NEI 99-02 [Revision 7]

Regulatory Assessment 

Performance Indicator 

Guideline

August 31, 2013
[THIS PAGE IS LEFT BLANK INTENTIONALLY]
NEI 99-02 [Revision 7]

Nuclear Energy Institute

Regulatory Assessment

Performance Indicator 

Guideline

 

August 31, 2013

Nuclear Energy Institute, 1201 F Street N.W., Suite 1100, Washington D.C. 20004 (202.739.8000)
ACKNOWLEDGMENTS

This guidance document, Regulatory Assessment Performance Indicator Guideline, NEI 99-02, 

was originally developed by the NEI Safety Performance Assessment Task Force in conjunction 

with the NRC staff. We appreciate the direct participation of the many utilities, INPO and the 

NRC who contributed to the development of the original guidance. Today (2013), the industry 

role in supporting and maintaining NEI 99-02 is led by the efforts of the NEI Reactor Oversight 

Process Task Force (ROPTF). The ROPTF is comprised of representatives of NEI member 

utilities and vendors, and INPO. This document benefits from their collaboration and from our 

continuing interactions with, and inputs from, the NRC staff.

Additional information on the ROPTF can be found at www.nei.org, or by contacting James 

Slider at NEI, phone number (202) 739-8015 and e-mail jes@nei.org.

INFORMATION COLLECTION

Licensee submission of performance indicator information to the Nuclear Regulatory 

Commission (NRC) is an information collection that was approved by the Office of Management 

and Budget. Additional information regarding this information collection is contained in NRC 

Regulatory Issue Summary 2000-08, Revision 1, "Voluntary Submission of Performance 

Indicator Data."

NOTICE

Neither NEI, nor any of its employees, members, supporting organizations, contractors, or 

consultants make any warranty, expressed or implied, or assume any legal responsibility for the 

accuracy or completeness of, or assume any liability for damages resulting from any use of, any 

information apparatus, methods, or process disclosed in this report or that such may not infringe 

privately-owned rights.
NEI 99-02 [Revision 7]

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i

EXECUTIVE SUMMARY

In 2000 the Nuclear Regulatory Commission revised its regulatory oversight process for

inspection, assessment and enforcement of commercial nuclear power reactors. This process

utilizes information obtained from licensee-reported performance indicators and NRC inspection 

findings. The purpose of this manual is to provide the guidance necessary for power reactor 

licensees to collect and report the data elements that will be used to compute the Performance 

Indicators. 

An overview of the complete oversight process is provided in NUREG 16491

, “Reactor

Oversight Process.” More detail is provided in SECY 99-0072, “Recommendations for Reactor 

Oversight Process Improvements,” as amended in SECY 99-007A3 and SECY 00-0494 “Results 

of the Revised Reactor Oversight Process Pilot Program.” 

This revision is effective for data collection as of October 1, 2013 and includes Frequently Asked 

Questions approved through March 31, 2013.

 1 NUREG-1649, “Reactor Oversight Process”, Revision 4, December 2006, available at URL: http://www.nrc.gov/reading-rm/doccollections/nuregs/staff/sr1649/r4/. 2 SECY-99-007, “Recommendations for Reactor Oversight Process Improvements”, January 8, 1999, available at URL: 

http://www.nrc.gov/reading-rm/doc-collections/commission/secys/1999/secy1999-007/1999-007scy_attach.pdf. 3 SECY-99-007A, Recommendations for Reactor Oversight Process Improvements (Follow-up to SECY-99-007)”, March 22, 1999, available at 

URL: http://www.nrc.gov/reading-rm/doc-collections/commission/secys/1999/secy1999-007/1999-007ascy.pdf 4 SECY-00-0049, “Results of the Revised Reactor Oversight Process Pilot Program”, February 24, 2000, available at URL: 

http://www.nrc.gov/reading-rm/doc-collections/commission/secys/2000/secy2000-0049/2000-0049scy.pdf
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ii

Summary of Changes to NEI 99-02

Revision 6 to Revision 7

Page or 

Section Major Changes

p. iii Added list of FAQs incorporated in Rev. 7

pp. 1-6 Editorial corrections from Slider, Heffner, Balazik

p. 4 Tabularized the criteria for submitting comments in CDE.

pp. 8-9 Editorial corrections to Table 2, Performance Indicators

p. 13 Editorial corrections to data example

p. 14-16 Incorporated FAQ 469 (09-09) for unplanned power changes indicator

p. 17-19 Editorial corrections from Gary Miller eliminating repetition in definition of unplanned 

power changes

p. 20 Editorial corrections to data example

pp. 21-29 Incorporated numerous changes to unplanned scrams with complications per FAQ 481 

(10-02)

p. 28 Editorial corrections to data example

p. 32 Amplified guidance saying SSFF report date is tied to date of revised LER.

p. 33 Editorial corrections to data example

pp. 34-39 Incorporated numerous changes on guidance for updating PRA data and basis 

document, per FAQ 477 (11-02) and conforming changes per Roy Linthicum.

p. 40 Editorial corrections to data example

p. 43 Editorial corrections to data example

p. 45 Editorial corrections to data example

p. 46 Incorporated clarification on notification criterion, per FAQ 12-06

p. 49 Incorporated clarification on multi-site ERO members, per FAQ 09-10

p. 49 Incorporated clarification on phone-talker, per FAQ 09-06

p. 53 Editorial corrections to data example

p. 54 Incorporated clarification on multi-site ERO members, per FAQ 09-10

p. 53 Incorporated clarification on performance enhancing opportunities, per FAQ 12-06

pp. 55-56 Incorporated clarification on multi-site ERO members, per FAQ 09-10

p.59 Editorial corrections to data example

p. 61 Incorporated guidance on sirens deliberately unavailable, per FAQ 11-13

p. 64 Editorial corrections to data example

p. 70 Editorial corrections to data example

p. 72 Editorial corrections to data example

pp. 73-78 Misc. clarifications per FAQ 12-02

p. 79 Editorial corrections to data example

Table B-1 Corrected MSPI data element descriptions 

App. D Replaced discussion of FAQ timeliness with a reference pointing to App. E

p. D-13 Inserted Point Beach addition of auxiliary feedwater pumps, per FAQ 11-05

p. D-15 Inserted Fort Calhoun case on sirens de-powered because of flood, per FAQ 11-11

App. E Inserted guidance on timely submittal of FAQs per whitepaper accepted May 2013

p. E-3 Inserted guidance on withdrawal of FAQs, per FAQ 10-01

Figure E-1 Revised FAQ template to link to updates of PRA information or basis document

App. F Incorporated numerous conforming changes and corrections provided by Roy 

Linthicum throughout this appendix (e.g., adding “segment” where “train” appears)

pp. F-1 to 

F-3, F-7, FClarified guidance on no cascading of unavailability, per FAQ 10-06.
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iii

Page or 

Section Major Changes

33

p. F-5 Clarified guidance on operability, per FAQ 09-08

p. F-10 Clarified guidance on changes in baseline unavailability, per FAQ 09-07

F2.1.2 Clarified that the fuel oil transfer pump is part of the EDG super-component, per FAQ 

11-07

p. F-29 Revised EDG failure mode definitions per FAQ 09-08

App. F, 

Table 7

Incorporated Browns Ferry generic common cause factor adjustments, per FAQ 10-03.

p. F-57 Clarified treatment of last isolation valve in a cooling water line, per FAQ 11-01

Fig. F-1 Revised to show FOTP is within the boundary of the EDG, per FAQ 11-07

Fig. F-6 Revised to show treatment of last isolation valve, per FAQ 11-01

App. G Incorporated conforming changes and corrections provided by Roy Linthicum

App. H Clarified guidance regarding availability of main feedwater in determining complicated 

scrams, per FAQ 10-02
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iv

Frequently Asked Questions

The following table identifies where NRC-approved FAQs were incorporated in the text. Not all 

FAQs required a text change, and those FAQs are also identified. All of these FAQs will be 

placed in the archived FAQ file which is available on the NRC website for reference only.

FAQ# PI Subject Subject 

Text Rev.6

Changes 

Text? Final Approval Date and Documentation Where Found in Revision 7?

09-04

(467)

IE04 USwC, 

Availability of 

Feedwater

pp. 21-22. No October 15, 2009 Meeting

http://pbadupws.nrc.gov/docs/ML0930/ML093060290.html

Subject was Brunswick scram 

on 11/26/2008 that was 

judged to be uncomplicated. 

The proposed resolution 

called for generic guidance to 

be clarified in a future generic 

FAQ.

09-08

(472)

MS06 

MS07 

MS08 

MS09 

MS10

Definition of 

Availability

App. F, 

§1.2.1

Yes

Done.

December 2, 2009 Meeting

http://pbadupws.nrc.gov/docs/ML0930/ML093060290.html

Changes are effective April 1, 2010 for data to be reported 

on July 21, 2010.

Page F-6, “Return to 

Service:...”

Page F-8, “or return to 

service...”

Page F-29, “...when the EDG 

output breaker...”

Page F-30, Added “Include all 

failures...” text to definitions 

of pump and valve failures.

09-07

(468)

MS06 

MS07 

MS08 

MS09 

MS10

Baseline 

Revisions

App. F, 

§1.2.1 

Yes

Done.

January 21, 2010 Meeting

http://pbadupws.nrc.gov/docs/ML1002/ML100261638.html

Changes are effective April 1, 2010 for data to be reported 

on July 21, 2010.

Page F-10, “Prior to 

implementation...”

09-09

(469)

IE03 Unplanned 

Power 

Changes

p. 14 Yes

Done.

March 18, 2010 Meeting

http://pbadupws.nrc.gov/docs/ML1008/ML100850185.html

Pages 14-16, delineation of 

applicable power changes

10-01

(470)

None Withdrawal of 

FAQs

App. E Yes

Done.

March 18, 2010 Meeting

http://pbadupws.nrc.gov/docs/ML1008/ML100850185.html

Page E-3, “Withdrawal of 

FAQs...”

09-06

(471)

EP01 Designated 

Notifier

pp. 45-46 Yes

Done.

April 21, 2010 Meeting

http://pbadupws.nrc.gov/docs/ML1011/ML101130117.html

Effective July 1, 2010.

Page 51, “Demonstrating 

sufficient knowledge...”

10-04

(473)

MS06 Browns Ferry 

CCF Values

App. F, 

Table 7

Yes

Done.

May 26, 2010 Meeting

http://pbadupws.nrc.gov/docs/ML1015/ML101530434.html

Page F-42, Table 7, Added Unit 

1 CCF adjustment value.

10-03

(474)

IE04 Wolf Creek 

Scrams

App. H No June 23, 2010 Meeting

http://pbadupws.nrc.gov/docs/ML1018/ML101800474.pdf

Decided scram should count 

as complicated

10-05

(475)

IE04 Palo Verde 

Scrams

App. H No June 23, 2010 Meeting

http://pbadupws.nrc.gov/docs/ML1018/ML101800474.pdf

NRC suggests generic FAQ 

should follow. This was later 

determined to be unneeded.

09-10

(476)

EP02 Common EOF p. 50 Yes

Done.

February 16, 2011

http://pbadupws.nrc.gov/docs/ML1106/ML11068A001.pdf

Effective 3Q2011, for data to be reported by October 21, 

2011.

Page 50, “If an ERO 

member...”

Page 55, “The participation 

indicator...”

Pages 56-58, “Option for 

ERO...”

11-02

(477)

MS05 MSPI Basis 

Document 

Update

pp. 33- 34 Yes

Done.

February 16, 2011

http://pbadupws.nrc.gov/docs/ML1106/ML11068A001.pdf

Page 37-38, Inserted various 

mentions of when to update 

the basis document.

11-03

(478)

IE04 Robinson 

Scram

App. H No February 16, 2011

http://pbadupws.nrc.gov/docs/ML1106/ML11068A001.pdf

Scram determined not to 

count as complicated. No 

change in text needed.

11-05

(479)

MS08 Point Beach 

AFW Pumps

App. D Yes

Done

May 4, 2011

http://pbadupws.nrc.gov/docs/ML1114/ML11140A101.html

Page D-13, “Point Beach...”

Page F-43, Table 7, Revised 

Point Beach MDP Standby 

value.
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v

FAQ# PI Subject Subject 

Text Rev.6

Changes 

Text? Final Approval Date and Documentation Where Found in Revision 7?

10-02

(481)

IE04 USwC p. 20, lines 

22-46

Yes

Done

September 21, 2011

http://pbadupws.nrc.gov/docs/ML1128/ML11284A011.pdf

Effective October 1, 2011, for data to be reported by 

January 21, 2012

Pages 20-26, Edited in role of 

MFW availability.

Page H-1, Revised 

introduction to mention 

unavailability of MFW.

Page H-4, Extensive revisions 

of Question H1.5.

Page H-5, conforming edits to 

text of H1.5.

Page H-20, conforming edits 

to H3.5.

11-01

(482)

MS10 Cooling Water 

Valve

p. F-52 Yes

Done

September 21, 2011

http://pbadupws.nrc.gov/docs/ML1128/ML11284A011.pdf

Effective January 1, 2012 for data to be reported by April 21, 

2012.

Page F-58, Revised “Cooling 

Water Support System” 

description.

Page F-66, Revised Figure F-6 

to show train boundaries 

consistent with FAQ.

11-04

(483)

IE03 Downpower 

to Recover 

Lost Recirc 

Pump

p. 13, lines 

24-29

Yes

Done

September 21, 2011

http://pbadupws.nrc.gov/docs/ML1128/ML11284A011.pdf

Effective October 1, 2011 for data to be reported by January 

21, 2012.

Page 17, “Power changes to 

restore...”

11-06

(480)

MS06 EDG Run 

Hours

App. F, 

§2.2.1

Yes

Done

September 21, 2011

http://pbadupws.nrc.gov/docs/ML1128/ML11284A011.pdf

Page F-24, “For pumps, run 

hours...”

11-07

(484)

MS05 Fuel Oil 

Transfer 

Pump

App. F, 

§2.1.2

Yes

Done

May 4, 2011

http://pbadupws.nrc.gov/docs/ML1114/ML11140A101.html

Effective January 1, 2012 for data to be reported by April 21, 

2012

Page F-21, “...which are part 

of the EDG supercomponent...”

Page F-22, Table 2, “Diesel 

Generators...”

Page F-50, Revised “Scope” 

section to mention fuel oil 

transfer pump and valve.

Page F-60, Revised Figure F-1 

to clarify that FOTP is within 

EDG Component Boundary 

depicted.

11-08

(487)

MS06 EDG Failure 

Modes

p.F-26, 

lines 3-15

Yes

Done

October 26, 2011

http://pbadupws.nrc.gov/docs/ML1130/ML11304A260.pdf

Effective January 1, 2012 for data to be reported by April 21, 

2012

Page F-29, Revised definition 

of EDF failure to run.

11-11

(485)

EP03 Siren Testing p. 57, lines 

6-10

Yes

Done

September 21, 2011

http://pbadupws.nrc.gov/docs/ML1128/ML11284A011.pdf

Effective 2Q2011

Page D-15, “Fort Calhoun...”

10-06

(486)

MS06 Cascaded 

Unavailability

§2.2, 

pp.31-36

Yes

Done

October 26, 2011

http://pbadupws.nrc.gov/docs/ML1130/ML11304A260.pdf

Effective April 1, 2012, for data to be reported by July 21, 

2012.

Pages 35-40, “...train/system 

boundaries...”

Page F-1, “The cooling water 

support system...”

Page F-2, “The impact of room 

cooling...”

Page F-7, “No Cascading...”

Page F-33, Revised “Failures of 

Discovered Conditions”.

Page F-55, Revised Scope to 

mention CST.

11-09

(488)

MS Crystal River 

Shutdown

App. D No October 26, 2011

http://pbadupws.nrc.gov/docs/ML1130/ML11304A260.pdf

Withdrawn

10-07 IE04 Vendor EOPs No May 4, 2011

http://pbadupws.nrc.gov/docs/ML1114/ML11140A101.html

Withdrawn

11-10 PP01 Security OUO No January 19, 2012

http://pbadupws.nrc.gov/docs/ML1203/ML12030A117.pdf

Approved final; see generic 

FAQ 12-02 for text changes 

needed

11-12 IE03 Fitzpatrick 

Downpowers

No January 19, 2012

http://pbadupws.nrc.gov/docs/ML1203/ML12030A117.pdf

Approved final; determination 

only; no change required.

11-13 EP03 Suspension of Yes March 28, 2012 Page 63, “Additionally, if 
NEI 99-02 [Revision 7]

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vi

FAQ# PI Subject Subject 

Text Rev.6

Changes 

Text? Final Approval Date and Documentation Where Found in Revision 7?

Siren Testing Done http://pbadupws.nrc.gov/docs/ML1211/ML12110A103.pdf

Effective April 1, 2012, for data to be reported by July 21, 

2012.

sirens are not...”

12-01 MS06 Columbia EDG 

Failure

No August 29, 2012

http://pbadupws.nrc.gov/docs/ML1224/ML12249A179.html

Withdrawn

12-02 PP01 Counting of 

Compensatory 

Hours for PIDS

Yes

Done

August 29, 2012

http://pbadupws.nrc.gov/docs/ML1224/ML12249A179.html

Page 77, “This indicator serves 

as a measure of...”

Page 79, “Compensatory 

measures: Measures...”

Page 81, “Degradation:...”

12-03 IE04 St. Lucie 

USwC

No August 29, 2012

http://pbadupws.nrc.gov/docs/ML1224/ML12249A179.html

12-06 EP02 DEP Oppys p. 51 Yes

Done

March 27, 2013

http://pbadupws.nrc.gov/docs/ML1311/ML13113A355.html

Section 2.4
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NEI 99-02 [Revision 7]

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TABLE OF CONTENTS

EXECUTIVE SUMMARY................................................................................................ i

SUMMARY OF CHANGES TO NEI 99-02 ...................................................................ii

FAQ TABLE .....................................................................................................................iv

1 INTRODUCTION ..................................................................................................... 1

Background................................................................................................................ 1

General Reporting Guidance ................................................................................... 2

Guidance for Correcting Previously Submitted Performance Indicator Data ... 3

Comment Fields......................................................................................................... 3

Numerical Reporting Criteria.................................................................................. 5

Submittal of Performance Indicator Data .............................................................. 5

2 PERFORMANCE INDICATORS ......................................................................... 10

2.1 INITIATING EVENTS CORNERSTONE.................................................... 10

UNPLANNED SCRAMS PER 7,000 CRITICAL HOURS......................................... 10

UNPLANNED POWER CHANGES PER 7,000 CRITICAL HOURS......................... 14

UNPLANNED SCRAMS WITH COMPLICATIONS................................................. 21

2.2 MITIGATING SYSTEMS CORNERSTONE............................................... 30

SAFETY SYSTEM FUNCTIONAL FAILURES ....................................................... 30

MITIGATING SYSTEM PERFORMANCE INDEX ................................................. 34

2.3 BARRIER INTEGRITY CORNERSTONE.................................................. 41

REACTOR COOLANT SYSTEM (RCS) SPECIFIC ACTIVITY ............................. 41

REACTOR COOLANT SYSTEM LEAKAGE ......................................................... 44

2.4 EMERGENCY PREPAREDNESS CORNERSTONE................................. 46

DRILL/EXERCISE PERFORMANCE .................................................................... 46

EMERGENCY RESPONSE ORGANIZATION DRILL PARTICIPATION................. 53

ALERT AND NOTIFICATION SYSTEM RELIABILITY ......................................... 60

2.5 OCCUPATIONAL RADIATION SAFETY CORNERSTONE.................. 65

OCCUPATIONAL EXPOSURE CONTROL EFFECTIVENESS ................................ 65

2.6 PUBLIC RADIATION SAFETY CORNERSTONE.................................... 71

RETS/ODCM RADIOLOGICAL EFFLUENT OCCURRENCE............................. 71

2.7 PHYSICAL PROTECTIONSECURITY CORNERSTONE....................... 73

PROTECTED AREA (PA) SECURITY EQUIPMENT PERFORMANCE INDEX ...... 73
NEI 99-02 [Revision 7]

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ix

Appendices 

A. Acronyms & Abbreviations............................................................... A-1

B. Structure and Format of NRC Performance Indicator Data Files B-1

C. Background Information and Cornerstone Development.............. C-1

D. Plant Specific-Specific Design Issues................................................ D-1

E. Frequently Asked Questions.............................................................. E-1

F. Methodologies for Computing the Unavailability Index, the 

Unreliability

Index and Component Performance Limits .....................................F-1

G. MSPI Basis Document Development................................................G-1

H. USwC Basis Document ................................................... H-1
NEI 99-02 [Revision 7]

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1

1 1 INTRODUCTION

2 This guideline describes the data and calculations for each performance indicator in the United 

3 States Nuclear Regulatory Commission’s (NRC) power reactor licensee assessment process. The 

4 guideline also describes the licensee quarterly indicator reports that are to be submitted to the 

5 NRC for use in its licensee assessment process.

6

7 This guideline provides the definitions and guidance for the purposes of reporting performance 

8 indicator data. Responses to Frequently Asked Questions (FAQs) that have been approved by 

9 the Industry/NRC working group and posted on the NRC’s external website become addenda to 

10 this guideline. No other documents should be used for definitions or guidance unless specifically 

11 referenced in this document. This guideline should not be used for purposes other than 

12 collection and reporting of performance indicator data in the NRC licensee assessment process.

13

14 Background

15 In 1998 and 1999, the NRC conducted a series of public meetings to develop a more objective 

16 process for assessing a licensee’s regulatory and safety performance. The new process uses risk17 informed insights to focus on those matters that are of safety significance. The objective is to 

18 monitor performance in three broad areas – reactor safety (avoiding accidents and reducing the 

19 consequences of accidents if they occur); radiation safety for plant workers and the public during 

20 routine operations; and protection of the plant against sabotage or other security threats. 

21

22 The three broad areas are divided into seven cornerstones: Initiating Events, Mitigating Systems, 

23 Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation 

24 Safety and Physical ProtectionSecurity. Performance indicators are used to assess licensee 

25 performance in each cornerstone. The NRC will uses a risk-informed baseline inspection 

26 process to supplement and complement the performance indicator(s). This guideline focuses on 

27 the performance indicator segment of the assessment process.

28

29 The thresholds for each performance indicator provide objective indication of the potential need 

30 to modify NRC inspection resources or to take other regulatory actions based on licensee 

31 performance. Table 1 provides a summary of the performance indicators and their associated 

32 thresholds.

33

34 The overall objectives of the process are to:

35 • improve the objectivity of the oversight processes so that subjective decisions and 

36 judgment are not central process features,

37 • improve the scrutability of the NRC assessment process so that NRC actions have a clear 

38 tie to licensee performance, and

39 • risk-Risk-inform the regulatory assessment process so that NRC and licensee resources 

40 are focused on those aspects of performance having the greatest impact on safe plant 

41 operation.

42
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2

1 In identifying those aspects of licensee performance that are important to the NRC’s mission, 

2 adequate protection of public health and safety, the NRC set high level performance goals for 

3 regulatory oversight. These goals are:

4

5 • maintain a low frequency of events that could lead to a nuclear reactor accident;

6 • zero significant radiation exposures resulting from civilian nuclear reactors;

7 • no increase in the number of offsite releases of radioactive material from civilian nuclear 

8 reactors that exceed 10 CFR Part 20 limits; and

9 • noNo substantiated breakdown of physical protection that significantly weakens 

10 protection against radiological sabotage, theft, or diversion of special nuclear materials.

11

12 These performance goals are represented in the new assessment framework as the strategic 

13 performance areas of Reactor Safety, Radiation Safety, and Safeguards.

14

15 Figure 1.0 provides a graphical representation of the licensee assessment process.

16

17 General Reporting Guidance

18 At quarterly intervals, each licensee will submit to the NRC the performance assessment data 

described in this guideline. The data is submitted electronically to the NRC by the 21st 19 calendar 

20 day of the month following the end of the reporting quarter. If a submittal date falls on a 

21 Saturday, Sunday, or federal holiday,; the next federal working day becomes the official due date 

22 (in accordance with 10 CFR 50.4). The format and examples of the data provided in each 

23 subsection show the complete data record for an indicator, and provide a chart of the indicator. 

24 These are provided for illustrative purposes only. Each licensee only sends to the NRC only the 

25 data set from the previous quarter, as defined in each Data Reporting Elements subsection (See 

26 Appendix B) along with any changes to previously submitted data.

27

28 The reporting of performance indicators is a separate and distinct function from other NRC 

29 reporting requirements. Licensees will continue to submit other regulatory reports as required by 

30 regulations,; such as, 10 CFR 50.72 and 10 CFR 50.73.

31

32 Performance indicator reports are submitted to the NRC for each power reactor unit. Some 

33 indicators are based on station parameters. In these cases the station value is reported for each 

34 power reactor unit at the station.

35

36 Issues regarding interpretation or implementation of NEI 99-02 guidance may occur during 

37 implementation. Licensees are encouraged to resolve these issues with the Region. In those 

38 instances where the NRC staff and the Licensee are unable to reach resolution, or to address 

39 plant specific-specific exceptions, the issue should be escalated to appropriate industry and NRC 

management using the FAQ process.5 40 In the interim period until the issue is resolved, the 

41 Licensee is encouraged to maintain open communication with the NRC. Issues involving 

42 enforcement are not included in thisaddressed through the FAQ process.

43

44

 5 See additional information on FAQs in Appendix E, Frequently Asked Questions, and Appendix D, Plant Specific Design Issues.
NEI 99-02 [Revision 7]

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3

1 Guidance for Correcting Previously Submitted Performance Indicator Data

2 In instances whereIf data errors or a newly identified faulted condition are determined to have 

3 occurred in a previous reporting period, the previously submitted indicator data are amended 

4 only to the extent necessary to correctly calculate the indicator(s) for the current reporting period

correctly.

6 5 This amended information is submitted using a the “change report” feature provided 

6 in the INPO Consolidated Data Entry (CDE) software. The values of previous reporting periods 

7 are revised, as appropriate, when the amended data is used by the NRC to recalculate the affected 

8 performance indicator. The current report should reflect the new information, as discussed in the 

9 detailed sections of this document. In these cases, the quarterly data report should include a 

10 comment to indicate that the indicator values for past reporting periods are different than 

11 previously reported. If an a Licensee Event Report (LER) was required and the number is 

12 available at the time of the report, the LER reference is noted. 

13

14 If a performance indicator data reporting error is discovered, an amended “mid-quarter” report 

15 does not need to be submitted if both the previously reported and amended performance 

16 indicator values are within the “green”same performance indicator band. In these instances, 

17 corrected data should be included in the next quarterly report along with a brief description of 

18 the reason for the change(s). If a performance indicator data error is discovered that causes a 

19 threshold to be crossed, a “mid-quarter” report should be submitted as soon as practical 

20 following discovery of the error. Probabilistic Risk Assessment (PRAError! Bookmark not 

21 defined.) model changes are the exception to this guidance (see “Clarifying Notes” under 

22 Mitigating System Performance Index description on pages 33-3435-37 for additional details).

23

24 Comment Fields

25 The quarterly report allows comments to be included with performance indicator data. A general 

26 comment field is provided for comments pertinent to the quarterly submittal that are not specific 

27 to an individual performance indicator. A separate comment field is provided for each 

28 performance indicator. Comments included in the report should be brief and understandable by 

29 the general public. Comments provided as part of the quarterly report will be included along 

with performance indicator data as part of the NRC Public Web7 30 site on the oversight program. 

31 If multiple PI comments are received by NRC that are applicable to the same unit/PI/quarter, the 

32 NRC Public Web site will display all applicable comments for the quarter in the order received 

33 (e.g., If a comment for the current quarter is received via quarterly report and a comment for the 

34 same PI is received via a change report, then both comments will be displayed on the Web site.) 

35 For General Comments, the NRC Public Web site will display only the latest “general” comment 

36 received for the current quarter (e.g., A “general” comment received via a change report will 

37 replace any “general” comment provided via a previously submitted quarterly report.)

38

39 Comments should be generally limited to instances as directed in this guideline. These instances 

40 includeare summarized in Table 1 below.

41

 6 Changes to data collection rules or practices required by the current revision of this document will not be applied retroactively to previously 

submitted data. Previously submitted data will not require correction or amendment provided it was collected and reported consistent with the 

NEI 99-02 revision and FAQ guidance in effect at the time of submittal. 7 www.nrc.gov/NRR/OVERSIGHT/ASSESS/index.html

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Table 1 – Guidance for Submitting Comments with PI Data8 1

Submit a Comment When... Guidance

A threshold has been exceeded Comment should include a brief explanation and 

should be repeated in subsequent quarterly reports 

as necessary to address the exceedance.

Revising previously submitted data Comment should include a brief characterization of 

the change, should identify affected time periods 

and should identify whether the change affects the 

“color” of the indicator.

Data is unavailable for the quarterly report For example, RCS activity may be unavailable for 

one or more months due to plant conditions that do 

not require calculation of RCS activity.

An FAQ has been submitted that could impact 

current or previously submitted data

An Safety System Functional Failure (SSFF) is 

reported

Comment shall include the LER number

A Notice of Enforcement Discretion or Technical 

Specification change has been granted without 

which the unit would have had an unplanned power 

change of greater than 20-percent of full power

There is a failure to perform regularly-scheduled 

tests of the Alert and Notification System (ANS)

There is a change in the ANS test methodology

There is a change in Mitigating System 

Performance Index (MSPI) coefficients

The comments automatically generated by CDE do 

not fulfill this requirement. The plant must generate 

a plant-specific comment that describes what was 

changed.

There is a change in the MSPI Basis Document that 

affects the value of an indicatort

Compensatory hours for security equipment 

upgrade modifications are excluded

Engineering evaluations of a degraded condition 

are incomplete

2

3 • Exceedance of a threshold (Comment should include a brief explanation and should be 

4 repeated in subsequent quarterly reports as necessary to address the threshold exceedance)

5 • Revision to previously submitted data (Comment should include a brief characterization of 

6 the change, should identify affected time periods and should identify whether the change 

7 affects the “color” of the indicator.)

8 • Unavailability of data for quarterly report (Examples include unavailability of RCS Activity 

9 data for one or more months due to plant conditions that do not require RCS activity to be 

10 calculated.)

11 • When an FAQ has been submitted that could impact the current or previously submitted data 

12 • When a Safety System Functional Failure is reported, the LER number shall be listed

13 • If an NOED or technical specification change has been granted which would otherwise have 

14 resulted in an unplanned power change of greater than 20% full power 

15 • Failure to perform regularly scheduled ANS tests 

 8 Text reformatted as table to improve readability; no change in Rev. 6 content is intended herein Rev. 7.
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1 • Changes in ANS test methodology 

2 • Changes to MSPI coefficients

3 • Changes to MSPI Basis Documents

4 • Excluded compensatory hours for security equipment upgrade modifications

5 • Uncompleted engineering evaluations of a degraded condition

6

7 Changes to MSPI coefficients require comments to be submitted. The comments automatically 

8 generated by CDE when MSPI coefficients are changed do not fulfill this requirement. The plant 

9 must generate a plant–specific comment that describes what was changed.

10

11 In specific circumstances, some plants, because of unique design characteristics, may typically 

12 appear in the “increased regulatory response band,” as shown in Table 12. In such cases the 

13 unique condition and the resulting impact on the specific indicator should be explained in the 

14 associated comment field. Additional guidance is provided under the appropriate indicator 

15 sections.

16

17 The quarterly data reports are submitted to the NRC under 10 CFR 50.4 requirements. The 

18 quarterly reports are to be submitted in electronic form only. Separate submittal of a paper copy 

19 is not requested. Licensees should apply standard commercial quality practices to provide 

20 reasonable assurance that the quarterly data submittals are correct, since they are subject to the 

21 requirements of 10 CFR 50.9. Licensees should plan to retain the data consistent with the 

22 historical data requirements for each performance indicator. For example, data associated with 

23 the barrier cornerstone should be retained for 12 months.

24

25 The criterion for reporting is based on the time the failure or deficiency is identified, with the 

26 exception of the Safety System Functional Failure indicator, which is based on the Report Date 

27 of the LER. In some cases the time of failure is immediately known, in other cases there may be 

28 a time-lapse while calculations are performed to determine whether a deficiency exists, and in 

29 some instances the time of occurrence is not known and has to be estimated. Additional 

30 clarification is provided in specific indicator sections.

31

32 Numerical Reporting Criteria

33 Final calculations are rounded up or down to the same number of significant figures digits as 

34 shown in Table 12. Where required, percentages are reported and noted as: 9.0%, 25%.

35

36 Submittal of Performance Indicator Data

37 Performance indicator data should be submitted as a delimited text file (data stream) for each 

38 unit, attached to an email addressed to Pidata.Resource@nrc.gov. The structure and format of 

39 the delimited text files is discussed in Appendix B. The email message can include report files 

40 containing PI data for the quarter (quarterly reports) for all units at a site and can also include 

41 any report file(s) providing changes to previously submitted data (change reports). The 

42 title/subject of the email should indicate the unit(s) for which data is included, the applicable 

43 quarter, and whether the attachment includes quarterly report(s) (QR), change report(s) (CR) or 

44 both. The recommended format of the email message title line is “<Plant Name(s)>-

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1 <quarter/year>-PI Data Elements (QR and/or CR)” (e.g., “Salem Units 1 and 2 – 1Q2000 – PI 

2 Data Elements (QR)”). Licensees should not submit hard copies of the PI data submittal (with 

3 the possible exception of a back back-up if the email system is unavailable). 

4

5 The NRC will send return emails with the licensee’s submittal attached to confirm and

6 authenticate receipt of the proper data, generally within 2 business days. The licensee is 

7 responsible for ensuring that the submitted data is received without corruption by comparing the 

8 response file with the original file. Any problems with the data transmittal should be identified 

9 in an email to Pidata.Resource@nrc.gov within 4 business days of the original data transmittal.

10

11 Additional guidance on the collection of performance indicator data and the creation of quarterly 

12 reports and change reports is provided in the INPO CDE Job Aids available on the INPO CDE 

webpage.

9 13

14

15 The reports made to the NRC under the regulatory assessment process [: what does this mean? Is 

16 it still needed?] are in addition to the standard reporting requirements prescribed by NRC 

17 regulations.

18

 9 http://www.inpo.org/inpo/CDE.asp
NEI 99-02 [Revision 7]

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1

2

-------HUMAN -------------- SAFETY CONSCIOUS WORK ---------- PROBLEM ----------------------

PERFORMANCE ENVIRONMENT IDENTIFICATION AND

RESOLUTION

PUBLIC HEALTH AND SAFETY

AS A RESULT OF CIVILIAN

NUCLEAR REACTOR

OPERATION

REACTOR

SAFETY SAFEGUARDS

INITIATING

EVENTS

MITIGATING

SYSTEMS

BARRIER

INTEGRITY

EMERGENCY

PREPAREDNESS

PUBLIC

RADIATION

SAFETY

OCCUPATIONAL

RADIATION

SAFETY

SECURITY

NRC’s

Overall

Safety

Mission

Strategic

Performance

Areas

RADIATION

SAFETY

Cornerstones

3

4

5 Figure 1 - Regulatory Oversight Framework
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Table 21 – PERFORMANCE INDICATORS

Cornerstone Indicator

Thresholds

(see Note 1 and Note 2 for PLE)

Increased 

Regulatory 

Response Band

Required 

Regulatory 

Response Band

Unacceptable 

Performance 

Band

Initiating Events IE01 Unplanned Scrams per 7000 Critical 

Hours (automatic and manual scrams 

during the previous four quarters)

>3.0 >6.0 >25.0

IE03 Unplanned Power Changes per 7000 

Critical Hours (over previous four 

quarters)

>6.0 N/A N/A

IE04 Unplanned Scrams with Complications 

(over the previous four quarters)

>1 N/A N/A

Mitigating Systems MS05 Safety System Functional 

Failures (over previous four 

quarters)

BWRs 

PWRs 

>6

>5

N/A

N/A

N/A

N/A

MS06 Mitigating System Performance Index

(Emergency AC Power Systems)

>1.0E-06 

OR or PLE = YES

>1.0E-05 >1.0E-04

MS07 Mitigating System Performance Index

(High Pressure Injection Systems)

>1.0E-06 OR 

or PLE = YES

>1.0E-05 >1.0E-04

MS08 Mitigating System Performance Index

(Heat Removal Systems)

>1.0E-06 

ORor PLE = YES

>1.0E-05 >1.0E-04

MS09 Mitigating System Performance Index

(Residual Heat Removal Systems)

>1.0E-06 

or OR PLE = YES

>1.0E-05 >1.0E-04

MS10 Mitigating System Performance Index

(Cooling Water Systems)

>1.0E-06

or OR PLE = YES

>1.0E-05 >1.0E-04

Barrier Integrity

Fuel Cladding

BI01 Reactor Coolant System (RCS) Specific 

Activity (maximum monthly values, 

percent of Tech. Spec limit)

>50.0% >100.0% N/A

Reactor Coolant 

System

BI02 RCS Identified Leak Rate (maximum 

monthly values, percent of Tech. Spec. 

limit)

>50.0% >100.0% N/A

1
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Table 1 2 - PERFORMANCE INDICATORS Cont’d

Cornerstone Indicator Thresholds (see Note 1 and Note 2 for PLE)

Increased 

Regulatory 

Response Band

Required 

Regulatory 

Response Band

Unacceptable 

Performance 

Band

Emergency 

Preparedness

EP01 Drill/Exercise Performance (over previous eight 

quarters)

<90.0% <70.0% N/A

EP02 ERO Drill Participation (percentage of Key ERO 

personnel that have participated in a drill or exercise in 

the previous eight quarters)

<80.0% <60.0% N/A

EP03 Alert and Notification System Reliability (percentage 

reliability during previous four quarters)

<94.0% <90.0% N/A

Occupational

Radiation Safety

OR01 Occupational Exposure Control Effectiveness 

(occurrences during previous 4 quarters)

>2 >5 N/A

Public Radiation 

Safety

PR01 RETS/ODCM Radiological Effluent Occurrence 

(occurrences during previous four quarters)

>1 >3 N/A

Physical 

ProtectionSecurity

PP01 Protected Area Security Equipment Performance Index 

(over a four quarter period)

>0.080 N/A N/A

1

2 Note 1: Thresholds that are specific to a site or unit will be provided in Appendix D when identified.

3 Note 2: PLE – = System Component Performance Limit Exceeded (see Appendix F, section F4) 

4

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1 2 PERFORMANCE INDICATORS

2 2.1 INITIATING EVENTS CORNERSTONE

3 The objective of this cornerstone is to limit the frequency of those events that upset plant 

4 stability and challenge critical safety functions, during power operations. If not properly 

5 mitigated, and if multiple barriers are breached, a reactor accident could result which may 

6 compromise the public health and safety. Licensees can reduce the likelihood of a reactor 

7 accident by maintaining a low frequency of these initiating events. Such events include reactor 

8 scrams due to turbine trips, loss of feedwater, loss of off-site power, and other significant reactor 

9 transients.

10

11 The indicators for this cornerstone are reported and calculated per reactor unit.

12

13 There are three indicators in this cornerstone:

14

15 • Unplanned (automatic and manual) scrams Scrams per 7,000 critical hours

16 • Unplanned Power Changes per 7,000 critical hours

17 • Unplanned Scrams with Complications

18

19 UNPLANNED SCRAMS PER 7,000 CRITICAL HOURS

20 Purpose

21 This indicator monitors the number of unplanned scrams. It measures the rate of scrams per year 

22 of operation at power and provides an indication of initiating event frequency.

23

24 Indicator Definition

25 The number of unplanned scrams during the previous four quarters, both manual and automatic, 

26 while critical per 7,000 hours.

27

28 Data Reporting Elements

29 The following data are reported for each reactor unit:

30

31 • the number of unplanned automatic and manual scrams while critical in the previous quarter

32

33 • the number of hours of critical operation in the previous quarter

34
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1 Calculation

2 The indicator is determined using the values for the previous four quarters as follows:

3

valueValue = 

(total number of hours criticalin the previous 4 qtrs)

(total unplanned scrams while criticalin the previous 4 qtrs)×7,000 hrs 4

5

6 Definition of Terms

7 Scram means the shutdown of the reactor by the rapid addition of negative reactivity by any 

8 means, e.g., insertion of control rods, boron, use of diverse scram switch, or opening reactor trip 

9 breakers.

10

11 Unplanned scram means that the scram was not an intentional part of a planned evolution or test 

12 as directed by a normal operating or test procedure. This includes scrams that occurred during 

13 the execution of procedures or evolutions in which there was a high chance of a scram occurring 

14 but the scram was neither planned nor intended.

15

16 Criticality, for the purposes of this indicator, typically exists when a licensed reactor operator 

17 declares the reactor critical. There may be instances where a transient initiates from a subcritical 

18 condition and is terminated by a scram after the reactor is critical—this condition would count as 

19 a scram.

20

21 Clarifying Notes

22 The value of 7,000 hours is used because it represents one year of reactor operation at about an 

23 80% availability factor.

24

25 If there are fewer than 2,400 critical hours in the previous four quarters the indicator value is 

26 displayed as N/A because rate indicators can produce misleadingly high values when the 

27 denominator is small. The data elements (unplanned scrams and critical hours) are still reported.

28

29 Dropped rods, single rod scrams, or half scrams are not considered reactor scrams. Partial rod 

30 insertions, such as runbacks, and rod insertion by the control system at normal speed also do not 

31 count unless the resulting conditions subsequently cause a reactor scram.

32

33 Anticipatory plant shutdowns intended to reduce the impact of external events, such as tornadoes 

34 or range fires threatening offsite power transmission lines, are excluded.

35

36 Examples of the types of scrams that are included:

37

38 • Scrams that resulted from unplanned transients, equipment failures, spurious signals, human 

39 error, or those directed by abnormal, emergency, or annunciator response procedures.

40 • A scram that is initiated to avoid exceeding a technical specification action statement time 

41 limit.
NEI 99-02 [Revision 7]

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1 • A scram that occurs during the execution of a procedure or evolution in which there is a high 

2 likelihood of a scram occurring but the scram was neither planned nor intended.

3

4 Examples of scrams that are not included:

5

6 • Scrams that are planned to occur as part of a test (e.g., a reactor protection system 

7 actuation test), or scrams that are part of a normal planned operation or evolution.

8

9 • Reactor protection system actuation signals or operator actions to trip the reactor that occur 

10 while the reactor is sub-critical.

11

12 • Scrams that are initiated at less than or equal to 35% reactor power in accordance with 

13 normal operating procedures (i.e., not an abnormal or emergency operating procedure) to 

14 complete a planned shutdown and scram signals that occur while the reactor is shut down.

15

16 • Plant shutdown to comply with technical specification Limiting Condition for Operation 

(LCOs)

10 17 , if conducted in accordance with normal shutdown procedures which include a 

18 manual scram to complete the shutdown.

19

 10 The section of Technical Specifications that identifies the lowest functional capability or performance level of equipment required for safe 

operation of the facility. (http://www.nrc.gov/reading-rm/basic-ref/glossary/limiting-condition-for-operation.html)

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1 Data Example

Unplanned Scrams Per 7,000 Critical Hours

2Q97 3Q97 4Q97 1Q98 2Q98 3Q98 4Q98 1Q99

No. of Scrams Critical in Qtr 1 0 0 1 1 1 2 2

Total Scrams over 4 Qtrs NA NA NA 2 2 3 5 6

No. Hrs Critical in Qtr 1500 1000 2160 2136 2160 2136 2136 1751

Total Hrs Critical in 4 Qtrs NA NA NA 6796 7456 8592 8568 8183

Indicator Value (Grayed) (Grayed) (Grayed) Grayed) 1.9 2.4 4.1 5.1

Thresholds

Green: ≤ 3.0 2.8 2.8 2.8 2.8

White: > 3.0 3.1 3.1 3.1 3.1

Yellow: > 6.0 6 6 6 6

Red: > 25.0 24.9 24.9 24.9 24.9

0

5

10

15

20

25

2Q98 3Q98 4Q98 1Q99

Unplanned Scrams per 7,000 Hrs

White > 3.0

Yellow > 6.0

Red > 25.0

Green ≤ 3.0

2

3
NEI 99-02 [Revision 7]

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14

1 UNPLANNED POWER CHANGES PER 7,000 CRITICAL HOURS

2 Purpose

3 This indicator monitors the number of unplanned power changes (excluding scrams) that could 

4 have, under other plant conditions, challenged safety functions. It may provide leading 

5 indication of risk-significant events but is not itself risk-significant. The indicator measures the 

6 number of plant power changes for a typical year of operation at power.

7

8 Indicator Definition

9 The number of unplanned changes in reactor power of greater than 20% of full-power, per 7,000 

10 hours of critical operation excluding manual and automatic scrams.

11

12 Data Reporting Elements

13 The following data is reported for each reactor unit:

14

15 • the number of unplanned power changes, excluding scrams, during the previous quarter

16

17 • the number of hours of critical operation in the previous quarter

18

19 Calculation

20 The indicator is determined using the values reported for the previous 4 four quarters as follows: 

21

22 valueValue =

7,000 hrs

(total number of hours critical during the previous 4 qtrs)

(total number of unplanned power changes over the previous 4 qtrs) 23 ×

24

25 Definition of Terms

26 Unplanned changes in reactor power, for the purposes of this indicator, are is a changes in 

27 reactor power that (1) are was initiated less than 72 hours following the discovery of an off28 normal condition that required or resulted in a power change, and that result in, or require a 

29 change in power level of greater than 20% of full power to resolve, and (2) has not been 

30 excluded from counting per the guidance below. Unplanned changes in reactor power also 

31 include uncontrolled excursions of greater than 20% of full power that occur in response to 

32 changes in reactor or plant conditions and are not an expected part of a planned evolution or test.

33

34 Clarifying Notes

35 The value of 7,000 hours is used because it represents one year of reactor operation at about an 

36 80% availability factor.

37

38 If there are fewer than 2,400 critical hours in the previous four quarters the indicator value is 

39 displayed as “N/A” because rate indicators can produce misleadingly high values when the 

FAQ469

(09-09)
NEI 99-02 [Revision 7]

08/31/2013

15

1 denominator is small. The data elements (unplanned power changes and critical hours) are still 

2 reported.

3

4 The 72 72-hour period between discovery of an off-normal condition and the corresponding 

5 change in power level is based on the typical time to assess the plant condition, and prepare, 

6 review, and approve the necessary work orders, procedures, and necessary safety reviews, to 

7 effect a repair. The key element to be used in determining whether a power change should be 

8 counted as part of this indicator is the 72-hour period and not the extent of the planning that is 

9 performed between the discovery of the condition and initiation of the power change.

10

11 Given the above, it is incumbent upon licensees to provide objective evidence that 

12 identifies when the off-normal condition was discovered and when the power change of 

13 more than 20% was initiated. Such objective evidence may include logs, troubleshooting 

14 plans, meeting minutes, corrective action program documents, or similar type 

15 documentation.

16

17 Examples of occurrences that would be counted against this indicator include:

18 • Power reductions that exceed 20% of full power and are not part of a planned and 

19 documented evolution or test. Such power changes may include those conducted in 

20 response to equipment failures or personnel errors or those conducted to perform 

21 maintenance.

22 • Runbacks and power oscillations greater than 20% of full power. A power oscillation 

23 that results in an unplanned power decrease of greater than 20% followed by an 

24 unplanned power increase of 20% should be counted as two separate PI events, unless the 

25 power restoration is implemented using approved procedures. For example, an operator 

26 mistakenly opens a breaker causing a recirculation flow decrease and a decrease in power 

27 of greater than 20%. The operator, hearing an alarm, suspects it was caused by his action 

28 and closes the breaker resulting in a power increase of greater than 20%. Both transients 

29 would count since they were the result of two separate errors (or unplanned/non30 proceduralized action).

• Unplanned downpowers of greater than 20% of full power for ALARA11 31 reasons.

32 • Power reductions due to equipment failures that are under the control of the nuclear unit 

33 are included in this indicator.

34

35 Examples of occurrences that are not counted include the following:

36 • Planned power reductions (anticipated and contingency) that exceed 20% of full power 

37 and are initiated in response to an off-normal condition discovered at least 72 hours 

38 before initiation of the power change.

 11 As defined in Title 10, Section 20.1003, of the Code of Federal Regulations (10 CFR 20.1003), ALARA is an acronym for "as low as (is) 

reasonably achievable," which means making every reasonable effort to maintain exposures to ionizing radiation as far below the dose limits as 

practical, consistent with the purpose for which the licensed activity is undertaken, taking into account the state of technology, the economics of 

improvements in relation to state of technology, the economics of improvements in relation to benefits to the public health and safety, and other 

societal and socioeconomic considerations, and in relation to utilization of nuclear energy and licensed materials in the public interest. (Source: 

http://www.nrc.gov/reading-rm/basic-ref/glossary/alara.html)

FAQ469

(09-09)

Balazik 

6/3/13
NEI 99-02 [Revision 7]

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16

1 • Unanticipated equipment problems that are encountered and repaired during a planned 

2 power reduction greater than 20% that alone could have required a power reduction of 

3 20% or more to repair. 

4 • Apparent power changes that are determined to be caused by instrument problems.

5 • If conditions arise that would normally require unit shutdown, and a Notice of 

6 Enforcement Discretionn NOED (NOED) is granted that allows continued operation 

7 before power is reduced greater than 20%, an unplanned power change is not reported 

8 because no actual change in power greater than 20% of full power occurred. However, a 

9 comment should be made that the NRC had granted an NOED during the quarter, which, 

10 if not granted, may have resulted in an unplanned power change.

11 • Anticipatory power reductions intended to reduce the impact of external events such 

12 as hurricanes or range fires threatening offsite power transmission lines, and power 

13 changes requested by the systeam load dispatcher.

14 • Power changes to make rod pattern adjustments.

15 • Power changes directed by the load dispatcher under normal operating conditions due to 

16 load demand, for economic reasons, for grid stability, or for nuclear plant safety 

17 concerns.

18

19 Anticipated power changes greater than 20% in response to expected environmental problems 

20 (such as accumulation of marine debris, biological contaminants, or frazil icing) which are 

21 proceduralized but cannot be predicted greater than 72 hours in advance may not need to be 

22 counted unless they are reactive to the sudden discovery of off-normal conditions. However, 

23 unique environmental conditions which have not been previously experienced and could not 

24 have been anticipated and mitigated by procedure or plant modification, may not count, even if 

25 they are reactive. The licensee is expected to take reasonable steps to prevent intrusion of 

26 marine or other biological growth from causing power reductions. Intrusion events that can be 

27 anticipated as part of a maintenance activity or as part of a predictable cyclic behavior would 

28 normally be counted unless the down power was planned 72 hours in advance. The 

29 circumstances of each situation are different and should be identified to the NRC in a FAQ if the 

30 licensee and resident inspector disagree so that a determination can be made concerning whether 

31 the power change should be counted.

32

33 Licensees should use the power indication that is used to control the plant to determine if a 

34 change of greater than 20% of full power has occurred.

35

36 If a condition is identified that is slowly degrading and the licensee prepares plans to reduce 

37 power when the condition reaches a predefined limit, and 72 hours have elapsed since the 

38 condition was first identified, the power change does not count. If however, the condition 

39 suddenly degrades beyond the predefined limits and requires rapid response, this situation would 

40 count. If the licensee has previously identified a slowly degraded off-normal condition but has 

41 not prepared plans recognizing the potential need to reduce power when the condition reaches 

42 predefined limits, then a sudden degradation of that condition requiring rapid response would 

43 constitute a new off-normal condition and therefore, a new time of discovery.

44

FAQ469

(09-09)
NEI 99-02 [Revision 7]

08/31/2013

17

1 Off-normal conditions that begin with one or more power reductions and end with an unplanned 

2 reactor trip are counted in the unplanned reactor scram indicator only. However, if the cause of 

3 the downpower(s) and the scram are different, an unplanned power change and an unplanned 

4 scram must both be counted. For example, an unplanned power reduction is made to take the 

5 turbine generator off line while remaining critical to repair a component. However, when the 

6 generator is taken off line, vacuum drops rapidly due to a separate problem and a scram occurs. 

7 In this case, both an unplanned power change and an unplanned scram would be counted. If an 

8 off-normal condition occurs above 20% power, and the plant is shut down by a planned reactor 

9 trip using normal operating procedures, only an unplanned power change is counted.

10

11 In developing a plan to conduct a power reduction, additional contingency power reductions may 

12 be incorporated. These additional power reductions are not counted if they are implemented to 

13 address the initial condition. 

14

15 Equipment problems encountered during a planned power reduction greater than 20% that alone 

16 may have required a power reduction of 20% or more to repair are not counted as part of this 

17 indicator if they are repaired during the planned power reduction. However, if during the 

18 implementation of a planned power reduction, power is reduced by more than 20% of full power 

19 beyond the planned reduction, then an unplanned power change has occurred.

20

21 Unplanned power changes and shutdowns include those conducted in response to equipment 

22 failures or personnel errors and those conducted to perform maintenance. They do not include 

23 automatic or manual scrams or load-follow power changes. Power changes to restore 

24 equipment to service in accordance with approved procedures are excluded.

25

26 Apparent power changes that are determined to be caused by instrumentation problems are not 

27 included.

28

29 Unplanned power changes include runbacks and power oscillations greater than 20% of full 

30 power. A power oscillation that results in an unplanned power decrease of greater than 20% 

31 followed by an unplanned power increase of 20% should be counted as two separate PI events, 

32 unless the power restoration is implemented using approved procedures. For example, an 

33 operator mistakenly opens a breaker causing a recirculation flow decrease and a decrease in 

34 power of greater than 20%. The operator, hearing an alarm, suspects it was caused by his action 

35 and closes the breaker resulting in a power increase of greater than 20%. Both transients would 

36 count since they were the result of two separate errors (or unplanned/non-proceduralized action). 

37 Alternately, ifIf the power change is implemented to restore equipment to service and is 

38 performed using an approved procedure, the power change(s) (increases or decreases) to 

39 restore the equipment to service would not count against this indicator. For example, in 

40 BWRs, a power reduction for the purpose of re-starting a recently tripped reactor recirculation 

41 pump to re-establish two-loop operation is excluded if the initial power reduction is caused by 

42 the recirculation pump trip. The second power reduction to recover the tripped recirculation 

43 pump does not count if it is implemented by an approved procedure in response to the initial 

44 condition.

45

FAQ483

(11-04)

FAQ483

(11-04)

Miller

2/11/13

Miller

2/11/13
NEI 99-02 [Revision 7]

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18

1 If conditions arise that would normally require unit shutdown, and an NOED is granted that 

2 allows continued operation before power is reduced greater than 20%, an unplanned power 

3 change is not reported because no actual change in power greater than 20% of full power 

4 occurred. However, a comment should be made that the NRC had granted an NOED during the 

5 quarter, which, if not granted, may have resulted in an unplanned power change. 

6

7 Anticipatory power reductions intended to reduce the impact of external events such as 

8 hurricanes or range fires threatening offsite power transmission lines, and power changes 

9 requested by the system load dispatchers, are excluded.

10

11 Anticipated power changes greater than 20% in response to expected environmental problems 

12 (such as accumulation of marine debris, biological contaminants, animal intrusion, 

13 environmental regulations, or frazil icing) may qualify for an exclusion from the indicator. The 

14 licensee is expected to take reasonable steps to prevent intrusion of animals, marine debris, or 

15 other biological growth from causing power reductions. Intrusion events that can be anticipated 

16 as a part of a maintenance activity or as part of a predictable cyclic behavior would normally be 

17 counted, unless the downpower was planned 72 hours in advance or the event meets the guidance 

18 below. 

19 In order fFor an environmental event to be excluded, any of the following may be applied: 

20 • If the conditions have been experienced before and they exhibit a pattern of predictability 

21 or periodicity (e.g., seasons, temperatures, weather events, animals, etc.), the station must 

22 have a monitoring procedure in place or make a permanent modification to prevent 

23 recurrence for the event to be considered for exclusion from the indicator. If monitoring 

24 identifies the condition, the licensee must have implemented a proactive procedure (or 

25 procedures) to specifically address mitigation of the condition before it results in impact 

26 to operation. This procedure cannot be a general Abnormal Operating Procedure (AOP) 

27 or Emergency Operating Procedure (EOP) addressing the symptoms or consequences of 

28 the condition (e.g., low condenser vacuum); rather, it must be a condition-specific 

29 procedure that directs actions to be taken to address the specific environmental conditions 

30 (e.g., jellyfish, gracilaria, frazil ice, etc.) 

31 • If the event is predictable, but the magnitude of the event becomes unique, the licensee 

32 must take appropriate actions and equipment designed to mitigate the event must be fully 

33 functional at the time of the event to receive an exclusion. 

34 • Environmental conditions that are unpredictable (i.e., lightning strikes) may not need to 

35 count if equipment designed to mitigate the event was fully functional at the time of the 

36 event. 

37 • Downpowers caused by adherence to environmental regulations, NPDES permits, or 

38 ultimate heat sink temperature limits may be excluded from the indicator. 

39 The circumstances of each situation are different. In all cases, the NRC Region and Resident 

40 Inspectors should evaluate the circumstances of the power change, and if in disagreement with

41 the licensee’s position, the event should be identified in an FAQ so that a decision can be made 

42 concerning whether the power change should be counted. If the event is truly unique, an FAQ 

43 should be submitted unless the NRC Region and Resident Inspectors agree with the licensee’s 

44 position.

45

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1 Power changes to make rod pattern adjustments are excluded.

2

3 Power changes directed by the load dispatcher under normal operating conditions due to load 

4 demand, for economic reasons, for grid stability, or for nuclear plant safety concerns arising 

5 from external events outside the control of the nuclear unit are not included in this indicator. 

6 However, pPower reductions due to equipment failures that are under the control of the nuclear 

7 unit are included in this indicator.

8

9 Licensees should use the power indication that is used to control the plant to determine if a 

10 change of greater than 20% of full power has occurred.

11

12 This indicator captures changes in reactor power that are initiated following the discovery of an 

13 off-normal condition. If a condition is identified that is slowly degrading and the licensee 

14 prepares plans to reduce power when the condition reaches a predefined limit, and 72 hours have 

15 elapsed since the condition was first identified, the power change does not count. If, however, 

16 the condition suddenly degrades beyond the predefined limits and requires rapid response, this 

17 situation would count.

18

19 Off-normal conditions that begin with one or more power reductions and end with an unplanned 

20 reactor trip are counted in the unplanned reactor scram indicator only. However, if the cause of 

21 the downpower(s) and the scram are different, an unplanned power change and an unplanned 

22 scram must both be counted. For example, an unplanned power reduction is made to take the 

23 turbine generator off line while remaining critical to repair a component. However, when the 

24 generator is taken off line, vacuum drops rapidly due to a separate problem and a scram occurs. 

25 In this case, both an unplanned power change and an unplanned scram would be counted. If an 

26 off-normal condition occurs above 20% power, and the plant is shutdown by a planned reactor 

27 trip using normal operating procedures, only an unplanned power change is counted.

28

29 Downpowers of greater than 20% of full power for ALARA reasons are counted in the indicator.

Miller

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Miller

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1 Data Example

Unplanned Power Changes per 7,000 Critical Hours

2Q97 3Q97 4Q97 1Q98 2Q98 3Q98 4Q98 1Q99

No. of Power Changes in Qtr 1 0 0 1 2 2 1 3

Total Power Changes in 4 Qtrs 1 1 1 2 3 5 6 8

No. Hrs Critical in Qtr 1500 1000 2160 2136 2160 2136 2136 1751

Total Hrs Critical in 4 Qtrs NA NA NA 6796 7456 8592 8568 8183

Indicator Value (Grayed) (Grayed) (Grayed) Grayed) 2.8 4.1 4.9 6.8

Thresholds

Green: ≤ 6.0 5.9 5.9 5.9 5.9

White: > 6.0 6.08 6.08 6.08 6.08

Yellow: NA

Red: NA

0

1

2

3

4

5

6

7

8

9

10

2Q98 3Q98 4Q98 1Q99

Unplanned Power Changes per 7,000 Hrs

White > 6.0

Green≤ 6.0

2
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1 UNPLANNED SCRAMS WITH COMPLICATIONS (USWC)

2 Purpose

3 This indicator monitors that subset of unplanned automatic and manual scrams that either 

4 require additional operator actions beyond that of the “normal” scram or involve the 

5 unavailability of or inability to recover main feedwater. Such events or conditions have the 

6 potential to present additional challenges to the plant operations staff and therefore, may be more 

7 risk-significant than uncomplicated scrams.

8

9 Indicator Definition

10 The USwC indicator is defined as the number of unplanned scrams while critical, both 

11 manual and automatic, during the previous 4 four quarters that require additional 

12 operator actions or involve the unavailability of or inability to recover main feedwater as 

13 defined by the applicable flowchart (Figure 2) during the scram response (see definition of scram 

14 response in the Definitions of Terms section) and the associated flowchart questions.

15

16 Data Reporting Elements

17 The following data are required to be reported for each reactor unit.

18

19 The number of unplanned automatic and manual scrams while critical in the previous quarter that 

20 required additional operator response actions or involved the unavailability of or 

21 inability to recover main feedwater as determined by the flowchart criteria during the 

22 scram response.

23

24 Calculation

25 The indicator is determined using the values reported for the previous 4 four quarters as follows:

26

27 Value = total unplanned scrams while critical in the previous 4 four quarters that 

28 required additional operator response actions or involved the unavailability of or 

29 inability to recover main feedwater as defined by the applicable 

30 flowchart and the associated flowchart questions (Figure 2) during the 

31 scram response.

32

33 Definition of Terms

34 Scram means the shutdown of the reactor by the rapid addition of negative reactivity by any 

35 means, e.g., insertion of control rods, boron, use of diverse scram switches, or opening reactor 

36 trip breakers. 

37

38 Normal Scram means any scram that is not determined to be complicated in accordance 

39 with the guidance provided in the Unplanned Scrams with Complications indicator. A 

40 normal scram is synonymous with an uncomplicated scram.

41

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(10-02)

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(10-02)

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(10-02)

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1 Unplanned scram means that the scram was not an intentional part of a planned evolution or test 

2 as directed by a normal operating or test procedure. This includes scrams that occurred during 

3 the execution of procedures or evolutions in which there was a high chance of a scram occurring 

4 but the scram was neither planned nor intended. 

5

6 Criticality, for the purposes of this indicator, typically exists when a licensed reactor operator 

7 declares the reactor critical. There may be instances where a transient initiates from a subcritical 

8 condition and is terminated by a scram after the reactor is critical—this condition would count as 

9 a scram.

10

11 Scram Response refers to the period of time that starts with the scram and concludes 

12 when operators have completed the scram response procedures and the plant has 

13 achieved a stabilized condition in accordance with approved plant procedures and as 

14 demonstrated by meeting the following criteria.:

15

16 For a PWR:

17 • Pressurizer pressure is within the normal operating pressure band.

18 • Pressurizer level is within the no-load pressurizer band.

19 • Level and pressure of all steam generators are within the normal operating bands. 

20 • RCS temperature is within the allowable RCS no-load temperature band (Tave if any RCS 

21 pump running, Tcold if no RCS pumps running).

22

23 For a BWR: 

24 • No emergency operating procedure (EOP) entry conditions exist related to either the 

25 primary containment or the reactor.

26 • Reactor cool-down rates are less than 100 degrees F/hr.

27 • Reactor water level is being maintained within the range specified by plant procedures.

28

29 Clarifying Notes

30 This indicator is a subset of the IE01 indicator “Unplanned Scrams” and to be considered in this 

31 indicator the scram must have counted in IE01.

32

33 PWR FLOWCHART QUESTIONS (See Figure 2)

34 Did two or more control rods fail to fully insert?

35

36 Did control rods that are required to move on a reactor trip fail to fully insert into the core as 

37 evidenced by the Emergency Operating Procedure (EOP) evaluation criteria? As an example, for 

38 some PWRs using rod bottom light indications, if more than one- rod bottom light is not 

39 illuminated, this question must be answered "Yes." The basis of this step is to determine if 

40 additional actions are required by the operators as a result of the failure of all rods to insert. 

41 Additional actions, such as emergency boration, pose a complication beyond the normal scram 

42 response that this metric is attempting to measure. It is allowable to have one control rod not 

43 fully inserted since core protection design accounts for one control rod remaining fully 

44 withdrawn from the core on a reactor trip. This question must be evaluated using the criteria 

45 contained in the plant EOP used to verify that control rods inserted. During performance of this 

FAQ481

(10-02)
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23

1 step of the EOP, the licensee staff would not need to apply the “Response Not Obtained” actions. 

2 Other means not specified in the EOPs are not allowed for this metric. 

3

4 Did the turbine fail to trip? 

5

6 Did the turbine fail to trip automatically/manually as required on the reactor trip signal? To be a 

7 successful trip, steam flow to the main turbine must have been isolated by the turbine trip logic 

8 actuated by the reactor trip signal, or by operator action from a single switch or pushbutton. The 

9 allowance of operator action to trip the turbine is based on the operation of the turbine trip logic 

10 from the operator action if directed by the EOP. Operator action to close valves or secure pumps 

11 to trip the turbine beyond use of a single turbine trip switch would count in this indicator as a 

12 failure to trip and a complication beyond the normal reactor trip response. Trips that occur prior 

13 to the turbine being placed in service or “latched” should have this question answered as “No”.

14

Was power lost to any ESF12 15 bus?

16

17 During a reactor trip or during the period operators are responding to a reactor trip using reactor 

18 trip response procedures, was power lost to any ESF (Emergency Safeguards Features) bus that 

19 was not restored automatically by the Emergency Alternating Current (EAC) power system and 

20 remained de-energized for greater than 10 minutes? Operator action to re-energize the ESF bus 

21 from the main control board is allowed as an acceptable action to satisfy this metric. 

22

23 This question is looking for a loss of power at any time for any duration where the bus was not 

24 energized/re-energized within 10 minutes. The bus must have:

25

26 • Remained energized until the scram response procedure was exited, or

27 • Been re-energized automatically by the plant EAC power system (i.e., EDG), or

28 • Been re-energized from normal or emergency sources by an operator closing a 

29 breaker from the main control board.

30

31 The question applies to all ESF busses (switchgear, load centers, motor control centers and DC 

32 busses). This does NOT apply to 120-volt power panels. It is expected that operator action to 

33 re-energize an ESF bus would not take longer than 10 minutes. 

34

35 Was a Safety Injection signal received?

36

37 Was a Safety Injection signal generated either manually or automatically during the reactor trip 

38 response? The question’s purpose is to determine if the operator had to respond to an abnormal 

39 condition that required a safety injection or respond to the actuation of additional equipment that 

40 would not normally actuate on an uncomplicated scram. This question would include any 

41 condition that challenged Reactor Coolant System (RCS) inventory, pressure, or temperature 

42 severely enough to require a safety injection. A severe steam generator tube leak that would 

43 require a manual reactor trip because it was beyond the capacity of the normal at power running 

 12 Engineered Safety Features are provisions made in the design of nuclear power plants to mitigate the consequences of postulated accidents by 

maintaining the integrity of the fuel cladding, reactor coolant pressure boundary, and primary reactor containment, and thereby limiting releases 

of radioactive material. (Source: http://pbadupws.nrc.gov/docs/ML0909/ML090900198.pdf): 
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1 charging system should be counted even if a safety injection was not used since additional 

2 charging pumps would be required to be started.

3

4 Was Main Feedwater unavailable or not recoverable using approved plant 

5 procedures following during the scram response?

6

7 If operating prior to the scram, did Main Feedwater cease to operate and was it unable to be 

8 restarted during the reactor scram response? The consideration for this question is whether Main 

9 Feedwater could be used to feed the steam generators if necessary. The qualifier of “not 

10 recoverable using approved plant procedures” will allow a licensee to answer “No” to this 

11 question if there is no physical equipment restraint to prevent the operations staff from starting 

12 the necessary equipment, aligning the required systems, or satisfying required logic using plant 

13 procedures approved for use and in place prior to the reactor scram occurring.

14

15 The operations staff must be able to start and operate the required equipment using 

16 normal alignments and approved emergency, normal and off-normal operating 

17 procedures to provide the required flow to feed the minimum number of steam generators 

18 required by the EOPs to satisfy the heat sink criteria. Manual operation of 

19 controllers/equipment, even if normally automatic, is allowed if addressed by procedure. 

20 Situations that require maintenance or repair activities or non-proceduralized operating 

21 alignments require an answer of “Yes.” Additionally, the restoration of Feedwater must be 

22 capable of feeding the Steam Generators in a reasonable period of time. Operations should be 

23 able to start a Main Feedwater pump and start feeding Steam Generators with the Main 

24 Feedwater System within about 30 minutes from the time it was recognized that Main Feedwater 

25 was needed. During startup conditions where Main Feedwater was not placed in service prior to 

26 the scram this question would not be considered and should be skipped. If For plants with design 

27 features or procedural prohibitions that prevent restarting Main Feedwater, this question should 

28 be answered as “No.” if Main Feedwater is free from damage or failure that would prevent it 

29 from performing its intended function and is available for use.

30

31 Was the scram response procedure unable to be completed without entering another EOP?

32

33 The response to the scram must be completed without transitioning to an additional EOP after 

34 entering the scram response procedure (e.g., ES01 for Westinghouse). This step is used to 

35 determine if the scram was uncomplicated by counting if additional procedures beyond the 

36 normal scram response required entry after the scram. A plant exiting the normal scram response 

37 procedure without using another EOP would answer this step as “No”. The discretionary use of 

38 the lowest level Function Restoration Guideline (Yellow Path) by the operations staff is an 

39 approved exception to this requirement. Use of the Re-diagnosis Procedure by Operations is 

40 acceptable unless a transition to another EOP is required.

41

FAQ481

(10-02)

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(10-02)
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25

1 BWR FLOWCHART QUESTIONS (See Figure 2)

2

Did an RPS13 3 actuation fail to indicate / establish a shutdown rod pattern for a cold clean 

4 core?

5

6 Withdrawn control rods are required to be inserted to ensure the reactor will remain shutdown 

7 under all conditions without boron to ensure the reactor will have the required shutdown margin 

8 in a cold, xenon-free state.

9

10 Any initial evaluation that calls into question the shutdown condition of the reactor requires this 

11 question to be answered “Yes.” The required entry into the Anticipated Transient 

12 Withoutwithout Scram (ATWS) leg of the EOP or required use of Alternate Rod Insertion (ARI) 

13 requires this question to be answered “Yes.” Failure of the rod position indication in conjunction 

14 with the loss of full-in-lights on enough rods to question the cold clean core shutdown status 

15 would require this question to be answered “Yes.”

16

17 The basis of this step is to determine if additional actions are required by the operators to ensure 

18 the plant remains shutdown as a result of the failure of any withdrawn rods to insert (or indicate 

19 inserted). Additional actions, such as boron injection, or other actions to insert control rods to 

20 maintain shutdown, pose a complication beyond a normal scram response. This question must be 

21 evaluated using the criteria contained in the plant EOP used to verify the insertion of withdrawn 

22 control rods.

23

24 Was pressure control unable to be established following the initial transient?

25

26 To be successful, reactor pressure must be controlled following the initial transient without the 

27 use of Safety Relief Valves (SRVs). Automatic cycling of the SRV(s) that may have occurred as 

28 a result of the initial transient would result in a “No” response, but automatic cycling of the 

29 SRV(s) subsequent to the initial transient would result in a “Yes” response. Additionally, the 

30 SRV(s) cannot fail open. The failure of the pressure control system (i.e., turbine valves / turbine 

31 bypass valves / HPCI / RCIC/isolation condenser) to maintain the reactor pressure or a failed 

32 open SRV(s) counts in this indicator as a complication beyond the normal reactor trip response 

33 and would result in a “Yes” response.

34

35 Was power lost to any Class 1E Emergency / ESF bus?

36

37 During a reactor trip or during the period operators are responding to a reactor trip using reactor 

38 trip response procedures, was power lost to any ESF bus that was not restored automatically by 

39 the Emergency Alternating Current (EAC) power system and remained de-energized for greater 

40 than 10 minutes? Operator action to re-energize the ESF bus from the main control board is 

41 allowed as an acceptable action to result in a “No” response. The focus of this question is a loss 

42 of power for any duration where the bus was not energized/re-energized within 10 minutes. The 

43 bus must have:

44

 13 Reactor Protection System (RPS): a complex control system that provides the ability to produce an automatic or manual rapid shutdown of the 

nuclear reactor, known as a reactor trip or scram. (Source: http://nrcoe.inel.gov/resultsdb/SysStudy/W.aspx)
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1 • Remained energized until the scram response procedure was exited, or

2 • Been re-energized automatically by the plant EAC power system (i.e., EDG), or

3 • Been re-energized from normal or emergency sources by an operator closing a breaker or 

4 switch from the main control board.

5

6 The question applies to all ESF busses (switchgear, load centers, motor control centers and DC 

7 busses). This does NOT apply to 120-volt power panels. It is expected that operator action to 

8 re-energize an ESF bus would not take longer than 10 minutes. 

9

10 Was a Level 1 Injection signal received?

11

12 Was a Level 1 Injection signal generated either manually or automatically during the reactor 

13 scram response? The consideration here is whether or not the operator had to respond to 

14 abnormal conditions that required a low pressure safety injection or the actuation of additional 

15 equipment that would not normally actuate on an uncomplicated scram. This question would 

16 include any condition that challenged RCS inventory, or Drywell drywell pressure severely 

17 enough to require a safety injection. Alternately the question would be plants that do not have a 

18 high pressure Emergency Core Cooling System (ECCS) level signal that is different from the 

19 low pressure ECCS level signal would ask “was low pressure injection required?”

20

21 Was Main Feedwater not available or not recoverable using approved plant 

22 procedures during the scram response?

23

24 If operating prior to the scram, did Main Feedwater cease to operate and was it unable to be 

25 restarted during the reactor scram response? The consideration for this question is whether Main 

26 Feedwater could be used to feed the reactor vessel if necessary. The qualifier of “not recoverable 

27 using approved plant procedures” will allow a licensee to answer “NO” to this question if there is 

28 no physical equipment restraint to prevent the operations staff from starting the necessary 

29 equipment, aligning the required systems, or satisfying required logic circuitry using plant 

30 procedures approved for use that were in place prior to the scram occurring.

31

32 The operations staff must be able to start and operate the required equipment using normal 

33 alignments and approved emergency, normal and off-normal operating procedures. 

34 Manual operation of controllers/equipment, even if normally automatic, is allowed if 

35 addressed by procedure. Situations that require maintenance or repair activities or non36 proceduralized operating alignments will not satisfy this question. Additionally, the restoration 

37 of Main Feedwater must be capable of being restored to provide feedwater to the reactor vessel 

38 in a reasonable period of time. Operations should be able to start a Main Feedwater pump and 

39 start feeding the reactor vessel with the Main Feedwater System within about 30 minutes from 

40 the time it was recognized that Main Feedwater was needed. During startup conditions where 

41 Main Feedwater was not placed in service prior to the scram, this question would not be 

42 considered, and should be skipped. 

43

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1 Following initial transient, did stabilization of reactor pressure/level and drywell pressure 

2 meet the entry conditions for EOPs?

3

4 This step is used to determine if the scram was uncomplicated and did not require using other 

5 procedures beyond the normal scram response. Following the initial transient, maintaining 

6 reactor and drywell pressures below the Emergency Procedure entry values while ensuring 

7 reactor water level is above the Emergency Procedure entry values allows answering ”No.” The 

8 requirement to remain in the EOPs because of reactor pressure/water level and drywell pressure 

9 following the initial transient indicates complications beyond the typical reactor scram. 

10 Additionally, repeated reactor water level scram signal(s) during the initial transientscram 

11 response indicate level could not be stabilized and required this question be answered 

12 “Yes”. 

Heffner

2/6/13
NEI 99-02 [Revision 7]

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Data Examples

Unplanned Scrams with Complications

1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07

No. Unplanned Scrams in Qtr 0 1 0 0 1 0 1 0 0 1 0

Total in 4 Qtrs 0 1 1 1 2 1 2 2 1 2 1

Indicator Value 0 1 1 1 2 1 2 2 1 2 1

Notes

Example assumes unit achieves first criticality in 1Q05 and ROP is in effect for this unit at that time.

Unit shut down in middle of 3Q06 and restarted in 2Q07; therefore value in 1Q07 is shown as not available.

"NA" value shown for 1Q07 is illustrative only. Actual value entered into INPO's Consolidated Data Entry system may differ.

Thresholds

Green: ≤ 1 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98

White: > 1 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02

Yellow: NA

Red: NA

0

1

2

3

1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07

Unplanned Scrams with Complications

White > 1

Green≤ 1
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1 IE04 Unplanned Scrams with Complications – Flowchart

2 Figure 2

3

Scram Occurs

Did two or more 

control rods fail to fully insert?

Did the turbine fail to trip?

Was power lost to any

ESF bus?

Was a Safety Injection

signal received?

Was Main Feedwater

unavailable or not recoverable 

using approved plant procedures 

during the scram response

?

Was the scram response 

procedure unable to be 

completed without entering 

another EOP?

No

No

No

No

No

No

Do Not Count

Count

Yes

Yes

Yes

Yes

Yes

Yes

Scram Occurs

Did an RPS actuation fail to

indicate/establish a shutdown rod pattern 

for a cold clean core?

Was pressure control unable to be

established following initial transient?

Was power lost to any Class 1E 

Emergency/ESF bus?

Was Main Feedwater

unavailable or not recoverable

using approved plant procedures 

during the scram response

?

No

No

No

No

Do Not Count

Yes

Yes

Yes

Yes

PWR BWR

Was a Level 1 Injection signal received?

Following initial transient

did stabilization of reactor pressure/

level and drywell pressure meet the 

entry conditions for EOPs?

No

No

Yes

Yes
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1 2.2 MITIGATING SYSTEMS CORNERSTONE

2 The objective of this cornerstone is to monitor the availability, reliability, and capability of 

3 systems that mitigate the effects of initiating events to prevent core damage. Licensees reduce 

4 the likelihood of reactor accidents by maintaining the availability and reliability of mitigating 

5 systems. Mitigating systems include those systems associated with safety injection, decay heat 

6 removal, and their support systems, such as emergency AC power. This cornerstone includes 

7 mitigating systems that respond to both operating and shutdown events.

8

9 The definitions and guidance contained in this section, while similar to guidance developed in 

10 support of INPO/WANO indicators and the Maintenance Rule, are unique to the Reactor 

11 Oversight Process (ROP). Differences in definitions and guidance in most instances are 

12 deliberate and are necessary to meet the unique requirements of the ROP.

13

14 While safety systems are generally thought of as those that are designed to mitigate design basis 

15 accidents, not all mitigating systems have the same risk importance. PRAs have shown that risk 

16 is often influenced not only by front-line mitigating systems, but also by support systems and 

17 equipment. Such systems and equipment, both safety- and non-safety related, have been 

18 considered in selecting the performance indicators for this cornerstone. Not all aspects of 

19 licensee performance can be monitored by performance indicators, and risk-informed baseline 

20 inspections are used to supplement these indicators. 

21

22

23 SAFETY SYSTEM FUNCTIONAL FAILURES

24 Purpose

25 This indicator monitors events or conditions that prevented, or could have prevented, the 

26 fulfillment of the safety function of structures or systems that are needed to:

27

28 (a) Shut down the reactor and maintain it in a safe shutdown condition;

29 (b) Remove residual heat;

30 (c) Control the release of radioactive material; or

31 (d) Mitigate the consequences of an accident. 

32

33 Indicator Definition

34 The number of events or conditions that prevented, or could have prevented, the fulfillment of 

35 the safety function of structures or systems in the previous four quarters.

36

37 Data Reporting Elements

38 The following data is reported for each reactor unit:

39

40 • the number of safety system functional failures reported during the previous quarter

41

42 Calculation

43 unitUnit value = number of safety system functional failures in previous four quarters
NEI 99-02 [Revision 7]

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1

2 Definition of Terms

3 A Safety System Functional Failure (SSFF) is any event or condition that could have prevented 

4 the fulfillment of the safety function of structures or systems that are needed to:

5

6 (A) Shut down the reactor and maintain it in a safe shutdown condition;

7 (B) Remove residual heat;

8 (C) Control the release of radioactive material; or

9 (D) Mitigate the consequences of an accident.

10

11 The indicator includes a wide variety of events or conditions, ranging from actual failures on 

12 demand to potential failures attributable to various causes, including environmental qualification, 

13 seismic qualification, human error, design or installation errors, etc. Many SSFFs do not involve 

14 actual failures of equipment.

15

16 Because the contribution to risk of the structures and systems included in the SSFF varies 

17 considerably, and because potential as well as actual failures are included, it is not possible to 

18 assign a risk-significance to this indicator. It is intended to be used as a possible precursor to 

19 more important equipment problems, until an indicator of safety system performance more 

20 directly related to risk can be developed.

21

22 Clarifying Notes

23 The definition of SSFFs is identical to the wording of the current revision to 10 CFR 

24 50.73(a)(2)(v). Because of overlap among various reporting requirements in 10 CFR 50.73, 

25 some events or conditions that result in safety system functional failures may be properly 

26 reported in accordance with other paragraphs of 10 CFR 50.73, particularly paragraphs (a)(2)(i), 

27 (a)(2)(ii), and (a)(2)(vii). An event or condition that meets the requirements for reporting under 

28 another paragraph of 10 CFR 50.73 should be evaluated to determine if it also prevented the 

29 fulfillment of a safety function. Should this be the case, the requirements of paragraph (a)(2)(v) 

30 are also met and the event or condition should be included in the quarterly performance indicator 

31 report as an SSFFError! Bookmark not defined.. The level of judgment for reporting an event 

32 or condition under paragraph (a)(2)(v) as an SSFF is a reasonable expectation of preventing the 

33 fulfillment of a safety function.

34

35 In the past, LERs may not have explicitly identified whether an event or condition was reportable 

36 under 10 CFR 50.73(a)(2)(v) (i.e., all pertinent boxes may not have been checked). It is 

37 important to ensure that the applicability of 10 CFR 50.73(a)(2)(v) has been explicitly considered 

38 for each LER considered for this performance indicator.

39

40 NUREG-1022: Unless otherwise specified in this guideline, guidance contained in the latest 

41 revision to NUREG-1022, “Event Reporting Guidelines, 10CFR 50.72 and 50.73,” that is 

42 applicable to reporting under 10 CFR 50.73(a)(2)(v), should be used to assess reportability for 

43 this performance indicator. Questions regarding interpretation of NUREG-1022 should not be 

44 referred to the FAQ process. They must be addressed to the appropriate NRC branch responsible 

45 for NUREG-1022. 

46
NEI 99-02 [Revision 7]

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32

1 Planned Evolution for maintenance or surveillance testing: NUREG-1022, Revision 2, page 56 

2 states, “The following types of events or conditions generally are not reportable under these 

3 criteria:...Removal of a system or part of a system from service as part of a planned evolution 

4 for maintenance or surveillance testing...”

5

6 “Planned” means the activity is undertaken voluntarily, at the licensee’s discretion, and is not 

7 required to restore operability or for continued plant operation.

8

9 A single event or condition that affects several systems: counts as only one failure.

10

11 Multiple occurrences of a system failure: the number of failures to be counted depends upon 

12 whether the system was declared operable between occurrences. If the licensee knew that the 

13 problem existed, tried to correct it, and considered the system to be operable, but the system was 

14 subsequently found to have been inoperable the entire time, multiple failures will be counted 

15 whether or not they are reported in the same LER. But if the licensee knew that a potential 

16 problem existed and declared the system inoperable, subsequent failures of the system for the 

17 same problem would not be counted as long as the system was not declared operable in the 

18 interim. Similarly, in situations where the licensee did not realize that a problem existed (and 

19 thus could not have intentionally declared the system inoperable or corrected the problem), only 

20 one failure is counted.

21

22 Additional failures: a failure leading to an evaluation in which additional failures are found is 

23 only counted as one failure; new problems found during the evaluation are not counted, even if 

24 the causes or failure modes are different. The intent is to not count additional events when 

25 problems are discovered while resolving the original problem.

26

27 Engineering analyses: events in which the licensee declared a system inoperable but an 

28 engineering analysis later determined that the system was capable of performing its safety 

29 function are not counted, even if the system was removed from service to perform the analysis.

30

31 Reporting date: the date of the SSFF is the Report Date of the LER. If the LER is revised to 

32 reflect the occurrence of an SSFF, the date of the SSFF is the Report Date of the revised 

33 LER.

34 The LER number should be entered in the comment field when an SSFF is reported.

Klett 

Whitepaper

2/23/2012
NEI 99-02 [Revision 7]

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33

1 Data Examples

Safety System Functional Failures

2Q98 3Q98 4Q98 1Q99 2Q99 3Q99 4Q99 1Q00 2Q00

Number this Quarter 1 3 2 1 1 2 0 1 0

Total over 4 Qtrs 1 4 6 7 7 6 4 4 3

Indicator Value 1 4 6 7 7 6 4 4 3

Notes

Example assumes the unit becomes subject to 10 CFR 50.73 and the ROP during 2Q98.

Unit was shut down in 2Q99 and restarted in 1Q00.

Thresholds for PWRs

Green: ≤ 5 4.92 4.92 4.92 4.92 4.92 4.92 4.92 4.92 4.92

White: > 5 5.05 5.05 5.05 5.05 5.05 5.05 5.05 5.05 5.05

Yellow: NA

Red: NA

0

1

2

3

4

5

6

7

8

9

10

2Q98 3Q98 4Q98 1Q99 2Q99 3Q99 4Q99 1Q00 2Q00

Safety System Functional Failures

White > 5

Green≤ 5

2
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34

1 MITIGATING SYSTEM PERFORMANCE INDEX

2

3 Purpose

4 The purpose of the Mitigating System Performance Index is to monitor the performance of 

5 selected systems based on their ability to perform risk-significant functions as defined herein. It 

6 is comprised of three elements - system unavailability, system unreliability and system 

7 component performance limits. The index is used to determine the cumulative significance of 

8 failures and unavailability over the monitored time period.

9

10 Indicator Definition

11 Mitigating System Performance Index (MSPI) is the sum of changes in a simplified core damage 

12 frequency evaluation resulting from differences in unavailability and unreliability relative to 

13 industry standard baseline values. The MSPI is supplemented with system component 

14 performance limits.

15 Unavailability is the ratio of the hours the train/system was unavailable to perform its 

16 monitored functions (as defined by the train/system boundaries, PRA success criteria and 

17 mission times) due to planned and unplanned maintenance or test during the previous 12 quarters 

18 while critical to the number of critical hours during the previous 12 quarters. (Fault exposure 

19 hours are not included; unavailable hours are counted only from the time of discovery of a failed 

20 condition to the time the train’s monitored functions are recovered.) Time of discovery of a 

21 failed monitored component is when the licensee determines that a failure has occurred or when 

22 an evaluation determines that the train would not have been able to perform its monitored 

23 function(s). In any case where a monitored component has been declared inoperable due to a 

24 degraded condition, if the component is considered available, there must be a documented basis 

25 for that determination, otherwise a failure will be assumed and unplanned unavailability would 

26 accrue. If the component is degraded but considered operable, timeliness of completing 

27 additional evaluations would be addressed through the inspection process.

28

29 Unreliability is the probability that the train/system would not perform its monitored functions, 

30 as defined by PRA success criteria, for a 24 hour run, when called upon during the previous 12 

31 quarters. 

32 Baseline values are the values for unavailability and unreliability against which current plant 

33 unavailability and unreliability are measured. 

34 Component performance limit is a measure of degraded performance that indicates when the 

35 performance of a monitored component in an MSPI system is significantly lower than expected 

36 industry performance.

37

38 The MSPI is calculated separately for each of the following five systems for each reactor type.

39

40 BWRs

41 • emergency AC power system

42 • high pressure injection system (high pressure coolant injection, high pressure core spray, 

43 or feedwater coolant injection)

44 • reactor core isolation cooling (or isolation condenser) 

FAQ486

(10-06)
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1 • residual heat removal system (or the equivalent function as described in the Additional 

2 Guidance for Specific Systems section of Appendix F)

3 • cooling water support system (includes direct cooling functions provided by service 

4 water and component cooling water or their cooling water equivalents for the above four 

5 monitored systems)

6

7 PWRs

8 • emergency AC power system

9 • high pressure safety injection system

10 • auxiliary feedwater system

11 • residual heat removal system (or the equivalent function as described in the Additional 

12 Guidance for Specific Systems section of Appendix F) 

13 • cooling water support system (includes direct cooling functions provided by service 

14 water and component cooling water or their cooling water equivalents for the above four 

15 monitored systems)

16

17 Data Reporting Elements

18 The following data elements are reported for each train/system 

19 • Unavailability Index (UAI) due to unavailability for each monitored system

20 • Unreliability Index (URI) due to unreliability for each monitored system

21 • Systems that have exceeded their component performance limits

22

23 Calculation

24 The MSPI for each system is the sum of the UAI due to unavailability for the system plus URI 

25 due to unreliability for the system during the previous twelve quarters.

26 MSPI = UAI + URI

27 Component performance limits for each system are calculated as a maximum number of allowed 

28 failures (Fm) from the plant specific number of system demands and run hours. Actual numbers 

29 of equipment failures (Fa) are compared to these limits. When the actual number of failures 

30 exceeds the component performance limit (i.e., Fa>Fm), this is designated as “Performance 

31 Limit Exceeded” or PLE=”yes”. This part of the indicator only applies to the green-white 

32 threshold.

33 See Appendix F for the calculation methodology for UAI due to system unavailability, URI due 

34 to system unreliability and system component performance limits.

35 The decision rules for assigning a performance color to a system are:

36 IF[(MSPI ≤ 1.0e - 06) AND (Fa ≤ Fm)] THEN performance is GREEN

37 IF{[(MSPI ≤ 1.0e - 06) AND (Fa > Fm)]OR [(MSPI > 1.0e - 06) AND (MSPI ≤ 1.0e - 05)] }

38 THEN performance is WHITE

39 IF[(MSPI > 1.0e - 05) AND (MSPI ≤ 1.0e - 04) ] THEN performance is YELLOW

40 IF(MSPI > 1.0e - 04) THEN performance is RED

Balazik
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1

2 Plant Specific-specific PRA

3 The MSPI calculation uses coefficients that are developed from plant specific-specific PRAs. 

4 The PRA used to develop these coefficients should reasonably reflect the as-built, as-operated 

5 configuration of each plant. 

6

7 Specific requirements appropriate for this PRA application are defined in Appendix G. Any 

8 questions related to the interpretation of these requirements, the use of alternate methods to meet 

9 the requirements or the conformance of a plant specific-specific PRA to these requirements will 

10 be arbitrated by an Industry/NRC expert panel. If the panel determines that a plant specific11 specific PRA does not meet the requirements of Appendix G such that the MSPI would be 

12 adversely affected, an appropriate remedy will be determined by the licensee and approved by 

13 the panel. The decisions of this panel will be binding.

14

15 Definition of Terms

16 Risk Significant Functions: those at at-power functions, described in the Appendix F section 

17 “Additional Guidance for Specific Systems,” that were determined to be risk-significant in 

18 accordance with NUMARC 93-01, or NRC NRC-approved equivalents (e.g., the STP exemption 

19 request). The risk risk-significant system functions described in Appendix F, “Additional 

20 Guidance for Specific Systems,” should be modeled in the plant’s PRA/PSA. System and 

21 equipment performance requirements for performing the risk risk-significant functions are 

22 determined from the PRA success criteria, mission times, and boundaries for the system.

23 Mission Time: The mission time modeled in the PRA for satisfying the function of reaching a 

24 stable plant condition where normal shutdown cooling is sufficient. Note that PRA models 

25 typically use a mission time of 24 hours. However, shorter intervals, as justified by analyses and 

26 modeled in the PRA, may be used.

27 Success criteria: The plant specific-specific values of parameters the train/system is required to 

28 achieve to perform its monitored functions. Success criteria to be used are those documented in 

29 the plant specific-specific PRA. Design Basis success criteria should be used in the case where 

30 the plant specific-specific PRA has not documented alternative success criteria for use in the 

31 PRA.

32 Individual component capability must be evaluated against train/system level success criteria 

33 (e.g., a valve stroke time may exceed an ASME requirement, but if the valve still strokes in time 

34 to meet the PRA success criteria for the train/system, the component has not failed for the 

35 purposes of this indicator.).

36

37 Clarifying Notes

38 Documentation and Changes

39 Each licensee will have the system boundaries, monitored components, and monitored functions 

40 and success criteria which differ from design basis readily available for NRC inspection on site. 

41 Design basis criteria do not need to be separately documented. Additionally, plant-specific 

42 information used in Appendix F should also be readily available for inspection. An acceptable 

43 format, listing the minimum required information, is provided in Appendix G. As stated in the 

44 Introduction section of NEI 99-02, plant-specific comments should be provided in the data 

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(11-02)

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1 submittal when either the MSPI basis document or an MSPI coefficient is changed. Changes 

2 to the site PRA of record, the site basis document, and the CDE database should be made in 

3 accordance with the following:

4

5 Changes to PRA coefficientPRA Model Revisions: Updates to the MSPI coefficients 

6 developed from the plant specific PRA will be made as soon as practical following an update to 

7 the plant specific- PRA(which are directly obtained from the plant-specific PRA) will be made 

8 in the quarter following approval of an update to the plant-specific PRA of record. The revised 

9 coefficients will be used in the MSPI calculation the quarter following the update. Thus, the 

10 PRA MSPI coefficients in use at the beginning of a quarter will remain in effect for the 

11 remainder of that quarter. In addition, Changes changes to the CDE database and MSPI basis 

12 document that are necessary to reflect changes to the plant plant-specific PRA of record should 

13 be incorporated prior to the next quarter’s data submittal. as soon as practical but need not be 

14 completed prior to the start of the reporting quarter in which they become effective. The 

15 quarterly data submittal should include a comment that provides a summary of any changes to 

16 the MSPI coefficients. The comments automatically generated by CDE when PRA coefficients 

17 are changed do not fulfill this requirement. The plant must generate a plant–specific comment 

18 that describes what was changed. Any PRA model changes will take effect the following quarter 

19 (model changes include error, corrections, updates, etc.). For example, if a plant’s PRA model of 

20 record is approved on September 29 (3rd third quarter), MSPI coefficients based on that model 

21 of record should be used for the 4th fourth quarter. Updates to the MSPI basis document and the

22 The calculation of the new coefficients should be completed (including a revision of the MSPI 

23 basis document if required by the plant specific- processes) and input to CDE database should be 

24 made prior to reporting the 4th fourth quarter’s data (i.e., completed by January 21).

25

26 Changes to non-PRA information: Updates to information that is not directly obtained from 

27 the PRA (e.g., unavailability baseline data, estimated demands/run hours) can affect both the 

28 MSPI basis document and the MSPI inputs into the CDE database. Changes to the MSPI 

29 basis document and MSPI inputs into the CDE database that are needed to reflect changes to 

30 non-PRA information will be made prior to the next quarterly data submittal. This does not 

31 imply that any change to estimated demands/run hours is required to be reflected in the MSPI 

32 basis document or CDE (See Appendix F, Section F.2.2.1 for requirements on when MSPI basis 

33 document and CDE changes are required for estimated demands/run hours). will become 

34 effective in the quarter following an approved revision to the site MSPI basis document. Changes 

35 to the CDE database that are necessary to reflect changes to the site basis document should be 

36 incorporated as soon as practical but need not be completed prior to the start of the reporting 

37 quarter in which they become effective. The quarterly data submittal should include a comment 

38 that provides a summary of any changes to the MSPI basis document and inputs to the CDE 

39 database. The comments automatically generated by CDE when PRA coefficients are changed 

40 do not fulfill this requirement. The plant must generate a plant–specific comment that describes 

41 what was changed.For example, changes to the planned unavailability baseline that do not 

42 require a change to the PRA model must be documented in an MSPI basis document revision in 

43 the quarter prior to the revised values being used as inputs into the CDE database. This means 

completed by the 21st 44 day of the month after the end of the quarter.

45

46 Plant Modifications: Any changes to the plant should be evaluated for their impact on the 

47 MSPI basis document, MSPI inputs into the CDE database, and the PRA of record. Plant 

FAQ477

(11-02)

FAQ477

(11-02)

FAQ477

(11-02)

Linthicum 

3/3/12

FAQ477

(11-02)
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38

1 modifications have the potential to involve both changes to the PRA model and non-PRA 

2 information, while some modifications may be limited to either the PRA model or non-PRA 

3 information. Modifications to the plant design that result in a change to segment or train 

4 boundaries, monitored components, or affect monitored functions or success criteria, shall 

5 be reflected in the MSPI basis document the quarter following the completed 

implementation (i.e., completed by the 21st 6 day of the month after the end of the quarter). 

7 Additionally, if modifications are made to sub-components within the boundary of a monitored 

8 component (such as the replacement of an emergency AC voltage regulator with a different type)

9 and that sub-component is described in the basis document, the basis document should be 

10 updated to reflect the sub-component modification the quarter following the completed 

implementation (i.e., completed by the 21st 11 day of the month after the end of the quarter).

12 If the plant modification has the potential to impact the PRA model in a manner that affects 

13 MSPI results, the modification shall be evaluated to determine if it results in a factor of three 

14 change in the corrected Birnbaum value of an MSPI monitored train or component. If the new 

15 Birnbaum value is greater than 1E-6, the MSPI basis document shall be updated to reflect the 

16 new Birnbaum values the quarter following the completed implementation (i.e., completed by 

the 21st 17 day of the month after the end of the quarter). Note that the use of supplemental 

18 evaluations to estimate the revised MSPI inputs for pending PRA model changes is allowed as an 

19 interim alternative until the PRA model of record is updated.

20 Example CDE Comments:

21 Following a periodic update to a PRA model, the following CDE comment would be 

22 appropriate:

23 The XYZ PRA Model Revision 6 was approved on 7/6/10 with a corresponding MSPI

24 Basis Document Revision 3 approved on 12/21/10. The PRA model revision was a 

25 periodic update to the model which included a data update, incorporation of an Auxiliary 

26 Feedwater Crosstie between Units and a change in Human Error Probabilities using the 

27 EPRI HRA calculator. As a result of the PRA model change, the CDF, Fussel-Vesely 

28 and Basic Event Probabilities for all monitored trains and components were revised.

29

30 Following a change to baseline unavailability, the following CDE comments would be 

31 appropriate:

32

33 Scenario 1: Change Results in Negligible (≤1E-8) Increase in Train Birnbaum

34

35 The planned unavailability baseline for the Residual Heat Removal was system was 

36 increased by 30 hours per three years as a result of a new preventive maintenance task. 

37 The increase in planned unavailability baseline was evaluated in the MSPI basis 

38 document Revision 3, dated 3/23/11, and determined to result in a negligible increase in 

39 Train Birnbaum values. Therefore, the revised values were incorporated into CDE

40 effective the second quarter 2011.

41

42 Scenario 2: Change Results in Significant (>1E-8) Increase in Train Birnbaum Values

43

44 The planned unavailability baseline for the Residual Heat Removal was system was 

45 increased by 30 hours per three years as a result of a new preventive maintenance task. 

46 The increase in planned unavailability baseline was evaluated in the MSPI basis 

FAQ477

(11-02)

Linthicum 

3/3/12

FAQ477

(11-02)

FAQ477

(11-02)

FAQ477

(11-02)

Linthicum

3/3/12
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1 document Revision 3, dated 3/23/11, concluding that a revision to the PRA model was 

2 required prior to implementing the change. PRA model Revision 4 to reflect this change 

3 in planned unavailability was approved on 2/15/11. The revised values were 

4 incorporated into CDEError! Bookmark not defined. effective the second quarter 2011.

5

6 Following a design change that has a significant impact (≥ factor of three increase) on Birnbaum 

7 values, the following CDE comment would be appropriate:

8

9 A modification was completed on 1/15/11 that removed a monitored MOV in the 

10 Residual Heat Removal system. The MSPI basis document Revision 2 was approved 

11 on 3/12/11 to account for this impact. As removal of the MOV had a negligible impact 

12 on the overall CDF, the PRA model was not updated to reflect this change. The MSPI 

13 Basis Document Revision includes an evaluation of the impact on MSPI inputs which 

14 will be used until the next revision of the PRA model is completed.

15

16 Monitored Systems

17 Systems have been generically selected for this indicator based on their importance in preventing 

18 reactor core damage. The systems include the principal systems needed for maintaining reactor 

19 coolant inventory following a loss of coolant accident, for decay heat removal following a 

20 reactor trip or loss of main feedwater, and for providing emergency AC power following a loss 

21 of plant off-site power. One support function (cooling water support system) is also monitored. 

22 The cooling water support system monitors the cooling functions provided by service water and 

23 component cooling water, or their direct cooling water equivalents, for the four front-line 

24 monitored systems. Other support systems (e.g., HVAC room coolers, DC power, instrument 

25 air, etc.) will not be cascaded onto the monitored systems’ unavailability or reliability data. 

26 For the purposes of MSPI, a failure or unavailability of a support system component that is 

27 outside the system and train boundary of a monitored system will not result in unavailability 

28 of a monitored train or failure of a monitored component. No support systems are to be 

29 cascaded onto the monitored systems, e.g., HVAC room coolers, DC power, instrument air, etc.

30 Diverse Systems

31 Except as specifically stated in the indicator definition and reporting guidance, no credit is given 

32 for the achievement of a monitored function by an unmonitored system in determining 

33 unavailability or unreliability of the monitored systems.

34 Use of Plant-Specific PRAError! Bookmark not defined. and SPAR Models

35 The MSPI is an approximation using information from a plant’s PRA and is intended as an 

36 indicator of system performance. More accurate calculations using plant-specific PRAs or SPAR 

37 models cannot be used to question the outcome of the PIs computed in accordance with this 

38 guideline.

FAQ477

(11-02)

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(10-06)

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3/3/12
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1 Data Examples

Mitigating System Performance Index

1Q05 2Q05 3Q05 4Q05 1Q06

Unavailability Index (UAI) 8.48E-08 1.00E-09 8.72E-08 1.00E-06 1.00E-07

Unreliability Index (URI) 1.42E-06 1.00E-09 3.55E-07 1.00E-06 1.00E-07

Performance Limit Exceeded No No No Yes No

Indicator Value (Calculated) 1.50E-06 2.00E-09 4.42E-07 2.00E-07

Indicator Value (Displayed) 1.5E-06 2.0E-09 4.4E-07 PLE 2.0E-07

Thresholds

Green: ≤ 1.0E-06 9.00E-07 9.00E-07 9.00E-07 9.00E-07 9.00E-07

White: > 1.0E-06 or PLE=Yes 1.10E-06 1.10E-06 1.10E-06 1.10E-06 1.10E-06

Yellow: > 1.0E-05 1.00E-05 1.00E-05 1.00E-05 1.00E-05 1.00E-05

Red: > 1.0E-04 1.00E-04 1.00E-04 1.00E-04 1.00E-04 1.00E-04

1.5E-06 2.0E-09 4.4E-07 3.0E-06 2.0E-07

1.00E-09

1.00E-08

1.00E-07

1.00E-06

1.00E-05

1.00E-04

1.00E-03

1Q05 2Q05 3Q05 4Q05 1Q06

Mitigating System Performance Index

White > 1.0E-06

Green≤ 1.0E-06

Yellow > 1.0E-05

Red > 1.0E-04

2
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1 2.3 BARRIER INTEGRITY CORNERSTONE

2 The purpose of this cornerstone is to provide reasonable assurance that the physical design 

3 barriers (fuel cladding, reactor coolant system, and containment) protect the public from 

4 radionuclide releases caused by accidents or events. These barriers are an important element in 

5 meeting the NRC mission of assuring adequate protection of public health and safety. The 

6 performance indicators assist in monitoring the functionality of the fuel cladding and the reactor 

7 coolant system. There is currently no performance indicator for the containment barrier. The 

8 performance of this barrier is assured through the inspection program.

9

10 There are two performance indicators for this cornerstone:

11

12 • Reactor Coolant System (RCS) Specific Activity

13 • RCS Identified Leak Rate

14

15 REACTOR COOLANT SYSTEM (RCS) SPECIFIC ACTIVITY

16 Purpose

17 This indicator monitors the integrity of the fuel cladding, the first of the three barriers to prevent 

18 the release of fission products. It measures the radioactivity in the RCS as an indication of 

19 functionality of the cladding.

20

21 Indicator Definition

22 The maximum monthly RCS activity in micro-Curies per gram (μCi/gm) dose equivalent Iodine23 131 per the technical specifications, and expressed as a percentage of the technical specification 

24 limit. Those plants whose technical specifications are based on micro-curies per gram (μCi/gm)

25 total Iodine should use that measurement.

26

27 Data Reporting Elements

28 The following data are reported for each reactor unit:

29

30 • maximumMaximum calculated RCS activity for each unit, in micro-Curies per gram 

31 dose equivalent Iodine-131, as required by technical specifications at steady state 

32 power, for each month during the previous quarter (three values are reported).

33

34 • Technical Specification limit

35

36

37 Calculation

38 The indicator is calculated as follows:

39

unitUnit value = 100

Technical Specification limit

the maximum monthly value of calculated activity 40 ×
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1

2 Definitions of Terms

3 (Blank)

4

5 Clarifying Notes

6 This indicator is recorded monthly and reported quarterly.

7

8 The indicator is calculated using the same methodology, assumptions and conditions as for the 

9 Technical Specification calculation. If more than one method can be used to meet Technical 

10 Specifications, use the results of the method that was used at the time to satisfy the Technical 

11 Specifications.

12

13 Unless otherwise defined by the licensee, steady state is defined as continuous operation for at 

14 least three days at a power level that does not vary more than ±5 percent.

15

16 This indicator monitors the steady state integrity of the fuel-cladding barrier at power. Transient 

17 spikes in RCS Specific Activity following power changes, shutdowns and scrams may not 

18 provide a reliable indication of cladding integrity and should not be included in the monthly 

19 maximum for this indicator.

20

21 Samples taken using technical specification methodology, when shutdown, are not reported. 

22 However, samples taken using the technical specification methodology at steady state power 

23 more frequently than required are to be reported. If in the entire month, plant conditions do not 

24 require RCS activity to be calculated, the data field is left blank for that month and the status 

25 “Final – N/A” is selected.

26

27 Licensees should use the most restrictive regulatory limit (e.g., technical specifications (TS) or 

28 license condition). However, if the most restrictive regulatory limit is insufficient to assure plant 

29 safety, then NRC Administrative Letter 98-10 applies, which states that imposition of 

30 administrative controls is an acceptable short-term corrective action. When an administrative 

31 control is in place as a temporary measure to ensure that TS limits are met and to ensure public 

32 health and safety (i.e., to ensure 10 CFR Part 100 dose limits are not exceeded), that 

33 administrative limit should be used for this PI.

34

35

36
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1 Data Examples

Reactor Coolant System Specific Activity

4/98 5/98 6/98 7/98 8/98 9/98 10/98 11/98 12/98 1/99 2/99 Prev. mth

Indicator, % of T.S. Limit 10 20 5 4 0.5 2 20 50 60 40 30 10

Max Activity μCi/gm I-131 Equivalent 0.1 0.2 0.05 0.04 0.005 0.02 0.2 0.5 0.6 0.4 0.3 0.1

T.S Limit 1 1 1 1 1 1 1 1 1 1 1 1

Thresholds Green ≤ 50% T.S. limit

White > 50% T.S limit

Yellow >100% T.S. limit

0

10

20

30

40

50

60

70

80

90

100

4/98 5/98 6/98 7/98 8/98 9/98 10/98 11/98 12/98 1/99 2/99

Prev.

mth

Indicator, 

% T.S. Limit

Month

Reactor Coolant System Specific Activity

GREEN

WHITE

Note: Yellow>100% Tech. Spec Limit

2

3

4
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1 REACTOR COOLANT SYSTEM LEAKAGE

2 Purpose

3 This indicator monitors the integrity of the RCS pressure boundary, the second of the three 

4 barriers to prevent the release of fission products. It measures RCS Identified Leakage as a 

5 percentage of the technical specification allowable Identified Leakage to provide an indication of

6 RCS integrity.

7

8 Indicator Definition

9 The maximum RCS Identified Leakage in gallons per minute each month per the technical 

10 specifications and expressed as a percentage of the technical specification limit.

11

12 Data Reporting Elements

13 The following data are required to be reported each quarter:

14

15 • The maximum RCS Identified Leakage calculation for each month of the previous 

16 quarter (three values).

17 • Technical Specification limit

18

19 Calculation

20 The unit value for this indicator is calculated as follows:

21

unitUnit value = 100

Technical Specification limiting value

the maximum monthly value of identified leakage 22 ×

23

24 Definition of Terms

25 RCS Identified Leakage as defined in Technical Specifications.

26

27 Clarifying Notes

28 This indicator is recorded monthly and reported quarterly.

29

30 Normal steam generator tube leakage is included in the unit value calculation if required by the 

31 plant’s Technical Specification definition of RCS identified leakage.

32

33 For those plants that do not have a Technical Specification limit on Identified Leakage, substitute 

34 RCS Total Leakage in the Data Reporting Elements.

35

36 Any RCS leakage determination made in accordance with plant Technical Specifications 

37 methodology is included in the performance indicator calculation. If in the entire month, plant 

38 conditions do not require RCS leakage to be calculated, the data field is left blank for that month

39 and the status “Final-N/A” is selected )
NEI 99-02 [Revision 7]

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45

1

2 If the source and collection point of the leakage were unknown during the time period of the 

3 leak, and the actual collection point was not a monitored tank or sump per the RCS Leakage 

4 Calculation Procedure, then, for the purposes of this indicator, the leakage is not considered RCS 

5 identified leakage and is not to be included in PI data. RCS leakage not captured under this 

6 indicator may be evaluated in the inspection program. 

7

8 Data Examples

Reactor Coolant System Leakage (RCSL)

4/98 5/98 6/98 7/98 8/98 9/98 10/98 11/98 12/98 1/99 2/99

Indicator %T.S. Value 60 40 10 70 50 60 40 30 30 20 20

Identified Leakage (gpm) 6 4 1 7 5 6 4 3 3 2 2

TS Value (gpm) 10 10 10 10 10 10 10 10 10 10 10

Threshold

Green ≤50% TS limit

White >50% TS limit

Yellow >100%TS limit

Data collected monthly, reported quarterly

0

10

20

30

40

50

60

70

80

90

100

110

120

4/98 5/98 6/98 7/98 8/98 9/98 10/98 11/98 12/98 1/99 2/99

Prev.

mth

Indicator, 

% of T. S. Limit

Month

RCS Leakage

GREEN BAND

WHITE BAND

YELLOW BAND

9
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46

1 2.4 EMERGENCY PREPAREDNESS CORNERSTONE

2 The objective of this cornerstone is to ensure that the licensee is capable of implementing 

3 adequate measures to protect the public health and safety during a radiological emergency. 

4 Licensees maintain this capability through Emergency Response Organization (ERO) 

5 participation in drills, exercises, actual events, training, and subsequent problem identification 

6 and resolution. The Emergency Preparedness performance indicators provide a quantitative 

7 indication of the licensee’s ability to implement adequate measures to protect the public health 

8 and safety. These performance indicators create a licensee response band that allows NRC 

9 oversight of Emergency Preparedness programs through a baseline inspection program. These 

10 performance indicators measure onsite Emergency Preparedness programs. Offsite programs are 

11 evaluated by FEMA.

12

13 The protection of public health and safety is assured by a defense in depth philosophy that relies 

14 on: safe reactor design and operation, the operation of mitigation features and systems, a multi15 layered barrier system to prevent fission product release, and emergency preparedness.

16

17 The Emergency Preparedness cornerstone performance indicators are:

18

19 • Drill/Exercise performance (DEP),

20 • Emergency Response Organization Drill Participation (ERO),

21 • Alert and Notification System Reliability (ANS)

22

23 DRILL/EXERCISE PERFORMANCE

24 Purpose

25 This indicator monitors timely and accurate licensee performance in drills and exercises when 

26 presented with opportunities for classification of emergencies, notification of offsite authorities, 

27 and development of protective action recommendations (PARs). It is the ratio, in percent, of 

28 timely and accurate performance of those actions to total opportunities.

29

30 The notification timeliness criterion for this PI is met when the licensee makes contact with the 

31 first responsible State or local governmental agency within 15 minutes. This success criterion 

32 normalizes the notification capabilities of licensees, regardless of the number of site specific offsite 

33 notification requirements. As such, NRC and licensees can assess a site’s specific capability to a common 

34 industry baseline to identify the possible need for additional inspection resources. Further, the 

35 notification performance enhancement opportunity provides the NRC assurance that a licensee is 

36 conducting the notification process in its entirety and evaluating compliance with the regulatory offsite 

37 notification requirement of Appendix E.IV.D.3 to 10 CFR Part 50.

38

39

40 Indicator Definition

41

42 The percentage of all drill, exercise, and actual opportunities that were performed timely and 

43 accurately by Key Positions, as defined in the ERO Drill Participation performance indicator, 

44 during the previous eight quarters.

45

FAQ 12-06
NEI 99-02 [Revision 7]

08/31/2013

47

1 Data Reporting Elements

2 The following data are required to calculate this indicator:

3

4 • theThe number of drill, exercise, and actual event opportunities during the previous quarter.

5

6 • theThe number of drill, exercise, and actual event opportunities performed timely and 

7 accurately during the previous quarter.

8

9 The indicator is calculated and reported quarterly. (See clarifying notes)

10 Calculation

11 The site average values for this indicator are calculated as follows:

12

100

The total opportunities to perform classifications, notifications & PARs during the previous 8 quarters

# of timely & accurate classifications, notifications, & PARsfrom DE & AEs *during the previous 8 quarters ×



 



 13

14

15 *DE & AEs = Drills, Exercises, and Actual Events

16

17 Definition of Terms

18 Opportunities should include multiple events during a single drill or exercise (if supported by the 

19 scenario) or actual event, as follows:

20

21 • each expected classification or upgrade in classification

22 • each initial notification of an emergency class declaration

23 • each initial notification of PARs or change to PARs

24 • each PAR developed

25

26 Timely means:

27

28 • classifications are made consistent with the goal of 15 minutes once available plant 

29 parameters reach an Emergency Action Level (EAL)

30 • PARs are made consistent with the goal of 15 minutes once data is available.

31 • offsite notifications are initiated within 15 minutes of event classification and/or PAR 

32 development (see clarifying notes)

33

34 Accurate means:

35

36 • Classification and PAR appropriate to the event as specified by the approved plan and 

37 implementing procedures (see clarifying notes)

38 • Initial notification form completed appropriate to the event to include (see clarifying notes):

39 - Class of emergency

40 - EAL number

41 - Description of emergency

42 - Wind direction and speed

43 - Whether offsite protective measures are necessary
NEI 99-02 [Revision 7]

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48

1 - Potentially affected population and areas

2 - Whether a release is taking place

3 - Date and time of declaration of emergency

4 - Whether the event is a drill or actual event

5 - Plant and/or unit as applicable

6

7 Clarifying Notes

8 While actual event opportunities are included in the performance indicator data, the NRC will 

9 also inspect licensee response to all actual events.

10

11 As a minimum, actual emergency declarations and evaluated exercises are to be included in this 

12 indicator. In addition, other simulated emergency events that the licensee formally assesses for 

13 performance of classification, notification or PAR development may be included in this indicator 

14 (opportunities cannot be removed from the indicator due to poor performance).

15

16 The following information provides additional clarification of the accuracy requirements 

17 described above:

18

19 • It is understood that initial notification forms are negotiated with offsite authorities. If 

20 the approved form does not include these elements, they need not be added. Alternately, 

21 if the form includes elements in addition to these, those elements need not be assessed for 

22 accuracy when determining the DEP PI. It is, however, expected that errors in such 

23 additional elements would be critiqued and addressed through the corrective action 

24 system.

25

26 • The description of the event causing the classification may be brief and need not include 

27 all plant conditions. At some sites, the EAL number is the description.

28

29 • “Release” means a radiological release attributable to the emergency event.

30

31 • Minor discrepancies in the wind speed and direction provided on the emergency 

32 notification form need not count as a missed notification opportunity provided the 

33 discrepancy would not result in an incorrect PAR being provided. 

34

35 The licensee shall identify, in advance, drills, exercises and other performance enhancing 

36 experiences in which opportunities will be formally assessed, and shall be available for NRC 

37 review. The licensee has the latitude to include opportunities in the PI statistics as long as the 

38 drill (in whatever form) simulates the appropriate level of inter-facility interaction. The criteria 

39 for suitable drills/performance enhancing experiences are provided under the ERO Drill 

40 Participation PI clarifying notes. 

41

42 If credit for an opportunity is given in the ERO Drill Participation performance indicator, then 

43 that opportunity must be included in the drill/exercise performance indicator. For example, if the 

44 communicator performing the entire notification during performance enhancing scenario is an 

45 ERO member in a Key Position, then the notification may be considered as an opportunity and, if 

46 so, participation credit awarded to the ERO member in the Key Position. 

47
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49

1 If an ERO member in a Key Position supports multiple units (at one or more sites), 

2 Drill/Exercise Performance (DEP) opportunities performed by the ERO member may be 

3 credited to all sites potentially served by the ERO member, in addition to the specific site 

4 participating in the drill or exercise.

5

6 When a performance enhancing experience occurs before an individual is assigned to a Key 

7 Position in the ERO, then opportunities for that individual that were identified in advance shall 

8 contribute to the Drill/Exercise (DEP) metric at the time the member is assigned to the ERO. 

9

10 Performance statistics from operating shift simulator training evaluations may be included in this 

11 indicator only when the scope requires classification. Classification, PAR notifications and 

12 PARs performed in the simulator may be included in the indicator. Notifications for 

13 Classification and Notifications for PARs may be included in this indicator if they are 

14 performed to the point of filling out the appropriate forms and demonstrating sufficient

15 knowledge to perform the actual notification.

16

17 “Demonstrating sufficient knowledge” is defined as demonstrating the use of communications 

18 equipment to contact the first offsite stakeholder for the purpose of transmitting initial 

19 notification information (offsite stakeholder maybe role-played) in accordance with site 

20 communication procedure(s), as well as, if used, demonstration of the needed interface 

21 between the key ERO communicator and the phone-talker. It is recognized that key control 

22 room positions may not perform the actual communication with offsite agencies as part of the 

23 notification process. Personnel filling non-key positions for contacting offsite agencies (phone24 talker) may not be available during simulator training. If an evaluator role-plays the phone25 talker during the simulator session, a phone-talker is required to complete the notification 

26 process out of sequence (e.g. notification form completed in the simulator is provided to a 

27 phone-talker at a later time and the phone-talker demonstrates use of the telephone equipment to 

28 an evaluator). Interactions normally between the Key Communicator and the phone-talker (e.g. 

29 receiving instruction, discussion of the notification and correction of errors in the notification 

30 form) occur between the phone-talker and an evaluator role playing the Key Communicator for 

31 this off-sequence demonstration. Timeliness is determined by adding the time required to 

32 complete the notification form in the simulator to the time required by the phone-talker to 

33 interact and then utilize the communications equipment out of sequence. However, there is no 

34 intent to disrupt ongoing operator qualification programs. Appropriate operator training 

35 evolutions should be included in the indicator only when Emergency Preparedness aspects are 

36 consistent with training goals. A successful PI opportunity is determined by evaluating 

37 performance against program expectations. Thus, if it is part of a pre-established expectation to 

38 enhance the realism of the training environment by marking “actual” on the notification forms, it 

39 should be considered a successful PI opportunity if a simulator crew marks “actual” on the 

40 notification form. However, all notification forms must be marked consistently, either “drill” or 

41 “actual” in accordance with the requirements of the licensee’s emergency preparedness program 

42 expectation. Not marking either drill or actual event (regardless of expectations) shall be a failed 

43 opportunity. 

44

45 Some licensees have specific arrangements with their State authorities that provide for different 

46 notification requirements than those prescribed by the performance indicator, e.g., within one 

47 hour, not 15 minutes. In these instances the licensee should determine success against the 

48 specific state requirements.

FAQ471

(09-06)

FAQ476

(09-10)

Hug

01/23/13
NEI 99-02 [Revision 7]

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50

1

2 For sites with multiple agencies to notify, the notification is considered to be initiated when 

3 contact is made with the first agency to transmit the initial notification information. 

4

5 Simulation of notification to offsite agencies is allowed. It is not expected that State/local 

6 agencies be available to support all drills conducted by licensees. The drill should reasonably 

7 simulate the contact and the participants should demonstrate their ability to use the equipment. 

8

9 Classification is expected to be made promptly following indication that the conditions have 

10 reached an emergency threshold in accordance with the licensee’s EAL scheme. With respect to 

11 classification of emergencies, the 15 minute goal is a reasonable period of time for assessing and 

12 classifying an emergency once indications are available to control room operators that an EAL 

13 has been exceeded. Allowing a delay in classifying an emergency up to 15 minutes will have 

14 minimal impact upon the overall emergency response to protect the public health and safety. 

15 The 15-minute goal should not be interpreted as providing a grace period in which a licensee 

16 may attempt to restore plant conditions and avoid classifying the emergency.

17

18 If an event has occurred that resulted in an emergency classification where no EAL was 

19 exceeded, the incorrect classification should be considered a missed opportunity. The subsequent 

20 notification should be considered an opportunity and evaluated on its own merits.

21

22 During drill performance, the ERO may not always classify an event exactly the way that the 

23 scenario specifies. This could be due to conservative decision making, Emergency Director 

24 judgment call, or a simulator driven scenario that has the potential for multiple ‘forks’. Situations 

25 can arise in which assessment of classification opportunities is subjective due to deviation from 

26 the expected scenario path. In such cases, evaluators should document the rationale supporting 

27 their decision for eventual NRC inspection. Evaluators must determine if the classification was 

28 appropriate to the event as presented to the participants and in accordance with the approved 

29 emergency plan and implementing procedures. 

30

31 If the expected classification level is missed because an EAL is not recognized within 15 minutes 

32 of availability, but a subsequent EAL for the same classification level is subsequently 

33 recognized, the subsequent classification is not an opportunity for DEP statistics. The reason 

34 that the classification is not an opportunity is that the appropriate classification level was not 

35 attained in a timely manner.

36

37 If a controller intervenes (e.g., coaching, prompting) with the performance of an individual to 

38 make an independent and correct classification, notification, or PAR, then that DEP PI 

39 opportunity shall be considered a failure. 

40

41 Failure to appropriately classify an event counts as only one failure: This is because notification 

42 of the classification, development of any PARs and PAR notification are subsequent actions to 

43 classification. Similarly, if the same error occurs in follow-up notifications, it should only be 

44 considered a missed opportunity on the initial notification form. 

45 A Classification based on a downgrade from a previously existing higher classification is not 

46 counted as an opportunity. It was not the intent to count downgrades as opportunities for the 

47 DEP performance indicator. When a higher classification is reached in a drill, exercise or real 

48 event it is probable that multiple EALs at equal or lower levels have also been exceeded. When 
NEI 99-02 [Revision 7]

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51

1 the reason for the highest classification is cleared, many of the lower conditions may still exist. 

2 It is impractical to evaluate downgrades in classification from a timeliness and accuracy 

3 standpoint. The notification of the downgrade should be handled as an update rather than a 

4 formal opportunity for the performance indicator. 

5

6 The notification associated with a PAR is counted separately: e. g., an event triggering a GE 

7 classification would represent a total of 4 opportunities: 1 for classification of the GE, 1 for 

8 notification of the GE to the State and/or local government authorities, 1 for development of a 

9 PAR and 1 for notification of the PAR. All PAR notifications resulting in a Recommendation of 

10 Evacuation or Shelter, whether default or not, should be counted as an opportunity for the 

11 drill/exercise performance indicator. 

12

13 If PARs at the SAE are in the site Emergency Plan they could be counted as opportunities. 

14 However, this would only be appropriate where assessment and decision making is involved in 

15 development of the PAR. Automatic PARs with little or no assessment required would not be an 

16 appropriate contributor to the PI. PARs limited to livestock or crops and no no-PAR PAR17 necessary decisions are also not appropriate.

18

19 Dose assessment and PAR development are expected to be made promptly following indications 

20 that the conditions have reached a threshold in accordance with the licensee’s PAR scheme. The 

21 15 minute goal from data availability is a reasonable period of time to develop or expand a PAR. 

22 Plant conditions, meteorological data, field monitoring data, and/or radiation monitor data should 

23 provide sufficient information to determine the need to change PARs. If radiation monitor 

24 readings provide sufficient data for assessments, it is not appropriate to wait for field monitoring 

25 to become available to confirm the need to expand the PAR. The 15 minute goal should not be 

26 interpreted as providing a grace period in which the licensee may attempt to restore conditions 

27 and avoid making the PAR recommendation. 

28

29 If a licensee has identified in its scenario objectives that Protective Action Guidelines (PAGs) 

30 will be exceeded beyond the 10 mile plume exposure pathway emergency planning zone (EPZ) 

31 boundary, then this would constitute a PI opportunity. In addition, there is a DEP PI opportunity 

32 associated with the timeliness of the notification of the PAR to offsite agencies. Essential to 

33 understanding that these DEP PI opportunities exist is the need to realize that it is a regulatory 

34 requirement for a licensee to develop and communicate a PAR when EPA PAG doses may be 

35 exceeded beyond the 10 mile plume exposure pathway EPZ. However, the licensee always has 

36 the latitude to identify which DEP PI opportunities will be included in the PI statistics prior to 

37 the exercise. Thus, a licensee may choose to not include a PAR beyond the 10-mile EPZ as a 

38 DEP PI statistic due to its ad hoc nature. 

39

40 If a licensee discovers after the fact (greater than 15 minutes) that an event or condition had 

41 existed which exceeded an EAL, but no emergency had been declared and the EAL is no longer 

42 exceeded at the time of discovery, the following applies: 

43 • If the indication of the event was not available to the operator, the event should not be 

44 evaluated for PI purposes.

45 • If the indication of the event was available to the operator but not recognized, it should be 

46 considered an unsuccessful classification opportunity.

47 • In either case described above, notification should be performed in accordance with 

48 NUREG-1022 and not be evaluated as a notification opportunity.
NEI 99-02 [Revision 7]

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52

1 Data Example

2

Emergency Response Organization

Drill/Exercise Performance 

3Q/96 4Q/96 1Q/97 2Q/97 3Q/97 4Q/97 1Q/98 2Q/98 3Q/98 4Q/98 Prev. Q

Successful Classifications, Notifications & PARs over qtr 0 0 11 11 0 8 10 0 23 11 12

Opportunities to Perform Classifications, Notifications, & PARs in qtr 0 0 12 12 0 12 12 0 24 12 12

Total # of succesful Classifications, Notifications, & PARs in 8 qtrs 40 63 74 75

Total # of opportunities to perform Classification, Notifications & PARs in 8 qtrs 48 72 84 84

2Q/98 3Q/98 4Q/98 Prev. Q

83.3% 87.5% 88.1% 89.3%

Threshold

Green ≥ 90%

White < 90%

Yellow < 70%

Red Not Applicable

Indicator expressed as a percentage of Opportunities to perform Classifications, Communications & PARs

0.6

0.7

0.8

0.9

1

2Q/98 3Q/98 4Q/98 Prev. Q

Indicator

Quarter

EP Drill/Exercise Performance

GREEN



YELLOW

Note: No Red Threshold

WHITE
NEI 99-02 [Revision 7]

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53

1 EMERGENCY RESPONSE ORGANIZATION DRILL PARTICIPATION

2 Purpose

3 This indicator tracks the participation of ERO members assigned to fill Key Positions in 

4 performance enhancing experiences, and through linkage to the DEP indicator ensures that the 

5 risk significant aspects of classification, notification, and PAR development are evaluated and 

6 included in the PI process. This indicator measures the percentage of ERO members assigned to 

7 fill Key Positions who have participated recently in performance-enhancing experiences such as 

8 drills, exercises, or in an actual event.

9

10 Indicator Definition

11 The percentage of ERO members assigned to fill Key Positions that have participated in a drill, 

12 exercise, or actual event during the previous eight quarters, as measured on the last calendar day 

13 of the quarter.

14

15 Data Reporting Elements

16 The following data are required to calculate this indicator and are reported:

17

18 • total number of ERO members assigned to fill Key Positions

19 • total number of ERO members assigned to fill Key Positions that have participated in a 

20 drill, exercise, or actual event in the previous eight quarters

21

22 The indicator is calculated and reported quarterly, based on participation over the previous eight 

23 quarters (see clarifying notes).

24

25 The participation indicator may include participation in a facility that supports multiple units.

26

27 Calculation

28 The site indicator is calculated as follows:

29

100

Total number of Key Positions assigned to ERO Members

# of ERO members assigned to Key Positions that have participated in drill, exercise or actual event the previous 8 qrts 30 ×

31

32

33 Definition of Terms

34 Key Positions are defined below

35

36 • Control Room

37

38 • Shift Manager (Emergency Director) - Supervision of reactor operations, responsible 

39 for classification, notification, and determination of protective action 

40 recommendations

41

42 • Shift Communicator - provides initial offsite (state/local) notification

FAQ476

(09-10)
NEI 99-02 [Revision 7]

08/31/2013

54

1

2 • Technical Support Center

3

4 • Senior Manager - Management of plant operations/corporate resources

5 • Key Operations Support 

6 • Key Radiological Controls - Radiological effluent and environs monitoring, 

7 assessment, and dose projections

8 • Key TSC Communicator- provides offsite (state/local) notification

9 • Key Technical Support

10

11 • Emergency Operations Facility

12

13 • Senior Manager - Management of corporate resources

14 • Key Protective Measures - Radiological effluent and environs monitoring, 

15 assessment, and dose projections

16 • Key EOF Communicator- provides offsite (state/local) notification 

17

18 • Operational Support Center

19

20 • Key OSC Operations Manager 

21 • Assigned: Those ERO personnel filling Key Positions listed on the licensee duty roster on the 

22 last day of the quarter of the reporting period. 

23

24 Clarifying Notes

25 When the performance of Key Positions includes classification, notification, or PAR 

26 development opportunities, the success rate of these opportunities must contribute to 

27 Drill/Exercise Performance (DEP) statistics for participation of those Key Positions to contribute 

28 to ERO Drill Participation. Participation drill credit before being assigned to the ERO may be 

29 counted for these Key Positions once the individual is assigned to the ERO as long as the success 

30 rate for the opportunities contributes to Drill/Exercise (DEP) statistics.

31

32 The licensee may designate drills as not contributing to DEP and, if the drill provides a 

33 performance enhancing experience as described herein, those Key Positions that do not involve 

34 classification, notification or PARs may be given credit for ERO Drill Participation. 

35 Additionally, the licensee may designate elements of the drills not contributing to DEP (e.g., 

36 classifications will not contribute but notifications will contribute to DEP.) In this case, the 

37 participation of all Key Positions, except those associated with the non-contributing elements, 

38 may contribute to ERO Drill Participation. Participation drill credit before being assigned to the 

39 ERO may be counted for the Key Positions not contributing to DEP if the drill provides a 

40 performance enhancing experience as described herein. The licensee must document such 

41 designations in advance of drill performance and make these records available for NRC 

42 inspection. 

43

44 In order for an opportunity to be considered a performance enhancing experience for a Key 

45 Communicator, the opportunity must include demonstration of the ability to perform a 

46 notification of the emergency classification level to required agencies. Documentation of the 

47 opportunity and its evaluation/critique is to be comprehensive enough to allow an Inspector to reasonably 

48 reach the same conclusion as the licensee as to the adequacy of the performing enhancing experience.

FAQ 12-06
NEI 99-02 [Revision 7]

08/31/2013

55

1

2 Option for Emergency Response Organizations with Common Facilities

3

4 If an ERO member in a Key Position supports multiple units (at one or more sites) and 

5 demonstrates similar skill sets during a performance-enhancing experience, participation 

6 credit may be granted for all sites supported.

7

8 Negative performance credit as well as positive performance credit will be assigned to all 

9 units.

10

11 Similarity of Skill Sets

12

13 Skill sets are considered similar when the procedures, processes and protocols involved 

14 accomplish the same task or goal. Examples of similar skill sets are provided below.

15

16 Classification

17

18 Classification of Emergencies are similar when Emergency Action Level procedures, 

19 processes and protocols used by the ERO members in the Key Position are essentially the 

20 same (for example all units would use NEI 99-01 or in the case where a unit may be an

21 advanced passive light water reactor it would be acceptable to utilize NEI 99-01 for 

22 existing technology and NEI 07-01 for passive technology). Training for key ERO 

23 members performing this function is to include unit-specific and/or technology differences 

24 relating to Initiating Conditions/Emergency Action Levels (e.g., ISFSI, unique hazards, 

25 design considerations, etc.).

26

27 Protective Action Recommendations (PARs)

28

29 Protective Action Recommendations, when developed with the same protective action 

30 strategies, are similar provided that the procedures, processes and protocols for the 

31 development of the protective action recommendations are essentially the same. For 

32 example:

33 • Logic flow charts may differ (e.g., because of population differences among the 

34 sites), but should serve the same purpose and be used in the same way. 

35 • Protective Action Zones may differ, but the process used to identify the action taken 

36 for the zones is the same. 

37 • Implementation of potassium iodide (KI) strategies may differ based on the 

38 implementation strategies of responsible authorities at the State and/or Local level, 

39 but the procedures, processes and protocols used to determine if KI is warranted 

40 should be the same. 

41 • PAR development discussion strategies should be the same for each site supported by 

42 the common facility. 

43

44 Dose Assessment

45

46 Dose assessment is similar when methodologies, applicable computer programs, and 

47 models are the same across sites and/or unit technologies served by the common facility. 

48 Definitions of what constitutes a radiological release during a classified emergency are 

FAQ476

(09-10)

FAQ476

(09-10)
NEI 99-02 [Revision 7]

08/31/2013

56

1 the same. Training for key ERO members performing this function must include unit2 specific differences in effluent monitors and release pathways, local meteorological 

3 regimes and topography impacts and how these differences impact the dose assessment.

4

5 Emergency Notifications

6

7 The emergency communicator functions are similar when procedures, processes and 

8 protocols are performed utilizing a similar emergency notification form design and 

9 content. Emergency communicators will be trained on all notification procedures, 

10 processes and protocol differences including, but not limited to, offsite contacts, form 

11 content, methods and equipment.

12

13 Link to Drill and Exercise Performance

14

15 Lessons learned (positive and negative) are shared to ensure that the benefits of the 

16 performance enhancing experience of the key ERO member(s) are applied across all 

17 units. Corrective actions from the performance of key ERO members performing DEP 

18 activities are shared with and applied to all key ERO members of all units. Similarly, 

19 corrective actions associated with common facility Key ERO member performance (e.g. 

20 training or qualification gaps, procedure deficiencies, equipment issues) are applied 

21 across all units corrective action programs. DEP opportunities performed shall be 

22 credited to all units, in addition to the unit participating in the drill or exercise.

23

24 Records

25

26 Lesson plans, rosters, records, etc., are available for NRC inspection. 

27

28 Credit can be granted to Key Positions for ERO Participation for a Security related Drill or 

29 Exercise as long as the Key Positions are observed evaluating the need to upgrade to the next 

30 higher classification level and/or evaluating the need to change protective action 

31 recommendations. Key TSC Communicator and Key EOF Communicator may be granted 

32 participation credit as long as the Key Position performs a minimum of one offsite (state/local) 

33 update notification. If an individual participates in more than one Security-related Drill/Exercise 

34 in a three year period, only one of the Security-related Drills/Exercise can be credited. A station 

35 cannot run more than one credited Security-related Drill/Exercise in any consecutive 4 quarter 

36 period. Objective evidence shall be documented to demonstrate the above requirements were 

37 met.

38

39 Evaluated simulator training evolutions that contribute to Drill/Exercise Performance indicator 

40 statistics may be considered as opportunities for ERO Drill Participation. The scenarios must at 

41 least contain a formally assessed classification and the results must be included in DEP statistics. 

42 However, there is no intent to disrupt ongoing operator qualification programs. Appropriate 

43 operator training evolutions should be included in this indicator only when Emergency 

44 Preparedness aspects are consistent with training goals. 

45

46 If an ERO member filling a Key Position has participated in more than one drill during the eight 

47 quarter evaluation period, the most recent participation should be used in the Indicator statistics.

48

FAQ476

(09-10)
NEI 99-02 [Revision 7]

08/31/2013

57

1 If a change occurs in the number of ERO members filling Key Positions, this change should be 

2 reflected in both the numerator and denominator of the indicator calculation.

3

4 If a person is assigned to more than one Key Position, it is expected that the person be counted in 

5 the denominator for each position and in the numerator only for drill participation that addresses 

6 each position. Where the skill set is similar, a single drill might be counted as participation in 

7 both positions. 

8

9 Assigning a single member to multiple Key Positions and then only counting the performance for 

10 one Key Position could mask the ability or proficiency of the remaining Key Positions. The 

11 concern is that an ERO member having multiple Key Positions may never have a performance 

12 enhancing experience for all of them, yet credit for participation will be given when any one of 

13 the multiple Key Positions is performed; particularly, if more than one ERO position is assigned 

14 to perform the same Key Position. 

15

16 ERO participation should be counted for each Key Position, even when multiple Key Positions 

17 are assigned to the same ERO member. In the case where a utility has assigned two or more Key 

18 Positions to a single ERO member, each Key Position must be counted in the denominator for 

19 that ERO member and credit given in the numerator when the ERO member performs each Key 

20 Position.

21

22 Similarly, ERO members need not individually perform an opportunity of classification, 

23 notification, or PAR development in order to receive ERO Drill Participation credit. The 

24 evaluation of the DEP opportunities is a crew evaluation for the entire Emergency Response 

25 Organization. ERO members may receive credit for the drill if their participation is a meaningful 

26 opportunity to gain proficiency in their ERO function. 

27

28 When an ERO member changes from one Key Position to a different Key Position with a skill 

29 set similar to the old one, the last drill/exercise participation may count. If the skill set for the 

30 new position is significantly different from the old position then the previous participation would 

31 not count. 

32

33 Participation may be as a participant, mentor, coach, evaluator, or controller, but not as an 

34 observer. Multiple assignees to a given Key Position could take credit for the same drill if their 

35 participation is a meaningful opportunity to gain proficiency.

36

37 Drills performed by an individual before being assigned to a Key Position in the ERO may be 

38 counted once the individual is assigned to the ERO as long as the performance enhancing 

39 experience(s) contributes to the Drill/Exercise (DEP) metric. The meaning of “drills” in this 

40 usage is intended to include performance enhancing experiences (exercises, functional drills, 

41 simulator drills, table top drills, mini drills, etc.) that reasonably simulate the interactions 

42 between appropriate centers and/or individuals that would be expected to occur during 

43 emergencies. For example, control room interaction with offsite agencies could be simulated by 

44 instructors or OSC interaction could be simulated by a control cell simulating the TSC functions, 

45 and damage control teams. 

46
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1 In general, a drill does not have to include all ERO facilities to be counted in this indicator. A 

2 drill is of adequate scope if it reasonably simulates the interaction between one or more of the 

3 following facilities, as would be expected to occur during emergencies: 

4

5 • the control room, 

6 • the Technical Support Center (TSC), 

7 • the Operations Support Center, 

8 • the Emergency Operations Facility (EOF),

9 • field monitoring teams,

10 • damage control teams, and

11 • offsiteOffsite governmental authorities.

12

13 The licensee need not develop new scenarios for each drill or each team. However, it is expected 

14 that the licensee will maintain a reasonable level of confidentiality so as to ensure the drill is a 

15 performance enhancing experience. A reasonable level of confidentiality means that some 

16 scenario information could be inadvertently revealed and the drill remain a valid performance 

17 enhancing experience. It is expected that the licensee will remove from drill performance 

18 statistics any opportunities considered to be compromised. There are many processes for the 

19 maintenance of scenario confidentiality that are generally successful. Examples may include 

20 confidentiality statements on the signed attendance sheets and spoken admonitions by drill 

21 controllers. Examples of practices that may challenge scenario confidentiality include drill 

22 controllers or evaluators or mentors, who have scenario knowledge becoming participants in 

23 subsequent uses of the same scenarios and use of scenario reviewers as participants. 

24

25 All individuals qualified to fill the Control Room Shift Manager/ Emergency Director position 

26 that actually might fill the position should be included in this indicator. 

27

28 The communicator is the Key Position that fills out the notification form, seeks approval and 

29 usually communicates the information to off siteoffsite agencies. Performance of these duties is 

30 assessed for accuracy and timeliness and contributes to the DEP PI. Senior managers who do not 

31 perform these duties should not be considered communicators even though they approve the 

32 form and may supervise the work of the communicator. However, there are cases where the 

33 senior manager actually collects the data for the form, fills it out, approves it and then 

34 communicates it or hands it off to a phone talker. Where this is the case, the senior manager is 

35 also the communicator and the phone talker need not be tracked. The communicator is not 

36 expected to be just a phone talker who is not tasked with filling out the form. There is no intent 

37 to track a large number of shift communicators or personnel who are just phone talkers.

38

39

40
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1 Data Example

Emergency Response Organization (ERO) Drill Participation

2Q/98 3Q/98 4Q/98 Prev. Q

Total number of Key ERO personnel 56 56 64 64

Number of Key personnel participating in drill/event in 8 qtrs 48 52 54 53

2Q/98 3Q/98 4Q/98 Prev. Q

Indicator percentage of Key ERO personnel participating in a drill in 8 qtrs 86% 93% 84% 83%

Thresholds

Green ≥80%

White <80%

Yellow <60%

No Red Threshold

50%

60%

70%

80%

90%

100%

2Q/98 3Q/98 4Q/98 Prev. Q

Indicator

Quarter

ERO Drill Participation

GREEN

WHITE

YELLOW Note: No Red threshold

2
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1 ALERT AND NOTIFICATION SYSTEM RELIABILITY 

2 Purpose

3 This indicator monitors the reliability of the offsite Alert and Notification System (ANS), a 

4 critical link for alerting and notifying the public of the need to take protective actions. It 

5 provides the percentage of the sirens that are capable of performing their safety function based 

6 on regularly scheduled tests.

7

8 Indicator Definition

9 The percentage of ANS sirens that are capable of performing their function, as measured by 

10 periodic siren testing in the previous 12 months.

11

12 Periodic tests are the regularly scheduled tests (documented in the licensee’s test plan or 

13 guidelines) that are conducted to actually test the ability of the sirens to perform their function 

14 (e.g., silent, growl, siren sound test). Tests performed for maintenance purposes should not be 

15 counted in the performance indicator database. Actions that could affect the as found condition 

16 of sirens prior to testing are not allowed.

17

18

19 Data Reporting Elements

20 The following data are reported: (see clarifying notes)

21

22 • the total number of ANS siren-tests during the previous quarter

23 • the number of successful ANS siren-tests during the previous quarter 

24

25 Calculation

26 The site value for this indicator is calculated as follows:

27

100

total number of siren - testsin the previous 4 qtrs

# of succesfulsiren - testsin the previous 4 qtrs 28 ×

29

30 Definition of Terms

31 Siren-Tests: the number of sirens times the number of times they are tested. For example, if 100 

32 sirens are tested 3 times in the quarter, there are 300 siren-tests.

33

34 Successful siren-tests are the sum of sirens that performed their function when tested. For 

35 example, if 100 sirens are tested three times in the quarter and the results of the three tests are: 

36 first test, 90 performed their function; second test, 100 performed their function; third test, 80 

37 performed their function. There were 270 successful siren-tests.

38 Clarifying Notes

39 The purpose of the ANS PI is to provide a uniform industry reporting approach and is not 

40 intended to replace the FEMA Alert and Notification reporting requirement at this time.
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1

2 For those sites that do not have sirens, the performance of the licensee’s alert and notification 

3 system will be evaluated through the NRC baseline inspection program. A site that does not 

4 have sirens does not report data for this indicator.

5

6 If a siren is out of service for maintenance or is inoperable at the time a regularly scheduled test 

7 is conducted, then it counts as both a siren test and a siren failure. Regularly scheduled tests 

8 missed for reasons other than siren unavailability (e.g., out of service for planned maintenance or 

9 repair) should be considered non opportunities. The failure to perform a regularly scheduled test 

10 should be noted in the comment field. Additionally, if sirens are not available for operation because of 

11 intentional actions to disable them, and the area is deemed uninhabitable by State and/or Local agencies, 

12 the siren(s) in question are not required to be counted in the numerator or denominator of the 

13 Performance Indicator for testing throughout the event. The conditions causing the suspension of testing, 

14 its duration and restoration are to be noted in the comment field for the indicator.

15

16 For plants where scheduled siren tests are initiated by local or state governments, if a scheduled 

17 test is not performed either intentionally or accidentally, the missed test is not considered as valid 

18 test opportunities. Missed test occurrences should be entered in the plant’s corrective action 

19 program. 

20

21 If a siren failure is determined to be due only to testing equipment, and subsequent testing shows 

22 the siren to be operable (verified by telemetry or simultaneous local verification) without any 

23 corrective action having been performed, the siren test should be considered a success. 

24 Maintenance records should be complete enough to support such determinations and validation 

25 during NRC inspection. 

26

27 A licensee may change ANS test methodology at any time consistent with regulatory guidance. 

28 For the purposes of this performance indicator, only the testing methodology in effect on the first 

29 day of the quarter shall be used for that quarter. Neither successes nor failures beyond the testing 

30 methodology at the beginning of the quarter will be counted in the PI. (No actual siren activation 

31 data results shall be included in licensees’ ANS PI data.) Any change in test methodology shall 

32 be reported as part of the ANS Reliability Performance Indicator effective the start of the next 

33 quarterly reporting period. Changes should be noted in the comment field. 

34

35 Siren systems may be designed with equipment redundancy, multiple signals or feedback 

36 capability. It may be possible for sirens to be activated from multiple control stations or signals. 

37 If the use of redundant control stations or multiple signals is in approved procedures and is part 

38 of the actual system activation process then activation from either control station or any signal 

39 should be considered a success. A failure of both systems would only be considered one failure, 

40 whereas the success of either system would be considered a success. If the redundant control 

41 station is not normally attended, requires setup or initialization, it may not be considered as part 

42 of the regularly scheduled test. Specifically, if the station is only made ready for the purpose of 

43 siren tests it should not be considered as part of the regularly scheduled test. 

44

45 Actions specifically taken to improve the performance of a scheduled test are not appropriate. 

46 The test results should indicate the actual as-found condition of the ANS. Such practices will 

47 result in an inaccurate indication of ANS reliability. 

48

FAQ

11-13
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1 Examples of actions that are NOT allowed and DO affect the as found conditions of sirens (not 

2 an all inclusiveall-inclusive list):

3

4 o Preceding test with an unscheduled test with the sole purpose to validate the siren 

5 is functional. 

6

7 o Prior to a scheduled test, adjustment or calibration of siren system activation 

8 equipment that was not scheduled to support post maintenance testing.

9

10 o Prior to a scheduled test, testing siren system activation equipment or an 

11 individual siren(s) unless the equipment is suspected damaged from adverse 

12 weather, vandalism, vehicular strikes, etc.

13

14 o Prior to a scheduled test, testing siren system activation equipment or an 

15 individual siren(s) unless the equipment is suspected as being non-functional as a 

16 result of a computer hardware or software failure, radio tower failure, cut phone 

17 line, etc.

18

19 However, in no case should response preclude the timely correction of ANS problems and 

20 subsequent post-maintenance testing, or the execution of a comprehensive preventive 

21 maintenance program.

22

23 Testing opportunities that will be included in the ANS performance indicator are required to be 

24 defined in licensee ANS procedures. These are typically: bi-weekly, monthly quarterly and 

25 annual tests. The site specific ANS design and testing document approved by FEMA is a 

26 reference for the appropriate types of test, however licensees may perform tests in addition to 

27 what is discussed in the FEMA report. 

28

29 Examples of actions that ARE allowed and do not affect the as found conditions of sirens (not an 

30 all inclusiveall-inclusive list): 

31

32 o Regardless of the time, an unscheduled diagnostic test and subsequent 

33 maintenance and repair followed by post maintenance testing after any event that 

34 causes actual or suspected damage, such as:

35

36 1. Severe/inclement weather (high winds, lightning, ice, etc.),

37 2. Suspected or actual vandalism,

38 3. Physical damage from impact (vehicle, tree limbs, etc.),

39 4. Computer hardware and software failures,

40 5. Damaged communication cables or phone lines.

41 6. Problems identified by established routine use of the siren 

42 feedback systems.

43

44 o Scheduled polling tests for the purpose of system monitoring to optimize system 

45 availability and functionality.

46

47
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1 If a siren is out of service for scheduled planned refurbishment or overhaul maintenance 

2 performed in accordance with an established program, or for scheduled equipment upgrades, the 

3 siren need not be counted as a siren test or a siren failure. However, sirens that are out of service 

4 due to unplanned corrective maintenance would continue to be counted as failures. Unplanned 

5 corrective maintenance is a measure of program reliability. The exclusion of a siren due to 

6 temporary unavailability during planned maintenance/upgrade activities is acceptable due to the 

7 level of control placed on scheduled maintenance/upgrade activities. It is not the intent to create 

8 a disincentive to performing maintenance/upgrades to ensure the ANS performs at its peak 

9 reliability.

10

11 As part of a refurbishment or overhaul plan, it is expected that each utility would communicate 

12 to the appropriate state and/or local agencies the specific sirens to be worked and ensure that a 

13 functioning backup method of public alerting would be in-place. The acceptable timeframe for 

14 allowing a siren to remain out of service for system refurbishment or overhaul maintenance 

15 should be coordinated with the state and local agencies. Based on the impact to their 

16 organization, these timeframes should be specified in upgrade or system improvement 

17 implementation plans and/or maintenance procedures. Deviations from these plans and/or 

18 procedures would constitute unplanned unavailability and would be included in the PI. 

19

20 Siren testing conducted at redundant control stations, such as county EOCs that are staffed 

21 during an emergency by an individual capable of activating the sirens, may be credited provided 

22 the redundant control station is in an approved facility as documented in the FEMA ANS design 

23 report.
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1 Data Example

Alert & Notification System Reliability

Quarter 3Q/97 4Q/97 1Q/98 2Q/98 3Q/98 4Q/98 Prev. Q

Number of succesful siren-tests in the qtr 47 48 49 49 49 54 52

Total number of sirens tested in the qtr 50 50 50 50 50 55 55

Number of successful siren-tests over 4 qtrs 193 195 201 204

Total number of sirens tested over 4 qtrs 200 200 205 210

2Q/98 3Q/98 4Q/98 Prev. Q

Indicator expressed as a percentage of sirens 96.5% 97.5% 98.0% 97.1%

Thresholds

Green ≥94%

White <94%

Yellow <90%

Red N/A

80.0%

82.0%

84.0%

86.0%

88.0%

90.0%

92.0%

94.0%

96.0%

98.0%

100.0%

2Q/98 3Q/98 4Q/98 Prev. Q

Indicator

Quarter

ANS Reliability

GREEN

WHITE

YELLOW

Note: No Red Threshold

2

3
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1 2.5 OCCUPATIONAL RADIATION SAFETY CORNERSTONE

2 The objectives of this cornerstone are to: 

3

4 (1) keep occupational dose to individual workers below the limits specified in 

5 10 CFR Part 20 Subpart C; and

6

7 (2) use, to the extent practical, procedures and engineering controls based upon sound 

8 radiation protection principles to achieve occupational doses that are as low as is 

9 reasonably achievable (ALARA) as specified in 10 CFR 20.1101(b). 

10

11 There is one indicator for this cornerstone:

12

13 • Occupational Exposure Control Effectiveness

14

15 OCCUPATIONAL EXPOSURE CONTROL EFFECTIVENESS

16 Purpose

17 The purpose of this performance indicator is to address the first objective of the occupational 

18 radiation safety cornerstone. The indicator monitors the control of access to and work activities 

19 within radiologically-significant areas of the plant and occurrences involving degradation or 

20 failure of radiation safety barriers that result in readily-identifiable unintended dose. 

21

22 The indicator includes dose-rate and dose criteria that are risk-informed, in that the indicator 

23 encompasses events that might represent a substantial potential for exposure in excess of 

24 regulatory limits. The performance indicator also is considered “leading” because the indicator:

25

26 • encompasses less-significant occurrences that represent precursors to events that might 

27 represent a substantial potential for exposure in excess of regulatory limits, based on industry 

28 experience; and

29

30 • employsEmploys dose criteria that are set at small fractions of applicable dose limits (e.g., 

31 the criteria are generally at or below the levels at which dose monitoring is required in 

32 regulation).

33

34 Indicator Definition

35 The performance indicator for this cornerstone is the sum of the following:

36

37 • Technical specification high radiation area (>1 rem per hour) occurrences

38 • Very high radiation area occurrences

39 • Unintended exposure occurrences

40

41
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1 Data Reporting Elements

2 The data listed below are reported for each site. For multiple unit sites, an occurrence at one unit 

3 is reported identically as an input for each unit. However, the occurrence is only counted once 

4 against the site-wide threshold value.

5

6 • The number of technical specification high radiation area (>1 rem per hour) 

7 occurrences during the previous quarter

8 • The number of very high radiation area occurrences during the previous quarter

9 • The number of unintended exposure occurrences during the previous quarter 

10

11 Calculation

12 The indicator is determined by summing the reported number of occurrences for each of the 

13 three data elements during the previous 4 quarters.

14

15 Definition of Terms

16 Technical Specification High Radiation Area (>1 rem per hour) Occurrence - A 

nonconformance (or concurrent14 nonconformances) with technical specifications15 17 or 

comparable requirements in 10 CFR 2016 18 applicable to technical specification high radiation 

19 areas (>1 rem per hour) that results in the loss of radiological control over access or work 

20 activities within the respective high-radiation area (>1 rem per hour). For high radiation areas 

21 (>1 rem per hour), this PI does not include nonconformance with licensee-initiated controls that 

22 are beyond what is required by technical specifications and the comparable provisions in 10 CFR 

23 Part 20.

24

25 Technical Specification specification high radiation areas, commonly referred to as locked high 

26 radiation areas, includes any area, accessible to individuals, in which radiation levels from 

27 radiation sources external to the body are in excess of 1 rem (10 mSv) per 1 hour at 30 

28 centimeters from the radiation source or 30 centimeters from any surface that the radiation 

29 penetrates, and excludes very high radiation areas. Technical specification high radiation areas, 

30 in which radiation levels from radiation sources external to the body are less than or equal to 1 

31 rem (10 mSv) per 1 hour at 30 centimeters from the radiation source or 30 centimeters from any

32 surface that the radiation penetrates, are excluded from this performance indicator.

33

34 • “Radiological control over access to technical specification high radiation areas” refers to 

measures that provide assurance that inadvertent entry17 35 into the technical specification high 

36 radiation areas by unauthorized personnel will be prevented.

37 • “Radiological control over work activities” refers to measures that provide assurance that 

38 dose to workers performing tasks in the area is monitored and controlled. 

39

40 Examples of occurrences that would be counted against this indicator include:

 14 “Concurrent” means that the nonconformances occur as a result of the same cause and in a common timeframe. 15 Or comparable provisions in licensee procedures if the technical specifications do not include provisions for high radiation areas. 16 Includes 10 CFR 20, §20.1601(a), (b), (c), and (d) and §20.1902(b). 17 In reference to application of the performance indicator definition in evaluating physical barriers, the term “inadvertent entry” means that the 

physical barrier cannot be easily circumvented (i.e., an individual who incorrectly assumes, for whatever reason, that he or she is authorized to 

enter the area, is unlikely to disregard, and circumvent, the barrier). The barriers used to control access to technical specification high radiation 

areas should provide reasonable assurance that they secure the area against unauthorized access. (FAQ 368)
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1 • Failure to post an area as required by technical specifications,

2 • Failure to secure an area against unauthorized access, 

3 • Failure to provide a means of personnel dose monitoring or control required by technical 

4 specifications,

5 • Failure to maintain administrative control over a key to a barrier lock as required by technical 

6 specifications, or

7 • An occurrence involving unauthorized or unmonitored entry into an area, or

8 • Nonconformance with a requirement of an RWP (as specified in the licensee’s technical 

9 specifications) that results in a loss of control of access to or work within a technical 

10 specification high radiation area. 

11

12 Examples of occurrences that are not counted include the following:

13 • Situations involving areas in which dose rates are less than or equal to 1 rem per hour,

14 • Occurrences associated with isolated equipment failures. This might include, for example, 

15 discovery of a burnt-out light, where flashing lights are used as a technical specification 

16 control for access, or a failure of a lock, hinge, or mounting bolts, when a barrier is checked 

or tested.18 17

18 • Nonconformance with an RWP requirement that does not result in a loss of control of access 

19 to or work within a technical specification high radiation area (e.g., signing in on the wrong 

20 RWP, but having received the pre-job brief and implemented all of the access work control 

21 requirements of the correct RWP). 

22

23 Very High Radiation Area Occurrence - A nonconformance (or concurrent nonconformances) 

24 with 10 CFR 20 and licensee procedural requirements that results in the loss of radiological 

25 control over access to or work activities within a very high radiation area. “Very high radiation 

26 area” is defined as any area accessible to individuals, in which radiation levels from radiation 

27 sources external to the body could result in an individual receiving an absorbed dose in excess of 

28 500 rads (5 grays) in 1 hour at 1 meter from a radiation source or 1 meter from any surface that 

29 the radiation penetrates.

30

31 • “Radiological control over access to very high radiation areas” refers to measures to ensure 

32 that an individual is not able to gain unauthorized or inadvertent access to very high radiation 

33 areas. 

34 • “Radiological control over work activities” refers to measures that provide assurance that 

35 dose to workers performing tasks in the area is monitored and controlled.

36

37 Unintended Exposure Occurrence - A single occurrence of degradation or failure of one or more 

38 radiation safety barriers that results in unintended occupational exposure(s), as defined below. 

39

40 Following are examples of an occurrence of degradation or failure of a radiation safety barrier 

41 included within this indicator:

42

43 • failure to identify and post a radiological area

44 • failure to implement required physical controls over access to a radiological area

45 • failure to survey and identify radiological conditions

 18 Presuming that the equipment is subject to a routine inspection or preventative maintenance program, that the occurrence was indeed isolated, 

and that the causal condition was corrected promptly upon identification.
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1 • failure to train or instruct workers on radiological conditions and radiological work controls

2 • failure to implement radiological work controls (e.g., as part of a radiation work permit) 

3

4 An occurrence of the degradation or failure of one or more radiation safety barriers is only 

5 counted under this indicator if the occurrence resulted in unintended occupational exposure(s) 

6 equal to or exceeding any of the dose criteria specified in the table below. The dose criteria were 

7 selected to serve as “screening criteria,” only for the purpose of determining whether an 

8 occurrence of degradation or failure of a radiation safety barrier should be counted under this 

9 indicator. The dose criteria should not be taken to represent levels of dose that are “risk10 significant.” In fact, the dose criteria selected for screening purposes in this indicator are 

11 generally at or below dose levels that are required by regulation to be monitored or to be 

12 routinely reported to the NRC as occupational dose records.

13

14 Table: Dose Values Used as Screening Criteria to Identify an Unintended Exposure 

15 Occurrence in the Occupational Exposure Control Effectiveness PI

2% of the stochastic limit in 10 CFR 20.1201 on total effective dose equivalent. 

The 2% value is 0.1 rem.

10 % of the non-stochastic limits in 10 CFR 20.1201. The 10% values are as follows:

5 rem the sum of the deep-dose equivalent and the committed dose equivalent 

to any individual organ or tissue

1.5 rem the lens dose equivalent to the lens of the eye

5 rem the shallow-dose equivalent to the skin or any extremity, other than dose 

received from a discrete radioactive particle (DRP)19

20% of the limits in 10 CFR 20.1207 and 20.1208 on dose to minors and declared pregnant 

women. The 20% value is 0.1 rem.

16

17 “Unintended exposure” refers to exposure that results in dose in excess of the administrative 

18 guideline(s) set by a licensee as part of their radiological controls for access or entry into a 

19 radiological area. Administrative dose guidelines may be established:

20

21 • within radiation work permits, procedures, or other documents, 

22 • via the use of alarm setpoints for personnel dose monitoring devices, or 

23 • by other means, as specified by the licensee. 

24

25 It is incumbent upon the licensee to specify the method(s) being used to administratively control 

26 dose. An administrative dose guideline set by the licensee is not a regulatory limit and does not, 

27 in itself, constitute a regulatory requirement. A revision to an administrative dose guideline(s) 

28 during job performance is acceptable (with regard to this PI) if conducted in accordance with 

29 plant procedures or programs.

30

31 If a specific type of exposure was not anticipated or specifically included as part of job planning 

32 or controls, the full amount of the dose resulting from that type of exposure should be considered 

33 as “unintended” in making a comparison with the respective criteria in the PI. For example, this 

 19 Controls established for DRPs are intended to minimize the possibility of exposures that could result in the SDE dose limit being exceeded, not 

to maintain the exposure to some intended SDE dose. Therefore, for the purpose of this PI, any DRP exposure is considered “unintended” and is 

a reportable PI event if it results (by itself, or added to previous “uniform” SDE exposures) in an SDE in excess of the regulatory limit in 

20.1201(a)(2)(ii).
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1 might include Committed Effective Dose Equivalent (CEDE), Committed Dose Equivalent 

2 (CDE), or Shallow Dose Equivalent (SDE).

3

4

5 Clarifying Notes

6 An occurrence (or concurrent occurrences) that potentially meet the definition of more than one 

7 element of the performance indicator will only be counted once. In other words, an occurrence 

8 (or concurrent occurrences) will not be double-counted (or triple-counted) against the 

9 performance indicator. If two or more individuals are exposed in a single occurrence, the 

10 occurrence is only counted once.

11

12 Radiography work conducted at a plant under another licensee’s 10 CFR Part 34 license is 

13 generally outside the scope of this PI. However, if a Part 50 licensee opts to establish additional 

14 radiological controls under its own program consistent with technical specifications or 

15 comparable provisions in 10 CFR Part 20, then a non-conformance with such additional controls 

16 or unintended dose resulting from the non-conformance shall be evaluated under the criteria in 

17 the PI.

18
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1 Data Example

Occupational Exposure Control Effectiveness 

3Q95* 4Q95 1Q96 2Q96 3Q96 4Q96 1Q97 2Q97 3Q97 4Q97 1Q98 2Q98 3Q98 4Q98

Number of Technical Specification High Radiation Area 

Occurrences this quarter

0 0 3 0 0 0 0 0 0 0 0 0 0 0

Number ofVery High Radiation Area Occurrences this Quarter 0 0 0 0 0 0 1 0 1 0 0 0 0 0

Number of Unintended Exposure Occurrences this Quarter 1 0 0 0 0 0 0 0 0 0 0 0 0 1

Cumulative Total Over the Current Four Quarters 1 1 4 4 3 3 1 1 2 2 1 1 0 1

Notes: Example assumes 3Q95 is the first quarter in which the PI 

is to be considered valid. 1 0 3 0 0 0 1 0 1 0 0 0 0 1

Thresholds

Green: <= 2

White: > 2

Yellow: > 5

No Red Threshold

0

1

2

3

4

5

6

3Q95* 4Q95 1Q96 2Q96 3Q96 4Q96 1Q97 2Q97 3Q97 4Q97 1Q98 2Q98 3Q98 4Q98

Occupational Exposure Control Effectiveness

GREEN

WHITE

YELLOW

2

3
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1 2.6 PUBLIC RADIATION SAFETY CORNERSTONE

2 RETS/ODCM RADIOLOGICAL EFFLUENT OCCURRENCE

3 Purpose

4 To assess the performance of the radiological effluent control program.

5

6 Indicator Definition

7 Radiological effluent release occurrences per site that exceed the values listed below:

8

Radiological effluent releases in excess of the following values: 

Liquid Effluents Whole Body 1.5 mrem/qtr

Organ 5 mrem/qtr

Gaseous Effluents Gamma Dose 5 mrads/qtr

Beta Dose 10 mrads/qtr

Organ Doses from 

I-131, I-133, H-3

& Particulates

 7.5 mrems/qtr

9

10 Note:

11 (1) Values are derived from the Radiological Effluent Technical Specifications (RETS) or 

12 similar reporting provisions in the Offsite Dose Calculation Manual (ODCM), if applicable 

13 RETS have been moved to the ODCM in accordance with Generic Letter 89-01.

14 (2) The dose values are applied on a per reactor unit basis in accordance with the RETS/ODCM.

15 (3) For multiple unit sites, allocation of dose on a per reactor unit basis from releases made via 

16 common discharge points is to be calculated in accordance with the methodology specified in 

17 the ODCM.

18

19 Data Reporting Elements

20 Number of RETS/ODCM Radiological Effluent Occurrences each quarter involving assessed 

21 dose in excess of the indicator effluent values.

22

23 Calculation

24 Number of RETS/ODCM Radiological Effluent Occurrences per site in the previous four 

25 quarters.

26

27 Definition of Terms

28 A RETS/ODCM Radiological Effluent Occurrence is defined as a release that exceeds any or all 

29 of the five identified values outlined in the above table. These are the whole body and organ 

30 dose values for liquid effluents and the gamma dose, beta dose, and organ dose values for 

31 gaseous effluents.

32
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1 Clarifying Notes

2 The following conditions do not count against the RETS/ODCM Radiological Effluent 

3 Occurrence:

4

5 • Liquid or gaseous monitor operability issues

6

7 • Liquid or gaseous releases in excess of RETS/ODCM concentration or instantaneous 

8 dose-rate values

9

10 • Liquid or gaseous releases without treatment but that do not exceed values in the table

11

12 Not all effluent sample (e.g., composite sample analysis) results are required to be finalized at 

13 the time of submitting the quarterly PI reports. Therefore, the reports should be based upon the 

14 best-available data. If subsequently available data indicates that the number of occurrences for 

15 this PI is different than that reported, then the report should be revised, along with an explanation 

16 regarding the basis for the revision.

17

18 Data Example

RESTS/ODCM Radiological Effluent Occurrence

3Q97* 4Q97 1Q98 2Q98 3Q98 4Q98 Prev. Q

Number of RETS/ODCM Occurrences this Quarter 1 0 0 1 0 0 1

Number of RETS/ODCM Occurrences in Last Four Quarters 1 1 1 2 1 1 2

Notes: * Example assumes 3Q97 is first quarter in which the PI is considered valid.

Thresholds

Green: <= 1

> 1 White <=3

Yellow: > 3

Red: N/A

0

1

2

3

4

3Q97* 4Q97 1Q98 2Q98 3Q98 4Q98 Prev. Q

RETS/ODCM Effluent Occurrences

White

Green

Yellow

No Red Threshold

19

20

21

22
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1 2.7 SECURITY CORNERSTONE

2 The performance indicator for this cornerstone was selected to provide baseline and trend 

3 information needed to evaluate each licensee’s physical protection system. The regulatory 

4 purpose is to provide high assurance that this system will function to protect against the design 

5 basis threat of radiological sabotage as defined in 10 CFR Part 73. As a surrogate to any 

6 engineered physical security protection system, posted security officers provide compensation 

7 when a portion of the system is unavailable to perform its intended function. The performance 

8 indicator value is not an indication that the protection afforded by the plant’s physical security 

9 organization is less than required by the regulatory requirements.

10

11 There is one performance indicator for the physical protection system. The performance 

12 indicator is assessed against established thresholds using the data and methodology as

13 established in this guideline. The NRC baseline inspections will validate and verify the testing 

14 requirements for each system to assure performance standards and testing periodicity are 

15 appropriate to provide valid data. 

16

17 Performance Indicator

18 The only physical protectionsecurity performance indicator is the Protected Area Security 

19 Equipment Performance Index.

20

21 This indicator serves as a measure of a plant’s ability to maintainunavailability of security

22 equipment—to be available to perform its intended function. When compensatory measures 

23 are employed because a segment of equipment is unavailable (i.e.,not adequately performing its 

24 intended function), there is no security vulnerability but there is an indication that something 

25 needs to be fixed. The PI also provides trend indications for evaluation of the effectiveness of 

26 the maintenance process, and also provides a method of monitoring equipment degradation as a 

27 result of aging that might adversely impact reliability. Maintenance considerations for protected 

28 area and vital area portals are appropriately and sufficiently covered by the inspection program. 

29

30

Protected Area (PA) Security Equipment Performance Index

31 Purpose:

32 Operability of the PA security system is necessary to detect and assess safeguards events and to 

33 provide the first line of the defense-in-depth physical protection of the plant perimeter. In the 

34 event of an attempted encroachment, the intrusion detection system identifies the existence of the 

35 threat, the barriers provide a delay to the person(s) posing the threat and the alarm assessment 

36 system is used to determine the magnitude of the threat. The PI is used to monitor the 

37 unavailability of PA intrusion detection systems and alarm assessment systems to perform their 

38 intended function.

39

40 Indicator Definition:

41 PA Security equipment performance is measured by an index that compares the amount of the 

42 time CCTVs and IDS are unavailable, as measured by compensatory hours, to the total hours in 

FAQ

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1 the period. A normalization factor is used to take into account site variability in the size and 

2 complexity of the systems. 

3

4 Data Reporting Elements:

5 Report the following site data for the previous quarter for each unit:

6

7 • Compensatory hours, CCTVs: The hours (expressed to the nearest tenth of an hour) 

8 expended in posting a security officer as required compensation for camera(s) unavailability 

9 because of degradation or defects.

10 • Compensatory hours, IDS: The hours (expressed to the nearest tenth of an hour) expended in 

11 posting a security officer as required compensation for IDS unavailability because of 

12 degradation or defects.

13 • CCTV Normalization factor: The number of CCTVs divided by 30. If there are 30 or fewer 

14 CCTVs, a normalization factor of 1 should be used.

15

16 • IDS Normalization factor: The number of physical security zones divided by 20. If there are 

17 20 or fewer zones, a normalization factor of 1 should be used.

18

19 Calculation

20

21 The performance indicator is calculated using values reported for the previous four quarters. The 

22 calculation involves averaging the results of the following two equations.

23

IDS Unavailability Index = IDS Normalization Factor x 8760 hrs

IDSCompensatory hoursin the previous 4 quarters 24

25

CCTV Unavailability Index = CCTV Normalization Factor x 8760 hrs

CCTV Compensatory hoursin the previous 4 quarters 26

27

Indicator Value = 

2

IDS Unavilability Index + CCTV Unavailability Index 28

29

30 Definition of Terms

31 Intrusion detection system (IDS) - E-fields, microwave fields, etc.

32 CCTV - The closed circuit television cameras that support the IDS.

33 Normalization factors - Two factors are used to compensate for larger than nominal size sites. 

34 − IDS Normalization Factor: Using a nominal number of physical security zones across the 

35 industry, the normalization factor for IDS is twenty. If a site has twenty or fewer intrusion 

36 detection zones, the normalization factor will be 1. If a site has more zones than 20, the 

37 factor is the total number of site zones divided by 20 (e.g., 50 ÷ 20 = 2.5).

38 − CCTV Normalization Factor: Using a nominal number of perimeter cameras across the 

39 industry, the normalization factor for cameras is 30. If a site has thirty or fewer perimeter 
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1 cameras, the normalization factor is 1. If a site has more than 30 perimeter cameras, the 

2 factor is the total number of perimeter cameras divided by 30 (e.g., 50 ÷ 30 = 1.7).

3 Note: The normalization factors are general approximations and may be modified as 

4 experience in the pilot program dictates.

5

6 Compensatory measures: Measures used to meet physical security requirements pending 

7 when the return of required equipment to serviceis unavailable. Protected Area protection is 

8 not diminished by the use of compensatory measures for equipment unavailability.

9

10 Compensatory man-hours: The man-hours (expressed to the nearest tenth of an hour) that 

11 compensatory measures are in place (posted) to address a degradation in the IDS and CCTV 

12 systems. When a portion of the system becomes unavailable—incapable of performing its 

13 intended function—and requires posting of compensatory measures, the compensatory man-hour

14 clock is started. The period of time ends when the cause of the degraded state has been repaired, 

15 tested, and system declared operable.

16

17 If a zone is posted for a degraded IDS and a CCTV camera goes out in the same posted area, the 

18 hours for the posting of the IDS will not be double counted. However, if the IDS problem is 

19 corrected and no longer requires compensatory posting but the camera requires posting, the hours 

20 will start to count for the CCTV category.

21

22 Equipment unavailability: When the system has been posted because of a degraded condition 

23 (unavailability), the compensatory hours are counted in the PI calculation. If the degradation is 

24 caused by environmental conditions, preventive maintenance or scheduled system upgrade, the 

25 compensatory hours are not counted in the PI calculation. However, if the equipment is 

26 degraded after preventive maintenance or periodic testing, compensatory posting would be 

27 required and the compensatory hours would count. Compensatory hours stop being counted 

28 when the equipment deficiency has been corrected, equipment tested and declared back in 

29 service.

30

31 Clarifying Notes

32 Compensatory posting: 

33 • The posting for this PI is only for the protected area perimeter, not vital area doors or other 

34 places where such posting may be required. 

35 • Postings for IDS segments for false alarms in excess of security program limits would be 

36 counted in the PI. In the absence of a false alarm limit in the security program, qualified 

37 individuals can disposition the condition and determine whether compensatory posting is 

38 required.

39 • Some postings are the result of non-equipment failures, which may be the result of 

40 test/maintenance conditions. For example, in a situation where a part of the IDS is taken out41 of-service to check a condition for false alarms not in excess of security program false alarm 

42 limits, no compensatory hours would be counted. If the equipment is determined to have 

43 malfunctioned, it is not operable and maintenance/repair is required, the hours would count.

44

FAQ

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1 • Compensatory hours expended to address simultaneous equipment problems (IDS & CCTV) 

2 are counted beginning with the initial piece of equipment that required compensatory hours. 

3 When this first piece of equipment is returned to service and no longer requires 

4 compensatory measures, the second covered piece of equipment carries the hours. If one IDS 

5 zone is required to be covered by more than one compensatory post, the total man-hours of 

6 compensatory action are to be counted. If multiple IDS zones are covered by one 

7 compensatory post, the man-hours are only counted once.

8 • IDS equipment issues that do not require compensatory hours would not be counted.

9 • Compensatory man man-hours for a failed Pan-Tilt-Zoom (PTZ) camera count for the PI 

10 only if the PTZ is either being used as a CCTV or is substituting for a failed CCTV.

11 • The PI metric is based on expended compensatory hours and starts when the IDS or CCTV is 

12 actually posted. There are no "fault exposure hours" or other consideration beyond the actual 

13 physical compensatory posting. Also, this indicator only uses compensatory man-hours to 

14 provide an indication of CCTV or IDS unavailability. If a PTZ camera or other non15 personnel (no expended portion of a compensatory man-hour) item is used as the 

16 compensatory measure, it is not counted for this PI.

17 • In a situation where security persons are already in place at continuously manned remote 

18 location security booths around the perimeter of the site and there is a need to provide 

19 compensatory coverage for the loss of IDS equipment, security persons already in these 

20 booths can fulfill this function. If they are used to perform the compensatory function, the 

21 hours are included in the PI. The man man-hours for all persons required to provide 

22 compensation are counted. If more persons are assigned than required, only the required 

23 compensatory man man-hours would be counted. 

24 • Compensatory hours for this PI cover hours expended in posting a security officer as required 

25 as compensation for IDS and/or CCTV unavailability because of a degradation or defect. If 

26 other problems (e.g., security computer or multiplexer) result in compensatory postings 

27 because the IDS/CCTV is no longer capable of performing its intended safeguards function, 

28 the hours would count. Equipment malfunctions that do not require compensatory posting 

29 are not included in this PI.

30 • If an ancillary system is needed to support proper operability of IDS or CCTV and it fails, 

31 and the supported system does not operate as intended, the hours would count. For example, 

32 a CCTV camera requires sufficient lighting to perform its function so that such a lighting 

33 failure would result in compensatory hours counted for this PI.

34

35 Data reporting: For this performance indicator, rounding may be performed as desired provided 

36 it is consistent and the reporting hours are expressed to the nearest tenth of an hour. Information 

37 supporting performance indicators is reported on a per unit basis. For performance indicators that 

38 reflect site conditions (IDS or CCTV), this requires that the information be repeated for each unit 

39 on the site. The criterion for data reporting is from the time the failure or deficiency is identified 

40 to the time it is placed back in service.

41
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1 Degradation: Required system, /equipment, or /component is no longer available/ or capable 

2 of performing its intended Intended safeguards functionFunction—manufacturer’s equipment 

3 design capability and/or as covered in the PSP.

4

5 Extreme environmental conditions: 

6 Compensatory hours do not count for extreme environmental conditions beyond the design 

7 specifications of the system, including severe storms, heavy fog, heavy snowfall, and sun glare 

8 that renders the IDS or CCTV temporarily inoperable. If after the environmental condition 

9 clears, the zone remains unavailable, despite reasonable recovery efforts, the compensatory hours 

10 would not begin to be counted until technically feasible corrective action could be completed. 

11 For example, a hurricane decimates a portion of the perimeter IDS and certain necessary 

12 components have to be obtained from the factory. Any restoration delay would be independent of 

13 the licensee’s maintenance capability and therefore would not be counted in the indicator.

14

15 Other naturally occurring conditions that are beyond the control of the licensee, such as damage 

16 or nuisance alarms from animals are not counted.

17

18 Independent Spent Fuel Storage Installations (ISFSIs): This indicator does not include protective 

19 measures associated with such installations.

20

21 Intended function: The ability of a component to detect the presence of an individual or display 

22 an image as intended by manufacturer’s equipment design capability and/or as covered as 

23 described in the Physical Security Plan PSP. 

24

25 Operational support: E-fields or equivalent that are taken out of service to support plant 

26 operations and are not equipment failures but are compensatorily posted do not count for this PI.

27

28 Scheduled equipment upgrade: 

29 • In the situation where system degradation results in a condition that cannot be corrected 

30 under the normal maintenance program (e.g., engineering evaluation specifies the need for a 

system/component20 31 modification or upgrade), and the system requires compensatory 

32 posting, the compensatory hours stop being counted toward the PI for those conditions 

33 addressed within the scope of the modification after such an evaluation has been made and 

34 the station has formally approved an upgrade with descriptive information about the upgrade 

35 plan including scope of the project, anticipated schedule, and expected expenditures. This 

36 formally initiated upgrade is the result of established work practices to design, fund, procure, 

37 install and test the project. A note should be made in the comment section of the PI submittal 

38 that the compensatory hours are being excluded under this provision. Compensatory hour 

39 counting resumes when the upgrade is complete and operating as intended as determined by 

40 site requirements for sign-off. Reasonableness should be applied with respect to a justifiable 

41 length of time the compensatory hours are excluded from the PI.

42

43 • For the case where there are a few particularly troubling zones that result in formal initiation 

44 of an entire system upgrade for all zones, counting compensatory hours would stop only for 

45 zones out of service for the upgrade. However, if subsequent failures would have been 

46 prevented by the planned upgrade those would also be excluded from the count. This 

 20 A modification to prevent the circumvention of the IDS (or CCTV) (such as the installation of a razor wire barrier) would fall under these 

provisions because the modification would be acting as an ancillary system of the IDS.

FAQ

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FAQ

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1 exclusion applies regardless of whether the failures are in a zone that precipitated the upgrade 

2 action or not, as long as they are in a zone that will be affected by the upgrade, and the 

3 upgrade would have prevented the failure.

4

5 Preventive maintenance: 

6 • Scheduled preventive maintenance (PM) on system/equipment/component to include 

7 probability and/or operability testing. Includes activities necessary to keep the system at the 

8 required functional level. Planned plant support activities are considered PM.

9 • If during preventive maintenance or testing, a camera does not function correctly, and can be 

10 compensated for by means other than posting an officer, no compensatory man-hours are 

11 counted.

12 • Predictive maintenance is treated as preventive maintenance. Since the equipment has not 

13 failed and remains capable of performing its intended security function, any maintenance 

14 performed in advance of its actual failure is preventive. It is not the intent to create a 

15 disincentive to performing maintenance to ensure the security systems perform at their peak 

16 reliability and capability.

17 • Scheduled system upgrade: Activity to improve, upgrade or enhance system performance, as 

18 appropriate, in order to be more effective in its reliability or capability.

19
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1 Data Example

Protected Area Security Equipment Performance Indicator

2Q97* 3Q97 4Q97 1Q98 2Q98 3Q98 4Q98 Prev. Q

IDS Compensatory Hours in the Quarter 36 48 96 126 65 45 60 55

CCTV Compensatory Hours in the Quarter 24 36 100 100 48 56 53 31

IDS Compensatory Hrs in Previous Four Quarters 36 84 180 306 335 332 296 225

CCTV Compensatory Hrs in the Previous Four Quarters 24 60 160 260 284 304 257 188

IDS Normalization Factor 1.05 1.05 1.05 1.05 1.1 1.1 1.1 1.1

CCTV Normalization Factor 1.2 1.2 1.2 1.2 1.3 1.3 1.3 1.3

IDS Unavailability Index 0.003914 0.009132 0.01957 0.0332681 0.03476546 0.03445413 0.03071814 0.02334994

CCTV Unavailability Index 0.002283 0.005708 0.01522 0.02473364 0.02493853 0.02669477 0.02256762 0.01650861

Indicator Value 0.00 0.01 0.02 0.03 0.03 0.03 0.03 0.02

Notes: *Example assumes 2Q97 is first quarter in which the PI is considered valid.

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

2Q97* 3Q97 4Q97 1Q98 2Q98 3Q98 4Q98 Prev. Q

PA Security Equipment Indicator

GREEN <= 0.08

WHITE > 0.08

Note: No Yellow or Red Threshold

2
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1

2

3

4

5 [This page left intentionally blank]
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A-1

1 APPENDIX A

2 Acronyms & Abbreviations

3

4 AC Alternating (Electrical) Current

5 AFW Auxiliary Feedwater System

6 ALARA As Low As Reasonably Achievable

7 ANS Alert & Notification System

8 AOT Allowed Outage Time

9 AOV Air Operated Valve

10 ATWS Anticipated Transient Without Scram

11 BWR Boiling Water Reactor

12 CCF Common Cause Failure

13 CCW Component Cooling Water

14 CDE Consolidated Data Entry

15 CDF Core Damage Frequency

16 CFR Code of Federal Regulations

17 CCTV Closed Circuit Television

18 DC Direct (Electrical) Current

19 DE & AEs Drills, Exercises and Actual Events

20 EAC Emergency AC

21 EAL Emergency Action Levels

22 EDG Emergency Diesel Generator

23 EOF Emergency Operations Facility

24 EFW Emergency Feedwater

25 ERO Emergency Response Organization

26 ESF Engineered Safety Features

27 FAQ Frequently Asked Question

28 FEMA Federal Emergency Management Agency

29 FSAR Final Safety Analysis Report

30 FV Fussel-Vesely

31 FWCI Feedwater Coolant Injection

32 IC Isolation Condenser

33 IDS Intrusion Detection System

34 ISFSI Independent Spent Fuel Storage Installation

35 HOV Hydraulic Operated Valve

36 HPCI High Pressure Coolant Injection

37 HPCS High Pressure Core Spray

38 HPSI High Pressure Safety Injection

39 HVAC Heating, Ventilation and Air Conditioning

40 INPO Institute of Nuclear Power Operations

41 LER Licensee Event Report

42 LPCI Low Pressure Coolant Injection

43 LPSI Low Pressure Safety Injection

44 LOCA Loss of Coolant Accident

45 MD Motor Driven

46 MOV Motor Operated Valve
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A-2

1 MSIV Main Steam Isolation Valve

2 MSPI Mitigating Systems Performance Index

3 N/A Not Applicable

4 NEI Nuclear Energy Institute

5 NRC Nuclear Regulatory Commission

6 NSSS Nuclear Steam Supply System

7 ODCM Offsite Dose Calculation Manual

8 OSC Operations Support Center

9 PA Protected Area

10 PARs Protective Action Recommendations

11 PI Performance Indicator

12 PLE Performance Limit Exceeded

13 PRA Probabilistic Risk Analysis

14 PSA Probabilistic Safety Assessment

15 PORV Power Operated Relief Valve

16 PWR Pressurized Water Reactor

17 RETS Radiological Effluent Technical Specifications

18 RCIC Reactor Core Isolation Cooling

19 RCS Reactor Coolant System

20 RHR Residual Heat Removal

21 ROP Reactor Oversight Process

22 RWST Refueling Water Storage Tank

23 SOV Solenoid Operated Valve

24 SPAR Standardized Plant Analysis Risk

25 SSFF Safety System Functional Failure

26 SSU Safety System Unavailability performance indicator

27 SWS Service Water System

28 TD Turbine Driven

29 TSC Technical Support Center

30 UAI Unavailability Index

31 URI Unreliability Index

32 USwC Unplanned Scrams with Complications
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1 APPENDIX B

2 STRUCTURE AND FORMAT OF NRC PERFORMANCE INDICATOR DATA FILES

3

4 Performance indicator data files submitted to the NRC as part of the Regulatory Oversight 

5 Process should conform to the structure and format identified below. The INPO CDE software

6 automatically produces files with the structure and format outlined below.

7

8 File Naming Convention

9 Each NRC PI data file should be named according to the following convention. The name 

10 should contain the unit docket number, underscore, the date and time of creation and (if a change 

11 file) a “C” to indicate that the file is a change report. A file extension of .txt is used to indicate a 

12 text file.

13

14 Example: 05000399_20000103151710.txt

15

16 In the above example, the report file is for a plant with a docket number of 05000399 and the file 

17 was created on January 3, 2000 at 10 seconds after 3:17 p.m. The absence of a C at the end of 

18 the file name indicates that the file is a quarterly data report.

19

20 General Structure

21 Each line of the report begins with a left bracket (e.g., “[“) and ends with a right bracket (e.g., 

22 “]”). Individual items of information on a line (elements) are separated by a vertical “pipe” (e.g., 

23 “|”). 

24

25 Each file begins with [BOF] as the first line and [EOF] as the last line. These indicate the 

26 beginning and end of the data file. The file may also contain one or more “buffer” lines at the 

27 end of the file to minimize the potential for file corruption. The second line of the file contains 

28 the unit docket number and the date and time of file creation (e.g., [05000399|1/2/2000 

29 14:20:32]). Performance indicator information is contained beginning with line 3 through the 

30 next to last line (last line is [EOF]). The information contained on each line of performance 

31 indicator information consists of the performance indicator ID, applicable quarter/year 

32 (month/year for Barrier Integrity indicators), comments, and each performance indicator data 

33 element. Table B-1 provides a description of the data elements and order for each line of 

34 performance indicator data in a report file.

35

36 Example:

37 [IE01|3Q1998|Comments here|2|2400]

38

39 In the above example, the line contains performance indicator data for Unplanned Scrams per 

7000 Critical Hours (IE01), during the 3rd 40 quarter of 1998. The applicable comment text is 

41 “Comments here”. The data elements identify that (see Table B-1) there were 2 unplanned 

42 automatic and manual scrams while critical and there were 2400 hours of critical operation 

43 during the quarter.

44
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1 TABLE B-1 – PI DATA ELEMENTS IN NRC DATA REPORT

Performance Indicator Data

Element

Number

Description

General Comment 1 Performance Indicator Flag (i.e., GEN)

2 Report quarter and year (e.g., 1Q2000)

3 Comment text

Unplanned Scrams per 7,000 Critical 

Hours

1 Performance Indicator Flag (i.e., IE01)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Number of unplanned automatic and manual scrams while 

critical in the reporting quarter

5 Number of hours of critical operation in the reporting quarter

Unplanned Power Changes per 7,000 

Critical Hours

1 Performance Indicator Flag (i.e., IE03)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Number of unplanned power changes, excluding scrams, during 

the reporting quarter

5 Number of hours of critical operation in the reporting quarter

Unplanned Scrams with Complications 1 Performance Indicator Flag (i.e., IE04)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Number of unplanned scrams with complications during the 

reporting quarter

Safety System Functional Failures 1 Performance Indicator Flag (i.e., MS05)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Number of safety system functional failures during the 

reporting quarter

Mitigating Systems Performance Index

(MSPI)– Emergency AC Power Systems

1 Performance Indicator Flag (i.e., MS06)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 MSPI Calculated ValueUnavailability Index

5 Unavailability IndexUnreliability Index

6 MSPI Calculated ValueUnreliability Index

7 Performance Limit ExceededError! Bookmark not defined.

Mitigating Systems Performance Index

(MSPI)- High Pressure Injection Systems

1 Performance Indicator Flag (i.e., MS07)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 MSPI Calculated Value

5 Unavailability Index

6 Unreliability Index

7 Performance Limit ExceededError! Bookmark not defined.
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Performance Indicator Data

Element

Number

Description

Mitigating Systems Performance Index

(MSPI)– Heat Removal Systems

1 Performance Indicator Flag (i.e., MS08)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 MSPI Calculated Value

5 Unavailability Index

6 Unreliability Index

7 Performance Limit ExceededError! Bookmark not defined.

Mitigating Systems Performance Index

(MSPI)– Residual Heat Removal Systems

1 Performance Indicator Flag (i.e., MS09)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 MSPI Calculated Value

5 Unavailability Index

6 Unreliability Index

7 Performance Limit ExceededError! Bookmark not defined.

Mitigating Systems Performance Index

(MSPI)– Cooling Water Systems

1 Performance Indicator Flag (i.e., MS10)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 MSPI Calculated Value

5 Unavailability Index

6 Unreliability Index

7 Performance Limit ExceededError! Bookmark not defined.

Reactor Coolant System Activity (RCSA) 1 Performance Indicator Flag (i.e., BI01)

2 Month and year (e.g., 3/2000)

3 Comment text

4

Maximum calculated RCS activity, in micro curies per gram 

dose equivalent Iodine 131, as required by technical 

specifications, for reporting month

5 Technical Specification limit for RCS activity in micro curies 

per gram does equivalent Iodine 131

Reactor Coolant System Identified

Leakage (RCSL)

1 Performance Indicator Flag (i.e., BI02)

2 Month and year (e.g., 3/2000)

3 Comment text

4 Maximum RCS Identified Leakage calculation for reporting 

month in gpm

5 Technical Specification limit for RCS Identified Leakage in 

gpm

Emergency Response Organization 

Drill/Exercise Performance

1 Performance Indicator Flag (i.e., EP01)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Number of drill, exercise and actual event opportunities 

performed timely and accurately during the reporting quarter

5 Number of drill, exercise and actual event opportunities during 

the reporting quarter
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Performance Indicator Data

Element

Number

Description

Emergency Response Organization 

(ERO) Drill Participation

1 Performance Indicator Flag (i.e.,EP02)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Total Key ERO members that have participated in a drill, 

exercise, or actual event in the previous 8 qruarters

5 Total number of Key ERO personnel at end of reporting quarter

Alert & Notification System Reliability 1 Performance Indicator Flag (i.e., EP03)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Total number of successful ANS siren-tests during the 

reporting quarter

5 Total number of ANS sirens tested during the reporting quarter

Occupational Exposure Control 

Effectiveness

1 Performance Indicator Flag (i.e., OR01)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Number of technical specification high radiation area 

occurrences during the reporting quarter

5 Number of very high radiation area occurrences during the 

reporting quarter

6 The number of unintended exposure occurrences during the 

reporting quarter

RETS/ODCM Radiological Effluent 

Indicator

1 Performance Indicator Flag (i.e., PR01)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 Number of RETS/ODCM occurrences in the quarter

Protected Area Security Equipment 

Performance IndicatorIndex

1 Performance Indicator Flag (i.e., PP01)

2 Quarter and year (e.g., 1Q2000)

3 Comment text

4 IDS Compensatory Hours in the quarter

5 CCTV Compensatory Hours in the quarter

6 IDS Normalization Factor

7 CCTV Normalization Factor

1
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1

2 APPENDIX C

3

4 Background Information and Cornerstone Development

5

6 INTRODUCTION

7 This section discusses the overall objectives and basis for the performance indicators used for 

8 each of the seven cornerstone areas. A more in-depth discussion of the background behind each 

9 of the performance indicators identified in the main report may be found in SECY 99-07.

10 INITIATING EVENTS CORNERSTONE

11 GENERAL DESCRIPTION

12 The objective of this cornerstone is to limit the frequency of those events that upset plant stability 

13 and challenge critical safety functions, during shutdown as well as power operations. When such 

14 an event occurs in conjunction with equipment and human failures, a reactor accident may occur. 

15 Licensees can therefore reduce the likelihood of a reactor accident by maintaining a low 

16 frequency of these initiating events. Such events include reactor trips due to turbine trip, loss of 

17 feedwater, loss of offsite power, and other reactor transients. There are a few key attributes of 

18 licensee performance that determine the frequency of initiating events at a plant.

19 PERFORMANCE INDICATORS

20 PRAs have shown that risk is often determined by initiating events of low frequency, rather than 

21 those that occur with a relatively higher frequency. Such low-frequency, high-risk events have 

22 been considered in selecting the PIs for this cornerstone. All of the PIs used in this cornerstone 

23 are counts of either initiating events, or transients that could lead to initiating events (see Table 12 

24 in the main body of NEI 99-02). They have face validity for their intended use because they are 

25 quantifiable, have a logical relationship to safety performance expectations, are meaningful, and 

26 the data are readily available. The PIs by themselves are not necessarily related to risk. They are 

27 however, the first step in a sequence which could, in conjunction with equipment failures, human 

28 errors, and off-normal plant configurations, result in a nuclear reactor accident. They also provide 

29 indication of problems that, if uncorrected, increase the risk of an accident. In most cases, where 

30 PIs are suitable for identifying problems, they are sufficient as well, since problems that are not 

31 severe enough to cause an initiating event (and therefore result in a PI count) are of low risk 

32 significance. In those cases, no baseline inspection is required (the exception is shutdown 

33 configuration control, for which supplemental baseline inspections is necessary).

34 MITIGATING SYSTEMS CORNERSTONE

35 GENERAL DESCRIPTION

36 The objective of this cornerstone is to ensure the availability, reliability, and capability of systems 

37 that respond to initiating events to prevent undesirable consequences (i.e., core damage). When 

38 such an event occurs in conjunction with equipment and human failures, a reactor accident may 

39 result. Licensees therefore reduce the likelihood of reactor accidents by enhancing the availability 

40 and reliability of mitigating systems. Mitigating systems include those systems associated with 
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1 safety injection, residual heat removal, cooling water support systems, and emergency AC power. 

2 This cornerstone includes mitigating systems that respond to both operating and shutdown events. 

3 PERFORMANCE INDICATORS

4 While safety systems and components are generally thought of as those that are designed for 

5 design-basis accidents, not all mitigating systems have the same risk importance. PRAs have 

6 shown that risk is often influenced not only by front-line mitigating systems, but also by support 

7 systems and equipment. Such systems and equipment, both safety- and non-safety-related, have 

8 been considered in selecting the PIs for this cornerstone. The PIs are all direct counts of either 

9 mitigating system availability or reliability or surrogates of mitigating system performance. They 

10 have face validity for their intended use, because they are quantifiable, have a logical relationship 

11 to safety performance expectations, are meaningful, and the data are readily available. Not all 

12 aspects of licensee performance can be monitored by PIs. Risk-significant areas not covered by 

13 PIs will be assessed through inspection. 

14 BARRIER INTEGRITY CORNERSTONE

15 GENERAL DESCRIPTION 

16 The purpose of this cornerstone is to provide reasonable assurance that the physical design 

17 barriers (fuel cladding, reactor coolant system, and containment) protect the public from 

18 radionuclide releases caused by accidents or events. These barriers play an important role in 

19 supporting the NRC Strategic Plan goal for nuclear reactor safety, “Prevent radiation-related 

20 deaths or illnesses due to civilian nuclear reactors.” The defense in depth provided by the 

21 physical design barriers which comprise this cornerstone allow achievement of the reactor safety 

22 goal.

23 PERFORMANCE INDICATORS

24 The performance indicators for this cornerstone cover two of the three physical design barriers. 

25 The first barrier is the fuel cladding. Maintaining the integrity of this barrier prevents the release 

26 of radioactive fission products to the reactor coolant system, the second barrier. Maintaining the 

27 integrity of the reactor coolant system reduces the likelihood of loss of coolant accident initiating 

28 events and prevents the release of radioactive fission products to the containment atmosphere in 

29 transients and other events. Performance indicators for reactor coolant system activity and reactor 

30 coolant system leakage monitor the integrity of the first two physical design barriers. Even if 

31 significant quantities of radionuclides are released into the containment atmosphere, maintaining 

32 the integrity of the third barrier, the containment, will limit radioactive releases to the 

33 environment and limit the threat to the public health and safety. The integrity of the containment 

34 barrier is ensured through the inspection process.

35

36 Therefore, there are three desired results associated with the barrier integrity cornerstone. These 

37 are to maintain the functionality of the fuel cladding, the reactor coolant system, and the 

38 containment.
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1 EMERGENCY PREPAREDNESS CORNERSTONE

2 GENERAL DESCRIPTION

3 Emergency Preparedness (EP) is the final barrier in the defense in depth approach to safety that 

4 NRC regulations provide for ensuring the adequate protection of the public health and safety. 

5 Emergency Preparedness is a fundamental cornerstone of the Reactor Safety Strategic 

6 Performance Area. 10 CFR Part 50.47 and Appendix E to Part 50 define the requirements of an 

7 EP program and a licensee commits to implementation of these requirements through an 

8 Emergency Plan (the Plan). The performance indicators for this cornerstone are designed to 

9 ensure that the licensee is capable of implementing adequate measures to protect the public health 

10 and safety in the event of a radiological emergency. 

11 PERFORMANCE INDICATORS

12 Compliance of EP programs with regulation is assessed through observation of response to 

13 simulated emergencies and through routine inspection of onsite programs. Demonstration 

14 exercises involving onsite and offsite programs, form the key observational tool used to support, 

15 on a continuing basis, the reasonable assurance finding that adequate protective measures can 

16 and will be taken in the event of a radiological emergency. This is especially true for the most 

17 risk significant facets of the EP program. This being the case, the PIs for onsite EP draw

18 significantly from performance during simulated emergencies and actual declared emergencies, 

19 but are supplemented by direct NRC inspection and inspection of licensee self assessmentself20 assessment. NRC assessment of the adequacy of offsite EP will rely (as it does currently) on 

21 regular FEMA evaluations.

22 OCCUPATIONAL EXPOSURE CORNERSTONE

23 GENERAL DESCRIPTION

24 This cornerstone includes the attributes and the bases for adequately protecting the health and 

25 safety of workers involved with exposure to radiation from licensed and unlicensed radioactive 

26 material during routine operations at civilian nuclear reactors. The desired result is the adequate 

27 protection of worker health and safety from this exposure. The cornerstone uses as its bases the 

28 occupational dose limits specified in 10 CFR 20 Subpart C and the operating principle of 

29 maintaining worker exposure “as low as reasonably achievable (ALARA)” in accordance with 

30 10 CFR 20.1101. These radiation protection criteria are based upon the assumptions that a linear 

31 relationship, without threshold, exists between dose and the probability of stochastic health 

32 effects (radiological risk); the severity of each type of stochastic health effect is independent of 

33 dose; and non-stochastic radiation-induced health effects can be prevented by limiting exposures 

34 below thresholds for their induction. Thus, 10 CFR Part 20 requires occupational doses to be 

35 maintained ALARA with the exposure limits defined in 10 CFR 20 Subpart C constituting the 

36 maximum allowable radiological risk. Industry experience has shown that the occurrences of 

37 uncontrolled occupational exposure that potentially could result in an individual exceeding a dose 

38 limit have been low frequency events. These potential overexposure incidents are associated with 

39 radiation fields exceeding 1000 millirem per hour (mrem/hr) and have involved the loss of one or 

40 more radiation protection controls (barriers) established to manage and control worker exposure. 

41 The probability of undesirable health effects to workers can be maintained within acceptable 

42 levels by controlling occupational exposures to radiation and radioactive materials to prevent 
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1 regulatory overexposures and by implementing an aggressive and effective ALARA program to 

2 monitor, control and minimize worker dose. 

3 PERFORMANCE INDICATORS

4 A combined performance indicator is used to assess licensee performance in controlling worker 

5 doses during work activities associated with high radiation fields or elevated airborne 

6 radioactivity areas. The PI was selected based upon its ability to provide an objective measure of 

7 an uncontrolled measurable worker exposure or a loss of access controls for areas having 

8 radiation fields exceeding 1000 millirem per hour (mrem/hr). The data for the PI are currently 

9 being collected by most licensees in their corrective action programs. The PI either directly 

10 measures the occurrence of unanticipated and uncontrolled dose exceeding a percentage of the 

11 regulatory limits or identifies the failure of barriers established to prevent unauthorized entry into 

12 those areas having dose rates exceeding 1000 mrem/hr. The indicator may identify declining 

13 performance in procedural guidance, training, radiological monitoring, and in exposure and 

14 contamination control prior to exceeding a regulatory dose limit. The effectiveness of the 

15 licensee’s assessment and corrective action program is considered a cross-cutting issue and is 

16 addressed elsewhere.

17 PUBLIC EXPOSURE CORNERSTONE

18 GENERAL DESCRIPTION

19 This cornerstone includes the attributes and the bases for adequately protecting public health and 

20 safety from exposure to radioactive material released into the public domain as a result of routine 

21 civilian nuclear reactor operations. The desired result is the adequate protection of public health 

22 and safety from this exposure. These releases include routine gaseous and liquid radioactive 

23 effluent discharges, the inadvertent release of solid contaminated materials, and the offsite 

24 transport of radioactive materials and wastes. The cornerstone uses as its bases, the dose limits 

25 for individual members of the public specified in 10 CFR 20, Subpart D; design objectives 

26 detailed in Appendix I to 10 CFR Part 50 which defines what doses to members of the public 

27 from effluent releases are “as low as reasonably achievable” (ALARA); and the exposure and 

28 contamination limits for transportation activities detailed in 10 CFR Part 71 and associated 

29 Department of Transportation (DOT) regulations. These radiation protection standards require 

30 doses to the public be maintained ALARA with the regulatory limits constituting the maximum 

31 allowable radiological risk based on the linear relationship between dose received and the 

32 probability of adverse health effects. 

33 PERFORMANCE INDICATORS

34 One PI for the radioactive effluent release program has been initially developed to monitor for 

35 inaccurate or increasing projected offsite doses. The effluent radiological occurrence (ERO) PI 

36 does not evaluate performance of the radiological environmental monitoring program (REMP) 

37 which will be assessed through the routine baseline inspection. For transportation activities, the 

38 infrequent occurrences of elevated radiation or contamination limits in the public domain from 

39 this measurement area precluded identification of a corresponding indicator. A second PI has been

40 proposed for future use to monitor the inadvertent release of potentially contaminated materials 

41 which could result in a measurable dose to a member of the public. These indicators will provide 

42 partial assessments of licensee radioactive effluent monitoring and offsite material release 
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1 activities and were selected to identify decreasing performance prior to exceeding public 

2 regulatory dose limits.

3 PHYSICAL SECURITY CORNERSTONE

4 GENERAL DESCRIPTION

5 This cornerstone addresses the attributes and establishes the basis to provide assurance that the 

6 physical protection system can protect against the design basis threat of radiological sabotage as 

7 defined in 10 CFR 73.1(a). The key attributes in this cornerstone are based on the defense in 

8 depth concept and are intended to provide protection against both external and internal threats. 

9 To date, there have been no attempted assaults with the intent to commit radiological sabotage 

10 and, although there has been no PRA work done in the area of safeguards, it is assumed that there 

11 exists a small probability of an attempt to commit radiological sabotage. Although radiological 

12 sabotage is assumed to be a small probability, it is also assumed to be risk significant since a 

13 successful sabotage attempt could result in initiating an event with the potential for disabling of 

14 the safety systems necessary to mitigate the consequences of the event with substantial 

15 consequence to public health and safety. An effective security program decreases the risk to 

16 public health and safety associated with an attempt to commit radiological sabotage.

17 PERFORMANCE INDICATORS

18 One performance indicator is used to assess licensee performance in this cornerstone.

19

20 The performance of the physical protection system will be measured by the percent of the time all 

21 components (barriers, alarms and assessment aids) in the systems are available and capable of 

22 performing their intended function. When systems are not available and capable of performing 

23 their intended function, compensatory measures must be implemented. Compensatory measures 

24 are considered acceptable pending equipment being returned to service, but historically have been 

25 found to degrade over time. The degradation of compensatory measures over time, along with the 

26 additional costs associated with implementation of compensatory measures provides the incentive 

27 for timely maintenance/I&C support to return equipment to service. The percent of time 

28 equipment is available and capable of performing its intended function will provide data on the 

29 effectiveness of the maintenance process and also provide a method of monitoring equipment 

30 degradation as a result of aging that could adversely impact on reliability. 

31

32
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1

2

3 [This page left intentionally blank.]
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1 APPENDIX D

2

3 Plant Plant-Specific Design Issues

4

5 This appendix provides additional guidance on plant specific-specific Frequently Asked Questions 

6 and identifies resolutions to performance indicator reporting issues that are specific to individual 

7 plant designs. Refer to Appendix E for guidance on the process for submitting an FAQ. FAQs 

8 should be submitted as soon as possible once the Licensee and resident inspector or region has 

9 identified an issue on which there is not agreement. If the Licensee is not sure how to interpret a 

10 situation and the quarterly report is due, an FAQ should be submitted and a comment in the PI 

11 comment field would be appropriate. It is incumbent on NRC and the Licensee to work 

12 expeditiously and cooperatively, sharing concerns, questions and data in order that the issue can be 

13 resolved quickly.

14

15 Plant-specific Issues

16

17 The NEI 99-02 guidance was written to accommodate situations anticipated to arise at a typical 

18 nuclear power plant. However, uncommon plant designs or unique conditions may exist that have 

19 not been anticipated. In these cases, licensees should first apply the guidance as written to 

20 determine the impact on the indicators. Then, if the licensee believes that there are unique 

21 circumstances sufficient to warrant an exception to the guidance as written, the licensee should 

22 submit a Frequently Asked Question to NEI for consideration at a public meeting with the NRC. 

23 If the FAQ is approved, the issue will be included in Appendix D of this document as a plant24 specific issue.

25

26 Some provisions in NEI 99-02 may differ from the design, programs, or procedures of a particular 

27 plant. Examples include (1) the overlapping Emergency Planning Zones at Kewaunee and Point 

28 Beach and (2) actions to address storm-driven debris on intake structures. 

29

30 In evaluating each request for a plant-specific exception, this forum will take into consideration 

31 factors related to the particular issue. 

32

33 Kewaunee and Point Beach

34

35 Issue: The Kewaunee and Point Beach sites have overlapping Emergency Planning Zones (EPZ). 

36 We report siren data to the Federal Emergency Management Agency (FEMA) grouped by criterion 

37 other than entire EPZs (such as along county lines). May we report siren data for the PIs in the 

38 same fashion to eliminate confusion and prevent 'double reporting' of sirens that exist in both 

39 EPZs? Kewaunee and Point Beach share a portion of EPZs and responsibility for the sirens has 

40 been divided along the county line that runs between the two sites. FEMA has accepted this, and 

41 so far the NRC has accepted this informally.

42

43 Resolution: The purpose of the Alert and Notification System Reliability PI is to indicate the 

44 licensee’s ability to maintain risk-significant EP equipment. In this unique case, each neighboring 

45 plant maintains sirens in a different county. Although the EPZ is shared, the plants do not share 

46 the same site. In this case, it is appropriate for the licensees to report the sirens they are 
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1 responsible for. The NRC Web site display of information for each site will contain a footnote 

2 recognizing this shared EPZ responsibility.

3

4 North Anna and Surry

5 Continue to report PP01 in accordance with the current guidance in NEI 99-02. 

6

7 Grand Gulf

8

9 Issue: Of the 43 sirens associated with our Alert Notification System, two of the sirens are located 

10 in flood plain areas. During periods of high river water, the areas associated with these sirens are 

11 inaccessible to personnel and are uninhabitable. During periods of high water, the electrical power 

12 to the entire area and the sirens is turned off. The frequency and duration of this occurrence varies 

13 based upon river conditions but has occurred every year for the past five years and lasts an average 

14 of two months on each occasion. 

15

16 Assuming the sirens located in the flood plain areas are operable prior to the flooded and 

17 uninhabitable conditions, would these sirens be required to be included in the performance 

18 indicator during flooded conditions?

19

20 Resolution: If sirens are not available for operation due to high flood water conditions and the area 

21 is deemed inaccessible and uninhabitable by State and/or Local agencies, the siren(s) in question 

22 will not be counted in the numerator or denominator of the Performance Indicator for that testing 

23 period.

24

25 Diablo Canyon Units 1 and 2

26

27 Issue: At Diablo Canyon (DC), intrusion of marine debris (kelp and other marine vegetation) at the 

28 circulating water intake structures can occur and, under extreme storm conditions result in high 

29 differential pressure across the circulating water traveling screens, loss of circulating water pumps 

30 and loss of condenser. Over the past several years, DC has taken significant steps, including 

31 changes in operating strategy as well as equipment enhancements, to reduce the vulnerability of 

32 the plant to this phenomenon. DC has also taken efforts to minimize kelp, however environmental 

33 restrictions on kelp removal and the infeasibility of removing (and maintaining removal of) 

34 extensive marine growth for several miles around the plant prevent them from eliminating the 

35 source if the storm-driven debris. To minimize the challenge to the plant under storm conditions 

36 which could likely result in loss of both circulating water pumps, DC procedurally reduces power 

37 to 25% power or less. From this power level, the plant can be safely shut down by control rod 

38 motion and use of atmospheric dump valves without the need for a reactor trip. 

39

40 Is this anticipatory plant shutdown in response to an external event, where DC has taken all 

41 reasonable actions within environmental constraints to minimize debris quantity and impact, able 

42 to be excluded from being counted under IE01 and IE02?

43

44 Resolution: In consideration of the intent of the performance indicators and the extensive actions 

45 taken by PG&E to reduce the plant challenge associated with shutdowns in response to severe 

46 storm-initiated debris loading, the following interpretation will be applied to Diablo Canyon. A 

47 controlled shutdown from reduced power (less than 25%), which is performed in conjunction with 
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1 securing of the circulating water pumps to protect the associated traveling screens from damage 

2 due to excessive debris loading under severe storm conditions, will not be considered a "scram." If, 

3 however, the actions taken in response to excessive debris loading result in the initiation of a 

4 reactor trip (manual or automatic), the event would require counting under both the Unplanned 

5 Scrams (IE01) and Scrams with a Loss of Normal Heat Removal (IE02) indicators.

6

7 Diablo Canyon

8

9 Issue: The response to PI FAQ #158 states “Anticipatory power changes greater than 20% in 

10 response to expected problems (such as accumulation of marine debris and biological 

11 contaminants in certain seasons) which are proceduralized but cannot be predicted greater than 72 

12 hours in advance may not need to be counted if they are not reactive to the sudden discovery of 

13 off-normal conditions.”

14 Due to its location on the Pacific coast, Diablo Canyon is subject to kelp/debris intrusion at the 

15 circulating water intake structure under extreme storm conditions. If the rate of debris intrusion is 

16 sufficiently high, the traveling screens at the intake of the main condenser circulating water pumps 

17 (CWPs) become overwhelmed. This results in high differential pressure across the screens and 

18 necessitates a shutdown of the affected CWP(s) to prevent damage to the screens.

19 To minimize the challenge to the plant should a shutdown of the CWP(s) be necessary in order to 

20 protect the circulating water screens, the following operating strategy has been adopted:

21 • If a storm of sufficient intensity is predicted, reactor power is procedurally curtailed to 50% in 

22 anticipation of the potential need to shut down one of the two operating CWPs. Although the 

23 plant could remain at 100% power, this anticipatory action is taken to avoid a reactor trip in the 

24 event that intake conditions necessitate securing a CWP. One CWP is fully capable of 

25 supporting plant operation at 50% power.

26 • If one CWP must be secured based on adverse traveling screen/condenser differential pressure, 

27 the procedure directs operators to immediately reduce power to less than 25% in anticipation of 

28 the potential need to secure the remaining CWP. Although plant operation at 50% power could 

29 continue indefinitely with one CWP, this anticipatory action is taken to avoid a reactor trip in 

30 the event that intake conditions necessitate securing the remaining CWP. Reactor shutdown 

31 below 25% power is within the capability of the control rods, being driven in at the maximum 

32 rate, in conjunction with operation of the atmospheric dump valves. 

33 • Should traveling screen differential pressure remain high and cavitation of the remaining CWP 

34 is imminent/occurring, the CWP is shutdown and a controlled reactor shutdown is initiated. 

35 Based on anticipatory actions taken as described above, it is expected that a reactor trip would 

36 be avoided under these circumstances.

37 How should each of the above power reductions (i.e., 100% to 50%, 50% to 25%, and 25% to 

38 reactor shutdown) count under the Unplanned Power Changes PI?

39

40 Resolution: Anticipatory power reductions, from 100% to 50% and from 50% to less than 25%, 

41 that result from high swells and ocean debris are proceduralized and cannot be predicted 72 hours 

42 in advance. Neither of these anticipatory power reductions would count under the Unplanned 

43 Power Changes PI. However, a power shutdown from less than 25% that is initiated on loss of the 

44 main condenser (i.e., shutdown of the only running CWP) would count as an unplanned power 

45 change since such a reduction is forced and can therefore not be considered anticipatory.
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1

2 D.C. Cook

3

4 Issue: The definition for the Reactor Coolant System (RCS) Leakage performance indicator is 

5 "The maximum RCS Identified Leakage in gallons per minute each month per the technical 

6 specification limit and expressed as a percentage of the technical specification limit."

7

8 Cook Nuclear Plant Unit 1 and 2 report Identified Leakage since the Technical Specifications have 

9 a limit for Identified Leakage with no limit for Total Leakage. Plant procedures for RCS leakage 

10 calculation requires RCS leakage into collection tanks to be counted as Unidentified Leakage due 

11 to non-RCS sources directed to the collection tanks. All calculated leakage is considered

12 Unidentified until the leakage reaches an administrative limit at which point an evaluation is 

13 performed to identify the leakage and calculate the leak rate. Consequently, Identified Leakage is 

14 unchanged until the administrative limit is reached. This does not allow for trending allowed RCS 

15 Leakage. The procedural requirements will remain in place until plant modifications can be made 

16 to remove the non-RCS sources from the drain collection tanks. What alternative method should 

17 be used to trend allowed RCS leakage for the Barrier Integrity Cornerstone?

18

19 Resolution: Report the maximum RCS Total Leakage calculated in gallons per minute each month 

20 per the plant procedures instead of the calculated Identified Leakage. This value will be compared 

21 to and expressed as a percentage of the combined Technical Specification Limits for Identified and 

22 Unidentified Leakage. This reporting is considered acceptable to provide consistency in reporting 

23 for plants with the described plant configuration.

24

25 Nine Mile Point

26

27 Issue: Some plants are designed to have a residual transfer of the non-safety electrical buses from 

28 the generator to an off-site power source when the turbine trip is caused by a generator protective 

29 feature. The residual transfer automatically trips large electrical loads to prevent damaging plant 

30 equipment during re-energization of the switchgear. These large loads include the reactor 

31 feedwater pumps, reactor recirculation pumps, and condensate booster pumps. After the residual 

32 transfer is completed the operators can manually restart the pumps from the control room. The 

33 turbine trip will result in a reactor scram. Should the trip of the reactor feedwater pumps be 

34 counted as a scram with a loss of normal heat removal?

35

36 Resolution: No. In this instance, the electrical transfer scheme performed as designed following a 

37 scram and the residual transfer. In addition the pumps can be started from the control room. 

38 Therefore, this would not count as a scram with a loss of normal heat removal.

39

40 Point Beach

41

42 Issue: On June 27th, Point Beach Unit 2 was manually scrammed, in accordance with Abnormal 

43 Operating Procedure AOP 13A, "Circulating Water System Malfunction," and power was reduced 

44 on Point Beach Unit 1 by greater than 20% (from 100% to 79%) due to reduced water level in the 

45 pump bay attributable to an influx of small forage fish (alewives). The large influx of fish created a 

46 high differential water level across the traveling screens and ultimately failure of shear pins for the 

47 screen drive system, leading to a rapid drop in bay level. The plant knows when the alewife 
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1 spawning and hatching seasons occur and the effects of Lake Michigan temperature fluctuations on 

2 the route of alewife schools. It was aware of the presence of large schools at other Lake Michigan 

3 plants this spring and discussed those events and the potential of them occurring at Point Beach at 

4 the morning staff meetings. During the thirty years of plant operation, there have been a few 

5 instances where a large number of fish entered the plant circulating water system.

6

7 High alewife populations coupled with seasonal variations, lake conditions and wind conditions 

8 created the situation that resulted in the downpower on June 27th. Point Beach staff believes that 

9 these are uncontrollable environmental conditions. Plant procedures are in place which direct 

10 actions when the water level in the pump bay decreases. However, it is not possible to predict the 

11 exact time of an influx of schooling fish nor the massive population of fish that arrived in the 

12 pump bay. Page 17 of NEI 99-02 Revision 1 states, "Anticipated power changes greater than 20% 

13 in response to expected problems (such as accumulation of marine debris and biological 

14 contaminants in certain seasons) which are proceduralized but cannot be predicted greater than 72 

15 hours in advance may not need to be counted if they are not reactive to the sudden discovery of 

16 off-normal conditions." Would this situation count as an unplanned power change?

17

18 Resolution: No. The influx of alewives was expected as evidenced by the discussion of events at 

19 other plants on Lake Michigan but was not predictable greater than 72 hours in advance due to the 

20 variables involved. Large schools of alewives are a result of environmental and aquatic conditions 

21 that occur in certain seasons. The response to the drop in bay level is proceduralized. 

22

23 Quad Cities

24

25 Issue:1) At Quad Cities, load reductions in excess of 20% during hot weather are sometimes 

26 necessary if the limits of the NPDES Permit limit would be exceeded. Actual initiation of a power 

27 change is not predictable 72 hrs in advance, as actions are not taken until temperatures actually 

28 reach predefined levels. Would these power changes be counted?

29 2) Power reductions are sometimes necessary during summer hot weather and/or lowered river 

30 level conditions when conducting standard condenser flow reversal evolutions. The load reduction 

31 timing is not predictable 72 hrs in advance as the accumulation of Mississippi River debris/silt 

32 drives the actual initiation of each evolution. The main condenser system design allows for 

33 cleaning by flow reversal, which is procedurally controlled to assure sufficient vacuum is 

34 maintained. It is sometimes necessary, due to high inlet temperatures, to reduce power more than 

35 20% to meet procedural requirements during the flow reversal evolution. These conditions are 

36 similar to those previously described in FAQ 158. Would these power changes be counted for this 

37 indicator?

38

39 Resolution:

40 1) No.

41 2) No. Power changes in excess of 20% for the purposes of condenser flow reversal are not 

42 counted as an unplanned power change. 

43

44
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1 River Bend Station

2

3 Issue: River Bend Station (RBS) seeks clarification of BI-02 information contained in NEI 99-02 

4 guidance, specifically page 80, lines 36 and 37 “Only calculations of RCS leakage that are 

5 computed in accordance with the calculational methodology requirements of the Technical 

6 Specifications are counted in this indicator.”

7 NEI 99-02, Revision 2 states that the purpose for the Reactor Coolant System (RCS) Leakage 

8 Indicator is to monitor the integrity of the reactor coolant system pressure boundary. To do this, 

9 the indicator uses the identified leakage as a percentage of the technical specification allowable 

10 identified leakage. Moreover, the definition provided is “the maximum RCS identified leakage in 

11 gallons per minute each month per technical specifications and expressed as a percentage of the 

12 technical specification limit.”

13 The RBS Technical Specification (TS) states “Verify RCS unidentified LEAKAGE, total 

14 LEAKAGE, and unidentified LEAKAGE increase are within limits (12 hour frequency).” RBS 

15 accomplishes this surveillance requirement using an approved station procedure that requires the 

16 leakage values from the 0100 and 1300 calculation be used as the leakage “of record” for the 

17 purpose of satisfying the TS surveillance requirement. These two data points are then used in the 

18 population of data subject to selection for performance indicator calculation each quarter (highest 

19 monthly value is used).

20 The RBS approved TS method for determining RCS leakage uses programmable controller

21 generated points for total RCS leakage. The RBS’ programmable controller calculates the average

22 total leakage for the previous 24 hours and prints a report giving the leakage rate into each sump it

23 monitors, showing the last four calculations to indicate a trend and printing the total unidentified

24 LEAKAGE, total identified LEAKAGE, their sum, and the 24 hour average. The programmable

25 controller will print this report any time an alarm value is exceeded. The printout can be ordered

26 manually or can be automatic on a 1 or 8 hour basis. While the equipment is capable of generating

27 leakage values at any frequency, the equipment generates hourly values that are summarized in a

28 daily report.

29 The RBS’ TS Bases states “In conjunction with alarms and other administrative controls, a 12 hour

30 Frequency for this Surveillance is appropriate for identifying changes in LEAKAGE and for 

31 tracking required trends.”

32 The Licensee provides that NEI 99-02 requires only the calculations performed to accomplish the

33 approved TS surveillance using the station procedure be counted in the RCS leakage indicator. In 

34 this case, the surveillance procedure captures and records the 0100 and 1300 RCS leakage values 

35 to satisfy the TS surveillance requirements. The NRC Resident has taken the position that all 

36 hourly values from the daily report should be used for the RCS leakage performance indicator 

37 determination, even though they are not required by the station surveillance procedure. The 

38 Resident maintains that all hourly values use the same method as the 0100 and 1300 values and 

39 should be included in the leakage determination.

40 Is the Licensee interpretation of NEI 99-02 correct?

41

42 Resolution: 

43 All calculations of RCS leakage that are computed in accordance with the calculational 

44 methodology requirements of the Technical Specifications are counted in this indicator. Since the 

45 River Bend Station leakage calculation is an average of the previous 24 hourly leakage rates which 

46 are calculated in accordance with the technical specification methodology, it is acceptable for 

47 River Bend Station to include only those calculations that are performed to meet the technical 

48 specifications surveillance requirement when determining the highest monthly values for reporting. 
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1 The ROP Working Group is forming a task force to review this performance indicator based on 

2 industry practices.

3

4 Catawba

5

6 Issue: Catawba Nuclear Station has 89 sirens in their 10-mile EPZ; 68 of these are located in York 

7 County. Duke Power's siren testing program includes a full cycle test for performance indicator 

8 purposes once each calendar quarter. On Tuesday, September 7, 2004, York County sounded the 

9 sirens in their county's portion of the EPZ to alert the public of the need to take protective actions 

10 for a Tornado Warning. Catawba is uncertain whether to include the results of the actual activation 

11 in their ANS PI statistics. The definition in NEI 99-02 does not address actual siren activations. In 

12 contrast, the Drill/Exercise Performance (DEP) Indicator requires that actual events be included in 

13 the PI. Should the performance during the actual siren activation be included in the Alert and 

14 Notification System (ANS) Performance Indicator Data?

15

16 Resolution: For this instance, Catawba may include the results of the September 7, 2004 actual 

17 siren activations in their ANS PI data. However, for all future instances, no actual siren activation 

18 data results shall be included in licensees' ANS PI data.

19

20 Fitzpatrick

21

22 Issue: Frazil icing is a condition that is known to occur in northern climates, under certain 

23 environmental conditions involving clear nights, open water, and low air temperatures. Under 

24 these conditions the surface of the water will experience a super-cooling effect. The super-cooling 

25 allows the formation of small crystals of ice, frazil ice. Strong winds also play a part in the 

26 formation of frazil ice in lakes. The strong winds mix the super-cooled water and the entrained 

27 frazil crystals, which have little buoyancy, to the depths of the lake. The submerged frazil crystals 

28 can then form slushy irregular masses below the surface. The crystals will also adhere to any 

29 submerged surface regardless of shape that is less than 32°F. 

30

31 In order to prevent the adherence of frazil ice crystals to the intake structure bars and ensure 

32 maintenance of the ultimate heat sink, the bars of the intake structure are continuously heated. 

33 Surveillance tests conducted before and after the event confirmed the operability of the intake 

34 structure deicing heaters. While heating assists in preventing formation of frazil ice crystals 

35 directly on the bars of the intake structure, the irregular slushy masses discussed above can be 

36 drawn to the intake structure in quantities that reduce flow to the intake canal. If the flow to the 

37 intake canal is restricted in this manner, then the circulating (lake) water flow must be reduced, to 

38 allow frazil ice formations to clear. This water flow reduction necessitates a reduction of reactor 

39 power. 

40

41 The plant put procedural controls in place to monitor the potential for frazil ice formation during 

42 periods of high susceptibility. A surveillance test requires evaluating the potential for frazil ice 

43 formation during the winter months, when intake temperature is less than 33°F. In support of the 

44 surveillance test, the Chemistry Department developed a test procedure for assessing the potential 

45 for frazil ice formation. An abnormal operating procedure was developed to mitigate the 

46 consequences of an event should frazil icing reduce the flow through the intake structure. During 

47 the overnight hours between March 2, and March 3 the environmental conditions were conducive 
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D-8

1 to the formation of frazil ice. Chemistry notified Operations that the potential for frazil icing was 

2 very high. Operators were briefed on this condition, the very high potential for frazil ice 

3 formation, and the need to closely monitor intake level.

4

5 When indications showed a lowering intake canal level with no other abnormalities indicated, 

6 operations entered the appropriate abnormal operating procedure and reduced power from 100% to 

7 approximately 30% so that circulating water pumps could be secured, thereby reducing flow 

8 through the intake structure heated bars, to slow the formation or accumulation of frazil ice and 

9 allow melting and break-up of the ice already formed. 

10

11 As noted above NEI 99-02 Revision 3, in discussing down-powers that are initiated in response to 

12 environmental conditions states “The circumstances of each situation are different and should be 

13 identified to the NRC in a FAQ so that a determination can be made concerning whether the power 

14 change should be counted.” 

15

16 Does the transient meet the conditions for the environmental exception to reporting Unplanned 

17 Power changes of greater than 20% RTP?

18

19 Resolution: Yes, the downpower was caused by environmental conditions, beyond the control of 

20 the licensee, which could not be predicted greater than 72 hours in advance. Procedures, specific to 

21 frazil ice, were in place to address this expected condition. In lieu of additional FAQ submittals, 

22 this response may be applied by the licensee to future similar instances of frazil ice formation.

23

24 Turkey Point

25

26 Issue 1: For the MSPI truncation requirements, three methods were provided whereby licensees 

27 could demonstrate sufficient convergence for PRA model acceptability for MSPI. If a licensee is 

28 unable to demonstrate either: (1) a truncation level of 7 orders of magnitude below the baseline 

29 CDF or (2) that Birnbaum values converge within 80% for event with Birnbaum values >1E-6 or 

30 (3) that CDF has converged within 5% when using the approach detailed in section F.6.

31

32 What if a licensee, due to limitations with their PRA can “come close” but not meet either of these 

33 requirements? 

34

35 Is our approach described in the MSPI basis document excerpted below acceptable, given that the 

36 5% guideline is exceeded by only 0.2%, and that we cannot reduce the increase in CDF due to the 

37 last decade decrease in truncation further due to hardware/software limitations?

38

39 What should be done in the future when model updates may result in a different degree of 

40 compliance with the truncation guidelines, e.g., the increase in CDF due to the last decade 

41 decrease in truncation is, say, now 6% instead of 5.2%?

42

43 NEI 99-02 Guidance needing interpretation (include page and line citation): 

44

45 Appendix F, Sections F.6, page F-48, which states: “The truncation level used for the method 

46 described in this section should be sufficient to provide a converged value of CDF. CDF is 

47 considered converged when decreasing the truncation level by a decade results in a change in 

48 CDF of less than 5%”
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1

2 Event or circumstances requiring guidance interpretation:

3

4 As documented in the Turkey Point MSPI Basis document, due to limitations with Turkey Point’s 

5 PRA they were only able to achieve a truncation of 3E-11 per year, and the increase in CDF due 

6 to the last decade decrease in truncation is 5.2%, only slightly greater than the 5% guideline.

7

8 Turkey Point’s Basis Document states in part:

9

10 “...The baseline CDF is 4.07E-6 per year, quantified at truncation of 1.0E-11 per year. This 

11 truncation is about five-and-a-half orders of magnitude below the baseline CDF. Attempts to 

12 quantify at lower truncations failed due to hardware/software limitations; therefore, the "7 orders 

13 of magnitude less than the baseline CDF" criterion defined in the first paragraph of Appendix 

14 F, Sections 1.3.1 and 2.3.1 cannot be met. However, an alternative is described in the second 

15 paragraph of these sections. For all MSPI basic events with a Birnbaum importance of greater 

16 than 1E-6, If the ratio of the Birnbaum importances calculated at one decade above

17 The lowest truncation (for our case, 1E-10 per year) to their Respective importances 

18 calculated at the lowest truncation (for our case, 1E-11 Per year) is greater than 0.8, then the 

19 baseline CDF cutset file at the Lowest truncation can be used to generate the MSPI Birnbaum 

20 importances.

21

22 Turkey Point meets this criterion for all but a few of the MSPI basic events with a Birnbaum 

23 importance of greater than 1E-6. The Birnbaum importances for these basic events were 

24 calculated using the alternative described in Section 6 of Appendix F. This alternative allows the 

25 user to calculate the Birnbaum importances by regenerating cutsets provided the truncation level 

26 is "sufficient to provide a converged value of CDF. CDF is considered to be converged when 

27 decreasing the truncation level by a decade results in a change in CDF of less than 5%." 

28

29 For Turkey Point, at 1E-11 per year, the increase in the baseline CDF due to the last decade 

30 decrease in truncation is 4.1%, meeting this criterion. However, when the Birnbaum calculations 

31 were attempted at a truncation of 1E-11 per year, the runs failed due to hardware/software 

32 limitations. This was most likely due to the fact that many more cutsets were being generated due 

33 to the quantification of the model with an important component out of service. However, the 

34 quantification of these Birnbaum importances via regeneration was possible at a truncation level of 

35 3E-11 per year. This is the truncation that was used to calculate the Birnbaum importances for the 

36 few basic events in the MSPI calculation that did not meet the “0.8” criterion. Birnbaum 

37 importance is not input into the MSPI calculation, FV importance is, and the Birnbaum importance 

38 is calculated using the FV, the basic event probability (p), and the baseline CDF. The FV for these 

39 basic events was calculated using the formula below.

40

41 FV = B*p / CDF(baseline)

42

43 The MSPI calculation takes the FVs calculated in this manner, divides them by their respective 

44 basic event probabilities, and multiplies the results by the baseline CDF input to the MSPI 

45 calculation, which is the CDF baseline calculated at a truncation of 1E-11 per year. This will 

46 effectively apply a "correction factor" to the Birnbaum equal to the ratio of the baseline CDF 

47 calculated at a truncation of 1E-11 per year and the baseline CDF calculated at a truncation 

48 of 3E-11 per year. This correction Factor should serve to allay any concerns over using a slightly 
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1 higher truncation level for quantification of the Birnbaum importances for these basic events. 

2 Further, at a truncation of 3E-11 per year, the increase in CDF due to the last decade decrease in 

3 truncation is 5.2%, just slightly greater than the 5% guideline."

4

5 Issue 2: The Turkey Point High Head Safety Injection (HHSI) design is different than the 

6 description provided in Appendix F for Train Determination. Therefore, there is no system-specific 

7 guidance for HHSI which is applicable to the HHSI system at Turkey Point.

8

9 At Turkey Point, each unit (Unit 3 and Unit 4) has two HHSI pumps. The Unit 3 and Unit 4 HHSI 

10 pumps start on an SI signal from either unit, and all of them feed the stricken unit. Should the 

11 Turkey Point reporting model be revised to address the four train approach?

12

13 Resolution 1: It is acknowledged that there may be limitations with PRA software modeling such 

14 that a few licensees may not meet the explicit guidance limits for truncation and convergence.

15

16 In such cases, the licensee shall submit a FAQ and present the details of their analyses. Approval 

17 will be on a case by case basis.

18 For Turkey Point, their model was able to approach 5.2% (vice 5%) convergence and that is 

19 considered sufficient for the purposes of MSPI calculation.

20

21 Resolution 2: Yes. In order to ensure accurate reporting, add the opposite-unit HHSI pump trains 

22 for unavailability monitoring for each unit, and the opposite-unit HHSI pumps for reliability 

23 monitoring for each unit. Although the opposite-unit HHSI pumps are cooled by the opposite-unit 

24 component cooling water (CCW) pumps, they should not be added as they are already monitored 

25 for their associated unit, and their Birnbaum importances for the opposite-unit are several orders of 

26 magnitude less than their Birnbaum importances for their own unit.

27

28 Prairie Island and Surry Stations

29

30 Issue: Prairie Island has two diesel-driven service water pumps that are monitored under MSPI. 

31 Surry has 3 diesel-driven service water pumps that are monitored under MSPI. There is no 

32 industry prior information associated with this component type on Table 4 on page F-37

33

34 Resolution: Due to insufficient industry data upon which to develop a separate set of parameters 

35 for this component type, an existing component type should be chosen. Given that the failures for 

36 this type of pump are expected to be dominated by the driver rather than the pump, the diesel37 driven AFW pump component type should be used. 

38

39 San Onofre 

40

41 Issue: During March 2006, the San Onofre Nuclear Generating Station (SONGS) completed the 

42 MSPI Basis Document. The MSPI Basis Document contained a calculation of the FV/UA values 

43 for the CCW and SWC systems. The FV/UA values were derived by assuming that Train A is 

44 constantly running for the entire year and therefore all unavailability would be assigned to the non45 running Train B. The resultant FV/UA value for Train B was then conservatively applied to both 

46 Train A and Train B without averaging.

47
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1 Since the system is symmetric in importance, what should have occurred is that the FV/UA values 

2 should have been calculated for each train and averaged since each train is run approximately 50% 

3 of the time. This would be equivalent to calculating each train’s FV/UA value assuming the other 

4 train is running and then multiplying each train’s FV/UA value by an “operating factor” – the 

5 percentage of time the respective train is actually the running train (approximately 50% in this 

6 case) – and then averaging the two (Train A and Train B) FV/UA values.

7

8 In summary, an error was made in application of the NEI 99-02R4, Section F.1.3.4 guidance.

9

10 Resolution: The SONGS misapplication of the guidance in NEI 99-02R4 regarding the treatment 

11 of FV/UA due to the modeling asymmetries of the SSC systems were discussed with the NRC at 

12 the May 18 Reactor Oversight Process Task Force public meeting. It was concluded that the MSPI

13 Basis Document of April 1, 2006 was in error and requires correction to reflect the train averaging 

14 of section F 1.3.4 prior to submittal of the 2Q06 data on July 21, 2006.

15

16 Oyster Creek

17

18 Issue: An intake structure sea grassing event occurred on 8/6/2005 resulting in an abnormal low 

19 level in the north side of the intake structure and a subsequent unplanned downpower from 100% 

20 power to approximately 41% power for a duration of approximately 40 hours. The event was 

21 reported as Unplanned, excluded per NEI 99-02. 

22

23 Oyster Creek had been maintaining the intake structure in a summer seasonal readiness condition 

24 that was consistent with conditions in previous summer seasons. Appropriate preventive 

25 maintenance had been performed on the intake traveling screens. Daily flushing of the screen 

26 wash headers and periodic header cleaning had been instituted, in accordance with plant 

27 procedures and monitoring practices for summer readiness. These were expected conditions that 

28 the plant is forced to deal with during summer seasons. However, this event involved larger 

29 amounts of submerged sea grass than had been seen in the past.

30

31 Higher than normal levels of grass were experienced between 2300 hours on August 6, 2005 and 

32 0235 hours on August 6, 2006 at the intake structure. At approximately 0235 hours the Control 

33 Room received a report from the operator at the intake that intake level on the north side of the 

34 intake structure downstream of the screens was at < 1.4 psig as sensed by the bubbler indicator. 

35 This equates to a level of <-2.0 ft Mean Sea Level (MSL) and required entry into Abnormal 

36 Operating Procedure ABN-32, Abnormal Intake Level. This required more frequent grass removal 

37 from intake structure components. Backwashing, raking and screen cleaning were in progress 

38 prior to the event, in accordance with plant procedures. At approximately 0305 hours, an 

39 unexpected large influx of submerged sea grass (Gracilaria) entered the North Side of the intake 

40 structure resulting in a collapse of the Trash grates. The grass loading caused each screen’s shear 

41 pin on the #1, 2, & 3 screens to break, as designed to provide a measure of protection for the intake 

42 structure. The three screens on the South Side of the intake structure were not affected during the 

43 entire event. Water level downstream of the screens on the North Side lowered due to operation of 

44 #1 and #2 Circulating Water Pumps, #1 New Radwaste Service Water Pump and #1 Service Water 

45 Pump. The Control Room Unit Operator was informed by the Shift Manager at the intake that 

46 level on the North Side of the intake was 0 psig on the bubbler gage at the Screen Wash Control 

47 Panel (which corresponds to -5.13’ Mean Sea Level). This level exceeded the Alert threshold for 

48 EAL HA3. At 0330 hours Emergency Service Water (ESW) System 1 pumps were declared 
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1 inoperable and Technical Specification LCO 3.4.C.3. (7-day clock) was entered. The sudden, 

2 unexpected, large influx of submerged grass impacted the North Side of the Intake Structure 

3 resulting in a collapse of the Trash grates and the #1, 2 & 3 Intake Screen shear pins had broken. 

4 The Trash Rake was caught in #1 Bay. The shear pin for #1 Screen was replaced but sheared 

5 immediately. Both the 1-1 and the 1-2 Main Circulating Water Pumps were secured due to the low 

6 intake level resulting in pump cavitation, which required the power reduction to approximately 

7 40%. 

8

9 Resolution: The downpower that is described in this FAQ does count. The facility has not 

10 developed a specific procedure to proactively monitor for environmental conditions that would 

11 lead to sea grass intrusion, to direct proactive actions to take before the intrusion, and actions to 

12 take to mitigate an actual intrusion that are appropriate for the station and incorporate lessons 

13 learned. Development and use of a such a procedure in the future, instead of standing orders, may 

14 provide the basis for a future FAQ allowing excluding a downpower >20% for this PI. 

15

16 No change to PI guidance is needed.

17

18 Calvert Cliffs

19

20 Issue: Anticipated power changes greater than 20% in response to expected environmental 

21 problems (such as accumulation of marine debris, biological contaminants, or frazil icing) which 

22 are proceduralized but cannot be predicted greater than 72 hours in advance may not need to be 

23 counted unless they are reactive to the sudden discovery of off normal conditions... . The licensee 

24 is expected to take reasonable steps to prevent intrusion of marine or other biological growth from 

25 causing power reductions... The circumstances of each situation are different and should be 

26 identified to the NRC in a FAQ so that a determination can be made concerning whether the power 

27 change should be counted.’

28

29 During summer months, under certain environmental conditions, Calvert Cliffs can experience 

30 instances of significant marine life impingements which can cause high differential pressure across 

31 our Circulating Water (bay water) System traveling screens, restricting flow capability of our 

32 Circulating Water (CW) pumps which could ultimately result in a plant derate or trip due to being 

33 unable to maintain sufficient condenser vacuum.

34

35 In anticipation of these potential marine life impingement conditions, the site has proceduralized 

36 actions to be taken within an Abnormal Operating Procedure (AOP). The actions to be taken in 

37 these circumstances include placing travel screens in manual mode of operation and using the 

38 intake aerator and fire hoses to disperse the fish population. Although instances of biological 

39 blockages are expected, neither the time of nor the severity of the intrusions can be predicted.

40 During July 2006 the site had been periodically dealing with instances of jellyfish intrusions which 

41 had challenged maintaining sufficient CW flow, but had not been severe enough to threaten plant 

42 full power operation. On July 7, 2006 the site experienced a severe jellyfish intrusion and 

43 implemented the applicable AOP. This time the actions were unable to ensure sufficient CW flow 

44 to maintain Unit 1 at 100% power and a rapid power reduction was initiated on Unit 1, which 

45 ultimately reduced power to 40%. When the jellyfish intrusion was controlled, sufficient CW flow 

46 was restored, and power was restored to 100%. Given that the circumstances of this jellyfish 

47 intrusion was beyond the control of the plant, and that appropriate site actions have been 

48 proceduralized, should this event be exempted from counting as an unplanned power change? In 
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1 addition, can this exemption be applied to future, similar marine life impingements at Calvert 

2 Cliffs, where the site carries out the approved actions designed to counter act these conditions, 

3 without submittal of future FAQs?

4

5 Resolution: The downpower that is described in this FAQ does count. The facility has not 

6 developed a specific procedure to proactively monitor for environmental conditions that would 

7 lead to jelly fish intrusion, to direct proactive actions to take before the intrusion, and actions to 

8 take to mitigate an actual intrusion that are appropriate for the station and incorporate lessons 

9 learned: e.g.: staging equipment, assigning additional personnel or watches, implementing finer 

10 mesh screen use, use of hose spray to ward off jelly fish. Development and use of a such a 

11 procedure in the future, may provide the basis for a future FAQ allowing excluding a downpower 

12 >20% for this PI. 

13

14 No change to PI guidance is needed.

15

16 Point Beach

17

18 Issue: Point Beach is upgrading the Unit 1 and Unit 2 auxiliary feedwater systems (AF) during the 

19 second quarter of 2011 with Unit 2 being completed during the spring outage and Unit 1 while the 

20 plant is on line. The current AF design has two motor-driven AF pumps that are shared between 

21 the two units. In the current configuration, the operating unit has planned unavailability during the 

22 other unit’s refueling outage. After the upgrade modifications are completed, the AF system will 

23 have one new motor-driven pump dedicated to each unit and will no longer have planned 

24 unavailability during the other unit’s refueling outage. The new pumps will be the same model 

25 casing as the old pumps, but will have a different impeller, resulting in a higher flow rate, and will 

26 be powered by 4160V versus 480V. The preventive maintenance activities for the new pumps and 

27 associated monitored valves will be essentially the same as those for the existing pumps and 

28 associated monitored valves. The change will reduce the number of motor-driven AF trains from 

29 two to one per unit and will change the Point Beach generic common cause failure adjustment 

30 value from 1.25 to 1.0 in NEI 99-02, Appendix F, Table 7.

31

32 The refueling outage is scheduled to be completed during the second quarter of 2011. As the units 

33 will be putting the new AF pumps and associated monitored valves in service during the middle of 

34 a quarter, the device records in CDE will be updated upon entry into MODE 4 ascending for Unit 2 

35 and when the new AF pump and associated monitored valves are placed in service for Unit 1. 

36 However, CDE and the MSPI Basis Document will not be updated until the end of the second 

37 quarter to reflect the new PRA and the new train definitions. 

38

39 The completion of the modification during the middle of a quarter will result in the inability to 

40 implement all of the guidance in NEI 99-02 related to reporting of data in CDE. The goal is to 

41 provide a second quarter MSPI submittal for AF that accurately reflects the actual availability and 

42 reliability of the existing and new AF system configurations and implements the guidance of NEI

43 99-02 as much as reasonable. However, as CDE does not support the submittal of split data and 

44 does not allow PRA model changes mid-quarter, an MSPI result for MS08, Heat Removal 

45 Systems, reflecting second quarter 2011 AF system unavailability and reliability would not be 

46 representative of the new system and would not provide meaningful results. Therefore, 

47 exemptions from NEI 99-02 reporting guidance are requested for Point Beach based upon the 

48 system design changes being implemented in the second quarter of 2011. 

FAQ479

(11-05)
NEI 99-02 [Revision 7]

08/31/2013

D-14

1

2 Resolution: Point Beach may have a one-time exemption from the reporting guidance on 

3 Page 2, Lines 15-23, of NEI 99-02, Revision 6. The 2Q2011 MS08 PI will be characterized 

4 as “Insufficient Data to Calculate PI,” as indicated by:

5

6

7

8 on the NRC’s “ROP Performance Indicators Summary” Web site because (1) the results will not 

9 be representative of the current PRA and MSPI Basis Document for that quarter and (2) the data 

10 reflecting the actual plant configuration cannot be processed in CDE software. A comment shall 

11 be added to the CDE submittal file explaining the basis for this characterization, which will 

12 include that the modification was installed mid-quarter, CDE is not capable of processing a “data 

13 split” within the same quarter, CDE does not allow mid-quarter PRA model changes, and an MSPI 

14 result for MS08, Heat Removal Systems, reflecting 2Q2011 AF system unavailability and 

15 reliability would not be representative of the new system nor provide meaningful results.

16

17 AF unavailability and reliability data will be reported to the NRC for 2Q2011. The data will 

18 be used for assessing MS08 data for subsequent quarters.

19

20 Because the new pumps and associated monitored valves will be similar to the existing pumps and 

21 associated monitored valves, Point Beach will determine the baseline unavailability data 

22 (nominally 2002-2004) for the new trains by using the unavailability data for the existing trains, 

23 removing the unavailability that was reported when the other unit was in an outage, and averaging 

24 the data over three years. With respect to historical unavailability data, because the new pumps 

25 and associated monitored valves will be similar to the existing pumps and associated monitored 

26 valves, Point Beach will determine the past three years of historical unavailability for the new 

27 trains by using the data for the existing trains, removing the unavailability taken when the other 

28 unit was in an outage, and averaging the data over three years. Point Beach will also update the 

29 MSPI basis document at the end of 2Q2011 to reflect the modification’s impact on system and 

30 train boundaries.

31

32 With respect to reliability data, Point Beach will update the device records and associated 

33 reliability data in CDE at the time the new pumps and associated monitored valves are placed in 

34 service and will update the MSPI basis document at the end of 2Q2011 to reflect the 

35 modification’s impact on monitored component boundaries. The most recent three years of 

36 reliability data for the currently installed pumps will serve as the reliability data for the new pumps 

37 because of their similar design and function

38

39 It is acceptable to revise the HRS/MDP Standby generic common cause failure adjustment value 

40 from 1.25 to 1.00, which will take effect upon the implementation of the modification, in NEI 99-

41 02, Revision 6, Appendix F, Table 7.

42

FAQ479

(11-05)

FAQ479

(11-05)
NEI 99-02 [Revision 7]

08/31/2013

D-15

1 Fort Calhoun

2

3 Issue: Under normal circumstances and in accordance with the Fort Calhoun Radiological 

4 Emergency Response Plan, section E, sirens are tested bi-weekly for functionality via Emergency 

5 Planning Test (EPT) EPT-1 (Alert Notification System Silent Test), quarterly via EPT-2 (Alert 

6 Notification System Growl Test), and annually via EPT-3 (Alert Notification System Complete 

7 Cycle Test). 

8

9 Current flooding along the Missouri River and within the 10-mile EPZ has resulted in several 

10 sirens being [deliberately] disabled by disconnecting AC power due to rising river levels. These 

11 flooding conditions do not only affect the operability/functionality of the sirens, but have also 

12 resulted in power disconnections for and evacuation of residents in the areas for which these sirens 

13 provide coverage. Additionally, backup route-alerting is still available for any remaining affected 

14 residents as verified through local and state governments.

15

16 In accordance with NEI 99-02, Revision 6 (Regulatory Assessment Performance Indicator 

17 Guideline), page 57 concerning siren testing states “Regularly scheduled tests missed for reasons 

18 other than siren unavailability (e.g., out of service for planned maintenance or repair) should be 

19 considered non opportunities.” This evaluation and exemption was applied to the sirens that have 

20 been removed from service due to flooding. 

21

22 These sirens were removed from service intentionally, and will remain out of service for an 

23 extended period of time; therefore they will not be counted in the performance indicator for Alert 

24 and Notification System Reliability. For all EPTs conducted on sirens during the time period 

25 when power has been removed from the siren due to flooding, the number of sirens tested will only 

26 be those that have normal power available. 

27

28 Resolution: If sirens are not available for operation due to high flood water conditions, and the 

29 area is deemed inaccessible and uninhabitable by State and/or Local agencies, the siren(s) in 

30 question will not be counted in the numerator or denominator of the Performance Indicator for that 

31 testing period.

32

33

34

35 [This page left intentionally blank.]

FAQ485

(11-11)
NEI 99-02 [Revision 7]

08/31/2013

E-1

1 APPENDIX E

2 FREQUENTLY ASKED QUESTIONS

3

4 Purpose

5

6 The Frequently Asked Question (FAQ) process is the mechanism for resolving interpretation 

7 issues with NEI 99-02. FAQs and responses are posted on the NRC Website 

8 (www.nrc.gov/NRR/OVERSIGHT/ASSESS/index.html) and INPO’s Consolidated Data Entry 

9 webpage. They Approved FAQs represent NRC approved interpretations of performance 

10 indicator guidance and should be treated as an extension of NEI 99-02. 

11

12 There are several reasons for submitting an FAQ:

13

14 1. To clarify the guidance when the licensee and NRC regional staff do not agree on the 

15 meaning or how to applyapplication of the guidance to a particular situation. 

16 2. To provide guidance for a class of plants whose design or system functions differ from that 

17 described in the guidance.

18 3. To request an exemption from the guidance for plant-specific circumstances, such as design 

19 features, procedures, or unique conditions.

20 4. When recommended in NEI 99-02, such as in response to unplanned power changes due to 

21 environmental conditions.

22

23 Proposed changes to the guidance are not a reason to submit an FAQ. A formal process exists

24 for changing the guidance, which usually includes analysis and piloting before being 

25 implemented. White papers that are submitted for guidance changes, if approved by the 

26 Industry/NRC working group, are converted into an FAQ for use and inclusion in the next 

27 revision of NEI 99-02. In some circumstances, while reviewing an FAQ, the Industry/NRC 

28 working group may determine that a change in the guidance is necessary.

29

30 The FAQ process is not the arena in which to resolve interpretation issues with any other NRC 

31 regulatory documents. In addition, the FAQ process is not used to make licensing or engineering 

32 decisions.

33

34 Process

35

36 1. Issue identification

37

38 Either the licensee or the NRC may identify the need for an interpretation of the guidance. 

39 FAQs should be submitted as soon as possible, but generally no later than the quarter 

40 following identification of the issue requiring interpretation. Once the licensee and 

41 resident inspector or region have identified an issue on which there is either disagreement 

42 or where both parties agree that guidance clarification is necessary, an FAQ should be 

43 submitted as soon as possible. The FAQ should be provided to the ROP Task Force by the next 

44 scheduled ROP Task Force meeting, if practical, but no later than its subsequent meeting. The 

45 ROP Task Force should submit the FAQ to the ROP Working Group by the following month’s 

46 meeting, if practical. If both the resident inspector and licensee agree that the issue is complex 

47 and more time is required (e.g., to complete a causal evaluation, obtain a vendor report, perform 

FAQ

Whitepaper 

May 2013
NEI 99-02 [Revision 7]

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E-2

1 a simulator run, etc.), the FAQ submittal may be delayed until the issue is sufficiently 

2 understood.once the licensee and resident inspector or region has identified an issue on which 

3 there is not agreement.

4

5 The licensee submits the FAQ by email to pihelp@nei.org. The email should include “FAQ” as 

6 part of the subject line and should provide the name and phone number of a contact person. If the 

7 licensee is not sure how to interpret a situation and the quarterly report is due, an FAQ should be 

8 submitted and a comment in the PI comment field would be appropriate. If the licensee has 

9 reasonable confidence that its position will be accepted, it is under no obligation to report the 

10 information (e.g., unavailability). Conversely, if the licensee is not confident that it will succeed 

11 in its FAQ, the information should be included in the submitted data. In either case, the report 

12 can be amended, if required, at a later date. 

13

14 2. Expeditiousness, Completeness and Factual Agreement

15

16 In order for the performance indicators to be a timely element of the ROP, it is incumbent on 

17 NRC and the licensee to work expeditiously and cooperatively, sharing concerns, questions and 

18 data in order that the issue can be resolved quickly. Where possible, agreement should be 

19 achieved prior to submittal of the FAQ on the factual elements of the FAQ, e.g., the engineering, 

20 maintenance, or operational situation. The FAQ must describe the situation clearly and 

21 concisely and must be complete and accurate in all respects. If agreement cannot be reached on 

22 the wording of the FAQ, NRC will provide its alternate view to the licensee for inclusion in the 

23 FAQ.

24

25 3. FAQ Format

26

27 See Figure E-1 for the format for submitting an FAQ. It is important to provide contact 

28 information and whether the FAQ should be considered generic to all plants, or only specific to 

29 the licensee submitting the FAQ. In most cases the FAQ will become effective as soon as 

30 possible; however, the licensee can recommend an effective date. The question section of the 

31 FAQ includes the specific wording of the guidance which needs to be interpreted, the 

32 circumstances involved, and the specific question. All relevant information should be included 

33 and should be as complete as possible. Incomplete or omitted information will delay the 

34 resolution of the FAQ. The licensee also provides a proposed response to the FAQ. The 

35 response should answer the question and provide the reasoning for the answer. (There must not 

36 be any new information presented in the response that was not already discussed in the question.) 

37 The NRC may or may not opt to request that the FAQ include an alternative response. Finally, 

38 the FAQ may include proposed wording to revise the guidance in the next revision.

39

40 4. Screening of licensee FAQs

41

42 Typically, FAQs are forwarded to and reviewed by NEI. New FAQs should be submitted at least 

43 one week prior to the ROP meeting, revisions to previously accepted FAQs can be submitted at 

44 any time. NEI may request that the FAQ be revised. After acceptance by NEI, the FAQ is 

45 reviewed by the industry’s ROP Task Force (Formerly SPATF). Additional wording may be 

46 suggested to the licensee. In some cases, the task force may believe the FAQ is without merit 

47 and may recommend that the FAQ be withdrawn. An accepted FAQ is entered in the FAQ log

48 which includes all unresolved FAQs. All open FAQs and the log are forwarded to NRC and the 
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1 task force members approximately one week prior to the (approximately) monthly ROP meeting 

2 between the task force and NRC or as soon as reasonably practical.

3

4 5. Public Meeting Discussions of FAQs

5

6 The FAQ log is reviewed at each monthly ROP meeting, and the Industry/NRC working group is 

7 responsible for achieving a consensus response, if possible. In most cases, the licensee is 

8 expected to present and explain the details of its FAQ. Licensee and resident/regional NRC staff 

9 are usually available (at the meeting or by teleconferencing) to respond to questions posed by the 

10 Industry/NRC) working group. The new FAQ is introduced by the licensee to ensure the 

11 working group understands the issues, but discussion of the FAQ may be referred to the next 

12 meeting if participants have not had an opportunity to research the issues involved. The FAQ 

13 will be discussed in detail, until all of the facts have been resolved and consensus has been 

14 reached on the response. The FAQ will then be considered “Tentatively Approved,” and 

15 typically one additional month will be allowed for reconsideration. At the following meeting the 

16 FAQ becomes “Final.” Typically, an FAQ is introduced one month; the facts are discussed for 

17 two or three months and a tentative decision reached; and it goes final the following month.

18

19 In cases where minor changes are necessary after final or tentative approval has occurred, the 

20 changes can be made if representatives from both industry and NRC concur on the final wording 

21 prior to FAQ issuance on the NRC website. 

22

23 In some limited cases (involving an issue with no contention and where exigent resolution is 

24 needed), it is possible for the ROP working group to reach immediate consensus and take the 

25 FAQ to Final; however, this will generally be an exception.

26

27 6. Withdrawal of FAQs

28

29 A licensee may withdraw an FAQ after it has been accepted by the joint ROP Working Group. 

30 Withdrawals must occur during an ROP Working Group monthly (approximately) meeting. 

31 However, the ROP Working Group should further discuss and decide if a guidance issue exists in 

32 NEI 99-02 that requires additional clarification. If additional clarification is needed then the 

33 original FAQ should be revised to become a generic FAQ. In many cases, there are lessons 

34 learned from the resources expended by the ROP Working Group that should be captured. In 

35 those cases, the FAQ will be entered in the FAQ log as a generic FAQ. If there is disagreement 

36 between the staff and industry, both positions should be articulated in the FAQ. These 

37 withdrawn FAQs should be considered as historical and are not considered to be part of NEI 99-

38 02. Although they do not establish precedenceprecedent, they do offer insights into perspectives 

39 of both industry and NRC staff and, as such, can inform future decisions to submit an FAQ.

40

41 7. Appeal Process

42

43 Once the facts and circumstances are agreed upon, if consensus cannot be reached after two 

44 consecutive working group meetings, the FAQ will be referred to the NRC Director of the 

45 Division of Inspection & Regional Support (DIRS). The director will conduct a public meeting 

46 at which both the licensee and NRC will present their positions as well as respond to any 

47 questions from the director. The director then will make the determination. Any additional 

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1 appeal to higher management is outside of this process and is solely at the licensee’s discretion 

2 and initiative. 

3

4 8. Promulgation and Effective Date of FAQs

5

6 Once approved by NRC, the accepted response will be posted on the NRC Website and is treated 

7 as an extension of this guideline.

8

9 For the licensee that submitted the FAQ, the FAQ is effective when the event occurred. Unless 

10 otherwise directed in an FAQ response, for other licensees, FAQs are to be applied to the data 

11 submittal for the quarter following the one in which the FAQ was posted and beyond. For 

example, an FAQ with a posting date of 9/30/2009 would apply to 4th 12 quarter 2009 PI data, 

13 submitted in January 2010 and subsequent data submittals. However, an FAQ with a posting 

14 date of 10/1/2009 would apply on a forward fit basis to first quarter 2010 PI data submitted in 

15 April 2010. Licensees are encouraged to check the NRC Web site frequently, particularly at the 

16 end of the reporting period, for FAQs that may have applicability for their sites.

17

18 At the time of a revision of NEI 99-02, active FAQs will be reviewed for inclusion in the text. 

19 These FAQs will then be placed in an “archived” file. Archived FAQs are for historical 

20 purposes and are not considered to be part of NEI 99-02.

21
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1 FAQ TEMPLATE

2

3

4 Plant: _________________________

5 Date of Event: _________________________

6 Submittal Date: _________________________

7 Licensee Contact: _________________________ Tel/email: __________________

8 NRC Contact: _________________________ Tel/email: __________________

9

10 Performance Indicator: 

11

12 Site-Specific FAQ (see Appendix D)? (__)Yes or (__) No

13

14 FAQ requested to become effective (__) when approved or (other date) ____________

15

16 Question Section

17 NEI 99-02 Guidance needing interpretation (include page and line citation):

18

19

20 Event or circumstances requiring guidance interpretation:

21

22

23 If licensee and NRC resident/region do not agree on the facts and circumstances, explain:

24

25

26 Potentially relevant FAQs:

27

28

29 Response Section

30 Proposed Resolution of FAQ:

31

32

33 If appropriate, provide proposed rewording of guidance for inclusion in next revision:

34

35

36 PRA update required to implement this FAQ?

37

38 MSPI Basis Document update required to implement this FAQ?

39

40

41

42

43

44 Figure E-1

45

46 [This page left intentionally blank.]

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1 APPENDIX F

2 METHODOLOGIES FOR COMPUTING THE UNAVAILABILITY INDEX,

3 THE UNRELIABILITY INDEX AND COMPONENT PERFORMANCE LIMITS

4

5 This appendix provides the details of three calculations: the System Unavailability Index, the 

6 System Unreliability Index, and component performance limits.

7

8 F 1. SYSTEM UNAVAILABILITY INDEX (UAI) DUE TO TRAIN UNAVAILABILITY

9 Unavailability is monitored at the train/segment level for the purpose of calculating UAI. The 

10 process for calculation of the System Unavailability Index has three major steps:

11 • Identification of system trains/segments

12 • Collection of plant data

13 • Calculation of UAI

14 The first of these steps is performed for the initial setup of the index calculation (and if there are 

15 significant changes to plant configuration or at the licensee’s discretion. The second step has 

16 some parts that are performed initially and then only performed again when a revision to the 

17 plant specific-specific PRA is made or changes are made to the normal preventive maintenance 

18 practices. Other parts of the calculation are performed periodically to obtain the data elements 

19 reported to the NRC. This section provides the detailed guidance for the calculation of UAI.

20

21 F 1.1. IDENTIFICATION OF SYSTEM TRAINS/SEGMENTS

22 The identification of system trains/segments is accomplished in two steps:

23 • Determine the system boundaries

24 • Identify the trains/segments within the system boundary

25 The use of simplified P&IDs can be used to document the results of this step and will also 

26 facilitate the completion of the directions in section F2.1.1 later in this document.

27

28 F 1.1.1. MONITORED FUNCTIONS AND SYSTEM BOUNDARIES

29 The first step in the identification of system trains is to define the monitored functions and 

30 system boundaries. Include all components within the system boundary that are required to 

31 satisfy the monitored functions of the system.

32

33 The cooling water support system is a system that is calculated separately in MSPIError! 

34 Bookmark not defined.; however, trains/segments of other support systems (e.g., HVAC room 

35 coolers, DC power, instrument air, etc.) that may be needed to satisfy a monitored function are 

36 not monitored in MSPI for unavailability if the components within those trains/segments are not 

37 included within the boundary of a monitored train/segment or the supported system.

38

39 Additional guidance for determining the impact on availability and unreliability from 

40 unmonitored component failures can be found in Section F.2.2.2.

41

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1 The monitored functions of the system are those functions in section F5 of this appendix that 

2 have been determined to be risk-significant functions per NUMARC 93-01 and are reflected in 

3 the PRAError! Bookmark not defined.. If none of the functions listed in section fiveSection F5

4 for a system are determined to be risk significant, then:

5

6 • If only one function is listed for a system, then this function is the monitored function (for 

7 example, CE NSSS designs use the Containment Spray system for RHR but this system is 

8 redundant to the containment coolers and may not be risk significant. The Containment Spray 

9 system would be monitored.)

10 • If multiple functions are listed for a system, the most risk significant function is the 

11 monitored function for the system. Use the Birnbaum Importance values to determine which 

12 function is most risk significant.

13

14 For fluid systems the boundary should extend from and include the water source (e.g., tanks, 

15 sumps, etc.) to the injection point (e.g., RCS, Steam Generators). For example, high-pressure 

16 injection may have both an injection mode with suction from the refueling water storage tank 

17 and a recirculation mode with suction from the containment sump. For Emergency AC systems, 

18 the system consists of all class 1E generators at the station (for multi-unit sites, see Unit Crosstie 

19 Capability below).

20

21 Additional system specific guidance on system boundaries can be found in section Section 5 

22 titled “Additional Guidance for Specific Systems” at the end of this appendix.

23

24 Some common conditions that may occur are discussed below.

25

26 System Interface Boundaries

27 For water connections from systems that provide cooling water to a single component in a 

28 monitored system, the final connecting valve is included in the boundary of the frontline system 

29 rather than the cooling water system. For example, for service water that provides cooling to 

30 support an AFW pump, only the final valve in the service water system that supplies the cooling 

31 water to the AFW system is included in the AFW system scope. This same valve is not included 

32 in the cooling water support system scope. The equivalent valve in the return path, if present, 

33 will also be included in the frontline system boundary.

34

35 The impact of room cooling or other related HVAC supports is excluded from the system/train 

36 boundary. Unavailability of these systems/components is not counted as unavailability of a 

37 monitored system/train. The only exception to this areis EDG ventilation systems that have a 

38 shared function of both providing room cooling/ventilation that also provide a flow path for EDG 

39 combustion or exhaust. In these cases, unavailability of components that result in unavailability 

40 of an EDG due to not having a combustion or exhaust flow path is included in EDG 

41 unavailability.

42

43 For control functions and electrical power, the system/train boundary includes all system 

44 dedicated relays, controllers, and contactors that support the monitored system functions, and all 

45 dedicated voltage supply breakers (both motive and control power) and their associated control 

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1 circuits (relay contacts for normally auto actuated components, control board switches for 

2 normally operator actuated components). If a relay, breaker, or contactor exists solely to support 

3 the operation of a monitored train/segment, it should be considered part of the train’s/segment’s 

4 boundary. If a relay, breaker, or contactor supports multiple trains/segments, it should not be 

5 considered as part of the monitored train’s/segment’s boundary. For turbine driven pumps, the 

6 system/train boundary includes the associated control system (relay contacts for normally auto 

7 actuated components, control board switches for normally operator actuated components), the 

8 control valve, and its voltage supply breaker. Failure or unavailability of components outside of 

9 the system/train boundary is not counted as unavailability of the impacted system/train.

10

11 Water Sources and Inventory

12 Water tanks are not considered to be monitored components. As such, they do not contribute to 

13 URI. However, since tanks can be in the train/segment boundary, periods of insufficient water 

14 inventory contribute to UAI if they result in loss of the monitored train/segment function for the 

15 required mission time. If additional water sources are required to satisfy train/segment mission 

16 times, only the connecting active valve from the additional water source is considered as a 

17 monitored component for calculating UAIURI. If there are valves in the primary water source 

18 that must change state to permit use of the additional water source, these valves are considered 

19 monitored and should be included in UAI for the system.

20

21 Unit Cross-Tie Capability

22 At multiple unit sites cross ties between systems frequently exist between units. For example at a 

23 two unit site, the Unit 1 Emergency Diesel Generators may be able to be connected to the Unit 2 

24 electrical bus through cross tie breakers. In this case the Unit 1 EAC system boundary would end 

25 at the cross tie breaker in Unit 1 that is closed to establish the cross-tie. The similar breaker in 

26 Unit 2 would be the system boundary for the Unit 2 EAC system. Similarly, for fluid systems the 

27 fluid system boundary would end at the valve that is opened to establish the cross-tie.

28

29 Common Components

30 Some components in a system may be common to more than one system/train/segment, in which 

31 case the unavailability of a common component is included in all affected 

32 systems/trains/segments. 

33

34 F 1.1.2. Identification of Trains within the System

35 Each monitored system shall then be divided into trains/segments to facilitate the monitoring of 

36 unavailability.

37

38 A train consists of a group of components that together provide the monitored functions of the 

39 system described in the “additional guidance for specific mitigating systems”. The number of 

40 trains in a system is generally determined as follows:

41

42 • For systems that provide cooling of fluids, the number of trains is determined by the number 

43 of parallel heat exchangers, or the number of parallel pumps, or the minimum number of 

44 parallel flow paths, whichever is fewer.

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1 • For emergency AC power systems the number of trains is the number of class 1E emergency 

2 (diesel, gas turbine, or hydroelectric) generators at the station that are installed to power 

3 shutdown loads in the event of a loss of off-site power. (For example, this does not include 

4 the diesel generator dedicated to the BWR HPCS system, which is included in the scope of 

5 the HPCS system.)

6 Some components or flow paths may be included in the scope of more than one train. For 

7 example, one set of flow regulating valves and isolation valves in a three-pump, two-steam 

8 generator system are included in the motor-driven pump train with which they are electrically 

9 associated, but they are also included (along with the redundant set of valves) in the turbine10 driven pump train. In these instances, the effects of unavailability of the valves should be 

11 reported in all affected trains. Similarly, when two trains provide flow to a common header, the 

12 effect of isolation or flow regulating valve failures in paths connected to the header should be 

13 considered in both trains.

14

15 Additional system specific guidance on train definition can be found in section Section F5 titled 

16 “Additional Guidance for Specific Systems” at the end of this appendix.

17 Additional guidance is provided below for the following specific circumstances that are 

18 commonly encountered:

19 • Cooling Water Support Systems and Trains

20 • Swing Trains and Components Shared Between Units

21 • Maintenance Trains and Installed Spares

22 • Trains or Segments that Cannot Be Removed from Service.

23

24 Cooling Water Support Systems and Trains

25 The cooling water function is typically accomplished by multiple systems, such as service water 

26 and component cooling water. A separate value for UAI will be calculated for each of the 

27 systems in this indicator and then they will be added together to calculate an overall UAI value.

28

29 In addition, cooling water systems are frequently not configured in discrete trains. In this case, 

30 the system should be divided into logical segments and each segment treated as a train. This 

31 approach is also valid for other fluid systems that are not configured in obvious trains. The way 

32 these functions are modeled in the plant-specific PRA will determine a logical approach for 

33 train/segment determination. For example, if the PRA modeled separate pump and line segments 

34 (such as suction and discharge headers), then the number of pumps and line segments would be 

35 the number of trains. 

36

37 Unit Swing trains and components shared between units

38 Swing trains/components are trains/components that can be aligned to any unit. To be credited 

39 as such, their swing capability must be modeled in the PRA to provide an appropriate Fussell40 Vesely value.

41

42 Maintenance Trains and Installed Spares

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1 Some power plants have systems with extra trains to allow preventive maintenance to be 

2 carried out with the unit at power without impacting the monitored function of the system. 

3 That is, one of the remaining trains may fail, but the system can still perform its monitored

4 function. To be a maintenance train, a train must not be needed to perform the system’s 

5 monitored function.

6

7 An "installed spare" is a component (or set of components) that is used as a replacement for other 

8 equipment to allow for the removal of equipment from service for preventive or corrective 

9 maintenance without impacting the number operability of trains available to achieve the 

10 monitored function of the system. To be an "installed spare," a component must not be needed 

11 for any train of the system to perform the monitored function. A typical installed spare 

12 configuration is a two train system with a third pump that can be aligned to either train (both 

13 from a power and flow perspective), but is normally not aligned and when it is not aligned 

14 receives no auto start signal. In a two train system where each train has two 100% capacity 

15 pumps that are both normally aligned, the pumps are not considered installed spares, but are 

16 redundant components within that train.

17

18 Unavailability of an installed spare is not monitored unless the system is monitored in segments, 

19 rather than trains. Trains in a system with an installed spare are not considered to be unavailable 

20 when the installed spare is aligned to that train. In the example above, a train would be 

21 considered to be unavailable if neither the normal component nor the spare component is aligned 

22 to the train.

23

24 Trains or Segments that Cannot Be Removed from Service

25 In some normally operating systems (e.g. Cooling Water Systems), there may exist trains or 

26 segments of the system that cannot physically be removed from service while the plant is 

27 operating at power for the following reasons:

28 • Directly causes a plant trip

29 • Procedures direct a plant trip

30 • Technical Specifications requires immediate shutdown (LCO 3.0.3)

31

32 These should be documented in the Basis Document and not included in unavailability 

33 monitoring. 

34

35 F 1.2. Collection of Plant Data

36 Plant data for the UAI portion of the index includes:

37

38 • Actual train total unavailability (planned and unplanned) data for the most recent 12 quarter 

39 period collected on a quarterly basis,

40 • Plant specific-specific baseline planned unavailability, and

41 • Generic baseline unplanned unavailability.

42

43 Each of these data inputs to UAI will be discussed in the following sections.

44

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1 F 1.2.1. ACTUAL TRAIN/SEGMENT UNAVAILABILITY

2 The Consolidated Data Entry (CDE) inputs for this parameter are Train Planned Unavailable 

3 Hours and Train Unplanned Unavailable Hours. Critical hours are derived from reactor startup 

4 and shutdown occurrences. The actual calculation of Train Unavailability is performed by CDE.

5

6 Train/Segment Unavailability: Train/Segment unavailability is the ratio of the hours the 

7 train/segment was unavailable to perform its monitored functions due to planned or unplanned 

8 maintenance or test during the previous 12 quarters while critical to the number of critical hours 

9 during the previous 12 quarters. 

10

11 Train/Segment unavailable hours: The hours the train/segment was not able to perform its 

12 monitored function while critical. Fault exposure hours are not included; unavailable hours are 

13 counted only for the time required to recover the train’s/segment’s monitored functions. In all 

14 cases, a train/segment that is considered to be OPERABLE is also considered to be available. 

15 Trains/segments that are not OPERABLE must be returned to service in order to be considered 

16 available. Unavailability must be by train/segment; do not use average unavailability for each 

17 train/segment because trains/segments may have unequal risk weights.

18

19 Return to Service: Return to service is the transition from unavailable to available. A 

20 train/segment is “returned to service” when the following conditions are met: clearance tags have 

21 been removed, the train/segment has been aligned and prepared for operation, (e.g., valve line-up 

22 complete, system filled and vented), further adjustment of associated equipment is not required 

23 or expected as the result of the unavailability period, and operators concur that the train/segment

24 is able to perform its expected functions. For standby equipment, automatic functions are 

25 aligned or can be promptly restored by an operator consistent with the requirements for crediting 

26 operator recovery stated later in this section.

27

28 Planned unavailable hours: These hours include time a train or segment is removed from service 

29 for a reason other than equipment failure or human error. Examples of activities included in 

30 planned unavailable hours are preventive maintenance, testing, equipment modification, or any 

31 other time equipment is electively removed from service to correct a degraded condition that had 

32 not resulted in loss of function. Based on the plant history of previous three years, planned 

33 baseline hours for functional equipment that is electively removed from service but could not 

34 be planned in advance can be estimated and the basis documented. When used in the calculation 

35 of UAI, if the planned unavailable hours are less than the baseline planned unavailable hours, the 

36 planned unavailable hours will be set equal to the baseline value.

37

38 Unplanned unavailable hours: These hours include elapsed time between the discovery and the 

39 restoration to service of an equipment failure or human error (such as a misalignment) that 

40 makes the train/segment unavailable. Time of discovery of a failed monitored component is 

41 when the licensee determines that a failure has occurred or when an evaluation determines that 

42 the train would not have been able to perform its monitored function(s). In any case where a 

43 monitored component has been declared inoperable due to a degraded condition, if the 

44 component is considered available, there must be a documented basis for that determination, 

45 otherwise a failure will be assumed and unplanned unavailability would accrue. If the component 

46 is degraded but considered operable, timeliness of completing additional evaluations would be 

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1 addressed through the inspection process. Unavailable hours to correct discovered conditions 

2 that render a monitored component train/segment incapable of performing its monitored function 

3 are counted as unplanned unavailable hours. An example of this is a condition discovered by an 

4 operator on rounds, such as an obvious oil leak, that was determined to have resulted in the 

5 equipment being non-functional even though no demand or failure actually occurred. 

6 Unavailability due to mis-positioning of components that renders a train incapable of performing 

7 its monitored functions is included in unplanned unavailability for the time required to recover 

8 the monitored function.

9

10 No Cascading of Unavailability: The failure or unavailability of an SSC that is not within the 

11 boundary of the monitored MSPIError! Bookmark not defined. system that it supports does 

12 not cause the supported monitored system to accrue unavailability. Although such a failure or 

13 condition may require a monitored train or segment of the supported system to be declared 

14 inoperable, the monitored train or segment of the supported system would not accrue 

15 unavailability. If the monitored component of the supported system is rendered non-functional 

16 through tag out or physical plant conditions (other than as discussed below), then unavailable 

17 time should be accrued for the monitored train or segment of the supported system. Otherwise, 

18 unavailability is not accrued.

19

20 Plants will sometimes disable the autostart of a supported monitored system when its support 

21 system is out of service. For example, a diesel generator may have the start function inhibited 

22 when the service water system that provides diesel generator cooling is removed from service. 

23 This is done for the purposes of equipment protection. This could be accomplished by putting a 

24 supported system’s monitored train/segmentcomponent in "maintenance" mode or by pulling the 

25 control fuses of the supported component. If no maintenance is being performed on a component 

26 that’s within a supported system’s monitored train/segment, and the supported system’s 

27 train/segment is only unavailable because of a monitored support system being out of service, no 

28 unavailability should be reported for the supported system’s train/segment. If, however, 

29 maintenance is performed on the supported system’s monitored train/segment, then the 

30 unavailability must be counted.

31

32 For example, if an Emergency Service Water train/segment (i.e., a monitored support system 

33 train/segment) is under clearanceunavailable, and the autostart of the associated High 

34 Pressure Safety Injection (HPSI) pump (a monitored supported system) is disabled, there is no 

35 unavailability to be reported for the HPSI pump; however, the ESW train/segment does accrue 

36 unavailability. If a maintenance task to collect a lube oil sample is performed and it can be 

37 performed with no additional tag out, no unavailability has to be reported for the HPSI pump. If 

38 however, the sample required an additional tag out that would make the HPSI pump unavailable, 

39 then the time that the additional tag out was in place must be reported as planned unavailable 

40 hours for the HPSI pump.

41

42 Additional guidance on the following topics for counting train unavailable hours is provided 

43 below.

44 • Short Duration Unavailability 

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1 • Credit for Operator Recovery Actions to Restore the Monitored Function

2

3 Short Duration Unavailability

4 Trains are generally considered to be available during periodic system or equipment 

5 realignments to swap components or flow paths as part of normal operations. Evolutions or 

6 surveillance tests that result in less than 15 minutes of unavailable hours per train/segment at 

7 a time need not be counted as unavailable hours. Licensees should compile a list of surveillances 

8 or evolutions that meet this criterion and have it available for inspector review. The intent is to 

9 minimize unnecessary burden of data collection, documentation, and verification because these 

10 short durations have insignificant risk impact.

11

12 Credit for Operator Recovery Actions to Restore the Monitored Functions

13

14 1. During testing or, operational alignment or return to service:

15

16 Unavailability of a monitored function during testing, or operational alignment or return to 

17 service need not be included if the test or operational alignment configuration is 

18 automatically overridden by a valid starting signal, or the function can be promptly restored 

either by an operator in the control room or by a designated operator1 19 stationed locally for 

that purpose. Restoration actions must be contained in a written procedure2 20 , must be 

21 uncomplicated (a single action or a few simple actions), must be capable of being restored in 

22 time to satisfy PRA success criteria, and must not require diagnosis or repair. Credit for a 

23 designated local operator can be taken only if (s)hethe operator is positioned at the proper 

24 location throughout the duration of the test or operational alignment for the purpose of 

25 restoration of the train should a valid demand occur. The intent of this paragraph is to allow 

26 licensees to take credit for restoration actions that are virtually certain to be successful (i.e., 

27 probability nearly equal to 1) during accident conditions.

28

29 The individual performing the restoration function can be the person conducting the test or 

30 operational alignment and must be in communication with the control room. Credit can also 

31 be taken for an operator in the main control room provided (s)hethe operator is in close 

32 proximity to restore the equipment when needed. Normal staffing for the test or operational 

33 alignment may satisfy the requirement for a dedicated designated operator, depending on 

34 work assignments. In all cases, the staffing must be considered in advance and an operator 

35 identified to perform the restoration actions independent of other control room actions that 

36 may be required.

37

38 Under stressful, chaotic conditions, otherwise simple multiple actions may not be 

39 accomplished with the virtual certainty called for by the guidance (e.g., lifting test leads and 

40 landing wires; or clearing tags). In addition, some manual operations of systems designed to 

41 operate automatically, such as manually controlling HPCI turbine to establish and control 

42 injection flow, are not virtually certain to be successful. These situations should be resolved 

43 on a case-by-case basis through the FAQ process.

 1

“Operator” in this circumstance refers to any plant personnel qualified and designated to perform the restoration function. 2

Including restoration steps in an approved test procedure.

FAQ472

(09-08)

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1

2 2. During Maintenancemaintenance

3

4 Unavailability of a monitored function during maintenance need not be included if the 

5 monitored function can be promptly restored either by an operator in the control room or by a 

6 designated operator (see footnote 1 below) stationed locally for that purpose. Restoration 

7 actions must be contained in an approved procedure, must be uncomplicated (a single 

8 action or a few simple actions), must be capable of being restored in time to satisfy PRA

9 success criteria and must not require diagnosis or repair. Credit for a designated local 

10 operator can be taken only if (s)hethe operator is positioned at a proper location throughout 

11 the duration of the maintenance activity for the purpose of restoration of the train should a 

12 valid demand occur. The intent of this paragraph is to allow licensees to take credit for 

13 restoration of monitored functions that are virtually certain to be successful (i.e., probability 

14 nearly equal to 1).

15

16 The individual performing the restoration function can be the person performing the 

17 maintenance and must be in communication with the control room. Credit can also be taken 

18 for an operator in the main control room provided (s)hethe operator is in close proximity to 

19 restore the equipment when needed. Normal staffing for the maintenance activity may 

satisfy the requirement for a dedicated designated1 20 operator, depending on work 

21 assignments. In all cases, the staffing must be considered in advance and an operator 

22 identified to perform the restoration actions independent of other control room actions that 

23 may be required.

24

25 Under stressful chaotic conditions otherwise simple multiple actions may not be 

26 accomplished with the virtual certainty called for by the guidance (e.g., lifting test leads and 

27 landing wires, or clearing tags). These situations should be resolved on a case-by-case basis 

28 through the FAQ process.

29

30 3. During degraded conditions

31 In accordance with current regulatory guidance, licensees may credit limited operator actions 

32 to determine that degraded equipment remains operable in accordance with Technical 

33 Specifications. If a train/segment is determined to be operable, then it is also available. 

34 Beyond this, no credit is allowed for operator actions during degraded conditions that render 

35 the train/segment unavailable to perform its monitored functions.

36

37 Counting Unavailability when Planned and Unplanned Maintenance are Performed in the Same 

38 Work Window

39

40 All maintenance performed in the work window should be classified with the classification for 

41 which the work window was entered. For example, if the initial work window was caused by 

42 unplanned maintenance then the duration of the entire work window would be classified as 

43 unplanned even if some additional planned maintenance were added that extended the work 

44 window. Another example is if a planned maintenance work window results in adding additional 

45 unplanned work due to a discovered condition during the maintenance, the entire work window 

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1 duration would be classified as planned maintenance. If, however, maintenance is performed on 

2 the monitored component, then the unavailability must be counted.

3

4 For example, if an Emergency Service Water train/segment is under clearance, and the autostart 

5 of the associated High Pressure Safety Injection (HPSI) pump is disabled, there is no 

6 unavailability to be reported for the HPSI pump. If a maintenance task to collect a lube oil 

7 sample is performed and it can be performed with no additional tag out, no unavailability has to 

8 be reported for the HPSI pump. If however, the sample required an additional tag out that would 

9 make the HPSI pump unavailable, then the time that the additional tag out was in place must be 

10 reported as planned unavailable hours for the HPSI pump.

11 

12 F 1.2.2. PLANT PLANT-SPECIFIC BASELINE PLANNED UNAVAILABILITY

13 The initial baseline planned unavailability is based on actual plant-specific values for the period 

14 2002 through 2004. (Plant specific-specific values of the most recent data are used so that the 

15 indicator accurately reflects deviation from expected planned maintenance.) These values are 

16 expected tomay change if the plant maintenance philosophy is substantially changed with 

17 respect to on-line maintenance or preventive maintenance. In these cases, the planned 

18 unavailability baseline value should be adjusted to reflect the current maintenance practices, 

19 including low frequency maintenance evolutions.

20

21 Prior to implementation of an adjustment to the planned unavailability baseline value, the 

22 impact of the adjusted values on all MSPI PRA inputs should be assessed. A change to the 

23 PRA model and associated changes to the MSPI PRA inputs values is required prior to 

24 changing the baseline unavailability if ∆CDF > 1E-8, where:

25 ∆CDFbaseline = ∑(ΔUAi * Birnbaumi)

26 ΔUAi = UAcurrent – UAbaseline for segment i

27 UAcurrent = proposed unavailability (expressed as a probability) to be used as the new 

28 baseline

29 UAbaseline = the base unavailability (expressed as a probability) for 2002 – 2004

30 Birnbaumi = Birnbaum value of segment i

31

32 The following changes are considered a “change in plant maintenance philosophy:”

33 • A change in frequency or scope of a current preventative maintenance activity or 

34 surveillance test.

35 • The addition of a new preventative maintenance activity or surveillance test.

36 • The occurrence of a periodic maintenance activity at a higher or lower frequency during a 

37 three year data window (e.g., a maintenance overhaul that occurs once every 24 months 

38 will occur twice two-thirds of the time and once one-third of the time). If the 

39 unavailability hours required for the additional maintenance activity are included in the 

40 PRA modeled unavailability, the baseline unavailability can be changed without further 

41 assessment.

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(09-07)

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(09-07)

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1 • Planned maintenance activities that occur less than once every three years (e.g., five- or 

2 10-year overhauls). If the unavailability hours required for the additional maintenance 

3 activity are included in the PRA-modeled unavailability, the baseline unavailability can 

4 be changed without further assessment.

5 • The performance of maintenance in response to a condition-based preventive 

6 maintenance activity.

7 • Performance of an on-line modification that has been determined to be consistent with 

8 the unavailability values contained in the PRA in that the PRA includes unavailability 

9 hours for the proposed modification, and current maintenance and testing programs; and 

10 the hours in the MSPI UA baseline do not reflect this total unavailability.

11

12 The following changes are not considered a “change in plant maintenance philosophy:”

13 • The performance of maintenance in response to a degraded condition (even when it is 

14 taken out of service to address the degraded condition) unless this action is in response to 

15 a condition-based preventive maintenance activity.

16 • Planned maintenance activity that exceeds its planned duration.

17 • The performance of an online modification that does not meet the change in plant 

18 maintenance philosophy online modification criterion.

19

20 Note: Condition-based maintenance consists of periodic preventive maintenance tasks or online 

21 monitoring of the health or condition of a component (e.g., vibration analysis, oil analysis, 

22 MOVAT) and predefined acceptance criteria where corrective action is to be taken on exceeding 

23 these criteria. Condition-based maintenance does not include discovery of a degraded condition 

24 as a result of actions that are outside of the maintenance programs.

25

26 Some significant maintenance evolutions, such as EDG overhauls, are performed at an interval 

27 greater than the three year monitoring period (5 or 10 year intervals). The baseline planned 

28 unavailability should be revised as necessary in the basis document during the quarter prior to 

29 the planned maintenance evolution and then removed after twelve quarters. A comment should 

30 be placed in the comment field of the quarterly report to identify a substantial change in planned 

31 unavailability. The comments automatically generated by CDE when PRA coefficients are 

32 changed do not fulfill this requirement. The plant must generate a plant-specific comment that 

33 describes what was changed. The baseline value of planned unavailability is changed at the 

34 discretion of the licensee to ensure the baseline is consistent with the current maintenance 

35 philosophy of the plant. Revised values will be used in the calculation the quarter following the 

36 basis document revision.

37

38 To determine the initial value of planned unavailability:

39

40 1) Record the total train unavailable hours reported under the Reactor Oversight Process for 

41 2002-2004.

42 2) Subtract any fault exposure hours still included in the 2002-2004 period.

43 3) Subtract unplanned unavailable hours. 
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4) Add any on-line overhaul hours1 1 and any other planned unavailability previously excluded 

2 under SSU in accordance with NEI 99-02, but not excluded under the MSPI. Short duration 

3 unavailability, for example, would not be added back in because it is excluded under both 

4 SSU and MSPI.

5 5) Add any planned unavailable hours for functions monitored under MSPI which were not 

6 monitored under SSU in NEI 99-02.

7 6) Subtract any unavailable hours reported when the reactor was not critical.

8 7) Subtract hours cascaded onto monitored systems by support systems. (However, do not 

9 subtract any hours already subtracted in the above steps.)

10 8) Divide the hours derived from steps 1-7 above by the total critical hours during 2002-2004. 

11 This is the baseline planned unavailability.

12 Support cooling planned unavailability baseline data is based on plant specific-specific

13 maintenance rule unavailability for years 2002-2004. Maintenance Rule practices do not 

14 typically differentiate planned from unplanned unavailability. However, best efforts will be made 

15 to differentiate planned and unplanned unavailability during this time period.

16

17 If maintenance practices at a plant have changed since the baseline years (e.g. increased 

18 planned online maintenance due to extended AOTs), then the baseline values should be 

19 adjusted to reflect the current maintenance practices and the basis for the adjustment 

20 documented in the plant’s MSPI Basis Document.

21

22 F 1.2.3. GENERIC BASELINE UNPLANNED UNAVAILABILITY

23 The unplanned unavailability values are contained in Table 1 and remain fixed. They are based 

24 on ROP PI industry data from 1999 through 2001. (Most baseline data used in PIs come from 

25 the 1995-1997 time period. However, in this case, the 1999-2001 ROP data are preferable, 

26 because the ROP data breaks out systems separately. Some of the industry 1995-1997 INPO data 

27 combine systems, such as HPCI and RCIC, and do not include PWR RHR. It is important to 

28 note that the data for the two periods is very similar.)

29

30 Table 1. Historical Unplanned Unavailability Train Values

31 (Based on ROP Industry-wide Data for 1999 through 2001)

SYSTEM UNPLANNED UNAVAILABILITY/TRAIN

EAC * 1.7 E-03

PWR HPSI 6.1 E-04

PWR AFW (TD) 9.1 E-04

PWR AFW (MD) 6.9 E-04

PWR AFW (DieselD) 7.6 E-04

PWR (except CE) RHR 4.2 E-04

CE RHR 1.1 E-03

BWR HPCI** 3.3 E-03

BWR HPCS 5.4 E-04

BWR FWCI Use plant-specific Maintenance Rule data for 2002-2004

 1 Note: The plant-specific PRA should model significant on-line overhaul hours.

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SYSTEM UNPLANNED UNAVAILABILITY/TRAIN

BWR RCIC 2.9 E-03

BWR IC 1.4E-03

BWR RHR 1.2 E-03

Support Cooling Use plant-specific Maintenance Rule data for 2002-2004

1 * Oconee to use EAC plant specific-specific Maintenance Rule data for 2002-2004

2 ** Oyster Creek to use Core Spray plant specific-specific Maintenance Rule data for 

3 2002-2004

4

5 Generic Baseline Unplanned Unavailability for Front Line systems divided into segments for 

6 unavailability monitoring

7 If a front line system is divided into segments rather than trains, the following approach is 

8 followed for determining the generic unplanned unavailability:

9 1. Determine the number of trains used for SSU unavailability reporting that was in use 

10 prior to MSPI.

11 2. Multiply the appropriate value from Table 1 by the number of trains determined in (1).

12 3. Take the result and distribute it among the MSPI segments, such that the sum is equal to 

13 (2) for the whole MSPI system.

14

15 Unplanned unavailability baseline data for the support cooling systems should be developed 

16 from plant specific-specific Maintenance Rule data from the period 2002-2004. Maintenance 

17 Rule practices do not typically differentiate planned from unplanned unavailability. However, 

18 best efforts will be made to differentiate planned and unplanned unavailability during this time 

19 period. NOTE: The sum of planned and unplanned unavailability cannot exceed the total 

20 unavailability.

21

22 F 1.3. CALCULATION OF UAI

23 The specific formula for the calculation of UAI is provided in this section. Each term in the

24 formula will be defined individually and specific guidance provided for the calculation of each 

25 term in the equation. Required inputs to the INPO Consolidated Data Entry (CDE) System will 

26 be identified.

27

28 Calculation of System UAI due to train/segment unavailability is as follows:

∑

=

=

n

j

UAI UAItj

1

29 Eq. 1

30 where the summation is over the number of trains/segments (n) and UAIt is the unavailability 

31 index for a train/segment.

32 Calculation of UAIt for each train/segment due to actual train/segment unavailability is as 

33 follows: 

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( )

max

t BLt

p

UAp t p UA UA

UA

FV UAI CDF − 



 



 =

1 , Eq. 2

2 where:

3 CDFp is the plant-specific Core Damage Frequency,

4 FVUAp is the train/segment-specific Fussell-Vesely value for unavailability,

5 UAP is the plant-specific PRAError! Bookmark not defined. value of unavailability 

6 for the train/segment,

7 UAt is the actual unavailability of train/segment t, defined as:

Critical hours during the previous12 quarters

Unavailable hours(planned and unplanned) during the previous12 quarters while critical 8 UAt =

9

10 and, determined in section 1.2.1

11 UABLt is the historical baseline unavailability value for the train/segment (sum of 

12 planned unavailability determined in section 1.2.2 and unplanned unavailability in 

13 section 1.2.3)

14

15 A method for calculation of the quantities in equation 2 from importance measures calculated 

16 using cutsets from an existing PRA solution is discussed in sections F 1.3.1 through F 1.3.3.

17

18 An alternate approach, based on re-quantification of the PRA model, and calculation of the 

19 importance measures from first principles is also an acceptable method. Guidance on this 

20 alternate method is contained in section F6 of this appendix. A plant using this alternate 

21 approach should use the guidance in section F6 and skip sections F 1.3.1 through F 1.3.3.

22

23 F 1.3.1.TRUNCATION LEVELS

24 The values of importance measures calculated using an existing cutset solution are influenced by 

25 the truncation level of the solution. The truncation level chosen for the solution should be 7 

26 orders of magnitude less than the baseline CDF for the alternative defined in sections F 1.3.2 and 

27 F 1.3.3.

28

29 As an alternative to using this truncation level, the following sensitivity study may be performed 

30 to establish the acceptability of a higher (e.g. 6 orders of magnitude) truncation level.

31

32 1. Solve the model at the truncation level you intend to use (e.g. 6 orders of magnitude 

33 below the baseline CDF).

34 2. Identify the limiting Birnbaum value for each train/component (this is the case 1 

35 value).

36 3. Solve the model again with a truncation 10 times larger (e.g. 5 orders of magnitude 

37 below the baseline CDF).

38 4. Identify the limiting Birnbaum value for each train/component (this is the case 2 value. 

39 For each component with Birnbaum-case 1 greater than 1.0E-06 calculate the ratio 

40 [(Birnbaum-case 2)/(Birnbaum-case 1)].

41 5. If the value for the calculated ratio is greater than 0.8 for all components with Birnbaum42 case 1 value greater than 1.0E-06, then the case 1 truncation level may be used for this 

43 analysis.

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1

2 This process may need to be repeated several times with successively lower truncation levels to 

3 achieve acceptable results.

4

5 F 1.3.2. CALCULATION OF CORE DAMAGE FREQUENCY (CDFP)

6 The Core Damage Frequency is a CDE input value. The required value is the internal events, 

7 average maintenance, at power value. Internal flooding and external events, including 

8 internal fire are not included in this calculated value. In general, aAll inputs to this indicator 

9 from the PRA are calculated from the internal events model only. 

10

11 F 1.3.3. CALCULATION OF [FV/UA]MAX FOR EACH TRAIN

12 FV and UA are separate CDEError! Bookmark not defined. input values. Equation 2 includes 

13 a term that is the ratio of a Fussell-Vesely importance value divided by the related 

14 unavailability or probability. This ratio is calculated for each train/segment in the system and 

15 both the FV and UA are CDE inputs. (It may be recognized that the quantity [FV/UA] 

16 multiplied by the CDF is the Birnbaum importance measure, which is used in section 2.3.3.)

17

18 Calculation of these quantities is generally complex, but in the specific application used here, can 

19 be greatly simplified. 

20

21 The simplifying feature of this application is that only those components (or the associated 

22 basic events) that can make a train unavailable are considered in the performance index. A 

23 simplifying assumption is made that Components components within a train that can each 

24 make the train unavailable are logically equivalent and the ratio FV/UA is a constant value for 

25 any basic event in that train. It can also be shown that for a given component or train represented 

26 by multiple basic events, the ratio of the two values for the component or train is equal to the 

27 ratio of values for any basic event within the train. Or:

= = Constant

p

UAp

UA

FV

UA

FV

be

be 28

29 Thus, the process for determining the value of this ratio for any train/segment is to identify a 

30 basic event that fails the train, determine the probability for the event, determine the associated 

31 FV value for the event and then calculate the ratio.

32

33 The set of basic events to be considered for use in this section will obviously include any test 

34 and maintenance (T&M) events applicable to the train/segment under consideration. Basic 

35 events that represent failure on demand that are logically equivalent to the test and maintenance 

36 events should also be considered. (Note that many PRAs use logic that does not allow T&M 

37 events for multiple trains to appear in the same cutset because this condition is prohibited by 

38 Technical specifications. For PRAs that use this approach, failure on demand events will not be 

39 logically equivalent to the T&M events, and only the T&M events should be considered.) 

40 Failure to run events and valve transfer open/close eventsshould not be considered as they are 

41 often not logically equivalent to test and maintenance events. Use the basic event from this set 

42 that results in the largest ratio (hence the maximum notation on the bracket) to minimize the 

43 effects of truncation on the calculation. If all events for the train/segment have been truncated, 

44 either a lower truncation value or the method provided in section F.6 should be used.

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1

2 Some systems have multiple modes of operation, such as PWR HPSI systems that operate in 

3 injection as well as recirculation modes. In these systems all monitored components are not 

4 logically equivalent; unavailability of the pump fails may fail all operating modes while 

5 unavailability of the sump suction valves only failsmay only fail the recirculation mode. In 

6 cases such as these, if unavailability events exist separately for the components within a train, 

7 the appropriate ratio to use is the maximum.

8

9 F 1.3.4. CORRECTIONS TO FV/UA RATIO

10

11 Treatment of PRA Modeling Asymmetries

12 In systems with rotated normally running pumps (e. g. cooling water systems), the 

13 PRAError! Bookmark not defined. models may assume one pump is always the running 

14 and another is in standby. For example, a service water system may have two 100% capacity 

15 pumps in one train, an A and B pump. In practice the A and B pumps are rotated and each one is 

16 the running pump 50% of the time. In the PRA model however, the A pump is assumed to be 

17 always running and the B pump is always in assumed to be in standby. This will result in one 

18 pump appearing to be more important than the other when they are, in fact, of equal importance. 

19 This asymmetry in importance is driven by the assumption in the PRA, not the design of the 

20 plant.

21

22 In the case where the system is known to be symmetric in importance, for calculation of UAI, the 

23 importance measures for each train, or segment, should be averaged and the average applied to 

24 each train or segment. Care should be taken when applying this method to be sure the system is 

25 actually symmetric.

26

27 If the system is not symmetric and the capability exists to specify a specific alignment in the 

28 PRAError! Bookmark not defined. model, the model should be solved in each specific 

29 alignment and the importance measures for the different alignments combined by a weighted 

30 average based on the estimated time each specific alignment is used in the plant.

31

32 Cooling Water and Service Water System [FV/UA]max Values

33 Component Cooling Water Systems (CCW) and Service Water Systems (SWS) at some nuclear 

34 stations contribute to risk in two ways. First, the systems provide cooling to equipment used for 

35 the mitigation of events and second, the failures (and unavailability) in the systems may also 

36 result in the initiation of an event. The contribution to risk from failures to provide cooling to 

37 other plant equipment is modeled directly through dependencies in the PRA model. The 

38 contribution to risk from failures to provide cooling to other plant equipment is modeled 

39 directly through dependencies in the PRA model. However, the contribution due to event 

40 initiation is treated in four general ways in current PRAs:

41

42 1) The use of linked initiating event fault trees for these systems with the same basic event 

43 names used in the initiator and mitigation trees.

44 2) The use of linked initiating event fault trees for these systems with different basic event 

45 names used in the initiator and mitigation trees.

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1 3) Fault tree solutions are generated for these systems external to the PRA and the calculated 

2 value is used in the PRA as a point estimate

3 4) A point estimate value is generated for the initiator using industry and plant specific-specific

4 event data and used in the PRAError! Bookmark not defined..

5 Each of these methods is discussed below.

6

7 Modeling Method 1

8 If a PRA uses the first modeling option, then the FV values calculated will reflect the total 

9 contribution to risk for a component in the system. No additional correction to the FV values is 

10 required.

11

12 Modeling Methods 2 and 3

13 The corrected ratio may be calculated as described for modeling method 4 or by the method 

14 described below.

15

16 If a linked initiating event fault tree with different basic events used in the initiator and 

17 mitigation trees is the modeling approach taken, or fault tree solutions are generated for these 

18 systems external to the PRA and the calculated value is used in the PRA as a point estimate, then 

19 the corrected ratio is given by:





 















 − = + ∑

=

i

m

m

m n n

m n m n corr FVie

IE q

IE IE

UAc

FVc FV UA

1 ,

, , *

( )

(1) (0) 20 [ / ] .

21

22 In this expression the summation is taken over all system initiators i that involve component n, 

23 where

24 FVc is the Fussell-Vesely for component C as calculated from the PRA Model. This does 

25 not include any contribution from initiating events,

26 UAc is the basic event probability used in computing FVc; i.e. in the system response 

27 models,

28 IEm,n(qn) is the system initiator frequency of initiating event m when the component n

29 unreliability basic event is qn. The event chosen in the initiator tree should represent the 

30 same failure mode for the component as the event chosen for UAc,

31 IEm,n(1) is as above but qn=1,

32 IEm,n(0) is as above but qn=0

33 and

34 FViem is the Fussell-Vesely importance contribution for the initiating event m to the 

35 CDF.

36 Since FV and UA are separate CDE inputs, use UAc and calculate FV from

[ ] FV UAc FV UA corr 37 = * /

38

39 Modeling Method 4

40 If a point estimate value is generated for the initiator using industry and plant specific-specific

41 event data and used in the PRA, then the corrected [FV/UA]MAX for a component C is calculated 

42 from the expression:

43 [FV /UA]MAX = [(FVc + FVie * FVsc)/UAc]
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1

2 Where:

3 FVc is the Fussell-Vesely for CDF for component C as calculated from the PRA Model. 

4 This does not include any contribution from initiating events.

5

6 FVie is the Fussell-Vesely contribution for the initiating event in question (e.g. loss of 

7 service water).

8

9 FVsc is the Fussell-Vesely within the system fault tree only for component C (i.e. the 

10 ratio of the sum of the cut sets in the fault tree solution in which that component appears 

11 to the overall system failure probability). Note that this may require the construction of a 

12 “satellite” system fault tree to arrive at an exact or approximate value for FVsc depending 

13 on the support system fault tree logic.

14

15 UAc is the basic event probability used in computing FVc, i.e., in the system response 

16 models.

17

18 FV and UA are separate CDEError! Bookmark not defined. input values.

19

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1 F 2. SYSTEM UNRELIABILITY INDEX (URI) DUE TO COMPONENT 

2 UNRELIABILITY

3

4 Calculation of the URI is performed in three major steps:

5 • Identification of the monitored components for each system,

6 • Collection of plant data, and

7 • Calculation of the URI.

8 Only the most risk significant components in each system are monitored to minimize the burden 

9 for each utility. It is expected that most, if not all the components identified for monitoring are 

10 already being monitored for failure reporting to INPO and are also monitored in accordance with 

11 the maintenance rule.

12

13 F 2.1. IDENTIFY MONITORED COMPONENTS

14 Monitored Component: A component whose failure to change state or remain running renders 

15 the train incapable of performing its monitored functions. In addition, all pumps and diesels in 

16 the monitored systems are included as monitored components.

17

18 The identification of monitored components involves the use of the system boundaries and 

19 success criteria, identification of the components to be monitored within the system boundary 

20 and the scope definition for each component. Note that the system boundary defined in section 

21 1.1.1 defines the scope of equipment monitored for unavailability. Only selected components 

22 within this boundary are chosen for unreliability monitoring. The first step in identifying these 

23 selected components is to identify the system success criteria.

24

25 F 2.1.1. SUCCESS CRITERIA

26 The system boundaries and monitored functions developed in section F 1.1.1 should be used to 

27 complete the steps in the following section.

28

29 For each system, the monitored functions shall be identified. Success criteria used in the PRA

30 shall then be identified for these functions.

31

32 If the licensee has chosen to use success criteria documented in the plant specific-specific

33 PRA that are different from design basis success criteria, examples of plant specific-specific

34 performance factors that should be used to identify the required capability of the train/system 

35 to meet the monitored functions are provided below.

36

37 • Actuation

38 o Time

39 o Auto/manual

40 o Multiple or sequential

41 • Success requirements

42 o Numbers of components or trains

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1 o Flows

2 o Pressures

3 o Heat exchange rates

4 o Temperatures

5 o Tank water level

6 • Other mission requirements

7 o Run time

8 o State/configuration changes during mission

9 • Accident environment from internal events

10 o Pressure, temperature, humidity

11 • Operational factors

12 o Procedures

13 o Human actions

14 o Training

15 o Available externalities (e.g., power supplies, special equipment, etc.)

16

17 If the licensee has chosen to use design basis success criteria in the PRA, it is not required to 

18 separately document them other than to indicate that is what was used. If success criteria from 

19 the PRA are different from the design basis, then the specific differences from the design basis 

20 success criteria shall be documented in the basis document.

21 If success criteria for a system vary by function or initiator, the most restrictive set will be used 

22 for the MSPI. Success criteria related to ATWS need not be considered.

23 PRAError! Bookmark not defined. analyses (e.g. operator action timing requirements) are 

24 sometimes based on thermal-hydraulic calculations that account for the best estimate physical 

25 capability of a system. These calculations should not be confused with calculations that are 

26 intended to establish system success criteria. For example a pump’s flow input for PRA thermal27 hydraulic calculations may be based on its actual pump curve showing 12,000 gpm at runout 

28 while the design basis minimum flow for the pump is 10,000 gpm. The 10,000 gpm value should 

29 be used for determination of success or failure of the pump for this indicator. This prevents the 

30 scenario of a component or system being operable per Technical Specifications and design basis 

31 requirements but unavailable or failed under this indicator.

32 If the licensee has chosen to use design basis success criteria in the PRA, it is not required to 

33 separately document them other than to indicate that is what was used. If success criteria from 

34 the PRA are different from the design basis, then the specific differences from the design basis 

35 success criteria shall be documented in the basis document.

36 If success criteria for a system vary by function or initiator, the most restrictive set will be used 

37 for the MSPI. Success criteria related to ATWS need not be considered.

38 Examples of plant-specific performance factors that should be used to identify the required 

39 capability of the train/system to meet the monitored functions are provided below.

40

41 • Actuation

42 o Time

43 o Auto/manual

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1 o Multiple or sequential

2 • Success requirements

3 o Numbers of components or trains

4 o Flows

5 o Pressures

6 o Heat exchange rates

7 o Temperatures

8 o Tank water level

9 • Other mission requirements

10 o Run time

11 o State/configuration changes during mission

12 • Accident environment from internal events

13 o Pressure, temperature, humidity

14 • Operational factors

15 o Procedures

16 o Human actions

17 o Training

18 o Available externalities (e.g., power supplies, special equipment, etc.)

19

20 F 2.1.2. SELECTION OF COMPONENTS

21 For unreliability, use the following process for determining those components that should be 

22 monitored. These steps should be applied in the order listed.

23

24 1) INCLUDE all pumps (except EDG fuel oil transfer pumps, which are part of the EDG 

25 super-component) and emergency power generatorsdiesels.

26 2) Identify all AOVs, SOVs, HOVs and MOVs that change state to achieve the monitored

27 functions for the system as potential monitored components. Solenoid and Hydraulic valves 

28 identified for potential monitoring are only those in the process flow path of a fluid system. 

29 Solenoid valves that provide air to AOVs are considered part of the AOV. Hydraulic valves 

30 that are control valves for turbine driven pumps are considered part of the pump and are not 

31 monitored separately. Check valves and manual valves are not included in the index.

32 a. INCLUDE those valves from the list of valves from step 2 whose failure alone can 

33 fail a train/segment. The success criteria used to identify these valves are those 

34 identified in the previous section. (See Figure F-5)

35 b. INCLUDE redundant valves from the list of valves from step 2 within a multi-train 

36 system, whether in series or parallel, where the failure of both valves would prevent 

37 all trains/segments in the system from performing a monitored function. The success 

38 criteria used to identify these valves are those identified in the previous section.(See 

39 Figure F-5) 

40 3) INCLUDE components that cross tie monitored systems between units (i.e. Electrical 

41 Breakers and Valves) if they are modeled in the PRA.

42 4) EXCLUDE those valves and breakers from steps 2 and 3 above whose Birnbaum importance, 

43 (See section F 2.3.5) as calculated in this appendix (including adjustment for support system 

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1 initiator, if applicable, and common cause), is less than 1.0E-06. This rule is applied at the 

2 discretion of the individual plant. A balance should be considered in applying this rule 

3 between the goal to minimize the number of components monitored and having a large 

4 enough set of components to have an adequate data pool. If a decision is made to exclude 

5 some valves based on low Birnbaum values, but not all, to ensure an adequate data pool, then 

6 the valves eliminated from monitoring shall be those with the smallest Birnbaum values. 

7 Symmetric valves in different trains should be all eliminated or all retained.

8 F 2.1.3. DEFINITION OF COMPONENT BOUNDARIES

9 Table 2 defines the boundaries of components, and Figures F-1, F-2, F-3 and F-4 provide 

10 examples of typical component boundaries as described in Table 2. 

11

12 Table 2. Component Boundary Definition 13

Component Component boundary

Diesel Generators The diesel generator boundary includes the generator body, generator actuator, lubrication 

system (local), fuel system (local), fuel oil transfer pumps/valves,1 cooling components 

(local), startup air system receiver, exhaust and combustion air system, dedicated diesel 

battery (which is not part of the normal DC distribution system), individual diesel generator 

control system, cooling water isolation valves, circuit breaker for supply to safeguard buses 

and their associated control circuit (relay contacts for normally auto actuated components, 

control board switches for normally operator actuated components*).

Motor-Driven Pumps The pump boundary includes the pump body, motor/actuator, lubrication system, cooling 

components of the pump seals, the voltage supply breaker, and its associated control circuit 

(relay contacts for normally auto actuated components, control board switches for normally 

operator actuated components*).

Turbine-Driven Pumps The turbine-driven pump boundary includes the pump body, turbine/actuator, lubrication 

system (including pump), extractions, turbo-pump seal, cooling components, and associated 

control system (relay contacts for normally auto actuated components, control board 

switches for normally operator actuated components*) including the control valve. 

Motor-Operated Valves The valve boundary includes the valve body, motor/actuator, the voltage supply breaker 

(both motive and control power) and its associated control circuit (relay contacts for 

normally auto actuated components, control board switches for normally operator actuated 

components*). 

Solenoid Operated 

Valves

The valve boundary includes the valve body, the operator, the supply breaker (both power 

and control) or fuse and its associated control circuit (relay contacts for normally auto 

actuated components, control board switches for normally operator actuated components*).

Hydraulic Operated 

Valves

The valve boundary includes the valve body, the hydraulic operator, associated local 

hydraulic system, associated solenoid operated valves, the power supply breaker or fuse for 

the solenoid valve, and its associated control circuit (relay contacts for normally auto 

actuated components, control board switches for normally operator actuated components*).

Air-Operated Valves The valve boundary includes the valve body, the air operator, associated solenoid-operated 

valve, the power supply breaker or fuse for the solenoid valve, and its associated control 

circuit (relay contacts for normally auto actuated components, control board switches for 

normally operator actuated components.*)

*Note: If the control circuit for any normally auto actuated component includes the control board switch and a failure of the control 

board switch prevents auto actuation of the component, it is considered to be a failure of the control circuit within the component 

boundary.

14

15 For control and motive power, supporting components as described in INPO 98-01 should be 

16 included in the monitored component boundary. In other words, if the relay, breaker or contactor 

17 exists solely to support the operation of the monitored component, it should be considered part of 

18 the component boundary. If a relay, breaker or contactor supports multiple components, it 

 1 The word “valves” is included here for plants with a gravity-fed fuel oil transfer system. For these designs, the valve serves the function 

fulfilled by the FOTP in pump-fed designs.

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1 should not be considered as part of the monitored component boundary. If a relay/switch 

2 supports operation of several monitored components, failure of relay/switch would not be 

3 considered an MSPI failure. However, failure of individual contacts on the relay/switch, which 

4 each support a single monitored component, would be considered a failure of the monitored 

5 component.

6

7 Example 1: If a limit switch in an MOV fails to make-up, which fails an interlock and prevents a 

8 monitored pump from starting, and the limit switch has no other function, a failure to start should 

9 be assigned to the pump. If the limit switch prevents both the pump and another monitored valve 

10 from functioning, no MPSI failures would be assigned.

11

12 Example 2: If a relay prevents an MOV from closing and the relay performs no other function, 

13 an MOV failure would be assigned, assuming failure to close is a monitored function of the 

14 valve. If the MOV also has a limit switch interlocked with another monitored component, the 

15 presence of the limit switch should not be interpreted as the relay having multiple functions to 

16 preclude assigning a failure. If, in addition to the relay failure, there were a separate failure of 

17 the limit switch, both an MOV and pump failure would be assigned.

18

19 Example 3: If a relay/switch supports operation of several monitored components, failure of 

20 relay/switch would not be considered an MSPI failure. However, failure of individual contacts 

21 on the relay, which each support a single monitored component, would be considered a failure of 

22 the monitored component.

23

24 If a system is designed to auto start, and a control circuit failure results in the monitored 

25 component not being capable of auto starting (whatever component actually fails) it is a failure 

26 to start. If a system is designed to auto start, and a manual start fails, it is not an MSPI failure 

27 unless the auto start feature would also have been affected (discovered condition). Control 

28 switches (either in the control room or local) that provide the primary means for actuating a 

29 component are monitored as part of the component it actuates.

30

31 Each plant will determine its monitored components and have them available for NRC 

32 inspection.

33

34 F 2.2. COLLECTION OF PLANT DATA

35 Plant data for the URI includes:

36 • Demands and run hours

37 • Failures

38

39 F 2.2.1. DEMANDS AND RUN HOURS

40 There are two methods that can be used to calculate the number of demands and run hours for 

41 use in the URI. These two methods are use of actual demands and run hours and estimated 

42 demands and run hours. Best judgment should be used to define each category of demands. But 

43 strict segregation of demands between each category is not as important as the validity of total 

44 number of demands and run hours. Linthicum

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1

2 For MSPI monitored components, the duty cycle (demand or run hour) categories shown in 

3 Table 3 are reported to CDE to support the URI derivation.

4

5 Table 3. Required Duty Cycle Categories by Component Type

6

Component Type Duty Cycle Categories Required

All valves and circuit breakers Demands

All pumps Demands

Run Hours

All Emergency Power Generators (both diesel 

and hydro electric)

Start Demands

Load Run Demands

Run Hours

7 Demands (including start demands for the emergency power generators) are defined as any 

8 requirements for the component to successfully start (pumps and emergency power generators) 

9 or open or close (valves and circuit breakers). Exclude post maintenance test demands, unless in 

10 case of a failure, the cause of the failure was independent of the maintenance performed. In this 

11 case the demand may be counted as well as the failure. Post maintenance tests are tests 

12 performed following maintenance but prior to declaring the train/component operable, consistent 

13 with Maintenance Rule implementation. Some monitored valves will include a throttle function 

14 as well as open and close functions. One should not include every throttle movement of a valve 

15 as a counted demand. Only the initial movement of the valve should be counted as a demand. 

16 Demands for valves that do not provide a controlling function are based on a full duty cycle.

17

18 Load run demands (emergency power generators only) are defined as any requirements for the 

19 output breaker to close given that the generator has successfully started and reached rated speed 

20 and voltage. Exclude post maintenance test load run demands, unless in case of a failure, the 

21 cause of the failure was independent of the maintenance performed. In this case, the load run 

22 demand should be counted, depending on whether the actual or estimated demand method will 

23 be used, as well as the failure.

24

25 Run hours (pumps and emergency power generators only) are defined as the time the component 

26 is operating. For pumps, Run run hours include the first hour of operation of the component. 

27 For EDGsemergency diesel generators, exclude all hours before the output breaker is closed (or 

28 EDG hours when the EDGemergency diesel generator is run unloaded) and the first hour after 

29 the breaker is closed (the first hour of operation after the breaker is closed is considered part of 

30 the load/run demand). Failures during shutdown of an emergency generation after the output 

31 breaker is opened are included as a failure to run. Exclude post maintenance test run hours, 

32 unless in case of a failure, the cause of the failure was independent of the maintenance 

33 performed. In this case, the run hours may be counted as well as the failure. Pumps that remain 

34 running for operational reasons following the completion of post- maintenance testing, accrue 

35 run hours from the time the pump was declared operable.

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1 Table 4. Duty Cycle Data Types

2

Type Definition

Actual ESF (ESF Nontest

Actual in CDE)

Any demands or run hours incurred as a result of a valid ESF signal.

Operational/Alignment 

(Operational Nontest in 

CDE)

Any demands or run hours incurred supporting normal plant 

operations not associated with test activities or as a result of a valid 

ESF signal.

Test Any demands or run hours incurred supporting test activities. 

Normally return to service tests and test for which a component is not 

expected to fully cycle (e.g., bumps for rotation checks after pump 

maintenance) are not included. 

3

4 For each type of duty cycle data, the three data types defined in Table 4 are reported to CDE. 

5

6 Best judgment should be used to define each type of demand or run hour data, but strict 

7 segregation of data between types is not as important as the validity of the total number (ESF 

8 nontest + operational nontest + test). 

The duty cycle data category types may be reported as either actual or estimated data. Since 

9

10 valid ESF signals are essentially random in frequency, actual ESF demands (start demands, load 

11 run demands, and run hours) are always reported as actual data. Operational/Alignment and test 

12 data, however, can be reasonably estimated based on plant scheduled test frequencies and 

13 operating history. Therefore, either or both operational/alignment and test data may be reported 

14 as estimated data if so designated in the unit’s MSPI basis document. Optionally, either or both 

15 operational/alignment and test data may be reported as actual data if so designated in the unit’s 

16 MSPI basis document. 

An actual ESF demand (also start demand, load run demand, or run hour) is any condition that 17

18 results in valid actuation, manual or automatic, of any of the MSPI systems due to actual or 

19 perceived plant conditions requiring the actuation. These conditions should be counted in MSPI 

20 as actual ESF demands except when: 

21 1) The actuation resulted from and was part of a pre-planned sequence during testing or 

22 reactor operation; or 

23 2) The actuation was invalid; or 

24 3) Occurred while the system was properly removed from service; or 

25 4) Occurred after the safety function had been already completed. 

Valid actuations are those actuations that result from "valid signals" or from intentional manual 26

27 initiation, unless it is part of a preplanned test. Valid signals are those signals that are initiated in 

28 response to actual plant conditions or parameters satisfying the requirements for initiation of the 

29 safety function of the system. They do not include those which are the result of other signals. 

30 Invalid actuations are, by definition, those that do not meet the criteria for being valid. Thus, 

31 invalid actuations include actuations that are not the result of valid signals and are not intentional 

32 manual actuations. 
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For preplanned actuations, operation of a system as part of a planned test or operational 1

2 evolution should not be counted in MSPI as actual ESF demands, but rather as 

3 operational/alignment or test demands. Preplanned actuations are those which are expected to 

4 actually occur due to preplanned activities covered by procedures. Such actuations are those for 

5 which a procedural step or other appropriate documentation indicates the specific actuation is 

6 actually expected to occur. Control room personnel are aware of the specific signal generation 

7 before its occurrence or indication in the control room. However, if during the test or evolution, 

8 the system actuates in a way that is not part of the planned evolution, that actuation should be 

9 counted. 

Actual ESF demands occur when the setpoints for automatic safety system actuation are met or 10

11 exceeded and usually include the actuation of multiple trains and systems. Automatic actuation 

12 of standby trains on a failure of a running train should not be considered as an actual ESF 

13 demand. Actuations caused by operator error, maintenance errors, etc. that are not due to actual 

14 plant requirements should be considered as “invalid” actuations and not counted in MSPIError! 

15 Bookmark not defined. as actual ESF demands.

CDE will use the actual ESF data, the actual/estimated operational data, and the actual/estimated 

16

17 test data to derive a total number of demands (start demand, load run demands, and run hours as 

18 required) for each MSPI monitored component for use in the URI derivation for the applicable 

19 MSPI system.

Reporting of Actual DemandsData: Actual demands data is a count of the number of demands, 

20

21 start demands, load run demands, and run hours occurring in the specific month (or quarter 

22 prior to April 2006). For the reporting of Actual demands, Table 5 shows the requirements for 

23 data to be reported each month if actual demands will be reported (or quarter prior to April 

24 2006), for all actual ESF demands, operational/alignment demands, and test duty cycle data.

25

26 Reporting of Estimated DemandsData: Estimated demands and run hours can be derived based 

27 on the number of times a procedure or maintenance activity is performed, or based on the 

28 historical data over an operating cycle or more. Table 6 shows the requirements for estimated 

29 data to be reported to CDE.

30

31 Estimated demands data are not reported to CDE on a periodic (monthly or quarterly) basis, 

32 rather, they are entered initially, typically for the period of a refueling cycle (e.g., 48 demands 

33 in 24 months) then updated as required. An update is required if a change to the basis for the 

34 estimate results in a >25% change in the estimate of the total (operational/alignment + test) value 

35 for a group of components within an MSPI system. For example, a single MOV in a system may 

36 have its estimated demands change by greater than 25%, but revised estimates are not required 

37 unless the total number of estimated demands for all MOVs in the system changes by >25%. 

38 The new estimate will be used in the calculation the quarter following the input of the updated 

39 estimates into CDE.

40

41

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1 Table 5. Required Reporting by Component Type (Actual Demands Commitment)

2

Component Type Report Each Month (or Quarter Prior to April 

2006)

All valves and circuit breakers Actual ESF Demands

Actual Operational/Alignment Demands

Actual Test Demands

All pumps Actual ESF Demands

Actual Operational/Alignment Demands

Actual Test Demands

Actual ESF Run Hours

Actual Operational/Alignment Run Hours

Actual Test Run Hours

All Emergency Power Generators (both 

diesel and hydroelectric)

Actual ESF Start Demands

Actual Operational/Alignment Start Demands

Actual Test Start Demands

Actual ESF Load Run Demands

Actual Operational/Alignment Load Run Demands

Actual Test Load Run Demands

Actual ESF Run Hours

Actual Operational/Alignment Run Hours

Actual Test Run Hours

3
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1 Table 6. Required Reporting by Component Type (Estimated Data Commitment)

2

Component Type Report 

All valves and circuit breakers Actual ESF Demands1

Estimated Operational/Alignment Demands

Estimated Test Demands

All pumps Actual ESF Demands1

Estimated Operational/Alignment Demands

Estimated Test Demands

Actual ESF Run Hours1

Estimated Operational /Alignment Run Hours

Estimated Test Run Hours

All Emergency Power Generators (both 

diesel and hydro electric)

Actual ESF Start Demands1

Estimated Operational /Alignment Start Demands

Estimated Test Start Demands

Actual ESF Load Run Demands1

Estimated Operational/Alignment Load Run Demands

Estimated Test Load Run Demands

Actual ESF Run Hours1

Estimated Operational /Alignment Run Hours

Estimated Test Run Hours

3

4 Note 1 for Table 6: For plants that have elected to use estimated test and operational/alignment demands 

5 and run hours, the reporting of ESF demands and run hours should be either “zero” or the actual 

6 demands/run hours.” If there were no actual ESF demands and run hours for the quarter, a "zero" 

7 must be entered into CDEError! Bookmark not defined. for actual ESF demands and run 

8 hours.

9

10

11 F 2.2.2. FAILURES

12 In general, a failure of a component for the MSPI is any circumstance when the component is 

13 not in a condition to meet the performance requirements defined by the PRA success criteria or 

14 mission time for the functions monitored under the MSPI. For EDGsemergency power 

15 generators, the mission time for failure determinations should be the maximum mission time 

16 considered in the PRA model (generally 24 hours), even if a shorter mission time is used for 

17 input into CDE. Note that a run failure that occurs beyond 24 hoursthe mission time after the 

18 EDG emergency power generator or pump is started is still counted as a MSPI failure. This 

19 accounts for the time during which the EDG component was in an unknown condition when it 

20 would have been unable to run for a full 24 hoursmission time. In addition, such failures are 

21 included in the data used to generate the baseline failure rates.

22

23 Failures for the MSPI are not necessarily equivalent to failures in the maintenance 

24 rule. Specifically, the MSPI failure determination does not depend on whether a failure is 

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1 maintenance preventable. Additionally, the functions monitored for the MSPI are normally a 

2 subset of those monitored for the maintenance rule.

3

4 EDG Emergency power generator failure to start: A failure to start includes those failures up 

5 to the point when the EDG emergency power generator output breaker has received a signal to 

6 close. has achieved required speed and voltage. (Exclude post maintenance tests (PMTs), unless 

7 the cause of failure was independent of the maintenance performed. Include all failures that 

8 result from a non-PMT demand following return to service. If a PMT failure occurs following 

9 return to service and was dependent ofcaused by the maintenance performedactivity, then this 

10 failure is excluded and the train, during the period from the completion of the maintenance 

11 activity to the declaration of return to service, is counted as unavailable.) (See the 

EDGemergency power generator1 12 failure to run definition for treatment of fuel oil transfer 

pump/valve failures.1 13 )

14

15 EDG Emergency power generator failure to load/run: Given that it the EDGemergency power 

16 generator has successfully started and the output breaker has received a signal to close, a failure 

17 of the EDG generator output breaker to close, to successfully load sequence and or a failure to 

18 run/operate for one hour to perform its monitored functionsafter breaker closure. The 

19 EDGemergency power generator does not have to be fully loaded to count the failure. Failure to 

20 load/run also includes failures of the EDGemergency power generator output breaker to re-close 

21 following a grid disturbance if the EDGemergency power generator was running paralleled to the 

22 grid, provided breaker closure is required by plant design. This failure mode is treated as a 

23 demand failure for calculation purposes. (Exclude post maintenance tests, unless the cause of 

24 failure was independent of the maintenance performed. Include all failures that result from a 

25 non-PMT demand following return to service. If a PMT failure occurs following return to 

26 service and was dependent oncaused by the maintenance performedactivity, then this failure is 

27 excluded and the train, during the period from the completion of the maintenance activity to the 

28 declaration of return to service, is counted as unavailable. )

29

30 EDG Emergency power generator failure to run: A failure after the EDGemergency power 

31 generator has successfully started, the output breaker has closed and the EDGgenerator has run 

32 for an hour after the breaker has closed. The EDGgenerator does not have to be fully loaded to 

33 count the failure. Given that it has successfully started and loaded and run for an hour, a failure 

34 of an EDG to run/operate. (Exclude post maintenance tests, unless the cause of failure was 

35 independent of the maintenance performed. Failures of the EDG fuel oil transfer 

36 pump(s)/valve(s) are considered to be EDG failures to run if the failure of the EDG fuel oil 

37 transfer pump/valve results in the failure of the EDG to be able to run for 24 hours (e.g., no 

redundant transfer pump/valve is available2 38 , or the redundant pump/valve is disabled in a manner 

39 preventing it from performing its intended function). Regardless of when the fuel oil transfer 

40 pump/valve(s) fails, this counts as a run failure. In the case where a fuel oil transfer 

41 pump/valve(s) failure results in more than 1one EDG to not be able to run for 24 hours, a failure 

42 is counted for each affected EDG. 

 1 Information Systems Laboratories, Inc. performed a review for the NRC of EDG and FOTP failures to support the changes made to EDG failure 

definitions in 2011. See Accession No. ML11259A101 in NRC’s Agencywide Documents Access and Management System (ADAMS). 2 In order for a redundant fuel oil transfer pump/valve to be credited in a failure determination, it must either automatically actuate or be able to 

be manually actuated in the time needed to satisfy the PRAError! Bookmark not defined. success criteria. If the pump/valve requires manual 

actuation, indication must be available to alert the operating staff of the need to actuate the pump/valve in in the time required.

FAQ472

(09-08)

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(11-08)

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1

2 Include all failures that result from a non-PMT demand following return to service. If a PMT 

3 failure occurs following return to service and was dependent oncaused by the maintenance 

4 performedactivity, then this failure is excluded and the train, during the period from the 

5 completion of the maintenance activity to the declaration of return to service, is counted as 

6 unavailable.)

7

8 Pump failure on demand: A failure to start and run for at least one hour is counted as failure on 

9 demand. (Exclude post maintenance tests, unless the cause of failure was independent of the 

10 maintenance performed. Include all failures that result from a non-PMT demand following 

11 return to service. If a PMT failure occurs following return to service and was dependent on

12 caused by the maintenance performedactivity, then this failure is excluded and the train, 

13 during the period from the completion of the maintenance activity to the declaration of return 

14 to service, is counted as unavailable.)

15

16 Pump failure to run: Given that it has successfully started and run for an hour, a failure of a 

17 pump to run/operate. (Exclude post maintenance tests, unless the cause of failure was 

18 independent of the maintenance performed. Include all failures that result from a non-PMT 

19 demand following return to service. If a PMT failure occurs following return to service and 

20 was dependent oncaused by the maintenance performedactivity, then this failure is excluded 

21 and the train, during the period from the completion of the maintenance activity to the 

22 declaration of return to service, is counted as unavailable.)

23

24 Valve failure on demand: A failure to transfer to the required monitored state (open, close, or 

25 throttle to the desired position as applicable) is counted as failure on demand. (Exclude post 

26 maintenance tests, unless the cause of failure was independent of the maintenance performed.

27 Include all failures that result from a non-PMT demand following return to service. If a PMT 

28 failure occurs following return to service and was caused by the maintenance 

29 performedactivity, then this failure is excluded and the train, during the period from the 

30 completion of the maintenance activity to the declaration of return to service, is counted as 

31 unavailable.)

32

33 Breaker failure on demand: A failure to transfer to the required monitored state (open or close 

34 as applicable) is counted as failure on demand. (Exclude post maintenance tests, unless the 

35 cause of failure was independent of the maintenance performed. Include all failures that result 

36 from a non-PMT demand following return to service. If a PMT failure occurs following return 

37 to service and was dependent oncaused by the maintenance performedactivity, then this failure is 

38 excluded and the train, during the period from the completion of the maintenance activity to the 

39 declaration of return to service, is counted as unavailable.)

40

41 Treatment of Demand and Run Failures

42 Failures of monitored components on demand or failures to run, either actual or test are included 

43 in unreliability. Failures on demand or failures to run while not critical are included unless an 

44 evaluation determines the failure would not have affected the ability of the component to 

45 perform it’s monitored at power function. In no case can a postulated action to recover a failure 

46 be used as a justification to exclude a failure from the count.

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1

2 Human errors/component trips, inadvertent actuations or unplanned unavailability introduced as 

3 part of a test or maintenance activity are not indicative of the reliability of the equipment had the 

4 activity not been performed, and should NOT be counted as failures as long as they are 

5 immediately revealed and promptly reported to the control room.

6

7 This applies to human errors which result in tripping an MSPI component that:

8

9 1. Occur while the MSPI train/segment is considered available;

10 2. Do not result in actual equipment damage;

11 3. Are immediately revealed through clear and unambiguous indication;

12 4. Are promptly reported to the control room without delay prior to the performance 

13 of corrective actions, and;

14 5. Are clearly associated with a test or maintenance activity such that the failure 

15 sequence would not have occurred and cannot occur if the test or maintenance 

16 activity was not being performed.

17

18 Unplanned unavailability should be counted from the time of the event until the equipment is 

19 returned to service.

20

21 Latent failures (failures that existed prior to the maintenance) that are discovered as part of 

22 maintenance or test activity are considered failures.

23

24 Treatment of Failures Discovered During Post Maintenance Tests

25 Failures identified during post maintenance tests (PMT) are not counted unless the cause of the 

26 failure was independent of the maintenance performed. The maintenance scope of work includes 

27 the activities required to be performed to conduct the maintenance, including support activities, 

28 the actual maintenance activities, and the activities required for restoration of the monitored 

29 component(s) to their available and operable conditions. This includes, but is not limited to, 

30 typical tasks such as scaffolding erection and removal, coatings applications, insulation removal 

31 and installation, rigging activities, health physics activities, interference removal and restoration, 

32 as required to support and perform the required maintenance activity. Support activities may be 

33 planned, scheduled and implemented on separate work orders from the work order for the 

34 monitored component(s). System or component failures introduced during the scope of work are 

35 not indicative of the reliability of the equipment, since they would not have occurred had the 

36 maintenance activity not been performed. In addition, the potential exists that components or 

37 devices not included in the direct scope of work may be affected by the ongoing activities. Such 

38 failures are not counted providing: 

39 • They are identified during or prior to the post-maintenance testing and are corrected 

40 prior to the component(s) being returned to operable status,

41 • The repair is documented in a work package, and

42 • The critical components not directly in the scope of work, but that have the potential 

43 to be affected by the maintenance activity, are noted by means such as cautions in the 

44 procedures, inclusion in the pre-job briefings, protection by signs, placards or 

45 padding, and
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1 • The licensee uses the corrective action program to document the basis for the 

2 determination that the cause of the failure was dependent on the maintenance 

3 performed. This determination must establish a clear relationship between the 

4 maintenance performed and the failure.

5

6 Treatment of Discovered Conditions that Result in the Inability to Perform a Monitored Function

7 Discovered conditions of monitored components (conditions within the component boundaries 

8 defined in section F 2.1.3) that render a monitored component incapable of performing its 

9 monitored function are included in unreliability as a failure, even though no actual failure on 

10 demand or while running existed. This treatment accounts for the amount of time that the 

11 condition existed prior to discovery, when the component was in an unknown failed state.

12

13 In accordance with current regulatory guidance, licensees may credit limited operator actions 

14 to determine that degraded equipment remains operable in accordance with Technical 

15 Specifications. If a component is determined to be operable, then no failure is counted. 

16 Beyond this, no credit is allowed for operator actions during degraded conditions that render the 

17 component unable to perform its monitored function.

18

19 Conditions that render a monitored component incapable of performing its monitored function 

20 that are immediately annunciated in the control room without an actual demand occurring are a 

21 special case of a discovered condition. In this instance the discovery of the condition is 

22 coincident with the failure. This condition is applicable to normally energized control circuits 

23 that are associated with monitored components, which annunciate on loss of power to the control 

24 circuit. For this circumstance there is no time when the component is in an unknown failed state. 

25 In this instance appropriate train unavailable hours will be accounted for, but no additional 

26 failure will be counted.

27

28 For other discovered conditions where the discovery of the condition is not coincident with the 

29 failure, the appropriate failure mode must be accounted for in the following manner:

30 • For valves and breakers a demand failure would be assumed and included. An additional 

31 demand may also be counted.

32 • For pumps and dieselsemergency power generators, if the discovered condition would 

33 have prevented a successful start, a start failure is included, but there would be no run 

34 time hours or run failure. An additional demand may also be counted.

35 • For emergency power generatorsdiesels, if it was determined that the diesel generator would 

36 start, but would fail to load (e.g. a condition associated with the output breaker), a load/run 

37 failure would be assumed and included. An additional start demand and load/run demand 

38 may also be counted.

39 • For pumps and emergency power generatorsdiesels, if it was determined that the 

40 pump/diesel generator would start and load run, but would fail sometime prior to 

41 completing its mission time, a run failure would be assumed. A start demand and a load/run 

42 demand would also be assumed and included. The evaluated failure time may be included in 

43 run hours.

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1 For a running component that is secured from operation due to observed degraded performance, 

2 but prior to failure, then a run failure shall be assumed unless evaluation of the condition shows 

3 that the component would have continued to operate for the mission time starting from the time 

4 the component was secured.

5

6 Unplanned unavailability would accrue in all instances from the time of discovery or 

7 annunciation consistent with the definition in section F 1.2.1.

8

9 Loss of monitored function(s) is assumed to have occurred if the established success criteria have 

10 not been met. If subsequent analysis identifies additional margin for the success criterion, future 

11 impacts on URI or UAI for degraded conditions may be determined based on the new criterion. 

12 However, the current quarter’s URI and UAI must be based on the success criteria of record at 

13 the time the degraded condition is discovered. If the new success criteria causes a revision to the 

14 PRA affecting the numerical results (i.e. CDF and FV), then the change must be included in the 

15 PRA model and the appropriate new values calculated and incorporated in the MSPI Basis 

16 Document prior to use in the calculation of URI and UAI. If the change in success criteria has no 

17 effect on the numerical results of the PRA (representing only a change in margin) then only the 

18 MSPI Basis Document need be revised prior to using the revised success criteria.

19

20 If the degraded condition is not addressed by any of the pre-defined success criteria, an 

21 engineering evaluation to determine the impact of the degraded condition on the monitored

22 function(s) should be completed and documented. The use of component failure analysis, circuit 

23 analysis, or event investigations is acceptable. Engineering judgment may be used in 

24 conjunction with analytical techniques to determine the impact of the degraded condition on the 

25 monitored function. The engineering evaluation should be completed as soon as practical. If it 

26 cannot be completed in time to support submission of the PI report for the current quarter, a 

27 preliminary determination should be reported and the comment field shall note that an 

28 evaluation is pending. The evaluation must be completed in time to accurately account for 

29 unavailability/unreliability in the next quarterly report. Exceptions to this guidance are expected 

30 to be rare and will be treated on a case-by-case basis. Licensees should identify these situations 

31 to the resident inspector.

32

33 Failures and Discovered Conditions of Non-Monitored Structures, Systems, and Components 

34 (SSC)

35 Failures of SSCs that are not included in the performance index will not be counted as a 

36 failure or a demand. Failures of SSCs that would have caused an SSC within the scope of the 

37 performance index to fail will not be counted as a failure or demand. An example could be a 

38 manual suction isolation valve left closed which would have caused a pump to fail. This would 

39 not be counted as a failure of the pump. Unmonitored components within a monitored 

40 train/segment boundary do not contribute to unreliability. If an unmonitored component within a 

41 monitored train/segment fails, unreliability is not accrued if the unmonitored component does not 

42 cause an actual demand and/or actual failure of a monitored component within the monitored 

43 train/segment. If the unmonitored component causes a monitored component within the 

44 monitored train/segment to actually fail when demanded, then the monitored component demand 

45 and failure are counted for unreliability. The failure of an unmonitored component within a 

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1 monitored train/segment can cause unavailability of that train/segment to be counted if the 

2 train/segment is rendered unavailable.

3

4 Unmonitored components outside a monitored train/segment boundary do not contribute to 

5 unreliability of monitored components or to unavailability of the monitored train/segment. If 

6 an unmonitored component outside a monitored train/segment fails, unreliability is not 

7 accrued regardless whether the unmonitored component causes an actual demand and/or actual 

8 failure of a monitored component. The failure of an unmonitored component outside a 

9 monitored train/segment cannot cause unavailability of that train/segment to be counted.

10

11 For example, a manual suction isolation valve (an unmonitored component within the train 

12 boundary) is left closed, which would have caused a pump to fail. The closed valve would 

13 not be counted as a failure of the pump, nor would unavailability be accrued. Any mis14 positioning of the valve that caused the train to be unavailable would be counted as 

15 unavailability from the time of discovery. The significance of the mis-positioned valve prior to 

16 discovery would be addressed through the inspection process. (Note, however, in the above 

17 example, if the shut manual suction isolation valve resulted in an actual pump failure, the pump 

18 failure would be counted as a demand and failure of the pump and unplanned unavailability 

19 would be counted against the appropriate train/segment.)

20

21

22 F 2.3. CALCULATION OF URI

23 Unreliability is monitored at the component level and calculated at the system level. URI is 

24 proportional to the weighted difference between the plant specific-specific component 

25 unreliability and the industry average unreliability. The Birnbaum importance is the weighting 

26 factor. Calculation of system URI due to this difference in component unreliability is as follows: 

27

( )

( )

( )

∑





















+ −

+ −

−

= =

m

j

Rj RBCj RBLj

Lj LBCj LBLj

Dj DBCj DBLj

B UR UR

B UR UR

B UR UR

URI

1

28 Eq. 3

29

30 Where the summation is over the number of monitored components (m) in the system, and:

31

BDj 32 , BLj and BRj are the Birnbaum importance measures for the failure modes fail on 

33 demand, fail to load and fail to run respectively,

34

35 URDBC, URLBC, and URRBC are Bayesian corrected plant specific-specific values of 

36 unreliability for the failure modes fail on demand, fail to load and fail to run respectively,

37 and

38

39 URDBL, URLBL, and URRBL are Baseline values of unreliability for the failure modes fail on 

40 demand, fail to load and fail to run respectively.

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1 The Birnbaum importance for each specific component failure mode is defined as

MAX pc

URc

p

UR

FV B CDF 



 



 2 = Eq. 4

3 Where,

4 CDFp is the plant-specific internal events, at power, core damage frequency,

5 FVURc is the component and failure mode specific Fussell-Vesely value for unreliability,

6 URPc is the plant-specific PRA value of component and failure mode unreliability,

7

8 Failure modes defined for each component type are provided below. There may be several basic 

9 events in a PRA that correspond to each of these failure modes used to collect plant specific10 specific data. These failure modes are used to define how the actual failures in the plant are 

11 categorized.

12

13 Valves and Breakers:

14 Fail on Demand (Open/Close)

15 Pumps:

16 Fail on Demand (Start)

17 Fail to Run

18 Emergency Diesel Generators:

19 Fail on Demand (Start)

20 Fail to Load/Run

21 Fail to Run

22 A method for calculation of the quantities in equation 3 and 4 from importance measures 

23 calculated using cutsets from an existing PRA solution is discussed in sections F 2.3.1 through F 

24 2.3.3.

25

26 An alternate approach, based on re-quantification of the PRA model, and calculation of the 

27 importance measures from first principles is also an acceptable method. Guidance on this 

28 alternate method is contained in section F6 of this appendix. A plant using this alternate 

29 approach should use the guidance in section F6 and skip sections F 2.3.1 through F 2.3.3.

30

31 F 2.3.1. TRUNCATION LEVELS

32 The values of importance measures calculated using an existing cutset solution are influenced by 

33 the truncation level of the solution. The truncation level chosen for the solution should be 7 

34 orders of magnitude less than the baseline CDF for the alternative defined in sections F 2.3.2 and 

35 F 2.3.3.

36

37 As an alternative to using this truncation level, the following sensitivity study may be performed 

38 to establish the acceptability of a higher (e.g. 6 orders of magnitude) truncation level.

39

40 1. Solve the model at the truncation level you intend to use. (e.g. 6 orders of magnitude 

41 below the baseline CDF)

42 2. Identify the limiting Birnbaum value for each component. (this is the case 1 value)
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1 3. Solve the model again with a truncation 10 times larger (e.g.. 5 orders of magnitude 

2 below the baseline CDF)

3 4. Identify the limiting Birnbaum value for each component. (this is the case 2 value)

4 5. For each component with Birnbaum-case 1 greater than 1.0E-06 calculate the ratio 

5 [(Birnbaum-case 2)/(Birnbaum-case 1)]

6 6. If the value for the calculated ratio is greater than 0.8 for all components with Birnbaum7 case 1 value greater than 1.0E-06, then the case 1 truncation level may be used for this 

8 analysis.

9

10 This process may need to be repeated several times with successively lower truncation levels to 

11 achieve acceptable results.

12

13 F 2.3.2. CALCULATION OF CORE DAMAGE FREQUENCY (CDFP)

14 The Core Damage Frequency is a CDE input value. The required value is the internal events

15 average maintenance at power value. Internal flooding and external events, including 

16 internal firesfire are not included in this calculated value. In general, all inputs to this 

17 indicator from the PRA are calculated from the internal events model only. 

18

19 F 2.3.3. CALCULATION OF [FV/UR]MAX

20 The FV, UR and common cause adjustment values developed in this section are separate CDE

21 input values. 

22

23 Equation 4 includes a term that is the ratio of a Fussell-Vesely importance value divided by the 

24 related unreliability. The calculation of this ratio is performed in a similar manner to the ratio 

25 calculated for UAI, except that the ratio is calculated for each monitored component. One 

26 additional factor needs to be accounted for in the unreliability ratio that was not needed in the 

27 unavailability ratio, the contribution to the ratio from common cause failure events. The 

28 discussion in this section will start with the calculation of the initial ratio and then proceed with 

29 directions for adjusting this value to account for the cooling water initiator contribution, as in the 

30 unavailability index, and then the common cause correction.

31

32 It can be shown that for a given component represented by multiple basic events, the ratio of the 

33 two values for the component is equal to the ratio of values for any basic event representing the 

34 component. Or,

35

= = Constant

Pc

URc

be

be

UR

FV

UR

FV 36

37

38 as long as the basic events under consideration are logically equivalent.

39

40 Note that the constant value may be different for the unreliability ratio and the unavailability 

41 ratio because the two types of events are frequently not logically equivalent. For example 

42 recovery actions may be modeled in the PRA for one but not the other. This ratio may also be 

43 different for fail on demand and fail to run events for the same component. This is particularly 

44 true for cooling water pumps that have a trip initiation function as well as a mitigation function.

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1

2 There are two options for determining the initial value of this ratio: The first option is to identify 

3 one maximum ratio that will be used for all applicable failure modes for the component. The 

4 second option is to identify a separate ratio for each failure mode for the component. These two 

5 options will be discussed next.

6

7 Option 1

8 Identify one maximum ratio that will be used for all applicable failure modes for the component. 

9 The process for determining a single value of this ratio for all failure modes of a component is to 

10 identify all basic events that fail the monitored function of the component (excluding 

11 common cause events and test and maintenance events). It is typical, given the component 

12 scope definitions in Table 2, that there will be several plant components modeled separately in 

13 the plant PRA that make up the MSPI component definition. For example, it is common that in 

14 modeling an MOV, the actuation relay for the MOV and the power supply breaker for the MOV 

15 are separate components in the plant PRA. Ensure that the basic events related to all of these 

16 individual components are considered when choosing the appropriate [FV/UR] ratio.

17

18 Determine the failure probabilities for the events, determine the associated FV values for the 

19 events and then calculate the ratios, [FV/UR]ind, where the subscript refers to independent 

20 failures. Choose from this list the basic event for the component and its associated FV value that 

21 results in the largest [FV/UR] ratio. This will typically be the event with the largest failure 

22 probability to minimize the effects of truncation on the calculation. If all events for the 

23 component have been truncated, either a lower truncation value or the method provided in 

24 sSection F.6 should be used.

25

26 Option 2

27 Identify a separate ratio for each failure mode for the component The process for determining a 

28 ratio value for each failure mode proceeds similarly by first identifying all basic events 

29 related to each monitored function of the component. After this step, each basic event must 

30 be associated with one of the specific defined failure modes for the component. Proceed as 

31 in option 1 to find the values that result in the largest ratio for each failure mode for the 

32 component. In this option the CDE inputs will include FV and UR values for each failure mode 

33 of the component.

34

35 F 2.3.4. CORRECTIONS TO FV/UR RATIO

36

37 Treatment of PRA Modeling Asymmetries

38 In systems with rotated normally running pumps (e. g. cooling water systems), the PRA models 

39 may assume one pump is always the running and another is in standby. For example, a service 

40 water system may have two 100% capacity pumps in one train, an A and B pump. In practice the 

41 A and B pumps are rotated and each one is the running pump 50% of the time. In the PRA model 

42 however, the A pump is assumed to be always running and the B pump is always in assumed to 

43 be in standby. This will result in one pump appearing to be more important than the other when 

44 they are, in fact, of equal importance. This asymmetry in importance is driven by the assumption 

45 in the PRA, not the design of the plant.

46

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1 When this is encountered, the importance measures may be used as they are calculated from the 

2 PRA model for the component importance used in the calculation of URI. Although these are not 

3 actually the correct importance values, the method used to calculate URI will still provide the 

4 correct result because the same value of unreliability is used for each component as a result of 

5 the data being pooled. Note that this is different from the treatment of importance in the 

6 calculation of UAI.

7

8 Cooling Water and Service Water System [FV/UR]ind Values

9 Ensure that the correction term in this section is applied prior to the calculation of the common 

10 cause correction in the next section. Component Cooling Water Systems (CCW) and Service 

11 Water Systems (SWS) at some nuclear stations contribute to risk in two ways. First, the systems 

12 provide cooling to equipment used for the mitigation of events and second, the failures in the 

13 systems may also result in the initiation of an event. Depending on the manner in which the 

14 initiator contribution is treated in the PRA, it may be necessary to apply a correction to the 

15 FV/UR ratio calculated in the section above.

16 The correction must be applied to each FV/UR ratio used for this index. If the option to use 

17 separate ratios for each component failure mode was used in the section above then this 

18 correction is calculated for each failure mode of the component.

19

20 The contribution to risk from failures to provide cooling to other plant equipment is modeled 

21 directly through dependencies in the PRA model. However, the contribution due to event 

22 initiation is treated in four general ways in current PRAs:

23 1) The use of linked initiating event fault trees for these systems with the same basic 

24 events used in the initiator and mitigation trees.

25 2) The use of linked initiating event fault trees for these systems with different basic 

26 events used in the initiator and mitigation trees.

27 3) Fault tree solutions are generated for these systems external to the PRA and the 

28 calculated value is used in the PRA as a point estimate

29 4) A point estimate value is generated for the initiator using industry and plant specific30 specific event data and used in the PRA.

31

32 Each of these methods is discussed below.

33

34 Modeling Method 1

35 If a PRA uses the first modeling option, then the FV values calculated will reflect the total 

36 contribution to risk for a component in the system. No additional correction to the FV values is 

37 required.

38

39 Modeling Methods 2 and 3

40 The corrected ratio may be calculated as described for modeling method 4 or by the method 

41 described below.

42

43 If a linked initiating event fault tree with different basic events used in the initiator and 

44 mitigation trees is the modeling approach taken, or fault tree solutions are generated for these 

45 systems external to the PRA and the calculated value is used in the PRA as a point estimate, then 

46 the corrected ratio is given by:
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F-39





 















 − = + ∑

=

i

m

m

m n n

m n m n corr FVie

IE q

IE IE

URc

FVc FV UR

1 ,

, , *

( )

(1) (0) 1 [ / ] .

2

3 In this expression the summation is taken over all system initiators i that involve component n, 

4 where

5 FVc is the Fussell-Vesely for component C as calculated from the PRA Model. This does 

6 not include any contribution from initiating events,

7 URc is the basic event unreliability used in computing FVc; i.e. in the system response 

8 models,

9 IEm,n(qn) is the system initiator frequency of initiating event m when the component n

10 unreliability basic event is qn. The event chosen in the initiator tree should represent the 

11 same failure mode for the component as the event chosen for URc,

12 IEm,n(1) is as above but qn=1,

13 IEm,n(0) is as above but qn=0

14 and

15 FViem is the Fussell-Vesely importance contribution for the initiating event m to the 

16 CDF.

17

18 Since FV and UR are separate CDE inputs, use URc and calculate FV from

[ ] FV URc FV UR corr 19 = * /

20

21 Modeling Method 4

22 If a point estimate value is generated for the initiator using industry and plant specific-specific

23 event data and used in the PRA, then the corrected [FV/UR]MAX for a component C is calculated 

24 from the expression:

25 [FV /UR]MAX = [(FVc + FVie * FVsc)/URc]

26

27 Where:

28 FVc is the Fussell-Vesely for CDF for component C as calculated from the PRA Model. 

29 This does not include any contribution from initiating events.

30 FVie is the Fussell-Vesely contribution for the initiating event in question (e.g. loss of 

31 service water).

32 FVsc is the Fussell-Vesely within the system fault tree only for component C (i.e. the 

33 ratio of the sum of the cut sets in the fault tree solution in which that component appears 

34 to the overall system failure probability). Note that this may require the construction of a 

35 “satellite” system fault tree to arrive at an exact or approximate value for FVsc depending 

36 on the support system fault tree logic.

37 URc is the basic event unreliability used in computing FVc; i.e., in the system 

38 response models.

39

40 FV and UR are separate CDE input values.

41

42 Including the Effect of Common Cause in [FV/UR]max

43 Be sure that the correction factors from the previous section are applied prior to the common 

44 cause correction factor being calculated.

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1

2 Changes in the independent failure probability of an SSC imply a proportional change in the 

3 common cause failure probability, even though no actual common cause failures have occurred. 

4 The impact of this effect on URI is considered by including a multiplicative adjustment to the 

5 [FV/UR]ind ratio developed in the section above. This multiplicative factor (A) is entered into 

6 CDE as “CCF.”

7

8 Two methods are provided for including this effect, a simple generic approach that uses 

9 bounding generic adjustment values and a more accurate plant specific-specific method that uses 

10 values derived from the plant specific-specific PRA. Different methods can be used for different 

11 systems. However, within an MSPI system, either the generic or plant specific-specific method 

12 must be used for all components in the system, not a combination of different methods. For the 

13 cooling water system, different methods may be used for the subsystems that make up the 

14 cooling water system. For example, component cooling water and service water may use 

15 different methods.

16

17 The common cause correction factor is only applied to components within a system and does not 

18 include cross system (such as between the BWR HPCI and RCIC systems) common cause. If 

19 there is only one component within a component type within the system, the adjustment value is 

20 1.0. Also, if all components within a component type are required for success, then the 

21 adjustment value is 1.0.

22

23 Generic CCF Adjustment Values

24 Generic values have been developed for monitored components that are subject to common 

25 cause failure. The correction factor is used as a multiplier on the [FV/UR] ratio for each 

26 component in the common cause group. This method may be used for simplicity and is 

27 recommended for components that are less significant contributors to the URI (e.g. [FV/UR] is 

28 small). The multipliers are provided in table Table 7. 

29

30 The EDG is a “super-component” that includes valves, pumps and breakers within the super31 component boundary. The EDG generic adjustment value should be applied to the EDG “super32 component” even if the specific event used for the [FV/UR] ratio for the EDG is a valve or 

33 breaker failure.

34
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F-41

1 Table 7. Generic CCF Adjustment Values 

2

EPS HPI HRS/ RHR

EDG MDP 

Running or 

Alternating+

MDP 

Standby

MDP 

Standby

TDP 

**

MDP 

Standby

Arkansas 1 1.25 2 1 1 1 1.5

Arkansas 2 1.25 1 2 1 1 1.5

Beaver Valley 1 1.25 2 1 1.25 1 1.5

Beaver Valley 2 1.25 2 1 1.25 1 1.5

Braidwood 1 & 2 3 1.25 1.25 1 1 1.5

Browns Ferry 1, 2 & 3 1.25 1 1 1 1 3

Browns Ferry 2 1.25 1 1 1 1 3

Browns Ferry 3 1.25 1 1 1 1 3

Brunswick 1 & 2 1.25 1 1 1 1 3

Byron 1 & 2 3 1.25 1.25 1 1 1.5

Callaway 1.25 1.25 1.25 1.25 1 1.5

Calvert Cliffs 1 & 2 1.25 1 2 1.25 1.5 1.5

Catawba 1 & 2 1.25 1.25 1.25 1.25 1 1.5

Clinton 1 1.25 1 1 1 1 1.5

Columbia Nuclear 1.25 1 1 1 1 1.5

Comanche Peak 1 & 2 1.25 1.25 1.25 1.25 1 1.5

Cook 1 & 2 1.25 1.25 1.25 1.25 1 1.5

Cooper Station 1.25 1 1 1 1 3

Crystal River 3 1.25 2 1 1 1 1.5

Davis-Besse 1.25 1.25 1.25 1 1.5 1.5

Diablo Canyon 1 & 2 2 1.25 1.25 1.25 1 1.5

Dresden 2 & 3 1.25 3 1 1 1 3

Duane Arnold 1.25 1 1 1 1 3

Farley 1 & 2 2 2 1 1.25 1 1.5

Fermi 2 1.25 1 1 1 1 3

Fitzpatrick 3 1 1 1 1 3

Fort Calhoun 1.25 1 2 1 1 1.5

Ginna 1.25 1 2 1.25 1 1.5

Grand Gulf 1.25 1 1 1 1 1.5

Harris 1.25 2 1 1.25 1 1.5

Hatch 1 & 2 2 1 1 1 1 3

Hope Creek 1.25 1 1 1 1 1.5

Indian Point 2 1.25 1 2 1.25 1 1.5

Indian Point 3 1.25 1 2 1.25 1 1.5

Kewaunee 1.25 1 1.25 1.25 1 1.5

LaSalle 1 & 2 1.25 1 1 1 1 1.5

Limerick 1 & 2 3 1 1 1 1 3

McGuire 1 & 2 1.25 1.25 1.25 1.25 1 1.5

Millstone 2 1.25 1 2 1.25 1 1.5

Millstone 3 1.25 2 1.25 1.25 1 1.5

Monticello 1.25 1 1 1 1 3

Nine Mile Point 1 1.25 3 1 1 1 3

FAQ473

(10-04)
NEI 99-02 [Revision 7]

08/31/2013

F-42

EPS HPI HRS/ RHR

EDG MDP 

Running or 

Alternating+

MDP 

Standby

MDP 

Standby

TDP 

**

MDP 

Standby

Nine Mile Point 2 1.25 1 1 1 1 1.5

North Anna 1 & 2 1.25 2 1 1.25 1 1.5

Oconee 1, 2 & 3 3 * 2 1 1.25 1 1.5

Oyster Creek 1.25 1 3 1 1 3

Palisades 1.25 1 1.25 1.25 1 1.5

Palo Verde 1, 2 & 3 1.25 1 1.25 1.25 1 1.5

Peach Bottom 2 & 3 1.25 1 1 1 1 3

Perry 1.25 1 1 1 1 1.5

Pilgrim 1.25 1 1 1 1 3

Point Beach 1 & 2 1.25 1 1.25 1.25 1 1.5

Prairie Island 1 & 2 1.25 1 1.25 1 1 1.5

Quad Cities 1 & 2 1.25 1 1 1 1 3

River Bend 1.25 1 1 1 1 1.5

Robinson 2 1.25 1 1.25 1.25 1 1.5

Salem 1 & 2 1.25 1.25 1.25 1.25 1 1.5

San Onofre 2 & 3 1.25 1 2 1.25 1 1.5

Seabrook 1.25 1.25 1.25 1 1 1.5

Sequoyah 1 & 2 1.25 1.25 1.25 1.25 1 1.5

South Texas 1 & 2 2 1 2 2 1 1.5

St. Lucie 1 1.25 1 1.25 1.25 1 1.5

St. Lucie 2 1.25 1 1.25 1.25 1 1.5

Summer 1.25 2 1 1.25 1 1.5

Surry 1 & 2 1.25 2 1 1.25 1 1.5

Susquehanna 1 & 2 3 1 1 1 1 3

Three Mile Island 1 1.25 2 1 1.25 1 1.5

Turkey Point 3 & 4 1.25 1 3 1 3 1.5

Vermont Yankee 1.25 1 1 1 1 3

Vogtle 1 & 2 1.25 1.25 1.25 1.25 1 1.5

Waterford 3 1.25 1 2 1.25 1 1.5

Watts Bar 1 1.25 1.25 1.25 1.25 1 1.5

Wolf Creek 1.25 1.25 1.25 1.25 1 1.5

1 * hydroelectric units ** as applicable + 2 Alternating pumps are redundant pumps where one pump is normally running, that are 

3 operationally rotated on a periodic basis.

4

 SWS CCW All All

MDP 

Running or 

Alternating

MDP 

Standby

DDP ** MDP 

Running or 

Alternating

MDP 

Standby

MOVs 

and 

Breakers

AOVs, 

SOVs, 

HOVs

All 

Plants

3 1.5 1.25 1.5 2 2 1.5

5 ** as applicable

6

7

FAQ479

(11-05)
NEI 99-02 [Revision 7]

08/31/2013

F-43

1 Plant Specific-specific Common Cause Adjustment

2 The plant specific-specific correction factor should be calculated for each FV/UR ratio that is 

3 used in the index. If the option to use a different ratio for each failure mode of a component is 

4 used, then the ratio is calculated for each failure mode. The general form of a plant specific5 specific common cause adjustment factor is given by the equation:

∑

∑

=

= 















+

















= n

i

i

cc

n

i

i

FV

FV FV

A

1

1 6 . Eq. 5

7 Where:

8 n = is the number of components in a common cause group,

9 FVi = the FV for independent failure of component i,

10 and

11 FVcc = the FV for the common cause failure of components in the group.

12

13 In the expression above, the FVi are the values for the specific failure mode for the component 

14 group that was chosen because it resulted in the maximum [FV/UR] ratio. The FVcc is the FV 

15 that corresponds to all combinations of common cause events for that group of components for 

16 the same specific failure mode. Note that the FVcc may be a sum of individual FVcc values that 

17 represent different combinations of component failures in a common cause group.

18

19 For cooling water systems that have an initiator contribution, the FV values used should be from 

20 the non-initiator part of the model.

21

22 For example consider again a plant with three one hundred percent capacity emergency diesel 

23 generators. In this example, three failure modes for the EDG are modeled in the PRA, fail to start 

24 (FTS), fail to load (FTL) and fail to run (FTR). Common cause events exist for each of the three 

25 failure modes of the EDG in the following combinations:

26 1) Failure of all three EDGs,

27 2) Failure of EDG-A and EDG-B,

28 3) Failure of EDG-A and EDG-C,

29 4) Failure of EDG-B and EDG-C.

30 This results in a total of 12 common cause events.

31

32 Assume the maximum [FV/UR] resulted from the FTS failure mode, then the FVcc used in 

33 equation 5 would be the sum of the four common cause FTS events for the combinations listed 

34 above. 

35

36 It is recognized that there is significant variation in the methods used to model common cause. It 

37 is common that the 12 individual common cause events described above are combined into a 

38 fewer number of events in many PRAs. Correct application of the plant specific-specific method 

39 would, in this case, require the decomposition of the combined events and their related FV 

40 values into the individual parts. This can be accomplished by application of the following 

41 proportionality:
NEI 99-02 [Revision 7]

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F-44

total

part part total

UR

UR 1 FV = FV × Eq. 6

2 Returning to the example above, assume that common cause was modeled in the PRA by 

3 combining all failure modes for each specific combination of equipment modeled. Thus there 

4 would be four common cause events corresponding to the four possible equipment groupings 

5 listed above, but each of the common cause events would include the three failure modes FTS, 

6 FTL and FTR. Again, assume the FTS independent failure mode is the event that resulted in the 

7 maximum [FV/UR] ratio. The FVcc value to be used would be determined by determining the 

8 FTS contribution for each of the four common cause events. In the case of the event representing 

9 failure of all three EDGs this would be determined from

ABC

FTS

FTS

UR

UR FV FV ABC

ABC = ABC ×

10 .

11 Where,

12 FVFTSABC = the FV for the FTS failure mode and the failure of all three EDGs

13 FVABC = the event from the PRA representing the failure of all three EDGs due to all 

14 failure modes

15 URFTSABC = the failure probability for a FTS of all three EDGs, and

16 URABC = the failure probability for all failure modes for the failure of all three EDGs.

17

18 After this same calculation was performed for the remaining three common cause events, the 

19 value for FVCC to be used in equation 5 would then be calculated from:

FVcc = FVFTSABC + FVFTSAB + FVFTSAC + FVFTSBC 20

21

22 This value is used in equation 5 to determine the value of A. The final quantity used in equation 4 

23 is given by:

24 [FV/UR] max = A*[FV/UR]ind

25

26 In this case the individual values on the right hand side of the equation above are input to CDE.

27

28 F 2.3.5. BIRNBAUM IMPORTANCE

29 One of the rules used for determining the valves and circuit breakers to be monitored in this 

30 performance indicator permitted the exclusion of valves and circuit breakers with a Birnbaum 

31 importance less than 1.0E-06. To apply this screening rule the Birnbaum importance is 

32 calculated from the values derived in this section as:

33

34 B = CDF*A*[FV/UR]ind = CDF*[FV/UR]max

35

36 Ensure that the support system initiator correction (if applicable) and the common cause 

37 correction are included in the Birnbaum value used to exclude components from monitoring.

38

39
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F-45

1 F 2.3.6. CALCULATION OF URDBC , URLBC AND URRBC

Equation 3 includes the three quantities URDBC 2 , URLBC and URRBC which are the Bayesian 

3 corrected plant specific-specific values of unreliability for the failure modes fail on demand, 

4 fail to load/run and fail to run respectively. This section discusses the calculation of these 

5 values. As discussed in section F 2.3 failure modes considered for each component type are 

6 provided below.

7

8 Valves and Breakers:

9 Fail on Demand (Open/Close)

10 Pumps:

11 Fail on Demand (Start)

12 Fail to Run

13 Emergency Diesel Generators:

14 Fail on Demand (Start)

15 Fail to Load/Run

16 Fail to Run

17

URDBC is calculated as follows.1 18

( )

( )

a b D

N a UR d

DBC

+ +

+ 19 = . Eq. 7

20 where in this expression:

21 Nd is the total number of failures on demand during the previous 12 quarters,

22 D is the total number of demands during the previous 12 quarters determined in 

23 section 2.2.1

24 The values a and b are parameters of the industry prior, derived from 

25 industry experience (see Table 48).

26

27 In the calculation of equation 7 the numbers of demands and failures is the sum of all demands 

28 and failures for similar components within each system. Do not sum across units for a multi-unit 

29 plant. For example, for a plant with two trains of Emergency Diesel Generators, the demands and 

30 failures for both trains would be added together for one evaluation of equation 7 which would be 

31 used for both trains of EDGs.

32

33 URLBC is calculated as follows.

( )

( )

a b D

N a UR l

LBC

+ +

+ 34 = . Eq. 8

35

36 where in this expression:

37 Nl is the total number of failures to load (applicable to EDG only) during the 

38 previous 12 quarters,

39 D is the total number of load demands during the previous 12 quarters determined 

40 in section 2.2.1

 1 Atwood, Corwin L., Constrained noninformative priors in risk assessment, Reliability Engineering and System Safety, 53 (1996; 37-46)

Linthicum

3/3/12

Dorathy 

8/14/13
NEI 99-02 [Revision 7]

08/31/2013

F-46

1 The values a and b are parameters of the industry prior, derived from industry 

2 experience (see Table 4).

3

4 In the calculation of equation 8 the numbers of demands and failures is the sum of all demands 

5 and failures for similar components within each system. 

6

7 URRBC is calculated as follows.

m

r

r RBC T

T b

N a UR *

( )

( )

+

+ 8 = Eq. 9

9 where:

10 Nr is the total number of failures to run during the previous 12 quarters 

11 (determined in section 2.2.2),

12 Tr is the total number of run hours during the previous 12 quarters (determined in 

13 section 2.2.1) 

14 Tm is the mission time for the component based on plant specific-specific PRA

15 model assumptions. For EDGs, the mission time associated with the Failure To 

Run Basic Event with the highest Birnbaum value is to be used.1 16 For all other 

17 equipment, where there is more than one mission time for different initiating 

18 events or sequences (e.g., turbine-driven AFW pump for loss of offsite power 

19 with recovery versus loss of Feedwater), the longest mission time is to be used.

20 and

21 a and b are parameters of the industry prior, derived from industry experience (see 

22 Table 4).

23

24 Note, however, that even though a PRA mission time can be less than 24 hours, when 

25 determining if an MSPI failure has occurred, the monitored component must have been able to 

26 perform its monitored function for a 24 hour run.

27

28 In the calculation of equation 9 the numbers of demands and run hours is the sum of all run hours 

29 and failures for similar components within each system. Do not sum across units for a multi-unit 

30 plant, unless the system is shared between multiple units. For example, a plant with two trains of 

31 Emergency Diesel Generators, the run hours and failures for both trains would be added together 

32 for one evaluation of equation 9 which would be used for both trains of EDGs.

33

 1 NOTE: The basis document should be revised in 4Q2009 and applied for1Q2010 data. Though the 

PRA mission time used in the MSPI calculations can be less than 24 hours for the EDGs, when 

determining if an MSPI failure has occurred, the EDG must have been able to perform its 

monitored function for a 24 hour run.

Linthicum

3/3/12

Linthicum

3/3/12

Linthicum

3/3/12
NEI 99-02 [Revision 7]

08/31/2013

F-47

1 F 2.3.7. BASELINE UNRELIABILITY VALUES

2 The baseline values for unreliability are contained in Table 8 and remain fixed.

3

4 Table 8. Industry Priors and Parameters for Unreliability

5

Component Failure Mode a a b a Industry 

MeanValue b

URBLC

Circuit Breaker Fail to open (or close) 4.99E-1 6.23E+2 8.00E-4

Hydraulic-operated valve Fail to open (or close) 4.98E-1 4.98E+2 1.00E-3

Motor-operated valve Fail to open (or close) 4.99E-1 7.12E+2 7.00E-4

Solenoid-operated valve Fail to open (or close) 4.98E-1 4.98E+2 1.00E-3

Air-operated valve Fail to open (or close) 4.98E-1 4.98E+2 1.00E-3

Motor-driven pump, 

standby

Fail to start 4.97E-1 2.61E+2 1.90E-3

Fail to run 5.00E-1 1.00E+4 5.00E-5

Motor-driven pump, 

running or alternating

Fail to start 4.98E-1 4.98E+2 1.00E-3

Fail to run 5.00E-1 1.00E+5 5.00E-6

Turbine-driven pump, 

AFWS

Fail to start 4.85E-1 5.33E+1 9.00E-3

Fail to run 5.00E-1 2.50E+3 2.00E-4

Turbine-driven pump, HPCI 

or RCIC

Fail to start 4.78E-1 3.63E+1 1.30E-2

Fail to run 5.00E-1 2.50E+3 2.00E-4

Diesel-driven pump, AFWS Fail to start 4.80E-1 3.95E+1 1.20E-2

Fail to run 5.00E-1 2.50E+3 2.00E-4

Emergency diesel generator Fail to start 4.92E-1 9.79E+1 5.00E-3

Fail to load/run 4.95E-1 1.64E+2 3.00E-3

Fail to run 5.00E-1 6.25E+2 8.00E-4

6

7 a. A constrained, non-informative prior is assumed. For failure to run events, a = 0.5 and b = 

8 (a)/(mean rate). For failure upon demand events, a is a function of the mean probability:

9

Mean Probability a

0.0 to 0.0025 0.50

>0.0025 to 0.010 0.49

>0.010 to 0.016 0.48

>0.016 to 0.023 0.47

>0.023 to 0.027 0.46

10

11 Then b = (a)(1.0 - mean probability)/(mean probability).

12

13 b. Failure to run events occurring within the first hour of operation are included within the 

14 failure to start failure mode. Failure to run events occurring after the first hour of operation

15 (after the first hour following closure of the load breaker for emergency power generators)

16 are included within the failure to run failure mode. 

17

Linthicum

3/3/12
NEI 99-02 [Revision 7]

08/31/2013

F-48

1 F 3. ESTABLISHING STATISTICAL SIGNIFICANCE

2 This performance indicator establishes an acceptable level of performance for the monitored 

3 systems that is reflected in the baseline reliability values in Table 4. Plant specific-specific

4 differences from this acceptable performance are interpreted in the context of the risk 

5 significance of the difference from the acceptable performance level. It is expected that a system 

6 that is performing at an acceptable performance level will see variations in performance over the 

7 monitoring period. For example a system may, on average, see three failures in a three year 

8 period at the accepted level of reliability. It is expected, due to normal performance variation, 

9 that this system will sometimes experience two or four failures in a three year period. It is not 

10 appropriate that a system should be placed in a white performance band due to expected 

11 variation in measured performance. This problem is most noticeable for risk sensitive systems 

12 that have few demands in the three year monitoring period.

13

14 This problem is resolved by applying a limit of 5.0E-07 to the magnitude of the most significant 

15 failure in a system. This ensures that one failure beyond the expected number of failures alone 

16 cannot result in MSPI > 1.0E-06. A MSPI > 1.0E-06 will still be a possible result if there is 

17 significant system unavailability, or failures in other components in the system.

18

19 This limit on the maximum value of the most significant failure in a system is only applied if the 

20 MSPI value calculated without the application of the limit is less than or equal to 1.0E-05.

21 This calculation will be performed by the CDE software; no additional input values are required.

22

23 F 4. CALCULATION OF SYSTEM COMPONENT PERFORMANCE LIMITS

24 The mitigating systems chosen to be monitored are generally the most important systems in 

25 nuclear power stations. However, in some cases the system may not be as important at a specific 

26 station. This is generally due to specific features at a plant, such as diverse methods of achieving 

27 the same function as the monitored system. In these cases a significant degradation in 

28 performance could occur before the risk significance reached a point where the MSPI would 

29 cross the white boundary. In cases such as this it is not likely that the performance degradation 

30 would be limited to that one system and may well involve cross cutting issues that would 

31 potentially affect the performance of other mitigating systems.

32 A performance based criterion for determining declining performance is used as an additional 

33 decision criterion for determining that performance of a mitigating system has degraded to the 

34 white band. This decision is based on deviation of system performance from expected 

35 performance. The decision criterion was developed such that a system is placed in the white 

36 performance band when there is high confidence that system performance has degraded even

37 though MSPI ≤< 1.0E-06.

38

39 The criterion is applied to each component type in a system. If the number of failures in a 36 

40 month period for a component type exceeds a performance based limit, then the system is 

41 considered to be performing at a white level, regardless of the MSPI calculated value. The 

42 performance based limit is calculated in two steps:

43 1. Determine the expected number of failures for a component type and

44 2. Calculate the performance limit from this value.

Zimmerman

2/7/13
NEI 99-02 [Revision 7]

08/31/2013

F-49

1 The expected number of failures is calculated from the relation

2 Fe = Nd * p + λ *Tr

3 Where:

4 Nd is the number of demands

5 p is the probability of failure on demand, from Table 8 (URLBC).

6 λ is the failure rate, from Table 8 (URLBC)

7 Tr is the runtime of the component

8

9 This value is used in the following expression to determine the maximum number of failures:

10 Fm = 4.65* Fe + 4.2

11

12 If the actual number of failures (Fa) of a similar group of components (components that are 

13 grouped for the purpose of pooling data) within a system in a 36 month period exceeds Fm, then 

14 the system is placed in the white performance band or the level dictated by the MSPI calculation 

15 if the MSPI calculation is > 1E-5.

16

17 This calculation will be performed by the CDE software, no additional input values are required.

18

19 F 5. ADDITIONAL GUIDANCE FOR SPECIFIC SYSTEMS

20 This section identifies the potential monitored functions for each system and describes typical 

21 system scopes and train determinations.

22

23 Emergency AC Power Systems

24

25 Scope

26 The function monitored for the emergency AC power system is the ability of the emergency 

27 generators to provide AC power to the class 1E buses following a loss of off-site power. The 

28 emergency AC power system is typically comprised of two or more independent emergency 

29 generators that provide AC power to class 1E buses following a loss of off-site power. The 

30 emergency generator dedicated to providing AC power to the high pressure core spray system in 

31 BWRs is not within the scope of emergency AC power.

32

33 The EDG component boundary includes the generator body, generator actuator, lubrication 

system (local), fuel system (local or day tank and fuel oil transfer pumps/valves1 34 ), cooling 

35 components (local), startup air system receiver, exhaust and combustion air system, dedicated 

36 diesel battery (which is not part of the normal DC distribution system), individual diesel 

37 generator control system, cooling water isolation valves, circuit breaker for supply to safeguard 

38 buses and their associated control circuit. Air compressors are not part of the EDG component

39 boundary.

40

41 The fuel oil transfer pumps required to meet the PRA mission time are within the system EDG 

42 component boundary, but are not considered to be a separate monitored component for reliability 

43 monitoring in the EDG system. Additionally they are monitored for contribution to train 

44 unavailability only if the fuel oil transfer pump(s) is (are) required to meet the EDG mission time 

 1

The word “valves” is included here for plants with a gravity-fed fuel oil transfer system. For these designs, the valve(s) provide the functional

equivalent of the FOTP in pump-fed designs.

FAQ484

(11-07)

FAQ484

(11-07)
NEI 99-02 [Revision 7]

08/31/2013

F-50

1 (as specified in Section F.2.2.2 and as defined in the MSPI Definition of Terms section). an EDG 

2 train can only be supplied from a single transfer pump. Where the capability exists to supply an 

3 EDG from redundant transfer pumps, the contribution to the EDG MSPI from these components 

4 is expected to be small compared to the contribution from the EDG itself. Monitoring the transfer 

5 pumps for reliability is not practical because accurate estimations of demands and run hours are 

6 not feasible (due to the auto start and stop feature of the pump) considering the expected small 

7 contribution to the index. (See also the EDG Failure-to-Run definition in Section F.2.2.2 as 

8 revised by FAQ 11-08.)

9

10 Emergency generators that are not safety grade, or that serve a backup role only (e.g., an 

11 alternate AC power source), are not included in the performance reporting.

12

13 Train Determination

14 The number of emergency AC power system trains for a unit is equal to the number of class 1E 

15 emergency generators that are available to power safe-shutdown loads in the event of a loss of 

16 off-site power for that unit. There are three typical configurations for EDGs at a multi-unit 

17 station:

18 1. EDGs dedicated to only one unit.

19 2. One or more EDGs are available to “swing” to either unit 

20 3. All EDGs can supply all units

21 For configuration 1, the number of trains for a unit is equal to the number of EDGs dedicated to 

22 the unit. For configuration 2, the number of trains for a unit is equal to the number of dedicated 

23 EDGs for that unit plus the number of “swing” EDGs available to that unit (i.e., The “swing” 

24 EDGs are included in the train count for each unit). For configuration 3, the number of trains is 

25 equal to the number of EDGs.

26

27 Clarifying Notes

28

29 An EDG is not considered to have failed due to any of the following events:

30 • spurious operation of a trip that would be bypassed in a loss of offsite power event

31 • malfunction of equipment that is not required to operate during a loss of offsite power event 

32 (e.g., circuitry used to synchronize the EDG with off-site power sources)

33 • failure to start because a redundant portion of the starting system was intentionally disabled 

34 for test purposes, if followed by a successful start with the starting system in its normal 

35 alignment

36

37

FAQ484

(11-07)
NEI 99-02 [Revision 7]

08/31/2013

F-51

1 BWR High Pressure Injection Systems

2

3 (High Pressure Coolant Injection, High Pressure Core Spray, and Feedwater Coolant 

4 Injection)

5

6 Scope

7 These systems function at high pressure to maintain reactor coolant inventory and to remove 

8 decay heat.

9

10 The function monitored for the indicator is the ability of the monitored system to take suction 

11 from the suppression pool (and from the condensate storage tank, if required to meet the PRA

12 success criteria and mission times) and inject into the reactor vessel. . The mitigation of ATWS 

13 events with a high pressure injection system is not considered a function to be monitored by the 

14 MSPI. (Note, however, that the FV values will include ATWS events).

15

16 Plants should monitor either the high-pressure coolant injection (HPCI), the high-pressure core 

17 spray (HPCS), or the feedwater coolant injection (FWCI) system, whichever is installed. The 

18 turbine and governor and associated piping and valves for turbine steam supply and exhaust are 

19 within the scope of the HPCI system. The flow path for the steam supply to a turbine driven 

20 pump is included from the steam source (main steam lines) to the pump turbine. The motor 

21 driven pump for HPCS and FWCI are in scope along with any valves that must change state such 

22 as low flow valves in FWCI. Valves in the feedwater line are not considered within the scope of 

23 these systems because they are normally open during operation and do not need to change state 

24 for these systems to operate. However waterside valves up to the feedwater line are in scope if 

25 they need to change state such as the HPCI injection valve. 

26

27 The emergency generator dedicated to providing AC power to the high-pressure core spray 

28 system is included in the scope of the HPCS. The HPCS system typically includes a "water leg" 

29 pump to prevent water hammer in the HPCS piping to the reactor vessel. The "water leg" pump 

30 and valves in the "water leg" pump flow path are ancillary components and are not included in 

31 the scope of the HPCS system. Unavailability is not included while critical if the system is below 

32 steam pressure specified in technical specifications at which the system can be operated.

33

34 Oyster Creek

35 For Oyster Creek the design does not include any high pressure injection system beyond the 

36 normal feedwater system. For the BWR high pressure injection system, Oyster Creek will 

37 monitor the Core Spray system, a low pressure injection system. 

38

39 Train Determination

40 The HPCI and HPCS systems are considered single-train systems. The booster pump and other 

41 small pumps are ancillary components not used in determining the number of trains. The effect 

42 of these pumps on system performance is included in the system indicator to the extent their 

43 failure detracts from the ability of the system to perform its monitored function. For the FWCI 

44 system, the number of trains is determined by the number of feedwater pumps. The number of 

45 condensate and feedwater booster pumps are not used to determine the number of trains. It is 

46 recommended that the DG that provides dedicated power to the HPCS system be monitored as a 
NEI 99-02 [Revision 7]

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F-52

1 separate “train” (or segment) for unavailability as the risk importance of the DG is less 

2 different than the fluid parts of the system.

3

4 Reactor Core Isolation Cooling 

5 (or Isolation Condenser)

6

7 Scope

8 This system functions at high pressure to remove decay heat. The RCIC system also functions to 

9 maintain reactor coolant inventory.

10

11 The function monitored for the indicator is the ability of the RCIC system to cool the reactor 

12 vessel core and provide makeup water by taking suction from the suppression pool (and from the 

13 condensate storage tank, if required to meet the PRA success criteria and mission times) and 

14 inject into the reactor vessel

15

16 The Reactor Core Isolation Cooling (RCIC) system turbine, governor, and associated piping and 

17 valves for steam supply and exhaust are within the scope of the RCIC system. Valves in the 

18 feedwater line are not considered within the scope of the RCIC system because they are normally 

19 open during operation and do not have to change state for RCIC to perform its function.

20

21 The function monitored for the Isolation Condenser is the ability to cool the reactor by 

22 transferring heat from the reactor to the Isolation Condenser water volume. The Isolation 

23 Condenser and inlet valves are within the scope of Isolation Condenser system along with the 

24 connecting active valve for isolation condenser makeup. Unavailability is not included while 

25 critical if the system is below steam pressure specified in technical specifications at which the 

26 system can be operated.

27

28 Train Determination

29 The RCIC system is considered a single-train system. The condensate and vacuum pumps are 

30 ancillary components not used in determining the number of trains. The effect of these pumps on 

31 RCIC performance is included in the system indicator to the extent that a component failure 

32 results in an inability of the system to perform its monitored function.

33

34 For Isolation Condensers, a train is a flow path from the reactor to the isolation condenser back 

35 to the reactor. The connecting active valve for isolation condenser makeup is included in the 

36 train.

37

38 BWR Residual Heat Removal Systems

39

40 Scope

41 The function monitored for the BWR residual heat removal (RHR) system is the ability of the 

42 RHR system to provide suppression pool cooling. The pumps, heat exchangers, and associated 

43 piping and valves for this function are included in the scope of the RHR system. If an RHR 

44 system has pumps that do not perform a heat removal function (e.g. cannot connect to a heat 

45 exchanger, dedicated LPCI pumps) they are not included in the scope of this indicator. 

46

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1

2 Train Determination

3 The number of trains in the RHR system is determined as follows. If the number of heat 

4 exchangers and pumps is the same, the number of heat exchangers determines the number of 

5 trains. If the number of heat exchangers and pumps are different, the number of trains should be 

6 that used by the PRA model. Typically this would be two pumps and one heat exchanger 

7 forming a train where the train is unavailable only if both pumps are unavailable, or two pumps 

8 and one heat exchanger forming two trains with the heat exchanger as a shared component where 

9 a train is unavailable if a pump is unavailable and both trains are unavailable if the heat 

10 exchanger is unavailable.

11

12 PWR High Pressure Safety Injection Systems

13

14 Scope

15 These systems are used primarily to maintain reactor coolant inventory at high RCS pressures 

16 following a loss of reactor coolant. HPSI system operation involves transferring an initial supply 

17 of water from the refueling water storage tank (RWST) to cold leg piping of the reactor coolant 

18 system. Once the RWST inventory is depleted, recirculation of water from the reactor building 

19 emergency sump is required. The function monitored for HPSI is the ability of a HPSI train to 

20 take a suction from the primary water source (typically, a borated water tank), or from the 

21 containment emergency sump, and inject into the reactor coolant system.

22

23 The scope includes the pumps and associated piping and valves from both the refueling water 

24 storage tank and from the containment sump to the pumps, and from the pumps into the reactor 

25 coolant system piping. For plants where the high-pressure injection pump takes suction from the 

26 residual heat removal pumps, the residual heat removal pump discharge header isolation valve to 

27 the HPSI pump suction is included in the scope of HPSI system. Some components may be 

28 included in the scope of more than one train. For example, cold-leg injection lines may be fed 

29 from a common header that is supplied by both HPSI trains. In these cases, the effects of testing 

30 or component failures in an injection line should be reported in both trains. 

31

32 Train Determination

33 In general, the number of HPSI system trains is defined by the number of high head injection 

34 paths that provide cold-leg and/or hot-leg injection capability, as applicable.

35

36 For Babcock and Wilcox (B&W) reactors, the design features centrifugal multi-stage pumps 

37 used for high pressure injection (about 2,500 psig) and no hot-leg injection path. Recirculation 

38 from the containment sump requires lining up the HPI pump suctions to the Low-Pressure 

39 Injection (LPI) pump discharges for adequate NPSH. This is typically a two-train system, with 

40 an installed spare pump (depending on plant-specific design) that can be aligned to either train.

41

42 For two-loop Westinghouse plants, the pumps operate at a lower pressure (about 1600 psig) and 

43 there may be a hot-leg injection path in addition to a cold-leg injection path (both are included as 

44 a part of the train).

45
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1 For Westinghouse three-loop plants, the design features three centrifugal pumps that operate at 

2 high pressure (about 2500 psig), a cold-leg injection path through the BIT (with two trains of 

3 redundant valves), an alternate cold-leg injection path, and two hot-leg injection paths. One of 

4 the pumps is considered an installed spare. Recirculation is provided by taking suction from the 

5 RHR pump discharges. A train consists of a pump, the pump suction valves and boron injection 

6 tank (BIT) injection line valves electrically associated with the pump, and the associated hot-leg 

7 injection path. The alternate cold-leg injection path is required for recirculation, and should be 

8 included in the train with which its isolation valve is electrically associated. This represents a 

9 two-train HPSI system.

10

11 For Four-loop Westinghouse plants, the design features two centrifugal pumps that operate at 

12 high pressure (about 2500 psig), two centrifugal pumps that operate at an intermediate pressure 

13 (about 1600 psig), a BIT injection path (with two trains of injection valves), a cold-leg safety 

14 injection path, and two hot-leg injection paths. Recirculation is provided by taking suction from 

15 the RHR pump discharges. Each of two high pressure trains is comprised of a high pressure 

16 centrifugal pump, the pump suction valves and BIT valves that are electrically associated with 

17 the pump. Each of two intermediate pressure trains is comprised of the safety injection pump, the 

18 suction valves and the hot-leg injection valves electrically associated with the pump. The cold19 leg safety injection path can be fed with either safety injection pump, thus it should be associated 

20 with both intermediate pressure trains. This HPSI system is considered a four-train system for 

21 monitoring purposes.

22

23 For Combustion Engineering (CE) plants, the design features two or three centrifugal pumps that 

24 operate at intermediate pressure (about 1300 psig) and provide flow to four cold-leg injection 

25 paths or two hot-leg injection paths. In most designs, the HPSI pumps take suction directly from 

26 the containment sump for recirculation. In these cases, the sump suction valves are included 

27 within the scope of the HPSI system. This is a two-train system (two trains of combined cold-leg 

28 and hot-leg injection capability). One of the three pumps is typically an installed spare that can 

29 be aligned to either train or only to one of the trains (depending on plant-specific design).

30

31 PWR Auxiliary Feedwater Systems

32

33 Scope

34 The function of the AFW system is to provide decay heat removal via the steam generators to 

35 cool down and depressurize the reactor coolant system following a reactor trip. The mitigation of 

36 ATWS events with the AFW system is not considered a function to be monitored by the MSPI. 

37 (Note, however, that the FV values will include ATWS events). 

38

39 The function monitored for the indicator is the ability of the AFW system to autostart, take 

40 a suction from a water source (typically, the condensate storage tank and if required to meet 

41 the PRA success criteria and mission time, from an alternate source) and to inject into at least 

42 one steam generator.

43

44 The scope of the auxiliary feedwater (AFW) or emergency feedwater (EFW) systems includes 

45 the pumps, the condensate storage tank (CST), and the components in the flow paths from 

46 between the pumps and the condensate storage tankCST, and, if required, the valve(s) that 

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1 connect the alternative water source to the auxiliary feedwater system. The flow path for the 

2 steam supply to a turbine driven pump is included from the steam source (main steam lines) to 

3 the pump turbine. Pumps included in the Technical Specifications (subject to a Limiting 

4 Condition for Operation) are included in the scope of this indicator. Some initiating events, such 

5 as a feedwater line break, may require isolation of AFW flow to the affected steam generator to 

6 prevent flow diversion from the unaffected steam generator. This function should be considered 

7 a monitored function if it is required.

8

9 Train Determination

10 The number of trains is determined primarily by the number of parallel pumps. For example, a 

11 system with three pumps is defined as a three-train system, whether it feeds two, three, or four 

12 injection lines, and regardless of the flow capacity of the pumps. Some components may be 

13 included in the scope of more than one train. For example, one set of flow regulating valves and 

14 isolation valves in a three-pump, two-steam generator system are included in the motor-driven 

15 pump train with which they are electrically associated, but they are also included (along with the 

16 redundant set of valves) in the turbine-driven pump train. In these instances, the effects of testing 

17 or failure of the valves should be reported in both affected trains. Similarly, when two trains 

18 provide flow to a common header, the effect of isolation or flow regulating valve failures in 

19 paths connected to the header should be considered in both trains.

20

21 PWR Residual Heat Removal System 

22

23 Scope

24 The function monitored for the PWR residual heat removal (RHR) system is the long term decay 

25 heat removal function to mitigate those transients that cannot rely on the steam generators alone 

26 for decay heat removal. These typically include the low-pressure injection function and the 

27 recirculation mode used to cool and recirculate water from the containment sump following 

28 depletion of RWST inventory to provide decay heat removal. The pumps, heat exchangers, and 

29 associated piping and valves for those functions are included in the scope of the RHR system. 

30 Containment spray function should be included if it provides a risk significant decay heat 

31 removal function. Containment spray systems that only provide containment pressure control are 

32 not included.

33

34 CE Designed NSSS

35 CE ECCS designs differ from the description above. CE designs run all ECCS pumps during the 

36 injection phase (Containment Spray (CS), High Pressure Safety Injection (HPSI), and Low 

37 Pressure Safety Injection (LPSI)), and on Recirculation Actuation Signal (RAS), the LPSI 

38 pumps are automatically shutdown, and the suction of the HPSI and CS pumps is shifted to the 

39 containment sump. The HPSI pumps then provide the recirculation phase core injection, and the 

40 CS pumps by drawing inventory out of the sump, cooling it in heat exchangers, and spraying the 

41 cooled water into containment, support the core injection inventory cooling.

42

43 For the RHR function the CE plant design uses HPSI to take a suction from the sump, CS to cool 

44 the fluid, and HPSI to inject at low pressure into the RCS. Due to these design differences, CE 

45 plants with this design should monitor this function in the following manner. The two 

46 containment spray pumps and associated coolers should be counted as two trains of RHR 
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1 providing the recirculation cooling. Therefore, for the CE designed plants two trains should be 

2 monitored, as follows:

3 • Train 1 (recirculation mode) Consisting of the "A" containment spray pump, the required 

4 spray pump heat exchanger and associated flow path valves.

5 • Train 2 (recirculation mode) Consisting of the "B" containment spray pump, the required 

6 spray pump heat exchanger and associated flow path valves.

7

8 Surry, North Anna and Beaver Valley Unit 1 

9 The at power RHR function, is provided by two 100% low head safety injection pumps taking 

10 suction from the containment sump and injecting to the RCS at low pressure and with the heat 

11 exchanger function (containment sump water cooling) provided by four 50% containment 

12 recirculation spray system pumps and heat exchangers.

13 The RHR Performance Indicator should be calculated as follows. The low head safety injection 

14 and recirculation spray pumps and associated coolers should be counted as two trains of RHR 

15 providing the recirculation cooling, function as follows:

16 • “A” train consisting of the “A” LHSI pump, associated MOVS and the required “A” train 

17 recirculation spray pumps heat exchangers, and MOVS.

18 • “B” train consisting of the “B” LHSI pump, associated MOVS and the required “B” train 

19 recirculation spray pumps, heat exchangers, and MOVS.

20

21 Beaver Valley Unit 2 

22 The at power RHR function, is provided by two 100% containment recirculation spray pumps 

23 taking suction from the containment sump, and injecting to the RCS at low pressure. The heat 

24 exchanger function is provided by two 100% capacity containment recirculation spray system 

25 heat exchangers, one per train. The RHR Performance Indicator should be calculated as follows. 

26 The two containment recirculation spray pumps and associated coolers should be counted as two 

27 trains of RHR providing the recirculation cooling.

28 Two trains should be monitored as follows:

29 • Train 1 (recirculation mode) Consisting of the containment recirculation spray pump 

30 associated MOVS and the required recirculation spray pump heat exchanger and MOVS.

31 • Train 2 (recirculation mode) Consisting of containment recirculation spray pump 

32 associated MOVS and the required recirculation spray pump heat exchanger, and MOVS.

33

34 Train Determination

35 The number of trains in the RHR system is determined by the number of parallel RHR heat 

36 exchangers. Some components are used to provide more than one function of RHR. If a 

37 component cannot perform as designed, rendering its associated train incapable of meeting one 

38 of the monitored functions, then the train is considered to be failed. Unavailable hours would be 

39 reported as a result of the component failure.

40
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1 Cooling Water Support System

2

3 Scope

4 The functions monitored for the cooling water support system are those functions that are 

5 necessary (i.e. Technical Specification-required) to provide for direct cooling of the components 

6 in the other monitored systemstrains or segments of systems supported by the cooling water 

7 system. It does not include indirect cooling provided by room coolers or other HVAC features.

8

9 Systems that provide this function typically include service water and component cooling water 

10 or their cooling water equivalents. Service water systems are typically open “raw water” 

11 systems that use natural sources of water such as rivers, lakes, or oceans. Component cooling 

12 water systems are typically closed “clean water” systems.

13

14 Pumps, valves, heat exchangers and line segments that are necessary to provide cooling to the 

15 other monitored trains or segments of system(s) supported by the cooling water system systems 

16 are included within the cooling water system scope boundary up to, but not including, the last 

17 isolation valve(s) that connects the cooling water support system to components in a single 

18 monitored train or segment of the supported system. This last isolation valve is included within 

19 the other boundary of the monitored train or segment of the supported system boundary. If 

20 theThe last valve(s) that provides cooling to SSCs in more than one monitored train or segment 

21 of supported system(s), then it is included within the boundary of the cooling water support 

22 system. All valves (e.g., manual isolation valves or motor operated valves) in a cooling water 

23 line to a single monitored train or segment of a supported system are included within the 

24 boundary of the monitored train or segment of the supported system. Figure F-6 depicts this 

25 concept and the treatment of multiple isolation valves. The SSCs outside the dashed boxes are 

26 included within the boundary of the cooling water system. The SSCs within the dashed boxes 

27 are included within the boundaries of the supported systems.Service water systems are typically 

28 open “raw water” systems that use natural sources of water such as rivers, lakes or oceans. 

29 Component Cooling Water systems are typically closed “clean water” systems.

30

31 Valves in the cooling water support system that must close to ensure sufficient cooling to the 

32 other monitored system components to meet risk significant functions are included in the system 

33 boundary.

34

35 If a cooling water system provides cooling to only one monitored system, then it should be

36 included in the scope of that monitored system. Systems that are dedicated to cooling RHR heat 

37 exchangers only are included in the cooling water support system scope. 

38

39 Train Determination

40 The number of trains in the Cooling Water Support System will vary considerably from plant to 

41 plant. The way these functions are modeled in the plant-specific PRA will determine a logical 

42 approach for train determination. For example, if the PRA modeled separate pump and line 

43 segments, then the number of pumps and line segments would be the number of trains. 

44

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1 Clarifying Notes

2 Service water pump strainers, cyclone separators, and traveling screens are not considered to be 

3 monitored components and are therefore not part of URI. However, clogging of strainers and 

4 screens that render the train unavailable to perform its monitored cooling function (which 

5 includes the mission times) are included in UAI. Note, however, if the service water pumps fail 

6 due to a problem with the strainers, cyclone separators, or traveling screens, the failure is 

7 included in the URI.

8

9

10 F 6. CALCULATION OF THE BIRNBAUM IMPORTANCE BY REQUANTIFICATION

11 This section provides an alternative to the method outlined in sections F 1.3.1-F 1.3.3 and F 

12 2.3.1-F 2.3.3. If you are using the method outlined in this section is used, do not perform the 

13 calculations outlined in sections F 1.3.1-F 1.3.3 and F 2.3.1-F 2.3.3 are not applicable.

14 The truncation level used for the method described in this section should be sufficient to 

15 provide a converged value of CDF. CDF is considered to be converged when decreasing the 

16 truncation level by a decade results in a change in CDF of less than 5%.

17 The Birnbaum importance measure can be calculated from:

18 B = CDF1 − CDF0

19 or

p

CDF CDF B B

−

− = 1

1 20

21 Where

22 CDF1 is the Core Damage Frequency with the failure probability for the component (any 

23 representative basic event) set to one,

24 CDF0 is the Core Damage Frequency with the failure probability for the component (any 

25 representative basic event) set to zero,

26 CDFB is the Base Case Core Damage Frequency,

27 and

28 p is the failure probability of the representative basic event.

29 As a special case, if the component is truncated from the base case then

30 CDFB = CDF0

31 and

32 B = CDF1 − CDFB

33

34 With the Birnbaum importance calculated directly by re-quantification, the CDE input values 

35 must be calculated from this quantity.

36

37 The CDF value input to CDE for this method is the value of CDFB from the baseline 

38 quantification. 

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1

2 The value of UA or UR is taken from the representative basic event (p) used in the 

3 quantification above. The FV value is then calculated from the expression

4

CDF

B p FV*

5 = .

6
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1 Figure F-1

2

3 * The Fuel Oil Transfer Pump(s)/Valve(s) are is included in the EDG System Component Boundary. See Section 5 for monitoring requirements.

DC Power

ESFAS/Sequencer

Room Cooling Cooling Water

Fuel Oil Transfer EDG Component Boundary Pump/Valve*

EDG 

Breaker Lubrication System

Class 1E Bus

Diesel Engine

Control and 

Protection System

Starting Air System 

Receiver

Combustion Air 

System and Supply

Jacket 

Water

Fuel Oil 

System

Fuel Oil Day 

Tank

Generator

Exciter and 

Voltage 

Regulator

Exhaust 

System

Governor and 

Control System

Isolation 

Valve

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1

2

Controls

Breaker

Motor Operator

Motor Driven Pump Boundary

Pump

ESFAS Controls

Breaker

Motor Operator

MOV Boundary

ESFAS

Figure F-2 Figure F-3
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1

2 Figure F-4

3

4

Controls

Turbine and Control 

Valve

Turbine Driven Pump Boundary

Pump

ESFAS
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1

2 Figure F-5

3

4

5

6

7

8

T

A

N

K

Monitored 

Components

Monitored 

Components

Non-monitored 

Components

(1 of 2 valves per train

success criteria)

(1 of 2 valves per system

success criteria)
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1 Figure F-6

2

Pump

System 1

Train A

System 2

Train A

System 3

Train A

Supply

Train Boundary

Train Boundary

Train Boundary

Return

Return

Return

3

4

5

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1 APPENDIX G

2 MSPI Basis Document Development

3

4

5 To implement the Mitigating Systems Performance Index (MSPI), Licensees will develop a plant

6 specific-specific basis document that documents the information and assumptions used to 

7 calculate the Reactor Oversight Program (ROP) MSPI. This basis document is necessary to 

8 support the NRC inspection process, and to record the assumptions and data used in developing 

9 the MSPI on each site. A summary of any changes to the basis document are noted in the 

10 comment section of the quarterly data submission to the NRC.

11

12 The Basis document will have two major sections. The first described below will document the 

13 information used in developing the MSPI. The second section will document the conformance 

14 of the plant specific PRA to the requirements that are outlined in this appendix.

15

16 G 1. MSPI Data

17

18 The basis document provides a separate section for each monitored system as defined in Section 

19 2.2 of NEI 99-02. The section for each monitored system contains the following subsections: 

20

21 G 1.1 System Boundaries

22 This section contains a description of the boundaries for each train of the monitored system. A 

23 plant drawing or figure (training type figure) should be included and marked adequately (i.e., 

24 highlighted trains) to show the boundaries. The guidance for determining the boundaries is 

25 provided in Appendix F, Section 1.1 of NEI 99-02.

26

27 G 1.2 Risk Significant Functions

28 This section lists the risk significant functions for each train of the monitored system. Risk 

29 Significant Functions are defined in section 2.2 of NEI 99-02. Additional detail is given in 

30 Appendix F, Section 1.1.1 and Section 5 “Additional Guidance for Specific Systems”. A single 

31 list for the system may be used as long as any differences between trains are clearly identified. 

32 This section may also be combined with the section on Success Criteria if a combination of 

33 information into a table format is desired. If none of the functions for the system are considered 

34 risk significant, identify the monitored function as defined in section F 1.1.1

35

36 G 1.3 Success Criteria

37 This section documents the success criteria as defined in Section 2.2 of NEI 99-02 for each of the 

38 identified monitored functions for the system. Additional detail is given in Appendix F, Section 

39 2.1.1. The criteria used are the documented PRA success criteria. 

40

41 • If the licensee has chosen to use design basis success criteria in the PRA, then provide a 

42 statement in this section that states the PRA uses design basis success criteria.

43 • If success criteria from the PRA are different from the design basis, then the specific 

44 differences from the design basis success criteria shall be documented in this section. 
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1 Provide the actual values used to characterize success such as: The time required in the 

2 PRA for the EDG to successfully reach rated speed and voltage is 15 seconds.

3 Where there are different success criteria for different monitored functions or different success 

4 criteria for different initiators within a monitored function, all should be recorded and the most 

5 restrictive shown as the one used, with the exception of ATWS-related success criteria which 

6 are not in the scope of MSPI. 

7

8 G 1.4 Mission Time

9 This section documents the risk significant mission time, as defined in Section 2.3.6 of 

10 Appendix F, for each of the identified monitored functions identified for the system. The 

11 following specific information should be included in support of the EDG mission time if a value 

12 less than 24 hours is used:

13 • EDG Mission Time with highest Birnbaum

14 • Basic Event and Description (basis for Birnbaum)

15 • Other Emergency Power Failure to Run Basic Events, Descriptions, mission time and 

16 Birnbaums (those not selected)

17 • Method for reduced mission time (e.g., Convolution, Multiple Discrete LOOP (Loss of 

18 Offsite Power) Initiating Events, Other)

19 • Loss of Offsite Power (LOOP) Initiating Events, Description and Frequency

20 • Basis for LOOP Frequency (Industry/NRC Reference)

21 • Basis for LOOP Non-recovery Failure (Industry/NRC Reference)

22 • Credit for Emergency Power Repair (Yes/No)

23 • If repair credited, failure probability of repair and basis

24

25 G 1.5 Monitored Components

26 This section documents the selection of monitored components as defined in Appendix F, 

27 Section 2.1.2 of NEI 99-02 in each train of the monitored system. A listing of all monitored 

28 pumps, breakers and EDGs emergency power generators should be included in this section. A 

29 listing of AOVs, HOVs , SOVs and MOVs that change state to achieve the monitored

30 functions should be provided as potential monitored components. The basis for excluding valves

31 and breakers in this list from monitoring should be provided. Component boundaries as 

32 described in Appendix F, Section 2.1.3 of NEI 99-02 should be included where appropriate.

33

34 G 1.6 Basis for Demands/Run Hours (estimate or actual)

35 The determination of reliability largely relies on the values of demands, run hours and failures of 

36 components to develop a failure rate. This section documents how the licensee will determine 

37 the demands on a component. Several methods may be used.

38 • Actual counting of demands/run hours during the reporting period

39 • An estimate of demands/run hours based on the number of times a procedure or other 

40 activities are performed plus either actual ESF demands/run hours or “zero” ESF 

41 demands/run hours

42 • An estimate based on historical data over a year or more averaged for a quarterly average 

43 plus either actual ESF demands/run hours or “zero” ESF demands/run hours

44 The method used, either actual or estimated values, shall be stated. If estimates are used for test 

45 or operational demands or run hours then the process used for developing the estimates shall be 

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1 described and estimated values documented. If the estimates are based on performance of

2 procedures, list the procedures and the frequencies of performance that were used to develop the 

3 estimates.

4

5 G 1.7 Short Duration Unavailability

6 This section provides a list of any periodic surveillances or evolutions of less than 15 minutes of 

7 unavailability that the licensee does not include in train unavailability. The intent is to minimize 

8 unnecessary burden of data collection, documentation, and verification because these short 

9 durations have insignificant risk impact.

10

11 G 1.8 PRA Information used in the MSPI

12

13 G 1.8.1 Unavailability FV and UA

14 This section includes a table or spreadsheet that lists the basic events for unavailability for each 

15 train of the monitored systems. This listing should include the probability, FV, and 

16 FV/probability ratio and text description of the basic event or component ID. An example format 

17 is provided as Table 1 at the end of this appendix. If the event chosen to represent the train is not 

18 the event that results in the largest ratio, provide information that describes the basis for the 

19 choice of the specific event that was used.

20

21 G 1.8.1.1 Unavailability Baseline Data

22 This section includes the baseline unavailability data by train for each monitored system. The 

23 discussion should include the basis for the baseline values used. The detailed basis for the 

24 baseline data may be included in an appendix to the MSPI Basis Document if desired.

25

26 The basis document should include the specific values for the planned and unplanned 

27 unavailability baseline values that are used for each train or segment in the system.

28

29 G 1.8.1.2 Treatment of Support System Initiator(s)

30 This section documents whether the cooling water systems are an initiator or not. This section 

31 provides a description of how the plant will include the support system initiator(s) as described 

32 in Appendix F of NEI 99-02. If an analysis is performed for a plant specific-specific value, the 

33 calculation must be documented in accordance with plant processes and referred to here. The 

34 results should also be included in this section. A sample table format for presenting the results of 

35 a plant specific-specific calculation for those plants that do not explicitly model the effect on the 

36 initiating event contribution to risk is shown in Table 4 at the end of this appendix.

37

38 G 1.8.2 Unreliability FV and UR

39 There are two options described in Appendix F for the selection of FV and UR values, the 

40 selected option should be identified in this section. This section also includes a table or 

41 spreadsheet that lists the PRA information for each monitored component. This listing should 

42 include the Component ID, event probability, FV, the common cause adjustment factor and 

43 FV/probability ratio and text description of the basic event or component ID. An example format 

44 is provided as Table 2 at the end of this appendix. If individual failure mode ratios (vice the 

45 maximum ratio) will be used in the calculation of MSPI, then each failure mode for each 

46 component will be listed in the table.
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1

2 A separate table should be provided in an appendix to the basis document that provides the 

3 complete set of basic events for each component. An example of this for one component is 

4 shown in Table 3 at the end of this appendix. Only the basic event chosen for the MSPI

5 calculation requires completion of all table entries.

6

7 G 1.8.2.1 Treatment of Support System Initiator(s)

8 This section documents whether the cooling water systems are an initiator or not. This section 

9 provides a description of how the plant will include the support system initiator(s) as described 

10 in Appendix F of NEI 99-02. If an analysis is performed for a plant specific-specific value, the 

11 calculation must be documented in accordance with plant processes and referred to here. The 

12 results should also be included in this section. A sample table format for presenting the results of 

13 a plant specific-specific calculation for those plants that do not explicitly model the effect on the 

14 initiating event contribution to risk is shown in Table 4 at the end of this appendix.

15

16 G 1.8.2.2 Calculation of Common Cause Factor

17 This section contains the description of how the plant will determine the common cause factor as 

18 described in Appendix F of NEI 99-02. If an analysis is performed for a plant specific-specific

19 value, the calculation must be documented in accordance with plant processes and referred to 

20 here. The results should also be included in this section.

21

22

23 G 1.9 Assumptions

24 This section documents any specific assumptions made in determination of the MSPI

25 information that may need to be documented. Causes for documentation in this section could be 

26 special methods of counting hours or runtimes based on plant specific-specific designs or 

27 processes, or other instances not clearly covered by the guidance in NEI 99-02.

28

29 G 2. PRA Requirements

30

31 G 2.1 Discussion

32 The MSPI application can be considered a Phase 2 application under the NRC’s phased approach 

33 to PRA quality. The MSPI is an index that is based on internal initiating events, full-power 

34 PRA, for which the ASME Standard has been written. The Standard has been endorsed by the 

35 staff in RG 1.200, which has been issued for trial use.

36

37 Licensees should assure that their PRA is of sufficient technical adequacy to support the MSPI

38 application by one of the following alternatives:

39

40 G 2.1.1 Alternative A (Consistent with MSPI PRA Task Group recommendations)

41

42 a) Resolve the peer review Facts and Observations (F&Os) for the plant PRA that are 

43 classified as being in category A or B, or document the basis for a determination that any 

44 open A or B F&Os will not significantly impact the MSPI calculation. Open A or B F&Os 

45 are significant if collectively their resolution impacts any Birnbaum values used in MSPI 

46 by more than a factor of 3. Appropriate sensitivity studies may be performed to quantify 
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1 the impact. If an open A or B F&O cannot be resolved by April 1, 2006 and significantly 

2 impacts the MSPI calculation, a modified Birnbaum value equal to a factor of 3 times the 

3 median Birnbaum value from the associated cross comparison group for pumps/diesels and 

4 3 times the plant values for valves/breakers should be used in the MSPI calculation at the 

5 index, system or component level, as appropriate, until the F&O is resolved.

6

7 And

8

9 b) Perform a self assessment using the NEI-00-02 process as modified by Appendix B of RG 

10 1.200 for the ASME PRA Standard supporting level requirements identified by the MSPI

11 PRA task group and resolve any identified issues or document the basis for a determination 

12 that any open issues will not significantly impact the MSPI calculation. Identified issues 

13 are considered significant if they impact any Birnbaum values used in MSPI by more than a 

14 factor of 3. Appropriate sensitivity studies may be performed to quantify the impact. If an 

15 identified issue cannot be resolved by April 1, 2006 and significantly impacts the MSPI 

16 calculation, a modified Birnbaum value equal to a factor of 3 times the median Birnbaum 

17 value from the associated cross comparison group for pumps/diesels and 3 times the plant 

18 value for valves/breakers should be used in the MSPI calculation at the index, system or 

19 component level, as appropriate, until the issue is resolved.

20

21 G 2.1.2 Alternative B (Consistent with RG 1.174 guidance)

22

23 a) Resolve the peer review Facts and Observations (F&Os) for the plant PRA that are 

24 classified as being in category A or B, or document the basis for a determination that any 

25 open A or B F&Os will not significantly impact the MSPI calculation. Open A or B F&Os 

26 are significant if collectively their resolution impacts any Birnbaum values used in MSPI 

27 by more than a factor of 3. Appropriate sensitivity studies may be performed to quantify 

28 the impact. If an open A or B F&O cannot be resolved by April 1, 2006 and significantly 

29 impacts the MSPI calculation, a modified Birnbaum value equal to a factor of 3 times the 

30 median Birnbaum value from the associated cross comparison group for pumps/diesels and 

31 3 times the plant values for valves/breakers should be used in the MSPI calculation at the 

32 index, system or component level, as appropriate, until the F&O is resolved.

33

34

35 And

36

37 b) Disposition any candidate outlier issues identified by the industry PRA cross comparison 

38 activity. The disposition of candidate outlier issues can be accomplished by:

39

40 • Correcting or updating the PRA model;

41 • Demonstrating that outlier identification was due to valid design or PRA modeling 

42 methods; or

43 • Using a modified Birnbaum value equal to a factor of 3 times the median value from the 

44 associated cross comparison group for pumps/diesels and 3 times the plant value for 

45 valves/breakers until the PRA model is corrected or updated.

46
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1

2 G 2.2 PRA MSPI Documentation Requirements

3

4 A. Licensees should provide a summary of their PRA models to include the following:

5 1. Approved version and date used to develop MSPI data

6 2. Plant base CDF for MSPI

7 3. Truncation level used to develop MSPI data

8

9 B. Licensees should document the technical adequacy of their PRA models, including:

10 1. Justification for any open category A or B F&Os that will not be resolved prior to 

11 April 1, 2006.

12 2. Justification for any open issues from:

13 a. the self-assessment performed for the supporting requirements (SR) identified in 

14 Table 5, taking into consideration Appendix B of RG 1.200 (trial), with particular 

15 attention to the notes in Table 4 of the MSPI PRA task group report.

16 -- OR --

17 b. identification of any candidate outliers for the plant from the group cross18 comparison studies.

19

20

21 C. Licensees should document in their PRA archival documentation:

22

23 1. A description of the resolution of the A and B category F&Os identified by the peer 

24 review team.

25 2. Technical bases for the PRA. 

26
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1

2 G 3. TABLES

3

4 Table G 1 Unavailability Data HPSI (one table per system)

Train Basic Event Name Basic Event Description Basic Event 

Probability (UAP)

Basic Event 

FVUAP 1 FVUAP/UAP

A 1SIAP02----MP6CM HPSI Pump A Unavailable Due to 

Mntc

3.20E-03 3.19E-03 9.97E-01

B 1SIBP02----MP6CM HPSI Pump B Unavailable Due to 

Mntc

3.20E-03 3.85E-03 1.20E+00

5 1. Adjusted for IEF correction if used

6

7 Table G 2 – AFW System Monitored Component PRA Information

Component Basic Event Description

Basic 

Event 

Probability 

(URPC)

Basic 

Event 

FVURC

[FV/UR]ind

CC 

Adjustment 

Factor (A)

CC 

Adjustment 

Used

Adjusted 

Birnbaum

1MAFAP01 1AFASYS----

AFACM

Train A Auxiliary Feedwater 

Pump Fails to Start

2.75E-03 2.33E-02 8.49E+00 1 Generic 1.1E-04

1MAFBP01 1AFBP01----

MPAFS

Train B Auxiliary Feedwater 

Pump Fails to Start

6.73E-04 4.44E-02 6.59E+01 1.25 Generic 1.1E-03

1MAFNP01 1AFNSYS----

AFNCM

Train N Auxiliary Feedwater 

Pump Fails to Start

1.05E-03 1.10E-02 1.05E+01 1.25 Generic 1.7E-04

1JCTAHV0001 1CTAHV001--

MV-FO

CST to AFW Pump N Supply 

Valve HV1 Fails to Open 

(Local Fault)

3.17E-03 2.48E-02 7.83E+00 2 Generic 2.0E-04

1JCTAHV0004 1CTAHV004--

MV-FO

CST to AFW Pump N Supply 

Valve HV4 Fails to Open 

(Local Fault)

3.17E-03 2.48E-02 7.83E+00 2 Generic 2.0E-04

8

9

10
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1 Table G 3 - Unreliability Data (one table per monitored component)

2 Component Name and ID: HPSI Pump B - 1SIBP02

Basic Event Name Basic Event Description

Basic Event 

Probability 

(URPC)

Basic 

Event 

FVURC 

1

[FV/UR]in

d

Common 

Cause 

Adjustment 

Factor 

(CCF)

Common 

Cause 

Adjustment 

Generic or 

Plant Specificspecific

Adjusted 

Birnbaum

1SIBP02---

XCYXOR

HPSI Pump B Fails to Start 

Due to Override Contact 

Failure

6.81E-04 7.71E-04 1.13E+00 3.0 Generic 5.0E-05

1SIBP02----

MPAFS

HPSI Pump B Fails to Start 

(Local Fault)

6.73E-04 7.62E-04 1.13E+00

1SIBP02----MP-FR HPSI Pump B Fails to Run 4.80E-04 5.33E-04 1.11E+00

1SABHPK125RXAFTHPSI Pump B Fails to Start 

Due to K125 Failure

3.27E-04 3.56E-04 1.09E+00

1SIBP02----

CB0CM

HPSI Pump B Circuit Breaker 

(PBB-S04E) Unavailable Due 

to Mntc

2.20E-04 2.32E-04 1.05E+00

1SIBP02----CBBFT HPSI Pump B Circuit Breaker 

(PBB-S04E) Fails to Close 

(Local Fault)

2.04E-04 2.14E-04 1.05E+00

3 1. Adjusted for IEF correction if used

4

5 Table G 4 Cooling Water Support System FV Calculation Results (one table per train/component/failure mode)

FVa (or FVc) FVie FVsa (orFVsc) UA (or UR)

Calculated FV (per appendix F)

(result is put in Basic Event column of table 1 

or table 2 as appropriate)

6
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TABLE G 5. ASME PRA Standard Supporting Requirements Requiring Self-Assessment

1Supporting 

Requirement

Comments

IE-A4 Focus on plant specific-specific initiators and special initiators, especially loss of DC 

bus, Loss of AC bus, or Loss of room cooling type initiators

IE-A7 Category I in general. However, precursors to losses of cooling water systems in 

particular, e.g., from fouling of intake structures, may indicate potential failure 

mechanisms to be taken into account in the system analysis (IE-C6, 7, 8, 9)

IE-A9 Category II for plants that choose fault trees to model support systems. Watch for 

initiating event frequencies that are substantially (e.g., more than 3 times) below generic 

values.

IE-C1 Focus on loss of offsite power (LOOP) frequency as a function of duration

IE-C2 Focus on LOOP and medium and small LOCA frequencies including stuck open 

PORVs

IE-C6 For plants that choose fault trees for support systems, attention to loss of cooling 

systems initiators.

IE-C9 Category II for plants that choose fault trees for support systems. Pay attention to 

initiating event frequencies that are substantially (i.e., more than 3 times) below generic 

values

AS-A3 Focus on credit for alternate sources, e.g., gas turbines, CRD, fire water, SW cross-tie, 

recovery of FW

AS-A4 Focus on credit for alternate sources, e.g., gas turbines, CRD, fire water, SW cross-tie, 

recovery of FW

AS-A5 Focus on credit for alternate sources, e.g., gas turbines, CRD, fire water, SW cross-tie, 

recovery of FW

AS-A9 Category II for MSPI systems and components and for systems such as CRD, fire 

water, SW cross-tie, recovery of FW

AS-A10 Category II in particular for alternate systems where the operator actions may be 

significantly different, e.g., more complex, more time limited.

AS-B3 Focus on credit for injection post-venting (NPSH issues, environmental survivability, 

etc.)

AS-B6 Focus on (a) time phasing in LOOP/SBO sequences, including battery depletion, and (c) 

adequacy of CRD as an adequate injection source.

SC-A4 Focus on modeling of shared systems and cross-ties in multi-unit sites

SC-B1 Focus on proper application of the computer codes for T/H calculations, especially for 

LOCA, IORV, SORV, and F&B scenarios.

SC-C1 Category II
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TABLE G 5. ASME PRA Standard Supporting Requirements Requiring Self-Assessment

1Supporting 

Requirement

Comments

SY-A4 Category II for MSPI systems and components

SY-A11 Focus on (d) modeling of shared systems

SY-A20 Focus on credit for alternate injection systems, alternate seal cooling

SY-B1 Should include EDG, AFW, HPI, RHR CCFs

SY-B5 Focus on dependencies of support systems (especially cooling water systems) to the 

initiating events 

SY-B9 Focus on credit for injection post-venting (NPSH issues, environmental survivability, 

etc.)

SY-B15 Focus on credit for injection post-venting (NPSH issues, environmental survivability, 

etc.)

HR-E1 Focus on credit for cross ties, depressurization, use of alternate sources, venting, core 

cooling recovery, initiation of F&B

HR-E2 Focus on credit for cross ties, depressurization, use of alternate sources, venting, core 

cooling recovery, initiation of F&B

HR-G1 Category II , though Category I for the critical HEPs would produce a more sensitive 

MSPI (i.e., fewer failures to change a color) 

HR-G2 Focus on credit for cross ties, depressurization, use of alternate sources, venting, core 

cooling recovery, initiation of F&B

HR-G3 Category I. See note on HR-G1. Attention to credit for cross ties, depressurization, use 

of alternate sources, venting, core cooling recovery, initiation of F&B

HR-G5 Category II. See note on HR-G1.

HR-H2 Focus on credit for cross ties, depressurization, use of alternate sources, venting, core 

cooling recovery, initiation of F&B

HR-H3 The use of some systems may be treated as a recovery action in a PRA, even though the 

system may be addressed in the same procedure as a human action modeled in the 

accident sequence model (e.g., recovery of feedwater may be addressed in the same 

procedure as feed and bleed). Neglecting the cognitive dependency can significantly 

decrease the significance of the sequence. 

DA-B1 Focus on service condition (clean vs. untreated water) for SW systems

DA-C1 Focus on LOOP recovery

DA-C15 Focus on recovery from LOSP and loss of SW events

DA-D1 For BWRs with isolation condenser, focus on the likelihood of a stuck open SRV

QU-B2 Truncation limits should be chosen to be appropriate for F-V calculations. 
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TABLE G 5. ASME PRA Standard Supporting Requirements Requiring Self-Assessment

1Supporting 

Requirement

Comments

QU-B3 This is an MSPI implementation concern and should be addressed in the guidance 

document. Truncation limits should be chosen to be appropriate for F-V calculations. 

QU-D3 Understanding the differences between plant models, particularly as they affect the 

MSPI, is important for the proposed approach to the identification of outliers 

recommended by the task group. 

QU-D5 Category II for those who have used fault tree models to address support system 

initiators.

QU-E4 Category II for the issues that directly affect the MSPI
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1 APPENDIX H

2 USwC Basis Document

3

4

5 The USwC PI will monitor the following six conditions that either have the potential to 

6 complicate the operators’ scram recovery response actions or involve the unavailability of or 

7 inability to recover main feedwater during the scram response. 

8

9 1. Reactivity Control

10 2. Pressure Control (BWRs)/Turbine Trip (PWRs)

11 3. Power available to Emergency Busses

12 4. Need to actuate emergency injection sources

13 5. Availability of Main Feedwater

14 6. Utilization of scram recovery Emergency Operating Procedures (EOPs)

15

16 Since the complicating conditions are not the same for Pressurized Water Reactors (PWRs) 

17 versus Boiling Water Reactors (BWRs), a separate flow chart for each type has been developed. 

18 If any one of the conditions in the appropriate flow chart is met the condition must be counted as 

19 a USwC event. 

20

21 H 1 PWR Flowchart Basis Discussion

22

23 H 1.1 Did two or more control rods fail to fully insert?

24

25 This question is designed to verify that the Reactor did actually trip. As long as a plant 

26 uses the EOP questions to verify that the reactor tripped without entering a “response not 

27 obtained” or “contingency actions” requirement this question should be answered as “No”. 

28 Some specific examples from plant EOPs are provided below.

29

30 Some CE plant EOPs use the following checks: 

31

32 • Check that reactor power is dropping.

33 • Check that start-up rate is negative.

34 • Check that no more than one full strength CEA is NOT inserted.

35

36 If the operations staff determines that one of these questions is not satisfied then they must 

37 perform a contingency action. The requirement to perform that contingency action would 

38 be considered as a complication for the Unplanned Scrams with Complications metric.

39

40 Some Westinghouse plant EOPs verify the following items:

41

42 • Verify Reactor Trip

43 o Rod bottom lights – LIT

44 o Reactor trip and bypass breakers – OPEN

45 o Neutron flux - LOWERING 

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1

2 If the operations staff determines that one of these questions is not satisfied then they must 

3 perform a response not obtained action. The requirement to perform that contingency 

4 action would be considered as a complication for the Unplanned Scrams with 

5 Complications metric. There is an exception in this question for Westinghouse plants using 

6 the question structure given in this example. A single rod bottom light not lit would be 

7 acceptable in the Unplanned Scrams with Complications metric even though it would 

8 require a response not obtained action. This exception is allowed to make the metric 

9 consistent between vendor procedures, also the reactor analysis allows for the single most 

10 reactive control rod to be stuck in the full out position. 

11

12 Some B&W plants EOPs verify the following:

13

14 • Verify Alternate Rod Insertion and reactor power dropping

15

16 If the operations staff determines that this question is not satisfied then they must perform a 

17 contingency action. The requirement to perform that contingency action would be 

18 considered as a complication for the Unplanned Scrams with Complications metric. There 

19 is an exception in this question for B & W plants using the question structure given in this 

20 example. A single rod not fully inserted would be acceptable in the Unplanned Scrams 

21 with Complications metric even though it would require a contingency action. This 

22 exception is allowed to make the metric consistent between vendor procedures, also the 

23 reactor analysis allows for the single most reactive control rod to be stack in the full out 

24 position

25

26 H 1.2 Did the turbine fail to trip? 

27

28 This question is designed to verify that the Turbine did actually trip. As long as a plant 

29 uses the EOP questions to verify that the turbine tripped without entering a “response not 

30 obtained” or “contingency actions” requirement this question should be answered as “No”. 

31 There is one exemption to this step that allows an Operator to use the manual turbine trip 

32 handswitch/pushbutton as an acceptable alternative. The simplicity of the action and the 

33 fact that Operators are specifically trained on this action provide the basis for this 

34 exception. It is NOT an acceptable alternative for the Operators to close individual 

35 governor or throttle valves, main steam isolation valves, or secure hydraulic control pumps. 

36 The failure of a generator output breaker to trip with the turbine is considered as a 

37 complication. Any actions beyond the use of one handswitch/pushbutton would need to be 

38 considered as a complication for this question. For reactor trips that occur prior to the 

39 turbine being placed in service or “latched” this specific question should be answered as 

40 “No” since the turbine is already tripped. Some specific examples from plant EOPs are 

41 provided below:

42

43 Some CE plant EOPs use the following checks: 

44

45 • Check that the main turbine is tripped

46 • Check that the main generator output breakers are open
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1

2 The use of the contingency action to manually trip the turbine is an acceptable alternative. 

3 Performance of any other contingency actions would require answering this question as 

4 “Yes”. 

5

6 Some Westinghouse plant EOPs verify the following items:

7

8 • Verify all turbine throttle valves – CLOSED

9 • Main generator output breaker - OPEN

10

11 The use of the contingency action to manually trip the turbine is an acceptable alternative. 

12 Performance of any other response not obtained actions would require answering this 

13 question as “Yes”. 

14

15 Some B&W plant EOPs verify the following:

16

17 • Verify turbine throttle and governor valve closed

18

19 The use of the contingency action to manually trip the turbine is an acceptable alternative. 

20 Performance of any other contingency actions would require answering this question as 

21 “Yes”. 

22

23 H 1.3 Was power lost to any ESF bus?

24

25 Most EOP versions check that power is available in response to the reactor trip. This 

26 question is designed to verify that electric power was available after the reactor trip. As 

27 long as a plant uses the EOP questions to verify that power was available without entering 

28 a “response not obtained” or “contingency actions” requirement this question should be 

29 answered as “No”. There is an exemption to this step that allows an Operator to manually 

30 restore power within 10 minutes as an acceptable alternative. The exception is limited to 

31 those actions necessary to close a breaker from the main control board. Actions requiring 

32 access to the back of the control boards or any other remote location would require 

33 answering this question as “Yes”. It is acceptable to manipulate more than one switch, 

34 such as a sync switch, in the process of restoring power to the bus. It is acceptable to close 

35 more than one breaker. It is acceptable to restore power from the emergency AC source, 

36 such as diesel generators, or from off-site power. This exception is allowed since most 

37 EOPs are configured to check that power is available to at least one of the safety busses 

38 which will satisfy plant safety concerns. If power is not available to at least one safety bus 

39 most EOPs will direct transition to another EOP to mitigate this condition. The additional 

40 operator action to restore power to additional busses has been discussed and considered 

41 acceptable as long as it can be completed within the time limitations of 10 minutes (chosen 

42 to limit the complexity) and the constraints of switch operation from the main control 

43 board. Any actions beyond these would need to be considered as a complication for this 

44 question. Because of the wide variation in power distribution designs, voltage, and 

45 nomenclature across the PWR fleet, no specific EOP examples are given here. 

46
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1

2 H 1.4 Was a Safety Injection signal received?

3

4 This question is designed to verify that the plant conditions are stable and do not require 

5 the actuation of the emergency injection system (safety injection for Westinghouse plants, 

6 SIAS for CE). Plant conditions that result from a loss of inventory or loss of pressure 

7 control in the RCS or Steam Generator (SG) would likely require actuation of the 

8 emergency injection systems and would be considered a complication. Conversely, plant 

9 conditions following the reactor trip that do not result in a safety injection actuation would 

10 not be considered as complications. An exception to this is the existence of a severe steam 

11 generator tube leak. In those limited circumstances where a steam generator tube leak 

12 exists that is severe enough to require a reactor trip but can be controlled by starting 

13 additional inventory control pumps that are not normally running during normal power 

14 operations without initiating a safety injection signal should result in a “Yes” answer and 

15 considered as a complication. A small steam generator tube leak where inventory can be 

16 maintained using the already running inventory control pumps would NOT be considered 

17 as complicated even if the reactor was tripped. Those instances where a safety injection 

18 was not required by actual plants conditions but occurred due to operator error, spurious 

19 actuations, or set-point error should be considered as complications and this question 

20 answered as “Yes”.

21

22 H 1.5 Was Main Feedwater unavailable or not recoverable using approved plant 

23 procedures following during the scram response?

24

25 This section of the indicator is a holdover from the Scrams with Loss of Normal Heat 

26 Removal indicator which the USwC indicator is replacingreplaced. Since all PWR 

27 designs have an emergency Feedwater system that operates if necessary, the availability 

28 of the normal or main Feedwater systems is as a backup in emergency situations can be 

29 important for managing risk following a reactor scram. This portion of the indicator is 

30 designed to measure assess that backup availability or ability to recover main feedwater as 

31 directed by approved plant procedures (e.g., the EOPs) on a loss of all emergency 

32 Feedwater.

33

34 It is not necessary for the main Feedwater system to continue operating following a 

35 reactor trip. Some plants, by design, have certain features to prevent main feedwater 

36 from continued operation or from allowing it to be restarted unless certain criteria are met. 

37 The system must be free from damage or failure that would prohibit restart of the system if 

38 necessary. Since some plant designs do not include electric electric-driven main Feedwater 

39 pumps (steam steam-driven pumps only), it may not be possible to restart main Feedwater 

40 pumps without a critical reactor. Those plants should answer this question as “No” and 

41 move on. Additionally, someSome other plant designs have interlocks in place and signals

42 to that prevent feeding the steam generators with main Feedwater unless reactor coolant 

43 temperature is greater than the no-load average temperature. In both cases, These these 

44 plants should also answermay be justified in answering this question as “No” if Main 

45 Feedwater is free from damage or failure that can prevent it from performing its intended 

46 function and is available for use. and move on. 

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1

2 Licensees should rely on the material condition availability of the equipment to reach the 

3 decision for this question. Condenser vacuum, cooling water, and steam pressure values 

4 should be evaluated based on the requirements to operate the pumps and may be lower than 

5 normal if procedures allow pump operation at that lower value. As long as these support 

6 systems are able to be restarted (if not running) to support main feedwater restart within 

7 the estimated 30 30-minute timeframe they can be considered as available. These 

8 requirements apply until the completion or exit of the scram response procedure.

9

10 The availability of steam dumps to the condenser does NOT enter into this indicator at all. 

11 Use of atmospheric steam dumps following the reactor trip is acceptable for any duration. 

12

13 Loss of one feed pump does not cause a loss of main feedwater. Only one is needed to 

14 remove residual heat after a trip. As long as at least one pump can still operate and provide 

15 Feedwater to the minimum number of steam generators required by the EOPs to satisfy the 

16 heat sink criteria, main feedwater should be considered available.

17

18 The failure in a closed position of a feedwater isolation valve to a steam generator is a loss 

19 of feed to that one steam generator. As long as the main feedwater system is able to feed 

20 the minimum number of steam generators required by the EOPs to satisfy the heat sink 

21 criteria, the loss of ability to feed other steam generators should not be considered a loss of 

22 feedwater. Isolation of the feedwater regulating or isolation valves does not constitute a 

23 loss of feedwater if nothing prevents them from being reopened in accordance with 

24 procedures.

25

26 A Steam Generator Isolation Signal or Feedwater Isolation Signal does not constitute a loss 

27 of main feedwater as long as it can be cleared and feedwater restarted. If the isolation 

28 signal was caused by a high steam generator level, the 30 minute estimate for restart 

29 timeframe should start once the high level isolation signal has cleared. 

30

31 The estimated 30 30-minute timeframe for restart of main Feedwater was chosen based 

32 on restarting from a hot and filled condition. Since this timeframe will not be measured 

33 directly it should be an estimation developed based on the material condition of the plants 

34 systems following the reactor trip. If no abnormal material conditions exist the 30 minutes 

35 should be met. If plant procedures and design would require more than 30 minutes even if 

36 all systems were hot and the material condition of the plants systems following the reactor 

37 trip were normal, that routine time should be used in the evaluation of this question, 

38 provided SG dry-out cannot occur on an uncomplicated trip if the time is longer than 30 

39 minutes. The opinion judgment of the on-shift licensed SRO during the reactor trip 

40 should be accepted used in determining if this timeframe was met. 

41

42 H 1.6 Was the scram response procedure unable to be completed without entering another 

43 EOP?

44

45 When a scram occurs plant operators enter the EOPs to respond to the condition. In the 

46 case of a routine scram the procedure entered will be exited fairly rapidly after verifying 

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1 that the reactor is shutdown, excessive cooling is not in progress, electric power is 

2 available, and reactor coolant pressures and temperatures are at expected values and 

3 controlled. Once these verifications are done and the plant conditions are considered 

4 “stable” operators may exit the initial procedure to another procedure that will stabilize and 

5 prepare the remainder of the plant for transition to the normal operating procedures. The 

6 plant could then be maintained in Hot Standby, to perform a controlled normal cool down, 

7 or to begin the restart process. The criteria in this question is used to verify there were no 

8 other conditions that developed during the stabilization of the plant in the scram response 

9 that required re-entry into the EOPs or transition to a follow on EOP. 

10

11 There are some EOPs that are used specifically at the operator discretion and are not 

12 required to be used. In the Westinghouse EOP suite these are Yellow Path functional 

13 restoration procedures and the re-diagnosis procedures. These procedures typically verify 

14 that the operator is taking the correct action (re-diagnosis) or the stabilization of some 

15 minor plant parameters (Yellow path). Use of these procedures is an allowed exception to 

16 this step. The transition out of these procedures to an EOP different from the current 

17 procedure in effect, i.e. a new procedure or the base procedure, would count as a 

18 complication. 

19

20 H 2 PWR Case Studies

21

22 H 2.1 PWR Case Study 1

23

24 At approximately 100% steady state reactor power, Control Room operators initiated a manual 

25 reactor trip as a result of indications that multiple Control Rods (CRs) had dropped into the 

26 reactor core. All Reactor Trip (RT) breakers opened but all rod bottom lights did not illuminate. 

27 Rod Cluster Control Assemblies (RCCA) L7, J13, F6, F10, K10, C5, and C13 were not 

28 considered fully inserted because the rod bottom lights for these RCCAs did not illuminate. The 

29 Plant Information Computer System indicated all RCCAs were fully inserted. In accordance 

30 with plant procedures, operators re-initiated a manual RT. Operations verified the reactor was 

31 tripped and all RCCAs were fully inserted. 

32

33 Prior to the event all CRs were withdrawn from the reactor core and in Automatic, both Main 

34 Boiler Feedwater Pumps (MBFPs) were in service, the Auxiliary Feedwater Pumps (AFWPs) 

35 were in standby, the EDGs were in standby, and off-site power was in service. At 1435 hours, 

36 indicated reactor power decreased from approximately 99.87% to 50% (based on the Nuclear 

37 Instrumentation System power range neutron flux monitors) as a result of 12 CRs dropping into 

38 the core. Of the twelve CRs that dropped into the core, four (4) CRs (M-12, M-4, D-12, and D-4) 

39 went from 223 steps to 150 steps out and eight (8) control rods (N-13, L-13, N-5, N-3, E-3, C-3, 

40 C13, and C-11) went from 223 steps out to 0 steps. Reactivity control is achieved by a 

41 combination of 53 CRs [29 RCCAs are in control banks (CB) and 24 in shutdown banks (SDBs)] 

42 and chemical shim (boric acid). The CRs are divided into 1) a shutdown (SD) group comprised 

43 of two SDBs of eight rod clusters each and two SDBs of four rod clusters each, and 2) a control 

44 group comprised of four CBs containing eight, four, eight, and nine rod clusters.

45
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1 After the manual RT, seven (7) rod bottom lights for CR SDB A, Rod L7, SDB 3, Rod J12, SDB 

2 D, Rods F6, F10, K10, CB A, Rod C5, and CB C, Rod C13 did not illuminate. All other 

3 reactivity indications were normal. As a result of the manual RT, the Main Turbine-Generator 

4 tripped, and the AFWPs automatically started. The EDGs did not start as off-site power 

5 remained in service. An alarm for low pressurizer pressure annunciated as a result of a reduction 

6 of the RCS pressure to the normal trip setpoint (1985 psig). The decrease in pressure was due to 

7 the negative reactivity from the initial rod insertion. All primary safety systems functioned 

8 properly. Unexpected responses included: both MBFP suction relief valves lifted (reset at 

9 approximately 1458 hours), a "Not in Sync" alarm was received for the 24 Static Inverter 

10 (adjusted and cleared), and a low oil level alarm on upper reservoir was received for the 23 

11 Reactor Coolant Pump (RCP). Power for the rod control system is distributed to five power 

12 cabinets from two motor-generator sets connected in parallel through two series of Reactor Trip 

13 Breakers (RTBs). The ac power distribution lines downstream of the RTBs are routed above the 

14 power cabinets through a fully enclosed three-phase, four wire plug-in, bus duct assembly.

15

16 The ac power to each cabinet is carried by the bus duct assembly through three plug-in fused 

17 disconnect switches for the stationary, movable and lift coil circuits of the mechanisms 

18 associated with that cabinet. During the investigation of the event the disconnect switch (JSI on 

19 top of rod control power cabinet (CAB) lAC was discovered to be open. Opening the disconnect 

20 switch caused loss of power to the stationary coils for twelve (12) CRs. The switch that was 

21 placed in the open position was for power cabinet lAC which controls the rods for CB A, Group 

22 1, CB C, Group 1, and SDB A, Group 1. Loss of power to these CRs caused the rods to drop into 

23 the reactor core per design. Four (4) CRs partially inserted (223 steps in to 150 steps). CR power 

24 cabinet (lAC) disconnect switch was inadvertently bumped open by a contractor erecting 

25 scaffolding around the CR power cabinets in the cable spreading room of the Control Building 

26 (NA). The disconnect switch to rod control power cabinet lAC was re-closed. An assessment of 

27 the condition by reactor engineering concluded that power was removed from the CR stationary 

28 gripper coils when the disconnect switch was opened. When no motion is demanded and rods are 

29 stationary, current is sent to the coils, which keeps the grippers engaged on the CR. The CR 

30 system sensed the power loss condition and transmitted a high current order to the movable 

31 gripper coils which had not lost their power. The movable gripper coils were able to catch four of 

32 the CRs as they were falling but did not catch the remaining CRs in the other CR groups. The 

33 cause of the failure of seven (7) rod bottom lights to illuminate after the dropped rod event was 

34 due to failed light bistables. 

35

36 In answering the questions for this indicator, some additional information beyond that gathered 

37 for the LER will be required. In this case the usage history of the EOPs will be required. For 

38 this example consider that there were no additional EOPs used beyond the normal procedures.

39

40 1. Did two or more control rods fail to fully insert?

41

42 Did control rods that are required to move on a reactor trip fully insert into the core as 

43 evidenced by the Emergency Operating Procedure (EOP) evaluation criteria? As an 

44 example for some PWRs using rod bottom light indications, if more than one-rod bottom 

45 light is not illuminated, this question must be answered "Yes." The basis of this step is to 

46 determine if additional actions are required by the operators as a result of the failure of all 
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1 rods to insert. Additional actions, such as emergency boration, pose a complication beyond 

2 the normal scram response that this metric is attempting the measure. It is allowable to 

3 have one control rod not fully inserted since core protection design accounts for one control 

4 rod remaining fully withdrawn from the core on a reactor trip. This question must be 

5 evaluated using the criteria contained in the plant EOP used to verify that control rods 

6 inserted. During performance of this step of the EOP the licensee staff would not need to 

7 apply the “Response Not Obtained” actions. Other means not specified in the EOPs are not 

8 allowed for this metric. 

9

10 Answer:

11 YES. This question should be answered as “YES” and the trip counted as a Scram with 

12 Complications since the rod bottom lights did not indicate fully inserted control rods. If 

13 the EOP allows the use of the plant computer indications instead of rod bottom lights this 

14 question should be answered as “NO.” To qualify the plant computer indication must not 

15 be considered as a “Response Not Obtained” step but rather as a listed normal indication.

16

17 2.Did the turbine fail to trip? 

18

19 Did the turbine fail to trip automatically/manually as required on the reactor trip signal? To 

20 be a successful trip, steam flow to the main turbine must have been isolated by the turbine 

21 trip logic actuated by the reactor trip signal, or by operator action from a single switch or 

22 pushbutton. The allowance of operator action to trip the turbine is based on the operation 

23 of the turbine trip logic from the operator action if directed by the EOP. Operator action to 

24 close valves or secure pumps to trip the turbine beyond use of a single turbine trip switch 

25 would count in this indicator as a failure to trip and a complication beyond the normal 

26 reactor trip response. Trips that occur prior to the turbine being placed in service or 

27 “latched” should have this question answered as “No”.

28 c

29 Answer:

30 NO. The turbine tripped per design,

31

32 3. Was power lost to any ESF bus?

33

34 During a reactor trip or during the period operators are responding to a reactor trip using 

35 reactor trip response procedures, was power lost to any ESF bus that was not restored 

36 automatically by the Emergency Alternating Current (EAC) power system and remained 

37 de-energized for greater than 10 minutes? Operator action to re-energize the ESF bus from 

38 the main control board is allowed as an acceptable action to satisfy this metric. This 

39 question is looking for a loss of power at any time for any duration where the bus was not 

40 energized/re-energized within 10 minutes. The bus must have:

41

42 • remained energized until the scram response procedure was exited, or

43 • been re-energized automatically by the plant EAC power system (i.e., EDG), or

44 • been re-energized from normal or emergency sources by an operator closing a 

45 breaker from the main control board.

46
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1 The question applies to all ESF busses (switchgear, load centers, motor control centers and 

2 DC busses). This does NOT apply to 120-volt power panels. It is expected that operator 

3 action to re-energize an ESF bus would not take longer than 10 minutes. 

4

5 Answer:

6 NO. Emergency diesels were not required to start. Offsite power remained available 

7 throughout the trip response. All ESF busses remained energized throughout the trip 

8 response.

9

10 4. Was a Safety Injection signal received?

11

12 Was a Safety Injection signal generated either manually or automatically during the reactor 

13 trip response? The questions purpose is to determine if the operator had to respond to an 

14 abnormal condition that required a safety injection or respond to the actuation of additional 

15 equipment that would not normally actuate on an uncomplicated scram. This question 

16 would include any condition that challenged Reactor Coolant System (RCS) inventory, 

17 pressure, or temperature severely enough to require a safety injection. A severe steam 

18 generator tube leak that would require a manual reactor trip because it was beyond the 

19 capacity of the normal at power running charging system should be counted even if a safety 

20 injection was not used since additional charging pumps would be required to be started.

21

22 Answer:

23 NO. No SI signal was required or received.

24

25 5. Was Main Feedwater unavailable or not recoverable using approved plant 

26 procedures following during the scram response?

27

28 If operating prior to the scram, did Main Feedwater cease to operate and was it unable to be 

29 restarted during the reactor scram response? The consideration for this question is whether 

30 Main Feedwater could be used to feed the steam generators if necessary. The qualifier of 

31 “not recoverable using approved plant procedures” will allow a licensee to answer “No” to 

32 this question if there is no physical equipment restraint to prevent the operations staff from 

33 starting the necessary equipment, aligning the required systems, or satisfying required logic 

34 using plant procedures approved for use and in place prior to the reactor scram occurring.

35

36 The operations staff must be able to start and operate the required equipment using

37 normal alignments and approved emergency, normal and off-normal operating 

38 procedures to feed the minimum number of steam generators required by the EOPs to 

39 satisfy the heat sink criteria. Manual operation of controllers/equipment, even if normally 

40 automatic, is allowed if addressed by procedure. Situations that require maintenance or 

41 repair activities or non-proceduralized operating alignments require an answer of “Yes.” 

42 Additionally, the restoration of Feedwater must be capable of feeding the Steam Generators 

43 in a reasonable period of time. Operations should be able to start a Main Feedwater pump 

44 and start feeding Steam Generators with the Main Feedwater System within about 30 

45 minutes from the time it was recognized that Main Feedwater was needed. During 

46 startup conditions where Main Feedwater was not placed in service prior to the scram this 

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1 question would not be considered and should be skipped. If design features or procedural 

2 prohibitions prevent restarting Main Feedwater this question should be answered as “No”.

3

4 Answer:

5 NO. Main feedwater pumps were available and the feedwater system could have been 

6 operated to supply feedwater to all steam generators. 

7

8 6. Was the scram response procedure unable to be completed without entering another 

9 EOP?

10

11 The response to the scram must be completed without transitioning to an additional EOP 

12 after entering the scram response procedure (e.g., ES01 for Westinghouse). This step is 

13 used to determine if the scram was uncomplicated by counting if additional procedures 

14 beyond the normal scram response required entry after the scram. A plant exiting the 

15 normal scram response procedure without using another EOP would answer this step as 

16 “No”. The discretionary use of the lowest level Function Restoration Guideline (Yellow 

17 Path) by the operations staff is an approved exception to this requirement. Use of the Re18 diagnosis Procedure by Operations is acceptable unless a transition to another EOP is 

19 required.

20

21 Answer:

22 NO. The reactor trip response procedures were completed without re-entering another 

23 EOP.

24

25 H 2.2 PWR Case Study 2

26

27 At 100% steady state reactor power, Operators manually tripped the reactor as a result of 

28 oscillating Feedwater (FW) flow and SG level with flow perturbations and FW pipe movement 

29 in the Auxiliary FW (AFW) Pump Building. Prior to the transient, while operating at 100% 

30 reactor power, with SG level control in AUTO, 22 SG Narrow Range (NR) level records show 

31 two cycles of level changes of approximately 2% and correction in automatic with no operator 

32 action. Subsequently, operators observed 22 SG NR level starting to decrease from a normal 

33 value of 49% to 30% with a deviation alarm annunciating at 44%. CR operators observed 

34 oscillating FW flow and erratic behavior of the 22 Main FW regulating valve FCV-427. 

35 Operators entered Abnormal Operating Procedure 2AOP-FW-1 and placed the FW regulating 

36 valve (FCV-427) in manual and attempted to increase FW flow in 22 SG without success. 

37 Excessive FW flow oscillations continued. Operators then opened low flow bypass valve FCV38 427L to increase SG level which started 22 SG level increasing at a level of 30%. At 

39 approximately 35% SG level valve FCV- 427L was returned to closed. A Nuclear Plant Operator 

40 (NPO) in the AFW Pump Building reported to the control room loud noises due to flow 

41 perturbations and pipe movement. Based on plant conditions, the Control Room Supervisor 

42 (CRS) directed a manual reactor trip. All control rods fully inserted and all primary systems 

43 functioned properly. The 22 FW regulating valve FCV-427 failed to fully close. Operators 

44 initiated FW isolation by closing FW motor operated isolation valves (MOV) BFD-5-1 and 

45 BFD-90-1. A 22 SG high level trip was actuated at 73% SG level, initiating automatic closure of 

46 the Main FW Pump motor operated discharge valves (BFD-2-21 and BFD-2-22), Main FW and 
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1 Low Flow FW regulating and isolation valves, and trip of the turbine driven Main FW Pumps. 

2 The plant was stabilized in hot standby with decay heat being removed by the main condenser. 

3 Offsite power remained available and therefore the EDGs did not start. The AFW System 

4 automatically started as a result of a SG low level normally experienced on trips from full power. 

5 FW regulating valve FCV-427 is a Copes-Vulcan globe valve with Copes-Vulcan actuator 

6 Model D-1000-160. The valve has a positioner to perform its modulating function and 3 

7 solenoids attached to the actuator for fast closure. CR operators observed the rod bottom lights, 

8 RT First Out Annunciator (Manual Trip). The plant was stabilized in hot standby with decay heat 

9 being released to the main condenser through the steam dump valves. A post transient 

10 evaluation was performed. A non-intrusive inspection was performed of the remaining FW 

11 regulating valves (FCV-417, FCV-437, FCV-447) to verify that their valve cages had not 

12 unthreaded from the valve body webs. The verification was done by obtaining the maximum 

13 stroke capability of the FCVs and relating that to a point at which the valve stem is connected 

14 into the actuator yoke (Measurements of the FCVs exposed stem threads and actuator posts were 

15 compared to the available actuator travel). These measurements provided reasonable assurance 

16 that the remaining FCV cages were properly threaded into their body webs. Following plant 

17 shutdown a walk down was performed of the four (4) FW lines inside containment and FW and 

18 AFW piping outside containment for any impacts of the FW flow perturbations. There were no 

19 indications of excessive movement or damage to the insulation, supports or piping above the 95 

20 foot elevation of containment nor was there any observed signs of excessive movements, support 

21 damage, support impacts/scarring, or insulation damage on FW lines to SG-21, SG-22, SG-23, 

22 SG-24 on any containment elevations. For FW and AFW piping outside containment, no piping 

23 or support damage was evident due to pipe movements from the flow perturbations. FW piping 

24 inside and outside containment showed some light powder insulation dust on the floor indicative 

25 of pipe vibration.

26

27 In answering the questions for this indicator, some additional information beyond that gathered 

28 for the LER will be required. In this case the usage history of the EOPs will be required. For 

29 this example consider that there were no additional EOPs used beyond the normal procedures.

30

31 1. Did two or more control rods fail to fully insert?

32

33 Did control rods that are required to move on a reactor trip fully insert into the core as 

34 evidenced by the Emergency Operating Procedure (EOP) evaluation criteria? As an 

35 example for some PWRs using rod bottom light indications, if more than one-rod bottom 

36 light is not illuminated, this question must be answered "Yes." The basis of this step is to 

37 determine if additional actions are required by the operators as a result of the failure of all 

38 rods to insert. Additional actions, such as emergency boration, pose a complication beyond 

39 the normal scram response that this metric is attempting the measure. It is allowable to 

40 have one control rod not fully inserted since core protection design accounts for one control 

41 rod remaining fully withdrawn from the core on a reactor trip. This question must be 

42 evaluated using the criteria contained in the plant EOP used to verify that control rods 

43 inserted. During performance of this step of the EOP the licensee staff would not need to 

44 apply the “Response Not Obtained” actions. Other means not specified in the EOPs are not 

45 allowed for this metric. 

46
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1 Answer:

2 NO. All control rods fully inserted as indicated by the rod bottom lights.

3

4 2. Did the turbine fail to trip? 

5

6 Did the turbine fail to trip automatically/manually as required on the reactor trip signal? To 

7 be a successful trip, steam flow to the main turbine must have been isolated by the turbine 

8 trip logic actuated by the reactor trip signal, or by operator action from a single switch or 

9 pushbutton. The allowance of operator action to trip the turbine is based on the operation 

10 of the turbine trip logic from the operator action if directed by the EOP. Operator action to 

11 close valves or secure pumps to trip the turbine beyond use of a single turbine trip switch 

12 would count in this indicator as a failure to trip and a complication beyond the normal 

13 reactor trip response. Trips that occur prior to the turbine being placed in service or 

14 “latched” should have this question answered as “No”.

15

16 Answer:

17 NO. The turbine tripped per design,

18

19 3. Was power lost to any ESF bus?

20

21 During a reactor trip or during the period operators are responding to a reactor trip using 

22 reactor trip response procedures, was power lost to any ESF bus that was not restored 

23 automatically by the Emergency Alternating Current (EAC) power system and remained 

24 de-energized for greater than 10 minutes? Operator action to re-energize the ESF bus from 

25 the main control board is allowed as an acceptable action to satisfy this metric. This 

26 question is looking for a loss of power at any time for any duration where the bus was not 

27 energized/re-energized within 10 minutes. The bus must have:

28

29 • remained energized until the scram response procedure was exited, or

30 • been re-energized automatically by the plant EAC power system (i.e., EDG), or

31 • been re-energized from normal or emergency sources by an operator closing a 

32 breaker from the main control board.

33

34 The question applies to all ESF busses (switchgear, load centers, motor control centers and 

35 DC busses). This does NOT apply to 120-volt power panels. It is expected that operator 

36 action to re-energize an ESF bus would not take longer than 10 minutes. 

37

38 Answer:

39 NO. Emergency diesels were not required to start. Offsite power remained available 

40 throughout the trip response. All ESF busses remained energized throughout the trip 

41 response.

42

43 4. Was a Safety Injection signal received?

44

45 Was a Safety Injection signal generated either manually or automatically during the reactor 

46 trip response? The questions purpose is to determine if the operator had to respond to an 
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1 abnormal condition that required a safety injection or respond to the actuation of additional 

2 equipment that would not normally actuate on an uncomplicated scram. This question 

3 would include any condition that challenged Reactor Coolant System (RCS) inventory, 

4 pressure, or temperature severely enough to require a safety injection. A severe steam 

5 generator tube leak that would require a manual reactor trip because it was beyond the 

6 capacity of the normal at power running charging system should be counted even if a safety 

7 injection was not used since additional charging pumps would be required to be started.

8

9 Answer:

10 NO. No SI signal was required or received.

11

12 5. Was Main Feedwater unavailable or not recoverable using approved plant 

13 procedures following during the scram response?

14

15 If operating prior to the scram, did Main Feedwater cease to operate and was it unable to be 

16 restarted during the reactor scram response? The consideration for this question is whether 

17 Main Feedwater could be used to feed the steam generators if necessary. The qualifier of 

18 “not recoverable using approved plant procedures” will allow a licensee to answer “No” to 

19 this question if there is no physical equipment restraint to prevent the operations staff from 

20 starting the necessary equipment, aligning the required systems, or satisfying required logic 

21 using plant procedures approved for use and in place prior to the reactor scram occurring.

22

23 The operations staff must be able to start and operate the required equipment using normal 

24 alignments and approved emergency, normal and off-normal operating procedures to feed 

25 the minimum number of steam generators required by the EOPs to satisfy the heat sink 

26 criteria. Manual operation of controllers/equipment, even if normally automatic, is 

27 allowed if addressed by procedure. Situations that require maintenance or repair activities 

28 or non-proceduralized operating alignments require an answer of “Yes.” Additionally, the 

29 restoration of Feedwater must be capable of feeding the Steam Generators in a reasonable 

30 period of time. Operations should be able to start a Main Feedwater pump and start feeding 

31 Steam Generators with the Main Feedwater System within about 30 minutes from the time 

32 it was recognized that Main Feedwater was needed. During startup conditions where Main 

33 Feedwater was not placed in service prior to the scram this question would not be 

34 considered and should be skipped. If design features or procedural prohibitions prevent 

35 restarting Main Feedwater this question should be answered as “No”.

36

37 Answer:

38 NO. Main FW was the cause of the manual reactor trip: one of four feed regulating 

39 valves (FRV-447) was unavailable for FW addition to SGs. FW pumps were available to 

40 be restarted and three FW loops could have been operated to supply FW to 3 of 4 SGs.

41

42 6. Was the scram response procedure unable to be completed without entering another 

43 EOP?

44

45 The response to the scram must be completed without transitioning to an additional EOP 

46 after entering the scram response procedure (e.g., ES01 for Westinghouse). This step is 

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(10-02)

FAQ481

(10-02)
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1 used to determine if the scram was uncomplicated by counting if additional procedures 

2 beyond the normal scram response required entry after the scram. A plant exiting the 

3 normal scram response procedure without using another EOP would answer this step as 

4 “No”. The discretionary use of the lowest level Function Restoration Guideline (Yellow 

5 Path) by the operations staff is an approved exception to this requirement. Use of the Re6 diagnosis Procedure by Operations is acceptable unless a transition to another EOP is 

7 required.

8

9 Answer:

10 NO. The reactor trip response procedures were completed without re-entering another 

11 EOP.

12

13 H 2.3 PWR Case Study 3

14

15 The An automatic reactor trip was initiated due to a low reactor coolant flow condition following 

16 a trip of the 'B' Reactor Coolant Pump (RCP) motor. The RCP trip was initiated by a current 

17 imbalance sensed by the motor's protective relay. The current imbalance was a result of a 

18 transmission system disturbance. At the time of the event, the plant was operating in Mode 1 

19 (Hot Full Power) at 100 percent power. The system disturbance was initiated by a transmission 

20 line fault within a neighboring electric cooperative's transmission system. Due to a defective 

21 electrical connection within the electric cooperative's protective relaying scheme, the 

22 transmission line breakers protecting the affected line did not receive a trip signal to clear the 

23 fault. Since the breaker failure relaying scheme utilized the same circuitry containing the 

24 defective electrical connection, breaker failure logic was not initiated to trip the next breakers 

25 upstream of the transmission line fault. In addition, there was no redundant line relaying or local 

26 backup relaying on the substation transformer. As a result, the fault was not properly cleared 

27 from the electric cooperative's transmission system. For approximately the next eight minutes, 

28 multiple subsequent faults were introduced onto the system as the transmission line incurred 

29 damage and fell to the ground over an approximate distance of six miles. Ultimately, the fault 

30 condition was cleared following the failure of the distribution system transformer supplying the 

31 faulted transmission line. Approximately one minute into the event, the "B" RCP tripped due to 

32 a motor current imbalance, which resulted from the transmission system disturbance. The 

33 automatic reactor trip was initiated for a low reactor coolant flow condition due to the RCP trip. 

34 Shortly after the reactor trip, the three remaining RCPs and all main condenser circulating water 

35 pumps also tripped because of motor current imbalance. Due to the tripping of all RCPs, the 

36 pressurizer spray system was unavailable. Additionally, the tripping of all main condenser 

37 circulating water pumps affected the ability to use the main condenser as a heat sink. This 

38 resulted in reliance on the atmospheric steam dumps causing reactor coolant system average 

39 temperature (RCS Tavg) to increase from 557 to 562 degrees F. The combination of establishing 

40 natural circulation due to the loss of all RCPs and increasing RCS Tavg, caused a pressurizer in41 surge raising RCS pressure to the pressurizer power-operated relief valve (PORV) set point. 

42 Prior to re-establishing the pressurizer spray system, both PORVs momentarily lifted once, 

43 relieving RCS pressure to the pressurizer relief tank. RCPs were restored approximately 32 

44 minutes after initiation of the event. During this entire event, all safety-related and non safety45 related systems and components functioned in accordance with design.

46
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1 In answering the questions for this indicator, some additional information beyond that gathered 

2 for the LER will be required. In this case the usage history of the EOPs will be required. For 

3 this example consider that there were no additional EOPs used beyond the normal procedures.

4

5 1. Did two or more control rods fail to fully insert?

6

7 Did control rods that are required to move on a reactor trip fully insert into the core as 

8 evidenced by the Emergency Operating Procedure (EOP) evaluation criteria? As an 

9 example for some PWRs using rod bottom light indications, if more than one-rod bottom 

10 light is not illuminated, this question must be answered "Yes." The basis of this step is to 

11 determine if additional actions are required by the operators as a result of the failure of all 

12 rods to insert. Additional actions, such as emergency boration, pose a complication beyond 

13 the normal scram response that this metric is attempting the measure. It is allowable to 

14 have one control rod not fully inserted since core protection design accounts for one control 

15 rod remaining fully withdrawn from the core on a reactor trip. This question must be 

16 evaluated using the criteria contained in the plant EOP used to verify that control rods 

17 inserted. During performance of this step of the EOP the licensee staff would not need to 

18 apply the “Response Not Obtained” actions. Other means not specified in the EOPs are not 

19 allowed for this metric. 

20

21 Answer:

22 NO. All control rods fully inserted as indicated by rod bottom lights.

23

24 2. Did the turbine fail to trip? 

25

26 Did the turbine fail to trip automatically/manually as required on the reactor trip signal? To 

27 be a successful trip, steam flow to the main turbine must have been isolated by the turbine 

28 trip logic actuated by the reactor trip signal, or by operator action from a single switch or 

29 pushbutton. The allowance of operator action to trip the turbine is based on the operation 

30 of the turbine trip logic from the operator action if directed by the EOP. Operator action to 

31 close valves or secure pumps to trip the turbine beyond use of a single turbine trip switch 

32 would count in this indicator as a failure to trip and a complication beyond the normal 

33 reactor trip response. Trips that occur prior to the turbine being placed in service or 

34 “latched” should have this question answered as “No”.

35

36 Answer:

37 NO. The turbine tripped per design.

38

39 3. Was power lost to any ESF bus?

40

41 During a reactor trip or during the period operators are responding to a reactor trip using 

42 reactor trip response procedures, was power lost to any ESF bus that was not restored 

43 automatically by the Emergency Alternating Current (EAC) power system and remained 

44 de-energized for greater than 10 minutes? Operator action to re-energize the ESF bus from 

45 the main control board is allowed as an acceptable action to satisfy this metric. This 
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1 question is looking for a loss of power at any time for any duration where the bus was not 

2 energized/re-energized within 10 minutes. The bus must have:

3

4 • remained energized until the scram response procedure was exited, or

5 • been re-energized automatically by the plant EAC power system (i.e., EDG), or

6 • been re-energized from normal or emergency sources by an operator closing a 

7 breaker from the main control board.

8

9 The question applies to all ESF busses (switchgear, load centers, motor control centers and 

10 DC busses). This does NOT apply to 120-volt power panels. It is expected that operator 

11 action to re-energize an ESF bus would not take longer than 10 minutes. 

12

13 Answer:

14 NO. All ESF busses remained energized throughout the trip response.

15

16 4. Was a Safety Injection signal received?

17

18 Was a Safety Injection signal generated either manually or automatically during the reactor 

19 trip response? The questions purpose is to determine if the operator had to respond to an 

20 abnormal condition that required a safety injection or respond to the actuation of additional 

21 equipment that would not normally actuate on an uncomplicated scram. This question 

22 would include any condition that challenged Reactor Coolant System (RCS) inventory, 

23 pressure, or temperature severely enough to require a safety injection. A severe steam 

24 generator tube leak that would require a manual reactor trip because it was beyond the 

25 capacity of the normal at power running charging system should be counted even if a safety 

26 injection was not used since additional charging pumps would be required to be started.

27

28 Answer:

29 NO. No SI signal was required or received.

30

31 5. Was Main Feedwater unavailable or not recoverable using approved plant 

32 procedures following during the scram response?

33

34 If operating prior to the scram, did Main Feedwater cease to operate and was it unable to be 

35 restarted during the reactor scram response? The consideration for this question is whether 

36 Main Feedwater could be used to feed the steam generators if necessary. The qualifier of 

37 “not recoverable using approved plant procedures” will allow a licensee to answer “No” to 

38 this question if there is no physical equipment restraint to prevent the operations staff from 

39 starting the necessary equipment, aligning the required systems, or satisfying required logic 

40 using plant procedures approved for use and in place prior to the reactor scram occurring.

41

42 The operations staff must be able to start and operate the required equipment using normal 

43 alignments and approved emergency, normal and off-normal operating procedures to 

44 feed the minimum number of steam generators required by the EOPs to satisfy the heat 

45 sink criteria. Manual operation of controllers/equipment, even if normally automatic, is 

46 allowed if addressed by procedure. Situations that require maintenance or repair activities 

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1 or non-proceduralized operating alignments require an answer of “Yes.” Additionally, the 

2 restoration of Feedwater must be capable of feeding the Steam Generators in a reasonable 

3 period of time. Operations should be able to start a Main Feedwater pump and start 

4 feeding Steam Generators with the Main Feedwater System within about 30 minutes. 

5 During startup conditions where Main Feedwater was not placed in service prior to the 

6 scram this question would not be considered and should be skipped. If design features or 

7 procedural prohibitions prevent restarting Main Feedwater this question should be 

8 answered as “No”.

9

10 Answer:

11 YES. The loss of power resulted in a complete loss of circulating water and the ability of 

12 main feedwater pump turbines to exhaust to the condenser. This question could be 

13 answered as “NO” if circulating water, condenser vacuum, and main feedwater could be 

14 restored within the 30 minute timeframe, or if an electric driven main feedwater pump 

15 was available that did not required condenser vacuum to feed steam generators. 

16

17 6. Was the scram response procedure unable to be completed without entering another 

18 EOP?

19

20 The response to the scram must be completed without transitioning to an additional EOP 

21 after entering the scram response procedure (e.g., ES01 for Westinghouse). This step is 

22 used to determine if the scram was uncomplicated by counting if additional procedures 

23 beyond the normal scram response required entry after the scram. A plant exiting the 

24 normal scram response procedure without using another EOP would answer this step as 

25 “No”. The discretionary use of the lowest level Function Restoration Guideline (Yellow 

26 Path) by the operations staff is an approved exception to this requirement. Use of the Re27 diagnosis Procedure by Operations is acceptable unless a transition to another EOP is 

28 required.

29

30 Answer:

31 NO. The reactor trip response procedures were completed without re-entering another 

32 EOP.

33

34 H 3 BWR Flowchart Basis Discussion

35

36 H 3.1 Did an RPS actuation fail to indicate / establish a shutdown rod pattern for a cold 

37 clean core?

38

39 The purpose of this question is to verify that the reactor actually tripped and had sufficient 

40 indication for operations to verify the trip. As long as a plant uses the EOP questions to 

41 verify that the reactor tripped without entering the level/pressure control leg of the EOPs, the 

42 response to this question should be “No”. 

43

44 The generic BWROG EPG/SAG Revision 2 Appendix B statement is offered as an example:

45

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1 Any control rod that cannot be determined to be inserted to or beyond position [02 

2 (Maximum Subcritical Banked Withdrawal Position)] and it has not been determined that the 

3 reactor will remain shutdown under all conditions without boron, enter Level/Power Control.

4

5 For example:.

6 Are all control rods inserted to or beyond position 02 (if no then this is a yes for this PI)? 

7 Will the reactor remain subcritical under all conditions without boron (if no then this is a 

8 “Yes” for this PI)?

9

10 For example:.

11 All rods not fully inserted; and, the reactor will not remain shutdown under all conditions 

12 without boron then enter level/pressure control (if yes then this is a “Yes” for this PI).

13

14 H 3.2 Was pressure control unable to be established following the initial transient?

15

16 This question is designed to verify the ability to transfer reactor energy to the environment 

17 using the normal pressure control system. The initial cycling of SRVs is typical for some 

18 transients in which there was no failure of the normal pressure control system. Initial 

19 operation of the SRVs is not indicative of pressure control problems with the normal pressure 

20 control system. Therefore, cycling may occur post-trip until the pressure is controlled. Any 

21 subsequent cycling after pressure has been controlled would result in a “YES” answer. Some 

22 plant designs also may have a setpoint setdown of SRVs which would open additional SRVs 

23 and reduce reactor pressure below the normal SRV closing setpoint. Any additional opening 

24 of SRVs to control reactor pressure either automatically or manually indicates the inability of 

25 the normal pressure control system to operate properly. Stuck open SRV(s) bypass the 

26 normal pressure control system and would result in a “YES” for this PI. 

27

28 For example:

29 A turbine trip occurs and SRVs open to control reactor pressure. The setpoint setdown 

30 actuates and reduces reactor pressure from a normal 1025 psig to 930 psig. Following 

31 closure of SRVs reactor pressure increases due to decay heat and bypass valves open. This 

32 question would be answered “NO”.

33

34 For example:

35 A pressure controller failure occurs with scram on high reactor pressure. The SRVs open to 

36 control reactor pressure. The setpoint setdown actuates and reduces reactor pressure from a 

37 normal 1025 psig to 930 psig. Following closure of SRVs reactor pressure increases due to 

38 decay heat and SRVs open again to control reactor pressure. The operator takes manual 

39 control of bypass valves and opens the bypass valves to maintain reactor pressure. This 

40 question would be answered “YES”. The yes answer is a result of SRVs opening after 

41 pressure control was established from the initial transient.

42

43 For example:

44 The pressure controller failure occurs with scram on high reactor pressure. The SRVs open to 

45 control reactor pressure. Setpoint setdown actuates and reduces reactor pressure from a 

46 normal 1025 psig to 930 psig. Following closure of SRVs reactor pressure does not increase 
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1 because the scram occurred with low decay heat load and Main Steam Line drains were open. 

2 This question would be answered “NO”.

3

4 H 3.3 Was power lost to any Class 1E Emergency / ESF bus?

5

6 Plants with a dedicated High Pressure Core Spray (HPCS) bus do not count the HPCS ESF 

7 bus in this PI.

8

9 The purpose of this question is to verify that electric power was available after the reactor 

10 trip. Loss of electrical power may result in other criteria being met in this PI. This question 

11 deals only with electrical power. Should electrical power be maintained or restored within 

12 the allowed 10 minutes, the response to this question should be ”No”. There is an exemption 

13 to this step that permits an Operator to manually restore power within 10 minutes as an 

14 acceptable alternative. The exception is limited to those actions necessary to close a 

15 breaker(s) or switch(es) from the main control board. Actions requiring access to the back of 

16 the control boards or any other remote location would require answering this question as 

17 “Yes”. It is acceptable to manipulate more than one switch, such as a sync switch, in the 

18 process of restoring power to the bus. It is acceptable to close more than one breaker. It is 

19 acceptable to restore power from the emergency AC source, such as the diesel generators, or 

20 from off-site power. The additional operator action to restore power to additional buses has 

21 been discussed and considered acceptable as long as it can be completed within the time 

22 limitations of 10 minutes (chosen to limit the complexity) and the constraints of breaker or 

23 switch operation from the main control board. Any actions beyond these would need to be 

24 considered as a complication for this question. Because of the wide variation in power 

25 distribution designs, voltage, and nomenclature in various plant designs no specific examples 

26 are given here. There is an exception for a plant designed with a dedicated High Pressure 

27 Core Spray Pump (HPCS) ESF bus. If a plant has a dedicated (only provides power to 

28 HPCS equipment) then the HPCS ESF bus does not have to be considered in this question. 

29 This would be similar to a scram with a loss of HPCI which in of itself would not count in 

30 this PI.

31

32 H 3.4 Was a Level 1 Injection signal received?

33

34 The consideration of this question is whether or not the operator had to respond to abnormal 

35 conditions that required a low pressure safety injection or if the operator had to respond to 

36 the actuation of additional equipment that would not normally actuate on an uncomplicated 

37 scram. For some plant designs some events result in a high pressure injection signal on 

38 vessel level. Automatic or manual initiation of low pressure ECCS indicates the inability of 

39 high pressure systems to operate properly or that a significant leak has occurred. Alternately, 

40 the question would be plants that do not have a separate high pressure ECCS level signal

41 from their Low level ECCS signal an allowance is made to deviate from this question and 

42 answer “Yes” if the system injected.

43
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1 H 3.5 Was Main Feedwater not available or not recoverable using approved plant 

2 procedures during the scram response?

3

4 If operating prior to the scram, did Main Feedwater cease to operate and was it unable to be 

5 restarted during the reactor scram response? The consideration for this question is whether 

6 Main Feedwater could be used to feed the reactor vessel if necessary. The qualifier of “not 

7 recoverable using approved plant procedures” will allow a licensee to answer “NO” to this 

8 question if there is no physical equipment restraint to prevent the operations staff from 

9 starting the necessary equipment, aligning the required systems, or satisfying required logic 

10 circuitry using plant procedures approved for use that were in place prior to the scram 

11 occurring.

12

13 The operations staff must be able to start and operate the required equipment using normal 

14 alignments and approved emergency, normal and off-normal operating procedures. 

15 Manual operation of controllers/equipment, even if normally automatic, is allowed if 

16 addressed by procedure. Situations that require maintenance or repair activities or non17 proceduralized operating alignments will not satisfy this question. Additionally, the 

18 restoration of Main Feedwater must be capable of being restored to provide feedwater to the 

19 reactor vessel in a reasonable period of time. Operations should be able to start a Main 

20 Feedwater pump and start feeding the reactor vessel with the Main Feedwater System within 

21 about 30 minutes from the time it was recognized that Main Feedwater was needed. During 

22 startup conditions where Main Feedwater was not placed in service prior to the scram, this 

23 question would not be considered, and should be skipped. 

24

25 H 3.6 Following initial transient, did stabilization of reactor pressure/level and drywell 

26 pressure meet the entry conditions for EOPs?

27

28 Since BWR designs have an emergency high pressure system that operates automatically 

29 between a vessel-high and vessel-low level, it is not necessary for the Main Feedwater 

30 System to continue operating following a reactor trip. However, failure of the Main 

31 Feedwater System to be available is considered to be risk significant enough to require a 

32 “Yes” response for this PI. To be considered available, the system must be free from damage 

33 or failure that would prohibit restart of the system. Therefore, there is some reliance on the 

34 material condition or availability of the equipment to reach the decision for this question. 

35 Condenser vacuum, cooling water, and steam pressure values should be evaluated based on 

36 the requirements to operate the pumps, and may be lower than normal if procedures allow 

37 pump operation at that lower value. 

38

39 The estimated 30-minute timeframe for restart of Main Feedwater was chosen based on 

40 restarting from a hot condition with adequate reactor water level. Since this timeframe

41 will not be measured directly, it should be an estimation developed based on the material 

42 condition of the plants systems following the reactor trip. If no abnormal material conditions 

43 exist, the 30 minutes should be capable of being met. If plant procedures and design would 

44 require more than 30 minutes, even if all systems were hot and the material condition of the 

45 systems following the reactor trip were normal, a routine time should be used in the 

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1 evaluation of this question. The considered opinionjudgment of an on-shift licensed SRO

2 should be used in determining if in meeting this timeframe is acceptablemet.

3

4 When a scram occurs plant operators will enter the EOPs to respond to the condition. In the 

5 case of a routine scram the procedure entered will be exited fairly rapidly after verifying that 

6 the reactor is shutdown, excessive cooling is not in progress, electric power is available, and 

7 reactor coolant pressures and temperatures are at expected values and controlled. Once these 

8 verifications are done and the plant conditions considered “stable” (see guidance in the 

9 Definition of Terms section under scram response) operators will exit the initial procedure 

10 to another procedure that will stabilize and prepare the remainder of the plant for transition 

11 for the use of normal operating procedures. The plant would then be ready be maintained in 

12 Hot Standby, to perform a controlled normal cool down, or to begin the restart process. The 

13 criteria in this question is used to verify that there were no other conditions that developed 

14 during the stabilization of the plant in the scram response related vessel parameters that 

15 required continued operation in the EOPs or re-entry into the EOPs or transition to a follow16 on EOP. Maintaining operation in EOPs that are not related to vessel and drywell parameters 

17 do not count in this PI. 

18

19 For example:

20 Suppression Pool level high or low require entry into an EOP on Containment Control. 

21 Meeting EOP entry conditions for this EOP do not count in this PI.

22

23 H 4 BWR Case Studies

24

25 H 4.1 BWR Case Study 1

26

27 A plant experienced an automatic reactor scram as a result of a breaker tripping due to a 

28 ground fault on the 34.5kv bus work downstream of the Service Transformer. Loss of 

29 service transformer resulted in the loss of power to 2 of 4 balance of plant main busses and 

30 one of 3 ESF busses. Emergency Diesel Generator Division 1 started on a loss of power and 

31 connected to the ESF bus.

32

33 The Main Generator tripped on reverse power and the turbine bypass valves opened to 

34 control pressure. No SRVs opened during this event. 

35

36 Both RPS actuation systems actuated, although for different reasons. The “A” RPS system 

37 actuated on loss of power to the Balance of Plant (BOP) (power to RPS “A” MG set) bus 

38 since it was powered from a service transformer. With the accompanying loss of power to 

39 the condensate/feedwater system components, the “B” RPS system actuated on low reactor 

40 water level of 11.4 inches. All control rods inserted to 00 position. 

41

42 Reactor water level dropped to approximately -75 inches on wide range level instrumentation 

43 before the High Pressure Core Spray (HPCS) and Reactor Core Isolation Cooling (RCIC) 

44 systems initiated at -41.6 and restored level to the EOP specified band. Level control was 

45 transferred to the startup level controller and both HPCS and RCIC were secured.

46

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1 Primary, secondary, and drywell isolations occurred as designed at -41.6 inches along with 

2 the start of the Division III (HPCS) diesel. 

3

4 A walk down of the switchyard following the reactor scram discovered that a raccoon had 

5 entered the service transformer area and caused the ground fault.

6

7 Prior to the scram power was 100% with both main feedwater pumps in service.

8

9 Feedwater was unavailable to control level.

10

11 Vessel level was restored to the EOP level band (+11.4 inches [low level scram setpoint] 

12 to +53.5 inches [high level feedpump trip setpoint]) without any additional scram signals. 

13 Drywell pressure was not affected noticeably by this event.

14

15 1. Did RPS actuation fail to indicate/establish a shutdown rod pattern for a cold clean 

16 core.

17 Answer: “No”. As indicated Alternate Rod Insertion was not indicated or required.

18 Alternate yes / no answers as examples:

19 Answer: “No”. While all rods did not fully insert, reactor engineering, using an approved 

20 procedure, ran a computer calculation that determined the reactor would remain shutdown 

21 under cold clean conditions.

22 Answer: “Yes”. All rods did not insert, reactor engineering could not be contacted so 

23 operations entered the ATWS leg of EOPs. Subsequent calculation by reactor engineering 

24 determined the reactor would remain shutdown under cold clean conditions.

25 Answer: “Yes”. All rods failed to fully insert. 

26 2. Was pressure control unable to be established following initial transient?

27 Answer: “No”. The Main Turbine did not trip as a result of the switchyard transient. 

28 The turbine did eventually trip on reverse power at which time the turbine bypass valves 

29 operated to control reactor pressure.

30 Alternate yes / no answers as examples.

31 Answer: “No”. The main turbine tripped resulting in opening of one or more SRVs. 

32 Following the initial opening of the SRVs, the main turbine bypass valves opened to 

33 control pressure.

34 Answer: “Yes”. The main turbine tripped resulting in opening of all 20 SRVs. As a result 

35 of pressure controller problems operations subsequently manually opened an additional 

36 SRV to control reactor pressure.
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1 Answer: “Yes”. The main turbine tripped and as a result of loss of condenser vacuum, 

2 one or more SRVs were used to control reactor pressure. 

3 3. Was power lost to any class 1E Emergency/ESF bus?

4 Answer: “No”. While an ESF bus (Division I) did lose power, the EDG started and 

5 restored power to the ESF bus.

6 Alternate yes / no answers as examples.

7 Answer: “No”. Power was lost to an ESF bus. The EDG was out of service and power 

8 was restored by closing an alternate feed breaker from the control room.

9 Answer: “Yes”. Power was lost to an ESF bus. The EDG was out of service. Power was 

10 restored to the ESF bus by resetting a lockout in the back panels and closing the breaker 

11 from the control room.

12 4. Was a level 1 Injection signal received?

13 Answer: “No”. Vessel level did decrease to approximately -75 inches resulting in the 

14 automatic start of RCIC and HPCS. However, for this plant Level 1 is -150.3 inches.

15 Alternate yes / no answers as examples,

16 Answer: “No”. HPCS and RCIC failed to start/run. Level dropped to -110 inches but was 

17 stabilized by use of Control Rod Drive (CRD) pumps.

18 Answer: “Yes”. HPCS and RCIC failed to start/run. Vessel level decreased to 

19 near -150.3 inches and operators manually initiated low pressure.

20 5. Was main feedwater unavailable or not recoverable using approved plant 

21 procedures following during the scram response?

22 Answer: “No”. While some of the condensate system pumps lost power resulting in 

23 both feedwater pumps tripping, the feedwater system was restored by use of normal 

24 procedures. Feedwater was restored, and RCIC/HPCS was secured.

25 Alternate yes / no answers as examples

26 Answer: “No”. Level was restored by RCIC. A condensate and condensate booster 

27 pump remained operating. While both feedwater pumps tripped there were no known 

28 issues with either pump that would prevent restarting if needed.

29 Answer: “Yes”. Level was restored by RCIC. A condensate and condensate booster 

30 pump remained operating. Both feedwater pumps tripped and problems with condenser 

31 vacuum prevented restart of the feedpumps if they had been needed.

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1 6. Following initial transient did stabilization of reactor pressure/level and drywell 

2 pressure meet the entry conditions for EOPs?

3 Answer: “No”. Following the initial event, reactor pressure was controlled by the 

4 turbine pressure control system to less than the high reactor pressure entry condition of 

5 1064.7 psig [reactor high pressure scram setpoint]. Vessel level was restored to the EOP 

6 level band (+11.4 inches[low level scram setpoint] to +53.5 inches [high level feedpump 

7 trip setpoint]) without any additional scram signals. Drywell pressure was not affected 

8 noticeably by this event. 

9 Alternate yes / no answers as examples.

10 Answer: “No”. Following the initial event, reactor pressure was controlled by the turbine 

11 pressure control system to less than the high reactor pressure entry condition of 1064.7 

12 psig [reactor high pressure scram setpoint]. Vessel level was restored to the EOP level 

13 band (+11.4 inches [low level scram setpoint] to +53.5 inches [high level feedpump trip 

14 setpoint]) without any additional scram signals. The vessel was overfed twice, resulting 

15 in a high level trip of the feedpump. However, when level decreased to less than the high 

16 level trip setpoint, the feed pump was restored to operation by procedure. Drywell 

17 pressure was not affected noticeably by this event.

18 Answer: “Yes”. Following the initial event, reactor pressure was controlled by the 

19 turbine pressure control system to less than the high reactor pressure entry condition of 

20 1064.7 psig [reactor high pressure scram setpoint]. Vessel level was restored to the EOP 

21 level band (+11.4 inches[low level scram setpoint] to +53.5 inches [high level feedpump 

22 trip setpoint]) but startup level control valve problems resulted in an additional low level 

23 scram signal. 

24 H 4.2 BWR Case Study 2

25

26 A plant received an automatic scram on a Turbine Control Valve Fast Closure as a result of a 

27 load reject. The initiating event for the automatic scram was closure of a 500 kV disconnect 

28 which was open for maintenance. High winds contributed to the disconnect closing and 

29 contacting the energized bus. The pressure exerted by the wind on the disconnect blades 

30 overcame the spring counterbalance of the disconnect switch. Additionally, the “Open” 

31 position lock bracket on the motor operator was broken. A low impedance ground fault was 

32 created through the installed maintenance grounds. 

33 The fault resulted in actuation of the Service Transformer differential lockout and the West 

34 500 kV buss differential lockout. Breakers opened as designed due to the Service 

35 transformer lockouts and the West Bus lockouts. This resulted in the loss of one of the 2 

36 service transformers and all plant busses normally powered from this transformer, including 

37 safety related busses Division 2 and 3 which were powered from the service transformer. 

38 The Division 2 & 3 EDGs subsequently started and appropriately re-energized the ESF 

39 buses.

40 Within 3-5 cycles of the ground fault, breakers opened at a nearby substation de-energizing 

41 the remaining 500 kV incoming power to the switchyard. This left the main generator 
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1 supplying power to some of the in-house loads including Balance of Plant and Division I 

2 Safety Related Bus (ESF Division I)

3 The load reject relays then actuated producing a Turbine Control Valve Fast Closure 

4 (TCV/FC) signal and a subsequent reactor scram. Approximately 4 seconds later the turbine 

5 speed increased to 1900 rpm and generator output frequency increased to 63.5 Hz. 

6 Subsequently, the turbine tripped as the generator remained excited and the turbine-generator 

7 began coasting down into an under-frequency condition. Generator output voltage remained 

8 constant.

9 As the turbine coasted down an under frequency condition occurred resulting in the turbine 

10 output breaker opening. This resulted in loss of the Division 1 ESF bus as well as loss of the 

2nd 11 service transformer and all remaining balance of plant loads about 2-3 minutes following 

12 the initial scram. 

13 In summary the loss of power to the plant BOP, which resulted in loss of Feedwater and 

14 normal pressure control, occurred in stages over several minutes, but still within the initial 

15 transient. The ESF buses also lost power but were restored automatically by the D/Gs.

16

17 1. Did RPS actuation fail to indicate/establish a shutdown rod pattern for a cold clean 

18 core?

19 Answer: “No”. Alternate Rod Insertion was not indicated or required.

20 2. Was pressure control unable to be established following initial transient?

21 Answer: “Yes”. While SRVs open once on the load reject and steam pressure decreased 

22 as the turbine coasted down, the loss of all balance of plant power several minutes later 

23 when the main generator tripped, resulted in loss of pressurized fluid for the hydraulic 

24 bypass valves. This resulted in the use of the SRVs to control reactor pressure following 

25 the initial scram. Additionally, the loss of the balance of plant power resulted in loss of 

26 main condenser cooling which prevented use of the main condenser as a heat sink. 

27 3. Was power lost to any class 1E Emergency/ESF bus?

28 Answer: “No”. While all ESF busses lost power the EDGs started and restored power 

29 automatically to the ESF busses.

30 4. Was a level 1 Injection signal received?

31 Answer: “No”. Vessel level did drop to about -42 inches resulting in auto start of 

32 RCIC. The level 1setpoint is -150.3 inches.

33 5. Was main feedwater unavailable or not recoverable using approved plant 

34 procedures following during the scram response?

35 Answer: “Yes”. The loss of balance of plant power after several minutes resulted in loss 

36 of all condensate and condensate booster pumps as well as loss of power to condensate 
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1 and feedwater valves, preventing the use of feedwater to control level. Level was 

2 controlled by RCIC. 

3 6. Following initial transient did stabilization of reactor pressure/level and drywell 

4 pressure meet the entry conditions for EOPs?

5 Answer: “No”. Following the initial event, reactor pressure was controlled by the SRVs 

6 to maintain the reactor pressure below the EOP entry setpoint of 1067.5 psig [reactor 

7 high pressure scram setpoint]. The vessel level was restored to the EOP level band 

8 (+11.4 inches[low level scram setpoint] to + 53.5 inches [high level feedpump trip 

9 setpoint]) by use of RCIC with one additional scram signal on high level Drywell 

10 pressure did increase slightly as a result of loss of cooling but never exceeded the EOP 

11 setpoint of 1.23 psig. The EOP for containment control was entered as a result of high 

12 suppression pool level due to swell from the heat/mass addition from the operation of 

13 systems (e.g.RCIC, SRVs).