interviewees stated that they were willing to make changes to improve performance, but, other than being encouraged to write PVARs, were seeking direction and information about how they, as individuals, could play a part in turning the site around. After their early successes with empowerment under the reengineering initiative, this mature workforce perceived themselves as an untapped resource for improving performance in their work groups that management has ignored over the past
 
five years. Only the interviewees from the operations department were clear about the new management's expectations for their role as the site's leaders.
 
In other cases, interviewees were experiencing changes but did not fully understand or accept the bases for the changes. For example, some specialty maintenance personnel interviewed were recently reassigned to begin cross-training in other disciplines. These staff recalled a similar effort in the early 1990's that was undertaken as part of the reengineering initiative, then later cancelled because it caused the specialty staff's primary skills to degrade, and reduced rather than enhanced staff competence overall. It was unclear to these interviewees why management was again pursuing a cross-training effort.
 
The team observed that the licensee had identified the communication challenges associated with change management at the site, including: the need to enhance two-way communication between the frontline and management to ensure that changes are implemented as intended, do not have unintended consequences, and minimize resistance to change. The team noted that the licensee was initiating the development of departmental communication plans to include effectiveness measures during the inspection.
 
Licensee safety culture assessment. The team determined that the licensee's third-party safety culture assessment had adequately captured these issues.
 
b.3 Resources The results of the NRC's independent safety culture assessment indicated that past resource allocation decisions have challenged nuclear safety at Palo Verde.
 
Cost-containment efforts caused or contributed to a reduction in the availability of qualified personnel, procedures that have not been upgraded or maintained, and degraded facilities and equipment.
 
Staffing, qualifications, and work hours. The licensee reduced staffing at the site through reductions in force and attrition over the past 15 years. The team
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concluded that the availability of qualified staff in key departments was reduced to levels that impacted the licensee's ability to simultaneously:
: (1) respond to the high amounts of emergent work and unplanned outages,
: (2) plan for and execute 2 refueling outages each year,
: (3) reduce growing backlogs,
: (4) train and qualify new hires, and
: (5) complete implementation of multiple programs and processes to improve site performance. The team noted that improving the staffing issues and performance issues are challenged by:
: (1) the relatively long periods required to fully qualify new staff in key disciplines (ranging from 2 to 6 years);
: (2) challenges in recruiting personnel;
: (3) limited training resources; and
: (4) the increasing rate of attrition from retirements.
 
Operations
 
=====Introduction:=====
The team identified an unresolved item (URI) associated with Technical Specification 5.2.2.d. for the routine use of heavy amounts of overtime for operations personnel.
 
=====Description:=====
Interviews with frontline personnel and managers in operations indicated that shortages of licensed operators and operator training personnel were perceived to be the most significant issue facing the operations organization. Interviewees reported that the licensed operator training pipeline was interrupted several times after 2000 with a resulting net loss of 20 licensed
 
operators by 2007 (see chart below). This loss occurred concurrently with a reduction from 6 operator shifts to 5 "self-relieving" shifts (i.e., shift crews that have sufficient numbers of personnel to ensure that regulatory and administrative control room staffing requirements can be met without overtime or assigning a member of another shift crew to cover for an individual's absence). The continued loss of operators reduced shift staffing to a point where 13 of 15 shifts were not self-relieving. This meant that most control room shifts did not have a sufficient number of operators to make up for a temporary absence or permanent loss of either a reactor operator (RO) or SRO. The reductions had the effect of requiring personnel to work additional overtime and limited most licensed operators' activities to standing watch in the control room. Interviewees indicated that career advancement opportunities for licensed operators were limited because of pressures to maintain shift crews; thereby, limiting the ability of licensed operators to integrate an operations perspective into other site activities.
 
The team reviewed operations payroll data that summarized the cumulative regular and overtime hours for each operations department position and calculated the annual overtime rate for select positions. Since 2003, overtime, as a percent of regular hours worked, has increased steadily and substantively for control room and auxiliary operators. The team noted that the increase in overtime rates for operations department positions appeared to be largely the result of a decrease in staffing, rather than the result of an increase in the total
 
number of person-hours expended.
 
Specifically, from 2003 through 2006, the total number of hours worked annually by personnel in the control room supervisor (CRS), SRO, RO, and auxiliary operator (AO) positions remained relatively constant, or decreased, while the percentage of those total hours that were worked as overtime increased. As a
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result, the payroll data indicated that the licensee increasingly relied on the use of overtime to provide the person-hours necessary to operate the three units.
 
Technical Specification 5.2.2.d requires administrative procedures to be developed and implemented to limit the working hours of unit staff that perform safety-related functions (e.g., licensed SROs, licensed ROs, radiation protection technicians, auxiliary operators and key maintenance personnel). The Technical Specifications further requires that the controls shall include guidelines on working hours that ensure adequate shift coverage shall be maintained without routine heavy use of overtime. Pending the completion of a review of the actual work hours by operations personnel, this issue is identified as URI 05000528, 05000529, 05000530/2007012-19, "Routine Heavy Use of Overtime."
 
Maintenance. Interviews with maintenance personnel did not indicate that overtime was a particular concern. Staffing and qualifications were consistent areas of concern among those interviewed. Some individuals described the staffing issue as "huge," adding that with low staffing the attitude has become, "I will do it however I can."  Many of the comments were focused on the increasing loss of experienced and qualified personnel. They indicated that although an apprentice or other new hire represents a "pair of hands," so that it may appear that staffing levels are adequate, their knowledge and skills do not replace those of a senior technician who has retired. They also stated that training and supervising new hires, many of whom have not worked in an industrial environment before, also increased their workload.
 
The team reviewed maintenance department staffing levels since 2003 and found that the total number of maintenance staff has remained relatively stable during this period. However, consistent with the interviewees' perceptions of the loss of senior staff, the team also noted that 125 maintenance personnel (about 23 percent of the department's staff) have retired or left the site since 2000, 48 of whom left in the 18-month period preceding the inspection. Overtime levels also increased markedly from their levels during the 2003 through 2004 time period as workload from emergent work has increased.
 
Maintenance Department Overtime Annual Averages for Years 2003 through 2007 Year 2003 2004 2005 2006 2007 Total Staff* 546 546 542 545 524 Overtime 10.4% 10.1% 15.8% 18.5% 17.9%** *Estimate based on total department staff during September of year shown. **Estimate based on monthly overtime rates for January through September 2007.
 
The team's review of an Apparent Cause Evaluation (ACE) Report, Analysis of Maintenance Organization Performance 2003 - Present, Event Date:  March 1, 2007, (CRDR 3039642), indicated that the increase in maintenance organization overtime was related to an increase in the maintenance organization human performance error rate. The report states, "The current materiel issues of the plant require more and more frequent overtime, which has shifted the performance of the maintenance organization in a negative direction."  "The organization generally performs at an error occurrence rate of 4/10000 hours or
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less when overtime worked is 5000 hours or less. When overtime worked exceeds 5000 hours the error-occurrence rate changes to 5.5/10000 hours or worse. Second, after overtime begins to escalate and longer periods of overtime are experienced a cumulative effect on error-occurrences becomes apparent. These two observations may be indications of overload and fatigue."
 
In addition to describing an association between overtime and maintenance human performance, the report provided some additional validation of the concerns expressed by maintenance personnel regarding the experience level of the staff. Specifically, the report described an analysis of human performance, overtime, and worker experience levels in the electrical maintenance shop and states, "The Electrical Maintenance shop is not the only work group showing evidence of this condition, but the indications are more pronounced and easier to illustrate-  What is evident is that the increased error occurrence rate caused by overtime demand is exacerbated by the decreasing level of station experience within the organization."
 
Engineering. Interviews with personnel in the engineering organization indicated that overtime was not generally perceived as excessive or a particular area of concern. Staffing and qualifications were significant concerns for the engineering personnel interviewed, and were described by some as the biggest issue facing the engineering organization. Although many interviewees acknowledged that Palo Verde had made significant efforts to hire additional engineering staff, they were concerned that given the extended time period required to train engineers, the effort to hire and train new personnel (i.e., the Legacy Program) was not started soon enough to effectively support transfer of the expert knowledge held by the many senior engineers who will soon be eligible for retirement.
 
The team reviewed a summary of engineering organization payroll data from
 
January 2003 through September 2007. The review indicated that staffing numbers had remained stable from 2003 through 2005 and then began increasing substantively beginning in June 2006. However, consistent with the interviewees' perceptions of the loss of senior staff, the team also noted that 102 engineering personnel (or about one-third of the department's staff) have retired or left the site since 2000, 46 (or about half) of whom left in the 18-month period preceding the inspection. Recorded overtime rates during this period peaked in 2006 at 8.4 percent, although the team noted that the majority of engineering personnel are classified as exempt and do not record overtime hours.
 
Engineering Department Staff and Overtime for Years 2003 through 2007 Year 2003 2004 2005 2006 2007 Total Staff* 331 337 335 366 410 Overtime 4.5% 4.0% 6.3% 8.4% 5.9%** *Estimate based on total department staff during September of year shown. **Estimate based upon monthly overtime rates for January through September 2007.
 
Other groups and interactive effects. Interviewees from other functional groups at frontline and mid-management levels also consistently reported inadequate levels of qualified staff to support the current workload, including the procedures 
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and standards group, work management, radiation protection, chemistry, business operations, performance improvement, quality assurance, and the training and human resources groups.
 
Because little hiring outside of APS occurred between 1993 and 2004, the human resources workload associated with recruiting and hiring was negligible and human resources staff did not develop recruiting skills. Interviewees stated that any active recruiting for open positions was carried out by line managers and supervisors, typically "by friendship" when possible. Interviewees reported that when "friendship" was insufficient, positions would sometimes remain open for years. If an individual was identified to be hired, competing demands on human resources staff often delayed completing the hiring process. The result for the line organizations was that the workload associated with the unfilled positions became the responsibility of the remaining staff for extended periods of time, or was simply not addressed.
 
The licensee also permitted the number of qualified training personnel to decline.
 
When an individual left a training position, the position either was eliminated or was difficult to fill because the line organizations could not afford to move personnel into the training positions. As a result, when new staff or contractors were hired and needed training to become fully qualified for their positions, the training resources were not available to qualify them in a timely manner.
 
Interviewees reported numerous examples of staff in chemistry, radiation protection, security, maintenance, and engineering that could not perform all of the tasks required for their positions without supervision, over extended periods of time, because there were insufficient training personnel to provide the required training.
 
The procedures and standards group was created in late October 2006, to centralize responsibility for maintenance and operations procedures, in response to procedure-related site performance problems. The original staffing plan for the group had eight vacancies, three of which were to be filled by hiring people external to APS. In addition, the group hired nine contractors for a project to enhance maintenance procedures. Because of difficulties in filling the open positions and a growing backlog of procedure change requests, the maintenance procedure improvement project was deferred and the contractors were assigned to address the backlog. This action met the group's need for procedure writers who were knowledgeable of maintenance practices. However, because of the staffing limitations in the operations department discussed above, the group was unable to recruit Palo Verde operations personnel to fill the in-house positions and was seeking to hire experienced operators from other sites.
 
Licensee response to staffing and qualifications issues. The team noted that the new senior managers have implemented an aggressive plan to recruit, hire, and train new staff to overcome the current shortages and prepare for staff retirements. In November 2007, the licensee had 226 open positions and was actively seeking staff from outside of APS with the requisite skills and knowledge of current industry standards and practices. Personnel to fill 50 of those open positions had been identified and were expected to begin work at the site in December 2007. In addition, the licensee had approximately doubled the number of Legacy Program engineers, maintenance apprentices, and junior 
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staff in other disciplines. Positions for new instructors have been authorized. The licensee is also augmenting many staff capabilities with additional skilled contractor personnel.
 
Since arriving at Palo Verde, senior management's highest priority has been to recruit and train large numbers of operator candidates, including candidates for non-licensed operator positions and "instant" SROs. The human resources department recently hired an experienced nuclear recruiter to assist in the hiring of personnel. In addition, the licensee hired four new operations training instructors and was considering alternative approaches to increase training instructors. During the inspection, senior management elected to advance the schedule for a class for non-licensed operator candidates by five months. The licensee also increased authorized staffing levels for the operations department
 
to 333 positions.
 
To maintain a more stable level of staffing within the security department, the licensee was increasing the frequency of the security training academy to twice per year and posting a continuously open vacancy announcement to establish a training pipeline for security officers. The licensee was also considering alternative methods to improve the retention of security personnel.
 
The licensee was taking steps to reduce barriers to recruiting, hiring, and retaining staff. For example, APS had previously implemented a policy to achieve compensation parity between engineers at Palo Verde and in the non-nuclear business units of APS. This change caused several Palo Verde engineers to take other, non-nuclear positions within APS to reduce stress or shorten their commutes. Senior management worked with corporate decision-makers to revise the policy and reduce the attrition of skilled engineers from the site. The licensee has also authorized hiring and retention bonuses for targeted skill sets and is offering reimbursement for relocation costs to some new hires.
 
Procedures and documentation. Interviewees uniformly indicated that station procedures, work instructions, drawings, and other documentation necessary to perform work were:
: (1) difficult to follow,
: (2) unnecessarily complicated, and
: (3) sometimes inaccurate, incomplete, or inconsistent with regulatory and other applicable requirements. Many procedur es have become outdated over time.
 
Although these documentation deficiencies have been identified by the NRC and the licensee as important contributing causes for Palo Verde's performance decline, the team noted that licensee actions to correct this problem had been ineffective in sustaining performance improvement.
 
The team observed that the licensee's processes for managing procedures and other critical documentation continued to be fragmented among various organizations across the site. At the time of the inspection, the licensee had identified the need for, but had not yet developed a comprehensive, integrated approach to address the full scope of site-wide documentation deficiencies (CRDR 3079100 - Programmatic Weaknesses in PV Programs, procedures, and processes - ImPACT FOP 11 and safety culture, Apparent Cause Evaluation Report, October 2007).
 
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The licensee had not determined whether to initiate a wholesale upgrade to its existing maintenance and operating procedures to bring them up to current industry standards or continue to address individual procedural deficiencies. As previously discussed, the procedures and standards group initiated a project to enhance maintenance procedures by ensuring the procedures incorporated human factors good practices. However, the project was stopped and the resources diverted when the backlog of procedure change requests began increasing in 2007 as a result of management efforts to reinforce procedure use and adherence expectations. Interviewees indicated that preliminary results of the enhancement project were less than satisfactory to the procedure users, who had been hoping for complete procedure rewrites. The team noted that the availability of qualified staff in the maintenance and operations organizations may not have supported the technical reviews and procedure validation activities that a wholesale upgrade project would require.
 
Interviews also indicated that licensee personnel were aware of the implications of the changing workforce at the site (i.e., increasing numbers of less experienced staff) on the level of detail and usability of the site's documentation, but have not developed a plan to address the issue. The deficiencies in current procedures and work instructions were described as particularly problematic by the less experienced personnel interviewed. These interviewees commented that procedures and other documentation were not helpful as training tools, were not written in plain language that could be understood without step-by-step translation from a senior staff person, and that the level of detail in the procedures was frequently inadequate for them to understand how to perform the task. Because procedures and documentation were of limited usefulness to the less experienced interviewees, these individuals were particularly concerned about the loss of expert knowledge and guidance they rely on when senior members of their work groups retire.
 
Facilities and equipment. Examples of longstanding degraded equipment conditions identified by the team include, in part, Borg Warner check valves, post accident monitoring chart recorders, radioactive waste systems, Target Rock solenoid valves, and cable vault flooding. In addition, interviewees provided
 
numerous examples of degraded or inadequate facilities and equipment that they described as challenging their ability to perform work effectively. Examples included work spaces that were not air conditioned, being denied heat protection when working outside during the summer, bird droppings in work spaces, frayed and decaying safety harnesses, outdated and unreliable software, instruments and test equipment that cannot be repaired because parts are no longer available, security personnel being required to use personal vehicles to patrol because there were an inadequate number of site vehicles, "temporary" power and ventilation systems in workspaces that have been in-place for years, training spaces too small to accommodate class sizes, inadequate access to desks, computers and telephones, and inadequacies in the availability of simple items, such as chairs, stools, shop cabinets, hand tools, or lockers for storing personal belongings. Interviewees reported that they had raised these needs to their supervisors, documented them in the CAP, but had been unsuccessful in resolving the issues over long periods of time. The team concluded that the staff's longstanding inability to resolve such issues contributed to the apparent "tolerance for degraded conditions" the team has observed. The team also noted
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that new management was taking steps to address some of these concerns with mechanisms such as the departmental "Top 10 lists" and the safety culture improvement plans for some work groups.
 
Continuing challenges. Corporate and senior site management personnel have repeatedly affirmed that the resources are available to address these issues.
 
The team noted that the licensee's ability to make a rapid improvement in overall site performance may be hampered by limitations in the availability of qualified staff and that previous performance improvement efforts were partly ineffective for similar reasons. Although senior management is taking aggressive steps to augment staff capabilities, the productivity of inexperienced personnel will likely be challenged until the improvement is made in programs, processes, and procedures.
 
Licensee safety culture assessment. The team determined that the licensee's third-party safety culture assessment adequately captured these issues.
 
b.4 Continuous Learning Environment The team determined that Palo Verde has not established a continuous learning environment. Results of the licensee's self-assessments, the licensee's third-party safety culture asse ssments, and the results of the NRC's safety culture assessment concurred that the site had become insular over the past 15 years.
 
As a result of cost-containment efforts, the licensee curtailed benchmarking and external training opportunities, the few new personnel who were hired between 1994 and 2003 were drawn from inside of APS, and internal training resources were cut. Palo Verde personnel had little exposure to new practices and rising standards in the nuclear industry.
 
Palo Verde's success in the 1990s created an "attitude of arrogance," according to many interviews. Interviewees reported this as another reason they stopped sending people to other utilities on benchmarking trips or for training opportunities. They saw themselves as a world-class nuclear plant that did not need to learn from others. Interviewees indicated that this attitude had hampered previous improvement efforts and led staff to dismiss information about current industry practices and standards from new hires and contractors with broader knowledge.
 
At the time of the inspection, the team did not identify any evidence that personnel were resistant to new ideas or feedback on means to improve individual and site performance. Interviewees were aware of planned benchmarking activities and perceived that benchmarking was necessary to fully understand and be able to implement new expectations and standards. As one operator stated, "I don't know what an operations-led organization looks like."
 
However, because of high workload levels, some interviewees predicted that many of the planned benchmarking activities would be cancelled or curtailed.
 
Based on past experiences, some believed that lessons learned from benchmarking activities would not result in improvements at the site because they would be judged by management to be "unnecessary enhancements" that would just add to the work group's workload, when workload was already excessive.
 
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Many interviewees also expressed the desire for more technical training. This was particularly true of the engineering groups. Focus group participants and individual interviewees were generally dissatisfied with the technical training they received because it had become solely focused on maintaining qualifications rather than enhancing knowledge and skills. Interviewees attributed the perceived training deficiencies to staffing shortages in the training function and restricted resources allocated to training. Some newer employees reported that they had elected to supplement the training they received from the organization by using personal funds to travel to conferences, attend seminars, or take classes because management would not pay for these activities.
 
Frontline and supervisory personnel and most middle managers interviewed believed that knowledge transfer was one of the more important challenges facing the site. Frontline and supervisory staff perceived that:
: (1) site procedures are particularly difficult for new hires to understand and follow and they were not aware of any plans to revise the procedures to make them more usable by new employees;
: (2) there have been limitations in the quality of training materials and the training provided to new employees that did not adequately prepare them for work in the field;
: (3) hiring plans within their work groups did not appear to take into account the length of time required for new employees to become fully qualified and effective in their jobs; and
: (4) the hiring plans did not take into account the additional workload that mentoring new staff imposes on the senior staff. The interviewees indicated that the consequences they experienced from the perceived inadequacies in ensuring knowledge transfer have included an increase in human errors in job performance and on-the-job injuries from inexperienced employees who are unfamiliar with an industrial environment, as well as increased difficulty in managing current workloads. The interviewees perceived that these problems have further contributed to the site's backlogs.
 
Licensee response. In addition to accelerating the hiring of new staff and training personnel, the licensee was beginning to address the knowledge transfer challenges. The human resources depar tment had developed a tool to aid managers in planning for the upcoming retirements in their work groups. Human resources had also developed and recently pilot-tested a knowledge management assessment tool to aid managers in understanding the scope of knowledge those personnel who were retiring would take with them. The tool could be used to identify new-employee training needs. The licensee has also retrained line managers in the systematic approach to training to improve their ability to ensure that training programs are effective. Senior management has also established the expectation with middle management that they, rather than the training department, own and are therefore responsible for the quality of training provided to their work groups.
 
Continuing challenges. The overhead costs associated with transitioning to an effective continuous learning organization are formidable. Adding and training a large number of new personnel, while at the same time increasing the work output from the existing workforce, will require personnel to do more than just work harder. Substantial productivity increases will be necessary to sustain this environment in the long-term. Site productivity will also be challenged by the expected loss of experienced personnel.
 
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Licensee safety culture assessment. The team determined that the licensee's third-party safety culture assessment adequately captured these issues, but did not fully explore their implications.
 
b.5 Accountability The team observed that a positive consequence of the site's reengineering effort was to create a strong sense of empowerment, individual responsibility for site performance, and pride in the site within the workforce. This sense of ownership was evident in:
: (1) the number of individuals who provided detailed write-in comments on the licensee's safety culture surveys in 2005 and 2007 (over half of the respondents on the latter);
: (2) the personnel who called the NRC's confidential "hotline" established for the inspection to request an interview simply to ensure that the team had their insights regarding the reasons for the performance decline at Palo Verde and what is needed to improve;
: (3) the many statements by focus group participants that they had been raising concerns about degrading site performance and offering improvement suggestions to management as early as 2001/2002, as documented in CRDRs, white papers, or PVARs provided to the team; and
: (4) the demonstrated willingness of personnel during the inspection to challenge ARRC decisions and submit repeat PVARs to attempt to ensure that their concerns were fully understood and classified appropriately. However, as previously described, a similar number of focus group participants expressed frustration that they were not fully aware of site performance improvement plans or how they could make an individual contribution.
 
When the team raised the issue of accountability in focus groups, personnel expressed a strong willingness to be held accountable for individual and site performance but were frustrated by what they perceived as the failure of past senior management and some of their middle-managers to be accountable to them. The context for these comments was generally in relation to having the resources to fix equipment and procedures, obtain training, replace personnel who had left their work groups, and the ability to perform work to their standards without excessive schedule or cost-containment pressures or interference with their views of the "right" way to perform a task. Several individuals reported that they had used the recently disseminated standards and expectations and industry safety culture principles booklets to challenge management decisions or actions they perceived as being inconsistent with the goals expressed in the
 
documents.
 
Interviewees also discussed the difficulties of holding co-workers accountable in the face of the many long-standing personal and professional relationships they have developed at the site and in the community (20 years or more among the majority of the workforce). Interviewees discussed the barriers to challenging the work products and behavior of long-term colleagues who have become close friends when those work products or behaviors were professionally unacceptable. Some personnel self-reported the choice to accept inadequate work products and behavior to avoid conflict in these close relationships. Conversely, interviewees also noted the long-standing adverse effects of past interpersonal conflicts that had not been resolved. In these instances, interviewees described conscious efforts to avoid interacting with the individuals
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with whom they had previous conflicts. The team noted that these conflict-avoidant behaviors contributed to the observed "siloing" (i.e., lack of cooperation)between some functional groups, as well as the failure of staff to hold one another accountable for meeting their own and the new management's standards. However, during the inspection, several interviewees reported that they were changing their conflict-avoidant behavior to support the need for performance improvement. These individuals described incidents in which they had personally rejected work products from other organizations that did not meet their standards and worked with the other organization to provide an acceptable product.
 
The team determined that the behavior of site personnel did not consistently reflect the strong, positive attitudes they expressed regarding their willingness to hold themselves accountable as well as to be held accountable by management. The examples of human performance deficiencies described earlier in this report indicated that personnel had not yet internalized senior management's new standards and expectations in individual behavior.
 
Licensee safety culture assessment. The team determined that the licensee's safety culture assessment adequately captured these issues.
 
b.6 Corrective Action Program The team identified several concerns in the corrective action safety culture component associated with problem identification, evaluation, and effective corrective actions. This safety culture component was assessed primarily through direct inspection activities.
 
Specific problem identification concerns during this inspection involved implementation of emergency action levels, the emergency exercise critique process, and solenoid valve performance in the auxiliary feedwater system. As previously discussed in this report, the team identified an apparent reluctance or inability among some personnel to identify issues as conditions adverse to quality without prompting. The team determined that this reluctance or inability was a safety culture weakness. Specific problem evaluation concerns during this inspection involved condensate storage tank temperatures, scaffolding procedures, post-accident monitoring instruments, emergency diesel generator oil leaks, emergency action levels, operability determinations, and the conduct of the corrective action review board and ARRC. The team noted that the licensee's problem evaluations lacked depth and rigor and were generally inconsistent with current industry standards and practices. The team determined that the observed lack of depth and rigor was a safety culture weakness.
 
Specific corrective action concerns during this inspection involved high lead levels in a low pressure safety injection pump bearing, 4160 and 480V motor terminations, establishment of maintenance rule criteria, and multiple databases to track deficient conditions. The team noted that corrective actions for these issues had not been completed or had not been effective, which the team determined represented a safety culture weakness.
 
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Multiple substantive crosscutting aspects associated with problem identification, evaluation and resolution have existed since 2004. Corrective actions have continued to be ineffective in improving performance as noted by effectiveness reviews, external industry reviews, and NRC inspections.
 
The team determined that the licensee's CAP, while complicated and cumbersome, contained the basic elements of an effective program. Licensee personnel often recognized appropriate problem identification, evaluation and resolution fundamentals and behaviors when interviewed; however, this knowledge and understanding of expectations was not consistently demonstrated in meetings or in the field over the course of the inspection. Licensee response:  The licensee's plan to improve the corrective action program was incomplete at the time of the inspection. However, the draft plan available for review addressed the majority of the team's concerns. Licensee safety culture assessment. The team determined that the licensee's safety culture assessment adequately captured these issues. b.7 Work Practices The team identified several concerns in the work practices area. This safety culture component was primarily assessed through direct inspection activities.
 
Work practice human performance concer ns observed during this inspection included:
: (1) Poor human error prevention techniques involving transient combustibles in the containment building and temporary shielding installation;
: (2) poor procedure compliance findings involving transient combustibles in the auxiliary building and radiological surv eys;
: (3) inadequate management oversight for findings involving compliance with Technical Specification Surveillance Requirement 3.0.3, and rigging of the Unit 3 air lock door; and
: (4) operations personnel conduct of operations weaknesses, including turnovers, three-way communications, alarm response, crew briefs, control room logs, and oversight of switchyard activities.
 
Work practice concerns have also been a longstanding issue and performance improvement actions have not sustained improvement as noted by effectiveness reviews, external industry reviews, and NRC inspections. In particular, the licensee's effectiveness review for hum an performance concluded that corrective actions were not well defined and there were no actions for implementation, monitoring, reinforcement, adjustment, or for managing the transfer of responsibility for human performance program changes. Furthermore, the corrective actions for past human performance problems were not fully implemented.
 
Interviews indicated that some personnel had begun implementing new work practice standards and expectations. For example, several interviewees described recent incidents during which they had stopped work in the face of uncertainty (e.g., an incorrect procedure or work order instructions that did not apply to the specific job) or what they perceived to be unsafe job conditions.
 
However, the team noted that these and other desirable work practices were not yet consistently implemented by site personnel.
 
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b.8 Work Control The team identified several concerns in the work control area. This safety culture component was primarily assessed through direct inspection activities. Work control human performance concerns observed during this inspection included weaknesses in communications between fire protection, operations, engineering, and maintenance, which contributed to findings associated with transient combustible material controls, switchyard maintenance activities, establishment of compensatory measures for incorrectly installed sprinklers, establishing performance criteria for plant systems, and installing emergency lighting in containment.
 
Work control concerns have been a longstanding issue and performance improvement actions have not sustained improvement as noted by effectiveness reviews, external industry reviews, and NRC inspections. In particular, the licensee's effectiveness review for hum an performance concluded that corrective actions were not well defined and there were no actions for implementation, monitoring, reinforcement, adjustment, or transfer of human performance ownership change. Furthermore, the corrective actions were either not fully implemented or not implemented as intended.
 
b.9 Operating Experience The team identified several concerns in the OE area. This safety culture component was assessed through direct inspection activities. OE opportunities were frequently missed, ignored or misapplied. A lack of technical rigor was frequently cited in component design basis reviews and self assessments with respect to the application of OE. The station did not appear to have a sense of the importance and benefits of a strong OE program. The failure to incorporate
 
OE into daily activities is an open issue from the Yellow finding. In addition, the failure to effectively use OE contributed to several performance deficiencies identified by the team. Specific examples of ineffective use of OE during the inspection involved AF TT&V, Target Rock reed switches, Borg Warner check
 
valves, and switchyard maintenance activities.
 
b.10 Self and Independent Assessments The team identified several concerns with self assessments. This safety culture component was assessed through direct inspection activities. Self-assessments conducted by Palo Verde personnel often lacked depth and did not effectively specify or implement corrective actions. As a result, the self-assessment program seldom resulted in improved organizational performance. Self-assessment corrective actions were not always tracked nor were corrective action documents always written to track the expected actions. The team noted that self assessments conducted by a mix of Palo Verde and industry personnel
 
led to more meaningful results.
 
Specific examples of poor self assessment implementation involved vague recommendations in the November 2006 operational decision-making self-assessment; the March 2007 work management self-assessment concluded only that the assessment needed to be re-performed later in 2007; the self-
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assessment of the maintenance rule program did not recognize that unavailability and reliability performance criteria could not be validated, that numerous systems had non-conservative performance criteria, and that switchyard risk reviews were not consistently performed; and deficiencies from the assessment of the safety injection system and the assessment of the environmental qualification program were not entered into the CAP.
 
b.11 Environment for Raising Concerns The team determined that the environment for raising concerns was healthy.
 
None of the licensee employees interviewed by the team indicated they were hesitant to raise nuclear safety issues and about 25 percent of those interviewed gave examples of occasions where they had willingly raised an issue multiple times. These included occasions when the individuals believed that the CAP had failed to prioritize an issue appropriately or had not timely or effectively resolved an issue. The large majority of interviewees perceived that their managers were receptive to concerns and willing to address them, although they also reported frustration with the organization's ineffectiveness at resolving longstanding issues such as obtaining replacements for out-dated equipment, completing repairs on equipment within an acceptable timeframe, and delays in hiring and qualifying personnel in time to replace those who had left their work groups or the site.
 
The team identified very few examples of recent incidents or perceptions of retaliation for raising safety concerns. Some interviewees described isolated examples of past incidents that created a perception of retaliation but the licensee had effectively mitigated those perceptions.
 
Almost all of the interviewees stated that if they were not satisfied with the response from their immediate supervisor, they would feel free to escalate the concern. The interviewees uniformly described positive experiences when bringing issues to their supervisors and could name several other avenues for raising concerns. The majority of interviewees explained that approaching their supervisors and using the CAP to raise concerns had been generally effective to communicate the concerns (although less effective in resolving them), and therefore, they have not had the need to use other alternative avenues.
 
The team noted some differences in the willingness of contractors to raise concerns compared to licensee employees. About 5 percent of the contractors in the focus groups stated that they had not been trained in how to write a PVAR or expressed reluctance to doing so for fear of being viewed as a "troublemaker."
 
Consistent with these perceptions, the Employee Concerns Program (ECP) had received several concerns involving contractor personnel in the month before the team arrived on site. In response to those concerns, the licensee reinforced expectations for maintaining a safety conscious work environment (SCWE) in all contract organizations. The ECP sent a letter describing the appropriate SCWE duties and obligations to each contract organization, which became a part of the contracts' terms and conditions. In addition, senior management took steps to integrate contractor supervisors and managers into alignment and other meetings to better communicate SCWE expectations.
 
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b.12 Preventing, Detecting, and Mitigating Perceptions of Retaliation Palo Verde had an Integrated Issues Resolution Process (IIRP) comprising the ECP, the Differing Professional Opinions (DPO) Program, the Management Issues Tracking Resolution (MITR) program, and the PVAR. A fifth, recently implemented corporate-level program, called EthicsPoint, was available for raising ethical concerns or conflicts with the corporate code of conduct, although no-one at the site had used EthicsPoint since it was implemented in early 2007.
 
The combined IIRP included these five alternative avenues for raising concerns at Palo Verde.
 
Employee Concerns Program. Most individuals interviewed by the team were aware of the ECP. Interviews indicated that a few groups, primarily contractors, had not heard of the ECP or received any information or training about the program. Many interviewees did not have personal experience with the ECP because they had not needed to use the program. The majority of those interviewed said that they would raise an issue through their chain-of-command first, and if that didn't work they would take their concern to the company's DPO program instead of using the ECP. The inspection team identified a misconception about the purpose of the ECP among many of the staff interviewed. The most common view was that the ECP is to be used for human resource (HR) issues, which the licensee normally processes through the MITR program, rather than for nuclear safety concerns. When the inspection team discussed this issue with the ECP manager, she indicated that she was aware of the issue and believed this misconception may exist because she formerly was the HR manager. Some interviewees thought that the ECP was not objective because it was linked to senior management. Also, several interviewees told the
 
team that they did not trust the ECP, but were unable to give examples to support the distrust. Personnel interviewed who had used the ECP in the past indicated that the experience was positive, and that they would not hesitate to use the ECP again if needed. No interviewees were aware of any breaches of confidentiality.
 
The team reviewed 36 ECP files from 2007 related to SCWE issues. The team determined that the concerns had been reviewed thoroughly and dispositioned
 
appropriately.
 
The ECP manager had received approval from senior management to conduct extensive benchmarking at other nuclear facilities. This effort has been funded in the 2008 budget. The ECP manager planned to contact the ECP managers at several other sites to obtain information about how other programs write reports, apply policies and guidelines, and advertise their programs. The effort will include reviewing performance indicators and methods for using the program's metrics to better educate management about resolution of issues. One of the other areas to be pursued is how other sites integrate safety issues into their CAPs without compromising confidentiality.
 
The ECP manager was actively working to increase the awareness of the program by making the program more visible at the site. The ECP manager had recently hired two new ECP investigators, and was planning to hire a third with 
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greater technical knowledge to better ensure that each concern is assessed appropriately. Interviewees indicated that the ECP staff was well known, well liked, and approachable.
 
The ECP was developing a plan to re-market the program. Since its integration into the IIRP, the ECP has lost some of its identity to the Palo Verde staff. The ECP manager planned to work with the communications department to develop a new way to communicate the purpose of the ECP without losing integration with
 
the IIRP.
 
Differing Professional Opinions Program. The DPO program was an avenue for resolving technical disagreements between staff members. The process required an independent third party with appropriate technical knowledge to review both sides of the issue and negotiate an acceptable resolution to the problem. After the review is complete, both parties have the option to agree with the resolution. If there is no agreement, the initiator may choose to escalate the issue to the senior management team for resolution where the final decision will be made by the site vice president/CNO. The team reviewed seven recently closed DPO files and concluded that the DPO process was effective.
 
Management Issues Tracking Resolution Process. The MITR process was designed to resolve personnel issues arising between management and staff and was managed by the HR department. As previously mentioned, the team noted some confusion among the staff as to the purpose of this process and took personnel issues or concerns to the ECP more frequently than to HR. Many of those interviewed had never heard of the MITR process. The team reviewed all MITR files from 2007 and determined that the issues had been investigated and
 
resolved effectively.
 
Retaliation and the Disciplinary Review Board. Approximately 98 percent of the interviewees stated that they had not experienced, nor heard of any issues of retaliation, harassment, intimidation or discrimination at Palo Verde. Some interviewees expressed concern that new accountability standards for industrial safety might lead to future perceptions of retaliation, but the team noted that the licensee was working to quell those impressions.
 
The licensee's Disciplinary Review Board (DRB) screened disciplinary actions for evidence of retaliation. The team reviewed several examples of the DRB's efforts to ensure that controversial terminations were not viewed by staff as being retaliatory. One example was a case where an individual had been terminated because of a fitness-for-duty (FFD) violation. Management worked with the line organization to explain the FFD process and the reasons why an employee might be fired for violating FFD standards. This communication successfully diffused the rumors surrounding this particular termination.
 
At the time of the inspection, the DRB did not review actions involving contractor personnel, but the ECP and HR were assessing the need to expand the scope of the program. Both organizations were benchmarking disciplinary review processes at other sites to better understand how Palo Verde can revise its own process to include contractor actions and ensure that all disciplinary actions are thoroughly reviewed for perceptions of retaliation.
 
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Employee Dispute Resolution Process. The Employee Dispute Resolution (EDR) process was a corporate-level program that allows an employee to dispute a disciplinary action. There were three steps in the process. The first step requires the individual to present the dispute and request resolution from his or her direct supervisor. If the employee does not agree with the supervisor's response, the employee can appeal the issue to the HR manager. At this second step, the HR manager assigns a representative to investigate the dispute and propose a solution that is acceptable to both the employee and supervisor.
 
When a disciplinary action or termination takes place, or if the result of Step 2 is not acceptable to the individual, he or she has a choice to request a review of the action taken by either the APS Corporate Vice President of HR or from a review panel. Employees may dispute the nature or severity of the impending discipline. During the review, the management team will try to ensure that the employee is able to openly discuss their opposition to the action. Once the review takes place, the decision to change the disciplinary action must be made within 10 working days.
 
The team's review of the EDR process indicated that the EDR generally reduced the level of discipline applied, but there were no terminations that had been reversed as a result of the process. The team determined that this process was effective in resolving employee disputes involving disciplinary actions.
 
b.13 Safety Policies The team concluded that Palo Verde's safety policies and training related to safety culture and the safety conscious work environment were appropriate. Interviews indicated that the new senior management team was generally perceived as believable in their emphasis on nuclear safety and as "walking the talk."  Focus group participants who had exercised the new senior managers' invitations to send an email or other communication regarding concerns or suggestions commented favorably that their issues were taken seriously and, in most cases, resulted in action. Consistent with the results of the licensee's safety culture assessment, the NRC team determined that most personnel
 
interviewed were "cautiously optimistic" that the new senior management team can be trusted to improve performance at the site.
 
9.0 REVIEW OF YELLOW FINDING - CONTAINMENT SUMP VOIDING Before commencing the inspection, the licensee informed the NRC that they were not prepared to support a closure review of the corrective actions associated with the Yellow finding. Consequently, the team only reviewed the licensee's progress in addressing the Yellow finding's performance concerns.
 
The team identified that the licensee was unable to effectively track the completion of corrective actions associated with the two NRC IP 95002 supplemental inspections and had not evaluated the effectiveness of corrective actions taken for this item. The inability of the licensee to resolve the Yellow finding performance deficiencies contributed to several of the violations documented in this report.
 
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====a. Inspection Scope====
The team reviewed the status of the implementation and completion of corrective actions associated with a Yellow finding previously issued to Palo Verde regarding the voiding of ECCS piping in all three units. The team evaluated the results of previous NRC IP 95002 inspections related to this finding, as well as prior Palo Verde performance improvement plans and corrective action plans. The team also reviewed a recent audit of these corrective actions conducted by Palo Verde.
 
====b. Observations and Findings====
On October 24, 2007, the team reviewed the July 2004 Yellow finding to determine if the associated corrective actions had been completed and if they had been assessed by the licensee as effective. The root cause analysis for the Yellow finding identified several deficiencies which were segregated into 10 focus areas. These 10 focus areas were assigned to individual licensee managers or focus area owners. The December 12, 2005, and the October 11, 2006, NRC IP 95002 inspections determined that the corrective actions for these deficiencies were not completed. The areas of concern involved questioning attitude, technical rigor, technical review, the establishment of performance measures and metrics, and the use of OE. PVNGS responded to the NRC in a November 16, 2006, letter detailing further commitments in completing these corrective actions by March 30, 2007.
 
In June 2007
, the licensee completed an IP 95002 effectiveness review and concluded that they had not maintained current documentation of the project which precluded an accurate status assessment of the corrective actions. The checklist used for this effectiveness review described several reasons for non-completion of the corrective actions, including:  improper alignment of the corrective action to the root cause; corrective actions not assigned as CRDRs and CRAIs (which did not allow for assessment of corrective action completi on); CRDR and CRAI completion dates being extended several months past original due dates; and the lack of metrics to measure effectiveness (originally scheduled for co mpletion by December 1, 2006). An additional issue was that no effectiveness reviews (effectiveness reviews of engineering products was originally scheduled to be complete by February 1, 2007)were conducted to insure proper closure of corrective actions.
 
Following discussions with the licensee, t he team determined that in early 2007, when it was known that Unit 3 was entering Column 4, the focus area owners assumed that the IP 95002 corrective actions would be integrated into the IP 95003 process. During this period a new senior management team was arriving and it was assumed by the focus area owners that a new plan would be developed for site improvement. As a result, the IP 95002 corrective actions were "administratively forgotten" as stated in the evaluation report and PVAR 3030058, which identified this deficiency on June 19, 2007. The licensee initiated CRDR 3031092 to resolve their inability to address the Yellow finding performance concerns.
 
10 REVIEW OF WHITE FINDING - EMERGENCY DIESEL GENERATOR K-1 RELAY Prior to the performance of the inspection, the licensee indicated they had not completed the effectiveness reviews of the root causes and corrective actions associated with the K-1 relay failure. Consequently, the team reviewed the licensee's progress and did not
- 148 -
complete an assessment using IP 95001. A subsequent inspection will be completed using IP 95001 as part of the NRC's review of the items described in the Confirmatory Action Letter dated June 21, 2007.
 
====a. Inspection Scope====
The team reviewed the licensee's assessment of the White finding associated with the Unit 3 K-1 relay to assure that the root causes and contributing causes of the risk significant performance issues were understood. In addition, the team reviewed the extent of condition and corrective actions to verify that they were sufficient to address the root causes and contributing causes, and to prevent recurrence.
 
Specifically, CRDR 2926830," Unit 3 Diesel Generator K1 Contactor Repeat Failure, Revision 3, dated September 20, 2007, was reviewed using the guidance provided in IP 95001. CRDR 2926830, incorporated the results of the Palo Verde ImPACT Team review to correct inadequacies in the previous revision of the root cause investigation. In addition, Revision 2 of this document was reviewed, along with APS Correspondence 102-05626-CDM/SAB/JAP/CJS from D. Mauldin to US NRC, dated January 9, 2007, responding to NRC Inspection Report 05000528; 05000529; 05000530/2006012 and a draft copy of the "K-1 Relay Issue Problem Development Sheet," dated July 26, 2007, used by the licensee to evaluate and address the inadequacies in earlier root cause investigations of this problem.
 
====b. Observations and Findings====
The team considered the technical analysis provided in the root cause investigation analysis to be adequate. However, the team observed several examples where the investigation could have been more technically rigorous or the investigators should have had a more questioning attitude. Specifically:
1) Root Cause 1 stated that the K1 relay was treated as a single replaceable component; however, there were no design documents or drawings of this safety-related relay found in the PVNGS nuclear records as stated in the "Overview of K1
 
Contactor History."
 
2)  The discovery, during troubleshooting, of variations of straight and bent actuator arms without corroborating drawings may have indicated that field modifications had been made at some time in the past and thus may have invalidated the original equipment qualification.
 
3) The decision to "adjust and field straighten" the actuator arms may have invalidated the equipment qualification. Metal fatigue and spring compression issues are mentioned; however, other qualification issues such as seismic qualification were not.
 
4)  The report was not rigorous in documenting the extent of condition. Specifically, the K1 relay condition could have also existed in the other two units at the same time; thereby, having an impact on plant risk at the other two units. The "Safety Significance" section, as it was written, potentially indicated a lack of appreciation by the licensee of the impact that the inoperability of safety systems and components had on plant risk.
 
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11 LICENSEE-IDENTIFIED VIOLATIONS The following violations of very low significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI.A of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs:
a. Technical Specification 5.4.1.a requires written procedures to be established, implemented, and maintained covering the activities specified in Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operations)," dated February 1978. Regulatory Guide 1.33, Appendix A, Item 1.l, "Plant Fire Protection Program," requires, in part, procedures for plant fire protection. Procedures 14DP-0FP34, "Fire Watch Duties," and 14DP-0FP36, "Hot Work Permit," stated that in the event of a fire, notify the fire department by calling the site emergency extension (i.e., contact security who contacts the control room). Contrary to this requirement, personnel notified the site fire department via the normal fire department extension vice the site emergency extension following a small fire in Unit 3 on October 5, 2007.
 
This resulted in the control room not being notified of the fire until several hours after the fire started, which impacted the ability of the SM to implement the EAL assessment process. The licensee subsequently determined that no EAL classification would have been required since the fire lasted less than five minutes. The licensee entered this item into the CAP as PVARs 3071922 and 3071994. This finding was determined to be of very low safety significance because it did not result in a missed emergency classification.


b. 10 CFR Part 50, Appendix B, Criteria XVI, "Corrective Action," requires the licensee to take appropriate and timely corrective action for conditions adverse to quality. The inspectors reviewed CRAI 2942350 that addressed training for chemistry personnel on changes to the 10 CFR 50.59 Guidance Manual. Some Chemistry personnel had not attended the training and the CRAI was closed as complete. This corrective action was in response to the ESP chemistry issues which resulted in the fouling of the EDG heat exchanger in 2006. The licensee did review procedures that were revised by these personnel that had not attended this training. The licensee performed an extent of condition and found one individual that was not qualified on applicability determinations had performed applicability determinations with supervisor permission because they thought the individual was qualified to perform applicability determinations after attending chemistry training in November 2006. Additionally, as a follow up to PVAR 3009064, dated May 4, 2007, the team reviewed an additional nine CRDRs reported in 2005, four CRDRs in 2006 and eleven CRDRs as of October 5, 2007 related to personnel performing safety-related and non-safety-related activities without proper qualifications. No items of significance were identified. This
Chief, Radiological Emergency Preparedness Section National Preparedness Directorate Technological Hazards Division Department of Homeland Security 1111 Broadway, Suite 1200 Oakland, CA 94607-4052


event was documented in the licensee's CAP as PVARs 3073306 and 3082659. This finding is of very low safety significance because the licensee concluded that the procedures that were changed and the tasks that were performed did not contain significant errors and had not resulted in the need to perform an evaluation for
Arizona Public Service Company
- 6 -


applicability determinations.
Electronic distribution by RIV:
Regional Administrator (Elmo.Collins@nrc.gov)
DRP Director (Dwight.Chamberlain@nrc.gov)
DRS Director (Roy.Caniano@nrc.gov)
DRS Deputy Director (Troy.Pruett@nrc.gov)
Senior Resident Inspector (Greg.Warnick@nrc.gov)
Branch Chief, DRP/D (Michael.Hay@nrc.gov)
Senior Project Engineer, DRP/D (Greg.Werner@nrc.gov)
Senior Project Engineer, DRP/D (Geoff Miller@nrc.gov)
Team Leader, DRP/TSS (Chuck.Paulk@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)


c. Technical Specification 5.4.1.a requires, in part, that written procedures be established, implemented, and maintained covering the activities specified in Appendix A of Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operations),"
DISTRIBUTION:
dated February 1978. Regulatory Guide 1.33, Appendix A, Section 9a, requires maintenance that can affect safety-related equipment be properly preplanned and
via e-mail:
- 150 -  
AHowell - ATH Fuller - KSF
- 151 - 12 MANAGEMENT MEETINGS On December 19, 2007, a public meeting was held to present the results of the inspection to Mr. R. Edington, Senior Vice President, Nuclear, and other members of the licensee's staff. The licensee acknowledged the inspection results. Proprietary information was reviewed during the inspection. The proprietary information was returned to the licensee and was not included in this inspection report.


On December 19, 2007, a public meeting was conducted following the IP 95003 exit meeting to discuss the licensee's performance improvement initiatives.
C Maier - MCM1 Vasquez - GMV D Furst, NSIR Vegel - AXV


A-1
N Hilton, OE June Cai, OE Lantz - REL John Wray, OE


=SUPPLEMENTAL INFORMATION=
Warnick - GXW Coleman - PRC


KEY POINTS OF CONTACT
Starkey, OE - DRS Mary Ann Ashley, NRR


===Licensee Personnel===
M Burrell, OE Dricks - VLD
: [[contact::G. Andrews]], Director, Performance Improvement
: [[contact::S. Bauer]], Director, Regulatory Affairs
: [[contact::R. Bement]], Vice President, Nuclear Operations
: [[contact::P. Borchert]], Director, Operations
: [[contact::P. Brandjes]], Department Leader, Maintenance 
: [[contact::R. Buzard]], Senior Consultant, Regulatory Affairs
: [[contact::D. Carnes]], Director, Nuclear Assurance
: [[contact::P. Carpenter]], Department Leader, Operations
: [[contact::R. Cavalieri]], Director, Outages
: [[contact::K. Chavet]], Senior Consultant, Regulatory Affairs
: [[contact::D. Coxon]], Unit Department Leader, Operations
: [[contact::R. Edington]], Senior Vice President, Nuclear
: [[contact::D. Elkington]], Consultant, Regulatory Affairs
: [[contact::J. Gaffney]], Director, Radiation Protection
: [[contact::T. Gray]], Department Leader, Radiation Protection
: [[contact::K. Graham]], Department Leader, Fuel Services
: [[contact::M. Grigsby]], Unit Department Leader, Operations
: [[contact::M. Grissom]], Section Leader, Reactor Engineering
: [[contact::J. Hesser]], Vice President, Engineering
: [[contact::M. Karbasian]], Director, Engineering
: [[contact::D. Marks]], Section Leader, Regulatory Affairs
: [[contact::S. McKinney]], Department Leader, Operations Support 
: [[contact::J. Mellody]], Department Leader, PV Communications
: [[contact::E. ONeil]], Department leader, Emergency Preparedness
: [[contact::M. Radspinner]], Section Leader, Systems Engineering
: [[contact::T. Radtke]], General Manager, Emergency Services and Support
: [[contact::H. Ridenour]], Director, Maintenance
: [[contact::F. Riedel]], Director, Nuclear Training Department
: [[contact::M. Shea]], Director, ImPACT Team
: [[contact::E. Shouse]], Representative, EPE
: [[contact::M. Sontag]], Department Leader, Performance Improvement
: [[contact::D. Straka]], Senior Consultant, Regulatory Affairs
: [[contact::J. Taylor]], Unit Department Leader, Operations
: [[contact::D. Vogt]], Section Leader, OPS STA
: [[contact::T. Weber]], Section Leader, Regulatory Affairs
: [[contact::J. Wood]], Department Leader, Nuclear Training Department


===NRC Personnel===
Wm Maier - WAM R Barnes, OE Robert Kahler
: [[contact::M. Runyan]], Senior Reactor Analyst


Items Opened and Closed
SUNSI Review Completed: __Yes___ ADAMS: U Yes G No Initials: __PJE__
Item Number
U Publicly Available G Non-Publicly Available G Sensitive U Non-Sensitive
Type Description 05000528; 05000529;
05000530/2007012-01
NCV Eight Examples of the Failure to Implement the
Operability Determination Process 05000528; 05000529;
05000530/2007012-02
NCV Failure to Implement Adequate Design Controls for
Condensate Storage Temp.
05000530/2007012-03
NCV Inadequate Installation of Fire Sprinklers 05000528; 05000529;
05000530/2007012-04
NCV Six Examples of a Failure to Implement the Corrective Action Program Requirements 05000528; 05000529;
05000530/2007012-05
NCV Failure to Evaluate Performance Monitoring Criteria for Auxiliary Feedwater System 05000528; 05000529;
05000530/2007012-06
NCV Failure to Meet Technical Specification Surveillance Requirement 3.6.6.6
05000528;
05000529/2007012-07
NCV Failure to Meet Technical Specification Surveillance Requirement 3.0.3
05000530/2007012-08
NCV Two Examples of a Failure to Maintain Control of
Transient Combustibles
05000530/2007012-09
FIN Failure to Install Emergency Lighting in Containment Prior to Work Commencement
05000530/2007012-10
NCV Failure to Follow Procedures for Temporary Shielding Installation 05000528; 05000529;
05000530/2007012-11
NCV Inadequate Implementation of Risk Management Actions and Risk Assessments for the Switchyard
05000530/2007012-12
NCV Incorrect Rigging of Personal Airlock Door
05000530/2007012-13
NCV Failure to Maintain Configuration Control of Pressurizer Instrument Condensing Pot Support
Brackets 05000528; 05000529
05000530/2007012-14
NCV Failure to Implement Maintenance Rule Requirements for the High Pressure Safety Injection
System 05000528; 05000529;
05000530/2007012-16
NCV Inability to Implement Emergency Action Levels
05000530/2007012-17
NCV Inadequate Briefings of Radiological Conditions
05000529/2007012-18
NCV Failure to Periodically Update the Updated Final Safety Analysis Report
Items Opened
05000528; 05000529;
05000530/2007012-15
AV Failure to Correct a Risk Significant Planning
Standard 05000528; 05000529;
05000530/2007012-19
URI Routine Heavy Use of Overtime 


A-3List of Acronyms
SEPI:OB ACES C:OB C:PBD OE ACES D:DRS PJElkmann/lmb MVasquez RELantz MHay JWray KFuller RJCaniano
ACC  Arizona Corporate Commission ACT  Action Tracking System
/RA/
ADAMS Agencywide Documents Access and Management System ADV  atmospheric dump valve
/RA/
ALARA as low as reasonably achievable
/RA/
AF  auxiliary feedwater APS  Arizona Public Service ARRC  Action Request Review Committee
/RA/
AT  activity tracking ATC  at-the-controls CAL  Confirmatory Action Letter CAP  corrective action program CAPR  corrective action to prevent recurrence
/RA/
CARB  corrective action review board
/RA/
CCDP  conditional core damage probability
/RA/
CDBR  component design basis review CDF  core damage frequency CFR  Code of Federal Regulations
4/17/08 4/22/08 4/22/08 4/24/08 4/29/08 4/22/08 4/30/08 OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
CRAI  condition report action item
CRDR  condition report/disposition request
CRS  control room supervisor
CS  containment spray CST  condensate storage tank DPO  differing professional opinion
DRB  Disciplinary Review Board
EAL  emergency action level
EC  emergency coordinator ECP  Employee Concerns Program ECCS  emergency core cooling system
ECE  engineering change evaluation ED  emergency director EDG  emergency diesel generator EDR  Employee Dispute Resolution EOP  emergency operating procedure EP  Emergency Plan
EPIP  Emergency Plan Implementing Procedure
EQ  environmental qualification
ESP  essential spray pond EW  essential cooling water FA  functional assessment
FFD  fitness-for-duty
FOP  fundamental overall problem
FP  fire protection
GPH  gallons per hour HEP  human error probability HPSI  high pressure safety injection
A-4IIRP  Integrated Issues Resolution Process IMC  Inspection Manual Chapter ImPACT improved performance and cultural transformation ISCPET Independent Safety Culture Performance Evaluation Team
ISLOCA intersystem loss of coolant accident
IP  Inspection Procedure
JPM  job performance measure
KART  key attribute review team LER  Licensee Event Report LERF  large early release frequency
LPSI  low pressure safety injection
LOCT  licensed operation cycle training
LOOP  loss of offsite power MITR  Management Issues Tracking Resolution MR  maintenance rule NCR  nonconformance report NPSH  net positive suction head NRC  U.S. Nuclear Regulatory Commission O&M  Operations & Maintenance OD  operability determination
ODMI  operational decision making instruction
OE  operating experience
PAL  personnel airlock
PAR  Protective Action Recommendation PC  performance criteria PDS  problem development statement
PI&R  problem identification and resolution
PM  preventative maintenance
PPM  parts per million PSF  performance shaping factor PSIA  pounds per square inch absolute
PVAR  Palo Verde action request
PVNGS Palo Verde Nuclear Generating Station
RP  radiation protection
RVLMS reactor vessel level monitoring system SCWE  safety conscious work environment SRP  Salt River Project
SDC  shutdown cooling SGTR  steam generator tube rupture SIBP  Site Integrated Business Plan SIIP  Site Integrated Improvement Plan SM  shift manager
SMART specific, measurable, achievable, reasonable, and timely SPAR  Standardized Plant Analysis Risk
SOV  solenoid operated valve
SQFT  square foot SRO  senior reactor operator SSC  structures, systems, and components
A-5STA  shift technical advisor SWMS  site work management system SWYD  switchyard TCCP  transient combustible controls permit
TDS  total dissolved solids
TID  total integrated dose
TGO  transmission/generation operations
T&TV  trip and throttle valve TS  Technical Specification TSSR  Technical Specification Surveillance Requirement
UFSAR Updated Final Safety Analysis Report
URI  unresolved item
WO  work order
}}
}}

Latest revision as of 16:56, 14 January 2025

IR 05000528-07-012, 05000529-07-012, and 05000530-07-012, Palo Verde Nuclear Generating Station, Units 1, 2, and 3, Final Significance Determination for a Preliminary White Finding
ML081230561
Person / Time
Site: Palo Verde  Arizona Public Service icon.png
Issue date: 04/30/2008
From: Caniano R
Division of Reactor Safety IV
To: Edington R
Arizona Public Service Co
References
EA-08-003 IR-07-012
Download: ML081230561 (6)
v • d • e


Text

April 30, 2008

SUBJECT:

PALO VERDE NUCLEAR GENERATING STATION, UNITS 1, 2, AND 3 - NRC INSPECTION REPORT 05000528/2007012, 05000529/2007012, AND 05000530/2007012, FINAL SIGNIFICANCE DETERMINATION FOR A PRELIMINARY WHITE FINDING

Dear Mr. Edington:

The purpose of this letter is to provide you the final results of our significance determination of the preliminary White finding identified in the subject inspection report (ADAMS accession number ML080320562) and by letter dated February 1, 2008 (ADAMS accession number ML080320590). The inspection finding was preliminarily characterized as White (i.e., a finding with low to moderate increased importance to safety that may require additional U. S.

Nuclear Regulatory Commission (NRC) inspections) using Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process. This preliminary White finding, and associated apparent violation of NRC requirements, involved the failure of the Palo Verde Nuclear Generating Station personnel to correct an identified weakness in the performance of senior reactor operators. Specifically, when evaluated during training evolutions beginning in May 2007, a high percentage of senior operators incorrectly classified a general emergency for simulated plant conditions that required a site area emergency declaration, and corrective actions were not completed until October 2007.

At your request, a Regulatory Conference was held on March 25, 2008, to further discuss your views on this issue. A copy of the presentation you provided at this meeting is attached to the Regulatory Conference Meeting Summary dated April 10, 2008 (ADAMS accession number ML081020348). During the meeting, your staff described your assessment of the significance of the findings and detailed corrective actions to address the failure to correct the weakness in senior reactor operator performance. Specifically,

UNITED STATES NUCLEAR REGULATORY COMMISSION R E GI ON I V 611 RYAN PLAZA DRIV E, SUITE 400 ARLINGTON, TEXAS 76011-4005

Arizona Public Service Company

- 2 -

You agreed that beginning on May 2, 2007, Palo Verde Nuclear Generating Station personnel identified a knowledge deficiency among senior operators regarding their evaluation of the reactor coolant fission product barrier and knowledge of the definition of prolonged release, that the station corrective action program was not effectively used when the knowledge deficiency was identified, and that the knowledge deficiency was not corrected until October 25, 2007.

  • You discussed your view that the failure by Palo Verde Nuclear Generating Station personnel to promptly correct the identified knowledge deficiency had very low safety significance because the knowledge deficiency could not result in an incorrect emergency classification during an actual plant event involving a steam generator tube rupture and use of the atmospheric dump valves for reactor coolant temperature control.
  • You discussed corrective actions that included requiring the operations training department to enter errors discovered in operator examination materials and operator failures on examinations and job performance measures into the corrective action program, initiating routine trending of weaknesses in operator performance during training, and requiring the concurrence of the emergency preparedness department on examinations and job performance measures used to test operator knowledge of emergency preparedness topics.
  • Following the conference you provided additional information (ADAMS accession number ML081130231), in response to our request, describing the simulator scenarios that formed the basis for your determination that the knowledge deficiency could not result in an incorrect classification during a steam generator tube rupture event.

After considering the information you provided during and following the conference, the NRC has concluded that the knowledge deficiency identified among senior operators would not likely result in an incorrect emergency classification during a steam generator tube rupture event.

Specifically, the NRC concluded that, given the identified knowledge weakness, an incorrect classification of a steam generator tube rupture event with atmospheric dump valves in operation can only occur with a concurrent potential loss of the fuel clad barrier, and that under these conditions all credible scenarios resulting in potential losses of the fuel clad barrier also cause loss of the reactor coolant barrier. The combination of a potential loss of the fuel clad barrier, loss of reactor coolant barrier, and the loss of containment barrier which results from operating the atmospheric dump valves, results in a general emergency condition, irrespective of the operators knowledge of whether a prolonged release is occurring. The NRC has determined your analysis of steam generator tube rupture events reasonably bounds the possible scenarios leading to a potential loss of the fuel clad barrier.

Arizona Public Service Company

- 3 -

Because the identified knowledge deficiency among senior operators would not likely result in an incorrect emergency classification during an actual plant event, the NRC has concluded the significance of the inspection finding is appropriately characterized as Green (i.e., a finding of very low safety significance).

The NRC has also determined the failure to correct an identified weakness in emergency preparedness performance with a promptness appropriate to its risk significance is a violation of 10 CFR 50.54(q) and 10 CFR Part 50, Appendix E, IV(F)(2)(g). The circumstances surrounding the violation are described in detail in the subject inspection report. This violation is being treated as a Non-Cited Violation (NCV), consistent with Section VI of the NRC Enforcement Policy. Therefore, no response to this letter is necessary. However, if you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this letter, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-001, with copies to; (1) the Regional Administrator, Region IV; (2) the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; and (3) the NRC Resident Inspector at Palo Verde.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosures, and your response, if you choose to provide one, will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). To the extent possible, your response should not include any personal privacy, proprietary, or safeguards information so that it can be made available to the Public without redaction.

Sincerely,

/RA/

Roy Caniano, Director

Division of Reactor Safety

Dockets: 50-528; 50-529; 50-530 Licenses: NPF-41; NPF-51; NPF-74

cc:

Steve Olea Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007

Arizona Public Service Company

- 4 -

Douglas K. Porter, Senior Counsel Southern California Edison Company Law Department, Generation Resources P.O. Box 800 Rosemead, CA 91770

Chairman Maricopa County Board of Supervisors 301 W. Jefferson, 10th Floor Phoenix, AZ 85003

Aubrey V. Godwin, Director Arizona Radiation Regulatory Agency 4814 South 40 Street Phoenix, AZ 85040

Scott Bauer, Director Regulatory Affairs Palo Verde Nuclear Generating Station Mail Station 7636 P.O. Box 52034 Phoenix, AZ 85072-2034

Mr. Dwight C. Mims Vice President, Regulatory Affairs and Performance Improvement Palo Verde Nuclear Generating Station Mail Station 7605 P.O. Box 52034 Phoenix, AZ 85072-2034

Jeffrey T. Weikert Assistant General Counsel El Paso Electric Company Mail Location 167 123 W. Mills El Paso, TX 79901

Eric J. Tharp Los Angeles Department of Water & Power Southern California Public Power Authority P.O. Box 51111, Room 1255-C Los Angeles, CA 90051-0100

Arizona Public Service Company

- 5 -

James Ray Public Service Company of New Mexico 2401 Aztec NE, MS Z110 Albuquerque, NM 87107-4224

Geoffrey M. Cook Southern California Edison Company 5000 Pacific Coast Hwy, Bldg. D21 San Clemente, CA 92672

Robert Henry Salt River Project 6504 East Thomas Road Scottsdale, AZ 85251

Brian Almon Public Utility Commission William B. Travis Building P.O. Box 13326 1701 North Congress Avenue Austin, TX 78701-3326

Karen O' Regan Environmental Program Manager City of Phoenix Office of Environmental Programs 200 West Washington Street Phoenix, AZ 85003

Matthew Benac Assistant Vice President Nuclear & Generation Services El Paso Electric Company 340 East Palm Lane, Suite 310 Phoenix, AZ 85004

Chief, Radiological Emergency Preparedness Section National Preparedness Directorate Technological Hazards Division Department of Homeland Security 1111 Broadway, Suite 1200 Oakland, CA 94607-4052

Arizona Public Service Company

- 6 -

Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

DRP Director (Dwight.Chamberlain@nrc.gov)

DRS Director (Roy.Caniano@nrc.gov)

DRS Deputy Director (Troy.Pruett@nrc.gov)

Senior Resident Inspector (Greg.Warnick@nrc.gov)

Branch Chief, DRP/D (Michael.Hay@nrc.gov)

Senior Project Engineer, DRP/D (Greg.Werner@nrc.gov)

Senior Project Engineer, DRP/D (Geoff Miller@nrc.gov)

Team Leader, DRP/TSS (Chuck.Paulk@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

DISTRIBUTION:

via e-mail:

AHowell - ATH Fuller - KSF

C Maier - MCM1 Vasquez - GMV D Furst, NSIR Vegel - AXV

N Hilton, OE June Cai, OE Lantz - REL John Wray, OE

Warnick - GXW Coleman - PRC

Starkey, OE - DRS Mary Ann Ashley, NRR

M Burrell, OE Dricks - VLD

Wm Maier - WAM R Barnes, OE Robert Kahler

SUNSI Review Completed: __Yes___ ADAMS: U Yes G No Initials: __PJE__

U Publicly Available G Non-Publicly Available G Sensitive U Non-Sensitive

SEPI:OB ACES C:OB C:PBD OE ACES D:DRS PJElkmann/lmb MVasquez RELantz MHay JWray KFuller RJCaniano

/RA/

/RA/

/RA/

/RA/

/RA/

/RA/

/RA/

4/17/08 4/22/08 4/22/08 4/24/08 4/29/08 4/22/08 4/30/08 OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

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