ML081300387

From kanterella
Jump to navigation Jump to search
IR 05000528-08-002, 05000529-08-002, & 05000530-08-002; 01/01/08 03/31/08; Palo Verde, Units 1, 2, and 3; Integrated Resident and Regional Report; Maintenance Risk Assessments and Emergent Work Control, Operability Evaluations, Post-Mainten
ML081300387
Person / Time
Site: Palo Verde  Arizona Public Service icon.png
Issue date: 05/09/2008
From: Hay M
NRC/RGN-IV/DRP/RPB-D
To: Edington R
Arizona Public Service Co
References
IR-08-002
Download: ML081300387 (79)


See also: IR 05000528/2008002

Text

{{#Wiki_filter:UNITED STATES

                              NU C LE AR RE G ULATO RY C O M M I S S I O N
                                                R E GI ON I V
                                     612 EAST LAMAR BLVD , SU ITE 400
                                      AR LIN GTON , TEXAS 76011-4125
                                               May 20, 2008

Randall K. Edington, Executive Vice President, Nuclear

 and Chief Nuclear Officer

Mail Station 7602 Arizona Public Service Company P.O. Box 52034 Phoenix, AZ 85072-2034 SUBJECT: ERRATA FOR PALO VERDE NUCLEAR GENERATING STATION - NRC

              INTEGRATED INSPECTION REPORT 05000528/2008002, 05000529/2008002,
              AND 05000530/2008002

Dear Mr. Edington: This errata corrects the decision basis for the significance determination for Noncited Violation 05000528; 05000529; 05000530/2008002-04, "Failure To Maintain Adequate Staffing Levels Results in Heavy Use of Overtime to Maintain Adequate Shift Coverage," described in Section 4OA2 of the subject inspection report. Please replace page 4 of the Summary of Findings and page 30 of NRC Inspection Report 05000528/2008002, 05000529/2008002, and 05000530/2008008, dated May 9, 2008, with the enclosed revised pages. We regret any inconvenience this may have caused. In accordance with 10 CFR 2.390 of the NRCs "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 NRCs document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). Should you have any questions concerning this inspection, we will be pleased to discuss them with you.

                                               Sincerely,
                                               /RA/
                                               Michael C. Hay, Chief
                                               Projects Branch D
                                               Division of Reactor Projects

Arizona Public Service Company -2- Dockets: 50-528

              50-529
              50-530

Licenses: NPF-41

              NPF-51
              NPF-74
cc w/Enclosure:                           Douglas K. Porter, Senior Counsel
Steve Olea                                Southern California Edison Company
Arizona Corporation Commission            Law Department, Generation Resources
1200 W. Washington Street                 P.O. Box 800
Phoenix, AZ 85007                         Rosemead, CA 91770
Chairman                                  Aubrey V. Godwin, Director
Maricopa County Board of Supervisors      Arizona Radiation Regulatory Agency
301 W. Jefferson, 10th Floor              4814 South 40 Street
Phoenix, AZ 85003                         Phoenix, AZ 85040
Scott Bauer, Director                     Mr. Dwight C. Mims
Regulatory Affairs                        Vice President, Regulatory Affairs and
Palo Verde Nuclear Generating Station      Performance Improvement
Mail Station 7636                         Palo Verde Nuclear Generating Station
P.O. Box 52034                            Mail Station 7605
Phoenix, AZ 85072-2034                    P.O. Box 52034
                                          Phoenix, AZ 85072-2034
Jeffrey T. Weikert
                                          Eric J. Tharp
Assistant General Counsel
                                          Los Angeles Department of Water & Power
El Paso Electric Company
                                          Southern California Public Power Authority
Mail Location 167
                                          P.O. Box 51111, Room 1255-C
123 W. Mills
                                          Los Angeles, CA 90051-0100
El Paso, TX 79901
James Ray                                 Geoffrey M. Cook
Public Service Company of New Mexico      Southern California Edison Company
2401 Aztec NE, MS Z110                    5000 Pacific Coast Hwy, Bldg. D21
Albuquerque, NM 87107-4224                San Clemente, CA 92672

Arizona Public Service Company -3-

                                     Brian Almon
Robert Henry                         Public Utility Commission
Salt River Project                   William B. Travis Building
6504 East Thomas Road                P.O. Box 13326
Scottsdale, AZ 85251                 1701 North Congress Avenue
                                     Austin, TX 78701-3326
Karen O' Regan                       Matthew Benac
Environmental Program Manager        Assistant Vice President
City of Phoenix                      Nuclear & Generation Services
Office of Environmental Programs     El Paso Electric Company
200 West Washington Street           340 East Palm Lane, Suite 310
Phoenix, AZ 85003                    Phoenix, AZ 85004
Arizona Public Service Company              -4-
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)
Only inspection reports to the following:
DRS STA (Dale.Powers@nrc.gov)
J. Adams, OEDO RIV Coordinator (John.Adams@nrc.gov)
P. Lougheed, OEDO RIV Coordinator (Patricia.Lougheed@nrc.gov)
ROPreports
PV Site Secretary (Patricia.Coleman@nrc.gov)
SUNSI Review Completed:         MCH       ADAMS: / Yes No Initials:      MCH__
/ Publicly Available         Non-Publicly Available      Sensitive / Non-Sensitive
R:\_REACTORS\_PV\2008\PV2008-02Errata-GGW.doc                           ML

RIV:RI:DRP/D RI:DRP/D RI:DRP/D RI:DRP/D RI:DRP/D RI:DRP/D JHBashore MPCatts JFMelfi GGWarnick RITreadway GBMiller /RA/ /RA/ /RA/ /RA/ MCHay for /RA/ E-mailed /RA/ 05/20/2008 05/19/2008 05/20/2008 05/20/2008 05/19/2008 05/192008 RI:DRP/E C:DRP/D JEJosey MLHay /RA/ /RA/ 05/20/2008 05/19/2008

OFFICIAL RECORD COPY                                   T=Telephone         E=E-mail    F=Fax
 and maintenance personnel failed to incorporate the adequate level of detail into
 their troubleshooting plans for the Unit 3 auxiliary feedwater trip and throttle
 Valve AFA-HV-0054 when it failed to fully close upon demand from the control
 room hand switch, and for the Unit 3 log power Channel A when induced noise
 was present. These issues were entered into the licensee's corrective action
 program as Palo Verde Action Requests 3120075 and 3118744.
 This finding is greater than minor because it is associated with the equipment
 performance attribute of the mitigating systems cornerstone and affects the
 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
 because it did not represent a loss of system safety function, an actual loss of
 safety function of a single train for greater than its technical specification allowed
 outage time, or screen as potentially risk-significant due to a seismic, flooding, or
 severe weather initiating event. Both examples have a crosscutting aspect in the
 area of human performance associated with decision-making because the
 licensee did not obtain appropriate interdisciplinary input and reviews on
 safety-significant or risk-significant decisions [H.1(a)]. (Section 1R19)
  • Green. The inspectors identified a noncited violation of Technical
 Specification 5.2.2.d involving the routine use of excessive overtime for
 operations personnel that performed safety-related functions. Specifically,
 between January 1 and December 31, 2007, operations personnel routinely used
 excessive overtime. This issue was entered into the licensees corrective action
 program as Condition Report/Disposition Request 3112231.
 The finding is greater than minor because if left uncorrected the finding would
 become a more significant safety concern in that the routine use of excessive
 work hours increases the likelihood of operator errors. Using the Manual
 Chapter 0609, "Significance Determination Process," Appendix M, the finding is
 determined to have very low safety significance because there were no recent
 instances where findings of low to moderate (White) or greater significance were
 attributed to the increased use of overtime by operating personnel. The finding
 has a crosscutting aspect in the area of human performance associated with
 resources because the licensee failed to maintain sufficient qualified operations
 personnel to maintain working hours within guidelines without the excessive use
 of overtime [H.2(b)] (Section 4OA2).
  • Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure
 of engineering personnel to ensure that potentially nonconforming conditions
 associated with the Class 1E 125 Vdc system were reviewed for operability.
 Specifically, between September 29, 2007 and March 7, 2008, engineering
 personnel failed to ensure all relevant information was reviewed for operability
 when it was determined that vendor recommended preventative maintenance
 tasks were not being performed on the Class 1E 125 Vdc system. This issue
 was entered into the licensee's corrective action program as Palo Verde Action
 Request 3144707.
                               -4-                                       Enclosure

Arizona Public Service Company - 30 -

                               2003         2004        2005          2006          2007
        Control                7.32          8.92      10.53         14.13         20.87
        Room
        Supervisor
        Reactor               10.43        13.84       16.25         20.96         27.65
        Operator
        Shift                  8.81        10.29       12.12         17.51         20.28
        Manager
      Since 2003, overtime, as a percent of regular hours worked, has increased steadily and
      substantively for control room operators. The inspectors 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. The inspectors also noted that the 2007 overtime rates were more
      than double the overtime rates of 2003.
      During their review the inspectors noted that Technical Specification 5.2.2.d,
      Organization - Unit Staff, requires that administrative procedures shall be developed
      and implemented to limit the working hours of unit staff that perform safety-related
      functions, as well as requiring that the controls shall include guidelines on working hours
      that ensure adequate shift coverage shall be maintained without routine heavy use of
      overtime. Station procedure 01DP-9EM01, Overtime Limitations, Revision 6, is the
      licensees administrative procedure used to control unit staff working hours in
      accordance with facility Technical Specifications. Section 2.1 of this procedure requires
      that department leaders ensure that adequate shift coverage is maintained without the
      routine heavy use of overtime. The objective is to have personnel work a nominal
      40-hour week while the plant is operating.
      The inspectors determined that the licensee had several missed opportunities to identify
      this issue. Specifically, during their review the inspectors noted that the licensee had not
      been issuing and reviewing Technical Specification required excess overtime reports
      from approximately June 2006 through July 2007. The purpose of these reports was to
      facilitate identification of excess overtime usage by site management. However, due to
      changing computer software the reports were not generated and reviewed. Also, the
      inspector noted that several CRDRs written that identified the metric window for
      operations overtime were red for most of 2007. The inspectors determined that these
      were indicators of the use of excessive overtime and these indicators were missed by
      the licensee.
      Analysis. The performance deficiency associated with this finding involved
      excessive routine use of heavy amounts of overtime for operations personnel
      that perform safety-related functions. The finding is greater than minor because
      if left uncorrected the finding would become a more significant safety concern in
      that the routine use of excessive work hours increases the likelihood of operator
      errors. Using the Manual Chapter 0609, "Significance Determination Process,"
      Appendix M, the finding is determined to have very low safety significance
      because there were no recent instances where findings of low to moderate
      (White) or greater significance were attributed to the increased use of overtime
      by operating personnel. The finding has a crosscutting aspect in the area of
      human performance associated with resources because the licensee failed to
       maintain sufficient qualified operations personnel to maintain working hours
      within guidelines without heavy use of overtime [H.2(b)].
                                                UNITE D S TATES
                              NUC LEAR RE GULATOR Y C OMMIS SI ON
                                                  R EG IO N I V
                                     6 12 EAST LAMAR BLVD , SU ITE 4 00
                                      AR L I N GTON , TEXAS 7 601 1- 4125
                                                 May 9, 2008

Randall K. Edington, Executive Vice President, Nuclear

  and Chief Nuclear Officer

Mail Station 7602 Arizona Public Service Company P.O. Box 52034 Phoenix, AZ 85072-2034 SUBJECT: PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED

               INSPECTION REPORT 05000528/2008002, 05000529/2008002, AND
               05000530/2008002

Dear Mr. Edington: On March 31, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility. The enclosed integrated report documents the inspection findings, which were discussed on April 16, 2008, with you and other members of your staff. The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. This report documents five NRC identified findings and two self-revealing findings. These findings were evaluated under the risk significance determination process as having very low safety significance (Green). 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 non-cited violations consistent with Section VI.A.1 of the NRC Enforcement Policy. Two licensee-identified violations, which were determined to be of very low safety significance, are listed in Section 4OA7 of this report. If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for 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 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.

Arizona Public Service Company -2- In accordance with 10 CFR 2.390 of the NRCs "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 NRCs document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

                                            Sincerely,
                                            /RA/
                                            Michael C. Hay, Chief
                                            Projects, Branch D
                                            Division of Reactor Projects

Docket Nos. 50-528

              50-529
              50-530

License Nos. NPF-41

              NPF-51
              NPF-74

Enclosure: NRC Inspection Report 05000528/2008002, 05000529/2008002, and 05000530/2008002

 w/Attachment: Supplemental Information

cc w/enclosure:Steve Olea Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 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

Arizona Public Service Company -3- 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 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

Arizona Public Service Company -4- 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 Chairperson, Radiological Assistance Committee Region IX Federal Emergency Management Agency Department of Homeland Security 1111 Broadway, Suite 1200 Oakland, CA 94607-4052

Arizona Public Service Company             -5-
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)
Only inspection reports to the following:
DRS STA (Dale.Powers@nrc.gov)
J. Adams, OEDO RIV Coordinator (John.Adams@nrc.gov)
P. Lougheed, OEDO RIV Coordinator (Patricia.Lougheed@nrc.gov)
ROPreports
PV Site Secretary (Patricia.Coleman@nrc.gov)
SUNSI Review Completed:__GEW__ADAMS: ;Yes                 No        Initials: __GEW__
;Publicly Available  Non-Publicly Available       Sensitive   ;Non-Sensitive
R:\_REACTORS\_PV\2008\PV2008-002RP-GGW.doc                              ML )81300387

RIV:RI:DRP/D RI:DRP/D RI:DRP/D SRI:DRP/D SRI:DRP/D SPE:DRP/D JBashore MCatts JFMelfi GGWarnick RTreadway GEWerner /RA/ MHay for /RA/ MHay for /RA/ E-mailed /RA/ /RA/ MCHay for /RA/ 05/8/2008 05/8/2008 05/9/2008 05/8/2008 05/8/2008 05/5/2008 C:DRS/PSB C:DRS/EB2 C:DRS/EB C:DRS/OB C:DRP/D MPShannon LJSmith RLBywater RELantz MHay /RA/ /RA/ DProulx for /RA/ /RA/ MRunyan for /RA/ 05/2/2008 05/2/2008 05/2/2008 05/2/2008 05/8/2008

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: 05000528/2008002, 05000529/2008002, 05000530/2008002 Licensee: Arizona Public Service Company Facility: Palo Verde Nuclear Generating Station, Units 1, 2, and 3 Location: 5951 S. Wintersburg Road

            Tonopah, Arizona

Dates: January 1 through March 31, 2008 Inspectors: J. Bashore, Resident Inspector

            M. Catts, Resident Inspector
            L. Carson II, Senior Health Physics Inspector
            P. Elkmann, Emergency Preparedness Inspector
            J. Melfi, Resident Inspector
            R. Treadway, Senior Resident Inspector
            G. Warnick, Senior Resident Inspector
            G. Werner, Senior Project Engineer

Approved By: Michael C. Hay, Chief, Project Branch D

            Division of Reactor Projects
                                       -1-                           Enclosure
                                                  CONTENTS

SUMMARY OF FINDINGS ...................................................................................................... - 3 - REPORT DETAILS .................................................................................................................. - 7 - REACTOR SAFETY ................................................................................................................ - 7 -

 1R04    Equipment Alignment............................................................................................. - 7 -
 1R05    Fire Protection........................................................................................................ - 8 -
 1R11    Licensed Operator Requalification Program .......................................................... - 8 -
 1R12    Maintenance Effectiveness .................................................................................... - 9 -
 1R13    Maintenance Risk Assessments and Emergent Work Control .............................. - 9 -
 1R15    Operability Evaluations ........................................................................................ - 11 -
 1R18    Plant Modifications............................................................................................... - 13 -
 1R19    Post-Maintenance Testing ................................................................................... - 14 -
 1R20    Refueling and Other Outage Activities ................................................................. - 17 -
 1R22    Surveillance Testing............................................................................................. - 18 -
 1EP2    Alert Notification System Testing ......................................................................... - 19 -
 1EP3    Emergency Response Organization Augmentation Testing ................................ - 19 -
 1EP4    Emergency Action Level and Emergency Plan Changes .................................... - 19 -
 1EP5    Correction of Emergency Preparedness Weaknesses and Deficiencies ............. - 20 -
 1EP6    Drill Evaluation ..................................................................................................... - 21 -

RADIATION SAFETY ............................................................................................................ - 21 -

 2OS1 Access Control to Radiologically Significant Areas.............................................. - 21 -
 2OS2 As Low As Is Reasonably Achievable (ALARA) Planning And Controls.............. - 22 -

OTHER ACTIVITIES.............................................................................................................. - 23 -

 4OA1 Performance Indicator Verification....................................................................... - 23 -
 4OA2 Identification and Resolution of Problems............................................................ - 25 -
 4OA3 Followup of Events and Notices of Enforcement Discretion ................................ - 39 -
 4OA5 Other Activities..................................................................................................... - 44 -
 4OA6 Meetings, Including Exit ....................................................................................... - 44 -
 4OA7 Licensee-Identified Violations .............................................................................. - 45 -

SUPPLEMENTAL INFORMATION ...............................................................................................1 KEY POINTS OF CONTACT ........................................................................................................1 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED ............................................................2 LIST OF DOCUMENTS REVIEWED ............................................................................................3 LIST OF ACRONYMS USED................................................................................................. - 30 -

                                                   -2-                                                       Enclosure
                                    SUMMARY OF FINDINGS

IR 05000528/2008002, 05000529/2008002, 05000530/2008002; 01/01/08 - 03/31/08; Palo Verde Nuclear Generating Station, Units 1, 2, and 3; Integrated Resident and Regional Report; Maintenance Risk Assessments and Emergent Work Control, Operability Evaluations, Post- Maintenance Testing, Identification and Resolution of Problems, Follow-Up of Events. This report covered a 3-month period of inspection by resident inspectors and regional inspectors. The inspection identified nine findings. 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 NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006. A. NRC-Identified and Self-Revealing Findings

       Cornerstone: Mitigating Systems
       *      Green. The inspectors identified a non-cited violation of Technical
              Specification 5.4.1.a for the failure of operations and engineering personnel to
              establish and implement maintenance procedures for inspection and
              replacement of items that have a specific lifetime. Specifically, between
              February 12, 2007 and March 7, 2008, operations and engineering personnel
              failed to inspect or replace the emergency diesel generators fuel oil injection
              pump upper O-rings prior to the end of their service life resulting in fuel leakage
              and increased unavailability and unreliability of Unit 1 Train A, Unit 2 Train B, and
              Unit 3 Train B emergency diesel generators. This issue was entered into the
              licensee's corrective action program as Palo Verde Action Request 3143422.
              This finding is greater than minor because it is associated with the equipment
              performance attribute of the mitigating systems cornerstone 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
              because it did not represent a loss of system safety function, an actual loss of
              safety function of a single train for greater than its technical specification allowed
              outage time, or screen as potentially risk-significant due to a seismic, flooding, or
              severe weather initiating event. This finding has a crosscutting aspect in the
              area of problem identification and resolution associated with operating
              experience because the licensee failed to use available operating experience,
              including vendor recommendations, to implement and institutionalize operating
              experience through changes to station processes, procedures, equipment, and
              training programs [P.2(b)]. (Section 1R15)
       *      Green. The inspectors identified two examples of a non-cited violation of 10 CFR
              Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," for
              the failure of operations, engineering, and maintenance personnel to follow
              procedures for troubleshooting failures of safety-related components.
                                            -3-                                    Enclosure
 Specifically, between January 8 and January 13, 2008, operations, engineering,
 and maintenance personnel failed to incorporate the adequate level of detail into
 their troubleshooting plans for the Unit 3 auxiliary feedwater trip and throttle
 Valve AFA-HV-0054 when it failed to fully close upon demand from the control
 room hand switch, and for the Unit 3 log power Channel A when induced noise
 was present. These issues were entered into the licensee's corrective action
 program as Palo Verde Action Requests 3120075 and 3118744.
 This finding is greater than minor because it is associated with the equipment
 performance attribute of the mitigating systems cornerstone and affects the
 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
 because it did not represent a loss of system safety function, an actual loss of
 safety function of a single train for greater than its technical specification allowed
 outage time, or screen as potentially risk-significant due to a seismic, flooding, or
 severe weather initiating event. Both examples have a crosscutting aspect in the
 area of human performance associated with decision-making because the
 licensee did not obtain appropriate interdisciplinary input and reviews on
 safety-significant or risk-significant decisions [H.1(a)]. (Section 1R19)
  • Green. The inspectors identified a non-cited violation of Technical
 Specification 5.2.2.d involving the routine use of excessive overtime for
 operations personnel that performed safety-related functions. Specifically,
 between January 1 and December 31, 2007, operations personnel routinely used
 excessive overtime. This issue was entered into the licensees corrective action
 program as Condition Report/Disposition Request 3112231.
 The finding is greater than minor because if left uncorrected the finding would
 become a more significant safety concern in that the routine use of excessive
 work hours increases the likelihood of operator errors. Using the IMC 0609,
 "Significance Determination Process," Phase 1 Worksheets, the finding is
 determined to have very low safety significance because no specific human
 performance issues due to personnel fatigue were identified that resulted in the
 degradation or loss of safety function of equipment important to safety. The
 finding has a crosscutting aspect in the area of human performance associated
 with resources because the licensee failed to maintain sufficient qualified
 operations personnel to maintain working hours within guidelines without the
 excessive use of overtime [H.2(b)]. (Section 4OA2)
  • Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure
 of engineering personnel to ensure that potentially nonconforming conditions
 associated with the Class 1E 125 Vdc system were reviewed for operability.
 Specifically, between September 29, 2007 and March 7, 2008, engineering
 personnel failed to ensure all relevant information was reviewed for operability
 when it was determined that vendor recommended preventative maintenance
 tasks were not being performed on the Class 1E 125 Vdc system. This issue
 was entered into the licensee's corrective action program as Palo Verde Action
 Request 3144707.
                               -4-                                    Enclosure
     This finding is greater than minor because it is associated with the equipment
     performance attribute of the mitigating systems cornerstone and affects the
     cornerstone objective to ensure 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
     because it did not represent a loss of system safety function, an actual loss of
     safety function of a single train for greater than its technical specification allowed
     outage time, or screen as potentially risk-significant due to a seismic, flooding, or
     severe weather initiating event. This finding has a crosscutting aspect in the
     area of human performance associated with decision-making because
     safety-significant decisions were not verified to validate underlying assumptions
     and identify unintended consequences [H.1(b)]. (Section 4OA2)
  • Green. A self-revealing non-cited violation of Technical Specification 3.7.3.c was
     identified for the failure of operations personnel to perform the actions required
     for an inoperable main feedwater isolation valve. Specifically, on July 17, 2006,
     operations personnel failed to perform actions to place the unit in Mode 3 within
     6 hours and Mode 5 within 36 hours, as required by Technical
     Specification 3.7.3.c, for an inoperable main feedwater isolation valve that had
     not been closed or isolated in 72 hours, as required by Technical
     Specification 3.7.3.a. This resulted in main feedwater isolation
     Valve 2JSGAUV0174 to steam Generator A exceeding the Technical
     Specification 3.7.3 allowed outage time. This issue was entered into the
     licensee's corrective action program as Condition Report/Disposition
     Request 2915450.
     This finding is greater than minor because it is associated with the equipment
     performance attribute of the mitigating systems cornerstone and affects the
     cornerstone objective to ensure the availability and reliability of systems that
     respond to initiating events to prevent undesirable consequences. A Phase 2
     analysis was required because the Manual Chapter 0609, "Significance
     Determination Process," Phase 1 Worksheets, determined that there was a loss
     of main feedwater isolation of a single train to steam Generator A for greater than
     the technical specification allowed outage time. Using the Phase 2 Worksheets
     associated with a steam generator tube rupture without steam generator
     isolation, the finding is determined to have very low safety significance since all
     remaining mitigation capability was available or recoverable. (Section 4OA3)

Cornerstone: Barrier Integrity

  • Green. The inspectors identified a non-cited violation of 10 CFR Part 50,
     Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure
     of fuels services personnel to evaluate leaving foreign material in the Unit 2 spent
     fuel pool in accordance with procedures, and failed to ensure those procedures
     included appropriate quantitative and qualitative acceptance criteria. Specifically,
     between October 13, 2006, and January 31, 2008, fuels services personnel used
     Procedure 30DP-9MP03, "System Cleanliness and Foreign Material Exclusion
     Controls," Revision 6, which did not specify acceptance criteria for time to
     perform a functional assessment of foreign material in the spent fuel pool,
     resulting in foreign material being left in the spent fuel pool for greater than one
     year without an evaluation on affected safety systems. This issue was entered
                                    -5-                                   Enclosure
          into the licensee's corrective action program as Palo Verde Action
          Request 3126308.
          This finding is greater than minor because it is associated with the structure,
          systems, and component performance and human performance attributes of the
          barrier integrity cornerstone and affects the cornerstone objective to provide
          reasonable assurance that physical design barriers (fuel cladding, reactor coolant
          system, and containment) protect the public from radionuclide releases caused
          by accidents or events. Using the Manual Chapter 0609, "Significance
          Determination Process," Phase 1 Worksheets, the finding is determined to have
          very low safety significance because the finding did not result in loss of cooling to
          the spent fuel pool; the finding did not result from fuel handling errors that caused
          damage to the fuel clad integrity or a dropped assembly; and the finding did not
          result in a loss of spent fuel pool inventory greater than ten percent of the spent
          fuel pool volume. This finding has a crosscutting aspect in the area of human
          performance associated with decision-making because the licensee failed to use
          conservative assumptions when evaluating degraded and nonconforming
          conditions [H.1.(b)]. (Section 4OA2)
  *       Green. A self-revealing non-cited violation of Technical Specification 5.4.1.a was
          identified for the failure of operations personnel to follow procedures.
          Specifically, on January 13, 2008, operations personnel failed to properly
          implement Procedure 40OP-9PC06, "Fuel Pool Cleanup and Transfer,"
          Revision 41, for operating the pool cooling cleanup system, resulting in pool
          cooling cleanup Filter PCN-F01B bypass Valve PCN-V061 being improperly
          aligned. This resulted in the inadvertent transfer of 300 gallons of spent fuel pool
          water to the refueling water tank. This issue was entered into the licensee's
          corrective action program as Condition Report/Disposition Request 3121713.
          The finding is greater than minor because it is associated with the configuration
          control and human performance attributes of the barrier integrity cornerstone and
          affects the cornerstone objective to provide reasonable assurance that physical
          design barriers (fuel cladding, reactor coolant system, and containment) protect
          the public from radionuclide releases caused by accidents or events. Using the
          Manual Chapter 0609, "Significance Determination Process," Phase 1
          Worksheets, the finding is determined to have very low safety significance
          because the finding did not result in loss of cooling to the spent fuel pool; the
          finding did not result from fuel handling errors that caused damage to the fuel
          clad integrity or a dropped assembly; and the finding did not result in a loss of
          spent fuel pool inventory greater than ten percent of the spent fuel pool volume.
          This finding has a crosscutting aspect in the area of human performance
          associated with work practices because the licensee failed to use adequate
          human error prevention techniques, such as pre-job briefings, to ensure that the
          pool cooling cleanup system activity was performed safely [H.4(a)].
          (Section 4OA3)

B. Licensee-Identified Violations

  Violations of very low safety significance that were identified by the licensee have been
  reviewed by the inspectors. Corrective actions taken or planned by the licensee have
  been entered into the licensee's corrective action program. These violations and
  corrective action tracking numbers are listed in Section 4OA7 of this report.
                                         -6-                                  Enclosure
                                       REPORT DETAILS

Summary of Plant Status Unit 1 operated at essentially full power for the entire inspection period. Unit 2 operated at essentially full power for the entire inspection period. Unit 3 began the inspection period shutdown for refueling Outage 3R13. The unit was restarted on January 15, 2008, returned to full power on January 24, 2008, and remained there for duration of the inspection period. 1. REACTOR SAFETY

       Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment (71111.04)

  a.   Inspection Scope
       Partial Walkdown
       The inspectors: (1) walked down portions of the three below listed risk important
       systems and reviewed plant procedures and documents to verify that critical portions of
       the selected systems were correctly aligned; and (2) compared deficiencies identified
       during the walk down to the licensee's Updated Final Safety Analysis Report (UFSAR)
       and corrective action program (CAP) to ensure problems were being identified and
       corrected.
       *       January 17, 2008, Unit 3, emergency diesel generator (EDG) Train B
       *       February 20, 2008, Unit 2, essential chilled water, essential spray pond water,
               and high pressure safety injection Train A while Train B was out of service
       *       March 14, 2008, Unit 1, 13.8 kV and 4.16 kV non-class 1E alternating current
               power system Train B
       Documents reviewed by the inspectors are listed in the attachment.
       The inspectors completed three samples.
  b.   Findings
       No findings of significance were identified.
                                            -7-                                  Enclosure

1R05 Fire Protection (71111.05)

 a. Inspection Scope
    Quarterly Inspection
    The inspectors walked down the four below listed plant areas to assess the material
    condition of active and passive fire protection features and their operational lineup and
    readiness. The inspectors: (1) verified that transient combustibles and hot work
    activities were controlled in accordance with plant procedures; (2) observed the
    condition of fire detection devices to verify they remained functional; (3) observed fire
    suppression systems to verify they remained functional and that access to manual
    actuators was unobstructed; (4) verified that fire extinguishers and hose stations were
    provided at their designated locations and that they were in a satisfactory condition;
    (5) verified that passive fire protection features (electrical raceway barriers, fire doors,
    fire dampers, steel fire proofing, penetration seals, and oil collection systems) were in a
    satisfactory material condition; (6) verified that adequate compensatory measures were
    established for degraded or inoperable fire protection features and that the
    compensatory measures were commensurate with the significance of the deficiency; and
    (7) verified the licensee identified and corrected fire protection problems.
    *        January 29, 2008, Unit 1, condensate storage pump house and tunnel
    *        January 29, 2008, Unit 1, spray pond pump house
    *        February 11, 2008, Unit 3, diesel generator building, 100 foot, 115 foot, and
             131 foot elevations
    *        February 25, 2008, Unit 2, condensate storage pump house and tunnel
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed four samples.
 b. Findings
    No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)

 a. Inspection Scope
    Quarterly Inspection
    On February 26, 2008, the inspectors observed testing and training of senior reactor
    operators (SROs) and reactor operators (ROs) to identify deficiencies and discrepancies
    in the training, to assess operator performance, and to assess the evaluator's critique.
    The training Scenario SES-0-07-E--02, "Loss of PKC-M43/Loss of Offsite Power,"
    involved four events including: (1) failure of condensate storage tank level instrument;
    (2) failure of a steam flow transmitter; (3) loss of Class 1E 125 volts direct current
    Bus (PK) C; and (4) loss of offsite power.
                                           -8-                                  Enclosure
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed one sample.
 b. Findings
    No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

 a. Inspection Scope
    The inspectors reviewed the two below listed maintenance activities to: (1) verify the
    appropriate handling of structure, system, and component (SSC) performance or
    condition problems; (2) verify the appropriate handling of degraded SSCs functional
    performance; (3) evaluate the role of work practices and common cause problems; and
    (4) evaluate the handling of SSC issues reviewed under the requirements of the
    Maintenance Rule, 10 CFR Part 50, Appendix B, and the Technical Specifications (TSs).
    *        January 25, 2008, Units 1, 2, and 3, EDG fuel oil injection pump leakage that
             impacted EDG operability as described in Condition Report/Disposition Request
             (CRDR) 2950136 and Palo Verde Action Requests (PVARs) 3092611, 3125050,
             and 3125979
    *        February 5, 2008, Unit 3, failure of control element Assembly 26 causing cross
             channel comparison failures and control element assembly Calculator 1
             deviations
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed two samples.
 b. Findings
    No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

 a. Inspection Scope
    Risk Assessment and Management of Risk
    The inspectors reviewed the two below listed assessment activities to verify:
    (1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and licensee
    procedures prior to changes in plant configuration for maintenance activities and plant
    operations; (2) the accuracy, adequacy, and completeness of the information considered
    in the risk assessment; (3) that the licensee recognizes, and/or enters as applicable, the
    appropriate licensee-established risk category according to the risk assessment results
    and licensee procedures; and (4) the licensee identified and corrected problems related
    to maintenance risk assessments.
                                         -9-                                 Enclosure
  *       January 9, 2008, Unit 2, risk assessment and management during scheduled
          implementation of design modification to lower average reactor coolant system
          (RCS) temperature by one degree Fahrenheit
  *       February 17 through March 3, 2008, Units 1, 2 and 3, risk assessment and
          management during re-performance of remote shutdown disconnect switch
          surveillance tests
  Documents reviewed by the inspectors are listed in the attachment.
  The inspectors completed two samples.

b. Findings

  No findings of significance were identified.

a. Inspection Scope

  Emergent Work Control
  The inspectors: (1) verified that the licensee performed actions to minimize the
  probability of initiating events and maintained the functional capability of mitigating
  systems and barrier integrity systems; (2) verified that emergent work-related activities
  such as troubleshooting, work planning/scheduling, establishing plant conditions,
  aligning equipment, tagging, temporary modifications, and equipment restoration did not
  place the plant in an unacceptable configuration; and (3) verified the licensee identified
  and corrected risk assessment and emergent work control problems. The following
  three activities were reviewed:
  *       January 8, 2008, Unit 3, troubleshooting and repair of nuclear instrument log
          Channel A induced noise while EDG Train A was in service
  *       January 10-17, 2008, Unit 3, auxiliary feedwater (AFW) Train A, trip and throttle
          Valve AFA-HV-54, troubleshooting and repair
  *       March 3, 2008, Unit 1, AFW actuating system for steam Generator (SG) A,
          Train B, troubleshooting and repair
  Documents reviewed by the inspectors are listed in the attachment.
  The inspectors completed three samples.

b. Findings

  No findings of significance were identified.
                                       - 10 -                                Enclosure

1R15 Operability Evaluations (71111.15)

 a. Inspection Scope
    The inspectors: (1) reviewed plant status documents such as operator shift logs,
    emergent work documentation, deferred modifications, and night orders to determine if
    an operability evaluation was warranted for degraded components; (2) referred to the
    UFSAR and design basis documents to review the technical adequacy of licensee
    operability evaluations; (3) evaluated compensatory measures associated with
    operability evaluations; (4) determined degraded component impact on any TSs; (5)
    used the Significance Determination Process, to evaluate the risk significance of
    degraded or inoperable equipment; and (6) verified that the licensee has identified and
    implemented appropriate corrective actions associated with degraded components. The
    following six activities were reviewed:
    *        January 1-15, 2008, Unit 3, evaluation of dissolved desiccant in the reactor
             coolant system (RCS) during heatup
    *        January 10, 2008, Unit 3, AFW pump Train A operability following
             troubleshooting efforts on AFW trip and throttle Valve AFA-HV-0054
    *        January 10, 2008, evaluation of Unit 3, shutdown cooling heat exchanger Train B
             performance degradation
    *        January 25, 2008, Units 1, 2, and 3, operability assessment associated with
             leakage from the EDGs fuel oil injection pumps
    *        February 17-March 3, 2008, Units 1, 2 and 3, operability evaluation of remote
             shutdown disconnect switches
    *        March 24 - 26, 2008, Units 1 and 2, EDG Train A operability for non optimal field
             configuration of overspeed trip air line pressure switch isolation valves
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed six samples.
 b. Findings
    Introduction. The inspectors identified a Green non-cited violation (NCV) of TS 5.4.1.a
    for the failure of operations and engineering personnel to adequately establish and
    implement maintenance procedures for inspection and replacement of items that have a
    specific lifetime.
    Description. Fuel oil leakage from the EDG fuel oil injection pump upper O-rings was
    first identified on December 12, 2006, when Unit 1 Train A EDG fuel oil injection
    Pump 5L developed a leak from the upper O-ring and was declared inoperable as
    documented in CRDR 2950136. On February 12, 2007, the fuel oil injection pump
    vendor, Haynes, completed a report and determined the Unit 1 Train A EDG fuel oil
    injection pump leakage was due to the pumps O-ring, made from Buna-N material,
    having approached the end of its useful life, as documented in 8000865-FA, "Failure
    Analysis of Fuel Injection Pump." Also, the licensee performed an apparent cause
                                         - 11 -                                 Enclosure

evaluation on February 20, 2007, as documented in CRDR 2950136 and determined the leakage was due to material aging of the Buna-N rubber. It was determined the shelf life of the Buna-N O-rings was 13 to 15 years and Unit 1 Trains A and B EDGs had pumps with O-rings that were approximately 15 years old. The evaluation also determined the contributing cause was that no preventative maintenance (PM) task existed to inspect and replace the O-rings even though the O-rings have a finite life time. On February 28, 2007, the licensee wrote condition report action item (CRAI) 2976063 to evaluate the Haynes report for eight pumps sent off-site for rework, including the degraded Unit 1 Train A EDG fuel oil injection Pump 5L. The due date for CRAI 2976063 was extended from December 21, 2007, to March 31, 2008, without putting a PM plan or schedule in place for the aging O-rings. Three more leaks occurred on fuel oil injection pumps upper O-rings. On November 13, 2007, Unit 1 Train A EDG fuel oil injection Pump 9L developed a leak of approximately 300 drops per minute (dpm) and was declared inoperable as documented in PVAR 3092611. After this leak, CRAI 3095506 was written on November 16, 2007, to implement replacement of the Buna-N O-rings for all EDGs onsite. However, the inspectors noted that the licensee did not initiate this action and determined the strategy was to replace the fuel oil injection pumps as they leaked. On January 23, 2008, approximately a 61 dpm leak was identified on Unit 2 Train B EDG fuel oil injection Pump 3R and the EDG was declared inoperable. On January 25, 2008, Unit 3 Train B EDG fuel oil injection Pump 5L developed a leak of approximately 200 dpm and the EDG was declared inoperable. The inspectors questioned the licensee on the operability of all EDGs onsite due to the increased fuel oil injection pump leakage and the age of the Buna-N O-rings. On January 25, 2008, the licensee performed an immediate operability determination on the reliability of all EDGs to perform their seven day mission time with the O-ring leakage, as documented in PVAR 3126297. Operations personnel reiterated that the service life of the fuel oil injection pump upper O-rings is 13 to 15 years and that the O-rings on all three units fuel oil injection pumps were reaching, or had reached, the end of their service life resulting in leakage from the O-rings. On January 28, 2008, the licensee completed a more in-depth evaluation in a prompt operability determination, documented in PVAR 3125979. The licensee determined a reasonable expectation of operability of the EDGs based on; 1) the leakage was low pressure; 2) multiple O-ring failures were unlikely to occur on a single EDG during any single EDG start and run; 3) complete failures of the O-rings would not occur; and, 4) the leak rate would not increase over time as determined in Haynes Vendor Report 8001090-Test, dated February 13, 2008. Following the review of the multiple fuel oil injection pump leakage issues, the inspectors noted that a maintenance procedure and had not been implemented for the inspection and replacement of the fuel oil injection pump upper O-rings that had exceeded their service life. On March 7, 2008, the inspectors shared their observations with the licensee who subsequently wrote PVAR 3143422 to develop and implement this PM procedure and schedule. Analysis. The performance deficiency associated with this finding involved the failure of operations and engineering personnel to adequately establish and implement maintenance procedures for inspection and replacement of items that have a specific lifetime; specifically, the EDG fuel oil injection pump upper O-rings. This finding is greater than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affects the cornerstone objective of ensuring the

                                    - 12 -                               Enclosure
    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 because it did not represent a loss of system safety function, an
    actual loss of safety function of a single train for greater than its TS allowed outage time,
    or screen as potentially risk-significant due to a seismic, flooding, or severe weather
    initiating event. This finding has a crosscutting aspect in the area of problem
    identification and resolution associated with operating experience because the licensee
    failed to use available operating experience, including vendor recommendations, to
    implement and institutionalize operating experience through changes to station
    processes, procedures, equipment, and training programs [P.2(b)].
    Enforcement. Technical Specification 5.4.1.a requires that written procedures be
    established, implemented, and maintained covering the activities specified in Regulatory
    Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33
    Appendix A, Section 9, "Procedures for Performing Maintenance," Sub-Section "b",
    requires that preventative maintenance procedures and schedules be developed to
    include inspections of equipment and replacement of items that have a specific lifetime.
    Contrary to this, between February 12, 2007 and March 7, 2008, operations and
    engineering personnel failed to establish and implement a PM procedure and schedule
    to inspect and replace the EDG fuel oil injection pump upper O-rings resulting in fuel
    leakage and increased unavailability and unreliability of Unit 1 Train A EDG, Unit 2
    Train B EDG, and Unit 3 Train B EDG. Because this finding is of very low safety
    significance and has been entered into the licensee's CAP as PVAR 3143422, this
    violation is being treated as an NCV consistent with Section VI.A.1 of the NRC
    Enforcement Policy: NCV 05000528; 05000529; 05000530/2008002-01, "Failure to
    Establish Preventative Maintenance Procedures for Emergency Diesel Generator Fuel
    Oil Injection Pump O-rings."

1R18 Plant Modifications (71111.18)

 a. Inspection Scope
    Temporary Modifications
    On March 24, 2008, the inspectors reviewed a temporary modification for Unit 2 to install
    an accelerometer on Train A shutdown cooling suction Valve 2JSIAUV0651 from reactor
    coolant Loop 1A. The inspectors reviewed the UFSAR, plant drawings, procedure
    requirements, operator logs, and TSs to ensure that the temporary modification was
    properly implemented. The inspectors verified that: (1) the modification did not have an
    effect on system operability/availability; (2) the installation was consistent with
    modification documents; (3) the post-installation test results were satisfactory and that
    the impact of the temporary modification on permanently installed SSCs were supported
    by the test; (4) the modification was identified on control room drawings and that
    appropriate identification tags were placed on the affected drawings; (5) the licensee
    evaluated the combined effects of temporary modifications; and (6) there were no
    temporary modifications installed that have not been evaluated. The inspectors verified
    that the licensee identified and implemented any needed corrective actions associated
    with temporary modifications.
                                          - 13 -                                 Enclosure
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed one sample.
 b. Findings
    No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

 a. Inspection Scope
    The inspectors selected the five below listed post-maintenance test activities of
    risk-significant systems or components. For each item, the inspectors: (1) reviewed the
    applicable licensing basis and/or design-basis documents to determine the safety
    functions; (2) evaluated the safety functions that may have been affected by the
    maintenance activity; and (3) reviewed the test procedure to ensure it adequately tested
    the safety function that may have been affected. The inspectors either witnessed or
    reviewed test data to verify that acceptance criteria were met, plant impacts were
    evaluated, test equipment was calibrated, procedures were followed, jumpers were
    properly controlled, the test data results were complete and accurate, the test equipment
    was removed, the system was properly re-aligned, and deficiencies during testing were
    documented. The inspectors also verified the licensee identified and corrected problems
    related to post-maintenance testing.
    *       January 10-17, 2008, Unit 3, AFW Train A, trip and throttle Valve AFA-HV-0054
            following troubleshooting and repair when the valve failed to close upon demand
            from the control room hand switch
    *       February 7, 2008, Unit 3, EDG Train A, following replacement of six fuel oil
            injection pumps
    *       February 28, 2008, Unit 2, low pressure safety injection Train B, following
            planned maintenance activities to lubricate, clean, and inspect motor operated
            valves and change oil in upper and lower motor bearings
    *       March 21, 2008, Unit 3, EDG Train B, following troubleshooting and repair of a
            packing leak on Valve 3PDGBV652
    *       March 21, 2008, Unit 3, EDG Train B, following replacement of the fuel oil
            injection Pump 7L
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed five samples.
                                         - 14 -                              Enclosure

b. Findings

  Introduction. The inspectors identified two examples of a Green NCV of 10 CFR
  Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," for the failure
  of operations, engineering, and maintenance personnel to follow procedures for
  troubleshooting degraded safety-related components.
  Description. The first example occurred on January 9, 2008, when the Unit 3 AFW
  system, Train A, was started to support retest activities. Following the run, operations
  personnel attempted to close trip and throttle Valve AFA-HV-0054 via the hand switch
  from the control room. Valve AFA-HV-0054 is the trip and throttle valve that provides
  overspeed protection for steam driven AFW Pump AFA-P01. The valve stroked partially
  closed and then stopped in mid position. Operations personnel reopened the valve and
  contacted outage maintenance and engineering personnel. At the time of the failure, the
  AFW system Train A was already considered inoperable during the retest activities on
  Valve AFA-HV-0054. Unit 3 was in Mode 3 at normal operating temperature and
  pressure.
  The valve failure was entered into the CAP on January 9, 2008, as PVAR 3118968. On
  January 9, 2008, a Level C troubleshooting plan was developed by valve services
  engineering. Work Order (WO) 3118969 was generated to implement the
  troubleshooting plan. The WO and troubleshooting plan were reviewed by the on duty
  shift manager (SM) and troubleshooting activities were authorized to begin. The
  inspectors noted the troubleshooting plan narrowly focused on the torque switch
  contacts in the Limitorque valve actuator, while other potential failure mechanisms were
  not addressed. On January 9, 2008, maintenance personnel determined that the
  resistance across the torque switch contacts was satisfactory, although a small fiber
  near the contact device was found. When the fiber was found, troubleshooting was
  stopped with the troubleshooting plan only partially completed. Operations and
  maintenance personnel were satisfied that the cause of the valves failure to close had
  been adequately addressed. On January 10, 2008, following the completion of other
  maintenance and required post maintenance testing on the AFW system Train A, the
  system was declared operable.
  On January 10, 2008, inspectors questioned the licensee's decision-making process and
  the adequacy of a Level C troubleshooting plan. Procedure 01DP-9ZZ01, "Systematic
  Troubleshooting," Revision 0, requires that a Level A troubleshooting plan be used for
  equipment classified as Key-Safety and having an impact on a safety function.
  Valve AFA-V-0054 is classified Key-Safety and its failure could adversely impact the
  reliability and availability of the steam driven AFW system. Engineering and
  maintenance personnel informally determined that a Level C troubleshooting plan would
  be sufficient and a valve services engineer subsequently developed the plan. The SM
  did not question the level or the rigor of the proposed troubleshooting plan. As a result,
  all potential failure mechanisms were not adequately addressed or evaluated. In
  addition, the Level C troubleshooting plan that was implemented was not performed in
  the field as written. Additionally, Procedure 70DP-0EE01, "Equipment Root Cause of
  Failure Analysis," Revision 17, provides guidance for quarantine and control of
  equipment failures to preserve physical evidence in order to aid the troubleshooting and
  diagnostic efforts. Upon its failure, before initiation of the troubleshooting plan,
  Valve AFA-HV-0054 was reopened thereby losing any contact or relay status
  information.
                                         - 15 -                                Enclosure

The issue of not establishing a Level A troubleshooting plan was entered into the CAP as PVAR 3120075 and subsequently addressed in Adverse CRDR 3120574. On January 11, 2008, the troubleshooting plan was revised to eliminate other potential failure mechanisms to ensure increased reliability of Valve AFA-HV-0054. The second example occurred on January 8, 2008, when operations personnel observed that the Unit 3 meter indication for log power Channel A increased approximately two decades while EDG Train A was in operation for a surveillance test. Log power Channel A is one of four log power channels. Two of four log power channels exceeding a trip setpoint would generate a reactor trip. The licensee entered this issue into the CAP as PVAR 3118744 and as adverse CRDR 3119111 on January 9, 2008. The inspection associated with this example is documented in Section 1R13 of this inspection report. On January 10, 2008, the inspectors requested a copy of the troubleshooting plan. The inspectors observed that a formal troubleshooting plan did not exist, and only a Level C one page hand written troubleshooting plan was available for review. The inspectors challenged the licensee regarding the adequacy of the troubleshooting plan for an SSC designated as Key-Safety. Inspectors noted that Procedure 01DP-9ZZ01, "Systematic Troubleshooting," Revision 0, provided guidance that a Level A troubleshooting plan be used for equipment classified as Key-Safety and having an impact on a safety function. Since Unit 3 was shutdown for refueling Outage 3R13, the safety function was not impacted, and a Level B, not a Level C troubleshooting plan, was appropriate. The inspectors noted that engineering and maintenance personnel did not recognize that the equipment reliability classification for log power Channel A was designated as Key-Safety. On January 11, 2008, the licensee developed a formal Level B troubleshooting plan, and implemented corrective maintenance WO 3118787. Troubleshooting determined that this indication deviation would occur whenever the exciter to EDG Train A was producing voltage, whether the generator was running with or without load. Maintenance personnel observed that the log power meter indication returned to normal when a cable within core protection calculator Channel A cabinet was disconnected. Maintenance personnel also confirmed that the noise was coming from the EDG exciter via core protection calculator Channel A, and not from the detector and preamplifier. The indication deviation was determined to be a result of typical noise produced by a generator exciter. The licensee eliminated the noise by installing an instrumentation filter via WO 3120932 on January 13, 2008. The inspectors noted both examples for this issue involved self-imposed schedule pressures during periods of high work activity, which are related to previously identified findings by the NRC and documented as NCV 05000528; 05000529; 05000530/2006003-07 and NCV 05000528; 05000529; 05000530/2006005-09. Analysis. The performance deficiency associated with this finding was the failure of operations, engineering, and maintenance personnel to follow procedures for troubleshooting degraded safety-related components. The finding is greater than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affects the 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

                                    - 16 -                                  Enclosure
    safety significance because it did not represent a loss of system safety function, an
    actual loss of safety function of a single train for greater than its TS allowed outage time,
    or screen as potentially risk-significant due to a seismic, flooding, or severe weather
    initiating event. Both examples have a crosscutting aspect in the area of human
    performance associated with decision-making because the licensee did not obtain
    appropriate interdisciplinary input and reviews on safety-significant or risk-significant
    decisions [H.1(a)].
    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 troubleshooting process of safety-related
    equipment needed to mitigate accidents was an activity affecting quality and was
    implemented by Procedure 01DP-9ZZ01, "Systematic Troubleshooting," Revision 0.
    Procedure 01DP-9ZZ01, Step 3.2.1, requires an engineering troubleshooting plan,
    Level A or Level B, when a degraded SSC is classified as Key-Safety. Contrary to the
    above, between January 8 and 13, 2008, operations, engineering, and maintenance
    personnel failed to enter the appropriate level of troubleshooting plan upon discovery of
    degraded conditions that affected SSCs. Specifically, operations, engineering, and
    maintenance personnel failed to adequately incorporate the level and detail into their
    troubleshooting plans on the Unit 3 AFW trip and throttle Valve AFA-HV-0054 when it
    failed to fully close upon demand from the control room hand switch, and on the Unit 3
    log power Channel A when induced noise was present on the channel. Because this
    finding is of very low safety significance and has been entered into the CAP as
    PVARs 3120075 and 3118744, and CRDRs 3120574 and 3119111, respectively, this
    violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC
    Enforcement Policy: NCV 05000530/2008002-02, "Two Examples of a Failure to
    Properly Implement the Systematic Troubleshooting Process."

1R20 Refueling and Other Outage Activities (71111.20)

 a. Inspection Scope
    Unit 3 Refueling Outage 3R13
    The inspectors reviewed the following risk-significant refueling items or outage activities
    to verify defense in depth commensurate with the outage risk control plan, compliance
    with the TSs, and adherence to commitments in response to Generic Letter 88-17, "Loss
    of Decay Heat Removal:" (1) the risk control plan; (2) tagging/clearance activities;
    (3) reactor coolant system instrumentation; (4) electrical power; (5) decay heat removal;
    (6) spent fuel pool (SFP) cooling; (7) inventory control; (8) reactivity control;
    (9) containment closure; (10) reduced inventory or mid-loop conditions; (11) refueling
    activities; (12) heatup and cooldown activities; (13) restart activities; and (14) licensee
    identification and implementation of appropriate corrective actions associated with
    refueling and outage activities. The inspectors' containment inspections included
    observations of the containment sump for damage and debris; and supports, braces,
    and snubbers for evidence of excessive stress, water hammer, or aging.
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed one sample.
                                          - 17 -                                 Enclosure
 b. Findings
    No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

 a. Inspection Scope
    The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure that
    the four below listed surveillance activities demonstrated that the SSCs tested were
    capable of performing their intended safety functions. The inspectors either witnessed
    or reviewed test data to verify that the following significant surveillance test attributes
    were adequate: (1) preconditioning; (2) evaluation of testing impact on the plant;
    (3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead
    controls; (7) test data; (8) testing frequency and method to demonstrate TS operability;
    (9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of American
    Society of Mechanical Engineers Code requirements; (12) updating of performance
    indicator (PI) data; (13) engineering evaluations, root causes, and bases for returning
    tested SSCs not meeting the test acceptance criteria were correct; (14) reference setting
    data; and (15) annunciators and alarms setpoints. The inspectors also verified that the
    licensee identified and implemented any needed corrective actions associated with the
    surveillance testing.
    *        January 3-17, 2008, Unit 3, Procedure 73ST-9AF04, "AFA-P01 Full
             Flow-Inservice Test," Revision 2
    *        February 7, 2008, Unit 3, Procedure 40ST-9DG01, "Diesel Generator A Test,"
             Revision 32
    *        February 17, 2008, Unit 3, Procedure 40ST-9ZZ25, "Online Remote Shutdown
             Disconnect Switch Operability," Revision 1
    *        February 28, 2008, Unit 2, Procedure 73ST-9ZZ18, "Main Steam and Pressurizer
             Safety Valve Set Pressure Verification," Revision 20
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed four samples.
 b. Findings
    No findings of significance were identified.
    Cornerstone: Emergency Preparedness
                                           - 18 -                               Enclosure

1EP2 Alert Notification System Testing (71114.02)

 a.  Inspection Scope
     The inspector discussed with licensee staff the status of offsite siren and tone alert radio
     systems to determine the adequacy of licensee methods for testing the alert and
     notification system in accordance with 10 CFR Part 50 Appendix E. The licensee's alert
     and notification system testing program was compared with criteria in NUREG-0654,
     "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and
     Preparedness in Support of Nuclear Power Plants," Revision 1, Federal Emergency
     Management Agency Report REP-10, "Guide for the Evaluation of Alert and Notification
     Systems for Nuclear Power Plants," and the licensee=s current Federal Emergency
     Management Agency approved alert and notification system design report.
    Documents reviewed by the inspector are listed in the attachment.
    The inspector completed one sample.
 b.  Findings
     No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation Testing (71114.03)

 a.  Inspection Scope
     The inspector discussed with licensee staff the status of primary and backup systems for
     augmenting the on-shift emergency response staff to determine the adequacy of
     licensee methods for staffing emergency response facilities. The inspector reviewed
     licensee Procedure EPIP-61, "Emergency Planning Equipment Testing," Revision 5, and
     the references listed in the attachment to this report related to the emergency response
     organization augmentation system, to evaluate the licensee=s ability to staff the
     emergency response facilities in accordance with the licensee emergency plan and the
     requirements of 10 CFR Part 50 Appendix E.
     Documents reviewed by the inspector are listed in the attachment.
     The inspector completed one sample.
 b.  Findings
     No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)

 a.  Inspection Scope
     The inspector performed an in-office review of:
     *       Palo Verde Nuclear Generating Station Emergency Plan, Revision 36, submitted
             May 21, 2007
                                         - 19 -                                Enclosure
    *        Palo Verde Nuclear Generating Station Emergency Plan, Revision 37, submitted
             May 21, 2007
    *        EPIP-99, "Emergency Plan Implementing Procedures Standard Appendices,"
             Revision 16, Appendix P, "Emergency Action Level (EAL) Bases," submitted
             November 9, 2007
    *        Palo Verde Nuclear Generating Station Emergency Plan, Revision 38, submitted
             February 11, 2008
    These revisions added descriptions to the technical basis for security-related EALs 7-5,
    7-6, and 7-7; updated descriptions of the duties of the shift technical advisor and
    systems engineering; updated emergency planning zone maps; added public alert and
    notification system sirens; updated the locations of offsite reception and care centers;
    changed the licensee's computer dose projection system from Mesorem Jr. to Raddose;
    updated the locations of telecommunications equipment; added a description of the
    transfer of dose projection duties from the control room to other emergency response
    facilities; removed the requirement that changes to EALs be approved by offsite officials
    in accordance with 10 CFR Part 50, Appendix E; updated emergency planning zone
    demographic information; added detail concerning the performance requirements for
    licensee dose assessment software; and made minor administrative corrections.
    These revisions were compared to their previous revisions, to the criteria of
    NUREG-0654, "Criteria for Preparation and Evaluation of Radiological Emergency
    Response Plans and Preparedness in Support of Nuclear Power Plants," Revision 1, to
    the criteria of Nuclear Energy Institute (NEI) Report 99-01, "Methodology for
    Development of Emergency Action Levels," Revisions 2 and 4, and to the standards in
    10 CFR 50.47(b) to determine if the revisions adequately implemented the requirements
    of 10 CFR 50.54(q). These reviews were not documented in a safety evaluation report
    and did not constitute approval of licensee changes; therefore, these revisions are
    subject to future inspection.
    Documents reviewed by the inspector are listed in the attachment.
    The inspectors completed four samples.
 b. Findings
    No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies (71114.05)

 a. Inspection Scope
    The inspector reviewed the licensees corrective action program requirements in
    Procedures 01DP-0AP12, "Palo Verde Action Request Processing," Revision 4,
    and 90DP-0IP10, "Condition Reporting," Revision 36, and other documents listed in the
    attachment to this report. The inspector reviewed summaries of 363 CRDRs assigned to
    the emergency preparedness department between February 2006 and January 2008,
    and selected 20 for detailed review against the program requirements. The inspector
    evaluated the response to the corrective action program requests to determine the
    licensees ability to identify, evaluate, and correct problems in accordance with the
                                          - 20 -                              Enclosure
     licensee program requirements and 10 CFR 50.47(b)(14) and 10 CFR Part 50,
     Appendix E.
     Documents reviewed by the inspector are listed in the attachment.
     The inspector completed one sample.
  b. Findings
     No findings of significance were identified.

1EP6 Drill Evaluation (71114.06)

  a. Inspection Scope
     On March 5, 2008, for the Emergency Response Organization exercise scenario Guide
     08-E-AEV-03002 simulator-based training evolution, contributing to Drill/Exercise
     Performance and Emergency Response Organization PIs, the inspectors: (1) observed
     the training evolution to identify any weaknesses and deficiencies in classification,
     notification, and Protective Action Requirements development activities; (2) compared
     the identified weaknesses and deficiencies against licensee identified findings to
     determine whether the licensee is properly identifying failures; and (3) determined
     whether licensee performance is in accordance with the guidance of the NEI 99-02,
     "Voluntary Submission of Performance Indicator Data," acceptance criteria.
     Documents reviewed by the inspectors are listed in the attachment.
     The inspectors completed one sample.
  b. Findings
     No findings of significance were identified.

2. RADIATION SAFETY

     Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

  a. Inspection Scope
     This area was inspected to assess the licensee's performance in implementing physical
     and administrative controls for airborne radioactivity areas, radiation areas, high
     radiation areas, and worker adherence to these controls. The inspector used the
     requirements in 10 CFR Part 20, the TSs, and the licensee's procedures required by TSs
     as criteria for determining compliance. During the inspection, the inspector interviewed
     the radiation protection manager, radiation protection supervisors, and radiation workers.
     The inspector performed independent radiation dose rate measurements and reviewed
     the following items:
     *        Performance indicator events and associated documentation packages reported
              by the licensee in the Occupational Radiation Safety Cornerstone (two samples)
                                          - 21 -                                Enclosure
    *       Controls (surveys, posting, and barricades) of three radiation, high radiation, or
            airborne radioactivity areas
    *       Radiation exposure permits, procedures, engineering controls, and air sampler
            locations
    *       Self-assessments, audits, licensee event reports (LERs), and special reports
            related to the access control program since the last inspection
    *       Licensee actions in cases of repetitive deficiencies or significant individual
            deficiencies
    *       Posting and locking of entrances to all accessible high dose rate-high radiation
            areas and very high radiation areas
    Documents reviewed by the inspector are listed in the attachment.
    The inspector completed seven samples.
 b. Findings
    No findings of significance were identified.

2OS2 As Low As Is Reasonably Achievable (ALARA) Planning And Controls (71121.02)

 a. Inspection Scope
    The inspector assessed licensee performance with respect to maintaining individual and
    collective radiation exposures ALARA. The inspector used the requirements in 10 CFR
    Part 20 and the licensee's procedures required by TSs as criteria for determining
    compliance. The inspector interviewed select licensee personnel and reviewed:
     *      Five outage work activities scheduled during the inspection period and
            associated work activity exposure estimates which were likely to result in the
            highest personnel collective exposures
    *       Site-specific ALARA procedures
    *       ALARA work activity evaluations, exposure estimates, and exposure mitigation
            requirements
    *       Intended versus actual work activity doses and the reasons for any
            inconsistencies
    *       Integration of ALARA requirements into work procedure and radiation work
            permit (or radiation exposure permit) documents
    *       Person-hour estimates provided by maintenance planning and other groups to
            the radiation protection group with the actual work activity time requirements
                                        - 22 -                                 Enclosure
     *       Use of engineering controls to achieve dose reductions and dose reduction
             benefits afforded by shielding
     *       Workers use of the low dose waiting areas
     *       Records detailing the historical trends and current status of tracked plant source
             terms and contingency plans for expected changes in the source term due to
             changes in plant fuel performance issues or changes in plant primary chemistry
     *       Source-term control strategy or justifications for not pursuing such exposure
             reduction initiatives
     *       Specific sources identified by the licensee for exposure reduction actions and
             priorities established for these actions, and results achieved against since the
             last refueling cycle
     *       Declared pregnant workers during the current assessment period, monitoring
             controls, and the exposure results
     *       Resolution through the CAP of problems identified through post-job reviews and
             post-outage ALARA report critiques
     *       Corrective action documents related to the ALARA program and follow-up
             activities, such as initial problem identification, characterization, and tracking
     Documents reviewed by the inspector are listed in the attachment.
     The inspector completed 14 samples.
  b. Findings
     No findings of significance were identified.

4. OTHER ACTIVITIES 4OA1 Performance Indicator (PI) Verification (71151)

  a. Inspection Scope
     Cornerstone: Initiating Events
     The inspectors sampled licensee submittals for the three PIs listed below for the period
     January 2007 to December 2007, for Units 1, 2, and 3. The definitions and guidance of
     NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 5, were used to verify
     the licensees basis for reporting each data element in order to verify the accuracy of PI
     data reported during the assessment period. The inspectors reviewed LERs, monthly
     operating reports, and operating logs as part of the assessment. Licensee PI data was
     also reviewed against the requirements of Procedures 93DP-0LC09, "Data Collection
     and Submittal Using INPO's Consolidated Data Entry System," Revision 7, and
     70DP-0PI01, "Performance Indicator Data Mitigating Systems Cornerstone," Revision 3.
     *       Unplanned Scrams Per 7,000 Critical Hours
                                            - 23 -                                 Enclosure
  • Unplanned Scrams With Complications
  • Unplanned Power Changes Per 7,000 Critical Hour

Documents reviewed by the inspectors are listed in the attachment. The inspectors completed three samples. Cornerstone: Emergency Preparedness The inspector reviewed licensee evaluations for three emergency preparedness cornerstone PIs for the period of January through December 2007. The definitions and guidance of NEI Report 99-02, "Regulatory Assessment Indicator Guideline," Revisions 3 through 5, and licensee PI Procedure 16DP-0EP19, "Performance Indicator Emergency Preparedness Cornerstone," Revision 6, were used to verify the accuracy of the licensees evaluations for each PI reported during the assessment period. The inspector reviewed a one hundred percent sample of drill and exercise scenarios and licensed operator simulator training sessions, notification forms, and attendance and critique records associated with training sessions, drills, and exercises conducted during the verification period. The inspector reviewed sixteen selected emergency responder qualification, training, and drill participation records. The inspector reviewed alert and notification system testing procedures, maintenance records, and a one hundred percent sample of siren test records.

  • Drill and Exercise Performance
  • Emergency Response Organization Participation
  • Alert and Notification System Reliability

Documents reviewed by the inspectors are listed in the attachment. The inspector completed three samples. Cornerstone: Occupational Radiation Safety The inspector reviewed the Occupational Exposure Control Effectiveness PI and associated licensee documents from October 1 through December 31, 2007. The review included corrective action documentation that identified occurrences in locked high radiation areas (as defined in the licensees TSs), very high radiation areas (as defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 5). Additional records reviewed included ALARA records and whole body counts of selected individual exposures. The inspector interviewed the licensee that were accountable for collecting and evaluating the PI data. In addition, the inspector toured plant areas to verify that high radiation, locked high radiation, and very high radiation areas were properly controlled. Performance indicator definitions and guidance contained in NEI 99-02, Revision 5, were used to verify the basis in reporting for each data element. Documents reviewed by the inspectors are listed in the attachment. The inspector completed one sample. Cornerstone: Public Radiation Safety

                                      - 24 -                                Enclosure
     The inspector reviewed the Radiological Effluent TS /Offsite Dose Calculation Manual
     Radiological Effluent Occurrences PI and associated licensee documents from
     October 1, 2007, through December 31, 2007. Licensee records reviewed included
     corrective action documentation that identified occurrences for liquid or gaseous effluent
     releases that exceeded PI thresholds and those reported to the NRC. The inspector
     interviewed the licensee that was accountable for collecting and evaluating the PI data.
     Performance indicator definitions and guidance contained in NEI 99-02, Revision 5, were
     used to verify the basis in reporting for each data element.
     Documents reviewed by the inspectors are listed in the attachment.
     The inspector completed one sample.
  b. Findings
     No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152) .1 Routine Review of Identification and Resolution of Problems

     The inspectors performed a daily screening of items entered into the licensee's CAP.
     This assessment was accomplished by reviewing daily summary reports for CRDRs and
     work mechanisms, and attending corrective action review and work control meetings.
     The inspectors: (1) verified that equipment, human performance, and program issues
     were being identified by the licensee at an appropriate threshold and that the issues
     were entered into the CAP; (2) verified that corrective actions were commensurate with
     the significance of the issue; and (3) identified conditions that might warrant additional
     follow-up through other baseline inspection procedures (IPs).

.2 Selected Issue Follow-up Inspection

  a. Inspection Scope
     In addition to the routine review, the inspectors selected the three below listed issues for
     a more in-depth review. The inspectors considered the following during the review of the
     licensee's actions: (1) complete and accurate identification of the problem in a timely
     manner; (2) evaluation and disposition of operability/reportability issues;
     (3) consideration of extent of condition, generic implications, common cause, and
     previous occurrences; (4) classification and prioritization of the resolution of the problem;
     (5) identification of root and contributing causes of the problem; (6) identification of
     corrective actions; and (7) completion of corrective actions in a timely manner.
     *       January 29, 2008, Unit 2, foreign material (FM) previously found in the spent fuel
             pool (SFP) no longer visible
     *       February 4, 2008, Units 1, 2, and 3, reviewed unresolved Item 05000528,
             05000529, 05000530/2007012-18, "Routine Heavy Use of Overtime," opened
             during the IP 95003 Supplemental Inspection for an NRC review of actual hours
             worked by operations personnel
                                           - 25 -                                Enclosure
  *       February 6-26, 2008, Units 1, 2, and 3, reviewed quality control evaluators
          organizational structure
  Documents reviewed by the inspectors are listed in the attachment.
  The inspectors completed three samples.

b. Findings and Observations .1 Foreign Material in the Spent Fuel Pool

  Introduction. The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B,
  Criterion V, "Instructions, Procedures, and Drawings," for the failure of fuels services
  personnel to evaluate leaving foreign material (FM) in the Unit 2 SFP in accordance with
  procedures, and failed to ensure those procedures included appropriate quantitative and
  qualitative acceptance criteria.
  Description. On October 13, 2006, during Unit 2 refueling Outage 2R13, fuels services
  personnel were performing under-bundle fuel inspection for fuel being removed from the
  reactor when FM was found. The FM appeared to be fixed inside the guardian grid of
  the lower end fitting of fuel Assembly P2N111, as documented in CRDR 2932719. A
  control room review of CRDR 2932719, performed on October 14, 2006, stated no
  additional foreign object search and retrieval (FOSAR) was required to look for the
  material.
  On November 7, 2006, fuels services personnel initiated CRAI 2940130 to use
  Procedure 78DP-9ZZ01, "Foreign Object Search And Retrieval, Remotely Operated
  Vehicles, And Submersible Retrieval Tools And Pumps," Revision 0, and a written plan
  to attempt to remove the FM from Assembly P2N111 per WO 2940366. Engineering
  personnel planned to evaluate leaving the debris in Assembly P2N111, if the removal
  attempt was unsuccessful. Fuels services personnel attempted to recover the FM on
  January 24, 2008, in accordance with WO 2940366; however, the piece of debris was no
  longer visible. On January 24, 2008, PVAR 3126308 documented that the FM may have
  been transported to another location in the Unit 2 SFP or RCS, and that the FOSAR
  effort would be expanded to the rest of the SFP. The PVAR stated, in part, that if the
  FOSAR effort failed to locate and retrieve the debris, then, an evaluation and an
  engineering deficiency work order (ENG-DFWO) would be initiated in accordance with
  Procedure 30DP-9MP03, "System Cleanliness and Foreign Material Exclusion Controls,"
  Revision 6.
  On January 24, 2008, inspectors reviewed Procedure 30DP-9MP03, Step 2.9.5, which
  states, "that if the FM cannot be retrieved, then the Responsible Leader shall ensure that
  an ENG-DFWO has been initiated and dispositioned by the Responsible Engineer
  before the system is closed. The ENG-DFWO shall be linked to the CRDR written to
  document the loss of FME control." Procedure 81DP-0DC13, "Deficiency Work Order,"
  Revision 21, Step 3.2.1 states, "engineering personnel assigned to disposition a
  deficiency work order (DFWO) which addresses degraded or nonconforming conditions
  to TS equipment or equipment that supports TS equipment should verify an operability
  determination or functional assessment has been performed in accordance with
  Procedure 40DP-9OP26, Operability Determination and Functional Assessment,
  Revision 18." The inspectors observed that Procedure 30DP-9MP03 provided no time
  limit acceptance criteria to perform a functional assessment and to write a DFWO, as
                                      - 26 -                                 Enclosure

specified in Procedure 81DP-0DC13, from the time the FM was found in the SFP. Additionally, the inspectors questioned fuels services personnel whether FM in the SFP was a potentially degraded or nonconforming condition and should be evaluated by the control room in accordance with Procedure 01DP-0AP12, "Palo Verde Action Request Processing," Revision 4, and Procedure 40DP-9OP26. Procedure 01DP-0AP12, Step 3.5 states, "A control room review will be performed for PVARs that have been screened at the Operations Review step and determined that a control room review is warranted. The condition described in the PVAR shall be evaluated by the SM for the assessment of potential operability concerns." If a degraded or nonconforming condition exists, Step 3.5.3 states, "the SM shall initiate actions to determine Operability/Functionality per Procedure 40DP-9OP26." On January 27, 2008, operations personnel performed a functional assessment of the effects of SFP FM on SFP cooling and the ability of the SFP to provide a borated water source, as documented in PVAR 3126308. Operations personnel determined the small piece of FM would have little impact on fuel assembly cooling and SFP cooling; and that the FM would not go back into the RCS because under-bundle inspections on fuel bundles are performed before the fuel is put back in the core. The inspectors noted that the FM could have been transferred back into the RCS and affect reactor core fuel assemblies, because at the time the FM was found in October 2006, no under-bundle inspections were performed for fuel going back into the RCS. Consequently, the licensee updated the functional assessment performed in PVAR 3126308 on January 31, 2008, to address the possibility that the FM was transported into the RCS. The licensee determined that due to the size of the FM, about three eights of an inch, that it would not create any operability concerns. The licensee determined that this FM was very similar in shape and size, and was covered by a more limiting evaluation performed for FM found in Unit 3 fuel bundles, as documented in DFWO 2885310. This DFWO, including Westinghouse vendor guidance, determined that the material was flexible graphite (grafoil), which is commonly used in gasket and valve packing material and has been approved for use in the RCS. The licensee wrote WO 3139395 to continue to look for the debris. Analysis. The performance deficiency associated with this finding involved the failure of fuels services personnel to evaluate leaving FM in the Unit 2 SFP in accordance with procedures, and failed to ensure those procedures included appropriate quantitative and qualitative acceptance criteria. The finding is greater than minor because it is associated with the SSC performance and human performance attributes of the barrier integrity cornerstone and affects the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, RCS, and containment) protect the public from radionuclide releases caused by accidents or events. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance because the finding did not result in loss of cooling to the SFP; the finding did not result from fuel handling errors that caused damage to the fuel clad integrity or a dropped assembly; and the finding did not result in a loss of SFP inventory greater than ten percent of the SFP volume. This finding has a crosscutting aspect in the area of human performance associated with decision-making because the licensee failed to use conservative assumptions when evaluating degraded and nonconforming conditions [H.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

                                    - 27 -                                Enclosure
  instructions, procedures, and drawings. The control of FM to prevent damage to quality
  and quality augmented components is implemented by Procedure 30DP-9MP03,
  "System Cleanliness and Foreign Material Exclusion Controls," Revision 6.
  Procedure 30DP-9MP03, Step 2.9.5 states, "that if the FM cannot be retrieved, then the
  Responsible Leader shall ensure that an ENG-DFWO has been initiated and
  dispositioned by the Responsible Engineer before the system is closed. The
  ENG-DFWO shall be linked to the CRDR written to document the loss of FME control."
  Procedure 81DP-0DC13, "Deficiency Work Order," Revision 21, Step 3.2.1, states,
  "engineering personnel assigned to disposition a DFWO which addresses degraded or
  nonconforming conditions to TS equipment or equipment that supports TS equipment
  should verify an operability determination or functional assessment has been performed
  in accordance with Procedure 40DP-9OP26, 'Operability Determination and Functional
  Assessment,' Revision 18." Contrary to the above, between October 13, 2006 and
  January 31, 2008, fuels services personnel failed to evaluate leaving FM in the Unit 2
  SFP in accordance with procedures, and failed to ensure those procedures included
  appropriate quantitative and qualitative acceptance criteria. Specifically, fuels services
  personnel used Procedure 30DP-9MP03, "System Cleanliness and Foreign Material
  Exclusion Controls," Revision 6, which did not specify acceptance criteria for time to
  perform a functional assessment of FM in the SFP, resulting in FM being left in the SFP
  for greater than one year without an evaluation on affected safety systems. Because
  this finding is of very low safety significance and has been entered into the licensee's
  CAP as PVAR 3126308, this violation is being treated as an NCV, consistent with
  Section VI.A.1 of the NRC Enforcement Policy: NCV 0500529/2008002-03, "Inadequate
  Procedure to Evaluate Foreign Material in the Spent Fuel Pool."

.2 Failure To Maintain Adequate Staffing Levels

  Introduction. The inspectors identified a Green noncited violation of Technical
  Specification 5.2.2.d involving the routine use of excessive overtime for operations
  personnel.
  Description. The inspectors reviewed APS payroll data from January 1, 2003 through
  December 31, 2007, that summarized the regular and overtime hours worked for each
  operations department position. During this review the inspectors noted that the total
  number of hours worked annually by operations department personnel remained
  relatively constant, or decreased, while the percentage of those total hours that were
  worked as overtime increased. As a result, the inspectors determined that the licensee
  increasingly relied on the use of overtime to provide the person-hours necessary to
  operate the three units.
                                        - 28 -                              Enclosure

Operator staffing from January 1 for 2003 through December 31, 2007

                          2003          2004             2005             2006         2007
 Control
 Room
 Supervisor                  25             24               24             23            33
 Reactor
 Operator                    43             40               40             39            36
 Shift
 Manager                     20             20               19             19            19
  • Data is an average number of personnel in the position over the year, taken from APS payroll data.

Operator Hours from January 1, 2003 through December 31, 2007

                                    2003         2004          2005         2006       2007
 Control          Regular          44411       40415         42407         38713     57367
 Room
                  Overtime          5014         5562          6890         8440     18473
 Supervisor
 Reactor          Regular          75589       71183         71329         67199     62945
 Operator         Overtime         12161       15206         17888         21740     26854
 Shift            Regular          35821       33348         33545         32300     32059
 Manager          Overtime          4870         5294          6273         8726     10035
  • Data taken from APS payroll data.

Average regular hours worked by position

                          2003          2004             2005             2006         2007
 Control
 Room
 Supervisor               1776          1684             1767             1683         1738
 Reactor
 Operator                 1758          1780             1783             1723         1748
 Shift
 Manager                  1791          1667             1766             1700         1687
  • Hours worked were calculated based on a comparison of the total regular hours worked by personnel in

the position relative to the average number of personnel in that position. The inspectors derived the percent overtime using the following assumptions: 1. A 4 percent correction factor to account for overtime hours worked as part of the normally scheduled shift rotation. 2. A 5 to10 percent correction factor to account for shift turnover. 3. A 75 percent correction factor to exclude overtime worked during refueling outages. The inspectors used the following equation to calculate the percent overtime worked. X=[[((Y*0.96)*0.9)/Z]*100]*0.75

         X = Percent overtime
         Y = Total overtime hours worked as documented in payroll data
         Z = Total regular hours worked as documented in payroll data
                                         - 29 -                                      Enclosure
                        2003         2004        2005          2006          2007
 Control                7.32          8.92      10.53         14.13         20.87
 Room
 Supervisor
 Reactor               10.43        13.84       16.25         20.96         27.65
 Operator
 Shift                  8.81        10.29       12.12         17.51         20.28
 Manager

Since 2003, overtime, as a percent of regular hours worked, has increased steadily and substantively for control room operators. The inspectors 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. The inspectors also noted that the 2007 overtime rates were more than double the overtime rates of 2003. During their review the inspectors noted that Technical Specification 5.2.2.d, Organization - Unit Staff, requires that administrative procedures shall be developed and implemented to limit the working hours of unit staff that perform safety-related functions, as well as requiring that the controls shall include guidelines on working hours that ensure adequate shift coverage shall be maintained without routine heavy use of overtime. Station procedure 01DP-9EM01, Overtime Limitations, Revision 6, is the licensees administrative procedure used to control unit staff working hours in accordance with facility Technical Specifications. Section 2.1 of this procedure requires that department leaders ensure that adequate shift coverage is maintained without the routine heavy use of overtime. The objective is to have personnel work a nominal 40- hour week while the plant is operating. The inspectors determined that the licensee had several missed opportunities to identify this issue. Specifically, during their review the inspectors noted that the licensee had not been issuing and reviewing Technical Specification required excess overtime reports from approximately June 2006 through July 2007. The purpose of these reports was to facilitate identification of excess overtime usage by site management. However, due to changing computer software the reports were not generated and reviewed. Also, the inspector noted that several CRDRs written that identified the metric window for operations overtime were red for most of 2007. The inspectors determined that these were indicators of the use of excessive overtime and these indicators were missed by the licensee. Analysis. The performance deficiency associated with this finding involved excessive routine use of heavy amounts of overtime for operations personnel that perform safety- related functions. The finding is greater than minor because if left uncorrected the finding would become a more significant safety concern in that the routine use of excessive work hours increases the likelihood of operator errors. Using the Manual C Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance because no specific human performance issues due to personnel fatigue were identified that resulted in the degradation or loss of safety function of equipment important to safety. The finding has a crosscutting aspect in the area of human performance associated with resources because the licensee failed to maintain sufficient qualified operations personnel to maintain working hours within guidelines without heavy use of overtime [H.2(b)].

                                      - 30 -                              Enclosure
  Enforcement. Technical Specification 5.2.2.d, "Organization-Unit Staff," requires, in part,
  that administrative procedures 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).
  This TS further requires the controls include guidelines on working hours that ensure
  adequate shift coverage be maintained without the routine heavy use of overtime.
  Procedure 01DP-9EM01, "Overtime Limitations," Revision 6, is the licensees
  administrative procedure used to control unit staff working hours. Procedure 01DP-
  9EM01 requires, in part, that department leaders ensure that adequate shift coverage is
  maintained without the routine heavy use of overtime. The objective is to have
  personnel work a nominal 40-hour week while the plant is operating. Contrary to the
  above, between January 1 and December 31, 2007, the licensee failed to meet the
  objective of operations personnel working a nominal 40-hour week while all three units
  are operating, and has relied upon the excessive use of overtime to maintain adequate
  shift coverage. Because this finding is of very low safety significance and has been
  entered into the CAP as CRDR 3112231, this violation is being treated as an NCV
  consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000528;
  05000529; 05000530/2008002-04, "Failure To Maintain Adequate Staffing Levels
  Results In Heavy Use of Overtime to Maintain Adequate Shift Coverage." Unresolved
  Item 05000528; 05000529; 05000530/2007012-18 is closed.

.3 Quality Control Organizational Structure

  Inspectors determined that no findings of significance were identified during the review
  of CRDR 3129081. Inspectors reviewed issues regarding warehouse operations as
  documented in CRDR 3129081. Inspectors evaluated the organizational structure of the
  Quality Control (QC) Evaluators and the effectiveness of the Employee Concerns
  Program within the Supply Chain and Stores department. The licensee addressed these
  issues in a letter to the NRC dated January 25, 2008. Inspectors evaluated the
  adequacy of the licensees response by conducting independent inspections.
  Inspectors observed that currently QC Evaluators report directly to the Warehouse
  Section Leader-Stores. The Warehouse Section Leader has the responsibility for
  receiving, processing, handling, and placing into stores, equipment and components for
  use at Palo Verde Nuclear Generating Station (PVNGS). Quality Control Evaluators
  perform inspections for quality related equipment and components in this receipt
  process. While QC Evaluators are insulated from cost and schedule pressures
  associated with the rest of the PVNGS organization, they are subject to the production
  pressures and budget constraints within the Supply Chain and Stores department.
  Consequently, QC Evaluators do not report to a management level that assures the
  required authority and organizational freedom, including sufficient independence from
  cost and schedule when opposed to safety considerations.
  Inspectors noted that the PVNGS Quality Assurance (QA) program was revised as
  specified in licensing document change request (LDCR) 01-F-012. Quality Control
  Evaluators were reassigned from the Nuclear Assurance Department to the Strategic
  Procurement organization. This change to the QA program was accomplished without
  prior NRC review and approval. Justification for changing the QA program without prior
  NRC review and approval was described in LDCR 01-012. Regulatory Affairs and NAD
  personnel concluded that the change was allowed without prior NRC approval under the
  provisions of 10 CFR 50.54(a)(3). The NRC previously approved, with an NRC safety
  evaluation, a similar quality assurance program description change to the Beaver Valley
                                       - 31 -                                 Enclosure
     Power Station (BVPS). The licensee concluded that the commitments made by Beaver
     Valley prior to the program change were the same as PVNGS commitments with respect
     to the quality assurance program. The licensee also concluded that all other issues
     questioned by the NRC during Beaver Valleys approval process were adequately
     addressed in LDCR-01-012. Based on these conclusions, the licensee believed that
     they were allowed to change the quality assurance program description in the UFSAR
     without prior NRC approval.
     Variations in the methods employed to meet the standards of the commitments exist
     between the licensee and the BVPS. At the BVPS, in order to provide maximum
     independence from production pressures within the Nuclear Procurement Department,
     QC Inspectors would report directly to the department manager and would be assigned
     a separate budget. At Palo Verde, the QC Evaluators report directly to a front line
     supervisor and fall under one common Supply Chain and Stores budget. Although the
     commitments themselves may be the same between the two facilities, the methods in
     which those commitments are met are different. Inspectors observed that by reporting
     directly to a front line supervisor, and being subject to one common budget, the QC
     Evaluators may not have an the necessary level of independence from production
     pressures within the Supply Chain and Stores department. No findings of significance
     were identified since the changes to the UFSAR did not involve a decrease in
     commitments to the NRC. The organizational structure for QC Evaluators is being
     addressed in the CAP as PVAR 3143574.

.3 Annual Sample: Review of Apparent Cause Evaluations

  a. Inspection Scope
     The inspectors selected 20 CRDRs and six apparent cause evaluations for detailed
     review. The reports were reviewed to ensure that the full extent of the performance
     issues were identified, an appropriate evaluation was performed, and appropriate
     corrective actions were specified and prioritized. The inspectors evaluated the selected
     CRDRs against the requirements of licensee Procedure 90DP-0IP10, "Condition
     Reporting," Revision 36.
     Documents reviewed by the inspectors are listed in the attachment.
     The inspectors completed one sample.
  b. Findings
     No findings of significance were identified.

.4 Multiple/Repetitive Degraded Cornerstone Column and Crosscutting Issues Follow-up

     Activities
     Quarterly Confirmatory Action Letter Inspection
     This inspection was the first in a series of inspections to be performed by the NRC to
     assess the progress that PVNGS made with respect to the implementation of their Site
     Integrated Improvement Plan (SIIP) and to verify their progress in addressing the
     specific actions in the NRC Confirmatory Action Letter (CAL) dated February 15, 2008.
                                           - 32 -                              Enclosure
  During the IP 95003 Supplemental Inspection, the licensee was still in the process of
  developing the SIIP and only limited progress had been made in completing SIIP tasks.
  As of November 1, 2007, the licensee had completed 12 closure packages and only 2
  had been approved for closure by the Closure Review Board (CRB). On December 31,
  2007, PVNGS submitted portions of their SIIP to address Action 5 of the original CAL
  dated June 21, 2007. Action 5 required the licensee to submit the portions of their
  improvement plan that impacted the Reactor Safety strategic performance area.
  The revised CAL, dated February 15, 2008, superseded the CAL dated June 21, 2007.
  The revised CAL contains a subset of actions delineated in the SIIP that the NRC
  determined were necessary to address the performance insights identified by PVNGS
  assessment activities and the IP 95003 Supplemental Inspection. The key performance
  areas that PVNGS has committed to address are as follows: Yellow and White findings
  as documented in NRC Inspection Reports 05000528; 05000529; 05000530/2004014
  and 2006012, problem identification and resolution issues, human performance issues,
  engineering programs, review of current equipment evaluations, safety culture,
  accountability, change management, emergency preparedness, longstanding equipment
  deficiencies, and backlog.
  The areas to be inspected are identified in the revised CAL. The licensee submitted a
  list of the specific tasks, including due dates, associated with the action plans and
  strategies for each of the CAL items on March 31, 2008. The items selected for this
  quarterly CAL inspection were based on the completion due dates provided by the
  licensee from their submittal dated, December 31, 2007.

a. Inspection Scope

  The inspectors selected the SIIP tasks listed below for an in-depth review. The
  inspectors considered the following during the review of the licensees actions: (1) SIIP
  task matches the CRAI description; (2) corrective actions address and correct the SIIP
  task; (3) corrective actions address the action plan problem statement and primary
  causes; (4) verification of SIIP task completion; (5) timely completion of corrective
  actions in accordance with the SIIP schedule; (6) review of metrics and measures for
  improved performance; (7) independent verification of improved performance; and
  (8) closure of SIIP task in accordance with procedures.
  *         Task 1.2.E.35 (CAL Item 5 and SIIP Action Plan 5, Strategy 1) (CRAI 3107133)
            -based on rankings, each engineering program owner complete a self
            assessment
  *         Task 2.2.B.1 (CAL Item 7 and SIIP Action Plan 12, Strategy 8) (CRAI 3062459)
            -develop a targeted staffing strategy for operations
  *         Task 2.2.B.2 (CAL Item 7 and SIIP Action Plan 12, Strategy 8) (CRAI 3062460)
            -develop a targeted staffing strategy for engineering
  *         Task 2.2.B.3 (CAL Item 7 and SIIP Action Plan 12, Strategy 8) (CRAI 3062461)
            -develop a targeted staffing strategy for maintenance
  *         Task 2.2.B.4 (CAL Item 7 and SIIP Action Plan 12, Strategy 8) (CRAI 3062464)
            -develop a targeted strategy for radiation protection and chemistry
                                        - 33 -                                Enclosure
  • Task 2.2.B.5 (CAL Item 7 and SIIP Action Plan 12, Strategy 8) (CRAI 3062465)
 -develop a targeted staffing strategy for other positions
  • Task 3.6.48 (CAL Item 2 and SIIP Action Plan 14, Strategy 2) (CRAI 3104935)
 -engineering design change for K1 relay module
  • Task 3.6.60 (CAL Item 2 and SIIP Action Plan 14, Strategy 4) (CRAI 3042092)
 -identify and classify components in the Class 1E 480V Power Switchgear
 system
  • Task 3.6.62 (CAL Item 2 and SIIP Action Plan 14, Strategy 4) (CRAI 3042095)
 -identify and classify components in the PK system
  • Task 3.6.64 (CAL Item 2 and SIIP Action Plan 14, Strategy 4) (CRAI 3042098)
 -identify and classify components in the AFW system
  • Task 3.7.3 f (CAL Item 1 and SIIP Action Plan 15, Focus Area 2)
 (CRAI 2785420) -implement design modification work order 2760330 to replace
 the existing carbon steel parts on the inboard butterfly valves JSIAUV0673 and
 JSIBUV0675 with stainless steel parts
  • Task 3.7.3 p (CAL Item 1 and SIIP Action Plan 15, Focus Area 1)
 (CRAI 2785390) -implement design modification for the Unit 1 containment sump
 suction valves
  • Task 5.1.E.3 (CAL Item 3 and SIIP Action Plan 3, Strategy 4) (CRAI 3062967)
 -incorporate operability determination in engineering continuing training program
 requirements
  • Task 9.1.A.1 (CAL Item 10 and SIIP Action Plan 8, Strategy 1) (CRAI 3063144) -
 implement Policy 1503, Emergency Planning, to require personnel to fill
 positions within required timeframe
  • Task 9.1.A.5 (CAL Item 10 and SIIP Action Plan 8, Strategy 1) (CRAI 3063199)
 -revise Policy Guide 150, "Emergency Planning"
  • Task 9.1.A.24 (CAL Item 10 and SIIP Action Plan 8, Strategy 8) (CRAI 3077904)
 -develop and implement a multi-discipline Emergency Plan Steering Committee
  • Task 15.1.10 (CAL Item 3 and SIIP Action Plan 6, Part 2, Strategy 7) (CRAI
 3017939) -develop and implement station metrics/indicators associated with self
 assessments
  • Task 15.2.1.b (CAL Item 3 and SIIP Action Plan 6, Part 2, Strategy 7) (CRAI
 3017946) -lessons learned and recommendations for incorporation of good
 practices into the site work management system
 The inspectors considered the following CAL SIIP tasks completed: 2.2.B.1,
 2.2.B.2, 2.2.B.3, 2.2.B.4, 2.2.B.5, 3.6.48, 3.6.60, 3.6.64, 3.7.3.p, 9.1.A.1, 9.1.A.5,
 9.1.A.24, 15.1.10, and 15.2.1.b.
                              - 34 -                                 Enclosure

b. Findings .1 Task Closure

  Each task within the SIIP required a closure package along with varying levels of
  management review for closure based on the priority of the corrective action. The
  inspectors reviewed a total of 33 tasks associated with the licensees SIIP. These tasks
  were in various stages of the closure process, including some items that were still open.
  The SIIP task closure packages were reviewed in accordance with Procedure 01DP-
  0AC06, "SIBP/SIIP Process," Revision 3, to determine if PVNGS personnel were
  following the closure process. The process has three closure categories:
  *       Category A - included significant conditions adverse to quality and CAL items
  *       Category B - included adverse conditions and improvement plan Priority 3
          CRAIs
  *       Category C - included improvement plan Priority 4 CRAIs.
  Category A tasks get the most reviews including: the standard CRDR/CRAI closure
  process; initiative lead concurs that the action is ready for closure; reviewed and
  approved by the CRB; and, independent reviews from senior management led boards.
  During the review of the SIIP tasks, the inspectors identified numerous quality issues,
  including closure packages for Tasks 3.6.62, 3.7.3.p, 5.1.E.3, and 9.1.A.8, as follows:
  *       Closure package for Task 3.6.62, "identify and classify components in the PK
          system," was inappropriately closed with outstanding reviews not completed to
          ensure operability of the PK system. For details, refer to Section .3 below.
  *       Closure package for Task 3.7.3.p, "implement design modification for the Unit 1
          containment sump suction valves," was closed without supporting documentation
          to demonstrate that testing had verified the containment sump piping was full of
          water after the modifications were completed. This action was completed, but
          the completion documentation was missing.
  *       Closure package for Task 5.1.E.3, "incorporate operability determination in
          engineering continuing training program requirements," was submitted without
          demonstrating that the training was effective. The inspectors determined that the
          submitted package quality failed to meet the purpose to enhance the skill and
          knowledge of engineers performing operability determinations. The package
          took credit for general engineering lessons learned training that was conducted in
          April and May 2007. The CRB also recognized that operability determination
          concerns still existed and additional efforts were needed. CRDR 3095373 was
          initiated and it contained 24 CRAIs to address the continuing problems with
          operability determinations. Additional inspections will be required to close CAL
          SIIP Task 5.1.E.3.
  The inspectors also reviewed the SIIP quality PIs, interviewed numerous personnel, and
  reviewed several Nuclear Assurance evaluations related to CAL SIIP actions. The
  licensee has been and continued to provide training to the task owners on
  Procedure 01DP-0AC06 closure process, and was also providing coaching to
                                       - 35 -                                 Enclosure
  individuals. Packages can be unsatisfactory for many reasons including: improper
  formatting, missing signatures, incomplete documentation, lack of demonstrated
  implementation, inadequate corrective actions, and inadequate sustainability
  requirements. The closure review process was described in Procedure 01DP-0AC06,
  Appendix L, SIBP/SIIP Action Closure Flowchart, and contained two quality control
  steps, administrative and preliminary reviews. Numerous packages that were submitted
  for closure did not meet the closure review checklist criteria and were sent back to the
  owners for correction prior to CRB review. The licensee was in the early stage of task
  closure and overall package quality needs to be improved.
  Nuclear Assurance Evaluation 08-0024, dated March 4, 2008, determined that the
  backlog of closure reviews and approvals was growing and that the rejection rate was
  high. As of February 4, 2008, 246 packages were submitted and 145 did not meet the
  standards during the administrative and preliminary reviews and were returned to the
  responsible owners. Those owners were provided feedback to improve the quality of the
  closure packages. During the same time period, the CRB reviewed 55 closure packages
  and CRB only accepted 40 packages for closure (of those, 30 packages had minor
  changes that needed to be made and were verified acceptable by the CRB chairman).
  Approximately 25 percent of the packages submitted to CRB required additional work.
  In reviewing recent SIIP quality PIs, it appears that package quality was improving, but
  no trend was available since the indicators were for January and February 2008. For
  comparison between January and February 2008, document quality was as follows: four
  packages verses 44 packages were accepted by the CRB without comments; 13
  packages verses one package were accepted by the CRB with comments; four
  packages for both January and February were tabled (not reviewed by the CRB); and
  five packages verses zero packages were rejected. The inspectors attended several
  recent CRB meetings and found the packages reviewed to be of higher quality.

.2 Metrics and Measures to Monitor Improvement

  During the inspection, the licensee was still in the process of finalizing the SIIP PIs.
  These indicators will not be finalized until PVNGS provides details of their actions to
  address each item of the CAL dated February 15, 2008, which was submitted to the
  NRC on March 31, 2008. The licensee developed eight additional PIs to track the
  quality and schedule completion of SIIP tasks. The inspectors reviewed a sample of
  these draft PIs and determined that most of the indicators appeared appropriate and
  should provide useful information. However, the inspectors determined that not enough
  time had passed to assess trends or determine the appropriateness of the goals and
  thresholds.
  The SIIP PIs used to track the schedule completion of the tasks were somewhat
  misleading because they used the site work management system completion dates
  verses SIIP completion dates. At the end of the inspection, none of the Category A
  closure packages (highest level and includes over 500 CAL SIIP items) were completely
  closed. Only 13 of over 500 CAL SIIP items were accepted by the CRB and these had
  not received the independent reviews required by Procedure 01DP-0AC06.
                                       - 36 -                                 Enclosure

.3 Failure to Implement Corrective Action Process for Class 1E 125 Vdc System

  Introduction. The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B,
  Criterion V, "Instructions, Procedures, and Drawings," for the failure of engineering
  personnel to ensure that potentially nonconforming conditions associated with the
  PK system were reviewed for operability.
  Description. On September 22, 2006, a root cause evaluation was documented in
  CRDR 2926830 for the Unit 3 EDG K1 contactor repeat failure, as discussed in NRC
  Inspection Report 05000528; 05000529; and 05000530/2006012. The licensee's root
  cause evaluation stated the root cause to be that the "K1 contactor was treated as a
  single reliable component; therefore, subcomponents of the K1 contactor mechanics
  were not fully understood. This lack of understanding produced ineffective PM tasks for
  the EDG field flash and de-excitation circuits." On May 15, 2007, during the extent of
  cause/condition review for CRDR 2926830, the licensee wrote CRAI 3014243 to
  address the following in other systems: identify and classify any auxiliary contacts,
  relays, starters, or contactors that had moving parts which break or make contacts
  and/or had physical adjustments; of those components identified, determine if
  dimensional criteria is given for the components as described in the vendor technical
  documents (VTDs); and if criteria is given, determine if the criteria is verified through
  PM tasks.
  On July 20, 2007, the licensee initiated CRAI 3042095 that looked at this extent of cause
  for the PK system. The CRAI evaluation identified over 300 relays and starters in the PK
  system that either required periodic gap/wipe adjustments in accordance with their
  VTDs, but had no PM to verify proper alignment; or had existing PMs, but the VTD
  adjustment requirements were not adequately reflected in the PMs. The licensee
  dispositioned this as an enhancement to create or modify these PMs, and on
  September 29, 2007, wrote CRAI 3069502 to track the completion of the necessary PM
  creation and revision tasks.
  The Palo Verde Site Integrated Business Plan (SIBP)/SIIP, Initiative 3.6, addressed
  corrective actions associated with the EDG K1 Relay. Specifically, Task 3.6.62
  addressed the extent of cause/condition to the PK system and performed the actions
  specified in CRAI 3042095. During review of the closure documentation associated with
  Task 3.6.62 on March 3, 2008, the reviewers concurred with the conclusion of writing
  CRAI 3069502 that tracked the creation and modification of PMs for the affected
  PK components.
  On March 11, 2008, inspectors reviewed SIBP/SIIP Closure Document for Task 3.6.62.
  The affected relays and starters in the PK system potentially did not conform to the
  vendor technical documents since adjustments were possible, but were not being
  verified through PMs. Inspectors questioned whether this constituted a potentially
  degraded/nonconforming condition instead of an enhancement as dispositioned in
  CRAI 3042095. Procedure 90DP-0IO10, "Condition Reporting," Revision 36,
  Step 3.3.1.12 states, in part, that during the course of a CRDR evaluation, if additional
  conditions unrelated to the original condition are discovered, a new PVAR for each new
  condition shall be initiated and submitted for review in accordance with
  Procedure 01DP-0AP12, "Palo Verde Action Request Processing," Revision 4.
  Procedure 01DP-0AP12, Step 3.5 states, in part, that the condition described in the
  PVAR shall be evaluated by the SM for the assessment of potential operability concerns.
                                       - 37 -                                 Enclosure
  Based on the inspectors concerns, the licensee wrote PVAR 3144707 and performed an
  immediate operability determination in accordance with Procedure 40DP-9OP26,
  "Operability Determination and Functional Assessment," Revision 18. The immediate
  operability determination stated the affected PK components were operable based on all
  surveillances of the associated valves and equipment being current, and that there were
  no known failures in these control circuits.
  Analysis. The performance deficiency associated with this finding was the failure of
  engineering personnel to ensure that potentially nonconforming conditions associated
  with the PK system were reviewed for operability. This finding is greater than minor
  because it is associated with the equipment performance attribute of the mitigating
  systems cornerstone and affects the cornerstone objective to ensure 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
  because it did not represent a loss of system safety function, an actual loss of safety
  function of a single train for greater than its TS allowed outage time, or screen as
  potentially risk-significant due to a seismic, flooding, or severe weather initiating event.
  This finding has a crosscutting aspect in the area of human performance associated with
  decision-making because safety-significant decisions were not verified to validate
  underlying assumptions and identify unintended consequences [H.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 resolution of adverse conditions is
  implemented by Procedure 90DP-0IO10, "Condition Reporting," Revision 36.
  Procedure 90DP-0IO10, Step 3.3.1.12 states, in part, that during the course of a CRDR
  evaluation, additional conditions unrelated to the original condition are discovered, a new
  PVAR for each new condition shall be initiated and submitted for review in accordance
  with Procedure 01DP-0AP12, "Palo Verde Action Request Processing," Revision 4.
  Procedure 01DP-0AP12, Step 3.5 states, in part, that the condition described in the
  PVAR shall be evaluated by the SM for the assessment of potential operability concerns.
  The assessment of operability of safety-related equipment needed to mitigate accidents
  is implemented by Procedure 40DP-9OP26, "Operability Determination and Functional
  Assessment," Revision 18. Contrary to the above, between September 29, 2007 and
  March 7, 2008, engineering personnel failed to ensure that potentially nonconforming
  conditions associated with the PK system were reviewed for operability. Specifically,
  engineering personnel failed to ensure all relevant information was reviewed for
  operability when it was determined that vendor recommended preventative maintenance
  tasks were not being performed on PK system. Because this finding is of very low safety
  significance and has been entered into the CAP as PVAR 3144707, this violation is
  being treated as an NCV, consistent with Section VI.A.1 of the Enforcement Policy:
  NCV 05000528; 05000529; 05000530/2008002-05, "Failure to Properly Implement
  Corrective Action Process for Potential Operability Issues with the Class 1E 125 Vdc
  System."

.4 Cross-References to Problem Identification and Resolution Observations and Findings

  Documented Elsewhere
  Section 1R15 describes a finding where operations and engineering personnel failed to
  use available operating experience, including vendor recommendations, to implement
                                        - 38 -                               Enclosure
    and institutionalize operating experience through changes to station processes,
    procedures, equipment, and training programs.
    Section 4OA2.4 describes a finding where CAP personnel failed to ensure a proper
    classification and prioritization of two CRDRs. The inspector evaluated the effectiveness
    of the licensees problem identification and resolution process with respect to the
    following inspection areas:
    *        Access Control to Radiologically Significant Areas (Section 2OS1)
    *        ALARA Planning and Controls (Section 2OS2)

4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)

    Event Follow-Up
 a. Inspection Scope
    The inspectors reviewed the four below listed events and degraded conditions for plant
    status and mitigating actions to: (1) provide input in determining the appropriate agency
    response in accordance with Management Directive 8.3, "NRC Incident Investigation
    Program;" (2) evaluate performance of mitigating systems and licensee actions; and
    (3) confirm that the licensee properly classified the event in accordance with EAL
    procedures and made timely notifications to NRC and state/governments, as required.
    *        January 13, 2008, a RO noticed a SFP level change on the control room remote
             camera while an auxiliary operator (AO) was performing an evolution on the pool
             cooling (PC) system
    *        January 20-March 15, 2008, Units 1, 2, and 3, design issues with remote
             shutdown disconnect switches to the remote shutdown panel
    *        January 22, 2008, Unit 3, dry cask storage platforms stored in the fuel building
             did not meet seismic requirements and could have affected pump room exhaust
             air cleanup system Trains A and B
    *        January 25, 2008, Units 1, 2, and 3, EDG fuel oil injection pump leakage that
             impacted EDG operability
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed four samples.
 b. Findings
    Introduction. A Green self-revealing NCV of TS 5.4.1.a was identified for the failure of
    operations personnel to follow procedures, which resulted in an inadvertent transfer of
    SFP water to the refueling water tank (RWT).
    Description. On January 13, 2008, the Unit 3 control room supervisor directed an AO to
    place PC cleanup Filter PCN-F01B in service or standby following filter replacement per
    Procedure 40OP-9PC06, "Fuel Pool Clean-up and Transfer," Revision 41. A pre-job
    briefing was performed where the pool cooling lineup was discussed. Specifically, it was
                                          - 39 -                              Enclosure

communicated to the AO that PC cleanup Train A was in service and that PC cleanup Train B was secured. It was, however, noted that PC cleanup Train B had recently been aligned for RWT recirculation/cleanup. The system drawing was not referenced during the pre-job briefing to verify the flowpath and ensure that the current system lineup was understood. The AO made an erroneous assumption during the valve alignment and marked Procedure 40OP-9PC06, Step 10.6.2.3, as not applicable since he believed Filter PCN-F01B Bypass Valve PCN-061 was not in the current flowpath. Step 10.6.2.3 would have closed Valve PCN-V061. This assumption was in error since Valve PCN-V061 was in the current flowpath due to the recent RWT recirculation/cleanup alignment. Consequently, Step 10.6.2.3 was not performed and Valve PCN-V061 was left open. When Step 10.6.2.5 was performed to open cleanup pump cross-tie isolation Valve PCN V045, a flowpath was established from PC cleanup Train A, through PC cleanup Train B to the RWT. The water transfer event was stopped by isolating the flowpath after a RO noticed a SFP level change on the control room remote camera and notified the AO. As a result of the improper alignment, an estimated 300 gallons of SFP inventory was transferred to the RWT. Similar events occurred between April 2003 and April 2006, when valves associated with the SFP were inappropriately positioned, resulting in a loss of SFP inventory. The events were documented in NCVs 05000528; 05000529; 05000530/2004003-09, 05000528/2005003-04, and 05000530/2006003-04. Analysis. The performance deficiency associated with this finding involved operations personnel not following procedures. The finding is greater than minor because it is associated with the configuration control and human performance attributes of the barrier integrity cornerstone and affects the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, the finding is determined to have very low safety significance because the finding did not result in loss of cooling to the SFP; the finding did not result from fuel handling errors that caused damage to the fuel clad integrity or a dropped assembly; and the finding did not result in a loss of SFP inventory greater than ten percent of the SFP volume. This finding has a crosscutting aspect in the area of human performance associated with work practices because the licensee failed to use adequate human error prevention techniques, such as pre-job briefings, to ensure that the pool cooling cleanup system activity was performed safely [H.4(a)]. Enforcement. Technical Specification 5.4.1.a requires that written procedures be established, implemented, and maintained covering the activities specified in Regulatory Guide 1.33, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Section 3.h, Procedures for Startup, Operation, and Shutdown of Safety-Related PWR Systems, which requires procedures for operating the fuel storage pool purification and cooling system. Procedure 40OP-9PC06, "Fuel Pool Cleanup and Transfer," Revision 41, provided instructions for placing a cleanup filter in service or standby. Contrary to the above, on January 13, 2008, operations personnel failed to properly implement Procedure 40OP-9PC06 for operating the PC cleanup system, resulting in Filter PCN-F01B Bypass Valve PCN-V061 being improperly aligned. This resulted in an inadvertent transfer of SFP water to the RWT. Because this finding is of very low safety significance and has been entered into the licensee's CAP as CRDR 3121713, this

                                     - 40 -                                 Enclosure
  violation is being treated as an NCV consistent with Section VI.A.1 of the Enforcement
  Policy: NCV 05000530/2008002-06, "Failure to Follow Procedures Resulted in Water
  Transfer from the Spent Fuel Pool."
  Event Report Reviews

a. Inspection Scope

  The inspectors reviewed the four below listed LERs and related documents to assess:
  (1) the accuracy of the LER; (2) the appropriateness of corrective actions; (3) violations
  of requirements; and (4) generic issues.

b. Findings .1 (Closed) LER 05000528/2006-003-00, "EDG Actuation on Loss of Power to A Train 4.16

  Kilovolt Bus"
  On May 30, 2006, Unit 1 was defueled, when an invalid load shed signal was received
  from the balance of plant engineered safety features actuation system load sequencer
  Train A resulting in a loss of power (LOP) to safety-related electrical Bus PBAS03. Prior
  to the LOP, EDG Train A had been manually removed from Bus PBAS03 following a
  maintenance surveillance test and was still operating in a post-run cooldown mode. The
  normal offsite power source had been restored to Bus PBAS03.
  The deenergization of Bus PBAS03 caused a valid LOP signal which resulted in EDG
  Train A receiving a valid emergency run signal. EDG Train A returned to rated
  frequency and voltage; however, its output breaker did not close because the load
  sequencer had locked-up, thus, preventing the closure signal to the EDG output breaker.
  Operations personnel completed actions to isolate the balance of plant engineered
  safety features actuation system load sequencer Train A, and energize electrical
  Bus PBAS03 from its normal offsite power supply approximately six hours after the LOP.
  Through extensive troubleshooting and reviews of previous events caused by the load
  sequencer, the licensee's investigation determined that the most probable cause for the
  event was from electrical noise/interference which affected the operation of the load
  sequencer. Corrective actions included the installation of a design modification to
  reduce electromagnetic interference in the sequencer. Suspect relays and noise
  suppression networks were also replaced in the EDG control cabinet, and several
  connections in the cabinet were reworked to further reduce the electrical noise. The
  LER was reviewed by the inspectors and no findings of significance were identified and
  no violation of NRC requirements occurred. The licensee documented the failed
  equipment in CRDR 2899375. This LER is closed.

.2 (Closed) LER 05000529/2006004-00, "Unit 2 Feedwater Isolation Valve Inoperability

  Results in Condition Prohibited by Technical Specifications"
  On July 27, 2006, the Unit 2 hydraulic accumulator for main feedwater isolation Valve
  (MFIV) 2JSGAUV0174 would not recharge due to a failed four-way valve lodged in the
  center block position. Evaluation of the valve concluded this condition would have
  prevented fast closure of Valve 2JSGAUV0174 upon receipt of a main steam isolation
  signal and had existed since July 13, 2006. This outage time exceeded the time
  requirements of TS 3.7.3.c, to place the plant in Mode 3 within 6 hours and Mode 6
  within 36 hours. The cause of the TS violation was the failure of operations personnel to
                                      - 41 -                                Enclosure

identify that Valve 2JSGAUV0174 "N" four-way valve did not return to the standby position following accumulator pressure reduction. The four-way valve was replaced and the MFIV operating procedure was revised to verify the four-way valves return to their required position. The licensee documented the failed equipment in CRDR 2915450. This LER is closed. Introduction. A Green self-revealing NCV of TS 3.7.3.c was identified for the failure of Unit 2 operations personnel to perform the actions specified in TS 3.7.3 for an inoperable MFIV, resulting in MFIV 2JSGAUV0174 to SG 1 exceeding the TS 3.7.3 allowed outage time. Description. On July 27, 2006, operations personnel declared MFIV 2JSGAUV0174 to SG 1 inoperable as a result of the hydraulic accumulator for Valve 2JSGAUV0174 failing to recharge. This failure occurred when the four-way "N" valve for Valve 2JSGAUV0174 became lodged in the center blocked position such that flow to the hydraulic accumulator was blocked. This would have prevented fast closure of Valve 2JSGAUV0174 upon receipt of a main steam isolation signal and had existed since July 13, 2006. The safety function of this MFIV is to provide containment isolation between the steam generators and the feedwater line in the event of a main steam line break, feedwater line break, or loss of reactor coolant accident. The MFIVs isolate main feedwater flow to the secondary side of the SGs following a high energy line break. Closure of the MFIVs terminates flow to both SGs, terminating the event for feedwater line breaks occurring upstream of the MFIVs. The safety function of the MFIV, to provide containment isolation, was not affected since the redundant valve, MFIV 2JSGBUV0132, on the economizer line would have closed. The normal position and the safety position for Valve 2JSGAUV0174 four-way "N" valve is in the open position to port accumulator nitrogen to fast close the MFIVs. Valve 2JSGAUV0174 was declared inoperable on July 27, 2006, and the "N" four-way valve was replaced. Engineering personnel evaluated the accumulator pressure trends and determined the "N" valve had been lodged in the blocked position since the last time operations personnel reduced pressure on July 13, 2006. A root cause investigation was conducted and documented in CRDR 2915450. The root cause investigation identified the cause to be the inability to detect the failure of the four-way "N" valve when using Procedure 40OP-9SG01, "Main Steam," Revision 53. Procedure 40OP-9SG01, Step 4.5, is used to verify the nitrogen precharge of the accumulators by turning the MFIV exercise/accumulator charge test switch to "ACC CH TEST," which shuttles the "N" four-way valve to bleed off accumulator hydraulic fluid. After verifying the nitrogen pre-charge, operations personnel turn the switch back to normal which causes the actuator air operated hydraulic pump to recharge the accumulator. Further, Procedure 40OP-9SG01, Step 4.6.10, is used if pressure becomes too high in the accumulators, then operations personnel reduce pressure by cycling the exercise/accumulator charge test switch to "ACC CH TEST," which cycles the "N" four-way valve to bleed off a slight amount of pressure. This process should automatically return the "N" four-way valve to its required position. Procedure 40OP-9SG01 did not provide a step to verify the position of the "N" four-way valve after cycling the valve. The action to prevent recurrence was to revise the procedure to require verification of hydraulic pump start and accumulator pressure increase greater than 100 pounds per square inch. The ability to increase accumulator pressure indicates the "N" four-way valve has returned to its proper position to support

                                    - 42 -                                  Enclosure
  MFIV operation. The direct cause of the failure of Valve 2JSGAUV0174 "N" four-way
  valve is unknown.
  This issue is similar to an event from June 1998 when the Unit 3 MFIV 3JSGAUV0177
  "N" four-way valve was found lodged in the center blocked position as described in
  CRDR 380142.
  Analysis. The performance deficiency associated with this finding involved the failure of
  operations personnel to perform the actions specified in TS 3.7.3.c. This finding is
  greater than minor because it is associated with the equipment performance attribute of
  the mitigating systems cornerstone and affects the cornerstone objective to ensure the
  availability and reliability of systems that respond to initiating events to prevent
  undesirable consequences. A Phase 2 analysis is required because the Manual
  Chapter 0609, "Significance Determination Process," Phase 1 Worksheets, determined
  that there was a loss of main feedwater isolation of a single train to SG 1 for greater than
  the TS allowed outage time. The initiating event likelihood is determined to be three to
  30 days since the finding occurred between July 17 and 27, 2006. Using the Phase 2
  Worksheets associated with a SG tube rupture without SG isolation, the finding is
  determined to only affect Sequence 2, with operator action credit reduced to zero, the
  finding is determined to have very low safety significance since all remaining mitigation
  capability was available or recoverable.
  Enforcement. Technical Specification 3.7.3.a requires that with one MFIV inoperable,
  actions must be taken to close or isolate the inoperable valve within 72 hours. If these
  actions are not completed, TS 3.7.3.c requires the unit be placed in Mode 3 within
  6 hours, and in Mode 5 within 36 hours. Contrary to the above, on July 17, 2006,
  operations personnel failed to perform the actions specified in TS 3.7.3.c. Specifically,
  on July 17, 2006, operations personnel failed to perform actions to place the unit in
  Mode 3 within 6 hours and Mode 5 within 36 hours, as required by TS 3.7.3.c for an
  inoperable MFIV that had not been closed or isolated in 72 hours, as required by
  TS 3.7.3.a. This resulted in MFIV 2JSGAUV0174 to SG 1 exceeding the TS 3.7.3
  allowed outage time. Because this finding is of very low safety significance and has
  been entered into the licensee's CAP as CRDR 2915450, this violation is being treated
  as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy:
  NCV 05000529/2008002-07, "Failure to Identify Inoperable Feedwater Isolation Valve
  Exceeds Technical Specification Allowed Outage Time."

.3 (Closed) 05000529/2006005-00, "Reactor Head Vent Axial Indications Caused by

  Degraded Alloy 600 Component"
  On October 7, 2006, engineering personnel performing preplanned in-service
  examinations of the Unit 2 reactor vessel head vent penetration discovered two axial
  indications. Operation personnel entered TS Limiting Condition for Operations 3.4.103,
  Condition A, and made an eight hour notification to the NRC for a nonconforming
  condition of the RCS. The indications were located on the inner diameter surface of the
  pipe adjacent to the J-weld to the head. The licensee determined that these indications
  were due to primary water stress corrosion cracking. The licensee removed the flaws by
  machining away approximately one inch of the vessel head vent. These removed
  indications were similar to indications found on April 23, 2005, during the previous
  refueling outage. This issue was previously noted on LER 05000529/2005001, and the
  licensee's corrective actions at that time included machining the inside surface of the
  pipe, and verifying no indications by examination. The LER was reviewed by the
                                        - 43 -                                 Enclosure
    inspectors and no findings of significance were identified and no violations of NRC
    requirements occurred. The licensee documented the problem in CRDR 2931237. This
    LER is closed.
 .4 (Closed) LER 05000529/2006006-00 and 05000529/2006-01, "Technical
    Specification 3.7.7 Violation for an Inoperable Essential Cooling Water Heat Exchanger"
    The event described in this LER was previously discussed in NRC Inspection
    Report 05000528/2006011; 05000529/2006011; 05000530/2006011, and documented
    as NCV 0500529/2006011-01, EW Train 2B Inoperable Longer than Allowed Outage
    Time. The inspectors reviewed this LER and its supplement and no additional findings
    were identified. This LER is closed.
    Personnel Performance
 a. Inspection Scope
    On January 3, 2008, inspectors reviewed the pressurizer level decrease to below TS
    limits during the performance of AFW Pump AFA-P01 full flow testing on Unit 3. The
    inspectors: (1) reviewed operator logs, plant computer data, and/or strip charts for the
    below listed evolutions to evaluate operator performance in coping with nonroutine
    events and transients; (2) verified that operator actions were in accordance with the
    response required by plant procedures and training; and (3) verified that the licensee
    has identified and implemented appropriate corrective actions associated with personnel
    performance problems that occurred during the nonroutine evolutions sampled.
    Documents reviewed by the inspectors are listed in the attachment.
    The inspectors completed one sample.
 b. Findings
    No findings of significance were identified.

4OA5 Other Activities

 a. Inspection Scope
    The inspectors reviewed the Institute of Nuclear Power Operations assessment dated
    July 2007.
 b. Findings
    No findings of significance were identified.

4OA6 Meetings, Including Exit

    On January 8, 2008, the inspectors presented the inspection results of the in-office
    review of licensee changes to the emergency plan and EALs, on a telephonic exit, to Mr.
    E. ONeil, Department leader, Emergency Preparedness, and other members of the
    licensee's management staff at the conclusion of the inspection. The licensee
    acknowledged the findings presented.
                                        - 44 -                                Enclosure
    On February 15, 2008, the inspectors presented the occupational radiation safety
    inspection results to Mr. L. Cortopassi, Plant Manager, and other members of the
    licensee's management staff at the conclusion of the inspection. The licensee
    acknowledged the findings presented.
    On February 15, 2008, the inspectors presented the biennial emergency preparedness
    inspection results to Mr. R. Edington, Executive Vice President, Nuclear, and Chief
    Nuclear Officer, and other members of the licensee's management staff at the
    conclusion of the inspection. The licensee acknowledged the findings presented.
    On March 12, 2008, the inspectors presented the inspection results of the in-office
    review of licensee changes to the emergency plan, on a telephonic exit, to Mr. E. ONeil,
    Department leader, Emergency Preparedness, and other members of the licensee's
    management staff at the conclusion of the inspection. The licensee acknowledged the
    findings presented.
    On April 16, 2008, the inspectors presented the inspection results to Mr. R. Edington,
    Executive Vice President, Nuclear, and Chief Nuclear Officer, and other members of the
    licensee's management staff at the conclusion of the inspection. The licensee
    acknowledged the findings presented.
    The inspectors noted that while proprietary information was reviewed, none would be
    included in this report.

4OA7 Licensee-Identified Violations

    The following violations of very low safety significance (Green) were identified by the
    licensee and are a violation of NRC requirements that meet the criteria of Section VI.A.1
    of the NRC Enforcement Policy, NUREG-1600, to be dispositioned as NCVs.
    *       10 CFR 50.54(q) of Title 10 of the Code of Federal Regulations requires the
            licensee to follow their emergency plan. Contrary to the above, between 2002
            and 2007, training personnel did not administer annual emergency preparedness
            training to all employee site badge holders, as required by Section 8.1.1 of the
            Emergency Plan. The finding was entered into the CAP as CRDR 2966025. The
            finding is of very low safety significance because it is associated with Planning
            Standards 50.47(b)(7) and 50.47(b)(15), is not a functional failure of the planning
            standards because all employees received initial general emergency
            preparedness training, and means existed to inform holders of site badges about
            the actions they should take during an emergency.
    *       Technical Specification Surveillance Requirement 3.3.11.2 requires that each
            remote shutdown system disconnect switch and control circuit is verified capable
            of performing the intended function. Contrary to the above, between
            January 20, 2008 and March 15, 2008, Procedure 40ST-9ZZ20, "Remote
            Shutdown Disconnect Switch and Control Circuit Operability," Revision 10, did
            not verify all circuit paths associated with each disconnect switch were
            adequately tested. This issue affected all the disconnect switches to the remote
            shutdown panel.
                                          - 45 -                               Enclosure
         The licensee entered into TS Surveillance Requirement 3.0.3 for a missed
         surveillance, performed a risk evaluation, and tested the most risk-significant
         disconnect switches to verify that these disconnect switches could perform their
         intended function. Of the risk-significant disconnect switches tested, the licensee
         identified that one disconnect switch associated with Unit 1 AFW pump to SG 1
         block Valve AFB-UV-34 would not have been capable of performing it's intended
         function due to an electrical jumper installed in the closing circuit. This valve is in
         the flow path from the motor driven AFW pump to SG 1. However, the potential
         failure of this valve would not have affected the ability to maintain a shutdown
         condition, because the flowpath to the SG 2 was not affected. The finding was
         entered into the CAP as PVARs 3129077, 3135575, 3136664, 3138937 and
         3144595. Using Manual Chapter 0609, "Significance Determination Process,"
         Appendix F, "Fire Protection Significance Determination Process," the finding is
         determined to have very low safety significance because at Step 1.3, Qualitative
         Screening Approach, the finding only affected the ability to reach and maintain a
         cold shutdown condition.

ATTACHMENT: SUPPLEMENTAL INFORMATION

                                      - 46 -                                 Enclosure
                               SUPPLEMENTAL INFORMATION
                                 KEY POINTS OF CONTACT

Licensee G. Andrews, Director, Performance Improvement S. Bauer, Department Leader, Regulatory Affairs J. Bayless, Senior Engineer R. Bement, Vice President, Nuclear Operations P. Borchert, Unit 1 Assistant Plant Manager P. Brandjes, Department Leader, Maintenance J. Bungard, Radiological Engineer R. Buzard, Section Leader, Compliance D. Carnes, Unit 2 Assistant Plant Manager P. Carpenter, Department Leader, Operations R. Cavalieri, Director, Outages K. Chavet, Senior Consultant, Regulatory Affairs L. Cortopossi, Plant Manager, Nuclear Operations D. Coxon, Unit Department Leader, Operations E. Dutton, Acting Director of Nuclear Assurance D. Elkington, Consultant, Regulatory Affairs T. Engbring, Senior Engineer J. Gaffney, Director, Radiation Protection T. Gray, Department Leader, Radiation Protection K. Graham, Department Leader, Fuel Services M. Grigsby, Unit Department Leader, Operations D. Hautala, Senior Engineer, Regulatory Affairs R. Henry, Site Representative, SRP J. Hesser, Vice President, Engineering G. Hettel, Director, Operations A. Huttie, Director, Emergency Services R. Indap, Senior Engineer M. Karbasian, Director, Design Engineering W. Lehman, Senior Engineer J. McDonnell. Department Leader, Radiation Protection S. McKinney, Department Leader, Operations Support J. Mellody, Department Leader, PV Communications E. ONeil, Department leader, Emergency Preparedness F. Poteet, Senior ISI Engineer M. Radspinner, Section Leader, Systems Engineering T. Radtke, General Manager, Emergency Services and Support H. Ridenour, Director, Maintenance F. Riedel, Technical Management Assistant, Nuclear Operations S. Sawtschenko, Department Leader, Emergency Preparedness J. Scott, Section Leader, Nuclear Assurance M. Shea, Director, IMPACT E. Shouse, Representative, El Paso Electric M. Sontag, Department Leader, Performance Improvement J. Summy, Director, Plant Engineering K. Sweeney, Department Leader, Systems Engineering

                                          A-1                Attachment

J. Taylor, Nuclear Project Manager, PNM J. Taylor, Unit Department Leader, Operations D Vogt, Section Leader, Operations Shift Technical Advisor J. Waid, Director, Nuclear Training T. Weber, Section Leader, Regulatory Affairs J. Wood, Department Leader, Nuclear Training Department T. Young, Director, Communications Nuclear Regulatory Commission M. Runyan, Senior Reactor Analyst, Region IV

                   LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000528; 05000529;        NCV     Failure to Establish Preventative Maintenance Procedures
05000530/2008002-01                for Emergency Diesel Generator Fuel Oil Injection Pump
                                   O-rings (Section 1R15)
05000530/2008002-02        NCV     Two Examples of a Failure to Properly Implement the
                                   Systematic Troubleshooting Process (Section 1R19)
05000529/2008002-03        NCV     Inadequate Procedure to Evaluate Foreign Material in the
                                   Spent Fuel Pool (Section 4OA2)
05000528; 05000529;        NCV     Failure to Maintain Adequate Staffing Levels Results in
05000530/2008002-04                Heavy Use of Overtime to Maintain Adequate Shift
                                   Coverage (Section 4OA2)
05000528; 05000529;        NCV     Failure to Properly Implement Corrective Action Process
05000530/2008002-05                for Potential Operability Issues with the Class 1E
                                   125 V DC System (Section 4OA2)
05000530/2008002-06        NCV     Failure to Follow Procedures Resulted in Water Transfer
                                   from the Spent Fuel Pool (Section 4OA3)
05000529/2008002-07        NCV     Failure to Identify Inoperable Feedwater Isolation Valve
                                   Exceeds Technical Specification Allowed Outage Time
                                   (Section 4OA3)
                                         A-2                                  Attachment

Closed

 05000528/2006003-00       LER     EDG Actuation on Loss of Power to A Train 4.16KV Bus
                                   (Section 4OA3)
 05000529/2006004-00       LER     Unit 2 Feedwater Isolation Valve Inoperability Results in
                                   Condition Prohibited by Technical Specifications
                                   (Section 4OA3)
 05000529/2006005-00       LER     Reactor Head Vent Axial Indications Caused by Degraded
                                   Alloy 600 Component (Section 4OA3)
 05000529/2006006-00       LER     Technical Specification 3.7.7 Violation for an Inoperable
 and                               Essential Cooling Water Heat Exchanger (Section 4OA3)
 05000529/2006006-01
 05000528; 05000529;       URI     Routine Heavy Use of Overtime (Section 4OA2)
 05000530/2007012-18

Discussed None

                             LIST OF DOCUMENTS REVIEWED

In addition to the documents called out in the inspection report, the following documents were selected and reviewed by the inspectors to accomplish the objectives and scope of the inspection and to support any findings: Section 1R04: Equipment Alignment Procedures

 NUMBER              TITLE                                                     REVISION
 40OP-9DG02          Emergency Diesel Generator B, Appendix A - DG             51
                     "B" Valve Checklist
 40OP-9DG02          Emergency Diesel Generator B, Appendix B - DG             51
                     "B" Electrical Checklist
 40OP-9ZZ04          Plant Startup Mode 2 To Mode 1                            53
 40OP-9ZZ05          Power Operations                                          123
 40OP-9NA03          13.8 kV Electrical System (NA)                            30
                                           A-3                                  Attachment

Drawings

NUMBER              TITLE                                             REVISION
02-M-ECP-001        P&I Diagram, Essential Chilled Water System       29
02-M-SIP-002        P&I Diagram, Essential Spray Pond System, Sheet 1 40
                    of 3
02-M-SIP-001        P&I Diagram, Safety Injection & Shutdown Cooling  37
                    System
13-E-MAA-001        Main Single Line Diagram                          23
01-M-DGP-001        P&I Diagram Diesel Generator System, Sheets       49
                    1through 9
13-E-MAA-001        Main Single Line Diagram                          23

Work Orders

3025982     3025983

Miscellaneous Schedulers Evaluation for Palo Verde Unit 1, week of March 10, 2008 Schedulers Evaluation for Palo Verde Unit 1, week of January 14, 2008 System Health Report, January 1, 2007, through June 30, 2007 Section 1R05: Fire Protection Procedures

NUMBER              TITLE                                             REVISION
14DP-0FP33          Control of Transient Combustibles                 15
14DP-0FP33          Control of Transient Combustibles                 16
14FT-9FP42          Monthly Portable Fire Extinguisher Inspection     9

Miscellaneous Technical Requirements Manual 3.11, Revision 44 PVNGS Pre-Fire Strategies Manual, Revision 19 UFSAR Appendix 9B, Fire Protection Evaluation Report, Revision 14 UFSAR Section 9.5.1, Fire Protection Evaluation Report, Revision 14 Section 1R11: Licensed Operator Requalification Program Procedures

NUMBER              TITLE                                             REVISION
EPIP-01             Satellite Technical Support Center Actions        24
                                         A-4                          Attachment
EPIP-99             Emergency Plan Implementing Procedure,            20
                    Appendices A and P

PVARs

3137869    3139481     3139486

Miscellaneous SES-0-07-E-02, Loss of PKC-M43/LOOP, Licensed Operator Continuing Training Simulator Evaluation Guide Licensed Operator Continuing Training 2008 Weekly Schedule Cycle NLR08-02, Revision 0 Simulator Evaluation Summary Sheet, Crew 33, Cycle NLR08-02 Section 1R12: Maintenance Effectiveness Procedures

NUMBER              TITLE                                             REVISION
70DP-0MR01          Maintenance Rule                                  17
01DP-9ZZ01          Systematic Troubleshooting                        1

PVARs

2951473    2954664     2963881     2964221    2995235   2988892    3005648    3027524
3053912    3092611     3093774     3094517    3114753   3119518    3119520    3124489
3125979    3126297     3130468

CRDRs

2945319    3095450

Work Orders

3092613    3129996

Miscellaneous January 1-June 30, 2007,DG- Diesel Generator System Health Report Maintenance Rule System Basis Document, DG - Diesel Generator, Revision 3 Reactor Protection System Health Report Westinghouse Drawing E-14273-435-501, APC - Channel A Wiring Diagram, Sheet 3 of 11, Revision 5 Westinghouse Drawing E-14273-435-501, APC - Channel A Wiring Diagram, Sheet 4 of 11, Revision 5

                                        A-5                           Attachment

Section 1R13: Maintenance Risk Assessments and Emergent Work Control Procedures

NUMBER           TITLE                                             REVISION
01DP-9ZZ01       Systematic Troubleshooting                        1
01DP-9ZZ01       Systematic Troubleshooting                        0
30DP-9MT03       Assessment and Management of Risk When            10
                 Performing Maintenance in Modes 1 - 4
70DP-0MR01       Maintenance Rule                                  11
70DP-0RA05       Assessment and Management of Risk When            6
                 Performing Maintenance in Modes 1 and 2
86TD-0EE01       Reliability Centered Maintenance System Review    9
                 Process
86TD-0EE02       Equipment Reliability Classification Process      1

Drawings

NUMBER           TITLE                                             REVISION
01-E-AFB-005     Elementary Diagram Auxiliary Feedwater System Iso 9
                 Valves Pump B to SG-1 & SF-2 1J-AFB-HV-34,
                 Sheet 1 of 2
01-E-PKB-001     Elementary Diagram 125V DC Class 1E Power         12
                 System DC Cont Center 1E-PKB-M42, 125V DC
                 Battery 1E-PKB0F12, Sheet 2
01-E-SAF-001     Sheets 3 and 4, Control Wiring Diagram Engineered 3
                 Safety Features Actuation System NSSS, ESFAS
                 Alarms
01-E-SBF-006     Sheets 3 and 4, Control Wiring Diagram Plant      6
                 Protection System Channel B, Part 4
03-E-AFB-003     Elementary Diagram Auxiliary Feedwater System     5
                 Aux FDW Regulating Valve Pump B to SG-1 & 2 3J-
                 AFB-HV-31, Sheet 2
03-E-AFB-007     Elementary Diagram Auxiliary Feedwater System,    8
                 Aux FDW Turbine Trip & Throttle Valve 3J-AFA-HV-
                 0054 & Thermocouples
03-J-AFA-HV-54   Control Logic Diagram Aux. Feedwater Pump A       1
                 Turbine Trip & Throttle Valve J-AFA-HV-54
13-VTD-E146-     ESFAS Auxiliary Relay Cabinet Assembly Manual     4
0006
                                      A-6                          Attachment
NP-1516            4" - 900# ASA Trip Throttle Valve TDP Mechanism        B
                   With SMB 000 Limitorque Operator, Hard Packing,
                   Double Leakoff, Strainer, Mech. Trip, (2) Limit
                   Switches, Solenoid

PVARs

3140408     3120075    3118968     3119426     3119964     3118744    3129956     3135143
3140246     3143624

CRDRs

3140975     3120574    3120411     3121467     3119111

CRAIs

3136090

Work Orders

3140409     3118969    2980775     2992529     3120932     3133493    3135731     3140249

Miscellaneous CHAR Services Power Point Presentation, Reduction of Electrical Noise Interference with Palo Verde Log Amp 3A Due to Operation of DG3A, January 13, 2008 Control Room Alarm Typer Printout, January 9, 2008 Unit 2 Control Room Logs, January 9, 2008 Section 1R15: Operability Evaluations Procedures

NUMBER             TITLE                                                  REVISION
40DP-9OP26         Operability Determination and Functional               18
                   Assessment
40ST-9DG02         Diesel Generator B Test                                36

Drawings

NUMBER             TITLE                                                  REVISION
01-E-AFB-005       Elementary Diagram Auxiliary Feedwater System Iso      9
                   Valves Pump B to SG-1 & SF-2 1J-AFB-HV-34,
                   Sheet 1 of 2
01-E-PKB-001       Elementary Diagram 125V DC Class 1E Power              12
                   System DC Cont Center 1E PKB M42, 125V DC
                   Battery 1E-PKB0F12, Sheet 2
                                        A-7                               Attachment
03-E-AFB-003        Elementary Diagram Auxiliary Feedwater System        5
                    Aux FDW Regulating Valve Pump B to SG 1 & 2 3J-
                    AFB-HV-31, Sheet 2
03-M-DGP-001        P & ID Diagram, Control Air Diesel Generator         44
                    System, Sheet 8

PVARs

2951473     2954664    2988892     3005648     3027524    3053912     3093774     3119518
3119520     3125979    3126297     3125050     3092611    3129956     3135143     3140246
3143624     3118968    3148305     3150570

CRDRs

2945319     3095450    3095505     2950136     3149153

CRAIs

2950256     2976063    3095506     3126903     2950257    3104314     3009278

Work Orders

3107411     3133493    3135731     3140249     3104640    3111422     3148320

Miscellaneous 13-JC-DF-202, Diesel Fuel Oil Storage Tank Level Instrument Uncertainty Calculation, Revision 6 13-JC-DF-202, Diesel Fuel Oil Storage Tank Level Instrument Uncertainty Calculation, Revision 6 8000865-FA, Haynes Vendor Report - Failure Analysis of Fuel Injection Pump, Revision 0 8001090-Test, Haynes Vendor Report - Special Testing of Fuel Injection Pump, Revision 0 Appendix C data sheets, September 29, 2001 and March 30, 2003 to 73DP 9ZZ10, "Guidelines for Heat Exchanger Thermal Performance Analysis," Revision 5 Letter, James S. Olszewski to James McDowell, "APS Fall, 2007 Desiccant Issue CAPS Root Cause Analysis Report," February 7, 2008 PROTO-HX 4.10 Data sheet, dated January 4, 2008 Regulatory Guide 1.33, Appendix A, Section 9, Procedures for Performing Maintenance, Revision 2

                                        A-8                              Attachment

Section 1R18: Plant Modifications Procedures

NUMBER                 TITLE                                        REVISION
81DP-ODC17             Temporary Modification Control               20

PVARs

3109083

CRAIs

2779043

Work Orders

3112242

Miscellaneous Impact Review Form for Temporary Modification Work Order 3112242 S-07-0451, 50.59 screening for Temporary Modification Work Order 3112242 Temporary Modification 3112242 Temporary Modification 2862207 Updated Final Safety Analysis Report, Section 3.9.2, Dynamic System Analysis and Testing, Revision 14 Updated Final Safety Analysis Report, Section 5.4.7, Residual Heat Removal System, Revision 14 Final Safety Analysis Report, Section 14.B 11.3.2, Pipe Shock and Vibration Testing, Revision 14 Section 1R19: Post-Maintenance Testing Procedures

NUMBER               TITLE                                                 REVISION
01DP-9ZZ01           Systematic Troubleshooting                            0
86TD-0EE01           Reliability Centered Maintenance System Review        9
                     Process
86TD-0EE02           Equipment Reliability Classification Process          1
40OP-9CH12           Refueling Water Tank Operations                       27
                                          A-9                              Attachment
73ST-2XI12       Safety Injection Train B Emergency Core Cooling     21
                 System Throttle Valves-Inservice Test
39MT-9ZZ32       Motor Operated Valve Diagnostic Testing             9
39MT-9ZZ02       PM or EQ Inspection of the Generic Letter 89-10     21
                 Limitorque SMB/SB Motor Operated Valve Actuators
40ST-9DG01       Diesel Generator A Test                             32
30DP-9MP01       Conduct of Maintenance                              52
40DP-9OP02       Conduct of Shift Operations                         37
70DP-0EE01       Equipment Root Cause of Failure Analysis            17
01DP-0AP12       Palo Verde Action Request Processing                4
90DP-0IP10       Condition Reporting                                 36
40ST-9DG02       Diesel Generator B Test                             36

Drawings

NUMBER           TITLE                                               REVISION
03-E-AFB-007     Elementary Diagram Auxiliary Feedwater System,      8
                 Aux FDW Turbine Trip & Throttle Valve 3J-AFA-HV-
                 0054 & Thermocouples
NP-1516          4" - 900# ASA Trip Throttle Valve TDP Mechanism     B
                 With SMB 000 Limitorque Operator, Hard Packing,
                 Double Leakoff, Strainer, Mech. Trip, (2) Limit
                 Switches, Solenoid
03-J-AFA-HV-54   Control Logic Diagram Auxiliary Feedwater Pump A    1
                 Turbine Trip & Throttle Valve J-AFA-HV-54
03-M-DGP-001     P & ID Diagram, Control Air Diesel Generator        44
                 System, Sheet 8

PVARs

3120075    3118968   3127568     3126297     3125979     3149118  3148305   3149003

CRDRs

3120574   3149153

CRAIs

3129614   3140483
                                      A-10                           Attachment

Work Orders

3118969     3124794     3021681       3021678   3052999    3021829   3021791    3021675
2855497     3127795     3120015       3149122   3149370    3017284   3148320    2983608

Miscellaneous 3JAFAHV0054 Troubleshooting Game Plan, January 9, 2008 Palo Verde Nuclear Generating Station Design Basis Manual-Auxiliary Feedwater System, Revision 16 Technical Specification 3.7.5, Auxiliary Feedwater System Technical Specification Bases B3.7.5, Auxiliary Feedwater System Palo Verde Nuclear Generating Station Surveillance Package Review Sheet Prompt Operability Determination, PVAR 3125979/3126297, EDG Fuel Pump Leakage, Revision 0 Engine Combustion Report APS Emergency Diesel Generator, 3A, February 7, 2008 U3-Diesel 3A Jerk Pump Replacement Schedule, February 4, 2008 Jerk Pump Inspection Checklist, January 2008 Emergency Diesel Generator Emergency Pump Monitoring Test 3JAFAHV0054 Level C Troubleshooting Game Plan, Revision1, January 11, 2008 Review of 3JAFAHV0054 Troubleshooting Game Plan, January 10, 2008 Emergency Diesel Generator Emergency Pump Monitoring Test Engine Combustion Report APS Emergency Diesel Generator, 3B, March 21, 2008 VTD-C628-00051, Cooper Energy Instruction Manual For KSV Turbocharged Diesel Generating Unit For Nuclear Power Plant Emergency Stand-By Service, Revision 11 Section 1R20: Refueling and Other Outage Activities Procedures

NUMBER               TITLE                                              REVISION
70DP-0RA01           Shutdown Risk Assessments                          22
40DP-9ZZ01           Containment Entry in Modes 1 Thru 4                27
40DP-9ZZ01           Containment Entry in Modes 1 Thru 4                28
                                          A-11                          Attachment
72OP-9RX01           Calculation of Estimated Critical Condition         20
40OP-9ZZ03           Reactor Startup                                     46

Permits

139182     137458       139567       139608      139609       143273 143274     142827
143405     143462       143494       145574      146500

Section 1R22: Surveillance Testing Procedures

NUMBER               TITLE                                               REVISION
40ST-9DG01           Diesel Generator A Test                             32
40ST-9ZZ25           Online Remote Shutdown Disconnect Switch            1
                     Operability
73DP-9ZZ14           Surveillance Testing                                9
73ST-9AF04           AFA-P01 Full Flow - Inservice Test                  2
73ST-9ZZ18           Main Steam and Pressurizer Safety Valve Set         20
                     Pressure Verification
73DP-9XI01           Pump and Valve Inservice Testing Program -          22
                     Component Tables

PVARs

3140020    3117353      3120075      3128646     3134489

Work Orders

3131169    3006277      3108764

Miscellaneous NUREG-1482, Guideline for Inservice Testing at Nuclear Power Plants, Revision 1 ASME/ANSI OM-1990, Operation and Maintenance of Nuclear Power Plants PVNGS Surveillance Test Package Review Sheet Technical Specification 3.7.1.1, Main Steam Safety Valves Section 1EP2: Alert Notification System Testing Procedures

NUMBER               TITLE                                               REVISION
EPIP-8               Emergency Planning Administration                   19
EPIP-61              Emergency Planning Equipment Testing                5
                                          A-12                           Attachment
16DP-0EP20            Emergency Planning Conduct of Operations              9

Miscellaneous Palo Verde Nuclear Generating Station Remote Control Siren System Operating Manual, Revisions 8 and 9 Section 1EP3: Emergency Response Organization Augmentation Testing Procedures

NUMBER                TITLE                                                 REVISION
EPIP 7                Telecommunications                                    17
                      EPIP Standard Appendices, Appendix H, Autodialer      18
EPIP 99
                      Activation

Miscellaneous Call-In Drill Evaluation Reports: January 18, 2007; January 16, 2007; March 16, 2007; May 17, 2007; June 26, 2007; July 31, 2007; August 21, 2007; September 26, 2007; October 23, 2007; November 14, 2007; and December 27; 2007 Section 1EP4: Emergency Action Level and Emergency Plan Changes Procedures

NUMBER                TITLE                                                 REVISION
EPIP-99               EPIP Standard Appendices                              16

Miscellaneous Nuclear Energy Institute Report 99-01, Methodology for Development of Emergency Action Levels 2 and 4 NUREG 0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1 Palo Verde Nuclear Generating Station Emergency Plan, Revision 36, submitted May 21, 2007 Palo Verde Nuclear Generating Station Emergency Plan, Revision 37, submitted May 21, 2007 Section 1EP5: Correction of Emergency Preparedness Weaknesses and Deficiencies Procedures

NUMBER                TITLE                                                 REVISION
60DP-0QQ19            Internal Audits                                       18
                                          A-13                              Attachment
Palo Verde          Section 100, PVNGS Self-Assessment and              5
Nuclear             Benchmarking Policy
Generating
Station Policy
120
EPIP-1              Satellite Technical Support Center Actions          20 and 21

PVARs

2870126      2807473   2870126      2914362     2973337     2976699  2981306    2981606
2981932      3028784   3046518      3048866     3051083     3053838  3053838    3089226
3104356      3107606   3107851      3133068     3133077     3132912

CRDRs

2966025      2966067   2976703      2981615     3014284     3015235  3080366

Work Orders

3009109      095917

Miscellaneous Audit Report 2006-001, "Emergency Planning," March 18, 2006 Audit Report 2007-001, "Emergency Planning," March 7, 2007 Self Assessment EP-06-01: Review EPIPs to ensure Changes meet 50.54Q Requirements, January 10, 2006 Self Assessment (Item 2905254): Autodialer Issue Self Assessment, August 6, 2006 Self Assessment (Item 2926340): Emergency Planning Generic Training Requirements, November 6, 2006 Self Assessment (Item 2947666): Contingency Plans to cope with Problems Encountered during Natural Disasters Self Assessment (Item 2949664): Quarterly Communications Surveillance Self Assessment (Item 2950098): Annual Validation of the Emergency Response Organization Database Self Assessment (Item 2950117): Assessment Summary of PVNGS Master List of Emergency Planning Objectives Self Assessment (Item 2951677): Review of On-site Emergency Kits for Outdated Radioactive Material Labels, December 19, 2006

                                         A-14                            Attachment

Self Assessment (Item 2952177): Comparison of EPIP and Emergency Planning Procedure Phone Numbers, January 2, 2007 Self Assessment (Item 2957279): STSC Communicator Annual Training Documentation for EP Performance Indicators Self Assessment (Item 2991885): EPlan Pager Validations, May 29, 2007 Self Assessment (Item 3067589): Results from Benchmarking Trips to Improve OSC Performance, October 24, 2007 Self Assessment (Item 3084358): SAMG Training Self Assessment (Item 3084363): Review EPIP-99 Appendix D, Notification, October 19, 2007 Self Assessment (Item 3084379): STARS Review of EPIP-09, Revision 10, October 18, 2007 Self Assessment (Item 3083981): PIs, October 18, 2007 Self Assessment (Item 3108037): Dose Model Assessment Report, December 12, 2007 Self Assessment (Item 3108421): Benchmark of EP Emergency Notification Form, December 12, 2007 Drill Evaluation Reports: 2006: February 15, March 29, June 16, June 28, July 12, September 7 (06-D-FAC-09007), September 27, December 1, December 6, and December 7 (06-D-ENV- 12011); 2007: January 31, February 15, March 7, March 29 and 30, April 19, May 3, July 19, August 16, September 13, September 14, October 18, and October 19 Design Change Request QF-1093 Section 1EP6: Drill Evaluation Procedures

NUMBER               TITLE                                                REVISION
EPIP 03              Technical Support Center Actions                     46
EPIP 04              Emergency Operations Facility Actions                41
EPIP 14              Dose Assessment                                      7
EPIP-99              Emergency Plan Implementing Procedure Standard       19
                     Appendices, Appendix A, Emergency Action Levels
EPIP-99              Emergency Plan Implementing Procedure Standard       19
                     Appendices, Appendix B, Protective Action
                     Recommendations
EPIP-99              Emergency Plan Implementing Procedure Standard       19
                     Appendices, Appendix D, Notifications
                                        A-15                               Attachment
EPIP-99            Emergency Plan Implementing Procedure Standard     19
                   Appendices, Appendix O, Recovery Organization
EPIP-99            Emergency Plan Implementing Procedure Standard     19
                   Appendices, Appendix S, Consideration for the use
                   of Fire Streams/Sprays to Reduce Plume Activity

PVARs

3171747    3142619

CRDRs

3143064    3143276

CRAIs

3150447

Miscellaneous Palo Verde Nuclear Generating Station Emergency Planning Form EP-0541, Palo Verde NAN Emergency Message Form Palo Verde Dose Assessment Forecast Palo Verde Nuclear Generating Station Emergency Planning Form EP-0012, Emergency Action Log NRC Form 361, Reactor Plant Event Notification Worksheet Palo Verde Nuclear Generating Station Annual Objective Evaluations Palo Verde Nuclear Generating Station Biennial Objective Evaluations 2008 Emergency Preparedness Evaluated Scenario 08-AEV-03002

                                       A-16                           Attachment

Section 2OS1: Access Control to Radiologically Significant Areas Procedures

NUMBER             TITLE                                             REVISION
75DP-0RP01         Radiation Protection Program Overview             6
75DP-0RP02         Radiation Contamination Control                   8
75DP-0RP03         ALARA Program Overview                            3
75DP-9RP01         Radiation Exposure and Access Control             10
75RP-0RP01         Radiological Posting and Labeling                 24
75RP-9RP01         Radiation Exposure and Access Control             10
75RP-9RP07         Radiological Surveys and Air Sampling             15
75RP-9RP10         Conduct of Radiation Protection Operations        24
75RP-9OP02         Control of High Radiation Areas, Locked High      2
                   Radiation Areas and Very High Radiation Areas

PVARs

3132404    3105482    3116100      3119691    3125775     3125779

Radiation Exposure Permits

3-1393     3-3002     3-3003       3-3006     3-3015      3-6000  3-6001     3-6003
3-6005     3-6006     3-6007       3-6009     3-6010      3-6011  3-6012     3-6013
                                       A-17                           Attachment

Section 2OS2: As Low As Is Reasonably Achievable (ALARA) Planning And Controls Procedures

NUMBER             TITLE                                               REVISION
75DP-0RP01         Radiation Protection Program Overview               6
75DP-0RP02         Radiation Contamination Control                     8
75DP-0RP03         ALARA Program Overview                              3
75DP-9RP01         Radiation Exposure and Access Control               10
75RP-0RP01         Radiological Posting and Labeling                   24
75RP-9RP01         Radiation Exposure and Access Control               10
75RP-9RP07         Radiological Surveys and Air Sampling               15
75RP-9RP10         Conduct of Radiation Protection Operations          24
75RP-9OP02         Control of High Radiation Areas, Locked High        2
                   Radiation Areas and Very High Radiation Areas

PVARs

3132404    3105482     3116100     3119691    3125775     3125779

Radiation Exposure Permits

3-1393     3-3002      3-3003      3-3006     3-3015      3-6000    3-6001     3-6003
3-6005     3-6006      3-6007      3-6009     3-6010      3-6011    3-6012     3-6013

Section 4OA1: Performance Indicator Verification Procedures

NUMBER             TITLE                                               REVISION
93DP-0LC09         Data Collection and Submittal Using INPOs          7
                   Consolidated Data Entry System
EPIP 99            EPIP Standard Appendices, Appendix A, Emergency     18
                   Action Levels
EPIP 99            EPIP Standard Appendices, Appendix B, Protective    18
                   Action Recommendations
EPIP 99            EPIP Standard Appendices, Appendix D and P          18
                                       A-18                             Attachment

Miscellaneous Nuclear Energy Institute 99-02, Regulatory Assessment Indicator Guideline, Revision 5 Palo Verde Units 1 - 3, Performance Indicator View Report, Unplanned Scrams With Complications, January - December, 2007 Palo Verde Units 1 - 3, Performance Indicator View Report, Unplanned Power Changes per 7000 Critical Hours, January - December, 2007 Palo Verde Units 1-3, PI View Report, Unplanned Scrams per 7000 Critical Hours, January - December, 2007 Palo Verde Units 1 - 3, Operating Data Reports, January - December, 2007 Palo Verde Units 1 - 3, 24 Month Power History Report, February 2006 - February 2008 LER 05000529/2007003, Manual Reactor Trip due to Increased Steam Generator Sodium Levels from Failed Heat Exchanger Plug, Revision 0 LER 05000529/2007001, Completion of a Shutdown Required by Technical Specification 3.5.3, Condition C, Revision 0 LER 05000528/2007006, Required Shutdown due to Inoperable Steam Admission Bypass Supply Valve to Auxiliary Feedwater Pump, Revision 0 Palo Verde Nuclear Generating Station Emergency Plan, Revision 37 Section 4OA2: Identification and Resolution of Problems (71152) Procedures

NUMBER               TITLE                                                REVISION
01DP-0AC06           Site Integrated Business Plan/Site Integrated        3
                     Improvement Plan Process
01DP-0AP12           Palo Verde Action Request Processing                 4
01DP-0AP16           PVNGS Self-Assessment and Benchmarking               0
01DP-OEM09           Employee Concerns Program                            0
12DP-0MC48           Quality Receiving Checklist Development              1
12DP-0MC46           Receipt Inspection                                   4
12DP-0MC29           Warehouse Discrepancy Notice                         18
12DP-0MC25           Stores                                               22
12DP-0MC 50          Control And Use Of The Metallurgist Pro-Alloy        3
                     Analyzer
                                          A-19                             Attachment

30DP-9MP03 System Cleanliness and Foreign Material Exclusion 6

          Controls

32MT-9ZZ06 Testing and Calibration of the 12IFC53A & 53B and 4

          the 77A & 77B Time Overcurrent Relays

32MT-9ZZ98 Testing and Recalibration Of The GR5 Ground Fault 1

          Relay

40DP-9OP19 Locked Valve, Breaker, and Component Tracking 88 40OP-9SI02 Recovery From Shutdown Cooling to Normal 61

          Operating Lineup

40ST-9SI04 Containment Spray Valve Verification 5 40ST-9SI09 Emergency Core Cooling System Systems Leak 24

          Test

41AL-1RK1C Alarm Response Procedure for 480 Volt 1E Trouble 36 60DP-0QQ21 Qualification and Certification Of Inspection 5

          Personnel

60DP-0QQ23 Qualification and Certification Of Inspection 1

          Personnel

73DP-0AP05 Engineering Programs Management and Health 3

          Reporting

78DP-9ZZ01 Foreign Object Search and Retrieval, Remotely 0

          Operated Vehicles, And Submersible Retrieval Tools
          and Pumps

81DP-0DC13 Deficiency Work Order 21 90DP-0IP10 Condition Reporting 36 ECP 01 Employee Concerns Program Guideline 1 ECP 02 Employee Concerns Program Guideline 8 ECP 03 Employee Concerns Program Guideline 4 01DP-OEM09 Employee Concerns Program 0 60DP-0QQ21 Qualification and Certification Of Inspection 5

          Personnel

0DP-0QQ23 Nuclear Assurance Stop Work And Escalation 1

          Processes

12DP-0MC48 Quality Receiving Checklist Development 1 12DP-0MC46 Receipt Inspection 4 12DP-0MC29 Warehouse Discrepancy Notice 18

                              A-20                           Attachment
12DP-0MC25        Stores                                           22
12DP-0MC 50       Control And Use Of The Metallurgist Pro-Alloy    3
                  Analyzer
ECP 01            Employee Concerns Program Guideline              1
ECP 02            Employee Concerns Program Guideline              8
ECP 03            Employee Concerns Program Guideline              4
16DP-0EP20        Emergency Planning Conduct of Operations         9
01DP-9EM01        Overtime Limitations                             6

Drawings

NUMBER            TITLE                                            REVISION
01-E-PGB-008      Elementary Diagram 480V Class 1E Power System    4
                  Load Centers 1E-PGA-L35 & 1E-PGB-L36 480V
                  Main FDR Breakers
01-J-RKS-0001     Annunciator/Electronic Isolation List            22

PVARs

2982198    3124586   3126308     3128719      3143447   2982198 3128719   3110619
3072309

CRDRs

 2726509   2913790   2926830     3048870      2984206   3129081 2883793   2932719
2984206    3127014   3144707      2883793     2984206   3129081 3065644   3130583
3095373    3098690   3110358     3130576      3090963   3112991 3112231   3075207
3058809    3075207   3030699     3039642      2984254   3075207 2859635   2774488
2870654    2908560   3030505

Work Orders

026318     026440    244627      2760330      2767628   2767631 2767649   2767650
2792424    2792442   2792443     2836046      2836047   2836050 2836051   2869753
2869762    2869769   2869770     2885310      2940366   3139395
                                      A-21                         Attachment

CRAIs

2785390      2785420   2933567     2938874    2940130      3014243     3017939    3017946
3042092      3042095   3042098     3065077    3069502      3086662     3086672    3104091
3104935      3126034   3100375     3123378    3126171      3129886     3075208    3090964
3116079      2987384   2993402     2993405    3020782      2874473     2844961    2779868

Site Integrated Improvement Plan Tasks

1.2.A.3      1.4.2    3.4.7.d      3.6.5        3.6.55       3.7.2.d   3.7.2.h    3.7.5.f
3.7.5.l      3.7.9.g  4.1.F.30     4.4.20       6.1.11       6.7.13    6.11.2.a   8.4.4
9.2.A.15     11.3.1   11.9.A.4.d   11.9.A.5.d

Quality Assurance Program Documents

Palo Verde Final Safety Analysis Report, Chapter 17.2B, Revision 11, June 2001
Palo Verde Final Safety Analysis Report, Chapter 1.8, Revision 12, June, 2003
ANSI N18.7-1976/ANS 3.2, Administrative Controls and Quality Assurance for the Operational
Phase of Nuclear Power Plants

NAD Audit Reports Nuclear Assurance Evaluation Report, ER 08-0003, January 8-10, 2008 Nuclear Assurance Evaluation Report ER 06-0012, January 6, 2006 Procurement and Material Control Audit 2007-005 Procurement and Material Control Audit 2007-003 Procurement and Material Control Audit 2007-004 SIBP/SIIP Closure Documents

Task 3.6.48 Closure Document, February 19, 2008
Task 3.6.64 Closure Document, February 19, 2008
Task 15.1.10 Closure Document, February 19, 2008
Task 3.6.60 Closure Document, February 20, 2008
Task 3.7.3.f Closure Document, February 26, 2008
Task 3.7.3.p Closure Document, February 26, 2008
Task 1.2.E.35 Closure Document, February 27, 2008
Task 3.6.62 Closure Document, March 3, 3008
Task 6.7.13 Closure Document, October 31, 2007
Task 15.2.1.b Closure Document, February 5, 2008

Miscellaneous Nuclear Assurance Department Noteworthy Station Quality Issue: Warehouse Operations Nuclear Assurance Department Station Quality Issue: Warehouse Operations

                                        A-22                               Attachment

List of Warehouse Discrepancy Notices for 2005, 2006, 2007 Palo Verde Nuclear Generating Station 2007 Synergy NSCA Integrated Issues Resolution Process brochure List of Warehouse Receipt Inspection Condition Report Disposition Request for 2005, 2006, 2007 Warehouse Operations and Human Performance Issues Event Date: March 16, 2007 Apparent Cause Evaluation Report Employee Concerns Program files July 1, 2001 through July 1, 2007 APS Investigation Results And Response To Allegation RIV-2007-A-0129

Licensing Document Change Request 01-F-012

Regulatory Guide 1.33 Revision 2, February 1976, Quality Assurance Program Requirements (Operation) Business Supply Chain and Stores Organization Chart, January 8, 2008 Attendance Record, Senior Management Meeting with warehouse personnel, Jan 18, 2008 Palo Verde Job Description, Evaluator Senior, November 7, 1996 Palo Verde Job Description, Evaluator II, February 2, 2006 Palo Verde Job Description, Storekeeper Senior, October 22, 1993 Palo Verde Job Description, Storekeeper, June 11, 2007 Training and Qualification records for QC Evaluators from 2005 through 2007 Quality Receiving Checklist 50051659302001 TD0961476 Quality Receiving Checklist 50051630202002 TD0961583 Quality Receiving Checklist 50051630202003 TD0961585 Unit 2 Operator Logs, January 23, 2008 13-VTD-G080-00008, General Electric Time Overcurrent Relays Types IFC51A And 51B, IFC 53A And 53B, IFC77A And 77B, Revision 3 13-VTD-G080-0246-1, General Electric Instructions For Undervoltage Relays Types IAV54 & IAV55, Revision 0 1EPGAL35B1*27X* Relay, Component Data Sheet - Bus Undervoltage Relay

                                         A-23                              Attachment

Air Operated Valves Program Summary, January 1, 2007 through June 30, 2007 Engineering Design Change 2007-0048, Change 13-VTD-P292-00004 For Cleaning and Inspecting the EDG K1 Contactor DC Coil Auxiliary Contact Module, Revision 3 10 CFR 50.54(q) EAL Change Process Guidance APS letter 102-05789-RKE/CJS to the NRC dated December 31, 2007 Emergency Preparedness Steering Committee Charter, Revision 2 Emergency Preparedness Steering Committee Minutes dated November 29, 2007, December 20, 2007, January 11, 2008, and February 15, 2008 Engineering Training Course NGT90, "Industry and Engineering Events 1Q2007" Nuclear Assurance Evaluation Report 07-0168 SIIP Performance Indicators dated March 5, 2008 Palo Verde Nuclear Generating Station Position Paper titled "Control Room Staffing and Overtime" APS payroll data From January 2003 through December 2007 SECY-01-0113, "Fatigue of Workers at Nuclear Power Plants" Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion Procedures

NUMBER              TITLE                                                 REVISION
01DP-0AP09          Procedure Use and Adherence                           7
40OP-9PC06          Fuel Pool Cleanup and Transfer                        41
40OP-9SG01          Main Steam                                            53
70DP-0EE01          Equipment Root Cause of Failure Analysis              17
73ST-9SG01          Main Steam Isolation Valves - Inservice Test          31
73ST-9XI16          Economizer Feedwater Isolation Valves - Inservice     27
                    Test
90DP-0IP10          Condition Reporting                                   36
93DP-0LC17          10CFR 50.59 and 72.48 Guidance Manual                 4
30DP-9MP03          System Cleanliness and Foreign Materials Exclusion    11
                    Controls
74DP-9CY03          Chemistry Control Instruction                         5
                                        A-24                              Attachment
74DP-9CY04        System Chemistry Specification                     52
74DP-9CY04        System Chemistry Specification                     35

Drawings

NUMBER            TITLE                                              REVISION
01-M-SGP-002      P&I Diagram, Main Steam System                     45
Westinghouse      Head Vent Line Repair Layout                       2
Drawing
8255C49
Westinghouse      Vent Pipe Repair Palo Verde 2 Reactor Vessel Head  0
Drawing,10005D
69
Westinghouse      Replacement Guide Cone Palo Verde 1, 2 & 3         0
Drawing           Reactor Vessel
10008C66

PVARs

2954664    2963881   2995235     3005648    3053912     3092611   3093774   3119520
3125050    3125979   3126297     2954664    2963881     2995235   3005648   3053912
3092611    3093774   3119520     3125050    3125979     3126297   3121048   3120070
2793806    2764549

CRDRs

2900393    3033543   2984700     2990092    3005058     3033623   3032677   2974523
2929277    2904740   2906158     2945319    2950136     3095450   117037    2604468
2915450    2928540   3121713     2897810    2905161     2902498   2928230   2913430

CRAIs

2928802    2946438   3121046     2937383,   2921512     2921404   2921856   2921406
2837083    2938381   2921501     2910704    2905572     2940200   2921504   2921508
2921521    2921515   2921517     2921513    2921508     2921501   2921403   2909939
2910010    2910041   2910020     2910103

Work Orders

2304865    3032675   2913678     2917854    2897128     2897130   2901582   2897078
2896333    2897080   2901584     2901583    2901582     2901581   2901580   2901579
2900133    2900132   2900131     2900130    2900129     2900128   2805530   2805528
                                     A-25                            Attachment
2804567      2804566     2898679    2898676     2805524     2897083   2898681   2898682
2804562      2804563     2805523    2917539     2717779     2793837

Miscellaneous 10 CFR 50.73, Licensee Event Report System ASCE/SEI43-05, Seismic Design Criteria for Structures, Systems, and Components in Nuclear Facilities Calculation 13-CC-ZF-0085C, DCS Stairway Sliding Evaluation - ASCE 43-05 Section A.1, Revision 0 Unit 2 Control Room Logs, July 27, 2006 Unit 3 Control Room Logs, January 13 and 22, 2008 Licensee Event Report 50-529/2006-004-00 Technical Specification 3.7.3, Main Feedwater Isolation Valves UFSAR Section 6.5.1, Engineered Safety Feature Filtration System BOP Chemistry Optimization Plan - Fourth Quarter 2007 Units 1, 2, and 3 Spray Ponds Train A and B Chemistry Parameter Data, January 2006 through January 2008 Units 1, 2, and 3 Trains A and B Essential Cooling Water Heat Exchanger Performance Data, January 2004 through November 2007 Root Cause Evaluation for CRDR Number 2897810, Loss of Thermal Performance of the Essential Cooling Water and Emergency Diesel Generator Intercooler Heat Exchangers, dated November 15, 2006 Action 2924010 N001-0302-00434, Westinghouse Correspondence LTR-SGDA-06-159, "Review of the Modified Excavation and Weld Repair of the Palo Verde Unit 2 Reactor Vessel Closure Head Vent Line" Westinghouse Calculation CN-EMT-02-36, Vent Line Modification Evaluation, Revision 3 Westinghouse Calculation CN-SGDA-05-32, PV2 RVCH Vent Pipe Repair, Revision 1 Westinghouse Calculation CN-EMT-02-27, Replacement Guide Cone Weld Strength Evaluation, Revision 3 ENS# 42886 10 CFR 50.59 Evaluation S-06-0485

                                         A-26                            Attachment
                           LIST OF ACRONYMS USED

AFW Auxiliary Feedwater ALARA As-Low-As-Is-Reasonably-Achievable AO Auxiliary Operator BVPS Beaver Valley Power Station CAL Confirmatory Action Letter CAP Corrective Action Program CFR Code of Federal Regulations CRAI Condition Report Action Item CRB Closure Review Board CRDR Condition Report Disposition Request CRS Control DFWO Deficiency Work Order DIWO Design Implementation Work Order DPM Drops Per Minute EAL Emergency Action Level EDG Emergency Diesel Generator ENG-DFWO Engineering Deficiency Work Order FM Foreign Material FOSAR Foreign Object Search and Retrieval IP Inspection Procedure LDCR Licensing Document Change Request LER Licensee Event Report LOP Loss of Power MFIV Main Feedwater Isolation Valve NEI Nuclear Energy Institute NCV Non-Cited Violation NRC U.S. Nuclear Regulatory Commission PC Pool Cooling PI Performance Indicator PK Class 1E 125 Vdc System PM Preventative Maintenance PVAR Palo Verde Action Request PVNGS Palo Verde Nuclear Generating Station QA Quality Assurance QC Quality Control RCS Reactor Coolant System RO Reactor Operators RPCS Reactor Power Cutback System RWT Refueling Water Tank SBC Steam Bypass Control SFP Spent Fuel Pool SIBP Site Integrated Improvement Plan SIIP Site Integrated Improvement Plan SM Shift Manager SSC Structures, Systems, and Components SG Steam Generator SRO Senior Reactor Operators TLI Turbine Load Index TS Technical Specification UFSAR Updated Final Safety Analysis Report

                                   - 30 -        Enclosure

VTD Vendor Technical Document WO Work Order

                          - 31 - Enclosure

}}