POLICY ISSUE

INFORMATION

October 24, 2005 SECY-05-0192

FOR: The Commissioners

FROM: Luis A. Reyes

Executive Director for Operations

SUBJECT: STATUS OF THE ACCIDENT SEQUENCE PRECURSOR (ASP) PROGRAM

AND THE DEVELOPMENT OF STANDARDIZED PLANT ANALYSIS RISK

(SPAR) MODELS

PURPOSE:

To inform the Commission of the status of the Accident Sequence Precursor (ASP) Program,

provide the annual quantitative ASP results, and communicate the status of the development

of the Standardized Plant Analysis Risk (SPAR) models.

SUMMARY:

This report discusses the following activities, which the staff has performed since the last status

report (SECY-04-0210), dated November 8, 2004:

• Analysis of the FY 2003 and FY 2004 events to identify precursors (i.e., events with a

conditional core damage probability (CCDP) or increase in core damage probability ()CDP)

that is greater than or equal to 1×10-6).

• The screening and analyses of events for fiscal year (FY) 2005 to identify significant

precursors, defined CCDP or )CDP that is greater than or equal to 1×10-3. 

• Evaluation of precursor data to identify statistically significant adverse trends for the

Industry Trends Program.

CONTACTS: Eliezer B. Goldfeiz, RES (ASP Program)

301-415-5539

Michael C. Cheok, RES (SPAR Model Development Program)

301-415-7496
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• Revision of SPAR models for all plants for internal initiating events during full-power

operation, completion of SPAR models for one lead plant for internal initiating events during

low-power and shutdown operations, and completion of SPAR models for two lead plants

for the calculation of large early release frequency (LERF), and completion of SPAR models

for four plants for external events.

• Identification of organizational conflict of interest concerns with our contractor, Idaho

National Laboratory, for several projects including those for SPAR model development. 

In addition, this report summarizes related upcoming activities for the next 12 months.

BACKGROUND:

In a memorandum to the Chairman dated April 24, 1992, the staff of the U.S. Nuclear

Regulatory Commission (NRC) committed to report periodically to the Commission on the

status of the ASP Program. In SECY-94-268, dated October 31, 1994, the staff made two

significant changes to the report. First, the staff committed to provide the report annually, and

second, the staff began to provide annual quantitative ASP results.

ASP Program

The NRC established the ASP Program in 1979 in response to the Risk Assessment Review

Group report (see NUREG/CR-0400, dated September 1978). The ASP Program

systematically evaluates U.S. nuclear power plant operating experience to identify, document,

and rank the operating events that were most likely to have led to inadequate core cooling and

severe core damage (precursors), accounting for the likelihood of additional failures.

To identify potential precursors, NRC staff reviews plant events from licensee event reports

(LERs), inspection reports, and special requests from NRC staff. The staff then analyzes any

identified potential precursors by calculating a probability of an event leading to a core damage

state. A plant event can be one of two types: (1) an occurrence of an initiating event, such as a

reactor trip or a loss of offsite power (LOOP), with any subsequent equipment unavailability or

degradation or (2) a degraded plant condition depicted by unavailability or degradation of

equipment without an occurrence of an initiating event. 

For the first type, a conditional core damage probability (CCDP) is calculated. This metric

represents a conditional probability that a core damage state is reached, given an occurrence of

an initiating event (and any subsequent equipment failure or degradation). 

For the second type, an increase in core damage probability ()CDP) is calculated. This metric

represents the increase in the probability of reaching a core damage state for the period that an

equipment or a combination of equipment is deemed unavailable or degraded from a nominal

core damage probability for the same period for which the nominal failure or unavailability

probability is assumed for the subject equipment.

An event with a CCDP or a )CDP greater than or equal to 1×10-6 is considered a precursor in

the ASP Program. The ASP Program defines a significant precursor as an event with a CCDP

or )CDP greater than or equal to 1×10-3.
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Program objectives. The ASP Program has the following objectives:

• Provide a measure for trending nuclear power plant core damage risk.

• Provide a partial check on dominant core damage scenarios predicted by probabilistic risk

assessments (PRAs).

• Provide feedback to regulatory activities.

• Evaluate the adequacy of NRC programs.

The NRC also uses the ASP Program to monitor performance against the safety goal

established in the agency’s Strategic Plan. (See NUREG-1100, Vol. 21, dated February 2005.) 

Specifically, the program provides input to the following performance measures:

• Zero events per year identified as a significant precursor of a nuclear reactor accident

(i.e., CCDP or )CDP greater than or equal to 1×10-3).

• No more than one significant adverse trend in industry safety performance with no trend

exceeding Abnormal Occurrence Criterion I.D.4.

Program scope. The ASP Program is one of three agency programs that assess the risk

significance of issues and events. (The other two programs are the Significance Determination

Process (SDP) and the Event Response Evaluation Process, as defined in Management

Directive 8.3, “NRC Incident Investigation Program”). Compared to the other two programs, the

ASP Program assesses the significance of a broader range of operating experience at U.S.

nuclear power plants. For example, when compared to the SDP, the ASP program analyzes

initiating events as well as degraded conditions where no deficiency in the licensee’s

performance was identified. In addition, because of the broader objectives of the ASP

Program, ASP analyses will often provide a more detailed evaluation of events, including

uncertainty and sensitivity analyses. Attachment 3 to this paper documents the differences

and scopes of the three programs.

SPAR Model Development Program

The objective of the SPAR Model Development Program is to develop standardized risk

analysis models and tools that staff analysts use in many regulatory activities, including the

ASP Program and Phase 3 of the Significance Determination Process (SDP). The SPAR

models have evolved from two sets of simplified event trees that were initially used to perform

precursor analyses in the early 1980s. Today’s Level 1, Revision 3 SPAR models for internal

events are far more comprehensive than their predecessors. For example, the revised SPAR

models include a new, improved loss of offsite power/station blackout (LOOP/SBO) module,

which the staff used in evaluating station blackout risk as part of the agency’s efforts to address

issues related to the reliability of the Nations’s electric power grid.

The Level 1, Revision 3 SPAR models comprise a standardized, plant-specific set of

PRA-based risk models that use the event tree/fault tree linking methodology. They also use

an NRC-developed standard set of event trees and standardized input data for initiating event

frequencies, equipment performance, and human performance, although these input data may

be modified to be more plant- and event-specific, when needed. The system fault trees

contained in the SPAR models are not as detailed as those contained in licensees’ PRA
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models. However, benchmarking performed during the onsite quality assurance review of the

SPAR models indicated that the core damage frequency from the SPAR models are no more

than 15 to 20 percent different when compared to the estimates from the licensee PRA models.

In 1999, the SPAR Model Users Group (SMUG) assumed coordination of model development

efforts that support the ASP Program and other risk-informed regulatory processes. This group

is composed of representatives from RES, the Office of Nuclear Reactor Regulation (NRR),

and the NRC’s regional offices. In August 2000, the SMUG completed the SPAR Model

Development Plan, which addresses the following models:

• Internal initiating events during full-power operation (Revision 3 SPAR models)

• Internal initiating events during low-power and shutdown (LP/SD) operations

• External initiating events (including fires, floods, and seismic events)

• Calculation of large early release frequency (LERF)

DISCUSSION:

This section summarizes the status, accomplishments, and results of each program since

the previous status report, SECY-04-0210, dated November 8, 2004.

Status of the ASP Program and SPAR Model Development Program

The following subsections summarize the status of ongoing activities and the accomplishments

of the ASP Program and SPAR Model Development Program. Attachment 1 to this paper

provides additional detail.

ASP Program

• Completed all precursor analyses from FYs 2001, 2002, and 2003, with the exception of the

ongoing analyses of the control rod drive mechanism nozzles at several plants which the

staff is currently analyzing.

• Completed the screening for FY 2004 and FY 2005 events for significant precursors (i.e.,

CCDP or )CDP greater than or equal to 1×10-3). The staff has not identified any significant

precursors for these years. The staff has completed the more detailed analyses for FY

2004 events, and has begun similar analyses for FY 2005 events. These analyses will be

finalized following peer review. 

• Evaluated precursor data to identify statistically significant adverse trends for the Industry

Trends Program.

• Issued (April 2005) the Risk Assessment Standardization Project (RASP) guidelines for

internal events during power operations as a collaborative effort involving RES, NRR, and

the regions, to standardize the risk assessment of operating events and conditions within

the agency.

• Developed expert elicitation guidelines to assist ASP and Significance Determination

Process (SDP) analysts in developing and documenting an estimate of plant conditions or

equipment functionality in cases where data are insufficient or inadequate.
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1 Screening and reviews of FY 2005 events have been completed through September 30, 2005.

SPAR Model Development Program

• Developed enhanced Revision 3 SPAR models in response to an NRR user need. This

effort involved (1) performing a cut set level review against the respective licensee’s plant

PRA to each of the Revision 3 SPAR models for the 61 plants that were not pilot plants in

the Mitigating Systems Performance Index (MSPI) Development Program, and (2)

incorporating into the Revision 3 SPAR models the resolution of the PRA modeling issues

that were identified (a) during the onsite quality assurance (QA) reviews of the Revision 3

SPAR models, (b) during the MSPI pilot program reviews, and (c) based on feedback from

model users.

• Completed SPAR model for one lead plant for internal initiating events during LP/SD

operations.

• Completed the SPAR model for calculating LERF for the lead plants in the second and third

plant classes.

• Incorporated external initiating events (i.e., internal fires, floods, and seismic event

sequences) into the Revision 3 SPAR models for Limerick, Salem, Callaway, Wolf Creek,

and Kewaunee.

• Developed a user-friendly interface for use with the Revision 3 SPAR models.

• Continued to interact with the Advisory Committee on Reactor Safeguards (ACRS) in its

quality review of the SPAR Model Development Program.

ASP Results, Trends, and Insights

This section summarizes the ASP results, trends, and insights, while Attachment 2 provides

additional detail.

• The staff completed the final analysis of the FY 2002 event at Davis-Besse Nuclear Power

Station, which involved multiple degraded conditions. This event is a significant precursor

()CDP = 6×10-3). No significant precursors were identified in FYs 2003, 2004, and 2005.1

• Four precursors identified in FY 2002–2004 had a )CDP greater than 1×10-4. These events

included the multiple degraded conditions at Davis-Besse, the potential common mode

failure of auxiliary feedwater at Point Beach 1 & 2 (original design deficiency), and another

potential common mode failure of auxiliary feedwater at Point Beach 2 (potential clogging of

recirculation lines).
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2 The trend analyses include preliminary FY 2004 analysis results. In addition, the staff is currently analyzing conditions

involving primary water stress corrosion cracking of control rod drive mechanism (CRDM) housings. For the purposes of

CCDP bin trend analyses, the CRDM cracking events were placed in the 10-5 CCDP bin based on preliminary results.

3 If a trend is considered statistically significant it is very unlikely that the trend is solely a result of chance (explained in

Attachment 2, Section 2.0).

• No statistically significant trend was identified in the rates of occurrence of all precursors

during the period from FY 1993 through FY 2004.2

 The staff will report on this result in the

NRC’s Performance and Accountability Report for FY 2005.

• Trending of precursors by CCDP bins is shown below. 

CCDP > 1×10-3 No trend

1×10-3 > CCDP > 1×10-4 Decreasing trend - statistically significant3

1×10-4 > CCDP > 1×10-5 No trend

1×10-5 > CCDP > 1×10-6 Increasing trend - statistically significant

• No trend is detected in the $10-3 CCDP bin and a decreasing trend is observed for the 10-4

CCDP bin. These trends indicate that the occurrence rate of higher risk precursors is

constant or decreasing. 

The occurrence rate of lower risk (i.e., 1×10-5 > CCDP > 1×10-6) precursors is increasing. 

The increasing trend is due to the grid-related LOOP events caused by the August 14, 2003

Northeast Blackout (3 precursors) and an increase in the scope of events analyzed due to

improvements in analysis methods and the SPAR models (20 precursors). Section 2.3 in

Attachment 2 discusses this in more detail.

The electrical grid-related LOOP events caused by the August 2003 Northeast Blackout

resulted in several agency actions prior to the summers of 2004 and 2005. These included

inspections of licensee conformance with applicable NRC regulations and the raising of

licensee awareness of the importance of grid reliability.

• The overall risk from ASP events is relatively constant for the period FY 1993 through

FY 2004. (See Attachment 2, Section 3.8.) 

UPCOMING ACTIVITIES:

The staff currently plans to engage in the following activities during the next 12 months:

• Identify and complete the preliminary analysis of significant precursors that occur through

June 30, 2006, to support the agency’s Strategic Plan goals for monitoring performance.

• Complete the final analysis of events for FY 2004, and continue the screening, review, and

analysis (preliminary and final) of events for FY 2005 and FY 2006.
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• Complete the preliminary assessment of all FY 2005 ASP events to support Agency Action

Review Meeting (AARM), by April 2006. In addition, preliminary assessments will also be

completed for events occurring during the first quarter of FY 2006 for those events where

the inspection reports are completed during that quarter.

• Issue the final results of the ASP trend study in FY 2006.

• Continue enhancing the Revision 3 SPAR models for internal events during power

operations.

• Continue developing SPAR models for internal events during LP/SD operations, LERF, and

external events in accordance with the approved SPAR Model Development Plan.

• Continue implementing RASP, including streamlining and coordinating ASP and SDP

analyses. In addition, the staff will continue to work with internal and external stakeholders

to eliminate reviews of ASP analyses for cases where these reviews are considered of

minimal value.

In a September 28, 2005 memorandum, the Office of General Counsel identified organizational

conflict of interest concerns with our contractor, Idaho National Laboratory, for several projects

including those for SPAR model development. The staff is currently considering potential

options for resolutions of these concerns. However, this issue may impact upcoming activities

and schedules related to the SPAR Model Development program and with programs that utilize

the SPAR models. 

In summary, the ASP Program continues to evaluate the safety significance of operating events

at nuclear power plants and to provide insights to NRC’s regulatory programs. The SPAR

Model Development Program is continuing to develop and improve independent risk analysis

tools and capabilities to support the use of PRA in the agency’s risk-informed regulatory

activities. SPAR models are used to support the Reactor Oversight Process, the ASP Program,

and the Generic Safety Issue resolution process. SPAR models are also used to perform

analyses in support of the staff’s risk-informed reviews of license amendments, as well as to

independently verify the Mitigating Systems Performance Index (MSPI).
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COORDINATION:

The Office of the General Counsel has reviewed this Commission paper and has no legal

objections to its content.

/RA Martin J. Virgilio Acting For/

Luis A. Reyes

Executive Director

 for Operations

Attachments: 1. Status of the Accident Sequence Precursor (ASP) Program and the

Standardized Plant Analysis Risk (SPAR) Model Development 

Program

2. Results, Trends, and Insights from the Accident Sequence Precursor (ASP)

Program

3. Accident Sequence Precursor (ASP) Program Description and Comparison

with Significance Determination Process (SDP) and Event Assessment

Processes
The Commissioners -8-

COORDINATION:

The Office of the General Counsel has reviewed this Commission paper and has no legal

objections to its content.

/RA Martin J. Virgilio Acting For/

Luis A. Reyes

Executive Director

 for Operations

Attachments: 1. Status of the Accident Sequence Precursor (ASP) Program and the

Standardized Plant Analysis Risk (SPAR) Model Development 

Program

2. Results, Trends, and Insights from the Accident Sequence Precursor (ASP)

Program

3. Accident Sequence Precursor (ASP) Program Description and Comparison

with Significance Determination Process (SDP) and Event Assessment

Processes

DISTRIBUTION: OERAB RF DRAA RF EDO WITS #199200101 *See previous concurrence

OAR in ADAMS? (Y or N) Y ADAMS ACCESSION NO.: ML052700542 TEMPLATE NO. SECY-012

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to receive a copy of this document, indicate in the box “C” copy w/o attach/encl “E” copy w/attach/encl “N” no copy “e” electronic copy

OFFICE *OERAB E *OERAB E *OERAB E *OERAB E *OERAB E *DRAA C

NAME EGoldfeiz DMarksberry CHunter MCheok NChokshi CAder

DATE 09/8/05 09/8/05 09/8/05 09/8/05 09/8/05 09/8/05

OFFICE OGC *NRR *Tech ED *RES DMDMRS EDO 

NAME KCyr JDyer PGarrity (by email) CPaperiello MVirgilo LReyes

DATE / /05 09/22/05 09/22/05 09/28/05 10/24/05 10/24/05
1 Attachment 1

Status of the Accident Sequence Precursor (ASP) Program

and the Standardized Plant Analysis Risk (SPAR)

Model Development Program

ASP Program Status

Analysis of ASP events. Table 1 of Attachment 2 to this paper provides the status of ongoing,

rejected, preliminary, and final ASP analyses. Attachment 2 also summarizes the preliminary

and final precursor analyses, and provides a list of events involving cracks in the control rod

drive mechanism (CRDM). All precursor analyses from Fiscal Years (FYs) 2001, 2002, and 2003

have been completed, with the exception of the ongoing analyses of the CRDM nozzles

at several plants. The analyses of FY 2004 events are also nearing completion, and analyses

of FY 2005 events have begun.

Davis-Besse. The condition discovered at the Davis-Besse Nuclear Power Station involved

degradation of the reactor vessel head and cracking of the CRDM housing. The related

precursor analysis also took into account the simultaneous existence of unqualified coatings

and other debris that could plug the containment sump, as well as a design deficiency

in the high-pressure injection pumps. The simultaneous occurrence of these conditions resulted

in the event being classified as a significant precursor. The final ASP analysis for this event

incorporating internal and external stakeholder comments was issued in March 2005.

CRDM cracking events. The staff is currently analyzing conditions involving primary water

stress corrosion cracking of CRDM housings. These events involve the discovery of such cracks

at 10 plants in FY 2001–2003. This ongoing analysis involves completing the probabilistic

analysis of the time-dependent failure frequencies of the CRDM housings. Sensitivity analyses

conducted to date show that these cracking events are most likely potential precursors, but not

significant precursors. Therefore, the staff has included these events in the total count

and trending of all precursors (i.e., CCDP or )CDP $1×10-6).

ASP Program status. The staff plans to complete its analysis of potential FY 2004 precursors

by November 2005, and preliminary assessments of all FY 2005 events by April 2006. In addition,

the ASP Program will give priority to analyses of potentially high-risk events when such events

are identified during NRC inspections or in LERs.

Investigation of trends and engineering insights. In SECY-04-012, the staff noted its intent

to perform a detailed evaluation of ASP data to investigate the nature of precursor trends

and identify insights that can be applied in the NRC’s regulatory programs. As part of that effort,

the staff has performed a trend analysis study to investigate the apparent decrease in all

precursors during FY 1997–1999 and the subsequent increase during FY 2000–2004. 

Section 2.3 of Attachment 2 to this paper summarizes the study results.

ASP expert elicitation process. In 2004, the staff initiated a project to develop a simplified,

limited expert elicitation methodology and guideline to meet the needs of the ASP Program. 

Since Phase 3 calculations of NRC’s Significance Determination Process (SDP) are similar to

those used in the ASP Program, the expert elicitation guideline is also applicable to the SDP. 

This procedure will formalize the process used to determine the probability of failure and

the operability of equipment for events or conditions that are rare or for which insufficient

operational data exist to make meaningful estimates. The new process will involve a formal

procedure for seeking expert opinion and judgment that follows the existing expert elicitation
2

methodology, but is simplified and streamlined as appropriate to the required degree of accuracy

and the schedule for completing the ASP analyses. This new expert elicitation guideline

is currently being field-tested.

Review of ASP analyses. In the past, the staff has issued ASP analyses for internal and

licensee review prior to issuing the final analysis. This peer review is typically a 3-month process. 

For better efficiency, the staff is currently working with internal and external stakeholders

on ways to reduce the number of analyses that would undergo peer review. For example,

we are looking into eliminating ASP reviews for non-controversial and low-risk events.

SPAR Model Development Status

The SPAR Model Development Program has played an integral role in the ASP analysis

of operating events and has evolved over three generations into detailed tools for the analysis

of internal events during full-power operations. New SPAR models are currently being developed in

response to staff needs for modeling internal initiating events during low-power/shutdown

(LP/SD) operations, external initiating events, and large early release frequency (LERF).

The Advisory Committee on Reactor Safeguards (ACRS) informed RES that it had selected

the SPAR Model Development Program as one of the three projects that will receive an ACRS

review during 2005 regarding “research quality.” The staff has engaged in several discussions

with ACRS about this matter, and more are anticipated before the review is completed.

The SPAR Model Users Group (SMUG) is composed of representatives from each organization

within the agency’s program and regional offices that use risk models in their regulatory activities. 

The SMUG meets regularly to provide technical guidance for the SPAR Model Development

Program, consistent with the approved Integrated SPAR Model Development Plan. 

In accordance with that plan, which conforms to the modeling needs that SMUG members

and their management identified for performing risk-informed regulatory activities, the staff

completed the following activities in model and method development since the previous report.

SPAR models for analysis of internal initiating events during full-power operation

• Developed enhanced Revision 3 SPAR models in response to an NRR user need. 

This effort involved (1) performing a cut set level review against the respective licensee’s

plant PRA to each of the Revision 3 SPAR models for the 61 plants that were not pilot plants

in the Mitigating Systems Performance Index (MSPI) Development Program,

and (2) incorporating into the Revision 3 SPAR models the resolution of the PRA modeling

issues that were identified (a) during the onsite quality assurance (QA) reviews of

the Revision 3 SPAR models, (b) during the MSPI pilot program reviews, and (c) based on

feedback from model users.

• Completed an improved, updated loss of offsite power/station blackout (LOOP/SBO)

module, which was then incorporated into each Revision 3 SPAR model.

• Developed an automated process that allows the incorporation of input data into all

72 Revision 3 SPAR models in a relatively short period of time compared to the previous

method employed. This new process was then used to update the basic event

(component unreliability and unavailability) and initiating event data used in the Revision 3

SPAR models with values that reflect current plant performance.
3

SPAR models for analysis of internal initiating events during low-power and shutdown

(LP/SD) operation

• Completed an interim LP/SD SPAR model for Davis-Besse and sent the model to the licensee

for review. The staff has now completed 11 LP/SD SPAR models.

• The staff is currently working to resolve a potential conflict of interest issue with our

contractor at Idaho National Laboratory (INL). Pending resolution of this issue, we plan to

complete additional LP/SD models and issue models to licensees in anticipation of onsite

QA review.

SPAR models for the calculation of large early release frequency (LERF)

• Completed the LERF SPAR model for Peach Bottom Atomic Power Station (the lead plant

in the second plant class), which is a boiling-water reactor (BWR) 3/4 with a Mark I

containment. The staff subsequently sent the model to the licensee in the course of

preparing for the onsite QA review of the model against the licensee’s Level 2/LERF model.

• Completed the LERF SPAR model for Sequoyah Atomic Power Station (the lead plant

in the third plant class), which is a pressurized-water reactor (PWR) with an ice-condenser

containment. The staff subsequently sent the model to the licensee in the course of

preparing for the onsite QA review of the model against the licensee’s Level 2/LERF model.

• The staff plans to issue models for the lead plant in the fifth plant class (BWRs with Mark II

containments) and the sixth plant class (PWRs with sub-atmospheric containments)

in FY 2006.

SPAR models for the analysis of external events

• This effort is part of the Risk Assessment Standardization Project (RASP) in support of

ASP and SDP Phase 3 analyses. Development is being performed in conjunction with

NRR’s SDP external events Phase 2 worksheet benchmarking program.

• Completed a feasibility study and issued a report on the feasibility of developing external

events models by expanding the existing Revision 3 models. Completed the Limerick

SPAR model with external events to demonstrate this feasibility.

• Completed external events SPAR models for the Salem, Callaway, Wolf Creek,

and Kewaunee plants.

• The staff is currently working to resolve a potential conflict of interest issue with our

contractor at INL. Pending resolution of this issue, we plan to complete additional external

events analysis models.

Risk Assessment Standardization Project (RASP)

The primary focus of RASP is to standardize risk analyses in SDP Phase 3, the ASP Program,

and the Incident Investigation Program under Management Directive (MD) 8.3. Under this

project, the NRC staff is working to complete the following activities:
4

• Provide on-call technical support to NRR and regional senior reactor analysts. This support 

will include developing analysis methods or refining existing methods, making analysisspecific enhancements to the SPAR models, and supporting SDP Phase 3 analyses on an

as-requested basis.

• Enhance SPAR models and the suite of codes used to manipulate those models (i.e., the

Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE)

PRA code and Graphical Evaluation Module (GEM) interface code).

• Document consistent methods and guidelines for SDP Phase 3, ASP, and MD 8.3 analyses

of internal events during power operations, internal fires and floods, external events (e.g.,

seismic events and tornadoes), internal events during Low Power/Shut Down (LP/SD)

operations, and LERF sequences.

During the past year, RES has provided increased support on several SDP analyses and risk

analyses associated with reactive inspections at the request of regional and NRR analysts. 

Likewise, regional and NRR analysts have provided valuable support to RES on ASP analysis. 

RASP support have been provided in the areas of SPAR model enhancements, modeling

methodology of unique conditions, development of key analysis assumptions, and calculation of

failure probabilities and initiating event frequencies for condition-specific analyses. These

information exchanges have reduced the time to complete SDP, MD 8.3, and ASP analyses. In

addition, interoffice support contributed to the significant reduction in the number of conflicting

results between ASP and SDP analyses.

RES made several enhancements to the Revision 3 SPAR models in accordance with the

RASP user need request from NRR. In addition, RES is resolving modeling issues identified

during comparisons with licensee PRA models. These activities have improved the fidelity of

SPAR models which has increased the use of SPAR models in SDP analyses. Agency-wide 

use of SPAR models in the analysis of operating events has reduced the time to review draft

results of SDP and MD 8.3 assessments, as well as contributed to the reduction of conflicts

between SDP and ASP analyses results.

Guidelines for internal events during power operations were completed in April 2005. The

deliverable was in the form of a practical, “how to” handbook of methods, best practices,

examples, tips, and precautions for applying SPAR models. This handbook was issued for trial

use by staff. The handbook has already proved useful to new analysts that recently joined the

ASP program. The time and resources needed to train future new analysts will be reduced. 

The staff began working on guidelines to address external events, LP/SD operations, and

LERF. A preliminary completion date for all guidelines is mid-2006.
1 Attachment 2

Results, Trends, and Insights from the

Accident Sequence Precursor (ASP) Program

This attachment discusses the results of accident

sequence precursor (ASP) analyses conducted by

the U.S. Nuclear Regulatory Commission (NRC),

as they relate to events that occurred during Fiscal

Year (FY) 2001–2005. Based on those results, this

document also discusses the NRC’s analysis of

historical ASP trends, and the evaluation of the

related insights. The 13 tables and 18 figures that

augment this discussion appear at the end of this

attachment.

1.0 ASP Event Analyses

Table 1 summarizes the status of the NRC’s ASP

analyses, as of September 30, 2005. Specifically,

the table identifies ASP analyses that the NRC staff

has completed for events that occurred during

FY 2001–2005. (Note that, as of September 30,

2005, the staff had not yet screened all of the

FY 2005 events.) The following subsections

summarize the results of these analyses, which are

further detailed in the associated Tables 2–10.

FY 2001 analyses. The ASP analyses for

FY 2001 identified 22 precursors. Of those

22 precursors, 17 were identified on the basis of

final analyses, and 5 are expected to be precursors

because they relate to events that involved

cracking of the control rod drive mechanism

(CRDM) housing.1

 All 22 of these precursors

occurred while these plants were at power.

Table 2 presents the results of the staff’s ASP

analyses for FY 2001 precursors that involved

initiating events, while Table 3 presents the

analysis results for precursors that involved

degraded conditions. In addition, Table 4 lists

the CRDM cracking events that occurred during

FY 2001–2003.

FY 2002 analyses. The ASP analyses for

FY 2002 identified 14 precursors. Of those

14 precursors, 10 were identified on the basis of

final analyses and 4 are potential precursors

(expected to be precursors) because they relate to

CRDM cracking events. All 14 of these precursors

occurred while these plants were at power.

The staff has completed the final analysis of the

multiple degraded conditions that occurred at the

Davis-Besse Nuclear Power Station coincident with

degradation of the reactor pressure vessel (RPV)

head. This event is a significant precursor.2

Table 5 shows that there were no FY 2002

precursors that involved initiating events, while

Table 6 presents the analysis results for precursors

that involved degraded conditions. In addition, as

previously noted, Table 4 includes CRDM cracking

events that occurred during FY 2002.

FY 2003 analyses. The ASP analyses for

FY 2003 identified 22 precursors. Of those

22 precursors, 21 were identified on the basis of

final analyses and 1 is a potential precursor

(expected to be a precursor) because it relates to

a CRDM cracking event. All but one of the

22 precursors occurred while these plants were

at power.

Table 7 presents the results of the staff’s ASP

analyses for FY 2003 precursors that involved

initiating events, while Table 8 presents the

analysis results for precursors that involved

degraded conditions.

FY 2004 analyses. In January 2005, the NRC

staff completed its screening and review of licensee

event reports (LERs) concerning events that occurred

during FY 2004. On the basis of that review,

the ASP analyses have identified 16 precursors,

including 6 based on final analyses and 10 based

on preliminary analyses. Of the 16 precursors,

14 occurred while these plants were at power.

Table 9 presents the results of the staff’s ASP

analyses for FY 2004 precursors that involved

initiating events, while Table 10 presents the

analysis results for precursors that involved

degraded conditions. The staff may identify

additional precursors after completing the ongoing

analyses of FY 2004 events in November of 2005.

1 As of September 30, 2005, the staff has not

completed its ASP analyses of CRDM cracking

events that occurred during FY 2001–2003. 

However, based on scoping analyses completed to

date, the staff anticipates that these events will yield

an increase in core damage probability ()CDP) that

is between 1×10-6 and 1×10-3.

2 A significant precursor has a conditional core

damage probability (CCDP) or increase in core

damage probability ()CDP) that is greater than or

equal to 1×10-3.
2

FY 2005 analyses. The staff has completed all

screening and reviews for potential significant

precursors through September 30, 2005. 

In particular, the staff reviewed a combination

of LERs and daily event notification reports

(as required by Title 10, Section 50.72, of the Code

of Federal Regulations, 10 CFR 50.72) to identify

potential significant precursors. The staff is still

screening and reviewing LERs concerning other

potential precursor events that occurred during

FY 2005.3

 Our goal is to complete preliminary

assessments of all FY 2005 events by April 2006.

2.0 Industry Trends

This section discusses the results of trending

analyses for all precursors and for precursors

grouped by the order of magnitude of their CCDPs

or )CDPs (called CCDP bins).

Statistically significant trend. The trending

method used in this analysis is consistent with

those methods used in the staff’s risk studies. 

(See Appendix E of Reference 1.) The trending

method uses the p-value approach for determining

the probability of observing a trend as a result of

chance alone. A trend is considered statistically

significant if the p-value is smaller than 0.05. 

The p-value is shown for each trend in the figures

provided at the end of this attachment.

Data coverage. Most of the data used in the

trending analyses span the period from FY 1993

through FY 2004. The trends include the results of

both final and preliminary analyses of potential

precursors. However, the following exceptions

apply to the data coverage of the trending

analyses:

• Significant precursors (10-3 bin). The trend of

significant precursors (i.e., CCDP or )CDP

>1×10-3) includes events that occurred during

FY 2005. The results for FY 2005 are based on

the staff’s screening and review of a

combination of LERs and daily event notification

reports (10 CFR 50.72).4

 The staff analyzes all

potential significant precursors immediately.

• CRDM cracking events. The staff is currently in

the process of conducting its preliminary

analyses of cracking that occurred in CRDM

housings during FY 2001–2003. Sensitivity

analyses conducted to date show that these

cracking events are most likely potential

precursors, but not significant precursors. 

Therefore, the staff has included these events

in the total count and trending of all precursors

(i.e., CCDP or )CDP >1×10-6). For the

purposes of CCDP bin trend analyses, these

events were placed in the 10-5 CCDP bin.

2.1 Occurrence Rate of All Precursors

The NRC’s Industry Trends Program (ITP)

provides the basis for addressing the agency’s

performance goal measure on the number of

“statistically significant adverse industry trends in

safety performance” (one measure associated with

the Safety Goal established in the NRC’s Strategic

Plan). Precursors identified by the ASP Program

are one indicator used by the ITP to assess

industry performance.

Results. No statistically significant trend is

detected in the occurrence rate for all precursors

that occurred during the period from 1993 through

2004. Figure 1 depicts the occurrence rate for all

precursors by fiscal year. Section 2.3 provides

a more detailed discussion of the relatively low

number of precursors between FY 1997 and

FY 1999 and the increasing number of potential

precursors from FY 2000 through FY 2004.

2.2 Occurrence Rate of Precursors by CCDP

Bin

In addition to the rate of occurrence of all

precursors, the staff analyzed the data to

determine whether trends exist in the rate of

occurrence of precursors with CCDPs of different

orders of magnitude. The method used in this

analysis is based on a staff technical paper

presented at the International Topical Meeting on

Probabilistic Safety Assessment. (See Reference 2.)

Figure 2a is a histogram displaying the number of

precursors per fiscal year for the CCDP $10-3 bin. 

(Note that Figure 2a shows the number of

precursors instead of the occurrence rate.) This

figure does not show a trend line because the staff

did not detect a statistically significant trend.

By contrast, Figures 2b–d are histograms of the

occurrence rate as a function of fiscal year for the

other three CCDP bins (10-4, 10-5, and 10-6). 

Because Figures 2b (10-4) and 2d (10-6) represent

statistically significant trends, each figure shows

3 Licensees have 60-day grace period after an event or

discovery of a degraded condition to submit an LER.

4 The staff has completed all screening and reviews

through September 30, 2005.
3

the trend line of the mean occurrence rate, with the

90-percent confidence band indicated by error bars. 

There is no trend represented in Figure 2c (10-5).

Results. The trending analysis of the four CCDP

bins (>10-3, 10-4, 10-5, and 10-6) yielded the following

results for the period from FY 1993 through

FY 2004:

CCDP Bin Trend

CCDP $10-3 No statistically significant

trend

10-3 > CCDP $ 10-4 Decreasing trend–

statistically significant

10-4 > CCDP $ 10-5 No statistically significant

trend

10-5 > CCDP $ 10-6 Increasing trend–

statistically significant

No trend is detected in the >10-3 CCDP bin and

a decreasing trend is observed for the 10-4 CCDP

bin. In addition, the trend for important precursors

is decreasing (Figure 3).5

 This decreasing trend

indicates that the occurrence rate of higher risk

precursors is decreasing. There is no statistically

significant trend detected in the 10-5 bin.

An increasing trend is detected in the 10-6 bin. The

increasing trend is due to the grid-related LOOP

events caused by the August 14, 2003 Northeast

Blackout (3 precursors) and an increase in the

number of identified events due to changes in ASP

screening criteria (20 precursors). A discussion

regarding the apparent increase in precursors

during the FY 1997–2004 period is presented in

Section 2.3.

2.3 Precursor Trend Evaluation

The objective of the precursor trends evaluation

is to investigate the apparent low number of

precursors during FYs 1997, 1998, and 1999 and

the subsequent increase during FY 2000–2004.

Factors that may contribute or influence the

increasing trend in the occurrence rate of all

precursors during FY 1997–2004 were investigated

in this evaluation. In addition, trending analysis

was performed on precursor data in

FY 2001–2004.

Results, insights, and conclusions from this

evaluation are summarized below.

Trending Analysis Results (FY 1997–2004). 

Statistical tests were performed on precursor data

to identify influences on trends from common

groups of precursors during the FY 1997–2004

period. To ensure consistency in the data during

the FY 1997–2004 period, the number of

precursors in later years were normalized (i.e.,

rebaselined) in the statistical tests to account for

the increase in scope of the ASP Program in

FY 2001.

Rebaselining. To ensure consistency in the data

during the 8-year period from FY 1997 through

FY 2004, data in later years were adjusted to

reflect the screening criteria that were used in the

ASP Program prior to FY 2001 to select potential

precursors for detailed analysis.

Analysis methods and Standardized Plant Analysis

Risk (SPAR) models used in the ASP Program

have evolved over time, resulting in increased

capabilities to analyze complex conditions that

were previously screened out during earlier years. 

Beginning around FY 2000 (at the end of calendar

year 1999), all degraded conditions are considered

for ASP analysis.

Examples of conditions that were screened out

during the early years included potential initiators

involving fire, external events (e.g., seismic and

tornado), high-energy line breaks, and internal

flooding.

In addition, current ASP Program screening criteria

include all greater than Green inspection findings

evaluated under the Significance Determination

Process (SDP). Only LERs were screened prior to

the full implementation of the Reactor Oversight

Process (ROP) in April 2000.

Rebaselining removed 23 precursors from the

data.

Precursor groups. The rebaselined precursor data

were then tested to identify significant influence on

trends caused by common groups of precursors,

such as precursors with similar cause, similar

initiator, or higher than average number of

precursor from the same plant or site. Potential

common groups of precursors that were identified

5 An important precursor has a conditional core

damage probability (CCDP) or increase in core

damage probability ()CDP) that is greater than or

equal to 1×10-4.
4

during FY 1997–2004 are —

• grid-related LOOP events caused by the August

14, 2003 Northeast Blackout (8 precursors),

• all LOOP events, including grid-related LOOPs

(22 precursors),

• CRDM housing cracking conditions

(10 precursors)6

, and

• precursors at Oconee and D.C. Cook

(22 precursors).

Results. A review of the trending results of the

rebaselined data reveal the following:

• Precursors $10-4. No statistically significant

trend is detected in the occurrence rate of the

higher risk precursors with a CCDP or )CDP

$1×10-4 during FY 1997–2004.

• Precursors $10-5. A statistically significant

increasing trend is detected in the occurrence

rate for precursors with CCDP or )CDP $1×10-5

during FY 1997–2004.

No trend is detected if any or all of the following

precursor groups are removed from the data:

Northeast Blackout LOOP events, all LOOP

events, or CRDM cracking conditions.

• Precursors $10-6. A statistically significant

increasing trend is detected in the occurrence

rate for precursors with CCDP or )CDP $1×10-6

during FY 1997–2004, as shown in Figure 4a.

No trend is detected if all LOOP events and

CRDM cracking conditions are removed from

the data, as shown in Figure 4b.7

A further analysis of all precursors reveal the

following:

S Degraded conditions, $10-6. A statistically

significant increasing trend is detected in the

occurrence rate of precursors involving

degraded conditions with a )CDP $1×10-6

during FY 1997–2004.

No trend is detected if the CRDM cracking

conditions are removed from the data.

S Initiating events, $10-6. A statistically

significant increasing trend is detected in the

occurrence rate of precursors involving

initiating events with a CCDP $1×10-6 during

FY 1997–2004.

No trend is detected if all LOOP events are

removed from the data.

S LOOP events had a greater influence on the

increasing nature of the overall trend than

CRDM cracking conditions.

• Other insights from the review of 1997–2004

data include the following:

S One-half (50 percent) of the precursors

involving degraded conditions had a

condition start date prior to FY 1997 and are

considered “legacy” conditions.

Forty-five percent of degraded conditions

that were discovered during FY 1997–2004

had a condition start date prior to FY 1993.

S Over one-half (56 percent) of all “legacy”

conditions that were discovered during

FY 1997–2004 were discovered at two sites:

Oconee (36 percent) and D.C. Cook

(21 percent). Four “legacy” conditions

involved all three units at Oconee and four

“legacy” conditions involved both units at

D.C. Cook.

S LOOP events account for 21 percent of all

precursors during FY 1997–2004, of which

36 percent were grid-related LOOP events

caused by the Northeast Blackout.

Trending Analysis Results (FY 2001–2004).

Trending analysis and statistical tests were

performed on data during FY 2001–2004. This

data set was not rebaselined for this evaluation.

The 2001–2004 period is of interest because

FY 2001 is the first full year of the implementations

of the Reactor Oversight Process (ROP) and the

expanded scope of the ASP Program. In addition,

the ASP Program started using Revision 3 of the

SPAR models in the analyses of FY 2001 events. 

Therefore, the 2001–2004 data are consistent for

trending purposes.

A review of the results reveals the following:

• Precursors $10-4. No statistically significant

trend is detected in the occurrence rate of the

6 The reviews and analyses for these events are

ongoing.

7 Figures 4c and 4d show the trends for all rebaselined

data excluding all LOOP events and CRDM housing

cracking conditions separately.
5

higher risk precursors with a CCDP or )CDP

$1×10-4 during FY 2001–2004. Four such

precursors were identified during this period.

• Precursors $10-5. No statistically significant

trend is detected in the occurrence rate of all

precursors with a CCDP or )CDP $1×10-5

during FY 2001–2004. Thirty-two precursors

were identified during this period.

S Precursors with a CCDP or )CDP $1×10-5

account for 43 percent of all precursors

during FY 2001–2004.

S A statistically significant increasing trend is

detected in the occurrence rate of precursors

involving only initiating events during

FY 2001–2004.

No trend is detected if either the Northeast

Blackout LOOP events or all LOOP events

are removed from the data.

S No statistically significant trend is detected in

the occurrence rate of precursors involving

only degraded conditions during

FY 2001–2004.

S The removal of any of the following precursor

groups does not have an effect on the trend

of the occurrence rate of precursors with a

CCDP or )CDP $1×10-5 during

FY 2001–2004: grid-related LOOPs, all

LOOP events, and CRDM cracking

conditions.

• Precursors $10-6. No statistically significant

trend is detected in the occurrence rate of all

precursors with a CCDP or )CDP $1×10-6

during FY 2001–2004, as shown in Figure 4e. 

Seventy-four precursors were identified during

this period.

S All precursors $10-6. Loss of offsite power

events account for 24 percent of all

precursors during FY 2001–2004.

When all LOOP events are excluded from

the data, a statistically significant decreasing

trend was detected.

S Degraded conditions $10-6. A statistically

significant decreasing trend is detected in the

occurrence rate of precursors involving

degraded conditions with a )CDP $1×10-6

during FY 2001–2004.

S Initiating events $10-6. A statistically

significant increasing trend is detected in the

occurrence rate of precursors involving

initiating events with a CCDP $1×10-6 during

FY 2001–2004.

Loss of offsite power events account for

18 of the 20 precursors involving initiating

events during FY 2001–2004.

Trending Evaluation Conclusions. The following

conclusions can be drawn from the evaluation of

precursors during FY 1997–2004:

• Important precursors. No statistically significant

trend is detected in the occurrence rate of riskimportant precursors (i.e., CCDP or )CDP

$1×10-4) for either the FY 1997–2004 or

FY 2001–2004 periods.

• FY 1997–2004 trend. A statistically significant

increasing trend is detected in the occurrence

rate of all precursors with CCDP or )CDP

$1×10-6 during FY 1997–2004.

No statistically significant trend is detected if

initiating events involving LOOP events and

degraded conditions involving cracking events

in CRDM housings are removed from the data. 

Both precursor groups have a pronounced

influence on the increasing trend. No underlying

trend was found when LOOP events and CRDM

cracking conditions are removed from the data

set. The NRC is currently addressing the

increasing number of LOOP events and the

CRDM cracking events (information notices,

Agency Action Plan, etc.).

• FY 2001–2004 trend. No statistically significant

trend was detected in the occurrence rate of all

precursors with a CCDP or )CDP $1×10-6

during FY 2001–2004.

The trend of all precursors has a step increase

from FY 1999 to FY 2000 and levels out after

FY 2001.

• An increase in scope of the ASP Program

resulted in the analysis and identification of 23

additional precursors that would not have been

analyzed in during the FY 1997–1999 period.

To ensure consistency between earlier and later

data populations in the trending analysis, data

should be rebaselined using consistent

screening criteria applied to each year during

the FY 1997–2004 period.
6

Data from FY 2001–2004 are consistent without

having to rebaseline the data for trending

purposes.

• Inconsistencies in data due to the increase in

program scope do not influence the trend of all

precursors during FY 1993–2004, as presented

in an earlier section of this attachment.

3.0 Insights and Other Trends

The discussion of significant precursors in

Section 3.1 covers the period from FY 1993

through FY 2005, although the FY 2005 results are

based on the staff’s screening and review of a

combination of LERs and daily event notification

reports (10 CFR 50.72).8

 The insights presented in

the remaining sections cover the period from

FY 1993 through FY 2004.

3.1 Significant Precursors

The ASP Program provides the basis for the

FY 2005 performance goal measure of “zero

events per year identified as a significant precursor

of a nuclear accident” (one measure associated

with the Safety Goal established in the NRC’s

Strategic Plan).9

 Specifically, the Strategic Plan

defines a significant precursor as an event that has

a probability of at least 1 in 1000 ($10-3) of leading

to a reactor accident (See Reference 3).

Table 11 summarizes all significant precursors that

occurred during the period from FY 1969 through

FY 2005.

Results. Figure 2a depicts the number of

significant precursors that occurred during

FY 1993–2005. A review of the data for that period

reveals the following insights:

• As of September 30, 2005, the performance

goal measure for significant precursors has

been met during the period from FY 1993

through FY 2005.

• The staff does not detect any statistically

significant trend in the occurrence of significant

precursors during FY 1993–2005.

• Significant precursors have occurred, on

average, about once every 3 to 4 years. The

events in this group involve differing failure

modes, causes, and systems.

• The multiple degraded conditions coincident

with degradation of the RPV head at

Davis-Besse were identified as a significant

precursor for FY 2002. The specific conditions

included cracking of CRDM nozzles,

degradation of the RPV head, potential clogging

of the emergency sump, and potential

degradation of the high-pressure injection (HPI)

pumps.

• Two additional precursors with a CCDP $1×10-3

have occurred during FY 1993–2005. 

Descriptions of these events are provided in

Table 11.

3.2 Important Precursors

Precursors with a CCDP or )CDP of at least 1 in

10,000 ($10-4) are considered important in the ASP

Program. An important precursor generally has a

CCDP higher than the core damage probability

(CDP) estimated by most plant-specific

probabilistic risk assessments (PRAs).

The staff identified four important precursors that

occurred during FY 2002 and FY 2003. There

were no important precursors identified in FY 2004. 

As of September 30, 2005, one potential important

precursor has been identified for FY 2005. This

event occurred at Kewaunee Nuclear Power Plant

and involved the potential loss of safety-related

equipment as a result of postulated flooding. 

The staff continues to work through ASP and SDP

processes to properly quantify the risk attributable

to this event and determine the proper regulatory

resolution.

The staff is continuing to analyze events that

occurred in FY 2005 to identify additional important

precursors. Table 12 summarizes the important

precursor analyses completed so far.

Results. A review of the data for FY 1993–2004

reveals the following insights:

• The mean occurrence rate of important

precursors exhibits a decreasing trend that is

statistically significant during the period from

FY 1993 through FY 2004, as shown in

Figure 3.

• Important precursors occur infrequently (about

8 The staff has completed all screening and reviews

through September 30, 2005.

9 Prior to FY 2005, the performance goal measure for

significant precursors was “no more than one event

per year identified as a significant precursor of a

nuclear accident.” 
7

two per year on average).

• Twenty-two important precursors occurred

during the period from FY 1993 through

FY 2004 period. Of these, 32 percent involved

a LOOP initiating event.

3.3 Initiating Events vs. Degraded Conditions

A precursor can be the result of either (1) an

operational event involving an initiating event such

as a LOOP, or (2) a degraded condition found

during a test, inspection, or engineering evaluation. 

A degraded condition involves a reduction in safety

system reliability or function for a specific duration

(although no reactor trip initiator actually occurred

during this time that challenged the degraded

condition).

Results. A review of the data for FY 1993–2004

reveals the following insights:

• Over the past 12 years, precursors involving

degraded conditions outnumbered initiating

events (68 percent compared to 32 percent,

respectively). This predominance was most

notable in FY 2001 and FY 2002, when

degraded conditions contributed to 91 percent

and 100 percent of the identified precursors,

respectively.

• The mean occurrence rate of precursors

involving initiating events does not exhibit a

trend that is statistically significant for the period

from FY 1993 through FY 2004, as shown in

Figure 5.

• The mean occurrence rate of precursors

involving degraded conditions exhibits an

increasing trend that is statistically significant for

the period from FY 1993 through FY 2004, as

shown in Figure 6. Specifically, the occurrence

rate of such precursors increased over this

period by a factor of two.

• Sixty-three percent of precursors involving

initiating events during FY 1993–2004 are

LOOP events. During the period from FY 2001

through 2004, 90 percent of all initiating event

precursors involved a LOOP.

3.4 Precursors Involving Loss of Offsite

Power Initiating Events

The loss of offsite power (LOOP) event at Quad

Cities Station Unit 2 (FY 2001), which was

attributable to a failure of the main power

transformer, was the only precursor due to a LOOP

that occurred in FY 2001–2002.

In FY 2003, the power blackout in the Northeast

United States in August 2003 caused nine plants to

lose offsite power, and the staff identified eight of

those events as precursors.10 Three additional

LOOP events occurred during FY 2003. These

events occurred at Palisades Nuclear Power Plant,

Unit 1 of the Grand Gulf Nuclear Station, and Unit 3

of the Peach Bottom Atomic Power Station.

Six LOOP events occurred during FY 2004. The

staff has completed its final analyses of the LOOP

events at Palo Verde Units 1, 2, and 3, but is still

conducting the remaining analyses of the events at

Units 1 and 2 of the St. Lucie Nuclear Plant and

Unit 3 of the Dresden Nuclear Power Station.

Results. A review of the data for FY 1993–2004

reveals the following insights:

• The mean occurrence rate of precursors

resulting from a LOOP exhibits an increasing

trend that is statistically significant for the period

from FY 1993 through FY 2004, as shown in

Figure 7. Specifically, the occurrence rate of

such precursors increased over this period by a

factor of three.

• Without the LOOP events that occurred as a

result of the electrical blackout in the Northeast

United States on August 14, 2003, the identified

precursors did not exhibit any statistically

significant trend (either increasing or

decreasing) for the period from FY 1993 through

FY 2004.

• Twenty-one percent of the LOOP precursor

events that occurred during FY 1993–2004 were

evaluated to be important precursors (CCDP

$1×10-4).

• A simultaneous unavailability of an emergency

power system train was involved in 5 of the 33

LOOP precursor events during FY 1993–2004. 

One of these precursors was a significant

precursor (Catawba Unit, 1996).

10 The ASP analysis of the LOOP event at Davis-Besse

on August 14, 2003, showed that this event did not

meet the threshold of a precursor in the ASP

Program. (The CCDP was less than 1×10-6.) The

plant had been shut down for more than two years

before this event occurred. 
8

3.5 Precursors at Boiling- vs. PressurizedWater Reactors

Since FY 2001, 22 precursors have occurred at

boiling-water reactors (BWRs) which is 11 more

than the total from the previous 8 years. The

precursor counts for pressurized-water reactors

(PWRs) include the ongoing analyses of events

involving cracking in CRDM housings.

A review of the data for FY 1993–2004 reveals the

following results for BWRs and PWRs:

BWRs

• The mean occurrence rate of precursors at

BWRs exhibits an increasing trend that is

statistically significant for the period from

FY 1993 through FY 2004, as shown in

Figure 8. Specifically, the occurrence rate of

precursors at BWRs have increased over this

period by a factor of four.

• Historically, an average of 3 precursors per year

occurred at BWRs during FY 1993–2004.

• Loss of offsite power events contribute to

69 percent of precursors involving initiating

events at BWRs.

• Only one precursor occurred at a BWR during

the 4-year period from FY 1997 through

FY 2000.

PWRs

• The mean occurrence rate of precursors at

PWRs does not exhibit a trend that is

statistically significant for the period from

FY 1993 through FY 2004, as shown in

Figure 9.

• Historically, an average of 11 precursors per

year occurred at PWRs during FY 1993–2004.

• Loss of offsite power events contribute to

61 percent of precursors involving initialing

events at PWRs.

3.6 Precursors Caused by Degraded

Conditions

Most precursors involving degraded conditions are

due to equipment unavailabilities. Such events

typically occur for extended periods without a

reactor trip, or in combination with a reactor trip in

which a risk-important component is unable to

perform its safety function as a result of a

degraded condition.

A review of the data for FY 1993–2004 reveals the

following insights concerning the unavailability of

safety-related equipment:11

Equipment unavailabilities at BWRs

• Of the 19 precursors involving the unavailability

of safety-related equipment that occurred at

BWRs during FY 1993–2004, most were

caused by failures in the emergency power

system (53 percent), residual heat removal

system (37 percent), or high pressure coolant

injection (26 percent).

Emergency core cooling systems

• An unavailability of safety-related high- and/or

low-pressure injection trains contributed to

55 percent of all identified precursors that

occurred at PWRs during FY 1993–2004. Most

of these unavailabilities were caused by failures

in either the emergency core cooling system

(ECCS) (26 percent) or emergency power

sources (26 percent), or resulted from

design-basis issues involving other structures or

systems that impact either the ECCS or one of

its support systems (31 percent).

• The 19 precursors that involved a failure in an

ECCS train yield the following insights:

S Eighteen precursors involved a conditional

unavailability that was identified during

testing, inspection, or engineering reviews.

S Fourteen precursors involved a condition that

affected sump recirculation during postulated

loss-of-coolant accidents of varying break

sizes.

11 The sum of percentages presented in this section

does not always equal 100-percent because some

precursors involve multiple equipment

unavailabilities.
9

Auxiliary/emergency feedwater systems

• The unavailability of one or more trains of the

auxiliary and emergency feedwater (AFW/EFW)

systems contributed to 42 percent of all

precursors that occurred at PWRs. Most of

these unavailabilities were caused by failures in

the AFW/EFW systems (22 percent) or

emergency power sources (45 percent), or

resulted from design-basis issues involving

other structures or systems that impact either

the AFW/EFW systems or one of their support

systems (33 percent).

• The 12 precursors that involved a failure in an

AFW/EFW train yield the following insights:

S Five of the train failures occurred following a

reactor trip.

S Ten of the precursors involved the

unavailability of the turbine-driven AFW/EFW

pump train.

Emergency power sources in PWRs

The unavailability of emergency power sources

such as emergency diesel generators (EDGs) and

hydroelectric generators (at Oconee), contributed

to 25 percent of all precursors that occurred at

PWRs.12 Most of these unavailabilities were

caused by random hardware failures in the

emergency power system (61 percent).

• The other unavailabilities were attributable to

design-basis issues (21 percent) and losses of

service water (21 percent).

• In all the analyzed LOOP events at PWRs, the

turbine-driven AFW/EFW pumps were operable.

Section 3.4 (above), discusses insights related to

precursors that involved a LOOP with a

simultaneous EDG unavailability.

3.7 Annual ASP Index

The staff derives the annual ASP index for

order-of-magnitude comparisons with

industry-average core damage frequency (CDF)

estimates derived from PRAs and individual plant

examinations (IPEs). The index for a given fiscal

year is the sum of the CCDPs and )CDPs divided

by the number of reactor-calendar years.

Results. Figure 10 depicts the annual ASP indices

for FY 1993–2004. A review of the ASP indices

reveals the following insights:

• Based on order of magnitude, the average ASP

index from FY 1993 through FY 2004 is

consistent with the CDF estimates from the

SPAR models and the staff’s observations of

the licensees’ PRAs, as estimated from data

gathered during SPAR benchmarking trips over

the past 4 years.

• The increase in the ASP index in FYs 1994,

1996, and 2002 are attributable to the significant

precursors that occurred in these years. 

Descriptions of these events are provided in

Table 11.

Limitations. Using CCDPs and )CDPs from ASP

results to estimate CDF is difficult because (1) the

mathematical relationship requires a significant

level of detail, (2) statistics for frequency of

occurrence of specific precursor events are sparse,

and (3) the assessment must also account for

events and conditions that did not meet the ASP

precursor criteria.

The ASP models and process do not explicitly

address all CDF scenarios, such as fires, flooding,

and external events. Thus, they are incomplete for

use in estimating total CDF. In addition, using

CCDPs and )CDPs can overestimate the CDF

because of double counting.

Because of these and other limitations, the staff

has primarily used the CCDPs and )CDPs as a

relative trending indication. Nonetheless, ASP

results can be linked to CDF by using an annual

ASP index. The IPEs also give incomplete

estimates of total CDF, although the IPEs are

reasonably similar in scope to the current ASP

Program.

3.8 Integrated ASP Index

The staff has modified the annual ASP index (as

discussed in Section 3.7) to provide a different

perspective on the contribution of precursors to the

average CDF from PRAs.

Specifically, the integrated ASP index, includes the

12 Not all EDG unavailabilities are precursors. An EDG

unavailability for a period of less than one

surveillance test cycle (1 month) is screened out in

the ASP Program (assuming no other complications). 

In addition, the risk contributions of EDG

unavailabilities vary plant-to-plant and may result in a

)CDP less than the threshold of a precursor (1×10-6).
10

risk contribution of a precursor for the entire

duration of the degraded condition (i.e., the risk

contribution is included in each fiscal year that the

condition existed).13 The risk contribution due to

precursors involving initiating events are included in

the fiscal year that the event occurred (i.e., same

as the original ASP index). Examples are provided

below.

Examples. A precursor involving a degraded

condition is identified in FY 2003 and has a )CDP

of 5×10-6. A review of the LER reveals that the

degraded condition existed since a design

modification performed in FY 2001. In the

integrated ASP index, the )CDP of 5×10-6 is

included in the FYs 2001, 2002, and 2003.

For an initiating event occurring in FY 2003, the

CCDP from this precursor is only included in

FY 2003.

The index or CDF from precursors for a given fiscal

year is the sum of CCDPs and )CDPs in the fiscal

year divided by the number of reactor-calendar

years in the fiscal year.

Results. Figure 11 depicts the integrated ASP

indices for FY 1993–2004. A review of the ASP

indices reveals the following insights:

• Based on order of magnitude, the average

integrated ASP index for the period from

FY 1993 through FY 2004 is consistent with the

CDF estimates from the SPAR models and the

licensee’s PRAs.

• Contributions to the average integrated CDF

from precursors over the 12-year period

(FY 1993–2004) are as follows:

S Four precursors contribute to nearly one-half

(47 percent) of the average integrated CDF

from precursors over the 12-year period. 

Specifically, long-term degraded conditions

at Point Beach Units 1 and 2 (discovered in

2001) involved potential common-mode

failure of all auxiliary feedwater pumps, while

long-term degraded conditions at D.C. Cook

Units 1 and 2 (discovered in 1999) involved a

number of locations in the plant where the

effects of postulated high-energy line break

events would damage safety-related

components. The associated )CDPs of the

degraded conditions at Point Beach and D.C.

Cook were high (7×10-4 and 4×10-4,

respectively) and the degraded conditions

existed since plant construction.

S Three significant precursors (i.e., CCDP or

)CDP > 1×10-3) contribute to 27 percent of

the average integrated CDF from precursors

over the 12-year period. Each significant

precursor existed for a one-year period.

Descriptions of these events are provided in

Table 11.

S The remaining 26 percent of the average

integrated CDF from precursors over the

12-year period was from contributions from

156 precursors.

Limitations. The integrated ASP index provides

the contribution of risk (per fiscal year) due to

precursors, and cannot be used for trending

purposes since the discovery of precursors

involving degraded conditions in future years may

change the previous year(s) cumulative risk.

3.9 Consistency with PRAs and IPEs

A secondary objective of the ASP Program is to

provide a partial validation of the dominant core

damage scenarios predicted by PRAs and IPEs. 

Most of the identified precursor events are

consistent with failure combinations identified in

PRAs and IPEs.

However, a review of the precursor events for

FY 1993–2004 reveals that approximately

26 percent of the identified precursors involved

event initiators or failure modes that were not

explicitly modeled in the PRA or IPE concerning the

specific plant at which the precursor event

occurred. Table 13 lists these precursors. The

occurrence of these precursors does not imply that

explicit modeling is needed; however, there could

be insights that could be fed-back to future

revisions of the PRA.

4.0 Summary

This section summarizes the ASP results, trends,

and insights.

• Significant precursors. The multiple degraded

conditions at Davis-Besse Nuclear Power

Station represent a significant precursor ()CDP

= 6×10-3) for FY 2002. No significant precursors

(i.e., CCDP or )CDP $1×10-3) were identified in

13 The original ASP index reported previously included

the risk contribution due to precursors only in the

fiscal year in which the precursors were identified.
11

FYs 2003, 2004, or 2005. The ASP Program

provides the basis for the FY 2005 performance

goal measure of “zero events per year identified as

a significant precursor of a nuclear accident.”

These results will be reported in the NRC’s

Performance and Accountability Report for

FY 2005 and the NRC Performance Budget

for FY 2007.

• Important precursors. Four degraded

conditions identified in FY 2002–2004 are

important precursors (i.e., CCDP or )CDP

$1×10-4). These events included the multiple

degraded conditions at Davis-Besse, the

potential common-mode failure of auxiliary

feedwater at Point Beach 1 & 2 (original design

deficiency), and another potential commonmode failure of auxiliary feedwater at Point

Beach 2 (potential clogging of recirculation

lines).

The NRC has already taken several actions

as the result of the multiple degraded conditions

at Davis-Besse. For example, the agency

issued an order requiring specific inspections

of the RPV head and associated penetration

nozzles at PWRs. The agency also issued

several bulletins, information notices, and

temporary instructions (i.e., inspection

procedures), as well as a regulatory issue

summary.

The degraded conditions at Point Beach

resulted in the issuance of two information

notices.

• Occurrence rate of important precursors.

No statistically significant trend was identified in

the occurrence rate of important precursors

during the period from FY 1997 through

FY 2004. A statistically significant decreasing

trend was identified in the occurrence rate of

important precursors for the longer period from

FY 1993 through FY 2004.

• Occurrence rate of all precursors

(FY 1993–2004). No statistically significant

trend was identified in the occurrence rate of all

precursors during the period from FY 1993

through FY 2004. The ITP uses this trend as

one of the agency’s monitored indicators.

This result will be reported in the NRC’s

Performance and Accountability Report

for FY 2005 and the NRC Performance Budget

for FY 2007.

• Occurrence rate of all precursors

(FY 1997–2004). A statistically significant

increasing trend was detected in the occurrence

rate of all precursors during the period from

FY 1997 through FY 2004. No statistically

significant trend is detected if LOOP events and

degraded conditions involving cracking events in

CRDM housings are removed from the data.

In FY 2001, the agency issued a bulletin and an

information notice associated with events

involving cracking in CRDM housings.

The electrical grid-related LOOP events caused

by the August 2003 Northeast Blackout resulted

in several agency actions prior to the summers

of 2004 and 2005. These included inspections

of licensee conformance with applicable NRC

regulations and the raising of licensee

awareness of the importance of grid reliability. 

References 4 and 5 provide additional insights

on the risk of LOOP and station blackout

events.

• Some observations.

S In the 12-year period from FY 1993 through

FY 2004, precursors involving degraded

conditions outnumbered initiating events

by approximately two to one. From FY 1997

through FY 2004, one-half of the precursors

involving degraded conditions had

a condition start date prior to FY 1997.

S Sixty-three percent of precursors involving

initiating events during FY 1993–2004 were

LOOP events. During the period from

FY 2001 through FY 2004, 90 percent of all

initiating event precursors involved a LOOP.

S The mean occurrence rate of precursors

at BWRs exhibits a statistically significant

increasing trend for FY 1993–2004. Since

FY 2001, 22 precursors have occurred at

BWRs, which is 11 more than the total from

the previous 8 years (9 of the 22 precursors

involved a LOOP). Of the precursors

involving the unavailability of safety-related

equipment, 53 percent were caused by

failures in the emergency power system,

37 percent were from failures in the residual

heat removal system, and 26 percent

resulted from failures in the high pressure

coolant injection system. (Note that

the percentages add up to more than

100 percent because e there are cases

in which simultaneous failures occurred.)
12

S The mean occurrence rate of precursors

at PWRs does not exhibit a statistically

significant trend for FY 1993–2004. Of the

precursors involving the unavailability of

safety-related equipment, 55 percent were

caused by an unavailability of high- and/or

low-pressure injection trains, 42 percent

were caused by the unavailability of one or

more trains of the auxiliary and emergency

feedwater, and 25 percent were the result of

the unavailability of emergency power

sources such as EDGs and hydroelectric

generators. (Note that the percentages add

up to more than 100 percent because there

are cases in which simultaneous failures

occurred.)

S The average integrated ASP index, which

sums the risk contribution of precursors on a

reactor-calendar year basis, is consistent

with the average core damage frequency

estimates from the SPAR models and the

licensees’ PRAs.

S A review of the precursor events for

FY 1993–2004 reveals that approximately

26 percent of the identified precursors

involved event initiators or failure modes that

were not explicitly modeled in the PRA or IPE

concerning the specific plant at which the

precursor event occurred. The occurrence of

these precursors does not imply that explicit

modeling is needed; however, there could be

insights that could be fed back to future

revisions of the PRA.

5.0 References

1. U.S. Nuclear Regulatory Commission.

NUREG/CR-5750, “Rates of Initiating Events at

U.S. Nuclear Power Plants: 1987–1995.” NRC:

Washington, DC. February 1999.

2. Rasmuson, D.M., and P.D. O’Reilly. “Analysis

of Annual Accident Sequence Precursor

Occurrence Rates for 1984–94,” in Proceeding

of the International Topical Meeting on

Probabilistic Safety Assessment. American

Nuclear Society (ANS), Park City, Utah. 29

September – 3 October, 1996. Vol. III, pp.

1645–1652. ANS: LaGrange Park, Illinois. 

1994.

3. U.S. Nuclear Regulatory Commission. NUREG1100, Vol. 21, “Performance Budget, Fiscal

Year 2006.” NRC: Washington, DC. February

2005.

4. U.S. Nuclear Regulatory Commission.

NUREG/CR-XXXX (INEEL/EXT-04-02525),

“Station Blackout Risk Evaluation for Nuclear

Power Plants (Draft)” NRC: Washington, DC. 

January 2005.

5. U.S. Nuclear Regulatory Commission.

NUREG/CR-XXXX (INEEL/EXT-04-02326),

“Evaluation of Loss of Offsite Power Events at

Nuclear Power Plants: 1986–2003 (Draft)” 

NRC: Washington, DC. October 2004.
13

Table 1. Status of ASP analyses (as of September 30, 2005).

Status FY 2001 FY 2002 FY 2003 FY 2004 FY 2005a

Analyzed events that were determined not to

be precursors 32 21 23 17 4

Preliminary precursor analyses underway 5b 4b 1b 1 7

Preliminary precursor analyses completed 0 0 1 9 3

Final precursor analyses completed 17 10 20 6 0

Total precursors identified 22 14 22 16c 10c

a. As of September 30, 2005, the staff has not yet screened all of the FY 2005 events and unavailabilities.

b. Events involving cracking of control rod drive mechanism housings. The analyses for these events have not been completed

and, therefore, the number of precursors attributable to cracking of CRDM housings may change.

c. All of the reviews and analyses for FY 2004 and FY 2005 events have not been completed, and therefore, the number of total

precursors for these years may change.

Table 2. FY 2001 precursors involving initiating events.

Event Date Plant Description CCDPa

8/2/01 Quad Cities 2 Plant-centered LOOP due to a transformer failure.

Licensee Event Report (LER) 265/01-001 5×10-6

9/3/01 LaSalle 2

Reactor scram, loss of offsite power to vital bus (blown fuses), and

subsequent unavailabilities: core spray pump, residual heat removal

pump, and control rod drive pump. LER 374/01-003

1×10-5

a. Conditional core damage probability.
14

Table 3. FY 2001 precursors involving degraded conditions.

Event

Datea

Condition

Durationb Plant Description )CDPc

11/1/00 > 11 years Prairie Island 1

Potential unavailability of service water (SW) pumps

due to improper design modification of backflush

system and failure of vacuum valves. 

LER 282/00-004, LER 282/00-003

1×10-6

11/1/00 > 11 years Prairie Island 2

Potential unavailability of SW pumps due to improper

design modification of backflush system and failure of

vacuum valves. LER 282/00-004, LER 282/00-003

1×10-6

2/23/01 1944 hours Limerick 2 Inadvertent opening/stuck open main steam relief valve

(MSRV). LER 353/01-001 3×10-6

3/28/01 6185 hours Fermi 2 EDG “14” unavailable due to degraded bearing.

LER 341/01-001 3×10-6

4/23/01 201 days Surry 1 EDG “3” unavailable due to abnormal wear of piston

rings. LER 280/01-001 3×10-6

4/23/01 201 days Surry 2 EDG “3” unavailable due to abnormal wear of piston

rings. LER 280/01-001 6×10-6

4/30/01 > 28 years Oconee 1

Potential unavailability of high pressure injection (HPI)

and component cooling water (CCW) pumps due to

flooding caused by a postulated break on nonseismically qualified piping.

Inspection Report (IR) 269/00-008

4×10-6

4/30/01 > 28 years Oconee 2

Potential unavailability of HPI and CCW pumps due to

flooding caused by a postulated break on nonseismically qualified piping. IR 270/00-008

1×10-6

4/30/01 > 28 years Oconee 3

Potential unavailability of HPI and CCW pumps due to

flooding caused by a postulated break on nonseismically qualified piping. IR 287/00-008

1×10-6

5/16/01 > 1 year Calvert Cliffs 1 TDAFW pump inoperable due to sealant intrusion.

LER 317/01-001 1×10-5

7/5/01 2088 hours Dresden 3 HPCI inoperable due to water hammer event.

LER 249/02-005 3×10-6

8/9/01 > 12 years D.C. Cook 2

Concurrent unavailabilities– EDGs potentially

unavailable due to lack of essential service water

(ESW) flow caused by a deformed SW strainer and

TDAFW pump inoperable due to failed latching

mechanism. LER 316/01-003

7×10-6

8/20/01 > 25 years ANO 1

Potential unavailability of safety-related equipment

during a postulated fire due to improper fire protection

and procedures. LER 313/01-006

4×10-6

8/29/01 > 12 years D.C. Cook 1

Concurrent unavailabilities– EDGs potentially

unavailable due to lack of ESW flow caused by a

deformed SW strainer and TDAFW pump inoperable

due to failed latching mechanism. LER 316/01-003

1×10-5
Event

Datea

Condition

Durationb Plant Description )CDPc

15

9/11/01 > 29 years Palisades

Potential unavailability of safety-related equipment

during a postulated fire due to improper installation of

smoke detectors. IR 255/01-008

1×10-6

a. Condition duration is the time period when the degraded condition existed. The ASP Program limits the analysis exposure time

of degraded condition to 1 year.

b. ASP event date is the discovery date for a precursor involving a degraded condition.

c. Increase in core damage probability (i.e., conditional core damage probability - core damage probability).

Table 4. FY 2001–2005 CRDM cracking events.a, b

Event Date Plant Description

12/4/00 Oconee 1

Reactor pressure vessel (RPV) head leakage due to primary water stress

corrosion cracking (PWSCC) of five thermocouple nozzles and one CRDM

nozzle. LER 269/00-006, LER 269/02-003, LER 269/03-002

2/18/01 Oconee 3 RPV head leakage due to PWSCC of nine CRDM nozzles.

LER 287/01-001, LER 287/00-003, LER 287/03-001

3/24/01 ANO 1 RPV head leakage due to PWSCC of one CRDM nozzle.

LER 313/01-002, LER 313/02-003

4/28/01 Oconee 2 RPV head leakage due to PWSCC of four CRDM nozzles.

LER 270/01-002, LER 270/02-002

6/21/01 Palisades RPV head leakage due to PWSCC of one CRDM nozzle.

LER 255/01-002, LER 255/01-004

10/1/01 Crystal River 3 RPV head leakage due to PWSCC of one CRDM nozzle. LER 302/01-004

10/12/01 TMI 1 RPV head leakage due to PWSCC of eight thermocouple nozzles and five

CRDM nozzles. LER 289/01-002

10/28/01 Surry 1 RPV head leakage due to PWSCC of two CRDM nozzles. LER 280/01-003

11/13/01 North Anna 2 RPV head leakage due to PWSCC of one CRDM nozzle.

LER 339/01-003, LER339/02-001

4/30/03 St. Lucie 2 RPV head leakage due to PWSCC of two CRDM nozzles. LER 389/03-002

a. The analyses of cracking events are ongoing. The risk associated with multiple cracks at a given plant will be considered collectively

in one analysis for each plant (i.e., only one precursor for each plant).

b. The reviews and analyses for these events have not been completed and, therefore, the number of precursors due to cracking

of CRDM housings may change.
16

Table 5. FY 2002 precursors involving initiating events.

Event Date Plant Description CCDP

None

Table 6. FY 2002 precursors involving degraded conditions.

Event

Datea

Condition

Durationb Plant Description )CDP

10/8/01 > 2 years Shearon Harris 1

RHR Train “A” unavailable for sump recirculation due

to debris entrapment and RHR Train “B” potentially

unavailable due to an inoperable isolation valve.

LER 400/01-003

6×10-6

11/29/01 > 30 years Point Beach 1

Concurrent unavailabilities– potential common-cause

failure of all EFW due to design deficiency of minimum

flow recirculation valves and potential loss of feed-andbleed capability during postulated loss of instrument air

(LOIA). LER 266/01-005

6×10-4

11/29/01 > 29 years Point Beach 2

Concurrent unavailabilities– potential common-cause

failure of all EFW due to design deficiency of minimum

flow recirculation valves and potential loss of feed-andbleed capability during postulated LOIA.

LER 266/01-005

7×10-4

12/3/01 > 1 year Callaway

Concurrent unavailabilities– potential unavailability of

ESW Pump “B” and MDAFW Pump “B” due to foreign

material and CCW Pump “B” out for test and

maintenance. LER 483/01-002

1×10-5

12/18/01 > 13 years Shearon Harris 1

Degraded fire barrier and lack of fire brigade training

could cause unavailability of Train “B” safety

equipment and TDAFW pump flow control.

IR 400/00-009

6×10-6

2/14/02 5216 hours Columbia Potential unavailability of four safety-related breakers

due to degraded MOC switches. LER 397/02-001 6×10-6

2/27/02 > 1 year Davis-Besse

RPV head leakage due to PWSCC of CRDM nozzles,

potential unavailability of sump recirculation due to

screen plugging, and potential unavailability of boron

precipitation control. LER 346/02-002

6×10-3

4/16/02 > 2 years Braidwood 1 Inoperable power operated relief valve (PORV) bleed

path due to leaking air accumulators. LER 456/02-002 4×10-6

5/30/02 > 1 year Oconee 3

Potential unavailability of a HPI pump due to

improperly installed wire connectors during a

postulated severe LOOP or high energy line break

(HELB). IR 270/02-015

3×10-6

7/19/02 > 23 years Indian Point 2 Degraded control room fire barrier. IR 247/02-010 7×10-6

a. Condition duration is the time period when the degraded condition existed. The ASP Program limits the analysis exposure time of

degraded condition to one year.

b. ASP event date is the discovery date for a precursor involving a degraded condition.
17

Table 7. FY 2003 precursors involving initiating events.

Event Date Plant Description CCDP

3/25/03 Palisades Plant-centered LOOP (Mode 6) and temporary loss of shutdown

cooling. LER 255/03-003 3×10-6

4/24/03 Grand Gulf 1 Plant-centered LOOP and subsequent loss of the instrument air

system. LER 416/03-002 1×10-6

8/14/03 Indian Point 2 Grid-related LOOP due to August 14, 2003 Northeast Blackout. 

LER 247/03-005 6×10-6

8/14/03 Indian Point 3 Grid-related LOOP due to August 14, 2003 Northeast Blackout. 

LER 247/03-005 7×10-6

8/14/03 Nine Mile Point 1 Grid-related LOOP due to August 14, 2003 Northeast Blackout. 

LER 220/03-002 2×10-5

8/14/03 Nine Mile Point 2 Grid-related LOOP due to August 14, 2003 Northeast Blackout. 

LER 410/03-002 2×10-5

8/14/03 Fitzpatrick Grid-related LOOP due to August 14, 2003 Northeast Blackout. 

LER 333/03-001 4×10-6

8/14/03 Ginna Grid-related LOOP due to August 14, 2003 Northeast Blackout. 

LER 244/03-002 3×10-5

8/14/03 Perry 1 Grid-related LOOP due to August 14, 2003 Northeast Blackout. 

LER 440/03-002 3×10-5

8/14/03 Fermi 2 Grid-related LOOP due to August 14, 2003 Northeast Blackout. 

LER 341/03-002 2×10-5

9/15/03 Peach Bottom 3 Plant-centered LOOP, an emergency diesel generator unavailable,

and stuck open safety relief valve. LER 227/03-004 3×10-6
18

Table 8. FY 2003 precursors involving degraded conditions.

Event

Datea

Condition

Durationb Plant Description )CDP

10/29/02 > 1 year Point Beach 1

Potential common-mode failure of all EFW pumps due

to clogging of recirculation lines during switchover to

service water. LER 266/02-003

6×10-5

10/29/02 > 1 year Point Beach 2

Potential common-mode failure of all EFW pumps due

to clogging of recirculation lines during switchover to

service water. LER 266/02-003

4×10-4

10/30/02 > 29 years Kewaunee

Potentially unavailable safety-related equipment due to

lack of fixed fire suppression system.

IR 305/02-006

1×10-5

12/20/02 > 1 year Shearon Harris 1

Postulated fire could cause the actuation of certain

valves that could result in a loss of the charging pump,

RCP seal cooling, loss of RCS inventory, and other

conditions. LER 400/02-004

9×10-6

2/26/03 28 hours Kewaunee

Concurrent unavailabilities– EDG “B” inoperable due to

faulty relay and EDG “A” out for test and maintenance.

LER 305/03-002

4×10-6

3/7/03 > 1 year Nine Mile Point 1

Potential unavailability of reactor building closed loop

cooling system due to degraded piping.

IR 220/03-03

4×10-6

5/20/03 164 hours Oyster Creek

Loss of 4.16kV Emergency Bus “1C” due to ground

fault in normally energized underground cable.

LER 219/03-002

1×10-6

7/1/03 504 hours Hope Creek 1 

Station service water Train “A” traveling screen failed

due to inadequate maintenance instructions.

IR 354/03-006

3×10-6

9/1/03 550 hours Perry 1

ESW pump “A” failure to run due to shaft failure and

inadequate repairs led to a second failure.

LER 440/03-004

1×10-6

9/29/03 4 months Waterford 3 Degraded EDG due to failed fuel line. LER 382/03-002 2×10-6

a. Condition duration is the time period when the degraded condition existed. The ASP Program limits the analysis exposure time of

degraded condition to one year.

b. ASP event date is the discovery date for a precursor involving a degraded condition.
19

Table 9. FY 2004 precursors involving initiating events (as of September 30, 2005).

Event Date Plant Description CCDP

1/4/04 Calvert Cliffs 2a Reactor trip caused by loss of main feedwater and complicated by a

failed relay causing overcooling. LER 318/04-001 2×10-5

5/5/04 Dresden 3a Plant-centered LOOP due to breaker malfunction. LER 249/04-003 3×10-6

6/14/04 Palo Verde 1 Grid-related LOOP with offsite power recovery complications due to

breaker failure. LER 528/04-006 9×10-6

6/14/04 Palo Verde 2 Grid-related LOOP with an emergency diesel generator unavailable.

LER 528/04-006 4×10-5

6/14/04 Palo Verde 3 Grid-related LOOP with offsite power recovery complications due to

breaker failure. LER 528/04-006 9×10-6

9/25/04 St. Lucie 1a Severe weather LOOP caused by Hurricane Jeanne while the plant

was shut down. LER 335/04-004 1×10-5

9/25/04 St. Lucie 2a Severe weather LOOP caused by Hurricane Jeanne while the plant

was shut down. LER 335/04-004 1×10-5

a. Preliminary analysis results may change pending comments from peer review.

Table 10. FY 2004 precursors involving degraded conditions (as of September 30, 2005).

Event

Datea

Condition

Durationb Plant Description )CDP

11/3/03 > 30 years Surry 1

Potential loss of reactor coolant pump (RCP) seal

cooling due to postulated fire damage to emergency

switchgear. LER 280/03-005

1×10-6

11/3/03 > 30 years Surry 2

Potential loss of RCP seal cooling due to postulated

fire damage to emergency switchgear.

LER 280/03-005

1×10-6

1/4/04 720 hours Brunswick 2 EDG “3” unavailable due to jacket water leak.

LER 325/04-001 2×10-6

1/30/04 > 2 years Dresden 2c

HPCI potentially unavailable due to water carryover into

steam line caused by feedwater level control failure. 

LER 249/04-002

3×10-6

1/30/04 > 2 years Dresden 3c

HPCI potentially unavailable due to water carryover into

steam line caused by feedwater level control failure. 

LER 249/04-002

3×10-6

3/17/04 1117 hours Peach Bottom 3c HPCI unavailable due to failed flow controller.

LER 278/04-001 2×10-6

7/31/04 > 11 years Palo Verde 1c Containment sump recirculation potentially inoperable

due to pipe voids. LER 528/04-009 4×10-5

7/31/04 > 11 years Palo Verde 2c Containment sump recirculation potentially inoperable

due to pipe voids. LER 528/04-009 4×10-5

7/31/04 > 11 years Palo Verde 3c Containment sump recirculation potentially inoperable

due to pipe voids. LER 528/04-009 4×10-5

a. Condition duration is the time period when the degraded condition existed. The ASP Program limits the analysis exposure time of

degraded condition to one year.

b. ASP event date is the discovery date for a precursor involving a degraded condition.

c. Preliminary analysis results may change pending comments from peer review.
20

Table 11. Significant (CCDP or )CDP $1×10-3) accident sequence precursors during the 1969–2005

period—ordered by event date. (See notes)

Plant

)CDP

or

CCDP

Date Description

Davis-Besse 6×10-3 2/27/02

Multiple conditions coincident with reactor pressure vessel (RPV) head

degradation

The analysis included multiple degraded conditions discovered on various

dates. These conditions included cracking of control rod drive mechanism

(CRDM) nozzles and reactor pressure vessel (RPV) head degradation;

potential clogging of the emergency sump; and potential degradation of the

high-pressure injection (HPI) pumps during recirculation. LER 346/02-002

Catawba 2 2×10-3 2/6/96

Loss of offsite power (LOOP) with an emergency diesel generator (EDG)

unavailable

When the reactor was at hot shutdown, a transformer in the switchyard

shorted out during a storm, causing breakers to open and resulting in a

LOOP event. Although both EDGs started, the output breaker of EDG “1B” to

essential bus “1B” failed to close on demand, leaving bus “1B” without AC

power. After 2 hours and 25 minutes, operators successfully closed the EDG

“1B” output breaker. LER 414/96-001 

Wolf Creek 1 3×10-3 9/17/94

Reactor coolant system (RCS) blowdown to refueling water storage tank

(RWST)

When the plant was in cold shutdown, operators implemented two

unpermitted simultaneous evolutions, which resulted in the transfer of 9,200

gallons (34,825 liters) of RCS inventory to the RWST. Operators immediately

diagnosed the problem and terminated the event by closing the residual heat

removal (RHR) cross-connect motor-operated valve (MOV). The temperature

of the RCS increased by 7 °F (4 °C) as a result of this event.

LER 482/94-013

Harris 1 6×10-3 4/3/91

HPI unavailability for one refueling cycle

A degraded condition resulted from relief valve and drain line failures in the

alternative minimum flow systems for the charging/safety injection pumps,

which would have diverted a significant amount of safety injection flow away

from the reactor coolant system. The root cause of the degradation is

believed to have been water hammer, as a result in air left in the alternative

minimum flow system following system maintenance and test activities.

LER 400/91-008

Turkey Point 3 1×10-3 12/27/86

Turbine load loss with trip; control rod drive (CRD) auto insert fails;

manual reactor trip; power operated relief valve (PORV) sticks open

The reactor was tripped manually following a loss of turbine governor oil

system pressure and the subsequent rapid electrical load decrease. Control

rods failed to insert automatically because of two cold solder joints in the

power mismatch circuit. During the transient, a PORV opened but failed to

close (the block valve had to be closed). The loss of governor oil pressure

was due to a cleared orifice blockage and the auxiliary governor dumping

control oil. LER 250/86-039
Plant

)CDP

or

CCDP

Date Description

21

Catawba 1 3×10-3 6/13/86

Chemical and volume control system (CVCS) leak (130 g.p.m.) from the

component cooling water (CCW)/CVCS heat exchanger joint (i.e., smallbreak loss-of-coolant accident (LOCA))

A weld break on the letdown piping, near the CCW/CVCS heat exchanger

caused excessive RCS leakage. A loss of motor control center (MCC) power

caused the variable letdown orifice to fail open. The weld on the 1-inch

(2.54-cm) outlet flange on the variable letdown orifice failed as a result of

excessive cavitation-induced vibration. This event was a small-break LOCA. 

LER 413/86-031

Davis-Besse 1×10-2 6/9/85

Loss of feedwater; scram; operator error fails auxiliary feedwater (EFW);

PORV fails open

While at 90-percent power, the reactor tripped with main feedwater (MFW)

pump “1” tripped and MFW pump “2” unavailable. Operators made an error

in initiating the steam and feedwater rupture control system and isolated EFW

to both steam generators (SGs). The PORV actuated three times and did not

reseat at the proper RCS pressure. Operators closed the PORV block

valves, recovered EFW locally, and used HPI pump “1” to reduce RCS

pressure. LER 346/85-013

Hatch 1 2×10-3 5/15/85

Heating, ventilation, and air conditioning (HVAC) water shorts panel;

safety relief valve (SRV) fails open; high-pressure coolant injection

(HPCI) fails; reactor core isolation cooling (RCIC) unavailable

Water from an HVAC vent fell onto an analog transmitter trip system panel in

the control room (the water was from the control room HVAC filter deluge

system which had been inadvertently activated as a result of unrelated

maintenance activities). This resulted in the lifting of the SRV four times. The

SRV stuck open on the fourth cycle initiating a transient. Moisture also

energized the HPCI trip solenoid making HPCI inoperable. RCIC was

unavailable due to maintenance. LER 321/85-018

Lasalle 1 2×10-3 9/21/84

Operator error causes scram; RCIC unavailable; RHR unavailable

While at 23-percent power, an operator error caused a reactor scram and

MSIV closure. RCIC was found to be unavailable during testing (one RCIC

pump was isolated and the other pump tripped during the test). RHR was

found to be unavailable during testing due to an inboard suction isolation

valve failing to open on demand. Both RHR and RCIC may have been

unavailable after the reactor scram. LER 373/84-054

Salem 1 5×10-3 2/25/83

Trip with automatic reactor trip capability failed

When the reactor was at 25-percent power, both reactor trip breakers failed

to open on demand of a low-low SG level trip signal. A manual trip was

initiated approximately 3 seconds after the automatic trip breaker failed to

open, and was successful. The same event occurred 3 days later, at

12-percent power. Mechanical binding of the latch mechanism in the breaker

under-voltage trip attachment failed both breakers in both events.

LER 272/83-011
Plant

)CDP

or

CCDP

Date Description

22

Davis-Besse 2×10-3 6/24/81

Loss of vital bus; failure of an EFW pump; main steam safety valve lifted

and failed to reseat

With the plant at 74-percent power, the loss of bus “E2” occurred due to a

maintenance error during CRDM breaker logic testing. A reactor trip

occurred, due to loss of CRDM power (bus “E2”), and instrumentation power

was also lost (bus “E2” and a defective logic card on the alternate source). 

During the recovery, EFW pump “2” failed to start due to a maladjusted

governor slip clutch and bent low speed stop pin. A main steam safety valve

lifted, and failed to reseat (valve was then gagged). LER 346/81-037 

Brunswick 1 7×10-3 4/19/81

RHR heat exchanger damaged

While the reactor was in cold shutdown during a maintenance outage, the

normal decay heat removal system was lost because of a failure of the single

RHR heat exchanger that was currently in service. The failure occurred when

the starting of a second RHR service water pump caused the failure of a

baffle in the waterbox of the RHR heat exchanger, thereby allowing cooling

water to bypass the tube bundle. The redundant heat exchanger was

inoperable because maintenance was in progress. LER 325/81-032 

Millstone 2 5×10-3 1/2/81

Loss of DC power and one EDG as a result of operator error; partial

LOOP

When the reactor was at full power, the 125v DC emergency bus was lost as

a result of operator error. The loss of the bus caused the reactor to trip, but

the turbine failed to trip because of the unavailability of DC bus “A.” Loads

were not switched to the reserve transformer (following the manual turbine

trip) because of the loss of DC bus “A.” Two breakers (on the “B” 6.9kV and

4.16kV buses) remained open, thereby causing a LOOP. EDG “B” tripped as

a result of leakage of the service water (SW) flange, which also caused the

“B” 4.16 kV bus to be de-energized. An operator recognition error caused the

PORV to be opened at 2380 psia. LER 336/81-005

St. Lucie 1 1×10-3 6/11/80

Reactor coolant pump seal LOCA due to loss of component cooling

water (CCW); top vessel head bubble

At 100-percent power, a moisture-induced short circuit in a solenoid valve

caused a CCW containment isolation valve to shut causing loss of CCW to all

reactor coolant pumps (RCPs). While reducing pressure to initiate the

shutdown cooling system (SCS), the top head water flashed to steam, thus

forming a bubble (initially undetected by the operators). During the cooldown,

the SCS relief valves lifted and low-pressure safety injection (LPSI) initiated

(i.e., the other LPSI pump started charging, while the other was used for

cooldown). LER 335/80-029

Davis-Besse 1×10-3 4/19/80

Loss of two essential busses

When the reactor was in cold shutdown, two essential busses were lost due

to breaker ground fault relay actuation during an electrical lineup. Decay heat

drop line valve was shut, and air was drawn into the suction of the decay heat

removal pumps, resulting in loss of a decay heat removal path.

LER 346/80-029
Plant

)CDP

or

CCDP

Date Description

23

Crystal River 3 5×10-3 2/26/80

Loss of 24-volt DC power to non-nuclear instrumentation (NNI)

The 24-volt power supply to the NNI was lost as a result of a short to ground. 

This initiated a sequence of events in which the PORV opened (and stayed

open) as a direct result of the loss of the NNI power supply. HPI initiated as a

result of depressurization through the open PORV, and with approximately

70 percent of NNI inoperable or inaccurate, the operator correctly decided

that there was insufficient information available to justify terminating HPI. 

Therefore, the pressurizer was pumped solid, one safety valve lifted, and flow

through the safety valve was sufficient to rupture the reactor coolant drain

tank rupture disk, thereby spilling approximately 43,000 gallons (162,800

liters) of primary water into the containment. LER 302/80-010 

Hatch 2 1×10-3 6/3/79

Loss of feedwater; HPCI fails to start; RCIC is unavailable

During a power increase, the reactor tripped due to a condensate system trip. 

HPCI failed to initiate on low-low level due to a failed turbine stop valve. In

addition, water from leaking mechanical seal lines and an unknown valve

caused water to back up and contaminate the pump oil. RCIC was out of

service for unspecified reasons. LER 366/79-045

Oyster Creek 2×10-3 5/2/79

Loss of feedwater flow

While testing the isolation condenser, a reactor scram occurred. The

feedwater pump tripped and failed to restart. The recirculation pump inlet

valves were closed. The isolation condenser was used during cooldown.

LER 219/79-014

Three Mile Island 2 1 3/28/79

Loss of feedwater; PORV failed open; operator errors led to core

damage

Operators misinterpreted plant conditions, including the RCS inventory,

during a transient that was triggered by a loss of feedwater and a stuck-open

PORV. As a result, the operators prematurely shut off the high-pressure

safety injection system, turned off the reactor coolant pumps, and failed to

diagnose and isolate a stuck-open pressurizer relief valve. With the no RCS

inventory makeup, the core became uncovered and fuel damage occurred. In

addition, contaminated water was spilled into the containment and auxiliary

buildings. LER 320/79-012

Salem 1 1×10-2 11/27/78

Loss of vital bus and scram; multiple components lost

While the reactor was at 100-percent power, vital instrument bus “1B” was

lost as a result of the failure of an output transformer and two regulating

resistors. Loss of the vital bus caused a false low RCS loop flow signal,

thereby causing a reactor trip. Two EFW pumps failed to start (one because

of the loss of vital bus “1B”, and the other because of a maladjustment of the

over-speed trip mechanism). Inadvertent safety injection occurred as a result

of decreasing average coolant temperature and safety injection signals.

LER 272/78-073

Calvert Cliffs 1 3×10-3 4/13/78

LOOP; one EDG failed to start

With the plant shut down, a protective relay automatically opened the

switchyard breakers, resulting in a LOOP. EDG “11” failed to start. EDG “22”

started and supplied the safety busses. LER 317/78-020
Plant

)CDP

or

CCDP

Date Description

24

Farley 1 5×10-3 3/25/78

Low-Low water level in one SG trip/scram; turbine-driven EFW pump

fails

A low level condition in a single SG resulted in a reactor trip. The turbinedriven EFW pump failed to start. Both motor-driven EFW pumps started, but

were deemed ineffective because all recirculation bypass valves were open

(thereby diverting flow). A recirculation valve was manually closed.

LER 348/78-021

Rancho Seco 1×10-1 3/20/78

Failure of NNI and steam generator dryout

When the reactor was at power, a failure of the NNI power supply resulted in a

loss of main feedwater, which caused a reactor trip. Because instrumentation

drift falsely indicated that the steam generator contained enough water,

control room operators did not take prompt action to open the EFW flow

control valves to establish secondary heat removal. This resulted in steam

generator dryout. LER 312/78-001

Davis-Besse 5×10-3 12/11/77

EFW pumps inoperable during test

During EFW pump testing, operators found that control over both pumps was

lost because of mechanical binding in the governor of one pump and blown

control power supply fuses for the speed changer motor on the other pump. 

LER 346/77-110

Davis-Besse 7×10-2 9/24/77

Stuck-open pressurizer PORV

A spurious half-trip of the steam and feedwater rupture control system

initiated closure of the startup feedwater valve. This resulted in reduced

water level in SG “2.” The pressurizer PORV lifted nine times and then stuck

open because of rapid cycling. LER 346/77-016

Cooper 1×10-3 8/31/77

Partial loss of feedwater; reactor scram; RCIC and HPCI degraded

A blown fuse caused the normal power supply to the feedwater and RCIC

controllers to fail. The alternate power supply was unavailable due to an

unrelated fault. A partial loss of feedwater occurred, and the reactor tripped

on low water level. RCIC and HPCI operated, however, both pumps did not

accelerate to full speed (RCIC due to the failed power supply and HPCI due a

failed governor actuator). LER 298/77-040

Zion 2 2×10-3 7/12/77

Testing causes instrumentation errors

With the reactor in hot shutdown, testing caused operators to lose indications

of reactor and secondary system parameters. In addition, inaccurate inputs

were provided to control and protection systems. LER 304/77-044

Millstone 2 1×10-2 7/20/76

LOOP from grid disturbance; errors in EDG loading fail the emergency

core cooling systems (ECCS)

With the reactor at power, a main circulating water pump was started, and

this resulted in an in-plant voltage reduction to below the revised trip set

point. This isolated the safety-related buses and started the EDGs. Each

time a major load was tied onto the diesel, the revised under-voltage trip set

points tripped the load. As a result, at the end of the EDG loading sequence,

all major loads were isolated, even though the EDGs were tied to the safetyrelated buses. LER 336/76-042
Plant

)CDP

or

CCDP

Date Description

25

Kewaunee 5×10-3 11/5/75

Inoperable EFW pumps during startup as a result of leaks from the

demineralizer into the condensate storage tank (CST)

Mixed bed resin beads were leaking from the demineralizer in the makeup

water system and migrated to the CST. As a result, during startup, both

motor-driven EFW pump suction strainers became clogged, thereby resulting

in low pump flow. The same condition occurred for the turbine-driven EFW

pump suction strainer. LER 305/75-020

Brunswick 2 9×10-3 4/29/75

Multiple valve failures; RCIC inoperable as a result of stuck-open

down/safety valve

At 10-percent power, the RCIC system was determined to be inoperable, and

SRV “B” was stuck open. The operator failed to scram the reactor according

to the EOPs. HPCI system failed to run and was manually shut down as a

result of high torus level. Loop “B” of RHR failed as a result of a failed service

water supply valve to the heat exchanger. The reactor experienced an

automatic scram on manual closure of the main steam isolation valve (MSIV). 

LER 324/75-013

Browns Ferry 1 2×10-1 3/22/75

Cable tray fire

The fire was started by an engineer, who was using a candle to check for air

leaks through a firewall penetration seal to the reactor building. The fire

resulted in significant damage to cables related to the control of Units 1 and

2. All Unit 1 emergency core cooling systems were lost, as was the capability

to monitor core power. Unit 1 was manually shut down and cooled using

remote manual relief valve operation, the condensate booster pump, and

control rod drive system pumps. Unit 2 was shut down and cooled for the first

hour by the RCIC system. After depressurization, Unit 2 was placed in the

RHR shutdown cooling mode with makeup water available from the

condensate booster pump and control rod drive system pump.

LER 259/75-006

Turkey Point 3 2×10-2 5/8/74

Failure of three EFW pumps to start during test

Operators attempted to start all three EFW pumps while the reactor was at

power for testing. Two of the pumps failed to start as a result of

over-tightened packing. The third pump failed to start because of a

malfunction in the turbine regulating valve pneumatic controller.

LER 250/74-LTR

Point Beach 1 5×10-3 4/7/74

Inoperable EFW pumps during shutdown

While the reactor was in cooldown mode, motor-driven EFW pump “A” did not

provide adequate flow. The operators were unaware that the in-line suction

strainers were 95 percent plugged (both motor-driven pumps “A” and “B”). A

partially plugged strainer was found in each of the suction lines for both

turbine-driven EFW pumps. LER 266/74-LTR
Plant

)CDP

or

CCDP

Date Description

26

Point Beach 1 1×10-3 1/12/71

Failure of containment sump valves

During a routine check of the containment tendon access gallery, air was

observed leaking from the packing of one sump isolation valve. Operators

attempted to open the valve, but the valve failed to open due to a shorted

solenoid in the hydraulic positioner. The redundant sump isolation valve was

also found inoperable due to a stuck solenoid in the hydraulic positioner. 

LER 266/71-LTR

*NOTES:

• Events are selected on the basis of CCDPs, as estimated by the ASP Program.

• Because of model and data uncertainties, it is difficult to differentiate between events with CCDPs that are within a factor of about 3. 

• ASP analyses have been performed since 1969, and the associated methodologies and PRA models have evolved over the past 35

years. Consequently, the results obtained in the earlier years may be conservative when compared to those obtained using the

current methodology and PRA models.

Table 12. FY 2001–2005 important precursors (as of September 30, 2005).

Plant Description/Event Identifier Event

Date )CDP

Point Beach 1 & 2

This condition involved a design deficiency in the air-operated

minimum-flow recirculation valves of the EFW pumps. The valves fail

closed on loss of instrument air, and this could potentially lead to pump

deadhead conditions and a common-mode, non-recoverable failure of

the EFW pumps. Because the pressurizer PORVs also depend on

instrument air, an event involving a loss of instrument air may also

result in the loss of feed-and-bleed cooling capability. LER 266/01-005

11/29/01

7×10-4

(Both

Units)

Davis-Besse

Cracking of CRDM nozzles, RPV head degradation, potential clogging

of the emergency sump, and potential degradation of the HPI pumps. 

LER 346/02-002

2/27/02 6×10-3

Point Beach 2

This condition involved a design deficiency in the flow-restricting

orifices in the recirculation lines of the EFW pumps. Because of this

design deficiency, the orifices are vulnerable to debris plugging when

the suction supply for the EFW pumps is switched to its safety-related

water supply (the service water system). Blocked flow in the

recirculation lines of the EFW pumps, combined with inadequacies in

plant emergency operating procedures, could potentially lead to pump

deadhead conditions and a common-mode, non-recoverable failure of

the pumps. The mean )CDP was 6×10-5 for Unit 1. LER 266/02-003

10/29/02 4×10-4
27

Table 13. Precursors involving failure modes and event initiators that were not explicitly modeled in the PRA

or IPE concerning the specific plant at which the precursor event occurred.

Plant Year Event Description

Calvert Cliffs 2 2004 Failed relay causes overcooling condition during reactor trip. LER 318/04-001

Dresden 2 & 3 2004 HPCI potentially unavailable due to water carryover into steam line caused by

feedwater level control failure. LER 249/04-002

Palo Verde 1, 2, & 3 2004 Containment sump recirculation potentially inoperable due to pipe voids.

LER 528/04-009

Shearon Harris 1 2003

Postulated fire could cause the actuation of certain valves that could result in a loss

of the charging pump, RCP seal cooling, loss of RCS inventory, and other conditions. 

LER 400/02-004

St. Lucie 2 2003 Reactor pressure vessel head leakage due to cracking of control rod drive

mechanism nozzles. LER 389/03-002

Crystal River 3

Three Mile Island 1

Surry 1

North Anna 2

2002

Reactor pressure vessel head leakage due to cracking of control rod drive

mechanism nozzle(s). LER 302/01-004, LER 289/01-002, LER 280/01-003, LER

339/01-003, LER 339/02-001

Columbia 2 2002 Common-cause failure (CCF) of breakers used in four safety-related systems.

IR 397/02-05

Davis-Besse 2002

Cracking of control rod drive mechanism nozzles and reactor pressure vessel head

degradation, potential clogging of the emergency sump, and potential degradation of

the high-pressure injection pumps. LER 346/02-002

Callaway 2002

Potential common-mode failure of all auxiliary feedwater pumps due to foreign

material in the condensate storage tank caused by degradation of the floating

bladder. LER 483/01-002

Point Beach 1 & 2 2002

Potential common-mode failure of all auxiliary feedwater (EFW) pumps due to a

design deficiency in the EFW pumps’ air-operated minimum flow recirculation valves.

The valves fail closed on loss of instrument air and this could potentially lead to pump

deadhead conditions and a common mode, non-recoverable failure of the EFW

pumps. LER 266/01-005

Harris 2002 Potential failure of residual heat removal pump “A” and containment spray pump “A”

due to debris in the pumps’ suction lines. LER 400/01-003

Oconee 1, 2, & 3

Arkansas 1

Palisades

2001

Reactor pressure vessel head leakage due to cracking of control rod drive

mechanism nozzle(s). LER 269/00-006, LER 269/02-003, LER 269/03-002, LER

270/01-002, LER 270/02-002, LER 287/01-001 , LER 287/01-003, LER 287/03-001,

LER 313/01-002, LER 313/02-003, LER 255/01-002, LER 255/01-004

Kewaunee 2001

Failure to provide a fixed fire suppression system could result in a postulated fire that

propagates and causes the loss of control cables in both safe shutdown trains.

IR 305/02-06

Prairie Island 1 & 2 2000

A 1988 change in the backwash system for the cooling water pump drive shaft

bearing lubrication water supply system could result in loss of plant cooling water

during postulated loss-of-offsite-power conditions. LER 282/00-004

Oconee 1, 2, & 3 2000

Non-seismic 16-inch fire system piping header transited through the auxiliary building

and posed a potential flooding problem should the piping rupture during a seismic

event. IR 269/00-08

Cook 1 & 2 1999 Postulated high-energy line leaks or breaks in turbine building leading to failure of

multiple safety-related equipment. LER 315/99-026
Plant Year Event Description

28

Oconee 1, 2, & 3 1999 Postulated high-energy line leaks or breaks in turbine building leading to failure of

safety-related 4 kV switchgear. LER 269/99-001

Cook 2 1998 Postulated high-energy line break in turbine building leading to failure of all

component cooling water pumps. LER 316/98-005

Oconee 1, 2, & 3 1998

Incorrect calibration of the borated water storage tank (BWST) level instruments

resulted in a situation where the emergency operating procedure (EOP) requirements

for BWST-to-reactor building emergency sump transfer would never have been met;

operators would be working outside the EOP. LER 269/98-004

Haddam Neck 1996

Potentially inadequate residual heat removal pump net positive suction head

following a large- or medium-break loss-of-coolant accident due to design errors. 

LER 213/96-016

LaSalle 1 & 2 1996 Fouling of the cooling water systems due to concrete sealant injected into the service

water tunnel. LER 373/96-007

Wolf Creek 1996

Reactor trip with the loss of one train of emergency service water due to the formation

of frazil ice on the circulating water traveling screens with concurrent unavailability of

the turbine-driven auxiliary feedwater pump. LER 482/96-001

Wolf Creek 1994 Blowdown of the reactor coolant system to the refueling water storage tank during hot

shutdown. LER 482/94-013
29

0.00

0.05

0.10

0.15

0.20

0.25

0.30

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

FYs 1993-2004 ASP events

Figure 1: Total Precursors– occurrence rate, by fiscal year. No trend line is shown because no trend was

detected that was statistically significant (p-value = 0.1016). FY 2004 results include preliminary data and

are subject to change.
30

0

1

2

3

4

5

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Fiscal Year

Number of Precursors

Figure 2a: Precursors in CCDP bin 10-3– number of

precursors, by fiscal year. No trend line is shown

because no trend is detected that is statistically

significant (p-value = 0.5762).

0.00

0.02

0.04

0.06

0.08

0.10

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 2b: Precursors in CCDP bin 10-4–

occurrence rate, by fiscal year. The decreasing trend

is statistically significant (p-value = 0.0291).

0.00

0.04

0.08

0.12

0.16

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

Figure 2c: Precursors in CCDP bin 10-5–

occurrence rate, by fiscal year. No trend line is

shown because no trend is detected that is

statistically significant (p-value = 0.9738).

0.00

0.04

0.08

0.12

0.16

0.20

0.24

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 2d: Precursors in CCDP bin 10-6–

occurrence rate, by fiscal year. The increasing trend

is statistically significant (p-value = 0.0003).

0.00

0.02

0.04

0.06

0.08

0.10

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 3: Important precursors (CCDP $10-4–

occurrence rate, by fiscal year. The decreasing trend

is statistically significant (p-value = 0.0255).
31

0.00

0.06

0.12

0.18

0.24

0.30

1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 4a: All precursors during FY 1997–2004

(rebaselined data)– occurrence rate, by fiscal year. 

The increasing trend is statistically significant (pvalue = 0.0002).

0.00

0.04

0.08

0.12

0.16

0.20

1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

Figure 4b: All precursors during FY 1997–2004

(rebaselined data) excluding all LOOP events and

CRDM cracking conditions– occurrence rate, by

fiscal year. No trend line is shown because no trend

is detected that is statistically significant (p-value =

0.1244)

0.00

0.04

0.08

0.12

0.16

0.20

0.24

1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 4c: All precursors during FY 1997–2004

(rebaselined data) excluding all LOOP events–

occurrence rate, by fiscal year. The increasing trend

is statistically significant (p-value = 0.0419).

0.00

0.06

0.12

0.18

0.24

0.30

0.36

2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

Figure 4e: All precursors during FY 2001–2004–

occurrence rate, by fiscal year. No trend line is

shown because no trend is detected that is

statistically significant (p-value = 0.6031).

0.00

0.06

0.12

0.18

0.24

0.30

1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 4d: All precursors during FY 1997–2004

(rebaselined data) excluding CRDM cracking

conditions– occurrence rate, by fiscal year. The

increasing trend is statistically significant (p-value =

0.0006).
32

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 7: Precursors involving loss of offsite

power events– occurrence rate, by fiscal year. The

increasing trend is statistically significant (p-value =

0.0405).

0.00

0.08

0.16

0.24

0.32

0.40

0.48

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 8: Precursors involving BWRs– occurrence

rate, by fiscal year. The increasing trend is

statistically significant (p-value = 0.0108).

0.00

0.04

0.08

0.12

0.16

0.20

0.24

0.28

0.32

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

Figure 9: Precursors involving PWRs– occurrence

rate, by fiscal year. No trend line is shown because

no trend is detected that is statistically significant (pvalue = 0.5698).

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

Figure 5: Precursors involving initiating events–

occurrence rate, by fiscal year. No trend line is

shown because no trend is detected that is

statistically significant (p-value = 0.8124).

0.00

0.04

0.08

0.12

0.16

0.20

0.24

0.28

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 6: Precursors involving degraded

conditions– occurrence rate, by fiscal year. The

increasing trend is statistically significant (p-value =

0.0317).
33

1.E-06

1.E-05

2.E-05

3.E-05

4.E-05

5.E-05

6.E-05

7.E-05

8.E-05

9.E-05

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Annual ASP Index (per reactor year)

Significant precursors

All other precursors

Enhanced SPAR Model CDF

SPAR Model Average CDF

Average Annual ASP Index

Figure 10: Annual ASP Index– total CCDP and )CDP of all precursors divided by the number of reactorcalendar years in a given year. Fiscal Years with significant precursors include 1994 (1), 1996 (1), and

2002 (1). Descriptions of these events are provided in Table 11. For some FY 2003 analyses and all

FY 2004 analyses, a new revision of the SPAR models was used. The major changes that occurred in the

SPAR models were initiating event frequencies and equipment reliability data updates, revised LOOP

recovery curves, and the incorporation of a reactor coolant pump seal LOCA probability calculation

package.
34

1.E-06

1.E-05

2.E-05

3.E-05

4.E-05

5.E-05

6.E-05

7.E-05

8.E-05

9.E-05

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Integrated ASP Index (per reactor year)

Significant precursors

All other precursors

Point Beach and D.C. Cook long-term degraded conditions

SPAR Model Average CDF

Enhanced SPAR Model Average CDF

Average Integrated ASP Index

Figure 11: Integrated ASP Index– risk contribution due to precursors, per fiscal year. The risk contribution

from the precursors involving degraded conditions is included in all Fiscal Years that the degraded condition

existed. The risk contribution from precursors involving initiating events is only included in the FY in which

the event occurred. For some FY 2003 analyses and all FY 2004 analyses, a new revision of the SPAR

models was used. The major changes that occurred in the SPAR models were initiating event frequencies

and equipment reliability data updates, revised LOOP recovery curves, and the incorporation of a reactor

coolant pump seal LOCA probability calculation package.
1 Attachment 3

Accident Sequence Precursor (ASP) Program Description

and Comparison with Significance Determination Process (SDP)

and Event Assessment Processes

1.0 Introduction

The Accident Sequence Precursor (ASP) Program

involves the systematic review and evaluation of

operating events that have occurred at licensed

U.S. commercial nuclear power plants. The ASP

Program identifies and categorizes precursors to

potential severe core damage accident sequences.

2.0 Background

The U.S. Nuclear Regulatory Commission (NRC)

established the ASP Program in 1979 in response

to the Risk Assessment Review Group report (see

NUREG/CR-0400, September 1978). Evaluations

done for the 1969–1979 period were the first efforts

in this type of analysis.

3.0 Program Objectives

The primary objective of the ASP Program is to

systematically evaluate U.S. nuclear plant

operating experience to identify, document, and

rank operating events most likely to lead to

inadequate core cooling and core damage

(precursors).

In addition, the other objectives of the ASP

Program are to —

• Provide a measure for trending nuclear power

plant core damage risk.

• Provide a partial check on dominant core

damage scenarios predicted by probabilistic risk

assessments (PRAs).

• Provide feedback to regulatory activities.

• Evaluate the adequacy of NRC programs.

The ASP Program provides the basis for two of five

performance measures for the performance goal to

maintain safety in the reactor safety arena of the

NRC’s Strategic Plan:

• “Zero events per year identified as a significant

precursor of a nuclear accident.” The Strategic

Plan defines a significant precursor as an event

that has a 1 in 1000 (10-3) or greater probability

of leading to a reactor accident.

• “No more than one significant adverse trend in

industry safety performance, with no trend

exceeding Abnormal Occurrence Criterion

I.D.4.” One of the indicators that the NRC’s

Industry Trends Program uses to assess

industry performance against this measure is

the trend of all precursors identified by the ASP

Program.

4.0 Precursor Definitions and Threshold

Definition of an operating event. An operating

event can be:

• An actual initiating event (e.g., loss of offsite

power, loss-of-coolant accident), or

• A condition found during a test, inspection, or

engineering evaluation involving a reduction in

safety system reliability or function for a specific

duration.

The ASP Program uses the term operating event

interchangeably with the terms “initiating event” or

“condition.”

Definition of a precursor. An accident sequence

precursor is an operating event that is an important

element of a postulated core-damage accident

sequence.

Accident sequences of interest to the ASP

Program are those that would have resulted in

inadequate core cooling and severe core damage if

additional failures had occurred.

Precursors are initiating events or conditions that,

when coupled with one or more postulated events,

could result in a plant condition involving

inadequate core cooling. The ASP Program uses

nominal initiating event frequencies and/or nominal

failure probabilities for estimating the conditional

probability of the postulated event portion of the

analysis.

The ASP Program currently performs detailed

analyses of operating events affecting at-power

and shutdown conditions.
2

At-power precursor. An at-power precursor is an

operating event that usually meets one of the

following criteria:

• The total failure of a system required to mitigate

the effects of a core damage initiator.

• The degradation of two or more safety system

trains required to mitigate effects of a core

damage initiator.

• The degradation of one safety system train for

an extended period of time.

• A core damage initiator such as a loss of offsite

power or small-break loss-of-coolant accident.

• A reactor trip or loss-of-feedwater with a

degraded safety system.

Shutdown Precursor. A shutdown precursor is

an operating event that meets both of the following

criteria:

• A core damage initiator such as a loss of

shutdown cooling, loss of reactor vessel

inventory, loss of offsite power, unavailability of

emergency power, or a loss-of-coolant accident,

and

• The initiator could only have occurred with the

plant in a shutdown condition.

CCDP vs. Importance. The figure of merit for

ASP analyses is the conditional core damage

probability (CCDP) for initiating events and the

increase in core damage probability ()CDP) or

importance for conditions.1

 The importance is the

measure of the incremental increase between the

CCDP for the period in which the condition existed

and the nominal CDP for the same period.

Threshold. An initiating event with a CCDP or a

condition with an importance greater than or equal

to 1×10-6 is classified as a precursor in the ASP

Program.

5.0 Comparison of ASP Program with SDP

and Event Assessment Processes2

Accident Sequence Precursor Program. The

main purpose of the ASP Program is to review and

evaluate operational experience to identify

precursors to potential severe core damage

sequences. The ASP Program provides a

comprehensive risk analysis of initiating events

(e.g., reactor trip initiator) and degraded conditions

(e.g., equipment or functional degradations) at

nuclear power plants.

Significance Determination Process. The main

purpose of the SDP is to determine the safety

significance of inspection findings. The SDP is part

of the Reactor Oversight Process and evaluates

inspection findings in all seven cornerstones of

safe operation — initiating events, mitigating

systems, barrier integrity, emergency

preparedness, public radiation safety, worker

radiation safety, physical protection. The SDP uses

a three-phase approach to determine the

significance of inspection findings in the initiating

events, mitigating systems, and barrier integrity

cornerstones.

NRC Incident Investigation Program (i.e., Event

Response Evaluation). The main purpose of the

event response evaluation element of the NRC

Incident Investigation Program is to determine the

appropriate level of reactive inspection in response

to a significant event. The event response

evaluation process is part of the Reactor Oversight

Process and provides a prompt evaluation of

significant operational events (as defined in

Management Directive 8.3, “NRC Incident

Investigation Program”) involving reactor and fuel

cycle facilities and NRC or Agreement State

licensed materials.

5.1 Summary of Similarities and Differences

The discussion below compares the various

programs and is focused on the part of the

programs used to evaluate actual events and

degraded conditions at nuclear power plants.

These events and conditions correspond to three

of the seven cornerstones of safe operation — 

1 The CCDP and importance are equal for precursors

involving initiating events. 

2 This section summarizes the differences and scopes

of the three programs as documented in a

memorandum to the Commission, entitled “Response

to Staff Requirements Memorandum SRM-M020319,

Dated April 1, 2002, Briefing on Office of Nuclear

Regulatory Research (RES) Programs, Performance,

and Plans,” dated July 12, 2002 (ADAMS Accession

no. ML0217600040).
3

initiating events, mitigating systems, and barrier

integrity.

Similarities Between ASP, SDP, and Event

Response Processes. The risk models and

technical methods used in ASP, SDP Phase 3, and

event response assessments are generally similar.

The Standardized Plant Analysis Risk (SPAR)

models are typically used in all three processes,

although the licensee’s probabilistic risk

assessment (PRA) can be used in SDP and event

response assessments. Most of the methods

applied in SDP Phase 3 and event response

assessments are derived from the ASP Program;

however, other methods, such as use of the

licensee’s generated PRA results and simplified

hand calculations, are permitted by the procedures.

The SDP Phase 1 is a screening procedure that

identifies the inspection findings to be evaluated

under SDP Phase 2 or 3. The ASP and event

response processes also employ screening

procedures. Risk significance estimation under the

SDP Phase 2 process is quite different from ASP,

SDP Phase 3, and event response processes. 

The SDP Phase 2 process uses site-specific,

risk-informed inspection notebooks to assess the

risk significance (i.e., color) of inspection findings.

The ASP, SDP Phase 3, and event response

evaluation processes primarily use SPAR models

in the analysis of events and degraded conditions.

Differences Between ASP, SDP Phase 3, and

Event Response Processes. Some differences

are inherent in the intended function of the system.

For example, the timeliness in which results are

needed has a significant impact on the level of

detail that goes into an analysis and the amount of

event-related information available at the time the

results are needed by decision makers. More

available time can reduce the uncertainties in the

results. Another example is the scope of the events

analyzed. Not all systems evaluate all events and

degraded conditions. Some differences are

highlighted below.

• Applicability. Inspection findings with a greaterthan-green risk significance are most likely

precursors in the ASP Program. However, not

all precursors result in an inspection finding.

These precursors include initiating events

(actual reactor trips) or degraded conditions

where no deficiency in the licensee’s

performance was identified. For example, an

extended loss of offsite power event caused by

an act of nature will be a precursor, most likely

in the 10-4 conditional core damage probability

(CCDP) range.

The SDP would screen out this event if no

performance deficiency was found. Significant

events and degraded conditions that result in a

reactive inspection (i.e., special inspection,

augmented inspection, incident investigation)

based on an event response evaluation would

be analyzed in the ASP Program. In the loss of

offsite power example above, an augmented

inspection or incident investigation would be

considered based on a CCDP in the 10-4 range.

Concurrent multiple degraded conditions are

analyzed together in the ASP Program. In the

SDP program, concurrent multiple degraded

conditions that involve different performance

deficiencies are analyzed individually.

• Analyses. Event response assessment is

expected to be performed within a day or two

after the event notification. Lack of detailed

information regarding the event or degraded

conditions at the time of the assessment

sometimes requires use of engineering

judgment or simplistic assumptions. In such a

case, the point estimate of the risk assessment

carries a large uncertainty. However, for

determining what reactive inspection may be

most appropriate, based on a risk-informed as

opposed to risk-based process, the emphasis is

not on the specific value but on the range of the

safety significance.