POLICY ISSUE

INFORMATION

November 8, 2004 SECY-04-0210

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 provide the status of the development of the

Standardized Plant Analysis Risk (SPAR) models. 

SUMMARY:

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

last status report, SECY-03-0049, dated March 31, 2003. A summary of upcoming activities for

the next 12 months is provided. 

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 provided annual quantitative ASP results.

CONTACTS: Don G. Marksberry, RES (ASP Program)

301-415-6378 

Patrick D. O’Reilly, RES (SPAR Model Development Program)

301-415-7570 
The Commissioners 2 

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 lead to inadequate core cooling and

severe core damage (precursors), if additional failures had occurred.

To identify potential precursors, the NRC staff reviews events and conditions from licensee

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

analyzes any identified potential precursors and calculates a conditional core damage probability

(CCDP). An event or condition with a CCDP greater than or equal to 1.0 x 10-6 is considered a

precursor in the ASP Program. The ASP Program defines a “significant” precursor as an event

with CCDP greater than or equal to 1 x 10-3. 

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 on an adhoc basis.

The NRC also uses the ASP Program to monitor performance against the Safety Goal

established in the agency’s Strategic Plan. (See NUREG-1614, Vol. 3, dated August 2004.) 

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

• No more than one event per year (this will be zero events per year for FY 05-06) identified

as a significant precursor of a nuclear reactor accident (i.e., CCDP or importance greater

than or equal to 1 x 10-3).

• No statistically significant adverse industry trends in safety performance (this determination

is principally made from the Reactor Oversight Program but supported by ASP results). 

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 and the event response evaluation process, as defined in Management Directive 8.3,

“NRC Incident Investigation Program”). The ASP Program assesses the significance of a

broader range of operating experience at U.S. nuclear power plants than the other two

programs. This includes initiating events (e.g., reactor trips, loss of offsite power events) and

degraded conditions (e.g., equipment or functional degradations) where no deficiency in the

licensee’s performance was identified, events that involve two or more degraded conditions

involving system unavailabilities that overlap in time, and events that occur during low power
The Commissioners 3 

1 The differences and scope of the three programs are documented in a memorandum to the Commission,

“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). The Risk Assessment Standardization Project (see Attachment 1) will

standardize the risk assessment of operating events and conditions within the agency.

and shutdown operations.1 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.

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.

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

models. However, benchmarking performed during the onsite quality assurance review of the

SPAR models indicated that they capture 80–85 percent of the core damage frequency from

the licensee models.

Revision 3 of the SPAR models includes the capability to perform uncertainty analysis through

the propagation of uncertainty distributions at the equipment and human performance levels. 

The SPAR models also use results from studies sponsored by the NRC’s Office of Nuclear

Regulatory Research (RES) to provide an independent validation of input parameters used in a

licensee’s PRA. These studies include system and component reliability analyses, initiating

event studies, and a human reliability analysis method.

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)
The Commissioners 4 

DISCUSSION:

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

last status report, SECY-03-0049, dated March 31, 2003.

Status of the ASP Program and SPAR Model Development Program: Implementation and

Results

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

• Screened and analyzed events for Fiscal Years (FYs) 2001–2004 to identify precursors and

“significant” precursors. The staff completed all event-related analyses for FY 2001 and

2002, with the exception of those related to several events involving cracks in control rod

drive mechanism housings and the multiple conditions at Davis-Besse coincident with the

degradation of the vessel head. In addition, the staff plans to complete the preliminary

analysis of FY 2003 events by the end of this year, while continuing the analyses of FY

2004 and 2005 events. 

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

Trends Program. 

• Implemented an initiative to improve the timeliness of ASP analyses by streamlining the

analysis and review process. The staff also improved the methods used in ASP analyses,

such as parameter and modeling uncertainty analysis, human reliability analysis, and the

expert elicitation process.

• Initiated the Risk Assessment Standardization Project (RASP) as a collaborative effort

involving RES, NRR, and the regions, in order to standardize the risk assessment of

operating events and conditions within the agency.

SPAR Model Development Program

• Completed the onsite quality assurance reviews of all 72 Revision 3 SPAR models. Based

on user requests, the staff also began enhancing all plant-specific SPAR models for internal

initiating events during full-power operation.

• Completed SPAR models for three lead plants for internal initiating events during LP/SD

operations.

• Completed the SPAR model for calculating LERF for the lead plant in the first plant class.

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

sequences) into the Revision 3 SPAR models.
The Commissioners 5 

ASP Results, Trends, and Insights

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

additional detail.

• No significant precursors were identified in either FY 2003 or FY 2004. As noted in the

previous status report, however, the staff did identify one event in FY 2002 as having the

potential to be a significant precursor. Specifically, that event involved multiple conditions

discovered at the Davis-Besse Nuclear Power Station. Because the preliminary analysis of

the conditions at Davis-Besse is undergoing peer review, the staff will report on this result in

the NRC’s forthcoming Performance and Accountability Report for FY 2004.

• Ten precursors identified in FYs 2001–2004 had a CCDP greater than 1x10-4.

• No trend was identified in the rates of occurrence of all precursors during the period from

FY 1993 through FY 2002. The staff will report on this result in the NRC’s Performance and

Accountability Report for FY 2004. 

• Trending of precursors by CCDP bins yielded mixed results. If a trend is considered

statistically significant (explained in Attachment 2), it is very unlikely that the trend is a result

of chance alone. Trending analysis of precursors in the CCDP bins yielded the following

results: 

CCDP > 1 x 10-3 No trend

1 x 10-3 > CCDP > 1 x 10-4 Decreasing trend - almost statistically significant 

1 x 10-4 > CCDP > 1 x 10-5 Decreasing trend - statistically significant 

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

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, 2005, to support the agency’s Strategic Plan goals for monitoring performance.

• Complete the final analysis of events for FY 2003; continue the screening, review, and

analysis (preliminary and final) of events for FYs 2004 and 2005.

• Evaluate precursor data for trends and engineering insights. 

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

operations.
The Commissioners 6 

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

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

• Develop an improved user interface for use with Revision 3 SPAR models (in response to

user feedback).

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

In summary, 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 most recent

example of this is the use of ASP results and insights in the Agency’s action plan for resolving

electrical grid concerns. The ASP program reports no significant trend in the number of

precursors over the last 10 years and one potentially significant precursor in 2002 (DavisBesse). There is no indication of an increase in the severity of precursors. The SPAR model

development program is continuing to develop and improve independent risk analysis tools and

capabilities to support the use of probabilistic risk assessment 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 the staff’s risk-informed reviews of license amendments as well as

to independently verify the Mitigating Systems Performance Index (MSPI) as part of the pilot

plant process.

/RA/

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
The Commissioners 6 

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

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

• Develop an improved user interface for use with Revision 3 SPAR models (in response to

user feedback).

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

In summary, 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 most recent

example of this is the use of ASP results and insights in the Agency’s action plan for resolving

electrical grid concerns. The ASP program reports no significant trend in the number of

precursors over the last 10 years and one potentially significant precursor in 2002 (DavisBesse). There is no indication of an increase in the severity of precursors. The SPAR model

development program is continuing to develop and improve independent risk analysis tools and

capabilities to support the use of probabilistic risk assessment 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 the staff’s risk-informed reviews of license amendments as well as

to independently verify the Mitigating Systems Performance Index (MSPI) as part of the pilot

plant process.

/RA/

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

DOCUMENT: A:ML042580366.wpd

WITS# 199200101

*See previous concurrence 

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

NAME DMarksberry PO’Reilly CHunter MCheok PBaranowsky

DATE 09/03/04 09/03/04 09/03/04 09/03/04 09/03/04

OFFICE DRAA* E NRR* E RES* E DMDMRS EDO 

NAME CAder JDyer CPaperiello MVirgilo LReyes

DATE 09/03/04 09/15/04 09/15/04 11/08/04 11/08/04

OFFICIAL RECORD COPY

OAR in ADAMS? (Y or N) Y Publicly Available? (Y or N) No*

* To be issued to the public by SECY

Template Number: SECY-012 Accession Number: ML042580366 RES File Code: 2C-3
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 FY 2001–2004 events. During this reporting period, the staff screened and

reviewed more than 700 licensee event reports (LERs) from FY 2001–2004 to identify potential

precursors. Of the 148 events selected for analysis, the staff completed 119 analyses, rejecting

79 as not meeting the precursor threshold and identifying 40 precursors. With the exception of

the ongoing analyses of the condition discovered at the Davis-Besse Nuclear Power Station

and the cracks in the control rod drive mechanism (CRDM) housings at several plants, the staff

has completed ASP analyses for all events that occurred in Fiscal Years (FYs) 2000–2002. 

The analyses of FY 2003 events are also nearing completion, and the analyses of FY 2004

events have begun. Attachment 2 to this paper summarizes the final and preliminary precursor

analyses, and provides a list of events involving CRDM cracking.

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 takes 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 Office of Nuclear Regulatory Research (RES) has

completed a project to use the laboratory characterization of the degraded vessel head material

and analytic models to estimate the probability of a loss-of-coolant accident from the vessel

head degradation. Preliminary ASP analysis results show that this event is potentially a

significant precursor. The staff issued the preliminary ASP analysis for peer review in

September 2004.

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

stress corrosion cracking of CRDM housings. The events reviewed during this reporting period

involved the discovery of such cracks at 11 plants in FYs 2001–2003 and may result in 11

precursors. This ongoing analysis involves completing the RES probabilistic analysis of the

time-dependent failure frequencies of the CRDM housings. The staff is currently analyzing

these potential precursors in conjunction with characterizing the probability of failure of the asfound crack conditions at Davis-Besse. In addition, the staff has conducted a sensitivity

analysis to show that CRDM cracking events at plants other than Davis-Besse would most likely

not cause an event to be classified as a significant precursor (i.e., CCDP $ 1x10-3), but would

most likely be classified as a precursor (i.e., CCDP $ 1x10-6). The staff will issue its preliminary

analyses of the remaining plants for peer review following the completion of the final DavisBesse analysis. 

Implementation of the ASP catchup plan. The staff plans to complete its FY 2003 analysis

of potential precursors by December 2004, while proceeding to analyze FY 2004 events. In

addition, to improve the timeliness of the analyses of potentially high-risk events, the agency is

redirecting resources to those analyses when such events are identified during NRC

inspections or in LERs. For example, collaboration with the regional office enabled the staff to

complete its preliminary ASP analysis of the June 2004 Palo Verde loss of offsite power in less

than 2 months. As a result, the staff subsequently included the results of that analysis in the
2

Region IV augmented inspection team (AIT) report. Similarly, within 4 months following the

issuance of LERs regarding the eight loss of offsite power events caused by the electrical grid

blackout in August 2003, the staff completed its analyses of all eight related precursors. These

results were used as input to the Agency’s grid reliability Action Plan.

Investigation of trends and engineering insights. Attachment 2 presents trends and general

insights that emerged from the staff’s analysis of the ASP data. In FY 2005, the staff will initiate

a detailed evaluation of the ASP data to investigate the nature of trends, determine whether

there is an explanation for the relatively low number of precursors between 1997 and 1998 and

the increasing number of potential precursors in 2000–2002, and identify any engineering

insights that can be applied in the NRC’s regulatory programs. This collaborative effort, which

will be initiated in response to a recommendation from the Operating Experience Task Force,

will draw upon the broad expertise of staff throughout the agency. 

ASP Program Improvements and Activities

To improve efficiencies in the ASP Program, the staff has initiated programs to streamline

the ASP analysis and review processes, and standardize the risk assessment of operating

events within the agency. (Subsequent sections of this attachment provide additional detail

concerning these and other improvements.) The goal of the ASP Program is to complete the

analysis of potential precursors within 4–12 months following the initiation of an event or

discovery of a condition. However, the staff recognizes that additional time may be required to

complete the analysis of the occasional complex, first-of-its-kind event that requires the

development of new models or methods. Historically, the staff has encountered about two

complex analyses per year.

Streamlining of analyses and reviews. As previously noted, the staff has attempted to

increase efficiency by initiating an effort to streamline the ASP analysis and review processes. 

Specifically, the staff has implemented a strategy to prioritize and, where appropriate, scale

back efforts on noncontroversial events and those with lower CCDPs. That strategy uses a

graded approach to methods, documentation, and peer review of ASP analyses. The graded

approach will improve efficiencies in analyzing events for potential precursors by reducing

duplicative analysis of events, the burden on licensees, and repetitive peer reviews. This

approach includes the following measures:

• For ASP analyses of noncontroversial, low-risk precursors in which the ASP results

reasonably agree with the SDP results, detailed uncertainty analyses and formal peer

reviews by staff and the licensee will not be performed. The ASP Program will continue the

in-house review process for all analyses.

• In lieu of a detailed ASP analysis of a condition in which the SPAR model was used in an

SDP Phase 3 analysis, RES will perform a comprehensive technical review of the final SDP

Phase 3 analysis for green, white, or yellow findings.

• RES resources will be optimized to focus on events with the highest risk significance. An

ASP analysis of a potentially significant precursor (i.e., CCDP > 1 x 10-3) will be started

immediately after being identified during an NRC inspection or documented in an LER.
3

The graded approach has had a noticeable effect in streamlining the ASP Program. In the last

18 months, about 70 percent of the ASP precursor analyses that included noncontroversial,

low-risk events and reasonably agreed with the SDP results did not require time for additional

peer reviews. The elimination of these reviews reduced the time to complete final precursor

analyses by four to five months. In addition, since these events were analyzed by the SDP, the

graded approach eliminated the burden on licensees, as well as staff, having to perform

additional peer reviews.

Methods improvements. The development of new and enhanced analytical methods is an

important part of the ASP analysis process. Methods used in routine analyses are improved

where needed, while new methods are developed for the analysis of complex, first-of-its-kind

events. As a result, the methods used in analysis today are more sophisticated than those

used in the past.

In the past, the ASP Program included a category called “Potentially Significant Events

Considered Impractical to Analyze.” That category was used to bin potential precursors that

were difficult to analyze because of a lack of information or an inability to reasonably model the

event within a PRA framework, considering the level of detail typically available in PRA models

and the resources available to the ASP Program. About 25 percent of the events in the ASP

database for the period from 1969 through 1994 were considered impractical to analyze. By

contrast, only two events since 1995 were similarly binned.

In the current program, the staff obtains information needed to analyze complex events using

more elaborate methods, such as plant visits, inputs from the inspection program, use of an

informal expert elicitation process, development of new analysis methods, enhancement of

existing SPAR models, and use of sensitivity or uncertainty analyses.

During the current reporting period, the following methods were developed or are currently

under development:

• Uncertainty analysis. Parameter and modeling uncertainties were first included in the ASP

analysis of the D.C. Cook (2001) and the Point Beach (2002) precursors. The parameter

values for equipment performance and human performance used in the risk model and the

uncertainties regarding these values (parameter uncertainty) are estimated using generic

industry data adjusted for plant-specific operating experience and design features. These

data and uncertainty distributions are then propagated through the SPAR model to produce

a mean value of the CDP as well as the 5th and 95th percentile values. The issue of

alternative model assumptions (often referred to as model uncertainty) is handled by

performing sensitivity studies.

• Human Reliability Analysis (HRA). The ASP Program uses the SPAR HRA methodology to

estimate human error probabilities for recovery actions. The HRA methodology report was

issued for peer review in Fall 2003, and the Advisory Committee on Reactor Safeguards

(ACRS) was briefed on the new method in October 2003. In addition to discussing the

method and models, the report presents definitions and guidance for use in applying the

model in ASP and SDP analyses. The final report (which will incorporate peer review

comments) will be issued during the first quarter of FY 2005.
4

• ASP expert elicitation process. In 2003, the staff initiated a project to develop a simplified,

limited expert elicitation methodology and procedure to meet the needs of the ASP

Program. 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 methodology, but is simplified and streamlined as appropriate to the

required degree of accuracy and the schedule for completing the ASP analyses. The staff

plans to issue the procedure for peer review early in FY 2005. 

The use of these new methods has proven to be effective in reducing the time needed to

complete precursor analyses. Uncertainty analysis has reduced the need for supplemental

information from regional staff and licensees for those cases where sensitivity analysis shows

an uncertain assumption is not an important contributor to the overall risk. In addition,

uncertainty analysis has been used as a measure of reasonableness when comparing ASP and

SDP results.

National Academy of Engineering report on precursor programs. On August 18, 2004, the

National Academy of Engineering (NAE) released a report, entitled “Accident Precursor

Analysis and Management, Reducing Technological Risk Through Diligence.” That report

documents the 7-month Accident Precursors Project, which reviewed approaches for detecting,

analyzing, and benefitting from accident precursors. The NAE invited the NRC to participate in

the project because of the agency’s recognized leadership in accident precursor analysis, as

demonstrated by the ASP Program. The NAE report contains 11 general recommendations

intended to enhance the use of accident precursor data. It also reinforces the potential value of

precursor analysis and the use of its results and insights in the regulatory program, consistent

with the findings of the NRC’s Operating Experience Task Force. In addition, the NAE report

recognizes the ASP Program as an example of a precursor program that is worthy of emulation

by other Government agencies. 

ASP database on the agency’s Intranet. The staff has upgraded its database of ASP

analysis results and reports, which currently contains the final analysis results of more than 600

precursors identified by the ASP Program since 1969. Beta testing of the upgraded ASP

database was completed in 2003, and the database is now available to the NRC staff through

the RES Reactor Operating Experience Results and Databases internal Web page. However,

given the sensitivity of information contained in the analysis reports, the agency will not make

this database available through the NRC’s public Web site at this time.

Communications with external organizations. In addition to a presentation at the NAE

workshop on precursor programs in August 2003, NRC staff representatives provided

presentations and inputs concerning ASP program status and results to numerous

organizations. In particular, these included presentations at the Sixth Technical Meeting on

Experience with Risk-Based Precursor Analysis held in Brussels, Belgium (November 2003);

the ACRS Subcommittee on Reliability and Probabilistic Risk Assessment (March 2004); the

Massachusetts Institute of Technology summer session on reactor safety (June 2003 and

2004); the National Aeronautics and Space Administration, Office of Safety and Mission

Assurance (July 2004); and the Atomic Energy Regulatory Board of India (September 2004). In

addition, staff representatives provided input to the annual Commission paper on the NRC’s
5

Industry Trends Program (SECY-04-0052) and the U.S. National Report to the Convention on

Nuclear Safety (soon to be published as a NUREG-series report). 

SPAR Model Development

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 and shutdown

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

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 the 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 last report:

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

• Completed the onsite quality assurance (QA) review of the last 19 Revision 3i SPAR

models, in conjunction with benchmarking of the SDP Plant Notebooks by the Office of

Nuclear Reactor Regulation (NRR). This effort involved reviewing the SPAR model with the

licensee’s PRA staff and benchmarking that model against the licensee’s PRA. With this

achievement, all 72 Revision 3i models have undergone onsite QA review, the models and

their accompanying documentation have been revised to reflect the review results, and they

have been certified as Revision 3 models.

• Completed the detailed review of the Revision 3 SPAR models for the 11 pilot plants

participating in the Mitigating Systems Performance Index (MSPI) Program, and modified

the SPAR models for those plants to reflect the review results.

• Using the insights obtained from the review of the pilot plants in the MSPI Development

 developed a strategy for a similar type of review (down to the cut set level) and

subsequent model revision that will produce a set of enhanced Revision 3 SPAR models. 

This effort will also require resolution of a number of PRA modeling issues that were

identified (1) during the onsite QA reviews of the Revision 3 SPAR models; (2) during the

MSPI pilot program reviews; and (3) from feedback by model users. The staff is currently

developing proposed strategies for resolving these modeling issues with the industry.

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

(LP/SD) operation

• Completed interim LP/SD SPAR models for Diablo Canyon Nuclear Power Plant, Palo

Verde Nuclear Generating Station, Oconee Nuclear Station, Peach Bottom Atomic Power

Station, River Bend Station, and Grand Gulf Nuclear Station, and sent the models to the

respective licensees for review. The staff has now completed 10 LP/SD SPAR models, and

this marks the completion of the first phase of the effort. The second phase consists of an

onsite QA review of the models.
6

• Conducted onsite QA reviews of the LP/SD SPAR models for Peach Bottom, River Bend,

and Grand Gulf. The staff will schedule onsite reviews for the remaining plants in FY 2005.

• Met with the ACRS to discuss development of LP/SD SPAR models. The Committee

provided favorable comments and asked the staff to keep the ACRS informed about the

progress of this model development effort.

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

• Completed the LERF SPAR model for Comanche Peak Steam Electrical Station (the lead

plant in the first plant class), which is a 4-loop Westinghouse-designed pressurized-water

reactor (PWR) with a large, dry 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 preliminary 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 Mark I

containments. The staff subsequently sent the model to key NRC users for internal review.

SPAR models for the analysis of external events

• Started work in July 2004 to incorporate external initiating events (i.e., fires, floods, and

seismic sequences) into the Revision 3 SPAR models. 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 plant visits to Diablo Canyon, Limerick Generating Station, and Salem

Generating Station to gather plant-specific information and data for a feasibility study. The

staff expects to complete this feasibility study early in FY 2005.

Risk Assessment Standardization Project (RASP)

Risk assessments of reactor events and conditions, which are performed by several groups

within the NRC, require the benefit of standard procedures, methods, models, and formats. 

Such standards would enable the staff to avoid duplication of effort, inconsistent products, and

conflicting results. Detailed documentation of analysis procedures and methods would also

reduce the time required to complete routine risk analyses of operating events and licensee

performance issues. In addition, improved documentation would enhance the internal and

external communication of risk results.

Background. NRR asked the RES staff to develop procedures and methods that RES, NRR,

and the regional offices will use to achieve more consistent results when performing risk

assessments of operating events and licensee performance issues. The project will draw upon

the expertise developed in the ASP Program to document risk assessment guidelines.

As envisioned, the RASP will promote consistency in the methods and formats used for the

agency’s risk assessments. The primary focus of this project is to standardize risk analyses in
7

SDP Phase 3, the ASP Program, and the Incident Investigation Program under Management

Directive (MD) 8.3.

Under this project, the NRC staff will complete the following activities:

• Develop guidelines for analyses of internal events during power operations.

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

internal fires and floods, external events (e.g., seismic events and tornadoes), internal

events during LP/SD operations, and LERF sequences.

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

SAPHIRE PRA code and GEM interface code).

• 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.

This effort will support the ASP Program’s long-term plan to improve the efficiency of ASP

analyses and to increase consistency between ASP approaches and those used in SDP

analyses, where possible. In addition, this effort is part of NRR’s SDP improvement initiative.

Status. The NRC formed the RASP Coordination Team to oversee the development and

implementation efforts. The team includes representatives from the RES Operating Experience

Risk Analysis Branch (OERAB), the NRR Probabilistic Safety Assessment Branch (SPSB) and

Inspection Program Branch (IIPB), and the regional offices. To date, the RASP Coordination

Team has identified preliminary deliverables, operating plan milestones, and a schedule.

The staff began working on the internal event guidelines in April 2004, and has identified the

scope, level of effort, and schedule for guidelines to address external events, LP/SD

operations, and LERF. The effort will directly follow completion of the internal events analysis

guidelines. 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 Years (FYs)

2001–2004. Based on those results, this

document also discusses the NRC’s analysis

of historical ASP trends, and the evaluation

of the related insights. The 11 tables and

14 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 15, 2004. 

Specifically, the table identifies the number of

preliminary and final analyses that the NRC

staff has completed for events that occurred

during each fiscal year (2001–2004), as well

as the number of preliminary analyses that

are still underway, which include events that

will be rejected as precursors. (Note that, as

of August 31, 2004, the staff had not yet

screened all of the FY 2004 events and

unavailabilities.) The following subsections

summarize the results of these analyses,

which are further detailed in the associated

Tables 2–9.

FY 2001 analyses. The ASP analyses for

FY 2001 identified 23 precursors. Of those

23 precursors, 18 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).1

 All 23 of these 

precursors occurred 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 precipitating conditions. In

addition, Table 4 lists the CRDM cracking

events that occurred during FYs 2001–2003.

FY 2002 analyses. The ASP analyses for

FY 2002 identified 14 precursors. Of those

14 precursors, 8 were identified on the basis

of final analyses, 1 is a potential precursor

based on preliminary analysis, and 5 are

potential precursors (expected to be

precursors) because they relate to CRDM

cracking events. All 14 of these precursors

occurred at power.

The staff has completed its preliminary

analysis of the multiple conditions that

occurred at the Davis-Besse Nuclear Power

Station coincident with degradation of the

reactor pressure vessel (RPV) head; the

document has been issued for peer review. 

This event is a potential significant

precursor.2

Table 5 presents the results of the staff’s

ASP analyses for FY 2002 precursors that

involved initiating events, while Table 6

presents the analysis results for precursors

that involved precipitating conditions. In

addition, as previously noted, Table 4

includes CRDM cracking events that

occurred during FY 2002.

FY 2003 analyses. In February 2004, the

1 NRC staff completed its screening and As of September 15, 2004, the staff has not

completed its preliminary ASP analyses of

CRDM cracking events that occurred during

FYs 2001–2003. However, based on

sensitivity analyses completed to date, the

staff anticipates that these events will yield an

increase in core damage probability (∆CDP)

that is greater than or equal to 1x10-6.

2

A significant precursor has a conditional core damage

probability (CCDP) or change in core damage probability

(∆CDP) that is greater than or equal to 1x10-3.
2

review of licensee event reports (LERs)

concerning events that occurred during FY

2003. On the basis of that review, the ASP

analyses have (thus far) identified 10

precursors, including 2 based on final

analyses and 8 based on preliminary

analyses. All 10 of these precursors

occurred at power. An additional 22 analyses

are ongoing, but the results of some of these

analyses will not exceed the precursor

threshold.

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 precipitating conditions. The

staff may identify additional precursors after

completing the ongoing analyses of FY 2003

events. 

FY 2004 analyses. The staff has completed

all screening and reviews for potential

significant precursors through September 15,

2004. In particular, the staff had 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 2004. 

The staff has also completed three preliminary

analyses for losses of offsite power (LOOPs)

that occurred during FY 2004 at Palo Verde

Nuclear Generating Station, Units 1, 2, and 3. 

Table 9 addresses the Unit 2 event within the

context of important precursors for

FYs 2001–2004.

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 4.) The trending method uses pvalue 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

figure 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 2002. In addition, 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 and

∆CDP > 1x10-3) includes events that

occurred during FYs 2003 and 2004. The

results for FY 2004 are based on the

staff’s screening and review of a

combination of LERs and daily event

notification reports (10 CFR 50.72).3

 The

staff analyzes all potential precursors

immediately. 

• CRDM cracking events. The staff is still

conducting its preliminary analyses of

cracking that occurred in CRDM housings

during FYs 2001 and 2002. Sensitivity

analyses conducted to date show that

these cracking events are most likely

potential precursors but not significant

presursors. Therefore, the staff has

included these events in the total count

and trending of all precursors (i.e., CCDP

and ∆CDP > 1x10-6). However, the staff

has not included these events in the CCDP

bin trends because their exact ∆CDP

values are not yet known.

3 The staff has completed all screening and

reviews through September 15, 2004.
3

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 of “no statistically

significant adverse industry trends in safety

performance” (one measure associated with

the Safety goal established in the NRC’s

Strategic Plan). Although the principle

measures come from the Reactor Oversight

Program, NRC’s Office of Nuclear Reactor

Regulation (NRR) also uses precursors

identified by the ASP Program to assess

industry performance. Thus, the method

used to trend precursors is consistent with

the analysis used to trend the other indicators

in the ITP.

Results. No statistically significant trend has

been observed in the occurrence rate for all

precursors that occurred during the period

from 1993 through 2002. Figure 1 depicts

the occurrence rate per reactor-year for all

precursors by fiscal year.

Figure 1 also shows the ASP results for

events that occurred before FY 1993, which

were derived using a less-rigorous

methodology but are shown to provide

historical perspective.

Data coverage. The trend of all precursors

includes the ongoing analyses of events that

involved cracking in CRDM housings. 

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 1.)

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 these figures

represent statistically significant trends, each

figure shows the trend line of the mean

occurrence rate, with the 90-percent

confidence band indicated by error bars.

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 2002:

CCD

P Bin Trend

>10-3 No statistically significant trend

10-4 Decreasing trend -

almost statistically significant

10-5 Decreasing trend - statistically

significant

10-6 Increasing trend - statistically

significant

While no trend was detected in the highest

CCDP bin (>10-3) and trends in bins 10-4 and

10-5 are decreasing, an increasing trend was

detected in the lowest CCDP bin (10-6). The

cause of this increasing trend will be

investigated in an upcoming study. In

FY 2005, the staff will initiate a detailed

evaluation of the ASP data to investigate the

nature of trends and identify insights that can

be applied in the NRC’s regulatory

programs. 
4

Data coverage. The trends of precursor bins

do not include the ongoing analyses of

events that involved cracking in CRDM

housings. The trend of the CCDP $10-3 bin

includes events for FYs 2003 and 2004. All

other bins cover the period from FY 1993

through FY 2002.

3.0 Insights and Other Trends

The discussion of significant precursors in

Section 3.1 covers the period from FY 1993

through FY 2004, although the FY 2004

results are based on the staff’s screening

and review of a combination of LERs and

daily event notification reports (10 CFR

50.72).4

 Section 3.4, which addresses the

LOOP initiating events, also covers the

period from FY 1993 through FY 2004.5

 The

insights presented in the remaining sections

cover the period from FY 1993 through

FY 2002. 

3.1 Significant Precursors

The ASP Program provides the basis for the

FY 2004 performance goal measure of “no

more than one event 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). 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 2.) It should be noted that this

performance goal was changed to zero

events per year beginning in FY 2005. 

Table 11 summarizes the top 20 significant

precursors that occurred during the period

from FY 1974 through FY 2004.

Results. Figure 2a depicts the number of

significant precursors that occurred during

FY 

1993–2004. A review of the data for that

period reveals the following insights:

• The staff did not identify any significant

precursors during FYs 2001, 2003, and

2004.

• The multiple conditions coincident with

degradation of the RPV head at

Davis-Besse represent a potential

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.

• The performance goal measure of “no

more than one event per year identified as

a significant precursor of a nuclear

accident” has not been exceeded during

the period from FY 1993 through FY 2004.

• The staff did not observe any statistically

significant trend in the occurrence of

significant precursors during FYs

1993–2004.

• Significant precursors have occurred, on

average, about once every 4 years. The

events in this group involve differing failure

modes, causes, and systems.

• Two additional precursors with a CCDP

$1x10-3 have occurred in the past 12

years. Specifically, the event at Wolf

Creek Generating Station (1994) involved

a reactor coolant system (RCS) draindown

to the refueling water storage tank during

hot shutdown, while the event at Unit 2 of

the Catawba Nuclear Station (1996)

involved an extended, plant-centered

LOOP with an emergency diesel generator

(EDG) out of service for maintenance. 4 The staff has completed all screening and

reviews through September 15, 2004.

5 FY 2004 includes LOOP events counted

through September 15, 2004. 
5

3.2 Important Precursors

Precursors with a CCDP or ∆CDP $1x10-4

are considered important in the ASP

Program. An important precursor generally

has a CCDP higher than the core damage

probability (CDP) estimated by most plantspecific probabilistic risk assessments

(PRAs).

The staff identified three important

precursors that occurred during FYs 2001

and 2002. By contrast, the staff’s preliminary

analyses of plants affected by the power

blackout in the Northeast United States in

August 2003 identified five potential

important precursors. In addition, the staff

has preliminarily identified one potential

important precursor for FY 2004.

The staff is continuing to analyze events that

occurred during FYs 2003 and 2004, and

these ongoing analyses may identify

additional important precursors. Table 9

summarizes the important precursors

identified so far. 

Data coverage. Results summarized below

do not include events that occurred during

FYs 2003 and 2004.

Results. A review of the data for FYs 1993–2002

reveals the following insights:

• The mean occurrence rate of important

precursors exhibited a decreasing trend

that is almost statistically significant during

the period from FY 1993 through FY 2002,

as shown in Figure 3.

• Important precursors occur infrequently

(about two per year on average). 

• Twenty-one important precursors occurred

during the period from FY 1993 through

FY 2002 period. Of these, 33 percent

involved a LOOP initiating event.

3.3 Initiating Events vs. Conditions

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

operational event involving an actual

initiating event such as a LOOP, or (2) a

condition found during a test, inspection, or

engineering evaluation. A condition involves

a reduction in safety system reliability or

function for a specific duration (although no

reactor trip initiator actually occurred during

this time).

Results. A review of the data for FYs

1993–2002 reveals the following insights:

• Over the past 10 years, conditions

outnumbered initiating events (73 percent

compared to 27 percent, respectively). 

This predominance was most notable in

FYs 2001 and 2002, when conditions

contributed to 91 percent and 100 percent

of the identified precursors, respectively.

• The mean occurrence rate of precursors

involving initiating events has exhibited a

decreasing trend that is statistically

significant for the period from FY 1993

through FY 2002, as shown in Figure 4. 

Specifically, the occurrence rate of such

precursors decreased over this period by a

factor of seven.

• The mean occurrence rate of precursors

involving conditions has exhibited an

increasing trend that is statistically

significant for the period from FY 1993

through FY 2002, as shown in Figure 5. 

Specifically, the occurrence rate of such

precursors increased over this period by a

factor of two. As discussed in Section 2.2,

above, the nature of increasing trends will

be investigated in an up coming study.

3.4 Precursors Involving Loss of Offsite

Power Initiating Events

The LOOP event at Quad-Cities Station

Unit 2, which was attributable to a failure of 
6

the main power transformer, was the only

precursor involving an initiating event during

FY 2001. No LOOP events occurred during

FY 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’s preliminary analyses identified

eight of those events as potential

precursors.6

 Three additional LOOP events

occurred during FY 2003. The staff is

continuing its preliminary analyses of those

events, which occurred at Palisades Nuclear

Power Plant and Units 2 and 3 of the Peach

Bottom Atomic Power Station.

As of September 15, 2004, six LOOP events

have occurred during FY 2004. The staff has

completed its preliminary analyses of the

LOOP events at Palo Verde Units 1, 2, and 3,

but is still conducting the remaining analyses

of the events at Vermont Yankee Generating

Station, Unit 2 of the Brunswick Steam

Electric Plant, and Unit 3 of the Dresden

Nuclear Power Station. 

Data coverage. Results summarized below

include LOOP events for FYs 2003 and 2004.

Although the staff is still analyzing six LOOP

events that occurred during FY 2003 and

2004, experience has shown that these

LOOP events are most likely precursors.

Results. A review of the data for FYs

1993–2004 reveals the following insights:

• The mean occurrence rate of precursors

resulting from a LOOP has exhibited 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 three.

• Without the LOOP events that occurred

as a result of the 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. The

review of the LOOP events associated with

the Northeast blackout is the focus of the

staff’s action plan for resolving U.S.

nuclear power plant issues relating to the

electric power grid concerns. 

• Approximately one-half (48 percent) of the

LOOP precursor events that occurred

during FYs 1993–2004 were evaluated to

be important precursors (CCDP$1.0x10-4).

• A simultaneous unavailability of an

emergency power system train was

involved in 4 of the 34 LOOP precursor

events during FYs 1993–2004. 

Specifically, those four events involved a

safety bus at Palo Verde Unit 2, which

failed to sequence loads (2004); an EDG

at Peach Bottom Unit 3, which tripped

about 2.5 hours into the LOOP event as a

result of low jacket coolant pressure

(2003); an output breaker to an EDG at

Indian Point Station Unit 2, which tripped

open after closing (1999); and an EDG that

was out of service for maintenance at

Catawba Unit 2 (1996). Three of these

four precursors had a CCDP >1x10-4. 

3.5 Precursors at Boiling- vs.

Pressurized-Water Reactors

Five precursors in FY 2001 and one in FY

2002 occurred at a boiling-water reactor

(BWR). The precursor counts for

pressurized-water reactors (PWRs) include

the ongoing analyses of events involving

cracking in CRDM housings.

6 The ASP analysis of the LOOP event at DavisBesse 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 x 10-6.) The plant had been

shut down for more than two years before this

event occurred. 
7

A review of the data for FYs 1993–2002

reveals the following results for BWRs and

PWRs:

BWRs

• The mean occurrence rate of precursors at

BWRs does not exhibit a trend that is

statistically significant for the period from

FY 1993 through FY 2002, as shown in

Figure 7.

• No precursors occurred at BWRs 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 2002, as shown in

Figure 8. 

• Historically, an average of 11 precursors

per year occurred at PWRs during FYs

1993–2002.

3.6 Precursors Caused by Unavailability

of Safety-Related Equipment7

Most precursors involve the unavailability of

safety-related equipment. Such events

typically occur during periods of extended

unavailability of equipment 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 an

unavailability condition.

A review of the data for FYs 1993–2002

reveals the following insights concerning the

unavailability of safety-related equipment:

Equipment unavailabilities at BWRs

• Nine precursors involving the unavailability

of safety-related equipment occurred at

BWRs during FYs 1993–2002. The events

in this group involved various failure

modes, causes, and systems.

Emergency core cooling systems

• An unavailability of safety-related highand/or low-pressure injection trains

contributed to 58 percent of all identified

precursors that occurred at PWRs during

FYs 1993–2002. Most of these

unavailabilities were caused by failures in

either the emergency core cooling system

(ECCS) (29 percent) or emergency power

sources (24 percent), or resulted from

design-basis issues involving other

structures or systems that impact either

the ECCS or one of its support systems

(29 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.

Auxiliary/emergency feedwater systems

• The unavailability of one or more trains of

the auxiliary and emergency feedwater

(AFW/EFW) systems contributed to

44 percent of all precursors that occurred

at PWRs. Most of these unavailabilities

were caused by failures in the AFW/EFW

systems (24 percent) or emergency power

sources (44 percent), or resulted from

design-basis issues involving other

structures or systems that impact either 

7 The sum of percentages presented in this

section does not always equal 100-percent

because some precursors involve multiple

equipment unavailabilities.
8

the AFW/EFW systems or one of their

support systems (32 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,8

 such as EDGs and hydroelectric

generators (at Oconee), contributed to

26 percent of all precursors that occurred at

PWRs. Most of these unavailabilities were

caused by random hardware failures in the

emergency power system (57 percent). 

The other unavailabilities were attributable

to design-basis issues (23 percent) and

losses of service water (23 percent).

• All LOOP events at PWRs had operable

turbine-driven AFW pumps.

Section 3.4 (above), discusses insights

related to precursors that involved a LOOP

with a simultaneous EDG unavailability.

3.7 Causes of Precursors Involving

Conditions 

Precursors involving conditional unavailability

of safety-related systems and components 

are attributable to numerous causes. For

the purposes of this review, the staff

classified ASP data into five causal

categories, including (1) design-basis issues,

(2) hardware/material failures, (3) procedure

errors, (4) maintenance deficiencies, and (5)

other personnel/human errors that were not

related to categories 1–4. 

Design-basis issues arise when the design

of plant structures, systems, and/or

components deviates from the regulatory

requirements and assumptions used in

safety analyses.

Results. Figure 9a depicts the distribution

of precursor causes within the five

categories, while Figure 9b plots precursors

related to design-basis issues. A review of

the data for FYs 1993–2002 reveals the

following insights:

• More than half (55 percent) of all identified

precursors related to design-basis issues,

and almost half of those had a ∆CDP >

1x10-5.

• Human-related deficiencies (i.e.,

procedures, maintenance, and other

human errors) accounted for 30 percent of

the identified condition-related precursors. 

Random hardware failures account for the

remaining 70 percent of condition-related

precursors.

3.8 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 divided by the number of reactoryears (RYs). 

Results. Figure 10 depicts the annual ASP

indices for FYs 1993–2002, with indices prior

to FY 1993 provided for historical context. A

review of the ASP indices reveals the

8 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 x 10-6). 

Reference 3 provides a detailed engineering

analysis of EDG unavailabilities.
9

following insights:

• Based on order of magnitude, the average

ASP index for the period from FY 1993

through FY 2002 is consistent with the CDF

estimates from the IPEs.9

• The increase in the ASP index for FY 2002

is attributable to the multiple conditions

coincident with degradation of the RPV

head at Davis-Besse. Both the preliminary

ASP analysis results and the associated

index are subject to change based on peer

review comments.10

Limitations. Using CCDPs 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 CCDP can

overestimate the CDF because of double

counting. 

Because of these and other limitations, the

staff has primarily used the CCDPs 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.

3.9 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 FYs 1994–2002 reveals that

approximately 20 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 10 lists these precursors. The

occurrence of these precursors do not imply

that explicit modeling is needed; however,

there could be insights that could be fedback to future revisions of the PRA.

4.0 References

1. 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.

2. U.S. Nuclear Regulatory Commission. 

NUREG-1100, Vol. 20, “Performance

Budget, Fiscal Year 2005.” NRC:

Washington, DC. February 2004.

3. U.S. Nuclear Regulatory Commission. 

NUREG/CR-5500, Vol. 5, “Reliability

Study: Emergency Diesel Generator

Power System, 1987–1993.” NRC:

Washington, DC. September 1999.

4. 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.

9 The CDF estimates in the IPEs range from 1

x10-6/RY to 3 x10-4/RY, with an average value

of 6 x10-5/RY. 

10 All preliminary results and subsequent indices

are subject to change. The indices for

FYs 2001 and 2002 also include the CRDM

cracking events, for which the staff used a

∆CDP value of 5 x10-5 for each event. 
10

Table 1. Status of ASP analyses as of September 15, 2004.

Status FY 2001 FY 2002 FY 2003 FY

2004a

Final analysis completed 18 8 2 0

Preliminary analysis completed 0 1 8 3

Preliminary analysis underway (includes events

that may be precursors) 5 5 22 7a

a. As of September 15, 2004, the staff has not yet screened all of the FY 2004 events and unavailabilities.

Table 2. FY 2001 at-power precursors involving initiating events (as of September 15, 2004). 

Plant Description/Event Identifier Plant

Type

Event

Date CCDP

Quad-Cities 2 Reactor scram attributable to failure of main power

transformer. LER # 265/01-001 BWR 8/2/01 5x10-6

LaSalle 2

Reactor scram attributable to actuation of the

under-voltage protective circuit on the Division 1

Engineered Safety Feature (ESF) Bus.

LER # 374/01-003

BWR 9/3/01 1x10-5
11

Table 3. FY 2001 at-power precursors involving conditional unavailabilities (as of September 15, 2004).

Plant Description/Event Identifier Plant

Type

Event

Date

Importance

(CCDP-CDP)

Oconee 1, 2, & 3

Non-seismic 16-inch fire system piping header transited

through the auxiliary building and posed a potential

flooding problem if the piping ruptured during a seismic

event. IR # 269/01-08

PWR 11/1/00

5x10-6

(Unit 1)

4x10-6

(Units 2 & 3)

Prairie Island 

1 & 2

Bearing lubrication for the cooling water pumps

degraded following a LOOP. LER # 282/00-004 PWR 11/1/00 1x10-6

Limerick 2

A manual scram occurred because a main steam relief

valve (MSRV) failed open as a result of erosion and

oxidation of the first stage pilot valve disk seating area.

LER # 353/01-001

BWR 2/23/01 3x10-6

Fermi 2

EDG 14 was inoperable for more than the time allowed

by the Technical Specifications(7 days).

LER # 341/01-001

BWR 3/28/01 3x10-6

Kewaunee

The licensee failed to provide a fixed fire suppression

system for Fire Area TU-95B, and this could result in a

postulated lube oil fire involving the AFW pump.

IR # 305/02-06

PWR 3/28/01 1x10-5

Surry 1 and 2 EDG failed as a result of insufficient lubrication.

LER # 280/01-001 PWR 4/15/01

3x10-6

(Unit 1)

6x10-6

(Unit 2)

Calvert Cliffs 1 AFW pump turbine bearing failed as a result of steam

intrusion. LER # 317/01-001 PWR 5/16/01 1x10-5

Dresden 3

The high-pressure coolant injection (HPCI) system was

inoperable following a water hammer event.

LER # 249/02-005

BWR 7/5/01 3x10-6

Palisades Smoke detectors in the cable room were not installed in

accordance with code. LER # 255/01-008 PWR 7/27/01 1x10-6

ANO 1

Fire protection and procedures were inadequate for the

north switchgear room, Fire Zone 99-M.

IR # 313/01-06

PWR 8/3/01 4x10-6

Cook 1 & 2 Degraded ESW flow rendered both Unit 2 EDGs

inoperable. LER # 316/01-003 PWR 8/29/01

1x10-5

(Unit 1)

7x10-6

(Unit 2)
12

Table 4. FYs 2001–2003 CRDM cracking events.a

Plant Event

Date Description/Event Identifier

Oconee 1 12/4/00 RPV head leakage resulted from primary water stress corrosion cracking

(PWSCC) of one CRDM nozzle. LER # 269/00-006

Oconee 3 2/18/01 RPV head leakage resulted from PWSCC of nine CRDM nozzles. 

LER # 287/01-001

ANO 1 3/24/01 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 313/01-002

Oconee 2 4/28/01 RPV head leakage resulted from PWSCC of four CRDM nozzles.

LER # 270/01-002

Palisades 6/21/01 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 255/01-004

Crystal River 10/1/01 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 302/01-004

TMI 1 10/12/01 RPV head leakage resulted from PWSCC of five CRDM nozzles. 

LER # 289/01-002

Surry 1 10/28/01 RPV head leakage resulted from PWSCC of two CRDM nozzles.

LER # 280/01-003

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

LER # 339/01-003

Davis-Besse 2/27/02

Cracking of CRDM nozzles, RPV head degradation, potential clogging of the

emergency sump, and potential degradation of the HPI pumps. 

LER # 346/02-002

St. Lucie 2 4/3/02 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 389/03-002

a. The staff issued the preliminary analysis of Davis-Besse for peer review in September 2004. The analyses of cracking events at

the remaining plants 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) 

Table 5. FY 2002 at-power precursors involving initiating events (as of September 15, 2004). 

Plant Description/Event Identifier Plant

Type

Event

Date CCDP

None
13

Table 6. FY 2002 at-power precursors involving conditional unavailabilities (as of September 15, 2004).

Plant Description/Event Identifier Plant

Type

Event

Date

Importance

(CCDPCDP)

Harris

Debris accumulated in suction lines to the “A” residual

heat removal (RHR) pump and “A” containment spray

pump. LER # 400/01-003

PWR 10/8/01 6x10-6

Point Beach 

1 & 2

Potential common-mode failure of all AFW pumps.

LER # 266/01-005 PWR 11/29/01 7x10-4

(Units 1 & 2)

Callaway

Foreign object rendered the “B” emergency service

water (ESW) pump inoperable, and foreign material in

the condensate storage tank (CST) caused a failure of

the “A” AFW pumps. LER # 483/01-002

PWR 12/3/01 2x10-5

Davis-Bessea

Cracking of CRDM nozzles, RPV head degradation,

potential clogging of the emergency sump, and potential

degradation of the HPI pumps. LER # 346/02-002

PWR 2/27/02 6x10-3

Braidwood 1

The bleed path for the power-operated relief valve

(PORV) was inoperable because of leaking accumulator

check valves. LER # 456/02-002

PWR 4/16/02 4x10-6

Columbia 2 Four safety-related systems had unreliable breakers. 

IR # 397/02-05 BWR 4/25/02 6x10-6

Oconee 3

The emergency power supply cable from the auxiliary

service water switchgear to the HPI pump was

inadequately installed. IR # 247/02-15

PWR 5/30/02 9x10-6

Indian Point 2

Moderate degradation of the control room west wall

could allow smoke and gases to penetrate the control

room in the event of a turbine building fire.

IR # 247/02-10

PWR 7/19/02 7x10-6

a. Preliminary analysis results are subject to change.
14

Table 7. FY 2003 at-power precursors involving initiating events (as of September 15, 2004).a

Plant Description/Event Identifier Plant

Type

Event

Date CCDP

Fermi 2b

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 314/03-002

BWR 8/14/03 2x10-4

Fitzpatrickb

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 333/03-001

BWR 8/14/03 9x10-5

Ginnab

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 244/03-002

PWR 8/14/03 2x10-4

Indian Point 

2 & 3b

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 247/03-005

PWR 8/14/03

1x10-4

(Unit 2)

7x10-5

(Unit 3)

Nine Mile Point 

1 & 2b

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 220/03-002

BWR 8/14/03

3x10-5

(Unit 1)

5x10-4

(Unit 2)

Perryb

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 440/03-002

BWR 8/14/03 5x10-4

a. Other analyses are ongoing.

b. Preliminary analysis results are subject to change.

Table 8. FY 2003 at-power precursors involving conditional unavailabilities (as of September 15,

2004).a

Plant Description/Event Identifier Plant

Type

Event

Date

Importance

(CCDPCDP)

Point Beach 

1 & 2

A design deficiency in the AFW orifices could cause

debris plugging of the pumps’ recirculation line, and

subsequent common-cause failure of all AFW pumps. 

LER # 266/02-003

PWR 10/29/02

6x10-5

(Unit 1)

4x10-4

(Unit 2)

a. Other analyses are ongoing.
15

Table 9. FYs 2001–2004 important precursors (as of September 15, 2004).

Plant Description/Event Identifier Event

Date CCDP

Point Beach 1 & 2

This condition involved a design deficiency in the air-operated

minimum-flow recirculation valves of the AFW 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 AFW 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

7x10-4

(Both

Units)

Davis-Bessea

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 6x10-3

Point Beach 2

This condition involved a design deficiency in the flow-restricting

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

design deficiency, the orifices are vulnerable to debris plugging

when the suction supply for the AFW pumps is switched to its

safety-related water supply (the service water system). Blocked flow

in the recirculation lines of the AFW 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 6x10-5

for Unit 1. LER # 266/02-003

10/29/02 4x10-4

Northeast

Blackout

Fermi 2a

Ginnaa

Indian Point 2a

Nine Mile Point 2a

Perrya

Reactor trip and loss of offsite power resulted from the power

blackout in the Northeast United States on August 14, 2003. The

plant-to-plant variations in CCDP are primarily attributable to the

varying durations of the LOOP at each site, minor problems with

mitigating systems in several plants, and design differences among

the plants. The offsite power recovery times used in the ASP

analyses are based on the times at which the grid control centers

gave permission to use the power, as reported in the LERs and

information compiled by the NRC’s regional offices. The related

ASP analyses also considered any additional time to get power from

the switchyard to a safety bus, and the probability of failing to

successfully restore the power. An important plant design feature

with respect to the risk of station blackout is the time to battery

depletion. Other important design features include the configuration

of EDGs and alternative power sources, and the availability of

turbine-powered mitigating systems. 

See Table 7 for LER numbers.

8/14/03

2x10-4

2x10-4

1x10-4

5x10-4

5x10-4

Palo Verde 2a

A ground fault in the electrical grid resulted in losses of offsite power

to all three units at Palo Verde. With the exception of one EDG in

Unit 2, all EDGs started and loaded onto engineered safeguard

buses. (The Unit 2 Train “A” buses had been de-energized as a

result of the loss of the EDG.) The CCDPs for Units 1 and 3 are

4x10-5. IR # 528/04-12

6/14/04 7x10-4

a. Preliminary analysis results are subject to change.
16

Table 10. 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

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 (AFW) pumps due to a design

deficiency in the AFW 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 AFW 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

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

Oconee 

1, 2, & 3 1999 Postulated high-energy line leaks or breaks in turbine building leading to failure ofsafety-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 servicewater 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
17

Table 11. Significant (CCDP $ 10-3) accident sequence precursors during the 1969–2004 period—ordered

by event date. (See note.)

Plant CCDP Date Description

Davis-Besse 6x10-3

Preliminary 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

mechanisms (CRDM) nozzles and reactor pressure vessel (RPV) head

degradation on February 27, 2002; potential clogging of the emergency

sump on September 4, 2002; and potential degradation of the highpressure injection (HPI) pumps on October 22, 2002. LER # 346/02-002

Catawba 2 2x10-3 2/6/96

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

(EDG) B 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 3x10-3 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 EF (4 EC) as a result

of this event. LER # 482/94-013

Harris 1 6x10-3 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 1x10-3 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 CCDP Date Description

18

Catawba 1 3x10-3 6/13/86

Chemical and volume control system (CVCS) leak (130 gpm) from the

component cooling water (CCW)/CVCS heat exchanger joint (i.e.,

small-break 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 smallbreak LOCA. LER # 413/86-031

Davis-Besse 1 1x10-2 6/9/85

Loss of feedwater; scram; operator error fails auxiliary feedwater

(AFW); 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 AFW 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 AFW locally, and used HPI pump “1” to

reduce RCS pressure. LER # 346/85-013

Hatch 1 2x10-3 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 2x10-3 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 5x10-3 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 CCDP Date Description

19

Davis Besse 1 2x10-3 6/24/81

Loss of vital bus; failure of an AFW 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, AFW 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 7x10-3 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 5x10-3 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 1x10-3 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 1x10-3 4/19/80

Loss of 2 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 CCDP Date Description

20

Crystal River 3 5x10-3 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 1x10-3 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 2x10-3 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 stuckopen PORV. As a result, the operators prematurely shut off the highpressure 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 1x10-2 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 AFW 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 3x10-3 4/13/78

LOOP; one EDG failed to start

With the plant shutdown, 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 CCDP Date Description

21

Farley 1 5x10-3 3/25/78

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

fails 

A low level condition in a single SG resulted in a reactor trip. The turbinedriven AFW pump failed to start. Both motor-driven AFW 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 1x10-1 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 AFW flow control valves to establish secondary heat removal. This

resulted in steam generator dryout. LER # 312/78-001

Davis-Besse 1 5x10-3 12/11/77

AFW pumps inoperable during test

During AFW 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 1 7x10-2 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 1x10-3 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 2x10-3 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 1x10-2 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 safety-related buses. LER # 336/76-042
Plant CCDP Date Description

22

Kewaunee 5x10-3 11/5/75

Inoperable AFW 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 AFW pump suction strainers became clogged, thereby

resulting in low pump flow. The same condition occurred for the turbinedriven AFW pump suction strainer. LER # 305/75-020

Brunswick 2 9x10-3 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 2x10-1 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 2x10-2 5/8/74

Failure of three AFW pumps to start during test

Operators attempted to start all three AFW 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 5x10-3 4/7/74

Inoperable AFW pumps during shutdown 

While the reactor was in cooldown mode, motor-driven AFW 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 AFW pumps. LER # 266/74-LTR

Point Beach 1 1x10-3 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
23

*NOTE (to Table 10):

• 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 30 years. Consequently, the results obtained in the earlier years may be conservative when compared to

those obtained using the current methodology and PRA models.
24

0 

0.1 

0.2 

0.3 

0.4 

0.5 

Precursors/Reactor Year

84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02

Fiscal Year

CRDM Cracking Events

Final Data

Historical

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= 0.34). The results prior to FY 1993 are shown to provide

perspective. The ongoing analyses of events involving cracks in the CRDM housings are included FY 2001

and 2002 data.
25

0.00

0.02

0.04

0.06

0.08

0.10

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

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 almost

statistically significant (p-value = 0.11).

0

1

2

3

4

5

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

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 was detected that is statistically

significant.

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

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

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

rate, by fiscal year. The decreasing trend is

statistically significant (p-value = 0.002). 

0.00

0.04

0.08

0.12

0.16

0.20

0.24

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

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 = 0.0001).

0.00

0.02

0.04

0.06

0.08

0.10

0.12

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

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 almost statistically significant (p-value = 0.14).
26

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

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 4: Precursors involving initiating

events-occurrence rate, by fiscal year. The

decreasing trend is statistically significant (p-value =

0.0001). 

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

Fiscal Year

Occurrence Rate

CRDM cracking events

arithmetic average

mean (per reactor calendar year)

Figure 5: Precursors involving conditional

unavailability of equipment-occurrence rate, by fiscal

year. The increasing trend is statistically significant

(p-value = 0.005). 

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

Fiscal Year

Occurrence Rate

CRDM cracking events

arithmetic average

Figure 8: Precursors involving PWRs-occurrence

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

no trend is detected that is statistically significant

(p-value = 0.37). 

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 6: Precursors involving loss of offsite power

initiating events-occurrence rate, by fiscal year. The

increasing trend is statistically significant (p-value =

0.02).

0.00

0.04

0.08

0.12

0.16

0.20

0.24

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

arithmetic average

Figure 7: Precursors involving BWRs-occurrence

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

trend was detected that is statistically significant

(p-value = 0.36). 
27

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

60%

65%

Design Hardware Procedure Personnel Maintenance

Precursor Cause

Percent (%)

Delta-CDP Bin: > 1E-4

Delta-CDP Bin: 1E-5 to 1.0E-4

Delta-CDP Bin: 1E-6 to 1E-5

Precursors from other causes

Figure 9a: Causes of precursors- percentage, by

cause type.

0

4

8

12

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year 

Number of Precursors Caused by Design Error

Figure 9b: Precursors caused by design-basis

issues- number of precursors, by fiscal year. 
28

1.0E-06 

1.0E-05 

1.0E-04 

1.0E-03 

ASP Index (per reactor year)

82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02w/o

Calendar Year

Annual ASP Index

Average CDF from IPEs

10-year ASP Index

Figure 10: Annual ASP Index - ASP Index for a year is the total CCDP of all precursors divided by the

total number of reactor years in a given year. Years with significant precursors (i.e., CCDP > 1E-3): 1983

(2), 1984 (2), 1985 (3), 1986 (2), 1990 (1), 1991 (1), 1994 (1), 1996 (1), and 2002 (1). The ongoing

analyses of events involving cracks in the CRDM housings are included FY 2001 and 2002 data. The

CCDPs of these events are assumed to be 5 x 10-5. The bar labeled “w/o” is FY 2002 index without the

potential precursor at Davis-Besse.